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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
Commission file number 1-10473
PRIDE COMPANIES, L.P.
(Name of registrant)
Delaware 75-2313597
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1209 North Fourth Street, Abilene, Texas 79601
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code:
(915) 674-8000
Securities registered pursuant to Section 12(b) of the Act:
Name of Each
Title of Each Class: Exchange on Which Registered:
- - ------------------- ----------------------------
Common Units New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
Number of Common Units outstanding as of March 26, 1998:
4,950,000
The aggregate market value of the 4,626,365 Common Units
held by non-affiliates of the Partnership as of March 26, 1998
was approximately $6.9 million, which was computed using the
closing sales price of the Common Units on March 26, 1998.
PART I
Items 1 and 2. Business and Properties
General
Pride Companies, L.P. (the "Partnership") was formed as a
limited partnership under the laws of the State of Delaware in
January 1990. The Partnership owns and operates (i) a crude oil
gathering business (the "Crude Gathering System") that gathers,
transports, resells and redelivers crude oil in the Texas and New
Mexico markets and (ii) certain integrated products pipelines and
terminal operations in San Angelo, Texas and Aledo, Texas (the
"Products System"). The Partnership also owns a modern simplex
petroleum refinery facility (the "Refinery") which was mothballed
on March 22, 1998. Under an agreement with Texaco Trading and
Transportation, Inc. ("TTTI"), the Partnership will begin
purchasing refined products from TTTI in April 1998 to market
through the Products System and its other products terminal in
Abilene, Texas that had been included as part of the Refinery
(see "-Long-Term Product Supply Agreement" below). Prior to
mothballing the Refinery, the Partnership's operations were
considered a single industry segment, the refining of crude oil
and the sale of the resulting petroleum products. The primary
purpose of the Crude Gathering System was to supply the Refinery
with crude oil. In that connection, it purchased and resold
crude oil in order to provide a supply of the appropriate grade
of crude oil at strategic locations to be used as feedstock for
the Refinery. In connection with the TTTI agreement and the
mothballing of the Refinery, the Crude Gathering System will
primarily market crude oil to other refineries and the
Partnership will now operate two separate and distinct industry
segments, the Crude Gathering System segment and the marketing
and products pipeline segment. The Crude Gathering System
consists of pipeline gathering systems and a fleet of trucks
which transport crude oil into third party pipelines and into the
system's primary asset, a common carrier pipeline. The Products
System consisted of two products pipelines that originated at the
Refinery and terminated at the Partnership's marketing terminals.
In connection with the mothballing of the Refinery, the products
pipeline that extends from the Refinery to the Aledo terminal was
idled, since TTTI's pipeline is connected to the Partnership's
Aledo terminal.
Pride Refining, Inc., a Texas corporation (the "Managing
General Partner"), owns a 1.9% general partner interest in and
serves as the managing general partner of the Partnership. The
Partnership succeeded in January 1990 to the businesses of Pride
SGP, Inc. ("Special General Partner" or "Pride SGP") which owns a
0.1% general partner interest in and serves as the special
general partner of the Partnership. The Managing General Partner
and the Special General Partner (collectively the "General
Partners") collectively own a 2% general partner interest.
Effective December 31, 1996, the Partnership adopted certain
amendments to its partnership agreement (the "Amendments"), which
modified the capital structure of the Partnership. In addition
to its general partner interest, the Special General Partner owns
a 4.9% interest in the Partnership through ownership of common
limited partner units with terms specified by the Amendments
("Common Units"). Public ownership represented by the remaining
Common Units is 93.1%. Prior to the effectiveness of the
Amendments, the Special General Partner owned a 51.7% limited
partner interest in the Partnership through ownership of common
limited partner units ("Old Common Units"), and the public owned
a 46.3% interest in the Partnership through ownership of
convertible preferred limited partner units ("Preferred Units").
Prior to the mothballing of the Refinery, the Partnership's
principal business consisted of refining crude oil into
commercial and military aviation fuel, conventional gasoline, low
sulfur diesel fuel, vacuum gas oil, liquefied petroleum gas and
vacuum residuum. In addition, the Partnership owns and operates
a crude oil gathering system connected by pipeline into the
Refinery and two common carrier products pipeline systems, one of
which transported products from the Refinery to Dyess Air Force
Base ("Dyess") in Abilene, and to the Partnership's products
terminal at San Angelo, Texas. The other pipeline formerly
transported products from the Refinery to the Partnership's
products terminal in Aledo, Texas (southwest of Fort Worth,
Texas) and was idled when the Refinery was mothballed. Prior to
January 20, 1997, the Partnership operated an additional 13-mile
pipeline segment that carried military aviation fuel from the
Partnership's products terminal in Aledo, Texas into Naval Air
Station Fort Worth located northwest of Fort Worth (formerly
Carswell Air Force Base), but shut that pipeline segment down due
to reduced military aviation fuel requirements for that base and
other economic considerations. The Partnership now trucks the
military aviation fuel from the Aledo products terminal to Naval
Air Station Fort Worth.
The Partnership owns the Texas Plains Pipeline System
("Texas Plains System") which consists of 271 miles of pipeline
transporting crude oil and vacuum gas oil from the Partnership's
Refinery to Borger, Texas, and then via Diamond Shamrock Refining
and Marketing Company's ("Diamond Shamrock") pipeline to its
refinery in McKee, Texas. As a result of the Refinery being
mothballed, the Texas Plains System will only ship crude oil.
See "Partnership Operations and Products" below.
The Partnership's primary market area for refined products
includes Central and West Texas and is a region that is not
significantly served by the major refining centers of the Gulf
Coast. Fina, Inc. ("Fina"), a competitor of the Partnership,
currently has products pipeline access into Abilene, while the
Partnership is the only supplier with a products pipeline into
San Angelo. TTTI recently converted an existing crude pipeline
into a products pipeline that will deliver gasoline, diesel and
military aviation fuel to the Partnership in Abilene and Aledo
for distribution to the Partnership's existing customers. In the
Partnership's primary market area, product prices reflect a
premium due to transportation costs required to import refined
products from supply points outside of the market area. Naval
Air Station Fort Worth, Dyess, and certain other military
installations have been long-time customers for the Partnership's
military aviation fuel. Management anticipates that the
Partnership will continue to bid for these and other military
supply contracts in the future although volumes awarded under the
recently awarded contract have been significantly reduced from
prior years since the Partnership no longer receives preferential
treatment under the small business set-aside program and due to
increasing competition. See "-Partnership Operations and
Products" and "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Factors and Trends
Affecting Operating Results." Gasoline and diesel tankage and
sales facilities at the Partnership's Aledo products terminal
allow the Partnership access to the smaller communities west of
the Dallas-Fort Worth ("DFW") market along Interstate 20 for
gasoline and the DFW market for diesel. See "-Markets and
Competition" below.
Partnership Operations and Products
Products System. The Partnership's primary product delivery
facilities consisted of a pipeline that connects the Refinery to
the Partnership's Aledo products terminal (the "Aledo Pipeline")
and a pipeline that connects the Refinery to Dyess in Abilene,
Texas, and the Partnership's products terminal at San Angelo,
Texas (the "San Angelo Pipeline"). In conjunction with the
Refinery being mothballed, TTTI will deliver product to Abilene
and Aledo. The Partnership will deliver a portion of the product
received from TTTI in Abilene to Dyess and to the products
terminal in San Angelo. The Aledo pipeline will be idled since
TTTI's pipeline is connected to the Partnership's Aledo terminal.
Prior to January 20, 1997, the Partnership operated an
additional 13-mile segment of pipeline that carried military
aviation fuel from the Partnership's products terminal in Aledo
into Naval Air Station Fort Worth located northwest of Fort
Worth, Texas. This pipeline segment was closed due to reduced
military aviation fuel requirements for that base and other
economic considerations.
The Partnership now trucks the military aviation fuel from
the Aledo products terminal to Naval Air Station Fort Worth and
delivers military aviation fuel through the San Angelo Pipeline.
Conventional gasoline is marketed through the Partnership's Aledo
products terminal and is delivered through the San Angelo
Pipeline to the Partnership's San Angelo products terminal for
marketing to non-military customers in the communities west of
the Dallas-Fort Worth ("DFW") metropolitan area along Interstate
20 and in the San Angelo area, respectively. Diesel fuel is also
delivered to the Aledo and San Angelo products terminals for
marketing to non-military customers in the DFW metropolitan area
and the San Angelo area. Additional products are delivered by
truck and rail throughout the Partnership's market area.
Military aviation fuel delivered by the San Angelo Pipeline
to Dyess is sold f.o.b. the Refinery with title passing to the
purchaser as the product enters the pipeline. Prior to 1998, the
Partnership had the only pipeline capable of delivering jet fuel
directly into Dyess. Fina recently purchased Conoco's product
terminal in Abilene and is constructing its own pipeline from its
terminal to Dyess that will enable Fina to deliver military
aviation fuel into Dyess.
Sales of military aviation fuel constitute a significant
portion of the Partnership's revenues. See "-Markets and
Competition" below. Such sales are under annual contracts
awarded by the Defense Fuel Supply Center after a bidding
process. The bidding process is conducted on a base-by-base
basis and is subject to the small business set-aside program.
When the bids are received, the Defense Fuel Supply Center
determines both the lowest overall bid and the lowest bid
submitted by a small business (defined as a refinery with a
throughput capacity of less than 75,000 BPD and fewer than 1,500
employees). If the lowest bid is not submitted by a small
business, the lowest small business bidder is offered the
opportunity to obtain a contract for a set percentage of the
base's requirements by matching the lowest overall bid. Prior to
the contract that begins April 1, 1998 and ends March 31, 1999,
the Partnership was considered a small business. As a result of
the planned mothballing of the Refinery and the agreement to
purchase products from TTTI, the Partnership could not bid as a
small business for the contract that begins April 1, 1998 and
ends March 31, 1999 nor will the Partnership be able to bid on
any future contracts as a small business. Since the Partnership
was not able to match the price of the lowest large business
under the small business set-aside program, the volumes under the
recently awarded contract are approximately 51% of the volumes
under the prior contract which is partially offset by an
approximate 2 cents improvement in the award price compared to
the base reference price net of transportation from the prior
contract. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Factors and Trends
Affecting Operating Results."
The Partnership and its predecessors have been supplying
products to Naval Air Station Fort Worth and Dyess since the
early 1960s. Management believes that the military will continue
to be a major customer of the Partnership into the foreseeable
future. Dyess is an Air Combat Command facility, formerly a
strategic air command facility, and the primary training base for
the B-1 bomber crews. In addition, Dyess also has two worldwide
deployable airlift squadrons which fly the C-130 Hercules. Under
the contract that is effective from April 1, 1997 through March
31, 1998, the Partnership contracted to sell military aviation
fuel to Dyess, Sheppard Air Force Base in Wichita Falls, Texas,
Fort Hood Military Installation in Killeen, Texas, Naval Air
Station Dallas in Dallas, Texas, E-Systems, Inc. in Greenville,
Texas, Naval Air Station Fort Worth, AASF in Dallas, Texas, and
Tinker Air Force Base in Oklahoma City, Oklahoma. Additionally,
the Partnership is selling jet fuel to Altus Air Force Base in
Altus, Oklahoma and Cannon Air Force Base in Clovis, New Mexico,
under a contract that is effective from October 1, 1997 through
September 30, 1998. Under the new contract that is effective
from April 1, 1998 through March 31, 1999, the Partnership will
supply military aviation fuel to Dyess, Sheppard Air Force Base,
Naval Air Station Fort Worth, Fort Hood Military Installation,
and E-Systems, Inc. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Factors and
Trends Affecting Operating Results - Other Factors."
Crude Oil Gathering Operations. The Partnership's Crude
Gathering System is divided into two distinct areas: (i) truck-
based crude oil gathering and (ii) pipeline operations. The
trucking operations comprise six district offices located in the
Abilene, Dallas, Graham, Lubbock, Midland, and San Angelo, Texas
areas. These districts utilize a fleet of 103 trucks to
transport crude oil from individual leases or small gathering
systems to injection stations owned and operated by the
Partnership along common carrier pipeline systems. As of
December 31, 1997, the Crude Gathering System operated 44 crude
oil injection stations located on various common carrier pipeline
systems including the Amoco, Arco, Chevron, Comyn, Conoco, EOTT,
Mobil, Sun, Texaco, Texas Plains System and other Texas-New
Mexico pipeline systems. The Partnership maintains 21 trucking
locations throughout the area for operation of its truck fleet.
In December 1997, the average length of travel for the
Partnership's trucks in its gathering operations was
approximately 76 miles round trip.
As of December 31, 1997, the pipeline assets utilized in the
Crude Gathering System consisted of in excess of 900 miles of
active pipeline, the major portion of which is the Comyn pipeline
system with approximately 414 miles of trunkline and 190 miles of
gathering lines and the Texas Plains System consisting of an
additional 242 miles of trunkline and 29 miles of gathering
lines. Ownership of the trunkline segments of the Comyn pipeline
system from Hawley to Comyn, Texas (90 miles), from Hearne to
Comyn, Texas (143 miles), and from Comyn to Ranger, Texas (37
miles) along with certain related pumping facilities was retained
by Pride SGP when the Partnership was formed. For the years
ended December 31, 1997, 1996 and 1995, the crude oil transported
through the active segment of the Comyn pipeline system which is
owned by Pride SGP accounted for approximately 64%, 51% and 72%,
respectively, of the total crude oil received by the Refinery.
At December 31, 1997, twelve miles of the 37-mile segment noted
above were inactive but are being reactivated in connection with
the TTTI agreement. The 143-mile section from Hearne to Comyn
transports 10,671 barrels per day ("BPD") of crude oil from the
eastern portion of the Austin Chalk formation. The Partnership
and Pride SGP have a lease agreement wherein the Partnership has
been granted the right to use the segments of the Comyn pipeline
owned by Pride SGP. The Partnership is entitled to use the
pipeline sections in exchange for its agreement to provide
maintenance and repair valued at approximately $250,000 annually.
In addition, the Partnership pays the taxes, insurance, and other
costs. Pursuant to the lease agreement, the Partnership was
accruing rentals to Pride SGP of $0.20 per barrel for all crude
oil transported by the Partnership, or third parties with
contractual relationships with it, through the 143-mile section
from Hearne to Comyn. Rentals accruing to Pride SGP from the
Partnership for the years ended December 31, 1997, 1996 and 1995
totaled approximately $788,000, $919,000, and $873,000,
respectively, for the lease of the pipeline. The original term
of the lease agreement ran through 2000. During 1992, the lease
was amended, whereby at the Partnership's option, the lease may
be extended through March 2013 as long as certain minimum
throughput levels are maintained. If such throughput levels are
not maintained during the extended term, the lease is cancelable
by Pride SGP with ninety days' notice. At any time during the
term of the amended lease agreement, the Partnership may upon 30
days' notice to Pride SGP purchase the Comyn pipeline for $10
million. On December 31, 1997, the lease was amended to reduce
the rental to a maximum of $400,000 annually as long as certain
debt is outstanding. See "Certain Relationships and Related
Transactions."
The Comyn pipeline is a common carrier pipeline that charges
a transportation fee in accordance with a published tariff
schedule filed with the Texas Railroad Commission. Shipments of
crude oil to the Refinery accounted for approximately 88% of the
crude oil shipped through the Comyn line. The Comyn pipeline is
also allowed to charge each customer's account with a line loss
allowance of 0.25% for each barrel transported in the system.
The Partnership owns the Texas Plains System, a crude oil
pipeline system that prior to the mothballing of the Refinery
also transported vacuum gas oil. It consists of 271 miles of
pipeline extending from Hawley, Texas, which is located near the
Partnership's Refinery, to Borger, Texas. The system has a total
capacity of 38,000 BPD, and an average of approximately 31,000
BPD of crude oil and vacuum gas oil was shipped on the pipeline
for the year ended December 31, 1997. After the mothballing of
the Refinery, the Partnership plans on shipping crude oil that
previously went to the Refinery to Diamond Shamrock's refinery in
McKee, Texas, in place of the vacuum gas oil. Prior to the
mothballing of the Refinery, the Partnership had sold all the
vacuum gas oil and a small portion of the crude oil transported
on the pipeline to Diamond Shamrock.
In addition to the Comyn system and Texas Plains System, the
Partnership owns and operates two smaller pipelines in West
Texas: Carlsbad in Tom Green County and East Broadview in
Lubbock County.
Crude oil from the Crude Gathering System pipelines can be
delivered to a variety of locations, including storage tanks
located at the Refinery, tank storage areas which facilitate
trucking to injection stations, and several different common
carrier crude oil pipelines.
The Crude Gathering System is the first purchaser of a
portion of the crude oil it gathers. These first purchase
barrels have traditionally been either resold to other companies
or shipped to the Refinery. The Partnership also gathers crude
oil for custom gathering customers and charges gathering fees
depending on several factors (including the transportation
distance involved) and delivers these barrels to an agreed upon
location by contract. The Crude Gathering System assumes title
to both first purchase and custom gathered barrels and the total
of the two categories is considered to be total gathered barrels.
The custom gathering area has been the fastest growing segment of
the Crude Gathering System operations. While first purchase
barrels have declined from 39,000 BPD in 1986 to 28,000 BPD for
the year ended December 31, 1997, custom gathered barrels have
grown from 5,000 BPD to 24,000 BPD for the same period. The
custom gathered barrels have declined over the last two years as
the Partnership has eliminated some of the marginal custom
gathered contracts. Both first purchase barrels and custom
gathered barrels are subject to decline if drilling activity
slows down as a result of declines in crude oil prices.
Refining. Prior to March 22, 1998, the principal business
of the Partnership was crude oil refining at its Refinery located
approximately ten miles north of Abilene, Texas. The Refinery
has a throughput capacity of 49,500 barrels per day ("BPD") and
is permitted to process 44,500 BPD. For the year ended December
31, 1997, the Refinery processed crude oil into refined products
at an average rate of approximately 31,400 BPD.
The Refinery produced vacuum residuum, which was sold to
third parties for processing into roofing material and similar
products, and distillates that included atmospheric gas oil for
blending with vacuum gas oils, diesel for sale as motor fuel,
kerosene, and heavy and light naphthas. Kerosene was produced
and sold as various grades of jet fuel. The light naphtha was
subjected to further processing to remove butane and propane to
produce liquefied petroleum gas and the remaining light naphtha
was used for a gasoline blend stock. The Refinery allowed heavy
naphtha to be converted into a high octane unleaded gasoline
blend stock. The Refinery produced up to 7,500 BPD of unleaded
gasoline. The Refinery also produced diesel fuel that complied
with federal environmental regulations restricting the amount of
sulfur allowed in highway use diesel fuel.
As previously mentioned, the Refinery was mothballed on
March 22, 1998. The Partnership currently plans to retain these
assets for possible future use should the long-term outlook in
the refining business improve. However, as a result of the
mothballing of the Refinery, the Partnership wrote down such
assets $40.0 million.
Markets and Competition
Fina, the Partnership's principal competitor in its primary
market area, operates a products pipeline in the Abilene area.
This competitor's pipeline originates in Big Spring, Texas (105
miles west of Abilene) and supplies Hawley, Midland, and Wichita
Falls, Texas and the Midcontinent. However, the Partnership
currently has the only products pipeline access to the San Angelo
area. Retailers and jobbers who are not supplied by the
Partnership or one of its exchange partners must truck their
products into San Angelo from locations as far away as 90 to 200
miles. TTTI recently converted an existing crude pipeline into a
products pipeline that will deliver gasoline, diesel and military
aviation fuel from the Gulf Coast to the Partnership's Abilene
and Aledo products terminals. Other Gulf Coast refiners ship
their products primarily throughout the southeast and central
United States. Total petroleum product demand for the
Partnership's market area is determined by demand for
conventional gasoline, diesel, commercial and military aviation
fuel, and kerosene. In the case of each product, however, demand
tends to vary by locality and season. Aviation fuel consumption
is limited to regional military and civilian air facilities.
Fina and Holly Corp. ("Holly") announced a plan in February
1997 to convert existing crude oil and natural gas pipelines and
lay 110 miles of new pipeline to bring additional gasoline and
diesel products to West Texas, New Mexico and Arizona. The
system will be supplied by Fina's refineries in Big Spring and
Port Arthur, Texas, a pipeline terminal in Duncan, Oklahoma, and
Holly's refinery in Artesia, New Mexico. Fina has indicated that
it believes Gulf Coast petroleum products will not be needed for
another five years. Other companies are also considering
projects to bring petroleum products into West Texas, New Mexico
and Arizona from the Gulf Coast. These proposals, if
implemented, would increase competition in the Partnership's
primary market areas.
In addition to its primary market areas in Abilene and San
Angelo for conventional gasoline and diesel, the Partnership has
access to a secondary market in the small communities west of
Dallas-Fort Worth along Interstate 20 for conventional gasoline
and the Dallas-Fort Worth metropolitan area for diesel. Prior to
the mothballing of the Refinery, the secondary market was
accessible from the Refinery via the Aledo Pipeline and the Aledo
products terminal. Now the Aledo products terminal is supplied
by TTTI's pipeline that connects directly to the Aledo terminal.
As a result of the reformulated gasoline requirement for the
Dallas-Fort Worth metropolitan area effective January 1, 1995,
most products terminals are supplying reformulated gasoline in
the area with only a small number having the capability of
supplying conventional gasoline. The Partnership's Aledo
products terminal is strategically located to take advantage of
this marketing opportunity, and the Partnership has entered into
supply and exchange agreements with three major oil companies at
that location. The San Angelo market area is accessible via the
San Angelo Pipeline that is connected to storage tanks at the
Refinery. Market demand for gasoline and diesel in Abilene and
in San Angelo is estimated to be approximately 17,500 BPD and
11,000 BPD, respectively. Market demand for petroleum products
in the Dallas - Fort Worth area is estimated to be approximately
343,000 BPD, with reformulated gasoline, diesel and a limited
amount of conventional gasoline accounting for an aggregate of
195,000 BPD.
The Partnership does not generally sell its products through
its own direct retail distribution system, but primarily sells to
other branded product companies and branded Pride dealers. A
number of major petroleum product marketers in West Texas do not
have local refinery facilities or sales terminals. Accordingly,
such marketers supplement their local needs by purchases or
product exchanges with local suppliers, such as the Partnership.
The Partnership currently sells or exchanges diesel, conventional
gasoline, and military aviation fuel, depending on local market
needs throughout the region. Some of the marketers in the area
that purchase or exchange refined products include Chevron,
Citgo, Conoco, Diamond Shamrock, Exxon, Fina, Phillips, Shell,
Star Enterprise and Texaco. The Partnership has five exchange
agreements and three sales agreements with these companies for
products supplied out of the San Angelo products terminal, one
exchange agreement and two sales agreements with these companies
for product supplied out of the Aledo products terminal, and two
exchange agreements and one sales agreement with these companies
for product supplied out of the Abilene products terminal. The
exchange agreements have enabled the Partnership to expand its
marketing area to Amarillo, Texas, El Paso, Texas, Lubbock,
Texas, Midland/Odessa, Texas, and Wichita Falls, Texas without
incurring transportation costs to these cities. Management also
expects that the Partnership will continue to sell conventional
gasoline and diesel to jobbers who will own and operate service
stations under the Pride brand. The Partnership also currently
operates five retail fueling facilities. These facilities are
located in Central and West Texas. Sales by such facilities
accounted for less than 1% of the Partnership's revenues for the
year ended December 31, 1997.
As a result of the Refinery being mothballed on March 22,
1998, the Partnership will now market to third parties the crude
oil it previously sold to the Refinery. These third parties
include other refiners and companies that buy, sell and exchange
crude oil. The Partnership recently entered into a two-year
contract to sell Gary-Williams Energy, Corporation (Gary-
Williams) a portion of the crude oil sold to the Refinery. The
Partnership is also in final negotiations with another refiner to
sell them the remainder of the crude oil on a long-term contract.
Customers
The Partnership delivers a substantial amount of its
military aviation fuels to the Defense Fuel Supply Center. The
Partnership entered into a three-year agreement with Diamond
Shamrock to supply them with vacuum gas oil through December 31,
1998 for use in Diamond Shamrock's refining operations. The
Partnership's revenues pursuant to the military aviation fuel
supply contracts and the Diamond Shamrock agreement accounted for
11% and 21%, respectively, of its total revenues for the year
ended December 31, 1997. The Partnership has proposed supplying
Diamond Shamrock with vacuum gas oil the Partnership would
purchase from TTTI and ship to Diamond Shamrock through the end
of the contract which is December 31, 1998. See "Legal
Proceedings".
Long-Term Product Supply Agreement
The Partnership announced on June 20, 1997 that it had
executed a long-term product supply agreement (the "Agreement")
with TTTI, a wholly-owned subsidiary of Texaco, Inc. The
Agreement has a 10-year primary term which begins in April 1998,
the date TTTI completes its system of pipelines and terminals.
The Agreement also has two-year renewal provisions for up to an
additional 10 years. After the initial five years of the initial
ten-year term ("Primary Term"), if TTTI determines that shipment
of products on its new products pipeline is no longer economical
due to non-economical product prices, then TTTI may notify the
Partnership of proposed redetermined prices. If the Partnership
does not accept such redetermined prices, then TTTI may elect to
terminate the Agreement by 18 months written notice. After the
Primary Term, if either party under the Agreement can demonstrate
that the prices for delivered products under the Agreement are
producing cash flows materially below that received during the
Primary Term, then such party may notify the other party of
proposed prices it must receive to continue. If the other party
does not accept such redetermined pricing then the other party
may elect not to renew the Agreement not less than one year prior
to the end of the current term. The Agreement may furthermore be
terminated upon any breach by the other party which continues
beyond 30 days following notice of breach. Additionally, the
Agreement provides that the Partnership will purchase all
gasoline, diesel and jet fuel, which it may desire to purchase,
exclusively from TTTI. The Partnership's cost for such product
is based primarily on the market price in the area in which the
products are received less a discount. The Partnership will use
TTTI products to supply its existing customer base, which
includes wholesale customers, exchange partners, and military
bases, primarily using the Partnership's existing pipelines and
terminals.
In connection with the Agreement, the Partnership mothballed
its Refinery, but will continue to utilize part of the Refinery
for a products and crude oil storage and terminalling facility.
See also "Financial Condition - Financial Resources and
Liquidity." The Partnership estimates the closure cost and
related severance costs at approximately $1.8 million. The
Partnership accrued this amount as of December 31, 1997. The
Agreement with TTTI will allow the Partnership to expand its
crude gathering operations, conducted under the name Pride
Pipeline Company. The arrangement with TTTI enables the
Partnership to transport the crude oil it previously gathered and
shipped to the Refinery to other attractive markets. A large
portion of Pride Pipeline Company's gathered crude oil was
restricted to use as feedstock for the Refinery. The Partnership
anticipates that the new arrangement will produce operating cash
flows similar to the level that the Partnership has experienced
for the last four years. However, the Partnership believes that
cash flows should be less volatile since the Agreement will
result in more stable product margins and eventually decrease the
Partnership's exposure to volatility in refining margins. The
Partnership also believes that the Agreement will better enable
the Partnership to remain competitive as environmental standards
change and the industry trends toward consolidation and
realignments in the future.
Employees
As of December 31, 1997, the Partnership had 340 employees,
of which 119 were employed in the Refinery and Products System
and 221 were employed in the Crude Gathering System. As a result
of the mothballing of the Refinery, the Partnership expects the
number of employees for the Refinery and Products System to
eventually decrease to 55 employees. None of the Partnership's
employees are subject to collective bargaining or similar
agreements.
Environmental Matters
The Partnership's activities involve the transportation,
storage, and handling of crude oil and petroleum products that
constitute or contain substances regulated under certain federal
and state environmental laws and regulations. The Partnership is
also subject to federal, state and local laws and regulations
relating to air emissions and disposal of wastewater as well as
other environmental laws and regulations, including those
governing the handling, release and cleanup of hazardous
materials and wastes. The Partnership has from time to time
expended certain resources, both financial and managerial, to
comply with environmental regulations and permit requirements and
anticipates that it will continue to be required to expend
financial and managerial resources for this purpose in the
future. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Factors and Trends
Affecting Operating Results" and "Legal Proceedings."
Forward Looking Statements
This Form 10-K contains certain forward looking statements.
Such statements are typically punctuated by words or phrases such
as "anticipate," "estimate," "projects," "should," "may,"
"management believes," and words or phrases of similar import.
Such statements are subject to certain risks, uncertainties or
assumptions. Should one or more of these risks or uncertainties
materialize, or should underlying assumptions prove incorrect,
actual results may vary materially from those anticipated,
estimated or projected. Among the key factors that may have a
direct bearing on the Partnership's results of operations and
financial conditions in the future are: (i) the margins between
the prices obtained for the Partnership's refined petroleum
products and the cost of such products, (ii) the volume
throughput on and margins from the transportation and resale of
crude oil from the Partnership's Crude Gathering System, (iii)
the impact of current and future laws and governmental
regulations affecting the petroleum industry in general and the
Partnership's operations in particular, (iv) the ability of the
Partnership to sustain cash flow from operations sufficient to
realize its investment in operating assets of the Partnership,
(v) the settlement of outstanding contract issues, and (vi) the
receipt of certain consents and approvals to modify the
Partnership's capital structure, as described in "Management's
Discussion and Analysis of Financial Condition and Results of
Operation - Financial Condition."
Item 3. Legal Proceedings
The Partnership has filed a substantial claim against the
Defense Fuel Supply Center relating to erroneous pricing of fuel
purchased over a period of several years from the Partnership and
its predecessors (the "DFSC Claim"). The ultimate outcome of
this matter cannot presently be determined.
The Partnership is contractually committed to supply Diamond
Shamrock with vacuum gas oil through December 31, 1998. The
Partnership has proposed supplying Diamond Shamrock with vacuum
gas oil that it would purchase from TTTI and ship to Diamond
Shamrock through the end of the contract. If this proposal is
acceptable to Diamond Shamrock and the Partnership can make the
appropriate arrangements to ship the vacuum gas oil to Diamond
Shamrock, the change to the contract is not expected to have a
material effect on the Partnership. If that proposal, or other
alternative proposals, are not acceptable, or the Partnership
cannot make the appropriate arrangements, there could be a
material adverse effect on the Partnership.
The Partnership is involved in various claims and routine
litigation incidental to its business for which damages are
sought. Management believes that the outcome of all claims and
litigation is either adequately insured or will not have a
material adverse effect on the Partnership's financial position
or results of operations.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of security holders
during fiscal 1997.
PART II
Item 5. Market for Partnership's Preferred Units, Common Units,
and Related Unitholder Matters
The Partnership adopted certain Amendments to its
partnership agreement effective at the close of business on
December 31, 1996 which modified the capital structure of the
Partnership. Prior to the effectiveness of the Amendments, the
Partnership had 4,700,000 Preferred Units listed on the New York
Stock Exchange under the symbol "PRF". On January 2, 1997, the
Common Units began trading on the New York Stock Exchange under
the same symbol. The following table sets forth, for the periods
indicated, the high and low closing prices of the Preferred Units
in 1996 and the Common Units in 1997 as reported on the New York
Stock Exchange Composite Tape. No distributions were made with
respect to the Preferred Units, the Old Common Units, or the
Common Units during the past two fiscal years. Information with
respect to accumulated arrearages has been omitted from the
following table since the Amendments cancelled those arrearages
as of the close of business on December 31, 1996.
1996 HIGH LOW
____ ____ ___
First Quarter $ 3-1/2 $ 2-1/8
Second Quarter 5-1/8 2-3/4
Third Quarter 4-1/2 3-3/8
Fourth Quarter 5-3/8 3-3/8
1997
____
First Quarter $ 3-3/4 $ 3-1/4
Second Quarter 3-3/4 2-15/16
Third Quarter 3-3/16 2-7/16
Fourth Quarter 2-1/2 1-9/16
Based on information received from its transfer agent and
servicing agent, the Partnership estimates the number of
beneficial common unitholders of the Partnership at December 31,
1997 to be approximately 3,100.
See "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Financial Condition -
Financial Resources and Liquidity" for a discussion of certain
restrictions imposed by the Partnership's lenders on the payment
of distributions to unitholders throughout the term of the
Partnership's credit facility with such lenders, which terminates
on December 31, 2002.
Item 6. Selected Financial Data
The following table sets forth, for the periods and at the
dates indicated, selected financial data for the Partnership.
The table is derived from the financial statements of the
Partnership and should be read in conjunction with those
financial statements. The summary income statement data for each
of the five years in the period ended December 31, 1997, as well
as the summary balance sheet data for December 31, 1993, 1994,
1995, 1996 and 1997 are all extracted from the audited financial
statements of the Partnership. See also "Management's Discussion
and Analysis of Financial Condition and Results of Operations."
The earnings per share amounts prior to 1997 have been
restated as required to comply with Statement of Financial
Accounting Standards No. 128, Earnings per Share. For further
discussion of earnings per share and the impact of Statement No.
128, see the notes to the consolidated financial statements
beginning on page F-7.
(The following table should be printed on 14" x 8.5" paper)
SELECTED FINANCIAL DATA
(In thousands, except per unit amounts)
Year Ended December 31,
________________________________________________________________
1993 1994 1995 1996 1997
---- ---- ---- ---- ----
Income Statement Data:
Revenues
Refinery and Products Systems $ 253,008 $ 220,610 $ 235,136 $ 294,328 $ 277,179
Crude Gathering System 609,772 553,847 527,212 597,425 494,155
Intrasystem and other (205,518) (184,551) (201,735) (276,550) (236,437)
________ ________ ________ ________ ________
Total revenues 657,262 589,906 560,613 615,203 534,898
________ ________ ________ ________ ________
Costs of sales and operating
expenses, excluding depreciation 636,102 570,877 543,425 596,841 516,146
Refinery closure costs - - - - 41,396
Marketing, general and administrative
expenses 12,834 11,059 10,274 10,111 8,955
Depreciation 5,881 6,546 7,006 6,976 6,872
________ ________ ________ ________ ________
Operating income (loss) 2,445 1,424 (92) 1,275 (38,471)
________ ________ ________ ________ ________
Other net 252 28 175 179 564
Interest expense (3,707) (5,191) (6,575) (5,808) (5,316)
Credit and loan fees (1,138) (1,651) (2,172) (2,109) (1,952)
________ ________ ________ ________ ________
Loss before income taxes and
cumulative effect of change in
accounting principle (2,148) (5,390) (8,664) (6,463) (45,175)
Income tax benefit - - 47 48 144
________ ________ ________ ________ ________
Loss before cumulative effect
of change in accounting principle (2,148) (5,390) (8,617) (6,415) (45,031)
Cumulative effect of change in
accounting principle (3,605) - - - -
________ _______ ________ ________ ________
Net loss $ (5,753) $ (5,390) $ (8,617) $ (6,415) $ (45,031)
======== ======= ======== ======== ========
Before conversion :
Basic and diluted loss per Unit
before cumulative effect:
Preferred Units $ (0.21) $ (0.53) $ (0.85) $ (0.63) -
Old Common Units $ (0.21) $ (0.53) $ (0.85) $ (0.63) -
Cumulative effect on prior years of
changing to LIFO per Unit :
Preferred Units $ (0.36) - - - -
Old Common Units $ (0.36) - - - -
Basic and diluted net loss per Unit:
Preferred Units $ (0.57) $ (0.53) $ (0.85) $ (0.63) -
Old Common Units $ (0.57) $ (0.53) $ (0.85) $ (0.63) -
After conversion :
Basic and diluted loss per Common
Unit before cumulative effect $ (0.43) $ (1.07) $ (1.71) $ (1.27) $ (8.92)
Cumulative effect on prior years of
changing to LIFO per Common
Unit $ (0.71) - - - -
Basic and diluted net loss per
Common Unit $ (1.14) $ (1.07) $ (1.71) $ (1.27) $ (8.92)
Numerator:
Net loss $ (5,753) $ (5,390) $ (8,617) $ (6,415) $ (45,031)
2% general partners' interest (115) (108) (172) (128) (901)
Numerator for basic and diluted
earnings per unit (5,638) (5,282) (8,445) (6,287) (43,230)
Denominator:
Denominator for basic and diluted
earnings per unit before
conversion :
Preferred Units 4,700 4,700 4,700 - -
Old Common Units 5,250 5,250 5,250 - -
Common Units - - - 4,950 4,950
Denominator for basic and diluted
earnings per unit after
conversion :
Common Units 4,950 4,950 4,950 4,950 4,950
Balance Sheet Data (at end of period):
Net property, plant and equipment $ 106,032 $110,884 $ 104,837 $ 99,554 $ 47,588
Total assets 138,562 146,552 138,306 139,716 95,281
Long-term debt (including current
maturities) 50,383 58,890 56,500 56,933 43,171
Redeemable preferred equity 0 0 0 0 19,529
Partners' capital (deficiency) 50,020 44,630 36,013 29,598 (15,433)
Operating Data (BPD):
Refinery
Crude oil throughput 32,215 30,483 29,806 32,555 31,449
Products refined 31,883 29,815 29,031 31,681 30,619
Products System
Transportation volumes 12,719 13,722 15,585 13,509 11,415
Crude Gathering System
Crude oil gathered 77,875 74,676 66,869 58,775 51,305
Refinery closure costs for the year ended December 31, 1997 includes a $40,000,000 noncash charge for impairment of
fixed assets, $1,750,000 related to closure of the Refinery and related severance costs, and $367,000 related to the
writeoff of certain Refinery assets offset by $721,000 in accruals that were reversed as a result of the Refinery being
mothballed.
Credit and loan fees include costs associated with the restructuring of the Partnership of $873,000, $1,064,000, and
$613,000 for 1995, 1996 and 1997, respectively.
This is the cumulative effect on prior years of the change in accounting method for inventory from the First-in/First-
out method to the Last-in/First-out method (LIFO).
On December 31, 1996 after the market closed the Preferred Units were converted to Common Units on a one-for-one basis.
At the same time, the Old Common Units were converted to Common Units on a one-for-twenty-one reverse unit split. The
"Before Conversion" section reflects the per unit information based on both the outstanding Preferred Units and Old
Common Units, whereas the "After Conversion" section reflects the pro forma per unit information based on the
outstanding Common Units.
Calculations exclude 299,996 officer and employee unit appreciation rights and 2,987,000 units attributed to the
redeemable preferred equity because the effect would be antidilutive. Also excludes 70,000 director unit appreciation
rights because the plan states they will be settled for cash.
At December 31, 1993, 1994, 1995, 1996 and 1997 current maturities were $300,000, $6,626,000, $3,447,000, $6,516,000
and $2,084,000, respectively.
/TABLE
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations
Results of Operations
General
The following is a discussion of the financial condition and
results of operations of the Partnership. This discussion should
be read in conjunction with the financial statements included in
this report.
Prior to the TTTI Agreement, the Partnership's operating
results depended principally on the rate of utilization of the
Refinery, the margins between the prices of its refined petroleum
products and the cost of crude oil, the volume throughput on the
Products System, and the volume throughput on and margins from
the transportation and resale of crude oil from its Crude
Gathering System. Higher Refinery utilization allows the
Partnership to spread its fixed costs across more barrels,
thereby lowering the fixed costs per barrel of crude oil
processed. The refining business is highly competitive, and the
Partnership's margins were significantly impacted by general
industry margins. Industry margins are determined by a variety
of regional, national, and global trends, including oil prices,
weather, and economic conditions, among other things. The
Refinery's military aviation fuel prices were influenced by these
trends since the pricing for military aviation fuel is based on
Jet A, a kerosene-based product, and the price of diesel and
heating fuels affect the price of kerosene.
As a result of mothballing the Refinery, the Partnership's
future operating results depend principally on the margins
between the cost at which petroleum products are purchased under
the TTTI agreement and the price realizable by the Partnership
for such products, the volume throughput on the Products System,
and the volume throughput on and margins from the transportation
and resale of crude oil from its Crude Gathering System. The
price the Partnership is able to realize on the resale of its
petroleum products is influenced by the level of competition in
the Partnership's markets. Since the Crude Gathering System will
primarily market crude oil to other refineries, the Partnership
will now operate two separate and distinct industry segments, the
Crude Gathering Systems segment and the marketing and products
pipeline segment.
Margins in the Crude Gathering System are influenced by the
level of competition and the price of crude oil. When prices are
higher, crude oil can generally be resold at higher margins.
Additionally, transportation charges trend upward when higher
crude oil prices stimulate increased exploration and development.
Conversely, when crude oil prices decrease, margins on the resale
of crude oil as well as transportation charges tend to decrease.
The intrasystem pricing of crude oil between the Refinery
and the Crude Gathering System was based in part on an adjusted
Midland spot price for crude oil above the Partnership's posted
price for the purchase of such crude oil (the "Premium"), which
represented the approximate amount above posting that would be
realized on the sale of such crude oil to an unrelated third
party. The total intrasystem price for crude oil between the
Refinery and the Crude Gathering System included the Premium, the
Partnership's posted price and transportation costs. An increase
in the Premium for crude oil had a negative impact on the
Refinery and a positive impact on the Crude Gathering System. On
the other hand, a decrease in the Premium for crude oil had a
positive impact on the Refinery and a negative impact on the
Crude Gathering System. For the years ended December 31, 1997,
1996, and 1995, the average Premium for crude oil was $1.91,
$2.38 and $1.76, respectively.
In evaluating the financial performance of the Partnership,
management believes it is important to look at operating income,
excluding depreciation, in addition to operating income which is
after depreciation. Operating income, excluding depreciation,
measures the Partnership's ability to generate and sustain
working capital and ultimately cash flows from operations.
However, such measure is before debt service, so it does not
indicate the amount available for distribution, reinvestment or
other discretionary uses. Gross revenues primarily reflect the
level of crude oil prices and are not necessarily an accurate
reflection of the Partnership's profitability. Also important to
the evaluation of the Refinery's performance are barrels of crude
oil refined, gross margin (revenue less cost of crude) per
barrel, and operating expenses per barrel, excluding
depreciation.
Year ended December 31, 1997 compared with year ended December
31, 1996
General. Net loss for the year ended December 31, 1997
increased to $45.0 million as compared to $6.4 million for the
year ended December 31, 1996. The results for the year ended
December 31, 1997 included $41.4 million in costs associated with
ceasing Refinery operations. Excluding the $41.4 million of
costs associated with ceasing Refinery operations, net loss was
$3.6 million for the year ended December 31, 1997. The closure
costs included a $40.0 million noncash charge for impairment of
certain Refinery fixed assets, $1.8 million related to the
closure of the Refinery and related severance costs and $367,000
related to the writeoff of certain Refinery assets offset by
$721,000 in accruals that were reversed since the Refinery is
being mothballed. Non-operating expenses decreased $1.0 million
for the year ended December 31, 1997 as compared to the same
period in 1996 due primarily to decreased interest expense and
credit and loan fees and a gain on the sale of the Partnership's
products trucks. Interest expense decreased $492,000 which is
attributable to lower interest rates that became effective upon
approval of the Amendments by the Unitholders. Credit and loan
fees for the year ended December 31, 1996 were reduced by a one-
time nonrecurring reversal of an accrual for facility fees of
$534,000 for periods prior to 1996. Such fees were eliminated by
the Partnership's principal creditors concurrent with the
amendments to the credit agreements in November 1996. For the
year ended December 31, 1997, the Partnership expensed $613,000
related to the restructuring compared to $1.1 million for the
same period in 1996. Depreciation expense was $6.9 million for
the year ended December 31, 1997 compared to $7.0 million for the
year ended December 31, 1996.
Operating loss for the year ended December 31, 1997 was
$38.5 million as compared to operating income of $1.3 million for
the year ended December 31, 1996. Excluding the $41.4 million of
costs associated with ceasing Refinery operations, operating
income was $2.9 million for the year ended December 31, 1997.
The results for the Refinery and Products System, excluding the
costs associated with ceasing Refinery operations, improved due
to strong refining margins. This was partially offset by weak
crude gathering margins. Operating loss, excluding depreciation,
for the year ended December 31, 1997 was $31.6 million as
compared to operating income, excluding depreciation, of $8.3
million for the year ended December 31, 1996. Excluding the
$41.4 million of costs associated with ceasing Refinery
operations, operating income, excluding depreciation, was $9.8
million for the year ended December 31, 1997.
Refinery and Products System. Operating loss for the
Refinery and Products System was $40.9 million for the year ended
December 31, 1997 compared to $7.7 million for the year ended
December 31, 1996. Excluding the $41.4 million of costs
associated with ceasing Refinery operations, operating income for
the Refinery and Products System was $537,000 for the year ended
December 31, 1997. The results for the Refinery and Products
System, excluding the costs associated with ceasing Refinery
operations, improved due to stronger refining margins.
Depreciation expense for the Refinery and Products System was
$5.0 million for both the year ended December 31, 1997 and for
the year ended December 31, 1996. Operating loss, excluding
depreciation, of the Refinery and Products System was $35.9
million for the year ended December 31, 1997 compared to $2.7
million for the year ended December 31, 1996. Excluding the
$41.4 million of costs associated with ceasing Refinery
operations, operating income, excluding depreciation, for the
Refinery and Products System was $5.5 million for the year ended
December 31, 1997.
Operating income for the Products System decreased to
$655,000 for the year ended December 31, 1997 from $1.2 million
for the year ended December 31, 1996. Depreciation expense for
the Products System decreased to $870,000 for the year ended
December 31, 1997 from $880,000 for the year ended December 31,
1996. Operating income, excluding depreciation, for the Products
System decreased to $1.5 million for the year ended December 31,
1997 from $2.1 million for the year ended December 31, 1996 as a
result of decreased transportation volumes on the San Angelo
pipeline. Transportation volumes decreased to 11,415 BPD for the
year ended December 31, 1997 from 13,509 BPD for the year ended
December 31, 1996.
Operating loss for the Refinery alone was $41.5 million for
the year ended December 31, 1997 compared to an operating loss of
$8.9 million for the same period in 1996. Excluding the $41.4
million of costs associated with ceasing Refinery operations,
operating loss for the Refinery was $51,000 for the year ended
December 31, 1997. Depreciation expense for the Refinery was
$4.1 million for both the years ended December 31, 1997 and 1996.
Operating loss, excluding depreciation, of the Refinery alone was
$37.4 million for the year ended December 31, 1997 compared to
operating loss, excluding depreciation, of $4.8 million for the
year ended December 31, 1996. Excluding the $41.4 million of
costs associated with ceasing Refinery operations, operating
income, excluding depreciation, for the Refinery was $4.0 million
for the year ended December 31, 1997.
Refinery gross margin per barrel was $1.76 for the year
ended December 31, 1997 compared to $1.09 for the year ended
December 31, 1996. The increase in the gross margin for the year
ended December 31, 1997 reflects the decline in the Premium for
crude oil, the increased margin on the military aviation fuel
sold to the government under the contract that began April 1,
1997, and the lower residuum yield experienced in 1997. The
lower residuum yield positively affects the Partnership since the
value of residuum is substantially lower than other refined
products that the Partnership sells. The residuum increased in
1996 as a result of the Refinery running a slightly heavier slate
of crude. Towards the end of 1996, the Partnership began running
a lighter slate of crude which resulted in a decreased residuum
yield in 1997. Refinery throughput averaged 31,449 BPD during
the year ended December 31, 1997 compared to 32,555 BPD for the
year ended December 31, 1996. Operating expenses per barrel,
excluding depreciation, increased to $4.61 for the year ended
December 31, 1997 from $1.09 for the year ended December 31,
1996. Excluding the $41.4 million of costs associated with
ceasing Refinery operations, operating expenses per barrel,
excluding depreciation, were $1.00 for the year ended December
31, 1997.
Crude Gathering System. Operating income for the Crude
Gathering System was $2.4 million for the year ended December 31,
1997 compared to $8.9 million for the year ended December 31,
1996 due to a decline in crude gathering margins. The Premium
for crude oil sold to the Refinery was substantially lower for
the year ended December 31, 1997 than the same period in 1996,
but the amount paid above posting for such crude oil to third
parties did not decrease accordingly. The amount paid above
posting for crude oil to third parties should decrease in the
future assuming the crude oil market's expectation for a high
Premium diminishes. Depreciation expense for the Crude Gathering
System decreased to $1.9 million for the year ended December 31,
1997 from $2.0 million for the year ended December 31, 1996.
Operating income, excluding depreciation, for the Crude Gathering
System decreased to $4.3 million for the year ended December 31,
1997 from $10.9 million for the year ended December 31, 1996.
Due to the elimination of several marginal contracts, the volume
of crude oil gathered by the Crude Gathering System decreased to
51,305 BPD for the year ended December 31, 1997 from 58,775 BPD
for the year ended December 31, 1996. For the year ended
December 31, 1997, net margin decreased to $0.13 per barrel from
$0.42 per barrel for the year ended December 31, 1996 resulting
from the lower Premium and the higher acquisition cost above
posting for crude oil during the year ended December 31, 1997.
Year ended December 31, 1996 compared with year ended
December 31, 1995
General. Net loss for the year ended December 31, 1996
decreased to $6.4 million as compared to a net loss of $8.6
million for the year ended December 31, 1995. The improvement
was a result of improved operations and lower non-operating
expenses. Non-operating expenses decreased $834,000 for the year
ended December 31, 1996 over the same period in 1995 due
primarily to decreased interest expense and credit and loan fees.
Of the decrease, $767,000 is related to lower interest expense
which is attributable to a lower average prime rate in 1996
compared to the 1995 average and the lowered interest rates in
the new credit agreement. Also, the credit and loan fees for the
year ended December 31, 1996 have been reduced by a one-time
nonrecurring reversal of an accrual for facility fees of $534,000
for periods prior to 1996 compared to a $234,000 reversal in 1995
for periods prior to 1995. Such fees were eliminated by the
Partnership's principal creditors concurrent with the amendments
to the credit agreements in November 1996 and August 1995. For
the year ended December 31, 1996, the Partnership expensed $1.1
million related to the restructuring compared to $873,000 for the
same period in 1995. Depreciation expense was $7.0 million for
both the years ended December 31, 1996 and 1995.
Operating income for the year ended December 31, 1996
increased to $1.3 million as compared to an operating loss of
$92,000 for the year ended December 31, 1995. The improved
results for the year ended December 31, 1996 were due to
significantly stronger crude gathering margins resulting from the
higher Premium for crude oil, partially offset by weak refining
margins. Operating income, excluding depreciation, increased for
the year ended December 31, 1996 to $8.3 million as compared to
$6.9 million for the year ended December 31, 1995.
Refinery and Products System. Operating loss for the
Refinery and Products System was $7.7 million for the year ended
December 31, 1996 compared to an operating loss of $3.9 million
for the year ended December 31, 1995. Depreciation expense for
the Refinery and Products System was $5.0 million for both the
year ended December 31, 1996 and the year ended December 31,
1995. Operating loss, excluding depreciation, of the Refinery
and Products System was $2.7 million for the year ended December
31, 1996 compared to operating income, excluding depreciation, of
$1.1 million for the year ended December 31, 1995.
Operating income for the Products System decreased to $1.2
million for the year ended December 31, 1996 from $1.7 million
for the year ended December 31, 1995. Depreciation expense for
the Products System increased to $880,000 for the year ended
December 31, 1996 from $874,000 for the year ended December 31,
1995. Operating income, excluding depreciation, for the Products
System decreased to $2.1 million for the year ended December 31,
1996 from $2.6 million for the year ended December 31, 1995
resulting from decreased transportation volumes. Transportation
volumes decreased to 13,509 BPD for the year ended December 31,
1996 from 15,585 BPD for the year ended December 31, 1995.
Operating loss for the Refinery alone was $8.9 million for
the year ended December 31, 1996 compared to an operating loss of
$5.6 million for the same period in 1995. Depreciation expense
for the Refinery was $4.1 million for both the years ended
December 31, 1996 and 1995. Operating loss, excluding
depreciation, of the Refinery alone was $4.8 million for the year
ended December 31, 1996 compared to operating loss, excluding
depreciation, of $1.5 million for the year ended December 31,
1995.
Refinery gross margin per barrel was $1.09 for the year
ended December 31, 1996 compared to $1.42 for the year ended
December 31, 1995. The decrease in the gross margin reflects the
increased Premium for crude oil, the decreased margin on the
military aviation fuel sold to the government under the contract
that began April 1, 1996, and the increased residuum yield
experienced in 1996. The increased residuum yield negatively
affects the Partnership since the value of residuum is
substantially lower than other refined products that the
Partnership sells. The residuum increased in 1996 as a result of
the Refinery running a slightly heavier slate of crude. Towards
the end of 1996, the Partnership began running a lighter slate of
crude which has resulted in a decreased residuum yield. Refinery
throughput averaged 32,555 BPD during the year ended December 31,
1996 compared to 29,806 BPD for the year ended December 31, 1995.
The Partnership was able to operate the refinery at a higher
throughput for the year ended December 31, 1996 due to the new
gas oil contract signed in early 1996. Operating expenses per
barrel, excluding depreciation, increased to $1.09 for the year
ended December 31, 1996 from $1.07 for the year ended December
31, 1995 due to increased utility costs and maintenance costs
during 1996.
Crude Gathering System. Operating income for the Crude
Gathering System was $8.9 million for the year ended December 31,
1996 compared to $3.8 million for the year ended December 31,
1995. Depreciation expense for the Crude Gathering System
decreased to $2.0 million for the year ended December 31, 1996
from $2.1 million for the year ended December 31, 1995.
Operating income, excluding depreciation, for the Crude Gathering
System increased to $10.9 million for the year ended December 31,
1996 from $5.8 million for the year ended December 31, 1995. Due
to the elimination of several marginal contracts, the volume of
crude oil gathered by the Crude Gathering System decreased to
58,775 BPD for the year ended December 31, 1996 from 66,869 BPD
for the year ended December 31, 1995. For the year ended
December 31, 1996, net margin increased to $0.42 per barrel from
$0.15 per barrel for the year ended December 31, 1995 resulting
from the higher Premium for crude oil for the year ended December
31, 1996.
Factors and Trends Affecting Operating Results
A number of factors have affected the Partnership's
operating results, both indirectly and directly, such as
environmental compliance, other regulatory requirements, industry
trends, price of crude oil, inventory prices, and, with respect
to certain products, seasonality and weather. The Managing
General Partner expects that such conditions will continue to
affect the Partnership's business to varying degrees in the
future. The order in which these factors are discussed is not
intended to represent their relative significance.
Environmental Compliance. Increasing public and
governmental concern about air quality is expected to result in
continued regulation of air emissions. Regulations relating to
carbon monoxide and regulations on oxygen content in gasoline and
sulfur content in diesel fuel are expected to be increasingly
important in urban areas. See "Business and Properties --
Environmental Matters." In addition, the Partnership plans to
spend up to approximately $1.5 million in 1998 and 1999 on
several projects to maintain compliance with various other
environmental requirements including approximately $1.2 million
related to mothballing the Refinery.
Effective January 1, 1995, the Clean Air Act Amendment of
1990 required that certain areas of the country use reformulated
gasoline ("RFG"). The Abilene and San Angelo market areas do not
require RFG. Collin, Dallas, Denton, and Tarrant Counties, which
comprise the Dallas-Fort Worth ("DFW") metroplex area, do require
RFG; however, the Partnership's Aledo terminal lies outside this
area and is allowed to supply conventional gasoline that is not
destined for sale in these four counties. In addition to the
requirement for RFG in certain areas, new but much less
restrictive regulations took effect that impose new quality
standards for conventional gasoline in the rest of the country.
Management does not anticipate that these have had or will have a
material adverse effect on the Partnership's operations.
Other Regulatory Requirements. The Partnership is subject
to the rules and regulations of Occupational Safety and Health
Administration, Texas Air Control Board, Texas Railroad
Commission, and Texas Water Commission.
Industry Trends and Price of Crude Oil. Industry trends and
the price of crude oil will continue to affect the Partnership's
business. In the last three years, the posting price for WTI
crude oil has varied from approximately $11.00 to $25.00 per
barrel. While refined products are generally sold at a margin
above crude oil prices, fluctuations in the price of crude oil
can have a significant short-term effect on refining margins
because there is usually a lag in the movement of product prices,
both up and down, after a change in crude oil prices. As a
result of purchasing product from TTTI, the Partnership will be
impacted by fluctuations in the cost of those products versus
fluctuations in the price realized by the Partnership on the sale
of such products and the amount of competition in its markets.
The general level of crude oil prices can also have a significant
effect on the margins in the crude gathering business. Margins
in the Crude Gathering System generally tend to be influenced by
competition and the general price level of crude oil. When
prices are higher, crude oil can generally be resold at higher
margins. Additionally, transportation charges are slightly less
competitive when higher crude oil prices result in increased
exploration and development. Conversely, when oil prices
decrease, margins on the resale of crude oil and transportation
charges generally tend to decrease.
Inventory Prices. The Partnership utilizes the last-
in/first-out (LIFO) method of determining inventory values. LIFO
minimizes the effect of fluctuations in inventory prices on
earnings by matching current costs with current revenue. The
LIFO method is the predominant method used in the refining
industry.
Seasonality and Weather. Gasoline consumption is typically
highest in the United States in the summer months and lowest in
the winter months. Diesel consumption in the southern United
States is generally higher just prior to and during the winter
months when commercial trucking is routed on southern highways to
avoid severe weather conditions further north.
Other Factors. The Partnership has entered into five
exchange agreements and three sales agreements with major oil
companies in the Abilene, San Angelo and Aledo markets. These
exchange agreements have allowed Pride to expand into Amarillo,
Texas, El Paso, Texas, Lubbock, Texas, Midland/Odessa, Texas, and
Wichita Falls, Texas without incurring transportation costs to
these cities.
The United States Government awarded the Partnership the
right to supply 52,510,000 gallons of military aviation fuel for
the contract period that begins April 1, 1998 and ends March 31,
1999. The award is for deliveries to Dyess, Sheppard Air Force
Base in Wichita Falls, Texas, Naval Air Station Fort Worth in
Fort Worth, Texas, Fort Hood Military Installation in Killeen,
Texas, and E-Systems in Greenville, Texas. The contract is for
approximately 51% of the volumes under the prior contract due to
the Partnership no longer being considered a small business and
thus not being allowed to match the price of the lowest large
business. Under the new contract, the prices awarded compared to
the base reference price net of transportation for such military
aviation fuel improved an average of approximately 2 cents from
last year's contract which partially offsets the reduced volumes.
See "Partnership Operations and Products."
Financial Condition
Inflation
The Partnership's operations would be adversely impacted by
significant, sustained increases in crude oil and other energy
prices. Although the Partnership's operating costs are generally
impacted by inflation, the Managing General Partner does not
expect general inflationary trends to have a material adverse
impact on the Partnership's operations.
Financial Resources and Liquidity
The Partnership receives payments from the United States
Government, major oil companies, and other customers within
approximately 7 to 15 days from shipment in the case of product
sales and by the 20th of the following month in the case of
third-party crude oil sales and exchanges. The Partnership
maintains refined products inventory in the amount of
approximately 5 to 10 days of sales and crude inventory of
approximately 10 to 15 days of sales. The Partnership will pay
for the refined products 10 days after receipt from TTTI and
crude oil feedstock on the 20th of the month following the month
in which it is received. As a result, the Partnership's
operating cycle is such that there is a lag on when it receives
payment for the refined products versus when it pays for such
products. Letters of credit are an integral part of the
operations of the Crude Gathering System since the Partnership
takes title to both first purchased barrels and custom gathered
barrels.
Restructuring and Recapitalization Plan. On December 31,
1997, the final phase of the restructuring and recapitalization
of the Partnership's debt and equity was completed as described
in the Partnership's 1996 consent solicitation. The initial
phase called for the execution of documents with the
Partnership's previous bank lenders and was completed on August
13, 1996. Effective December 31, 1996, the Unitholders adopted
the Amendments to the Partnership Agreement which included
conversion of the outstanding preferred units into common units
and the cancellation of all preferred and common unit arrearages.
As part of the 1996 restructuring plan, the previous lenders
converted a portion of their term loan into notes, lowered
certain interest rates and credit and loan fees and extended the
maturity. Varde Partners, Inc. ("Varde") assumed the rights and
obligations of the previous lenders in the Old Bank Debt,
BankBoston, N.A. ("BankBoston") subsequently provided the
Partnership with a letter of credit facility and a term loan
commitment of $21.0 million, and Pride SGP converted two notes
into redeemable preferred equity securities. During 1997, 1996
and 1995, the Partnership expensed $613,000, $1,064,000 and
$873,000, respectively, related to the restructuring and
recapitalization. The Partnership also capitalized $6.6 million
of fees and other costs including $3.3 million in noncash fees in
1997 related to the restructuring and recapitalization and has
included $1.3 million in prepaid expenses and $5.3 million in
deferred financing costs on the December 31, 1997 balance sheet.
Refinancing of Revolver, Term Loan, Convertible Notes and
Letter of Credit Facility. On December 31, 1997, Varde purchased
and assumed the lenders' rights and obligations under the
Partnership's Old Bank Debt (as defined below). In conjunction
with Varde's purchase and assumption of the lenders' rights and
obligations under the Old Bank Debt, BankBoston refinanced the
Partnership's letter of credit and revolver facilities (the "New
Revolver") on December 31, 1997 and agreed to fund $21.0 million
of term financing at a future date (the "Proposed Term Loan"), in
each case for a 5-year term.
The New Revolver from BankBoston provides for the issuance
of letters of credit to third parties to support the
Partnership's purchase or exchange of crude oil and petroleum
products, in an aggregate amount not to exceed $65.0 million,
with a sublimit of $10.0 million for direct cash borrowings for
general working capital purposes. Amounts available under the
New Revolver are subject to a borrowing base calculated as the
sum of the Partnership's cash and cash equivalents, certain
receivables, deposits, inventory and other amounts, reduced by a
portion of crude oil royalties payable and certain other amounts
payable.
Though no advances had been drawn under the letter of credit
facility at December 31, 1997, the Partnership did have
approximately $36.4 million in outstanding letters of credit to
cover the letters of credit outstanding with the previous banks.
The fee on outstanding letters of credit was 2.75% per annum as
of December 31, 1997. There is also an issuance fee of 0.125%
per annum on the face amount of each letter of credit. The fee
for the unused portion of the New Revolver is 0.5% per annum. At
the Partnership's discretion, cash borrowings under the New
Revolver at December 31, 1997 bore interest at either LIBOR plus
3.25% or prime plus 2%. LIBOR and the prime rate were 5.625% and
8.5%, respectively, at December 31, 1997. The credit agreement
evidencing the New Revolver also requires the Partnership to pay
an agency fee of up to $70,000 per annum depending on the number
of participants in the credit facility and restricts the payment
of distributions to unitholders throughout the term of the credit
agreement.
If and when funded, the Proposed Term Loan would be expected
to be used to refinance a $20.0 million bridge loan held by Varde
and to provide an additional $1.0 million for general working
capital purposes. The Partnership pays 0.5% per annum for the
Proposed Term Loan commitment.
On December 31, 1997, Varde assumed the rights and
obligations of the previous lenders, which equaled $45.8 million
and made an additional new loan of $4.7 million ("New Loan") (the
"Closing"). As of the Closing, the prior bank debt consisted of
(i) a standby letter of credit facility (the "Old LC Facility"),
(ii) a $12.0 million revolving line of credit, of which $6.9
million was outstanding (the "Old Revolver"), (iii) a $22.0
million term loan (the "Old Term Loan") and (iv) three series of
convertible senior secured notes in an aggregate principal amount
of $16.8 million (the "Old Convertible Notes," consisting of the
"Old Series A Note," the "Old Series B Note" and the "Old Series
C Note"). (The Old Revolver, Old Term Loan and Old Convertible
Notes are collectively the "Old Bank Debt".) As of the Closing,
no advances had been drawn under the Old LC Facility, which had
approximately $36.4 million in outstanding letters of credit.
The Managing General Partner and Pride SGP were guarantors of the
Old Bank Debt and have guaranteed the Partnership's obligations
to Varde and BankBoston. Substantially all of the Partnership's
assets were pledged as collateral in connection with the credit
agreements, and Pride SGP had pledged its assets at no cost to
the Partnership as additional collateral for such debt.
As a result of Varde's assumption of the Old Bank Debt and
the New Loan, Varde holds a term loan of $20.0 million ("A Term
Loan"), a term loan of $9.5 million ("B Term Loan"), a term loan
of $4.7 million ("C Term Loan") and an unsecured note of $2.5
million ("Subordinate Note A"). The A Term Loan bears interest
rates of 11% in the first two years and 13% in the third year,
15% in the fourth and 17% in the fifth year. The B Term Loan and
C Term Loan bear interest rates of 11% in the first three years,
13% in the fourth year and 15% in the fifth year except
$3,000,000 of the B Term Loan which is subject to interest rates
of 12% through maturity. If the A Term Loan is not repaid with
borrowings under the Proposed Term Loan or otherwise, the
interest rates applicable to the A Term Loan, B Term Loan and C
Term Loan would be 11%, 13%, 15%, 17% and 19% for the first,
second, third, fourth and fifth years, respectively, during all
or any portion of the period after February 1998 that the A Term
Loan is held by Varde, except $3.0 million of the B Term Loan
which is subject to interest rates of 18% through maturity. The
Subordinate Note A is convertible into 397,000 Common Units and
bears interest at prime plus one percent.
The cash interest and dividend payments on the B Term Loan,
C Term Loan, Subordinate Note A and the redeemable preferred
equity held by Varde are limited to $90,833 per month or $1.1
million annually. To the extent the interest and dividends on
the various Varde securities exceed the cap on cash payments,
such excess will be paid in kind. The A Term Loan is due December
31, 2002. The B Term Loan, C Term Loan and Subordinate Note A
are due December 31, 2002 if the A Term Loan has not been
refinanced, otherwise 180 days after the maturity of the Proposed
Term Loan, but no later than June 30, 2003 if the A Term Loan has
been refinanced. The Partnership is required to make quarterly
principal payments on the A Term Loan as set forth in the Varde
credit agreement as well as make payments of excess cash flow for
the preceding year. Accordingly, the Partnership has classified
$1.5 million of the A Term Loan as current as of December 31,
1997. The Partnership will not have to make principal payments
prior to the scheduled maturity on the B Term Loan, C Term Loan
and Subordinate Note A except in the case the Partnership
receives proceeds related to the DFSC Claim and certain other
transactions. See "Legal Proceedings."
Under the prior credit facility, the Partnership had a $6.5
million standby letter of credit facility for general corporate
purposes and the purchase of crude oil and other refinery
feedstocks and a $42.5 million standby letter of credit facility
for the purchase of crude oil. The fee on outstanding standby
letters of credit was 1.5% per annum. For the unused portion of
the standby letter of credit facility, the fee was 0.5% per
annum. Though no advances had been drawn under either facility,
the Partnership did have approximately $721,000 and $35.7
million, respectively, in outstanding standby letters of credit
at December 31, 1997 which were backed by a letter of credit
issued by BankBoston in the same amount. The prior credit
agreement also provided, at the banks' discretion, an additional
$8.0 million standby letter of credit facility for the purchase
of crude oil and other refinery feedstocks. The Partnership had
no outstanding letters of credit under such facility as of
December 31, 1997.
During the year ended December 31, 1997, the Partnership had
drawn up to approximately $8.5 million on the Revolver and Old
Revolver (collectively, the "Revolvers"). The weighted average
amount outstanding under the Revolvers was approximately $3.8
million. The weighted average interest rate during the 1997
period for these facilities was approximately 10.0%. During the
year ended December 31, 1996, the Partnership had drawn up to
approximately $7.3 million on the Old Revolver and $2.0 million
on an uncommitted line (the "Uncommitted Line"); the weighted
average amount outstanding under the Old Revolver and Uncommitted
Line was approximately $1.1 million and $21,000, respectively.
The weighted average interest rate during the 1996 period for
these facilities was approximately 10.5%.
Advances under the Old Revolver and Old Term Loan accrued
interest at prime plus 1.5% and 2%, respectively, payable
monthly. The prime rate was 8.5% as of December 31, 1997. The
Old Convertible Notes issued to the lenders under the credit
facility consisted of $2.5 million in Convertible Senior Secured
Series A Promissory Notes ("Old Note A"), $9.3 million in
Convertible Senior Secured Series B Promissory Notes ("Old Note
B"), and $5.0 million in Convertible Senior Secured Series C
Promissory Notes ("Old Note C"). The Old Convertible Notes
accrued interest at prime plus 1% payable monthly.
The Partnership or management has a three-year call on
Varde's position for an amount equal to a 40% return to Varde,
subject to a minimum payment of $7.5 million over Varde's cost.
The securities held by Varde will have certain antidilution
provisions and registration rights. Any litigation proceeds
received by the Partnership related to the DFSC Claim will be
used to retire up to $6.0 million of either the A Term Loan or
the Proposed Term Loan, whichever is then outstanding, and up to
$5.0 million of either the B Term Loan or New Series A Preferred,
whichever is then outstanding, with any excess divided one-third
to Varde to be used to retire Varde's most senior securities and
two-thirds to the Partnership.
At the Closing, certain members of management agreed to
invest an aggregate of $2.0 million in the form of a note payable
to Varde and will receive a one-third economic non-directive
interest in $6.0 million of the B Term Loan, C Term Loan,
Subordinate Note A, Series B Preferred Units, Series C Preferred
Units and Series D Preferred Units. The note payable to Varde
will be secured by management's interest in such securities. Any
cash yield on management's share of such securities will be paid
to Varde as interest, net of applicable federal income tax.
Other Indebtedness. The Partnership had two outstanding
financing agreements to fund working capital with Pride SGP which
were entered into on March 26, 1993 and September 7, 1995. Pride
SGP made the unsecured loans to the Partnership in the aggregate
principal amount of $2.5 million bearing interest at prime plus
1%. On December 31, 1997, Pride SGP agreed to convert the two
notes into redeemable preferred equity securities.
Other installment loans include a $6.0 million nonrecourse
note, due 2014, payable monthly with interest at 8% and a balance
of $5.7 million at December 31, 1997. The note is supported by a
minimum throughput agreement. The assets of Pride Borger, Inc.,
a wholly-owned subsidiary of the Partnership, are pledged as
collateral. Monthly principal payments are based on the number
of throughput barrels. The Partnership has classified $146,000
as current at December 31, 1997.
The Partnership converted certain non-interest bearing
accounts payable to the U. S. Government Defense Fuel Supply
Center related to pricing adjustments which had been accrued
since 1993 to a $2.4 million installment loan, payable in monthly
installments of $84,000, with a balance of $420,000 at December
31, 1997. The loan bears interest based on the rate set semi-
annually by the Secretary of the Treasury. This rate was 6.75%
as of December 31, 1997. The Partnership has classified the
entire balance as current.
Conversion of Debt by Pride SGP into Preferred Equity. At
the Closing, Pride SGP agreed to convert (i) a $2.0 million note
of the Partnership payable to Pride SGP to Series E Cumulative
Convertible Preferred Units ("Series E Preferred Units") which is
convertible into 317,000 Common Units and (ii) a $450,000 note
owed to Pride SGP into Series F Cumulative Preferred Units
("Series F Preferred Units"). The Series E Preferred Units and
Series F Preferred Units will be subordinated to the Series B
Preferred Units, Series C Preferred Units and Series D Preferred
Units. The preferential quarterly payments on the Series E
Preferred Units and Series F Preferred Units will be 6% per annum
in the first three years after issuance, 12% per annum in the
fourth and fifth years and 15% per annum thereafter or may be
paid in kind at 8% per annum in the first three years, 12% per
annum in the fourth and fifth years and 15% per annum thereafter
until mandatory redemption at December 31, 2002. Upon funding of
the Proposed Term Loan, the maturity will be extended 180 days
past the maturity of the Proposed Term Loan but no later than
June 30, 2003.
Amendment to Pipeline Lease Agreement. In connection with
the Varde transaction, Pride SGP agreed to amend that certain
Pipeline Lease Agreement dated March 29, 1990, between Pride SGP
and the Partnership to provide that during the term of the Varde
indebtedness, the aggregate annual consideration payable by the
Partnership for use of the reactivated portion of the pipeline
would be capped at $400,000 unless Varde otherwise agreed.
Varde Equity Participation. At the Closing, Varde received
preferred equity securities including $9.3 million of Series B
Cumulative Convertible Preferred Units ("Series B Preferred
Units"), $5.0 million of Series C Cumulative Convertible
Preferred Units ("Series C Preferred Units") and $2.8 million of
Series D Cumulative Preferred Units ("Series D Preferred Units")
which initially mature December 31, 2002. On funding of the
Proposed Term Loan, the maturity date of the preferred equity
securities would be extended 180 days past the maturity of the
Proposed Term Loan but no later than June 30, 2003. The Series B
Preferred Units and Series C Preferred Units are convertible into
1,480,000 and 793,000 Common Units, respectively. The
preferential quarterly payments on the Series B Preferred Units
and Series C Preferred Units will be 6% per annum in the first
three years after issuance, 12% per annum in the fourth and fifth
years and 15% per annum thereafter or may be paid in kind at 8%
per annum in the first three years, 12% per annum in the fourth
and fifth years and 15% per annum thereafter. The preferential
quarterly payments on the Series D Preferred Units will be 11%
per annum in the first three years after issuance, 13% per annum
in the fourth and fifth years and 15% per annum thereafter or be
paid in kind through maturity at 13% per annum in the first five
years and 15% per annum thereafter. Any payments of principal on
the securities held by Varde shall be applied in the following
order: A Term Loan (if then outstanding), B Term Loan, C Term
Loan, Subordinate Note A, Series B Preferred Units, Series C
Preferred Units, and Series D Preferred Units.
Future Stages of the Varde Transaction, Proposed
Restructuring. The documentation under which Varde acquired the
Old Bank Debt contemplated two possible future transactions.
First, if and when the Proposed Term Loan is funded, such
proceeds will be used to retire Varde's A Term Loan for $20.0
million and an additional $1.0 million in borrowings will be made
available for working capital purposes.
Second, Varde has proposed an additional restructuring of
its investment ("Restructuring") that could further reduce the
Partnership's bank debt in connection with the authorization and
issuance of new preferred equity, which would in turn be
convertible into Common Units, if approved by the unitholders
pursuant to a consent solicitation on or before October 1, 1999
(the "Restructuring Consent Solicitation"). Subject to
unitholder authorization of additional preferred equity in
connection with the Restructuring Consent Solicitation, Varde has
agreed to exchange a total of $33.8 million of debt and preferred
equity securities composed of $9.5 million of B Term Loan, $4.7
million of C Term Loan, $2.5 million of Subordinate Note A, $9.3
million of Series B Preferred Units, $5.0 million of Series C
Preferred Units and $2.8 million of Series D Preferred Units
(including any paid in kind distributions on these instruments)
for the following series of newly authorized redeemable preferred
equity:
(i) Nonconvertible preferred equity in the amount of
$9.5 million ("New Series A Preferred Units")
which includes $500,000 that was Varde's
transaction fee for bridging the A Term Loan,
(ii) Convertible preferred equity in the amount of $2.5
million ("New Series B Preferred Units"), which
would be convertible into 10% of the Common Units
outstanding, and
(iii) Convertible preferred equity in the amount of $2.5
million ("New Series C Preferred Units") which
would be convertible into an additional 42% of the
Common Units outstanding, plus an additional 8% of
the Common Units for Varde's account if the A Term
Loan continues to be held by Varde.
As part of the proposed Restructuring, Pride SGP will be asked,
subject to unitholder approval, to approve the Partnership
recapitalization and convert $2.4 million of claims and the
Series E Preferred Units and Series F Preferred Units into a
total of 7.5% of the outstanding Common Units.
If all requisite unitholder consents are received and all
proposed transactions are consummated, including the
restructuring of certain claims of Pride SGP and the
authorization and issuance of additional preferred equity, Varde
will convert the $33.8 million of debt and equity securities that
it holds of the Partnership into $14.5 million of newly
authorized equity securities.
Operations. Cash flows have been and will continue to be
significantly affected by fluctuations in the cost and volume of
crude oil and refined products held in inventory and the timing
of accounts receivable collections. For the year ended December
31, 1997, cash was provided by a decrease in accounts receivable
(resulting from lower crude oil prices and refined product
prices) and a decrease in inventories (resulting from the lower
inventory levels). This was partially offset by a decrease in
accounts payable (resulting from the lower crude oil prices).
For the year ended December 31, 1996, cash was provided by
increases in accounts payable (resulting from higher crude oil
prices). This was partially offset by an increase in inventory
(resulting from an increase of volumes on hand) and increases in
accounts receivable (resulting from the higher crude oil prices
and refined product prices).
The Partnership is currently not in compliance with certain
covenants under its credit agreements with BankBoston and Varde
due to the $40.0 million noncash charge for impairment of fixed
assets. The Partnership had originally estimated the impairment
to be a maximum of $30.0 million and had the covenant set based
on that original estimate. As a result of the additional $10.0
million impairment, the Partnership is in violation of certain
covenants and obtained waivers.
The Partnership has incurred recurring operating losses and
has working capital and partners' deficiencies. In addition, the
Partnership has not historically complied with certain of the
financial and performance covenants included in its credit
facilities with lenders and management and is not certain whether
the Partnership will be able to comply with various financial
covenants contained in these credit facilities throughout 1998.
Although the Partnership intends to request waivers from such
lenders, it is not certain that certain waivers will be granted.
Such covenant violations could enable the lenders to notice a
default and to accelerate the Partnership's loans with such
lenders. The ability of the Partnership to operate in future
periods may be adversely affected by these conditions.
The net loss for the year ended December 31, 1997 increased
from December 31, 1996; however, excluding the $41.4 million in
costs associated with ceasing refining operations, the loss for
December 31, 1997 decreased to $3.7 million as a result of
stronger refining margins. This was partially offset by weak
crude gathering margins during 1997. Under the new military
aviation fuel contract with the U. S. Government which begins
April 1, 1998 and ends March 31, 1999, the Partnership will
supply approximately 51% of the volumes that it supplied under
the contract which began April 1, 1997 and ends March 31, 1998;
however, the prices awarded compared to the base reference price
net of transportation under this contract are an average of
approximately 2 cents per gallon higher than the prices in the
previous contract which partially offsets the reduced volumes.
Since 1993, the Partnership has been able to achieve continuous
reductions in marketing, general and administrative expenses.
The move of the Partnership's corporate offices has resulted in a
cost reduction since the beginning of 1995. Also, during 1995,
certain initiatives were taken to reduce crude gathering costs.
The Partnership's ability to generate profits is principally
dependent upon increased volumes and/or improved profit margins,
as well as continued cost control initiatives. The ability to
generate profits could be affected if other Gulf Coast refiners
bring refined products into West Texas from the Gulf Coast via
pipeline. Though management has and will continue to pursue
options regarding increasing volumes and margins and reducing
costs, including limiting any significant capital expenditures,
these improvements, if achieved, will be gradual and, in many
cases, will take sustained periods of time to implement in order
to achieve profitability. As a result, management is also
reviewing other strategic alternatives including redeployment of
its operating assets, possible asset sales and alliances with
other companies.
1996 Amendments. The Amendments to the Agreement of Limited
Partnership ("Partnership Agreement") for the Partnership were
submitted to the preferred unitholders, common unitholders and
the Special General Partner pursuant to a Consent Solicitation
Statement dated October 7, 1996 (the "1996 Consent
Solicitation"). The Amendments modified the capital structure of
the Partnership. Generally, the Amendments provided for the
Partnership's Preferred Units and the Partnership's Old Common
Units to be treated as a single class of limited partner units
with identical rights and privileges, and the elimination of
certain existing contingent distribution preferences of the
General Partners. The Amendments resulted in the elimination of
the respective cumulative distribution arrearages of both the
outstanding Preferred and Old Common Units and the elimination of
distribution and liquidation preferences attributable to such
Preferred Units. The Amendments also provided that the
outstanding Old Common Units would be subject to a 1 for 21
reverse unit split.
The Amendments also included certain other changes to the
Partnership Agreement including the terms of certain new
redeemable preferred equity securities which were issued to the
Partnership's bank lenders in lieu of payment for certain
Partnership debt when the Partnership successfully refinanced its
existing credit facility with other third party creditors in
December 1997.
Capital Expenditures
Maintenance capital expenditures additions totaled $2.1
million for the year ended December 31, 1997 compared to $1.9
million for the year ended December 31, 1996.
Year 2000 Compliance
The Partnership has determined that it will need to modify
or replace significant portions of its software so that its
computer systems will function properly with respect to dates in
the year 2000 and beyond. The Partnership also has initiated
discussions with its significant suppliers, large customers and
financial institutions to ensure that those parties have
appropriate plans to remediate Year 2000 issues where their
systems interface with the Partnership's systems or otherwise
impact its operations. The Partnership is assessing the extent
to which its operations are vulnerable should those organizations
fail to remediate properly their computer systems.
The Partnership's comprehensive Year 2000 initiative is
being managed by a team of internal staff and outside
consultants. The team's activities are designed to ensure that
there is no adverse effect on the Partnership's core business
operations and that transactions with customers, suppliers, and
financial institutions are fully supported. The Partnership is
well under way with these efforts, which are scheduled to be
completed in early 1999. While the Partnership believes its
planning efforts are adequate to address its Year 2000 concerns,
there can be no guarantee that the systems of other companies on
which the Partnership's systems and operations rely will be
converted on a timely basis and will not have a material effect
on the Partnership. The cost of the Year 2000 initiatives is not
expected to be material to the Partnership's results of operation
or financial position.
Item 8. Financial Statements and Supplementary Data
The financial statements of the Partnership, together with
the report thereon of Ernst & Young LLP, appear on pages F-2
through F-18 of this report. See the Index to Financial
Statements on page F-1 of this report.
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
None.
PART III
Item 10. Directors and Executive Officers of the Partnership
Set forth below is certain information concerning the
executive officers and directors of the Managing General Partner
as of December 31, 1997 who are responsible for the operations of
the Partnership. All directors of the Managing General Partner
are elected by its shareholders. All officers of the Managing
General Partner serve at the discretion of the board of directors
of the Managing General Partner.
POSITION WITH THE
NAME AGE MANAGING GENERAL PARTNER
____ ___ ________________________
E. Peter Corcoran 69 Chairman of the Board
Brad Stephens 47 Chief Executive Officer, Treasurer,
and Director
D. Wayne Malone 54 President, Chief Operating Officer
and Director
Douglas Y. Bech 52 Director
Clark Johnson 52 Director
Robert Rice 75 Director
Craig Sincock 45 Director
Dave Caddell 48 Vice President and General Counsel
George Percival 38 Chief Financial Officer
Judy Sharrow 38 Secretary
E. Peter Corcoran. Mr. Corcoran served as a director of
Pride Pipeline Company, an affiliate of the Partnership, from
1985 to 1990 and became a director of the Managing General
Partner in 1990. In March 1994, he became Chairman. In 1991, Mr.
Corcoran retired from Lazard Freres & Co., having been a limited
partner thereof since 1983 and a general partner from 1968 until
1983. Mr. Corcoran serves as a member of the Audit and Conflicts
Committee of the Board of Directors of the Managing General
Partner.
Brad Stephens. Mr. Stephens served as Vice President of one
of the predecessor companies of the Partnership ("Predecessor
Companies") from 1988 until June 1989, when he became Executive
Vice President and Chief Financial Officer. In March 1994, he
became Chief Executive Officer. Prior to 1988, Mr. Stephens was
President of Independent Bankshares and First State Bank of
Abilene, where he had been employed since 1978. Mr. Stephens is
a Certified Public Accountant and prior to 1978, he was employed
by the accounting firm of Deloitte Haskins & Sells.
D. Wayne Malone. Mr. Malone has been associated with the
Predecessor Companies since 1979 and has been an officer,
director, and shareholder of the various companies since 1981.
Mr. Malone became President of Pride Pipeline Company in 1980,
President of Pride Marketing of Texas, Inc. in 1984 in charge of
retail, wholesale, and aviation fuel sales, and President of a
predecessor of Pride SGP in March 1988, adding the
responsibilities of refining and product trucking. Mr. Malone
also served as President of Carswell Pipeline Company. In March
1994, he became President and Chief Operating Officer.
Douglas Y. Bech. Mr. Bech became a director of the Managing
General Partner in 1993. He is Chairman of Club Regina Resorts,
Inc. and the founding partner of Raintree Capital Company,
L.L.C., a merchant banking firm. From 1994 to 1997, Mr. Bech was
a partner in the law firm of Akin, Gump, Strauss, Hauer & Feld,
L.L.P., and from 1993 to 1994 he was a partner in the Houston
office of Gardere & Wynne, L.L.P. From 1970 to 1993, he was
associated with and a senior partner of the law firm of Andrews &
Kurth, L.L.P. Mr. Bech is also a director of Wainoco Oil
Corporation and Jetfax, Inc. Mr. Bech serves as a member of the
Compensation Committee of the Board of Directors of the Managing
General Partner.
Clark Johnson. Mr. Johnson became a director of the
Managing General Partner in 1993. He is President and CEO of
Frontier Oil Corporation, a refining and marketing company which
is a subsidiary of Wainoco Oil Corporation. He also serves as
Senior Vice President of Wainoco Oil. Prior to those positions,
he held the positions of Executive Vice President and Chief
Operations Officer of Kerr-McGee Refining Corporation, and senior
management positions with Coastal Corporation and Tenneco Oil
Company. Mr. Johnson serves as a member of the Audit and
Conflicts Committee and as Chairman of the Compensation Committee
of the Managing General Partner.
Robert Rice. Mr. Rice became a director of the Managing
General Partner in 1990. He is an independent investor and
corporate director. He is a director of First Olsen Tankers,
Ltd., ATCO Ltd., and Hvide Marine Incorporated. Mr. Rice serves
as Chairman of the Audit and Conflicts Committee and as a member
of the Compensation Committee of the Board of Directors of the
Managing General Partner.
Craig Sincock. Mr. Sincock became a director of the
Managing General Partner in February, 1994. He is President and
a director of Avfuel Corporation, a privately held corporation
and independent supplier of aviation fuel headquartered in Ann
Arbor, Michigan. He has been associated with Avfuel Corporation
since the early 1980's and is an active real estate investor.
Mr. Sincock serves as a member of the Audit and Conflicts
Committee of the Board of Directors of the Managing General
Partner.
Dave Caddell. Mr. Caddell is Vice President and General
Counsel. He practiced general corporate law from November, 1992
to March, 1994. Previously, he served as Vice President and
General Counsel of the Predecessor Companies and the Partnership
from 1985 to October, 1992.
George Percival. Mr. Percival, a Certified Public
Accountant, came to the Partnership in June, 1990, and has served
as Chief Financial Officer since August of 1994. Prior to
joining the Partnership, he was with Computer Language Research
(d.b.a. Fast-Tax), where he had been the Senior Tax Manager since
1987. Prior to that he was employed by the accounting firms of
Coopers & Lybrand (1984 to 1987), and Fox and Company (1981 to
1984).
Judy Sharrow. Ms. Sharrow has served as Secretary of the
Managing General Partner since October 1992. In addition, she is
Manager of Investor Relations for the Partnership. Ms. Sharrow
has been associated with the Predecessor Companies since 1983.
Item 11. Executive Compensation
(a) Compensation of the General Partners. In respect of
their general partner interests in the Partnership, the General
Partners are allocated an aggregate of 2% of the income, gains,
losses and deductions arising from the Partnership's operations
and receive an aggregate of 2% of any distributions. For the
year ended December 31, 1997, the General Partners did not
receive any distributions in respect of their 2% general partner
interest in the Partnership. The compensation set forth below
under Officers' Compensation is in addition to any 2%
distribution to the General Partners. The General Partners are
not required to make any contributions to the capital of the
Partnership, beyond those made upon formation of the Partnership,
to maintain such 2% interest in allocations and distributions of
the Partnership. The General Partners do not receive, as general
partners of the Partnership, any compensation other than amounts
attributable to their 2% general partner interest in the
Partnership. Additionally, the Special General Partner is
allocated a portion of the income, gains, losses and deductions
arising from the Partnership's operations in respect of its
Common Units.
Effective December 31, 1996, the special participation
interest of the Special General Partner and the incentive
interests of the Managing General Partner were eliminated as a
result of the adoption of the Second Amended and Restated
Agreement of Limited Partnership. For the year ended December
31, 1997, the Special General Partner did not receive any
distributions in respect of the Common Units. The Partnership
reimburses the General Partners for all their direct and indirect
costs (including general and administrative costs) allocable to
the Partnership. See "Certain Relationships and Related
Transactions."
(b) Summary Officers' Compensation Table. The following
table sets forth certain compensation paid during fiscal 1997 by
the Partnership to the executive officers of the Managing General
Partner:
(The following table should be printed on 11" x 8.5" paper)
SUMMARY COMPENSATION TABLE
Long-Term
Compensation
------------
Securities
Underlying
Options/ All Other
Year Salary Bonus UARs Compensation
---- -------- ------- ------------ ------------
Brad Stephens 1997 $225,000 $ - - $ 8,800
Chief Executive Officer 1996 225,000 - 56,000 8,500
1995 242,000 - - 8,000
D. Wayne Malone 1997 225,000 - - 8,900
Chief Operating Officer 1996 225,000 - 56,000 8,500
1995 242,000 - - 8,000
Dave Caddell 1997 165,000 - - 7,300
Vice President/General 1996 165,000 - 32,000 7,300
Counsel 1995 178,000 - - 7,000
George Percival 1997 100,000 - - 4,000
Chief Financial Officer 1996 100,000 20,000 16,000 4,200
1995 100,000 15,000 - 5,000
The Partnership implemented a Unit Appreciation Rights Plan under which certain key
employees of the Partnership received unit appreciation rights ("UARs"). This column
represents the number of UARs granted to each of the officers listed in the table. See "-
(c) Benefit Plans - Unit Appreciation Rights". Effective December 31, 1997, the number of
UARs previously granted to the officers was reduced retroactive to December 31, 1996.
In this column is the Partnership's contribution to the Section 401(k) Plan for each
officer and reimbursement of income taxes on certain perquisites. See "-Benefit Plans -
Section 401(k) Plan" below.
Messrs. Stephens, Malone and Caddell received a salary increase on August 1, 1994, from
the Board of Directors, but chose to defer such increase. Such deferred amounts were paid
in 1995.
/TABLE
(c) Benefit Plans. In order to attract, retain and motivate
officers and other employees who provide administrative and
managerial services, the Partnership provides incentives for key
executives and middle managers employed by the Partnership
through an Annual Incentive Plan. The Plan provides for certain
key executives to share in a bonus pool which varies in size with
the Partnership's operating income plus depreciation, calculated
after bonus accrual, after payments under the Partnership's unit
appreciation plan, and after proceeds of litigation, to the
extent not otherwise included in operating income ("Cash Flow").
Provided that Cash Flow exceeds $8 million, the key executive
bonus pool includes 8% of an amount equal to the Partnership's
first $2 million of Cash Flow in excess of $8 million, plus 12%
of the next $4 million of Cash Flow, plus 15% of any Cash Flow in
excess of $14 million. The bonus pool for middle managers
consists of up to 4% of Cash Flow, provided that Cash Flow
exceeds $8 million.
Unit Appreciation Rights. During 1996, the Partnership
implemented a Unit Appreciation Rights Plan under which certain
key employees of the Partnership receive UARs, which entitle such
key employees, upon exercise of such rights, to either receive
cash or Common Units equal to the difference in the market price
of the units on the exercise date and the market price of the
units on the date on which such UARs were granted. It is
anticipated that UARs aggregating approximately 10% of the total
units will be reserved for issuance to key employees. However,
no Common Units are expected to be issued under this plan. The
employees to whom awards are made and the number of UARs awarded
are subject to the discretion of the board of directors of the
Managing General Partner.
On December 9, 1996, four officers and twelve employees were
awarded a total of 293,000 UARs at a grant price of $3.75 per
unit. Since the fair market value of the UARs did not exceed the
grant price at December 9, 1996, no compensation expense has been
accrued. Effective December 31, 1997, the number of UARs was
increased to 299,996, reallocated among the officers and
employees, and the exercise price was reduced to $1.94 per unit.
(This page should be printed on 11" x 8.5" paper)
OPTION/UNIT APPRECIATION RIGHTS ("UARs")
GRANTS IN LAST FISCAL YEAR
Potential
Realizable Value
at Assumed
Annual Rates of
Unit Price Appreciation
Individual Grants for UAR Term
______________________________________________________________ ____________________
Number of
Securities % of Total
Underlying Options/UARs
Options/ Granted to Exercise
UARs Employees of Base
Granted In Fiscal Price Expiration
Name (#) Year ($/Unit) Date 5%($) 10%($)
_______________ _______ __________ ________ __________ ________ _________
Brad Stephens 56,000 19% $ 1.94 1