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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K/A
AMENDMENT NO. 2
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934:
FOR THE FISCAL YEAR ENDED JULY 31, 2002
COMMISSION FILE NUMBER 1-3876
HOLLY CORPORATION
INCORPORATED UNDER THE LAWS OF THE STATE OF DELAWARE
I.R.S. EMPLOYER IDENTIFICATION NO. 75-1056913
100 CRESCENT COURT, SUITE 1600
DALLAS, TEXAS 75201-6927
TELEPHONE NUMBER: (214) 871-3555
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Common Stock, $0.01 par value registered on the American Stock Exchange.
SECURITIES REGISTERED PURSUANT TO 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 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/A or any amendment to
this Form 10-K/A. [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [X] No [ ]
On September 30, 2002, the aggregate market value of the Common Stock, par value
$.01 per share, held by non-affiliates of the registrant was approximately
$146,000,000. (This is not to be deemed an admission that any person whose
shares were not included in the computation of the amount set forth in the
preceding sentence necessarily is an "affiliate" of the registrant.)
15,522,928 shares of Common Stock, par value $.01 per share, were outstanding on
September 30, 2002.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's proxy statement for its annual meeting of
stockholders in December 2002, which proxy statement will be filed with the
Securities and Exchange Commission within 120 days after July 31, 2002, are
incorporated by reference in Part III.
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PURPOSE OF AMENDMENT
Holly Corporation is filing this Amendment No. 2 to its Annual Report
on Form 10-K for the fiscal year ended July 31, 2002, originally filed on
October 11, 2002 and amended on Form 10-K/A on September 9, 2003, in response to
comments received from the Securities and Exchange Commission in order to comply
with Item 10(e) of Regulation S-K regarding the use of non-GAAP financial
measures. This Amendment No 2 amends and restates in its entirety the original
Form 10-K as amended, but continues to speak as of the date of the original
filing of the original Form 10-K. Holly Corporation has not updated the
disclosure in this Amendment No. 2 to speak as of a later date. All information
contained in this amendment and the original Form 10-K as amended is subject to
updating and supplementing as provided in the periodic reports filed subsequent
to the original filing date with the Securities and Exchange Commission.
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TABLE OF CONTENTS
ITEM PAGE
---- ----
PART I
Forward-Looking Statements.................................................. 5
1 & 2. Business and properties..................................................... 6
3. Legal proceedings........................................................... 21
4. Submission of matters to a vote of security holders......................... 22
PART II
5. Market for the Registrant's common equity and related
stockholder matters...................................................... 24
6. Selected financial data..................................................... 25
7. Management's discussion and analysis of financial condition
and results of operations................................................ 26
7A. Quantitative and qualitative disclosures about market risk.................. 41
8. Financial statements and supplementary data................................. 41
9. Changes in and disagreements with accountants on accounting
and financial disclosure................................................. 68
PART III
10. Directors and executive officers of the Registrant.......................... 68
11. Executive compensation...................................................... 69
12. Security ownership of certain beneficial owners
and management........................................................... 70
13. Certain relationships and related transactions.............................. 71
PART IV
14. Exhibits, financial statement schedules and reports on
Form 8-K................................................................. 71
Signatures................................................................................ 72
Certifications............................................................................ 73
Index to exhibits......................................................................... 75
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GLOSSARY
Within this report, the following terms have these specific meanings:
"Alkylation" means the reaction of propylene or butylene (olefins) with
isobutane to form an iso-paraffinic gasoline (inverse of cracking).
"Cracking" means the process of breaking down larger, heavier and more
complex hydrogen molecules into simpler and lighter molecules.
"Crude distillation" means the process of distilling vapor from
liquids, usually by heating, and condensing slightly above atmospheric
pressure the vapor back to liquid in order to purify, fractionate or
form the desired products.
"Fluid catalytic cracking" means the breaking down of large, complex
hydrocarbon molecules into smaller, more useful ones by the application
of heat, pressure and a chemical (catalyst) to speed the process.
"Hydrodesulfurization" means to remove sulfur and nitrogen compounds
from oil or gas in the presence of hydrogen and a catalyst at
relatively high temperatures.
"Isomerization" means a refinery process for converting C5/C6 gasoline
compounds into their isomers, i.e., rearranging the structure of the
molecules without changing their size or chemical composition.
"Refined product margins" means the difference between refined product
sales prices and the costs for crude oil and other feedstocks exclusive
of depreciation, depletion and amortization
"Reforming" means the process of converting gasoline type molecules
into aromatic, higher octane gasoline blend stocks while producing
hydrogen in the process.
"Sour crude oil" means crude oil containing appreciable quantities of
hydrogen sulfide or other sulfur compounds.
"Vacuum distillation" means the process of distilling vapor from
liquids, usually by heating, and condensing below atmospheric pressure
the vapor back to liquid in order to purify, fractionate or form the
desired products.
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PART I
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K/A contains certain "forward-looking statements"
within the meaning of the U.S. Private Securities Litigation Reform Act of 1995.
All statements, other than statements of historical facts included in this Form
10-K/A, including without limitation those under "Business and Properties" under
Items 1 and 2, "Legal Proceedings" under Item 3 and "Liquidity and Capital
Resources" and "Additional Factors that May Affect Future Results" under Item 7
"Management's Discussion and Analysis of Financial Condition and Results of
Operations," are forward-looking statements. Such statements are subject to
risks and uncertainties, including but not limited to risks and uncertainties
with respect to the actions of actual or potential competitive suppliers of
refined petroleum products in the Company's markets, the demand for and supply
of crude oil and refined products, the spread between market prices for refined
products and market prices for crude oil, the possibility of constraints on the
transportation of refined products, the possibility of inefficiencies or
shutdowns in refinery operations or pipelines, effects of governmental
regulations and policies, the availability and cost of financing to the Company,
the effectiveness of the Company's capital investments and marketing strategies,
the Company's efficiency in carrying out construction projects, the costs of
defense and the risk of an adverse decision in the Longhorn Pipeline litigation,
and general economic conditions. Should one or more of these risks or
uncertainties, among others as set forth in this Form 10-K/A, materialize,
actual results may vary materially from those estimated, anticipated or
projected. Although the Company believes that the expectations reflected by such
forward-looking statements are reasonable based on information currently
available to the Company, no assurances can be given that such expectations will
prove to have been correct. Cautionary statements identifying important factors
that could cause actual results to differ materially from the Company's
expectations are set forth in this Form 10-K/A, including without limitation in
conjunction with the forward-looking statements included in this Form 10-K/A
that are referred to above. All forward-looking statements included in this Form
10-K/A and all subsequent written or oral forward-looking statements
attributable to the Company or persons acting on its behalf are expressly
qualified in their entirety by these cautionary statements. The forward-looking
statements speak only as of the date made, other than as required by law, and
the Company undertakes no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise.
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ITEMS 1 AND 2. BUSINESS AND PROPERTIES
Holly Corporation, including its consolidated and wholly-owned subsidiaries,
herein referred to as the "Company" unless the context otherwise indicates, is
principally an independent petroleum refiner, which produces high value light
products such as gasoline, diesel fuel and jet fuel. The Company was
incorporated in Delaware in 1947 and maintains its principal corporate offices
at 100 Crescent Court, Suite 1600, Dallas, Texas 75201-6927. The telephone
number of the Company is 214-871-3555, and its internet website address is
www.hollycorp.com. The information contained on the website does not constitute
part of this Annual Report on Form 10-K/A. The Company also maintains executive
offices in Artesia, New Mexico.
The Company:
- owns and operates two refineries, a high conversion petroleum
refinery in Artesia, New Mexico which is operated in
conjunction with crude vacuum distillation and other
facilities situated 65 miles away in Lovington, New Mexico
(collectively known as the "Navajo Refinery"), and one
refinery in Great Falls, Montana;
- owns and operates seven refined product terminals in Artesia,
Roswell, Moriarty, Bloomfield and Lovington, New Mexico, El
Paso, Texas, and in Mountain Home, Idaho;
- owns interest in two product storage facilities in
Albuquerque, New Mexico and Tucson, Arizona; and
- owns and operates approximately 2,000 miles of pipeline
located in west Texas and New Mexico.
Navajo Refining Company, L.P. ("Navajo"), one of the Company's wholly-owned
subsidiaries, owns the Navajo Refinery, which has a crude capacity of 60,000
barrels-per-day ("BPD"), can process a variety of sour (high sulfur) crude oils
and serves markets in the southwestern United States and northern Mexico. The
Company also owns Montana Refining Company, a Partnership ("MRC"), which owns a
7,000 BPD petroleum refinery in Great Falls, Montana ("Montana Refinery"), which
can process a variety of sour crude oils and which primarily serves markets in
Montana. In conjunction with the refining operations, the Company owns and
operates approximately 2,000 miles of pipelines of which 1,400 miles are part of
the supply and distribution network for the Company's refineries and the
remaining 600 miles are used in the Company's pipeline transportation business.
In recent years, the Company has made an effort to develop and expand a pipeline
transportation business generating revenues from unaffiliated parties. The
pipeline transportation business segment operations include approximately 1,000
miles of the Company's 2,000 miles of pipelines, of which approximately 400
miles are also used as part of the supply and distribution network of the Navajo
Refinery. Additionally, the Company owns a 25% interest in Rio Grande Pipeline
Company, which provides transportation of liquid petroleum gases ("LPG") to
northern Mexico, and a 49% interest in NK Asphalt Partners, which manufactures
and markets asphalt and asphalt products in Arizona and New Mexico. In addition
to its refining and pipeline transportation operations, the Company also
conducts a small-scale oil and gas exploration and production program and has a
small investment in a joint venture conducting a retail gasoline station and
convenience store business in Montana.
The Company's operations are currently organized into two business divisions,
which are Refining, including the Navajo Refinery and the Montana Refinery and
the Company's interest in the NK Asphalt Partners joint venture, and Pipeline
Transportation. Operations of the Company that are not included in either the
Refining or Pipeline Transportation business divisions include the operations of
Holly Corporation, the parent company, as well as oil and gas operations and an
investment in a Montana retail gasoline business. The accompanying discussion of
the Company's business and properties reflects this organizational structure.
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REFINERY OPERATIONS
The Company's refinery operations include the Navajo Refinery and the Montana
Refinery.
The following tables set forth certain information about the combined refinery
operations of the Company during the last three fiscal years:
YEARS ENDED JULY 31,
-----------------------------------------
2002 2001 2000
---- ---- ----
(in thousands except for BPD and per barrel)
Crude charge (BPD) (1) ................................... 60,200 63,700 65,300
Refinery utilization (2) ................................. 89.9%(3) 95.5% 97.5%
Refinery production (BPD) (4) ............................ 66,400 69,600 70,800
Sales of refined products (BPD) (5) ...................... 76,400 77,000 77,600
Average sales price per sales barrel ..................... $ 31.12 $ 39.82 $ 33.42
Sales of produced refined products (BPD) ................. 67,000 69,100 70,400
Average sales price per produced barrel .................. $ 30.95 $ 39.60 $ 33.52
Reconciliation to Sales and other revenues in Consolidated
Financial Statements
(Also see Note 14 to Consolidated Financial Statements)
Sales of refined product (BPD) ........................... 76,400 77,000 77,600
Average sales price per sales barrel ..................... $ 31.12 $ 39.82 $ 33.42
Refinery segment sales and other revenues (6) ............ $ 868,730 $1,120,248 $ 947,317
Pipeline transportation segment sales and other revenues . $ 18,588 $ 18,454 $ 14,861
Corporate and other sales and other revenues ............. $ 1,588 $ 3,428 $ 3,768
---------- ---------- ----------
Consolidated Sales and other revenues .................... $ 888,906 $1,142,130 $ 965,946
========== ========== ==========
(1) Crude charge represents the barrels per day of crude oil processed through
the crude units at the Company's refineries.
(2) Crude charge divided by total crude capacity of 67,000 BPD.
(3) Refinery utilization rate for fiscal 2002 reflects a 29-day turnaround for
major maintenance at the Navajo Refinery in November-December 2001.
(4) Refinery production represents the barrels per day of refined products
yielded from processing crude and other refinery feedstocks through the
crude units and other conversion units at the Company's refineries.
(5) Includes refined products purchased for resale representing 9,400 BPD,
7,900 BPD, and 7,200 BPD in fiscal years ended July 31, 2002, 2001, and
2000, respectively.
(6) In addition to revenues from sales of refined products, the refining
segment includes other miscellaneous revenues amounting to $918, $1,107,
and $729 in fiscal years ended July 31, 2002, 2001, and 2000 respectively.
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YEARS ENDED JULY 31,
------------------------------------------------------------
2002 2001 2000
----------------- ---------------- -----------------
BPD % BPD % BPD %
------- ------- ------ ------- ------- -------
Sales of produced refined products (1)
Gasolines............................. 37,700 56.3% 38,700 56.1% 40,100 57.1%
Diesel fuels.......................... 14,000 20.9% 15,100 21.8% 15,400 21.8%
Jet fuels............................. 7,100 10.6% 7,400 10.8% 7,300 10.3%
Asphalt............................... 5,800 8.6% 5,300 7.6% 5,100 7.3%
LPG and other......................... 2,400 3.6% 2,600 3.7% 2,500 3.5%
------- ------- ------ ------- ------- -------
Total.............................. 67,000 100.0% 69,100 100.0% 70,400 100.0%
======= ======= ====== ======= ======= =======
(1) Excludes refined products purchased for resale.
NAVAJO REFINERY
FACILITIES
The crude oil capacity of the Navajo Refinery is 60,000 BPD and it has the
ability to process a variety of sour crude oils into high value light products
(such as gasoline, diesel fuel and jet fuel).
For the last three fiscal years, sour crude oils have represented approximately
83% of the crude oils processed by the Navajo Refinery. The Navajo Refinery's
processing capabilities enable management to vary its crude supply mix to take
advantage of changes in raw material prices and to respond to fluctuations in
the availability of crude oil supplies. The Navajo Refinery converts
approximately 91% of its raw materials throughput into high value light
products. For fiscal 2002, gasoline, diesel fuel and jet fuel (excluding volumes
purchased for resale) represented 58.2%, 21.6%, and 11.0%, respectively, of
Navajo's sales volume.
The following table sets forth certain information about the operations of the
Navajo Refinery during the last three fiscal years:
YEARS ENDED JULY 31,
--------------------------------------
2002 2001 2000
------ ------ -------
Crude charge (BPD) (1)........................................ 53,600 57,800 59,400
Refinery production (BPD) (2)................................. 59,400 63,200 64,600
Sales of produced refined products (BPD)...................... 59,800 62,600 64,300
Sales of refined products (BPD) (3)........................... 68,900 70,200 71,000
Refinery utilization (4)...................................... 89.3%(5) 96.3% 99.0%
(1) Crude charge represent the barrels per day of crude oil processed through
the crude units at the Company's refineries.
(2) Refinery production represents the barrels per day of refined products
yielded from processing crude and other refinery feedstocks through the
crude units and other conversion units at the Company's refineries.
(3) Includes refined products purchased for resale representing 9,100 BPD,
7,600 BPD, and 6,600 BPD, respectively.
(4) Crude charge divided by total crude capacity of 60,000 BPD.
(5) Refinery utilization rate for fiscal 2002 reflects a 29-day turnaround for
major maintenance in November- December 2001.
Navajo's Artesia facility is located on a 300-acre site and has fully integrated
crude, fluid catalytic cracking ("FCC"), vacuum distillation, alkylation,
hydrodesulfurization, isomerization and reforming units, and approximately 1.5
million barrels of feedstock and product tank storage, as well as other
supporting units and office buildings at the
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site. The operating units at the Artesia facility include newly constructed
units, older units that have been relocated from other facilities and re-erected
in Artesia, and units that have been operating as part of the Artesia facility
(with periodic major maintenance) for many years, in some cases since before
1970. The Artesia facilities are operated in conjunction with integrated
refining facilities located in Lovington, New Mexico, approximately 65 miles
east of Artesia. The principal equipment at Lovington consists of a crude unit
and an associated vacuum unit. The Lovington facility processes crude oil into
intermediate products, which are transported to Artesia by means of two
Company-owned pipelines, and which are then upgraded into finished products at
the Artesia facility.
The Company has approximately 500 miles of crude gathering pipelines
transporting crude oil to the Artesia and Lovington facilities from various
points in southeastern New Mexico. In addition, the Company operates crude oil
gathering systems in West Texas. These systems include approximately 600 miles
of pipelines and over 600,000 barrels of tankage and are being used to provide
crude oil transportation services to third parties as well as to transport West
Texas crude oil that may be exchanged for crude oil used in the Navajo Refinery.
The Company distributes refined products from the Navajo Refinery to its
principal markets primarily through two Company-owned pipelines which extend
from Artesia to El Paso. In addition, the Company uses a leased pipeline to
transport petroleum products to markets in Northwest New Mexico and to Moriarty,
New Mexico, near Albuquerque. The Company has product storage at terminals in El
Paso, Texas, Tucson, Arizona, and Albuquerque, Artesia, Moriarty and Bloomfield,
New Mexico.
Prior to July 2000, Navajo Western Asphalt Company ("Navajo Western"), a
wholly-owned subsidiary of the Company, owned and operated an asphalt terminal
and blending and modification facility near Phoenix. Navajo Western marketed
asphalt produced at the Navajo Refinery and asphalt produced by third parties.
In July 2000, Navajo Western and a subsidiary of Koch Materials Company ("Koch")
formed a joint venture, NK Asphalt Partners, to manufacture and market asphalt
and asphalt products in Arizona and New Mexico under the name "Koch Asphalt
Solutions - Southwest." Navajo Western contributed all of its assets to NK
Asphalt Partners and Koch contributed its New Mexico and Arizona asphalt
manufacturing and marketing assets to NK Asphalt Partners. Effective January 1,
2002, the Company sold a 1% equity interest to the other joint venture partner
thereby reducing the Company's equity interest from 50% to 49%. All asphalt
produced at the Navajo Refinery is sold at market prices to the joint venture
under a supply agreement.
MARKETS AND COMPETITION
The Navajo Refinery primarily serves the growing southwestern United States
market, including El Paso, Texas; Albuquerque, Moriarty and Bloomfield, New
Mexico; Phoenix and Tucson, Arizona; and the northern Mexico market. The
Company's products are shipped by pipeline from El Paso to Albuquerque and from
El Paso to Mexico via products pipeline systems owned by Chevron Pipeline
Company and from El Paso to Tucson and Phoenix via a products pipeline system
owned by Kinder Morgan's SFPP, L.P. ("SFPP"). In addition, the Company began in
late 1999 transportation of petroleum products to markets in Northwest New
Mexico and to Moriarty, New Mexico, near Albuquerque, via a pipeline from Chaves
County to San Juan County, New Mexico, leased by the Company from Mid-America
Pipeline Company.
The petroleum refining business is highly competitive. Among the Company's
competitors are some of the world's largest integrated petroleum companies,
which have their own crude oil supplies and distribution and marketing systems.
The Company competes with independent refiners as well. Competition in
particular geographic areas is affected primarily by the amounts of refined
products produced by refineries located in such areas and by the availability of
refined products and the cost of transportation to such areas from refineries
located outside those areas.
THE EL PASO MARKET
Most of the light products of the Company's Navajo Refinery (i.e. products other
than asphalt, LPGs and carbon black oil) are currently shipped to El Paso on
pipelines owned and operated by the Company. Of the products shipped to El Paso,
most are subsequently shipped (either by the Company or by purchasers of the
products from the Company) via common carrier pipeline to Tucson and Phoenix,
Arizona, Albuquerque, New Mexico and markets in northern Mexico; the remaining
products shipped to El Paso are sold to wholesale customers primarily for
ultimate retail sale in the El Paso area. The Company expanded its capacity to
supply El Paso in 1996 when the Company
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replaced an 8-inch pipeline from Orla to El Paso, Texas with a new 12-inch line,
a portion of which has been leased to Alon USA LP ("Alon"), formerly Fina, Inc.,
to transport refined products from the Alon refinery in Big Spring, Texas to El
Paso, Texas. Holly receives monthly payments from Alon in the amount of $523,000
with respect to the lease of the pipeline, subject to period rent adjustments.
The El Paso market for refined products is currently supplied by a number of
refiners located either in El Paso or that have pipeline access to El Paso.
Historically, the Company accounted for approximately 15% of the refined
products consumed in the El Paso market. Since 1995, the volume of refined
products transported by various suppliers via pipeline to El Paso has
substantially expanded, in part as a result of the Company's own 12-inch
pipeline expansion described above and primarily as a result of the completion
in November 1995 of the Valero Energy Corporation ("Valero" - formerly Ultramar
Diamond Shamrock Corporation ("UDS")) 10-inch pipeline running 408 miles from
the UDS refinery near Dumas, Texas to El Paso. The capacity of this pipeline (in
which ConocoPhillips now has a 1/3 interest) is currently 60,000 BPD after an
expansion completed in 1999. In August 2000, UDS (now Valero) announced that it
is studying a potential expansion of this pipeline to 80,000 BPD.
Until 1998, the El Paso market and markets served from El Paso were generally
not supplied by refined products produced by the large refineries on the Texas
Gulf Coast. While wholesale prices of refined products on the Gulf Coast have
historically been lower than prices in El Paso, distances from the Gulf Coast to
El Paso (more than 700 miles if the most direct route were used) have made
transportation by truck unfeasible and have discouraged the substantial
investment required for development of refined products pipelines from the Gulf
Coast to El Paso.
In 1998, a Texaco, Inc. subsidiary completed a 16-inch refined products pipeline
running from the Gulf Coast to Midland, Texas along a northern route (through
Corsicana, Texas). This pipeline, now owned by Shell Pipeline Company, LP
("Shell"), is linked to a 6-inch pipeline, also owned by Shell, that is
currently being used to transport to El Paso approximately 16,000 to 18,000 BPD
of refined products that are produced on the Texas Gulf Coast (this volume
replaces a similar volume that had been produced in the Shell Oil Company
refinery in Odessa, Texas, which was shut down in 1998). The Shell pipeline from
the Gulf Coast to Midland has the potential to be linked to existing or new
pipelines running from the Midland, Texas area to El Paso with the result that
substantial additional volumes of refined products could be transported from the
Gulf Coast to El Paso.
THE PROPOSED LONGHORN PIPELINE
An additional potential source of pipeline transportation from Gulf Coast
refineries to El Paso is the proposed Longhorn Pipeline. This pipeline is
proposed to run approximately 700 miles from the Houston area of the Gulf Coast
to El Paso, utilizing a direct route. The owner of the Longhorn Pipeline,
Longhorn Partners Pipeline, L.P. ("Longhorn Partners"), is a Delaware limited
partnership that includes affiliates of ExxonMobil Pipeline Company, BP Pipeline
(North America), Inc., Williams Pipe Line Company, and the Beacon Group Energy
Investment Fund, L.P. and Chisholm Holdings as limited partners. Longhorn
Partners has proposed to use the pipeline initially to transport approximately
72,000 BPD of refined products from the Gulf Coast to El Paso and markets served
from El Paso, with an ultimate maximum capacity of 225,000 BPD. A critical
feature of this proposed petroleum products pipeline is that it would utilize,
for approximately 450 miles (including areas overlying the environmentally
sensitive Edwards Aquifer and Edwards-Trinity Aquifer and heavily populated
areas in the southern part of Austin, Texas) an existing pipeline (previously
owned by Exxon Pipeline Company) that was constructed in about 1950 for the
shipment of crude oil from West Texas to the Houston area. At the date of this
report, the Longhorn Pipeline has not begun operations. The Longhorn Pipeline
did not operate in the period from late 1998 through July 2002 because of a
federal court injunction in August 1998 and a settlement agreement in March 1999
entered into by Longhorn Partners, the United States Environmental Protection
Agency ("EPA") and Department of Transportation ("DOT"), and the other parties
to the federal lawsuit that had resulted in the injunction and settlement.
Additionally, the Longhorn Pipeline did not operate through July 2002 because it
lacked valid easements from the Texas General Land Office for crossing certain
stream and river beds and state-owned lands. Since July 2002 the Longhorn
Pipeline has not been operating because Longhorn Partners has not completed
certain agreed improvement projects and pre-start-up steps.
The March 1999 settlement agreement in the federal lawsuit that resulted in an
injunction against operation of the Longhorn Pipeline required the preparation
of an Environmental Assessment under the authority of the EPA and the DOT while
the federal court retained jurisdiction. A final Environmental Assessment (the
"Final EA") on the Longhorn Pipeline was released in November 2000. The Final EA
was accompanied by a Finding of No Significant
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Impact that was conditioned on the implementation by Longhorn Partners of a
proposed mitigation plan developed by Longhorn Partners which contained 40
mitigation measures, including the replacement of approximately 19 miles of pipe
in the Austin area with new thick-walled pipe protected by a concrete barrier.
Some elements of the proposed mitigation plan were required to be completed
before the Longhorn Pipeline would be allowed to operate, with the remainder
required to be completed later or to be implemented for as long as operations
continued. The plaintiffs in the federal court lawsuit that resulted in the
Environmental Assessment of the Longhorn Pipeline challenged the Final EA in
further federal court proceedings that began in January 2001. One of the
intervenor plaintiffs in the federal court lawsuit, the Lower Colorado River
Authority ("LCRA"), entered into a settlement agreement with Longhorn Partners
in 2001 under the terms of which Longhorn Partners agreed to implement specified
additional mitigation measures relating to water supplies in certain areas of
Central Texas and the LCRA agreed to dismiss with prejudice its participation as
an intervenor in the federal court lawsuit. In July 2002, the federal court in
Austin ruled that Longhorn's compliance with the Final EA would suffice under
the federal National Environmental Policy Act to allow the Longhorn Pipeline to
begin operation. The court also subsequently ruled that the parties that had
brought the challenge to the Longhorn Pipeline in federal court were the
"prevailing parties" and that therefore Longhorn Partners and the federal
government defendants should pay certain costs relating to the federal court
litigation. The parties that were plaintiffs in the federal litigation, other
than the LCRA, are taking an appeal to the United States Court of Appeals for
the Fifth Circuit (the "Fifth Circuit") of the district court's ruling on the
adequacy of the Final EA. In addition, the Federal Government defendants in the
federal court lawsuit are cross-appealing to the Fifth Circuit the trial court's
ruling concerning payment of certain costs. At the date of this report, it is
not possible to predict the outcome of these appeals.
Prior to the federal court's ruling on the adequacy of the Final EA, in December
2001 Longhorn Partners began construction to implement mitigation measures
required by the Final EA and the settlement with the LCRA. Published reports
indicate that this construction continued until late July 2002, when the
construction activities were halted before completion of the project. The latest
public statements from Longhorn Partners indicate that Longhorn Partners is
seeking additional financing to complete the project and that the project will
not begin operations until after December 2002.
The Company supported the initial plaintiffs in the federal district court
lawsuit that ultimately resulted in the Final EA and is supporting such
plaintiffs in the appeal to the Fifth Circuit of the federal district court's
July 2002 decision. In addition, the Company provided financial support for the
preparation of expert analyses of the Final EA and of the earlier draft
Environmental Assessment and for certain groups and individuals who have wished
to express their concerns about the Longhorn Pipeline. The Company believes that
the Longhorn Pipeline, as originally proposed to operate beginning in the fall
of 1998, would have improperly avoided the substantial capital expenditures
required to comply with environmental and safety standards that are normally
imposed on major pipeline projects involving environmentally sensitive areas.
The Company's belief in this regard was based in part on the fact that, in 1987,
a proposed new crude oil pipeline (the All American Pipeline) over essentially
the proposed route for the Longhorn Pipeline was found unacceptable, after an
environmental impact study, because of serious potential dangers to the
environmentally sensitive aquifers over which that proposed pipeline would have
operated.
If the Longhorn Pipeline is allowed to operate as currently proposed, the
substantially lower requirement for capital investment permitted by the direct
route through Austin, Texas and over the Edwards Aquifers would permit Longhorn
Partners to give its shippers a cost advantage through lower tariffs that could,
at least for a period, result in significant downward pressure on wholesale
refined products prices and refined products
s in El Paso and related markets; any effects on the Company's markets in Tucson
and Phoenix, Arizona and Albuquerque, New Mexico would be expected to be limited
in the next few years because current common carrier pipelines from El Paso to
these markets are now running at capacity and proration policies of these
pipelines allocate only limited capacity to new shippers. Although some current
suppliers in the market might not compete in such a climate, the Company's
analyses indicate that, because of location, recent capital improvements, and
on-going enhancements to operational efficiency, the Company's position in El
Paso and markets served from El Paso could withstand such a period of lower
prices and refined product margins. However, the Company's results of operations
could be adversely impacted if the Longhorn Pipeline were allowed to operate as
currently proposed. It is not possible to predict whether and, if so, under what
conditions, the Longhorn Pipeline will ultimately be operated, nor is it
possible to predict the consequences for the Company of Longhorn Pipeline's
operations if they occur.
-11-
In August 1998, a lawsuit (the "El Paso Lawsuit") was filed by Longhorn Partners
in state district court in El Paso, Texas against the Company and two of its
subsidiaries (along with an Austin, Texas law firm which was subsequently
dropped from the case). The suit, as most recently amended by Longhorn Partners
in September 2000, seeks damages alleged to total up to $1,050,000,000 (after
trebling) based on claims of violations of the Texas Free Enterprise and
Antitrust Act, unlawful interference with existing and prospective contractual
relations, and conspiracy to abuse process. The specific actions of the Company
complained of in the El Paso Lawsuit, as currently amended, are alleged
solicitation of and support for allegedly baseless lawsuits brought by Texas
ranchers in federal and state courts to challenge the proposed Longhorn Pipeline
project, support of allegedly fraudulent public relations activities against the
proposed Longhorn Pipeline project, entry into a contractual "alliance" with
Fina Oil and Chemical Company, threatening litigation against certain partners
in Longhorn Partners, and alleged interference with the federal court settlement
agreement that provided for the Environmental Assessment of the Longhorn
Pipeline. The Company believes that the El Paso Lawsuit is wholly without merit
and plans to continue to defend itself vigorously. However, because of the size
of the damages claimed and in spite of the apparent lack of merit in the claims
asserted, the El Paso Lawsuit has created problems for the Company, including
the exclusion of the Company from the possibility of certain types of major
corporate transactions, an adverse impact on the cost and availability of debt
financing for Company operations, and what appears to be a continuing adverse
effect on the market price of the Company's common stock. In August 2002, the
Company filed a lawsuit in New Mexico state court in Carlsbad, New Mexico (the
"Carlsbad Lawsuit") against Longhorn Partners and its major owners concerning
the El Paso Lawsuit; the Carlsbad Lawsuit seeks actual and punitive damages for
tortious interference with existing business relations, malicious abuse of
process, unfair competition, prima facie tort and conspiracy. For additional
information on the El Paso Lawsuit and the Carlsbad Lawsuit, see Item 3, "Legal
Proceedings."
ARIZONA AND ALBUQUERQUE MARKETS
The common carrier pipelines used by the Company to serve the Arizona and
Albuquerque markets are currently operated at or near capacity and are subject
to proration. As a result, the volumes of refined products that the Company and
other shippers have been able to deliver to these markets have been limited. The
flow of additional products into El Paso for shipment to Arizona, either as a
result of operation of the Longhorn Pipeline or otherwise, could further
exacerbate such constraints on deliveries to Arizona. No assurances can be given
that the Company will not experience future constraints on its ability to
deliver its products through the common carrier pipeline to Arizona. Any future
constraints on the Company's ability to transport its refined products to
Arizona could, if sustained, adversely affect the Company's results of
operations and financial condition. SFPP, the owner of the common carrier
pipelines running from El Paso to Tucson and Phoenix, has recently proposed to
expand the capacity of these pipelines by approximately 54,000 BPD. Under the
announced schedule, the expansion would be completed by early 2005. According to
a September 2002 filing by SFPP with the Federal Energy Regulatory Commissions
("FERC"), this project is contingent on obtaining a favorable ruling from FERC
concerning tariff rates to be allowed on the pipelines after completion of the
expansion. For the Company, the proposed expansion would permit the shipment of
additional refined products to markets in Arizona, but pipeline tariffs would
likely be higher and the expansion would also permit additional shipments by
competing suppliers. The ultimate effects of the proposed pipeline expansion on
the Company cannot presently be estimated.
In the case of the Albuquerque market, the common carrier pipeline used by the
Company to serve this market currently operates at or near capacity with
resulting limitations on the amount of refined products that the Company and
other shippers can deliver. The Company has entered into a Lease Agreement (the
"Lease Agreement") for a pipeline between Artesia and the Albuquerque vicinity
and Bloomfield, New Mexico with Mid-America Pipeline Company. The Company owns
and operates a 12" pipeline from the Navajo Refinery to the Leased Pipeline as
well as terminalling facilities in Bloomfield, New Mexico, which is located in
the northwest corner of New Mexico, and in Moriarty, which is 40 miles east of
Albuquerque. Transportation of petroleum products to markets in northwest New
Mexico and diesel fuels to Moriarty began at the end calendar 1999. In December
2001, the Company completed its expansion of the Moriarty terminal and its
pumping capacity on the Leased Pipelines. The terminal expansion included the
addition of gasoline and jet fuel to the existing diesel fuel delivery
capabilities, thus permitting the Company to provide a full slate of light
products to the growing Albuquerque and Santa Fe, New Mexico areas. The enhanced
pumping capabilities on the Company's leased pipeline extending from the Artesia
refinery through Moriarty to Bloomfield will permit the Company to deliver a
total of over 45,000 BPD of light products to these locations. If needed,
additional pump stations could further increase the pipeline's capabilities.
-12-
An additional factor that could affect some of the Company's markets is excess
pipeline capacity from the West Coast into the Company's Arizona markets after
the elimination of bottlenecks in 2000 on the pipeline from the West Coast to
Phoenix. If refined products become available on the West Coast in excess of
demand in that market, additional products could be shipped into the Company's
Arizona markets with resulting possible downward pressure on refined product
prices in these markets. The availability of refined products on the West Coast
for shipment to Phoenix may however be reduced by the effects on West Coast
gasoline supplies of the scheduled ban in California on the use of MTBE as a
constituent of gasoline after 2003.
In March 2000, Equilon Pipeline Company, LLC (whose successor is Shell Pipeline
Company, LP) announced a 500-mile pipeline, called the "New Mexico Products
Pipeline System" to carry gasoline and other refined fuels from the Odessa,
Texas area to Bloomfield, New Mexico. It was announced that the pipeline would
have a capacity of 40,000 BPD and that shipments would begin in 2001. In
addition to the pipeline, a product terminal would be built in Moriarty, New
Mexico. This system would have access to products manufactured at Gulf Coast
refineries and could result in an increase in the supply of products to some of
the Company's markets. This project has been delayed because of the requirement
announced in August 2000 that an environmental impact study must be completed on
the proposed project.
OTHER DEVELOPMENTS AFFECTING MARKETS AND COMPETITION
In addition to the projects described above, other projects have been explored
from time to time by refiners and other entities, which projects, if
consummated, could result in a further increase in the supply of products to
some or all of the Company's markets.
In recent years, there have been several refining and marketing consolidations
or acquisitions between entities competing in the Company's geographic market.
These transactions could increase future competitive pressures on the Company.
CRUDE OIL AND FEEDSTOCK SUPPLIES
The Navajo Refinery is situated near the Permian Basin in an area which
historically has had abundant supplies of crude oil available both for regional
users, such as the Company, and for export to other areas. The Company purchases
crude oil from producers in nearby southeastern New Mexico and West Texas and
from major oil companies. Crude oil is gathered both through the Company's
pipelines and tank trucks and through third party crude oil pipeline systems.
Crude oil acquired in locations distant from the refinery is exchanged for crude
oil that is transportable to the refinery. In recent years the Company's access
to crude oil has expanded, primarily as a result of acquisitions in 1998 and
1999 of crude oil gathering, transportation and storage assets in West Texas.
Approximately 4,000 BPD of isobutane used in the Navajo Refinery's operations is
purchased from other refineries in the region and is shipped to the Artesia
refining facilities on a Company-owned 65-mile pipeline running from Lovington
to Artesia.
PRINCIPAL PRODUCTS AND MARKETS
The Navajo Refinery converts approximately 91% of its raw materials throughput
into high value light products.
-13-
Set forth below is certain information regarding the principal products of
Navajo during the last three fiscal years:
YEARS ENDED JULY 31,
------------------------------------------------------------------
2002 2001 2000
------------------- ------------------ -------------------
BPD % BPD % BPD %
--------- -------- ------- -------- ------- --------
Sales of produced refined products (1)
Gasolines.............................. 34,800 58.2% 36,000 57.5% 37,500 58.4%
Diesel fuels........................... 12,900 21.6% 13,800 22.0% 14,200 22.0%
Jet fuels.............................. 6,600 11.0% 7,000 11.2% 6,800 10.6%
Asphalt................................ 3,400 5.7% 3,500 5.6% 3,600 5.6%
LPG and other.......................... 2,100 3.5% 2,300 3.7% 2,200 3.4%
--------- -------- ------- -------- ------- --------
Total............................... 59,800 100.0% 62,600 100.0% 64,300 100.0%
========= ======== ======= ======== ======= ========
(1) Excludes refined products purchased for resale.
Light products are shipped by product pipelines or are made available at various
points by exchanges with others. Light products are also made available to
customers through truck loading facilities at the refinery and at terminals.
Navajo's principal customers for gasoline include other refiners, convenience
store chains, independent marketers, an affiliate of PEMEX (the government-owned
energy company of Mexico) and retailers. Navajo's gasoline is marketed in the
southwestern United States, including the metropolitan areas of El Paso,
Phoenix, Albuquerque, Bloomfield, and Tucson, and in portions of northern
Mexico. The composition of gasoline differs, because of local regulatory
requirements, depending on the area in which gasoline is to be sold; under
current standards, MTBE is a constituent of gasolines exported by the Company to
northern Mexico and some grades of gasoline marketed in Phoenix during certain
times of the year. Diesel fuel is sold to other refiners, truck stop chains,
wholesalers, and railroads. Jet fuel is sold primarily for military use.
Military jet fuel is sold to the Defense Energy Support Center (the "DESC")
under a series of one-year contracts that can vary significantly from year to
year. Navajo sold approximately 6,800 BPD of jet fuel to the DESC in its 2002
fiscal year and has a contract to supply up to 8,500 BPD to the DESC for the
year ending September 30, 2003. Since the formation of NK Asphalt Partners in
July 2000, all asphalt is sold to NK Asphalt Partners. Carbon black oil is sold
for further processing, and LPGs are sold to LPG wholesalers and LPG retailers.
Approximately 5% of the Company's revenues for fiscal 2002 resulted from the
sale for export of gasoline and diesel fuel to an affiliate of PEMEX.
Approximately 9% of the Company's revenues for fiscal 2002 resulted from the
sale of military jet fuel to the United States Government. The Company has had a
military jet fuel supply contract with the United States Government for each of
the last 33 years. The Company's size in terms of employees and refining
capacity allows the Company to bid for military jet fuel sales contracts under a
small business set-aside program; a pending proposal would significantly
increase the maximum refining capacity that would qualify for this program from
the current level of 75,000 BPD. The loss of Navajo's military jet fuel contract
with the United States Government could have a material adverse effect on the
Company's results of operations to the extent alternate commercial jet fuel or
additional diesel fuel sales could not be secured. In addition to the United
States Government and PEMEX, other significant sales were made to two petroleum
companies. Arco Products Company, which in April 2000 was acquired by BP p.l.c.,
is a purchaser of gasoline that supplies Arco's retail network and accounted for
approximately 15% of the Company's revenues in fiscal 2002. Tosco Corporation
and affiliates, which in September 2001 was acquired by Phillips Petroleum
Company, (now "ConocoPhillips"), is a purchaser of gasoline and diesel fuel that
supplies Tosco's retail network and accounted for approximately 13% of the
Company's revenues in fiscal 2002. Loss of, or reduction in amounts purchased
by, major current purchasers for retail sales could have a material adverse
effect on the Company to the extent that, because of market limitations or
transportation constraints, the Company was not able to correspondingly increase
sales to other purchasers. The Company believes that its recently expanded
pipeline transportation system to the Albuquerque area and northern New Mexico
gives the Company increased flexibility in the event of the loss of a major
current purchaser of products for retail sales.
-14-
CAPITAL IMPROVEMENT PROJECTS
The Company has invested significant amounts in capital expenditures in recent
years to enhance the Navajo Refinery and expand its supply and distribution
network. In December 2001, the Company received the necessary permitting for the
construction of a new gas oil hydrotreater unit and for the expansion of the
crude refining capacity from 60,000 BPD to an estimated 70,000 BPD. The Company
expects that the hydrotreater and the expansion to an estimated 70,000 BPD will
be completed by December 2003. The total cost of the gas oil hydrotreater
project and the expansion is estimated to be $56 million, of which $20.4 million
has already been spent. In November 1997, the Company purchased a hydrotreater
unit for $5.1 million from a closed refinery. During the last three years, the
Company has spent approximately $15.3 million on relocation, engineering and
equipment fabrication related to the hydrotreater project. The remaining costs
to complete the hydrotreater and expansion projects are estimated to be
approximately $35.6 million. Additionally, Navajo Refining has budgeted $7
million in fiscal 2003 for other projects, principally refining and pipeline
projects.
The hydrotreater will enhance higher value light product yields and expand the
Company's ability to produce additional quantities of gasolines meeting the
present California Air Resources Board ("CARB") standards, which were adopted in
the Company's Phoenix market for winter months beginning in late 2000, and
enable the Company to meet the recently adopted EPA nationwide Low-Sulfur
Gasoline requirements scheduled to become effective in 2004 on all of the
Company's gasolines. Based on the current configuration of the Navajo Refinery,
the Company can produce sufficient volumes under the present Phoenix CARB
standards to supply the Phoenix market in the winter months at the Company's
historic levels without increasing beyond normal levels the Company's purchases
of such gasoline from other refiners. Additionally, in fiscal 2001 the Company
completed the construction of a new additional sulfur recovery unit, which is
currently utilized to enhance sour crude processing capabilities and will
provide sufficient capacity to recover the additional extracted sulfur that will
result from operations of the hydrotreater.
Contemporaneous with the hydrotreater project, Navajo will be making necessary
modifications to several of the Artesia processing units for the first phase of
Navajo's expansion, which will increase crude oil refining capacity from 60,000
BPD to an estimated 70,000 BPD. The first phase of the expansion is expected to
be completed by December 2003. Certain additional permits will be required to
implement needed modifications at Navajo's Lovington, New Mexico refining
facility which is operated in conjunction with the Artesia facility. It is
envisioned that these necessary modifications to the Lovington facility would
also be completed by December 2003. The permits received by Navajo to date for
the Artesia facility, subject to possible minor modifications, should also
permit a second phase expansion of Navajo's crude oil capacity from an estimated
70,000 BPD to an estimated 80,000 BPD, but a schedule for such additional
expansion has not been determined.
The Company leases from Mid-America Pipeline Company more than 300 miles of 8"
pipeline running from Chaves County to San Juan County, New Mexico (the "Leased
Pipeline"). The Company owns and operates a 12" pipeline from the Navajo
Refinery to the Leased Pipeline as well as terminalling facilities in
Bloomfield, New Mexico, which is located in the northwest corner of New Mexico
and in Moriarty, which is 40 miles east of Albuquerque. Transportation of
petroleum products to markets in northwest New Mexico and diesel fuels to
Moriarty began at the end of calendar 1999. In December 2001, the Company
completed an expansion of the Moriarty terminal and the pumping capacity on the
Leased Pipeline. The terminal expansion included the addition of gasoline and
jet fuel to the existing diesel fuel delivery capabilities, thus permitting the
Company to provide a full slate of light products to the growing Albuquerque and
Santa Fe, New Mexico areas. The enhanced pumping capabilities on the Company's
leased pipeline extending from the Artesia refinery through Moriarty to
Bloomfield will permit the Company to deliver a total of over 45,000 BPD of
light products to these locations. If needed, additional pump stations could
further increase the pipeline's capabilities.
The additional pipeline capacities resulting from the new pipelines constructed
in conjunction with the Rio Grande joint venture (discussed under "Pipeline
Transportation") and from the Leased Pipeline have reduced pipeline operating
expenses at existing throughputs. In addition, the new pipeline capacity will
allow the Company to increase volumes, through refinery expansion or otherwise,
that are shipped into existing and new markets and
-15-
would allow the Company to shift volumes among markets in response to any future
increased competition in particular markets.
MONTANA REFINERY
MRC owns a 7,000 BPD petroleum refinery in Great Falls, Montana, which can
process a wide range of crude oils and primarily serves markets in Montana. For
the last three fiscal years, excluding downtime for scheduled maintenance and
turnarounds, the Montana Refinery has operated at an average annual crude
capacity utilization rate of approximately 89%.
The following table sets forth certain information about the operations of the
Montana Refinery during the last three fiscal years:
YEARS ENDED JULY 31,
---------------------------------
2002 2001 2000
------ ------- --------
Crude charge (BPD) (1).......................... 6,600 6,200 5,900
Refinery production (BPD) (2)................... 7,000 6,400 6,200
Sales of produced refined products (BPD)........ 7,200 6,500 6,100
Sales of refined products (BPD) (3)............. 7,500 6,800 6,600
Refinery utilization (4)........................ 94.3% 88.6% 84.3%
(1) Crude charge represents the barrels per day of crude oil processed through
the crude unit at each of the Company's refineries.
(2) Refinery production represents the barrels per day of refined products
yielded from processing crude and other refinery feedstocks through the
crude units and other conversion units at each of the Company's refineries.
(3) Includes refined products purchased for resale representing 300 BPD, 300
BPD, and 500 BPD, respectively.
(4) Crude charge divided by total crude capacity of 7,000 BPD.
The Montana Refinery currently obtains its supply of crude oil primarily from
suppliers in Canada via a common carrier pipeline, which runs from the Canadian
border to the refinery. The Montana Refinery's principal markets include Great
Falls, Helena, Bozeman and Billings, Montana. MRC competes principally with
three other Montana refineries.
Set forth below is certain information regarding the principal products of
Montana Refinery during the last three fiscal years:
-16-
YEARS ENDED JULY 31,
---------------------------------------------------------------------
2002 2001 2000
--------------------- -------------------- -------------------
BPD % BPD % BPD %
--------- -------- -------- -------- ------- -------
Sales of produced refined products (1)
Gasolines............................... 2,900 40.3% 2,700 41.5% 2,600 42.6%
Diesel fuels............................ 1,100 15.3% 1,300 20.0% 1,200 19.7%
Jet fuels............................... 500 6.9% 400 6.2% 500 8.2%
Asphalt................................. 2,400 33.3% 1,800 27.7% 1,500 24.6%
LPG and other........................... 300 4.2% 300 4.6% 300 4.9%
--------- -------- -------- -------- ------ -------
Total................................ 7,200 100.0% 6,500 100.0% 6,100 100.0%
========= ======== ======== ======== ====== =======
(1) Excludes refined products purchased for resale.
For the 2003 fiscal year, MRC's capital budget totals $800,000, most of which is
for various improvements at the Montana Refinery.
PIPELINE TRANSPORTATION OPERATIONS
PIPELINE TRANSPORTATION BUSINESS
In recent years, the Company developed and expanded a pipeline transportation
business generating revenues from unaffiliated parties. The pipeline
transportation operations include approximately 1,000 miles of the 2,000 miles
of pipeline that the Company owns and operates, of which approximately 400 miles
are part of the supply and distribution network of the Navajo Refinery.
Additionally, the Company has a 25% investment in Rio Grande Pipeline Company,
described below. For fiscal 2003, the Company did not budget any significant
amount for capital expenditures that will be used for the pipeline
transportation business.
The Company has a 25% interest in Rio Grande Pipeline Company ("Rio Grande"), a
pipeline joint venture with subsidiaries of The Williams Companies, Inc. and BP
p.l.c. to transport liquid petroleum gases to Mexico. Deliveries by the joint
venture began in April 1997.
In October 1996, the Company completed a new 12" refined products pipeline from
Orla to El Paso, Texas, which replaced a portion of an 8" pipeline previously
used by Navajo that was transferred to Rio Grande.
In 1998, the Company implemented an alliance with FINA, Inc. ("FINA") to create
a comprehensive supply network that can increase substantially the supplies of
gasoline and diesel fuel in the West Texas, New Mexico, and Arizona markets to
meet expected increasing demand in the future. FINA constructed a 50-mile
pipeline which connected an existing FINA pipeline system to the Company's 12"
pipeline between Orla, Texas and El Paso, Texas pursuant to a long-term lease of
certain capacity of the Company's 12" pipeline. In August 1998, FINA began
transporting to El Paso gasoline and diesel fuel from its Big Spring, Texas
refinery, and the Company began to realize pipeline rental and terminalling
revenues from FINA under these agreements. In August 2000, Alon USA LP, a
subsidiary of an Israeli petroleum refining and marketing company, succeeded to
FINA's interest in this alliance. Effective from February 2002, Alon may
transport up to 20,000 BPD to El Paso on this interconnected system.
The Company operates a crude oil gathering system in West Texas purchased from
Fina Oil and Chemical Company in 1998. The assets purchased include
approximately 500 miles of pipelines and over 350,000 barrels of tankage.
Approximately 27,000 barrels per day of crude oil are gathered on these systems.
These assets generate a relatively stable source of transportation service
income and give Navajo the ability to purchase additional crude oil at the lease
in new areas, thus potentially enhancing the stability of crude oil supply and
refined product margins for the Navajo Refinery.
During the fourth quarter of fiscal 1999, the Company completed a new 65-mile
10" pipeline between Lovington and Artesia, New Mexico, to permit the delivery
of isobutane (and/or other LPGs) to an unrelated refinery in El Paso as well as
to increase the Company's ability to access additional raw materials for the
Navajo Refinery.
-17-
In the second quarter of fiscal 2000, the Company acquired certain pipeline
transportation and storage assets located in West Texas and New Mexico in an
asset exchange with ARCO Pipeline Company. The acquired assets, including 100
miles of pipelines and over 250,000 barrels of tankage, allow the Company to
transport crude oil for unaffiliated companies and increase the Company's
ability to access additional crude oil for the Navajo Refinery.
ADDITIONAL OPERATIONS AND OTHER INFORMATION
CORPORATE OFFICES
The Company leases its principal corporate offices in Dallas, Texas. The
Company's lease for its principal corporate offices expires April 30, 2006,
requires lease payments of $32,951 per month, plus certain operating expenses,
and provides for no option to renew. The operations of Holly Corporation, the
parent company, are performed at this location. Functions performed by the
parent company include overall corporate management, planning and strategy,
legal support, treasury management and tax reporting.
EXPLORATION AND PRODUCTION
The Company conducts a small-scale oil and gas exploration and production
program. For fiscal 2003, the Company has budgeted approximately $600,000 for
capital expenditures related to oil and gas exploration activities.
JET FUEL TERMINAL
The Company owns and operates a 120,000-barrel-capacity jet fuel terminal near
Mountain Home, Idaho, which serves as a terminalling facility for jet fuel sold
by unaffiliated producers to the Mountain Home United States Air Force Base.
OTHER INVESTMENTS
In fiscal 1998, the Company invested and advanced a total of $2 million to a
joint venture operating retail service stations and convenience stores in
Montana. The Company has a 49% interest in the joint venture and accounts for
earnings using the equity method. The Company has reserved approximately
$800,000 related to the collectability of advances and related accrued interest
to this joint venture.
EMPLOYEES AND LABOR RELATIONS
As of September 30, 2002, the Company had approximately 560 employees of which
approximately 210 are covered by collective bargaining agreements ("Covered
Employees"). Contracts relating to the Covered Employees at all facilities will
expire during 2006. The Company considers its employee relations to be good.
REGULATION
Refinery and pipeline operations are subject to federal, state and local laws
regulating the discharge of matter into the environment or otherwise relating to
the protection of the environment. Permits are required under these laws for the
operation of our refineries, pipelines and related operations, and these permits
are subject to revocation, modification and renewal. Over the years, there have
been and continue to be ongoing communications, including notices of violations,
and discussions about environmental matters between the Company and federal and
state authorities, some of which have resulted or will result in changes of
operating procedures and in capital expenditures by the Company. Compliance with
applicable environmental laws, regulations and permits will continue to have an
impact on the Company's operations, results of operations and capital
requirements. The Company believes that its current operations are in
substantial compliance with existing environmental laws, regulations and
permits.
The Company's operations and many of the products it manufactures are
specifically subject to certain requirements of the federal Clean Air Act
("CAA") and related state and local regulations. The CAA contains provisions
that will require capital expenditures for the installation of certain air
pollution control devices at the Company's refineries during the next several
years. Subsequent rule making authorized by the CAA or similar laws or new
agency interpretations of existing rules, may necessitate additional
expenditures in future years. In December 2001, following discussions initiated
by the Company, the Company entered into Consent Decree with the EPA, the New
Mexico Environment Department and the Montana Department of Environmental
Quality with respect to a global settlement of issues concerning the application
of air quality requirements to past and future operations of the Company's
refineries. The Consent Decree was entered by the federal court in New Mexico in
March 2002 and
-18-
requires investments by the Company expected to total between $15 million and
$20 million over a number of years as well as changes in operational practices
at the Navajo and Montana refineries. See the discussion of the Consent Decree
below and under Item 3, "Legal Proceedings."
The CAA may authorize the EPA to require modifications in the formulation of the
refined transportation fuel products the Company manufactures in order to limit
the emissions associated with their final use. For example, on December 21,
1999, the EPA promulgated national regulations limiting the amount of sulfur
that is to be allowed in gasoline. The EPA believes such limits are necessary to
protect new automobile emission control systems that may be inhibited by sulfur
in the fuel. The new regulations require the phase-in of gasoline sulfur
standards beginning in 2004 and continuing until 2008, with special provisions
for refiners serving those Western states exhibiting lesser air quality problems
and for small business refiners, such as the Company.
The EPA recently promulgated regulations that will limit the sulfur content of
highway diesel fuel beginning in 2006 to 15 parts per million. The current
standard is 500 parts-per-million. As a small business refiner, the Company may,
on a refinery by refinery basis, choose to comply with the 2006 program and
extend its interim gasoline standard by three years (until 2011) or delay the
diesel standard by four years (until 2010) and keep its original gasoline sulfur
program timing.
The EPA has recently stated its intent to propose new regulations that will
limit emissions from diesel fuel powered engines used in off-road activities
such as mining, construction and agriculture. The EPA has also stated its intent
to simultaneously limit the sulfur content of diesel fuel used in these engines
to facilitate compliance with the new emission standards. The EPA expects to
propose the new off-road diesel engine emissions and related fuel sulfur
standards early in 2003.
Additionally, effective January 1, 1995, certain cities in the United States
were required to use only reformulated gasoline ("RFG"), a cleaner burning fuel.
Phoenix is the only principal market of the Company that currently requires the
equivalent of RFG (or an alternative clean burning gasoline formula), although
this requirement could be implemented in other markets over time. Phoenix
adopted the even more rigorous California Air Resources Board ("CARB") fuel
specifications for winter months beginning in late 2000. This new requirement,
the recently adopted low-sulfur gasoline and diesel requirements described
above, and other requirements of the CAA, could cause the Company to expend
substantial amounts to permit the Company's refineries to produce products that
meet applicable requirements. The Company believes that the completion of the
hydrotreater project described above under "Capital Improvement Projects" will
allow the Company to meet announced future gasoline requirements.
The Company is aware of public concern regarding possible groundwater
contamination resulting from the use of MTBE (methyl tertiary butyl ether) as a
source of required oxygen in gasolines sold in specified areas of the country.
Gasoline containing a specified amount of oxygen is required by the EPA to be
used in those regions that exceed the National Ambient Air Quality Standards for
either ozone or carbon monoxide. That oxygen requirement may be satisfied by
adding to gasoline any one of many oxygen-containing materials including, among
others, MTBE and also ethanol, an oxygen containing compound that is
manufactured primarily from "renewable" agricultural products and that has not
been shown to exhibit the environmental concerns associated with MTBE. Ethanol
serves as an oxygenate, an octane booster and as an extender of gasoline.
The Company's operations are also subject to the federal Clean Water Act
("CWA"), the federal Safe Drinking Water Act ("SDWA") and comparable state and
local requirements. The CWA, the SDWA and analogous laws prohibit any discharge
into surface waters, ground waters and publicly-owned treatment works except in
strict conformance with permits, such as pre-treatment permits and National
Pollutant Discharge Elimination System ("NPDES") permits, issued by federal,
state and local governmental agencies. NPDES permits and analogous water
discharge permits are valid for a maximum of five years and must be renewed.
The Company generates wastes that may be subject to the Resource Conservation
and Recovery Act ("RCRA") and comparable state and local requirements. The EPA
and various state agencies have limited the approved methods of disposal for
certain hazardous and non hazardous wastes.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as "Superfund," imposes liability, without regard to
fault or the legality of the original conduct, on certain classes of
-19-
persons who are considered to be responsible for the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances. Under CERCLA,
such persons may be subject to joint and several liabilities for the costs of
cleaning up the hazardous substances that have been released into the
environment, for damages to natural resources and for the costs of certain
health studies. It is not uncommon for neighboring landowners and other third
parties to file claims for personal injury and property damage allegedly caused
by hazardous substances or other pollutants released into the environment.
Analogous state laws impose similar responsibilities and liabilities on
responsible parties. In the course of our historical operations, as well as in
our current ordinary operations, we have generated waste, some of which falls
within the statutory definition of a "hazardous substance" and some of which may
have been disposed of at sites that may require cleanup under Superfund.
As is the case with all companies engaged in industries similar to ours, we face
potential exposure to future claims and lawsuits involving environmental
matters. The matters include soil and water contamination, air pollution,
personal injury and property damage allegedly caused by substances which we
manufactured, handled, used, released or disposed of.
The Company is and has been the subject of various state, federal and private
proceedings relating to environmental regulations, conditions and inquiries,
including the Consent Decree discussed above and below in Item 3, "Legal
Proceedings." Current and future environmental regulations are expected to
require additional expenditures, including expenditures for investigation and
remediation, which may be significant, at the New Mexico and Montana refineries
and at pipeline transportation facilities. The extent of future expenditures for
these purposes cannot presently be determined.
The Company's operations are also subject to various laws and regulations
relating to occupational health and safety. The Company maintains safety,
training and maintenance programs as part of its ongoing efforts to ensure
compliance with applicable laws and regulations. Compliance with applicable
health and safety laws and regulations has required and continues to require
substantial expenditures.
The Company cannot predict what additional health and environmental legislation
or regulations will be enacted or become effective in the future or how existing
or future laws or regulations will be administered or interpreted with respect
to the Company's operations. Compliance with more stringent laws or regulations
or more vigorous enforcement policies of regulatory agencies could have an
adverse effect on the financial position and the results of operations of the
Company and could require substantial expenditures by the Company for the
installation and operation of systems and equipment not currently possessed by
the Company.
INSURANCE
The Company's operations are subject to normal hazards of operations, including
fire, explosion and weather-related perils. The Company maintains various
insurance coverages, including business interruption insurance, subject to
certain deductibles. The Company is not fully insured against certain risks
because such risks are not fully insurable, coverage is unavailable, or premium
costs, in the judgment of the Company, do not justify such expenditures. At the
current time the Company is not fully insured for terrorism since, in the
judgment of the Company, premium costs in the current insurance market do not
justify such expenditures. Shortly after the events of September 11, 2001, the
Company completed a security assessment of its principal facilities. Several
security measures identified in the assessment have been implemented and other
security measures are in the process of being implemented. Because of recent
changes in insurance markets, insurance coverages available to the Company are
becoming more costly and in some cases less available. So long as this current
trend continues, the Company expects to incur higher insurance costs and
anticipates that, in some cases, it will be necessary to reduce somewhat the
extent of insurance coverages because of reduced insurance availability at
acceptable premium costs.
COST REDUCTION AND PRODUCTION EFFICIENCY PROGRAM
In May 2000, the Company announced a cost reduction and production efficiency
program. The cost reduction and production efficiency program included
productivity enhancements and a reduction in workforce. By the end of fiscal
2002, implementation of the program and other initiatives has achieved
approximately $20 million in annual pre-tax improvements. As part of the
implementation of cost reductions, the Company offered a voluntary early
retirement program to eligible employees, under which 55 employees retired by
July 31, 2001. The pre-tax cost of
-20-
the voluntary early retirement program was $6.8 million and was reflected in the
Company's earnings for the quarter ended July 31, 2000.
ITEM 3. LEGAL PROCEEDINGS
In August 1998, a lawsuit (the "El Paso Lawsuit") was filed in state district
court in El Paso, Texas against the Company and two of its subsidiaries (along
with an Austin, Texas law firm which was subsequently dropped from the case).
The suit was filed by Longhorn Partners Pipeline, L.P. ("Longhorn Partners"), a
Delaware limited partnership composed of Longhorn Partners GP, L.L.C. as general
partner and affiliates of ExxonMobil Pipeline Company, BP Pipeline (North
America), Inc., Williams Pipe Line Company, and the Beacon Group Energy
Investment Fund, L.P. and Chisholm Holdings as limited partners. The suit, as
most recently amended by Longhorn Partners in September 2000, seeks damages
alleged to total up to $1,050,000,000 (after trebling) based on claims of
violations of the Texas Free Enterprise and Antitrust Act, unlawful interference
with existing and prospective contractual relations, and conspiracy to abuse
process. The specific actions of the Company complained of in the El Paso
Lawsuit, as currently amended, are alleged solicitation of and support for
allegedly baseless lawsuits brought by Texas ranchers in federal and state
courts to challenge the proposed Longhorn Pipeline project, support of allegedly
fraudulent public relations activities against the proposed Longhorn Pipeline
project, entry into a contractual "alliance" with Fina Oil and Chemical Company,
threatening litigation against certain partners in Longhorn Partners, and
alleged interference with the federal court settlement agreement that provided
for an Environmental Assessment of the Longhorn Pipeline. In April 2002, the
state district court in El Paso denied the Company's motion for summary judgment
which had been pending for more than a year and which sought a court ruling that
would have terminated the litigation. The Company filed an appeal seeking review
by the state appeals court in El Paso of the district court's denial of summary
judgment; in late August 2002, the state appeals court in El Paso issued an
order dismissing the appeal for want of jurisdiction. In early October 2002 the
Company filed a petition seeking review by the Texas Supreme Court of the
decision of the state appeals court. In the trial court, a motion filed by the
Company to transfer the venue for trial of the case from the El Paso trial court
to another Texas court has been pending since May 2000, and no hearing on this
motion is currently scheduled. The Company believes that the El Paso Lawsuit is
wholly without merit and plans to continue to defend itself vigorously. In
August 2002, the Company filed a lawsuit in New Mexico state court in Carlsbad,
New Mexico (the "Carlsbad Lawsuit") against Longhorn Partners and its major
owners concerning the El Paso Lawsuit; the Carlsbad Lawsuit seeks actual and
punitive damages for tortious interference with existing business relations,
malicious abuse of process, unfair competition, prima facie tort and conspiracy.
The Company and the other parties in the El Paso Lawsuit and the Carlsbad
Lawsuit have agreed to suspend temporarily further proceedings in these lawsuits
to permit voluntary mediation in November 2002 concerning issues involved in the
two lawsuits.
In December 2001, with the consent of the Company, a Consent Decree (the
"Consent Decree") was filed in the United States District Court for the District
of New Mexico in the case of United States of America v. Navajo Refining
Company, L.P. and Montana Refining Company. The Consent Decree resulted from
negotiations which were initiated by the Company and which began in July 2001
involving representatives of the Company, the EPA, the New Mexico Environment
Department, and the Montana Department of Environmental Quality with respect to
a possible settlement of issues concerning the application of federal and state
air quality requirements to past and future operations of the Company's
refineries. The Consent Decree was approved and entered by the Court in March
2002. The Consent Decree requires investments by the Company expected to total
between $15 million and $20 million over a number of years at the Company's New
Mexico and Montana refineries for the installation of certain state of the art
pollution control equipment and requires changes in operational practices at
these refineries that go beyond current regulatory requirements to reduce air
emissions. In addition, the Consent Decree provides to the Company and its
subsidiaries releases from liability for enforcement actions with respect to a
number of possible issues relating to the application of air quality regulations
to the Company's refineries. The Consent Decree also provides for payment by the
Company of penalties to Federal, New Mexico and Montana regulatory authorities
in the total amount of $750,000 and expenditures of approximately $1.5 million
for environmentally beneficial projects and provides for the payment by the
Company of agreed monetary penalties in the event of noncompliance with
specified requirements of the Consent Decree. The Company is currently
implementing provisions of the Consent Decree applicable to current operations
and is preparing to implement those Consent Decree provisions that require
future capital investments or operational changes.
In September 2002, the Company filed suit against the Federal Government in the
United States Court of Federal
-21-
Claims (the "Federal Claims Lawsuit") with respect to claims which total
approximately $210 million relating to jet fuel sales by the Company to the
Defense Fuel Supply Center in the years 1982 through 1995; these claims had been
filed by the Company in May and June 2001 and were denied by the Department of
Defense in November 2001. Also in September 2002, the Company filed additional
claims with the Department of Defense under the Contract Disputes Act asserting
that additional amounts totaling approximately $88 million are due to the
Company with respect to jet fuel sales to the Defense Fuel Supply Center in the
years 1995 through 1999 (the "1995-99 Jet Fuel Claims"). While the Company
believes that the positions asserted by the Company in the Federal Claims
Lawsuit and in the 1995-99 Jet Fuel Claims are justified under applicable law,
the Company believes that the Federal Claims Lawsuit will be vigorously
contested by the Federal Government and that, as to the 1995-99 Jet Fuel Claims,
these claims will initially not be allowed by the Department of Defense and any
recovery with respect to these claims would require further proceedings. It is
not possible at the date of this report to predict what amount, if any, will
ultimately be payable to the Company with respect to the Federal Claims Lawsuit
and the 1995-99 Jet Fuel Claims.
In September 2002, the Federal Energy Regulatory Commission ("FERC") issued an
order (the "Order") in proceedings brought by the Company and other parties
against SFPP relating to tariffs of common carrier pipelines, which are owned
and operated by SFPP, for shipments of refined products in the period from 1993
through July 2000 from El Paso, Texas to Tucson and Phoenix, Arizona and from
points in California to points in Arizona. The Company is one of several
refiners that regularly utilize an SFPP pipeline to ship refined products from
El Paso, Texas to Tucson and Phoenix, Arizona. The Order appears to resolve most
remaining issues relating to SFPP's tariffs on the pipelines to points in
Arizona from 1993 through July 2000 and is expected to be followed by a final
FERC ruling after completion of computations based on the guidance provided by
the Order. Based on prior preliminary computations and the rulings made in the
Order, the Company expects that the final FERC ruling for the years at issue
would result in a refund to the Company of approximately $15 million. The final
FERC decision on this matter will be subject to judicial review by the Court of
Appeals for the District of Columbia Circuit. At the date of this Report, it is
not possible to predict when amounts may be payable to the Company under the
anticipated final FERC decision on this matter, whether a final settlement may
be reached with SFPP based on the Order, or what may be the result of judicial
review proceedings on this matter in the Court of Appeals for the District of
Columbia Circuit.
The Company is a party to various other litigation and proceedings which it
believes, based on advice of counsel, will not have a materially adverse impact
on the Company's financial condition, results of operations or cash flows.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders during the fourth quarter
of the Company's 2002 fiscal year.
EXECUTIVE OFFICERS OF REGISTRANT
The executive officers of the Company as of October 10, 2002 are as
follows:
EXECUTIVE
NAME AGE POSITION OFFICER SINCE
---- --- -------- -------------
Lamar Norsworthy 56 Chairman of the Board 1971
and Chief Executive Officer
Matthew P. Clifton 51 President and Director 1988
W. John Glancy 60 Senior Vice President, General 1998
Counsel, Secretary and Director
David G. Blair 44 Vice President, Marketing 1994
Asphalt and LPG
Leland J. M. Griffin 54 Vice President, Montana 1999
Operations
-22-
Thomas D. Guercio 33 Vice President, Information 2001
Technology
Randall R. Howes 45 Vice President, Technical Support 1997
and Planning
John A. Knorr 52 Vice President, Crude Oil 1988
Supply and Trading
Stephen J. McDonnell 51 Vice President and Chief 2000
Financial Officer
Mike Mirbagheri 63 Vice President, International 1982
Crude Oil and Refined
Products
Bruce R. Shaw 35 Vice President, Corporate Development 2001
Scott C. Surplus 43 Vice President, Treasury and Tax 2000
James G. Townsend 47 Vice President, Pipelines
and Terminals 1997
Kathryn H. Walker 52 Vice President, Accounting 1999
Gregory A. White 45 Vice President, Marketing 1994
Light Oils
In addition to the persons listed above, James E. Resinger has served as
refinery manager of the Navajo Refinery since late July 2002. Prior to joining
the Company, Mr. Resinger served from June 1997 to October 2000 as FCC Complex
Manager and from October 2000 to July 2002 as Director of Refinery Operations
for Hess Oil, Virgin Islands.
All officers of the Company are elected annually to serve until their successors
have been elected. Mr. Glancy held the office of Senior Vice President, Legal
from December 1998 through September 1999, when his title was changed to Senior
Vice President and General Counsel; he has held the additional office of
Secretary since April 1999; prior to December 1998, Mr. Glancy had been outside
counsel to the Company on various matters for over 10 years. Mr. Knorr is also
President of one of the partners of MRC and serves as the General Manager of
MRC. Mr. Griffin and Ms. Walker have served in their respective positions since
September 1999. Mr. Griffin has served as the Refinery Manager of the Montana
Refinery since 1989. Ms. Walker has served as the Controller of Navajo since
1993. Mr. McDonnell held the office of Vice President, Finance and Corporate
Development from August 2000 to September 2001, when his title was changed to
Vice President and Chief Financial Officer. Mr. McDonnell was with Central and
South West Corporation as a Vice President in the mergers and acquisitions area
from 1996 to June 2000. Mr. Shaw was Vice President of Brierley & Partners,
specializing in early stage investments, from 2000 to 2001 and from 1997 to 1999
was Director of Corporate Development for Holly Corporation. Mr. Surplus has
served in his current position since June 2000. Mr. Surplus previously served as
Assistant Treasurer of the Company from 1990 to March 2000. From April 2000 to
June 2000, Mr. Surplus was not with the Company and was the Vice President,
Finance of e.io, inc., a data storage service company. Mr. Guercio has served in
his current position since September 2001 and has served as the Company's Chief
Information Officer since May 2001, when he joined the Company. Mr. Guercio
served as a Managing Director for an energy based technology company, Delinea
Corporation, from September 2000 to May 2001, and was the Chief Information
Officer and Director of Operations from October 1998 to September 2000 for
Toni&Guy and TIGI Linea, an international retailer, distributor and
manufacturing company. From 1992 to October 1998, Mr. Guercio was with KPMG in
the business consulting and assurance practices area.
-23-
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The Company's common stock is traded on the American Stock Exchange under the
symbol "HOC". The following table sets forth the range of the daily high and low
sales prices per share of common stock, dividends paid per share and the trading
volume of common stock for the periods indicated:
TOTAL
FISCAL YEARS ENDED JULY 31, HIGH LOW DIVIDENDS VOLUME
--------------------------- ---- --- --------- ------
2001
First Quarter ...................... $ 6.63 $ 5.97 $ .09 651,200
Second Quarter ..................... $ 9.75 $ 6.25 $ .09 1,509,200
Third Quarter ...................... $ 18.40 $ 8.95 $ .09 3,647,800
Fourth Quarter ..................... $ 25.07 $ 15.00 $ .10 10,746,000
2002
First Quarter ...................... $ 21.07 $ 13.76 $ .10 2,504,300
Second Quarter ..................... $ 20.24 $ 14.97 $ .10 2,677,400
Third Quarter ...................... $ 20.54 $ 15.95 $ .10 2,418,500
Fourth Quarter ..................... $ 18.12 $ 14.15 $ .11 3,039,700
In June 2001, the Board of Directors declared a two-for-one stock split,
effected in the form of a 100-percent stock dividend which was distributed in
July 2001. All references to the number of shares (other than common stock on
the Consolidated Balance Sheet) and per share amounts in this Form 10-K/A Annual
Report have been adjusted to reflect the split on a retroactive basis.
As of September 30, 2002, the Company had approximately 1,600 stockholders of
record.
On September 20, 2002, the Company's Board of Directors declared a regular
quarterly dividend in the amount of $.11 per share payable on October 7, 2002.
The Company intends to consider the declaration of a dividend on a quarterly
basis, although there is no assurance as to future dividends since they are
dependent upon future earnings, capital requirements, the financial condition of
the Company and other factors. The Senior Notes and Credit Agreement limit the
payment of dividends. See Note 7 to the Consolidated Financial Statements.
-24-
ITEM 6. SELECTED FINANCIAL DATA
The following table shows selected financial information for the Company as of
the dates or for the periods indicated. This table should be read in conjunction
with the consolidated financial statements of the Company and related notes
thereto included elsewhere in this Form 10-K/A.
YEARS ENDED JULY 31, 2002 2001 2000 1999 1998
--------------------------------------------------------------------------------------------------------------------------
(In thousands, except per share amounts)
FINANCIAL DATA
For the year
Sales and other revenues .............................. $ 888,906 $ 1,142,130 $ 965,946 $ 597,986 $ 590,299
Income before income taxes ............................ $ 50,896 $ 121,895 $ 18,634 $ 33,159 $ 24,866
Income tax provision .................................. $ 18,867 $ 48,445 $ 7,189 $ 13,222 $ 9,699
--------- ----------- --------- --------- ---------
Net income ............................................ $ 32,029 $ 73,450 $ 11,445 $ 19,937 $ 15,167
========= =========== ========= ========= =========
Net income per common share - basic ................... $ 2.06 $ 4.84 $ 0.71 $ 1.21 $ 0.92
Net income per common share - diluted ................. $ 2.01 $ 4.77 $ 0.71 $ 1.21 $ 0.92
Cash dividends declared per common share ............... $ 0.41 $ 0.37 $ 0.34 $ 0.32 $ 0.30
Average number of common shares outstanding
Basic .............................................. 15,560 15,187 16,131 16,507 16,507
Diluted ............................................ 15,971 15,387 16,131 16,507 16,507
At end of year
Working capital ....................................... $ 59,873 $ 57,731 $ 363 $ 13,851 $ 14,793
Total assets .......................................... $ 502,306 $ 490,429 $ 464,362 $ 390,982 $ 349,857
Long-term debt (including current portion) ............ $ 34,285 $ 42,857 $ 56,595 $ 70,341 $ 75,516
Stockholders' equity .................................. $ 228,556 $ 201,734 $ 129,581 $ 128,880 $ 114,349
Net cash provided by operating activities ............... $ 41,847 $ 105,641 $ 46,804 $ 47,628 $ 38,193
Net cash used for financing activities .................. $ (14,104) $ (14,677) $ (27,227) $ (22,057) $ (4,674)
Net cash used for investing activities .................. $ (21,953) $ (28,752) $ (20,143) $ (23,979) $ (50,959)
-25-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
This Item 7, including but not limited to the sections on "Liquidity and Capital
Resources" and "Additional Factors that May Affect Future Results," contains
"forward-looking" statements. See "Forward-Looking Statements" at the beginning
of Part I.
CRITICAL ACCOUNTING POLICIES
The Company's discussion and analysis of its financial condition and results of
operations are based upon the Company's consolidated financial statements, which
have been prepared in accordance with accounting principles generally accepted
in the United States. The preparation of these financial statements requires the
Company to make estimates and judgments that affect the reported amounts of
assets, liabilities, revenues and expenses, and related disclosure of contingent
assets and liabilities as of the date of the financial statements. Actual
results may differ from these estimates under different assumptions or
conditions. The Company considers the following policies to be the most critical
to understanding the judgments that are involved and the uncertainties that
could impact its results of operations, financial condition and cash flows. For
additional information, also see Note 1 to the Consolidated Financial Statements
"Description of Business and Summary of Significant Accounting Policies".
INVENTORY VALUATION
The Company's crude oil and refined product inventories are stated at the lower
of cost or market. Cost is determined using the last-in, first-out ("LIFO")
inventory valuation methodology and market is determined using current estimated
selling prices. Under the LIFO method, the most recently incurred costs are
charged to cost of sales and inventories are valued at the earliest acquisition
costs. In periods of rapidly declining prices, LIFO inventories may have to be
written down to market due to the higher costs assigned to LIFO layers in prior
periods. In addition, the use of the LIFO inventory method may result in
increases or decreases to cost of sales in years that inventory volumes decline
as the result of charging cost of sales with LIFO inventory costs generated in
prior periods. As of July 31, 2002, the Company's LIFO inventory layers were
valued at historical costs that were established in years when price levels were
much lower; therefore, the Company is less sensitive to current market price
impairment. As of July 31, 2002, the excess of current cost over the LIFO value
of the Company's crude oil and refined product inventories was approximately
$30.1 million.
DEFERRED MAINTENANCE COSTS
The Company's refinery units require routine maintenance and repairs which are
commonly referred to as "turnarounds". Catalysts used in certain refinery
processes also require routine "change-outs". The required frequency of the
maintenance varies by unit and by catalyst, but generally is every two to five
years. In order to minimize downtime during turnarounds, the Company utilizes
contract labor as well as its maintenance personnel on a continuous 24 hour
basis. Whenever possible, turnarounds are scheduled so that some units continue
to operate while others are down for maintenance. The Company records the costs
of turnarounds as deferred charges and then amortizes the deferred costs over
the expected periods of benefit. The American Institute of Certified Public
Accountants has issued an Exposure Draft for a Proposed Statement of Position,
"Accounting for Certain Costs and Activities Related to Property, Plant, and
Equipment", which would require the Company to expense the turnaround costs as
they are incurred. If this proposed statement had been adopted in its current
form as of July 31, 2002, the Company would have been required to expense, as of
July 31, 2002, $13.8 million of deferred maintenance costs and would be required
to expense all future turnaround costs as incurred.
LONG-LIVED ASSETS
The Company calculates depreciation and amortization based on estimated useful
lives and salvage values of its assets. When assets are placed into service, the
Company makes estimates with respect to their useful lives that the Company
believes are reasonable. However, factors such as competition, regulation or
environmental matters could cause the Company to change its estimates, thus
impacting the future calculation of depreciation and amortization. The Company
evaluates long-lived assets for potential impairment by identifying whether
indicators of impairment exist and, if so, assessing whether the long-lived
assets are recoverable from estimated future undiscounted cash flows. The actual
amount of impairment loss, if any, to be recorded is equal to the amount by
which a long-lived asset's carrying value exceeds its fair value. Estimates of
future discounted cash flows and fair value of assets require subjective
assumptions with regard to future operating results and actual results could
differ from those
-26-
estimates. No impairments of long-lived assets were recorded during the fiscal
years ended July 31 2002, 2001, and 2000.
CONTINGENCIES
The Company is subject to proceedings, lawsuits and other claims related to
environmental, labor, product and other matters. The Company is required to
assess the likelihood of any adverse judgments or outcomes to these matters as
well as potential ranges of probable losses. A determination of the amount of
reserves required, if any, for these contingencies is made after careful
analysis of each individual issue. The required reserves may change in the
future due to new developments in each matter or changes in approach such as a
change in settlement strategy in dealing with these matters.
-27-
RESULTS OF OPERATIONS
FINANCIAL DATA
YEARS ENDED JULY 31,
------------------------------------
2002 2001 2000
---------- ----------- ---------
(In thousands, except per share data)
Sales and other revenues ........................................................... $ 888,906 $ 1,142,130 $ 965,946
Operating costs and expenses
Cost of products sold (exclusive of depreciation, depletion and amortization).... 698,245 871,321 800,663
Operating expenses (exclusive of depreciation, depletion and amortization) ...... 96,289 100,410 88,550
Selling, general and administrative expenses (exclusive of depreciation,
depletion, and amortization) ................................................... 22,248 23,123 20,724
Depreciation, depletion and amortization ........................................ 27,699 27,327 27,496
Exploration expenses, including dry holes ....................................... 1,379 2,042 1,729
Voluntary early retirement costs ................................................ - - 6,783
---------- ----------- ---------
Total operating costs and expenses ......................................... 845,860 1,024,223 945,945
---------- ----------- ---------
Income from operations ............................................................. 43,046 117,907 20,001
Other income (expense)
Equity in earnings of joint ventures ............................................ 7,753 5,302 1,586
Interest expense, net ........................................................... (1,425) (2,467) (5,153)
Other income .................................................................... 1,522 1,153 2,200
---------- ----------- ---------
7,850 3,988 (1,367)
---------- ----------- ---------
Income before income taxes ......................................................... 50,896 121,895 18,634
Income tax provision ............................................................... 18,867 48,445 7,189
---------- ----------- ---------
Net income ......................................................................... $ 32,029 $ 73,450 $ 11,445
========== =========== =========
Net income per common share - basic (1) ............................................ $ 2.06 $ 4.84 $ 0.71
Net income per common share - diluted (1) .......................................... $ 2.01 $ 4.77 $ 0.71
Cash dividends declared per common share ........................................... $ 0.41 $ 0.37 $ 0.34
Weighted average number of shares (1)
Basic ........................................................................... 15,560 15,187 16,131
Diluted ......................................................................... 15,971 15,387 16,131
Cash and cash equivalents .......................................................... $ 71,630 $ 65,840 $ 3,628
Working capital .................................................................... $ 59,873 $ 57,731 $ 363
Total assets ....................................................................... $ 502,306 $ 490,429 $ 464,362
Total debt, including current maturities ........................................... $ 34,285 $ 42,857 $ 56,595
Stockholders' equity ............................................................... $ 228,556 $ 201,734 $ 129,581
Total debt to capitalization ratio ................................................. 13.0% 17.5% 30.4%
Sales and other revenues (2)
Refining ........................................................................ $ 868,730 $ 1,120,248 $ 947,317
Pipeline Transportation ......................................................... 18,588 18,454 14,861
Corporate and other ............................................................. 1,588 3,428 3,768
---------- ----------- ---------
Consolidated .................................................................... $ 888,906 $ 1,142,130 $ 965,946
========== =========== =========
-28-
FINANCIAL DATA (CONTINUED)
YEARS ENDED JULY 31,
------------------------------------
2002 2001 2000
---------- ----------- ---------
(In thousands)
Income (loss) from operations (2)
Refining ........................................................................ $ 42,725 $ 116,218 $ 25,480
Pipeline Transportation ......................................................... 10,621 10,243 7,859
Corporate and other ............................................................. (10,300) (8,554) (13,338)
---------- ----------- ---------
Consolidated .................................................................... $ 43,046 $ 117,907 $ 20,001
========== =========== =========
Cash flow from operating activites ................................................. $ 41,847 $ 105,641 $ 46,804
Cash flow used for financing activites ............................................. $ (14,104) $ (14,677) $ (27,227)
Cash flow used for investing activites ............................................. $ (21,953) $ (28,752) $ (20,143)
Capital expenditures ............................................................... $ 35,313 $ 28,571 $ 19,261
EBITDA (3) ......................................................................... $ 80,020 $ 151,689 $ 51,283
(1) In June 2001, the Board of Directors declared a two-for-one stock split,
effected in the form of a 100-percent stock dividend which was distributed in
July 2001. All references to the number of shares and per share amounts have
been adjusted to reflect the split on a retroactive basis.
(2) The Refining segment includes the Company's principal refinery in Artesia,
New Mexico, which is operated in conjunction with refining facilities in
Lovington, New Mexico (collectively, the Navajo Refinery) and the Company's
refinery near Great Falls, Montana. The petroleum products produced by the
Refining segment are marketed in the southwestern United States, Montana and
northern Mexico. Costs associated with pipelines and terminals operated in
conjunction with the Refining segment as part of the supply and distribution
networks of the refineries are included in the Refining segment. The Pipeline
Transportation segment includes approximately 1,000 miles of the Company's
pipeline assets in Texas and New Mexico. Revenues from the Pipeline
Transportation segment are earned through transactions with unaffiliated parties
for pipeline transportation, rental and terminalling operations. Pipeline
Transportation segment revenues do not include any amount relating to pipeline
transportation services provided for the Company's refining operations. The
charge in the 2000 fiscal year for the voluntary early retirement program is
included in Corporate and other.
(3) Earnings before interest, taxes, depreciation and amortization - EBITDA is
calculated as net income plus (i) interest expense net of interest income, (ii)
income tax provision, and (iii) depreciation, depletion and amortization. EBITDA
is not a calculation based upon generally accepted accounting principles:
however, the amounts included in the EBITDA calculation are derived from amounts
included in the consolidated financial statements of Holly. EBITDA should not be
considered as an alternative to net income or operating income, as an indication
of operating performance of Holly or as an alternative to operating cash flow as
a measure of liquidity. EBITDA is not necessarily comparable to similarly titled
measures of other companies. EBITDA is presented here because it enhances an
investor's understanding of Holly's ability to satisfy principal and interest
obligations with respect to Holly's indebtedness and to use cash for other
purposes, including capital expenditures. EBITDA is also used by Holly
management for internal analysis and as a basis for financial covenants. Our
EBITDA presented above is reconciled to net income as follows:
-29-
YEARS ENDED JULY 31,
------------------------------------
2002 2001 2000
---------- ----------- ---------
(In thousands)
Net Income................................................................... $ 32,029 $ 73,450 $ 11,445
Add provision for income tax.............................................. 18,867 48,445 7,189
Add interest expense...................................................... 2,953 4,980 5,914
Subtract interest expense................................................. (1,528) (2,513) (761)
Add depreciation and amortization......................................... 27,699 27,327 27,496
---------- ----------- ---------
EBITDA.................................................................... $ 80,020 $ 151,689 $ 51,283
========== =========== =========
2002 COMPARED TO 2001
Net income for the fiscal year ended July 31, 2002 was $32.0 million ($2.06 per
basic share and $2.01 per diluted share) compared to net income of $73.5 million
($4.84 per basic share and $4.77 per diluted share) for the year ended July 31,
2001 primarily as a result of lower refined product margins, which the Company
defines and the difference between refined product sales prices and the costs
for crude oil and other feedstocks exclusive of depreciation, depletion and
amortization, and to a lesser extent, lower production of refined products due
to maintenance turnarounds at the Navajo Refinery, including an extended 29-day
turnaround in November-December 2001. During fiscal 2002, the Company, along
with the refining industry as a whole, experienced substantially lower refined
product margins compared to the very favorable refined product margins that
prevailed in the prior year. The Company's refined product margins began to
decline after the first fiscal quarter of 2001 and remained lower throughout the
rest of the fiscal year.
The Company's revenues decreased by $253.2 million to $888.9 million in fiscal
2002 as compared to $1.1 billion in fiscal 2001 primarily as a result of lower
sales prices. The average sales price per sales barrel in fiscal 2002 was
$31.12, approximately 22% less than the average sales price per sales barrel of
$39.82 in fiscal 2001. Cost of products sold also decreased by $173.1 million to
$698.2 million in fiscal 2002 as compared to $871.3 million in fiscal 2001 due
principally to lower costs of purchased crude oil. The Company's average cost of
crude in fiscal 2002 was $22.33 per barrel, approximately 19% less than the
average cost of crude in fiscal 2001. Additionally, production of refined
products was reduced by approximately 5% during the year ended July 31, 2002 as
a result of two planned maintenance turnarounds at the Company's Navajo
Refinery, the first in August 2001 and a second 29-day extended turnaround in
November and December 2001. The Company's refined product margins for fiscal
2002 were well below the refined product margins for fiscal 2001,
The Company's operating expenses were $4.1 million lower for fiscal 2002
compared to fiscal 2001 principally as a result of lower cost for utilities,
principally purchased natural gas. Selling, general and administrative costs
were $875,000 lower due to decreased costs associated with legal proceedings and
decreased compensation expense.
Interest expense declined by $2.0 million during fiscal 2002 from fiscal 2001
primarily due to reduced interest costs as the Company has made required
principal payments on term debt The reduction in interest expense was partially
offset by a $1.0 million decrease in interest income for fiscal 2002 as compared
to fiscal 2001, primarily due to lower interest rates on invested funds. The
Company realized additional income of $2.5 million in fiscal 2002 from the
Company's investments in joint ventures, primarily due to record performance by
NK Asphalt Partners, an asphalt joint venture.
The Company's 2002 income tax provision was approximately 37.1% of income before
income taxes as compared to 39.7% in 2001. This decrease is primarily due to
lower state tax expense and additional utilization of limited net operating loss
carryforwards.
-30-
2001 COMPARED TO 2000
Net income for the fiscal year ended July 31, 2001 was $73.5 million ($4.84 per
basic share and $4.77 per diluted share), as compared to $11.4 million ($.71 per
basic and diluted share) for the prior year. Earnings for the fourth quarter of
the 2000 fiscal year had been reduced by a one-time $6.8 million pre-tax charge
for voluntary early retirement costs associated with the Company's cost
reduction and efficiency program.
Significantly higher refined product margins were the principal factor in the
favorable change in net income as compared to the prior year. Refined product
margins increased above fiscal 2000 refined product margins due to very strong
refined product margins for refined products in markets served by the Company's
refineries. Both revenues and cost of products sold were higher in fiscal 2001
as compared to fiscal 2000, due principally to the increased cost of purchased
crude oil and, with respect to revenues, higher refined product margins.
Favorably impacting earnings for fiscal 2001 was the realization of significant
benefits from the cost reduction and production efficiency program announced in
May 2000. The benefits realized in fiscal 2001 by the cost reduction initiatives
somewhat mitigated the impact on the Company of increased utilities costs
experienced by the Company and other petroleum refining and transportation
companies during much of the year. Also contributing to income in fiscal 2001
was the Company's $4.3 million share of earnings in an asphalt joint venture
formed in July 2000 with a subsidiary of Koch Industries, Inc., an increase in
pipeline transportation income of $3.3 million, and lower net interest expense
of $2.7 million due to higher levels of short-term investments in the current
fiscal year. The Company's income in fiscal 2001 also included $1.1 million
resulting from the settlement of certain contractual issues relating to the
crude oil gathering system purchased in 1998, as compared to other income of
$2.2 million in fiscal 2000 resulting from the termination of a long-term sulfur
recovery agreement with a third party. General and administrative expenses
increased in fiscal 2001 due to increased accrued compensation.
LIQUIDITY AND CAPITAL RESOURCES
Cash and cash equivalents increased by $5.8 million to $71.6 million during the
year ended July 31, 2002. The cash flow generated from operations of $41.8
million exceeded the cash required for financing activities of $14.1 million and
investing activities of $22.0 million. Working capital increased during the year
ended July 31, 2002 by $2.1 million to $59.9 million.
On October 30, 2001, the Company announced plans to repurchase up to $20 million
of the Company's common stock. Such repurchases are expected to be made from
time to time in open market purchases or privately negotiated transactions,
subject to price and availability. An amendment to the Company's Credit
Agreement was made to allow for the repurchases. During fiscal 2002, 98,500
shares were repurchased for approximately $1.6 million or $16.26 per share. In
fiscal 2003, an additional 63,500 shares were repurchased through September 19,
2002 for approximately $1.1 million or $16.66 per share.
In December 2001, an agreement was reached among the Company, the EPA, the New
Mexico Environment Department, and the Montana Department of Environmental
Quality with respect to a global settlement of issues concerning the application
of air quality requirements to past and future operations of the Company's
refineries. The Consent Decree implementing this agreement requires investments
by the Company expected to total between $15 million and $20 million over a
number of years for the installation of certain state of the art pollution
control equipment at the Company's New Mexico and Montana refineries. See Part
I, Item 3, "Legal Proceedings" for additional information.
In August 2002, the Company entered into an agreement with a group of banks led
by Canadian Imperial Bank of Commerce to extend its Revolving Credit Agreement
and reduce the commitment from $90 million to $75 million. If there is a
satisfactory resolution in the Longhorn Partners Pipeline lawsuit prior to
October 10, 2003, the expiration date will be October 10, 2004, and if there is
not a satisfactory resolution of this lawsuit, the expiration date will be
October 10, 2003. Under the current agreement, the Company will have access to
$75 million of commitments for both revolving credit loans and letters of
credit. Up to $37.5 million of this facility may be used
-31-
for revolving credit loans. At July 31, 2002 the Company had letters of credit
outstanding under the facility of $19.2 million and had no borrowings
outstanding.
The Company believes its internally generated cash flow together with its Credit
Agreement provide sufficient resources to fund planned capital projects,
scheduled repayments of the Senior Notes, planned stock repurchases, continued
payment of dividends (although dividend payments must be approved by the Board
of Directors and cannot be guaranteed) and the Company's liquidity needs.
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided by operating activities amounted to $41.8 million in fiscal
2002, compared to $105.6 million in fiscal 2001 and $46.8 million in fiscal
2000. Comparing fiscal 2002 to fiscal 2001, the $63.8 million decrease in cash
provided by operations was primarily the result of a $41.4 million decrease in
net income, a $9.1 million increase in expenditures on turnarounds and changes
in working capital items. Comparing fiscal 2001 to fiscal 2000, the $58.8
million increase in cash provided by operations was primarily the result of a
$62.0 million increase in net income.
CASH FLOWS FOR FINANCING ACTIVITIES
Cash flows used for financing activities amounted to $14.1 million in fiscal
2002, compared to $14.7 million in fiscal 2001 and $27.2 million in fiscal 2000.
During fiscal 2002, the Company repaid $8.6 million of its fixed rate term debt,
received proceeds of $2.4 million for common stock issued upon exercise of stock
options (179,300 shares), paid $1.6 million, or $16.26 per share, to repurchase
98,500 shares of its common stock and paid $6.4 million in dividends. The
Company had no bank borrowings during the 2002 fiscal year. During fiscal 2001,
the Company repaid $13.7 million of its fixed rate term debt, received proceeds
of $5.5 million for common stock issued upon exercise of stock options (379,000
shares), and paid $5.6 million in dividends. During fiscal 2000, the Company
repaid $13.7 million of its fixed rate term debt, repurchased 8.5% of its
outstanding common stock from an institutional stockholder for $7.2 million and
paid $5.5 million in dividends.
See Note 7 to the Consolidated Financial Statements for a summary of the terms
and conditions of the Senior Notes and of the Credit Agreement.
CASH FLOWS FOR INVESTING ACTIVITIES AND CAPITAL PROJECTS
Cash flows used for investing activities totaled $70.8 million over the last
three years, $22.0 million in 2002, $28.8 million in 2001, and $20.1 million in
2000. All of these amounts were expended on capital projects except for
investments and working capital advances, of $3.3 million in fiscal 2002, $5.8
million in fiscal 2001 and $3.3 million in fiscal 2000, to a joint venture
created to manufacture and market asphalt products. The net negative cash flow
for investing activities was offset by distributions to the Company from the Rio
Grande Pipeline Company joint venture of $3.2 million in fiscal 2002, $0.1
million in fiscal 2001, and $2.4 million in fiscal 2000 and from distributions
and working capital advance repayments from the asphalt joint venture of $8.5
million in fiscal 2002 and $5.6 million in fiscal 2001. The Company realized,
during fiscal 2002, $4.5 million in proceeds from the sale of marketable equity
securities.
The Company's capital budget adopted for 2003 totals $14.8 million - $6.5
million for additional costs relating to the hydrotreater project and refinery
expansion, $3.2 million for other refinery improvements, $3.0 million for
pipeline transportation projects, $.6 million for oil and gas exploration and
production, and $1.5 million for information technology and other. The 2003
capital budget includes authorizations for some expenditures that are expected
to be made after the close of the 2003 fiscal year. The Company expects to
expend approximately $40 million in fiscal 2003 for capital improvements, which
amount includes amounts authorized in previous fiscal years. This amount is
expected to be allocated approximately $30 million for the hydrotreater project
and the refinery expansion to an estimated 70,000 BPD described below,
approximately $6 million for other refinery improvements, approximately $2
million for pipeline and transportation projects, and approximately $2 million
for other projects, including information technology projects and oil and gas
exploration and development. These expenditures include projects authorized in
the Company's 2003 capital budget as well as expenditures authorized in prior
capital budgets but expected to be carried out in fiscal 2003.
-32-
In November 1997, the Company purchased a hydrotreater unit for $5.1 million
from a closed refinery. This purchase gave the Company the ability to
reconstruct the unit at the Navajo Refinery at an estimated savings of
approximately $20.0 million as compared to the purchase cost of a new unit.
During the last three years, the Company spent approximately $15.3 million on
relocation, engineering and equipment fabrication related to the hydrotreater
project. The remaining costs to complete the hydrotreater project and the
expansion project are estimated to be approximately $35.6 million. The Company
expects that the hydrotreater project will be completed by December 2003. The
hydrotreater will enhance higher value light product yields and expand the
Company's ability to produce additional quantities of gasolines meeting the
present California Air Resources Board ("CARB") standards, which have been
adopted in the Company's Phoenix market for winter months beginning in late
2000, and to meet the recently adopted EPA nationwide Low-Sulfur Gasoline
requirements scheduled to begin in 2004. In fiscal 2001 the Company completed
the construction of a new additional sulfur recovery unit, which is currently
utilized to enhance sour crude processing capabilities and will provide
sufficient capacity to recover the additional extracted sulfur that will result
from operation of the hydrotreater.
Contemporaneous with the hydrotreater project, Navajo will be making necessary
modifications to several of the Artesia processing units for the first phase of
Navajo's expansion, which will increase crude oil refining capacity from 60,000
BPD to an estimated 70,000 BPD. The first phase of the expansion is expected to
be completed by December 2003. Additional air emission permits will be required
to implement needed modifications at Navajo's Lovington, New Mexico refining
facility which is operated in conjunction with the Artesia facility. It is
envisioned that these necessary modifications to the Lovington facility would
also be completed by December 2003. The permits received by Navajo to date for
the Artesia facility, subject to possible minor modifications, should also
permit a second phase expansion of Navajo's crude oil capacity from an estimated
70,000 BPD to an estimated 80,000 BPD, but a schedule for such additional
expansion has not been determined. The total cost of the hydrotreater and
expansion project to an estimated 70,000 BPD is expected to be approximately
$56.0 million.
The Company leases from Mid-America Pipeline Company more than 300 miles of 8"
pipeline running from Chaves County to San Juan County, New Mexico (the "Leased
Pipeline"). The Company owns and operates a 12" pipeline from the Navajo
Refinery to the Leased Pipeline as well as terminalling facilities in
Bloomfield, New Mexico, which is located in the northwest corner of New Mexico
and in Moriarty, which is 40 miles east of Albuquerque. Transportation of
petroleum products to markets in northwest New Mexico and diesel fuels to
Moriarty began in the last months of calendar 1999. In December 2001, the
Company completed its expansion of the Moriarty terminal and its pumping
capacity on the Leased Pipeline. The terminal expansion included the addition of
gasoline and jet fuel to the existing diesel fuel delivery capabilities, thus
permitting the Company to provide a full slate of light products to the growing
Albuquerque and Santa Fe, New Mexico areas. The enhanced pumping capabilities on
the Company's leased pipeline extending from the Artesia refinery through
Moriarty to Bloomfield will permit the Company to deliver a total of over 45,000
BPD of light products to these locations. If needed, additional pump stations
could further increase the pipeline's capabilities.
CONTRACTUAL OBLIGATIONS AND COMMITMENTS
The following table presents long-term contractual obligations of the Company in
total and by period due. These items include the Company's long-term debt based
on maturity dates and the Company's operating lease commitments. The Company's
operating leases contain renewal options that are not reflected in the table
below and that are likely to be exercised.
PAYMENTS DUE BY PERIOD
-------------------------------------------------------
LESS THAN
CONTRACTUAL OBLIGATIONS TOTAL 1 YEAR 2-3 YEARS 4-5 YEARS OVER 5 YEARS
-------------------------------------------------- --------- -------- ---------- --------- ------------
(In thousands)
Long-term debt (stated maturities) ............... $ 34,285 $ 8,571 $ 25,714 $ - $ -
Operating leases ................................. $ 29,020 $ 6,091 $ 11,976 $ 10,666 $ 287
-33-
In July 2000, Navajo Western Asphalt Company ("Navajo Western"), a wholly-owned
subsidiary of the Company, and a subsidiary of Koch Materials Company ("Koch")
formed a joint venture, NK Asphalt Partners, to manufacture and market asphalt
and asphalt products in Arizona and New Mexico under the name "Koch Asphalt
Solutions - Southwest." Navajo Western contributed all of its assets to NK
Asphalt Partners and Koch contributed its New Mexico and Arizona asphalt and
manufacturing assets to NK Asphalt Partners. Effective January 2002, the Company
sold a 1% equity interest to the other joint venture partner, thereby reducing
the Company's interest from 50% to 49%. All asphalt produced at the Navajo
Refinery is sold at market prices to the joint venture under a supply agreement.
The Company is required to make additional contributions to the joint venture of
up to $3,250,000 for each of the next eight years contingent on the earnings
level of the joint venture. The Company expects to finance such contributions
from its share of cash flows of the joint venture. In the event that Holly fails
to make the required contributions, Holly may lose its voting rights during such
default and the other partner could cause the partnership to bring a proceeding
to collect the unpaid contributions plus interest at the prime rate plus 2%.
As part of the Consent Decree filed December 2001 implementing an agreement
reached among the Company, the EPA, the New Mexico Environment Department, and
the Montana Department of Environmental Quality, the Company is required to make
investments at the Company's New Mexico and Montana refineries for the
installation of certain state of the art pollution control equipment expected to
total between $15 million and $20 million over a period expected to end in 2009.
-34-
ADDITIONAL FACTORS THAT MAY AFFECT FUTURE RESULTS
The Company's operating results have been, and will continue to be, affected by
a wide variety of factors, many of which are beyond the Company's control, that
could have adverse effects on profitability during any particular period. Among
these factors is the demand for crude oil and refined products, which is largely
driven by the conditions of local and worldwide economies as well as by weather
patterns and the taxation of these products relative to other energy sources.
Governmental regulations and policies, particularly in the areas of taxation,
energy and the environment, also have a significant impact on the Company's
activities. Operating results can be affected by these industry factors, by
competition in the particular geographic areas that the Company serves and by
factors that are specific to the Company, such as the success of particular
marketing programs and the efficiency of the Company's refinery operations.
In addition, the Company's profitability depends largely on the spread between
market prices for refined petroleum products and crude oil prices. This margin
is continually changing and may fluctuate significantly from time to time. Crude
oil and refined products are commodities whose price levels are determined by
market forces beyond the control of the Company. Additionally, due to the
seasonality of refined products markets and refinery maintenance schedules,
results of operations for any particular quarter of a fiscal year are not
necessarily indicative of results for the full year. In general, prices for
refined products are influenced by the price of crude oil. Although an increase
or decrease in the price for crude oil generally results in a similar increase
or decrease in prices for refined products, there is normally a time lag in the
realization of the similar increase or decrease in prices for refined products.
The effect of changes in crude oil prices on operating results therefore depends
in part on how quickly refined product prices adjust to reflect these changes. A
substantial or prolonged increase in crude oil prices without a corresponding
increase in refined product prices, a substantial or prolonged decrease in
refined product prices without a corresponding decrease in crude oil prices, or
a substantial or prolonged decrease in demand for refined products could have a
significant negative effect on the Company's earnings and cash flows.
The Company is dependent on the production and sale of quantities of refined
products at refined product margins sufficient to cover operating costs,
including any increases in costs resulting from future inflationary pressures.
The refining business is characterized by high fixed costs resulting from the
significant capital outlays associated with refineries, terminals, pipelines and
related facilities. Furthermore, future regulatory requirements or competitive
pressures could result in additional capital expenditures, which may or may not
produce the results intended. Such capital expenditures may require significant
financial resources that may be contingent on the Company's access to capital
markets and commercial bank loans. Additionally, other matters, such as
regulatory requirements or legal actions, may restrict the Company's access to
funds for capital expenditures.
Until 1998, the El Paso market and markets served from El Paso were generally
not supplied by refined products produced by the large refineries on the Texas
Gulf Coast. While wholesale prices of refined products on the Gulf Coast have
historically been lower than prices in El Paso, distances from the Gulf Coast to
El Paso (more than 700 miles if the most direct route were used) have made
transportation by truck unfeasible and have discouraged the substantial
investment required for development of refined products pipelines from the Gulf
Coast to El Paso.
In 1998, a Texaco, Inc. subsidiary completed a 16-inch refined products pipeline
running from the Gulf Coast to Midland, Texas along a northern route (through
Corsicana, Texas). This pipeline, now owned by Shell Pipeline Company, LP
("Shell"), is linked to a 6-inch pipeline, also owned by Shell, that is
currently being used to transport to El Paso approximately 16,000 to 18,000 BPD
of refined products that are produced on the Texas Gulf Coast (this volume
replaces a similar volume produced in the Shell Oil Company refinery in Odessa,
Texas, which was shut down in 1998). The Shell pipeline from the Gulf Coast to
Midland has the potential to be linked to existing or new pipelines running from
the Midland, Texas area to El Paso with the result that substantial additional
volumes of refined products could be transported from the Gulf Coast to El Paso.
An additional potential source of pipeline transportation from Gulf Coast
refineries to El Paso is the proposed Longhorn Pipeline. This pipeline is
proposed to run approximately 700 miles from the Houston area of the Gulf Coast
to El Paso, utilizing a direct route. The owner of the Longhorn Pipeline,
Longhorn Partners Pipeline, L.P. ("Longhorn Partners"), is a Delaware limited
partnership that includes affiliates of ExxonMobil Pipeline Company, BP Pipeline
(North America), Inc., Williams Pipe Line Company, and the Beacon Group Energy
Investment Fund, L.P. and Chisholm Holdings as limited partners. Longhorn
Partners has proposed to use the pipeline initially to
-35-
transport approximately 72,000 BPD of refined products from the Gulf Coast to El
Paso and markets served from El Paso, with an ultimate maximum capacity of
225,000 BPD. A critical feature of this proposed petroleum products pipeline is
that it would utilize, for approximately 450 miles (including areas overlying
the environmentally sensitive Edwards Aquifer and Edwards-Trinity Aquifer and
heavily populated areas in the southern part of Austin, Texas) an existing
pipeline (previously owned by Exxon Pipeline Company) that was constructed in
about 1950 for the shipment of crude oil from West Texas to the Houston area. At
the date of this report, the Longhorn Pipeline has not begun operations. The
Longhorn Pipeline did not operate in the period from late 1998 through July 2002
because of a federal court injunction in August 1998 and a settlement agreement
in March 1999 entered into by Longhorn Partners, the United States Environmental
Protection Agency ("EPA"), the Department of Transportation ("DOT"), and the
other parties to the federal lawsuit that had resulted in the injunction and
settlement. Additionally, the Longhorn Pipeline did not operate through July
2002 because it lacked valid easements from the Texas General Land Office for
crossing certain stream and river beds and state-owned lands. Since July 2002
the Longhorn Pipeline has not been operating because Longhorn Partners has not
completed certain agreed improvement projects and pre-start-up steps.
The March 1999 settlement agreement in the federal lawsuit that resulted in an
injunction against operation of the Longhorn Pipeline required the preparation
of an Environmental Assessment under the authority of the EPA and the DOT while
the federal court retained jurisdiction. A final Environmental Assessment (the
"Final EA") on the Longhorn Pipeline was released in November 2000. The Final EA
was accompanied by a Finding of No Significant Impact that was conditioned on
the implementation by Longhorn Partners of a proposed mitigation plan developed
by Longhorn Partners which contained 40 mitigation measures, including the
replacement of approximately 19 miles of pipe in the Austin area with new
thick-walled pipe protected by a concrete barrier. Some elements of the proposed
mitigation plan were required to be completed before the Longhorn Pipeline would
be allowed to operate, with the remainder required to be completed later or to
be implemented for as long as operations continued. The plaintiffs in the
federal court lawsuit that resulted in the Environmental Assessment of the
Longhorn Pipeline challenged the Final EA in further federal court proceedings
that began in January 2001. One of the intervenor plaintiffs in the federal
court lawsuit, the Lower Colorado River Authority ("LCRA"), entered into a
settlement agreement with Longhorn Partners in 2001 under the terms of which
Longhorn Partners agreed to implement specified additional mitigation measures
relating to water supplies in certain areas of Central Texas and the LCRA agreed
to dismiss with prejudice its participation as an intervenor in the federal
court lawsuit. In July 2002, the federal court in Austin ruled that Longhorn's
compliance with the Final EA would suffice under the federal National
Environmental Policy Act law to allow the Longhorn Pipeline to begin operation.
The court also subsequently ruled that the parties that had brought the
challenge to the Longhorn Pipeline in federal court were the "prevailing
parties" and that therefore Longhorn Partners and the federal government
defendants should pay certain costs relating to the federal court litigation.
The parties that were plaintiffs in the federal litigation, other than the LCRA,
are taking an appeal to the United States Court of Appeals for the Fifth Circuit
(the "Fifth Circuit") of the district court's ruling on the adequacy of the
Final EA. In addition, the federal government defendants in the federal court
lawsuit are cross-appealing to the Fifth Circuit the trial court's ruling
concerning payment of certain costs. At the date of this report, it is not
possible to predict the outcome of these appeals.
In December 2001, prior to the federal court's ruling on the adequacy of the
Final EA, Longhorn Partners began construction to implement mitigation measures
required by the Final EA and the settlement with the LCRA. Published reports
indicate that this construction continued until late July 2002, when the
construction activities were halted before completion of the project. The latest
public statements from Longhorn Partners indicate that Longhorn Partners is
seeking additional financing to complete the project and that the project will
not begin operations until after December 2002.
If the Longhorn Pipeline is allowed to operate as currently proposed, the
substantially lower requirement for capital investment permitted by the direct
route through Austin, Texas and over the Edwards Aquifers would permit Longhorn
Partners to give its shippers a cost advantage through lower tariffs that could,
at least for a period, result in significant downward pressure on wholesale
refined products prices and refined products margins in El Paso and related
markets; any effects on the Company's markets in Tucson and Phoenix, Arizona and
Albuquerque, New Mexico would be expected to be limited in the next few years
because current common carrier pipelines from El Paso to these markets are now
running at capacity and proration policies of these pipelines allocate only
limited capacity to new shippers. Although some current suppliers in the market
might not compete in such a climate, the Company's analyses indicate that,
because of location, recent capital improvements, and on-going enhancements to
-36-
operational efficiency, the Company's position in El Paso and markets served
from El Paso could withstand such a period of lower prices and refined product
margins. However, the Company's results of operations could be adversely
impacted if the Longhorn Pipeline were allowed to operate as currently proposed.
It is not possible to predict whether and, if so, under what conditions, the
Longhorn Pipeline will ultimately be operated, nor is it possible to predict the
consequences for the Company of Longhorn Pipeline's operations if they occur.
In August 1998, a lawsuit (the "El Paso Lawsuit") was filed by Longhorn Partners
in state district court in El Paso, Texas against the Company and two of its
subsidiaries (along with an Austin, Texas law firm which was subsequently
dropped from the case). The suit, as most recently amended by Longhorn Partners
in September 2000, seeks damages alleged to total up to $1,050,000,000 (after
trebling) based on claims of violations of the Texas Free Enterprise and
Antitrust Act, unlawful interference with existing and prospective contractual
relations, and conspiracy to abuse process. The specific actions of the Company
complained of in the El Paso Lawsuit, as currently amended, are alleged
solicitation of and support for allegedly baseless lawsuits brought by Texas
ranchers in federal and state courts to challenge the proposed Longhorn Pipeline
project, support of allegedly fraudulent public relations activities against the
proposed Longhorn Pipeline project, entry into a contractual "alliance" with
Fina Oil and Chemical Company, threatening litigation against certain partners
in Longhorn Partners, and alleged interference with the federal court settlement
agreement that provided for the Environmental Assessment of the Longhorn
Pipeline. The Company believes that the El Paso Lawsuit is wholly without merit
and plans to continue to defend itself vigorously. However, because of the size
of the damages claimed and in spite of the apparent lack of merit in the claims
asserted, the El Paso Lawsuit has created problems for the Company, including
the exclusion of the Company from the possibility of certain types of major
corporate transactions, an adverse impact on the cost and availability of debt
financing for Company operations, and what appears to be a continuing adverse
effect on the market price of the Company's common stock. In August 2002, the
Company filed a lawsuit in New Mexico state court in Carlsbad, New Mexico (the
"Carlsbad Lawsuit") against Longhorn Partners and its major owners concerning
the El Paso Lawsuit; the Carlsbad Lawsuit seeks actual and punitive damages for
tortious interference with existing business relations, malicious abuse of
process, unfair competition, prima facie tort and conspiracy. For additional
information on the El Paso Lawsuit and the Carlsbad Lawsuit, see Item 3, "Legal
Proceedings."
Other legal proceedings that could affect future results are described in Item
3, "Legal Proceedings."
In March 2000, Equilon Pipeline Company, LLC (whose successor is Shell Pipeline
Company, LP) announced a 500-mile pipeline, called the "New Mexico Products
Pipeline System" to carry gasoline and other refined fuels from the Odessa,
Texas area to Bloomfield, New Mexico. It was announced that the pipeline would
have a capacity of 40,000 BPD and shipments would begin in 2001. In addition to
the pipeline, a product terminal would be built in Moriarty, New Mexico. This
system would have access to products manufactured at Gulf Coast refineries and
could result in an increase in the supply of products to some of the Company's
markets. This project has been delayed because of the requirement announced in
August 2000 that an environmental impact study be completed on the proposed
project.
An additional factor that could affect some of the Company's markets is excess
pipeline capacity from the West Coast into the Company's Arizona markets after
the expansion in 1999 of the pipeline from the West Coast to Phoenix. If refined
products become available on the West Coast in excess of demand in that market,
additional products may be shipped into the Company's Arizona markets with
resulting possible downward pressure on refined product prices in these markets.
The availability of refined products on the West Coast for shipment to Phoenix
may however be reduced by the effects on West Coast gasoline supplies of the
scheduled ban in California on the use of MTBE as a constituent of gasoline
after 2003.
In addition to the projects described above, other projects have been explored
from time to time by refiners and other entities, which projects, if
consummated, could result in a further increase in the supply of products to
some or all of the Company's markets.
In recent years there have been several refining and marketing consolidations or
acquisitions between entities competing in the Company's geographic market.
These transactions could increase the future competitive pressures on the
Company.
-37-
The common carrier pipelines used by the Company to serve the Arizona and
Albuquerque markets are currently operated at or near capacity and are subject
to proration. As a result, the volumes of refined products that the Company and
other shippers have been able to deliver to these markets have been limited. The
flow of additional products into El Paso for shipment to Arizona, either as a
result of the Longhorn Pipeline or otherwise, could further exacerbate such
constraints on deliveries to Arizona. No assurances can be given that the
Company will not experience future constraints on its ability to deliver its
products through the common carrier pipeline to Arizona. Any future constraints
on the Company's ability to transport its refined products to Arizona could, if
sustained, adversely affect the Company's results of operations and financial
condition. Kinder Morgan's SFPP, L.P. ("SFPP"), the owner of the common carrier
pipelines running from El Paso to Tucson and Phoenix, has recently proposed to
expand the capacity of these pipelines by approximately 54,000 BPD. Under the
announced schedule, the expansion would be completed by early 2005. According to
a September 2002 filing by SFPP with the Federal Energy Regulatory Commissions
("FERC"), this project is contingent on obtaining a favorable ruling from FERC
concerning tariff rates to be allowed on the pipelines after completion of the
expansion. For the Company, the proposed expansion would permit the shipment of
additional refined products to markets in Arizona, but pipeline tariffs would
likely be higher and the expansion would also permit additional shipments by
competing suppliers. The ultimate effects of the proposed pipeline expansion on
the Company cannot presently be estimated.
In the case of the Albuquerque market, the common carrier pipeline used by the
Company to serve this market currently operates at or near capacity with
resulting limitations on the amount of refined products that the Company and
other shippers can deliver. As described above under "Cash Flows for Investing
Activities and Capital Projects," the Company has leased from Mid-America
Pipeline Company a pipeline running from near the Navajo Refinery to the
Albuquerque vicinity and Bloomfield, New Mexico. The Company operates a 12"
pipeline from the Navajo Refinery to the Leased Pipeline as well as terminalling
facilities in Bloomfield, NM, which is located in the northwest corner of New
Mexico, and in Moriarty, which is 40 miles east of Albuquerque. Transportation
of petroleum products to markets in northwest New Mexico and diesel fuels to
Moriarty began at the end of calendar 1999. In December 2001, the Company
completed its expansion of the Moriarty terminal and its pumping capacity on the
Lease Pipelines. The terminal expansion included the addition of gasoline and
jet fuel to the existing diesel fuel delivery capabilities, thus permitting the
Company to provide a full slate of light products to the growing Albuquerque and
Santa Fe, New Mexico area. The enhanced pumping capabilities on the Company's
leased pipeline extending from the Artesia refinery through Moriarty to
Bloomfield will permit the Company to deliver a total of over 45,000 BPD of
light products to these locations. If needed, additional pump stations could
further increase the pipeline's capabilities. Completion of this project at
Moriarty allows the Company to transport gasoline and jet fuel directly to the
Albuquerque area on the leased pipeline, thereby eliminating third party tariff
expenses and the risk of future pipeline constraints on shipments to
Albuquerque. Any future constraints on the Company's ability to transport its
refined products to Arizona or Albuquerque could, if sustained, adversely affect
the Company's results of operations and financial condition.
Effective January 1, 1995, certain cities in the country were required to use
only reformulated gasoline ("RFG"), a cleaner burning fuel. Phoenix is the only
principal market of the Company that currently requires the equivalent of RFG
(or an alternative clean burning gasoline formula), although this requirement
could be implemented in other markets over time. Phoenix adopted the even more
rigorous California Air Resources Board ("CARB") fuel specifications for winter
months beginning in late 2000. Completion of the hydrotreater project, described
above under "Cash Flows for Investing Activities and Capital Projects," will
enhance higher value light product yields and expand the Company's ability to
produce more gasoline which meets the present CARB standards in the Company's
Phoenix market and meets the recently proposed EPA nationwide Low-Sulfur
Gasoline requirements that become effective in 2004. These new requirements,
other requirements of the federal Clean Air Act, or other presently existing or
future environmental regulations could cause the Company to expend substantial
amounts to permit the Company's refineries to produce products that meet
applicable requirements.
RISK MANAGEMENT
The Company uses certain strategies to reduce some commodity price and
operational risks. The Company does not attempt to eliminate all market risk
exposures when the Company believes the exposure relating to such risk would not
be significant to the Company's future earnings, financial position, capital
resources or liquidity or that the cost of eliminating the exposure would
outweigh the benefit.
-38-
The Company's profitability depends largely on the spread between market prices
for refined products and market prices for crude oil. A substantial or prolonged
decrease in this spread could have a significant negative effect on the
Company's earnings, financial condition and cash flows. At times, the Company
utilizes petroleum commodity futures contracts to minimize a portion of its
exposure to price fluctuations associated with crude oil and refined products.
In the quarter ended January 31, 2001, the Company entered into energy commodity
futures contracts to hedge certain commitments to purchase crude oil and deliver
gasoline in March 2001. The hedge was intended to help protect the Company from
the risk that refined product margins with respect to the hedged gasoline sales
would decline.
During the year ended July 31, 2001, the Company entered into commodity price
swaps and collar options to help manage the exposure to price volatility
relating to forecasted purchases of natural gas in March 2001 and from May 2001
to May 2002. These transactions were designated as cash flow hedges related to
the purchase of 1.2 million MMBtu, approximately 50% of the forecasted natural
gas purchases for the Navajo Refinery. The price swaps and collar options
effectively established minimum and maximum prices to be paid for the portion of
natural gas hedged of $5.29 and $5.63 per MMBtu, respectively. At July 31, 2001,
included in comprehensive income, was a loss of $2.1 million, as the values of
the outstanding hedges were marked to the current fair value. In fiscal 2002,
the Company recorded net adjustments of $2.1 million to comprehensive income,
which included actual losses of approximately $3.3 million that were
reclassified from comprehensive income to operating expenses as the transactions
occurred under the swap and collar arrangements. At July 31, 2002, there were no
commodity price swaps or collar options outstanding.
At July 31, 2002, the Company had outstanding unsecured debt of $34.3 million
and had no borrowings outstanding under its Credit Agreement. The Company does
not have significant exposure to changing interest rates on its unsecured debt
because the interest rates are fixed, the average maturity is approximately two
years and such debt represents less than 15% of the Company's total
capitalization. As the interest rates on the Company's bank borrowings are reset
frequently based on either the bank's daily effective prime rate, or the LIBOR
rate, interest rate market risk is very low. There were no bank borrowings
during fiscal 2002 or fiscal 2001. Additionally, the Company invests any
available cash only in investment grade, highly liquid investments with
maturities of three months or less and hence the interest rate market risk
implicit in these cash investments is low. A ten percent change in the market
interest rate over the next year would not materially impact the Company's
earnings or cash flow since the interest rates on the Company's long-term debt
are fixed and the Company's borrowings under the Credit Agreement, if any, and
cash investments are at short-term market rates and such interest has
historically not been significant as compared to the total operations of the
Company. A ten percent change in the market interest rate over the next year
would not materially impact the Company's financial condition since the average
maturity of the Company's long-term debt is approximately two years, such debt
represents less than 15% of the Company's total capitalization, and the
Company's borrowings under the Credit Agreement and cash investments are at
short-term market rates.
The Company's operations are subject to normal hazards of operations, including
fire, explosion and weather-related perils. The Company maintains various
insurance coverages, including business interruption insurance, subject to
certain deductibles. The Company is not fully insured against certain risks
because such risks are not fully insurable, coverage is unavailable, or premium
costs, in the judgment of the Company, do not justify such expenditures. At the
current time the Company is not fully insured for terrorism since in the
judgment of the Company, premium costs in the current insurance market do not
justify such expenditures. Shortly after the events of September 11, 2001, the
Company completed a security assessment of its principal facilities. Several
security measures identified in the assessment have been implemented and others
are in the process of being implemented. Because of recent changes in insurance
markets, insurance coverages available to the Company are becoming more costly
and in some cases less available. So long as this current trend continues, the
Company expects to incur higher insurance costs and anticipates that, in some
cases, it will be necessary to reduce somewhat the extent of insurance coverages
because of reduced insurance availability at acceptable premium costs.
NEW ACCOUNTING PRONOUNCEMENTS
SFAS No. 142 "Goodwill and Other Intangible Assets"
In June 2001, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standard ("SFAS") No. 142, "Goodwill and Other
Intangible Assets." This statement changes how goodwill and
-39-
other intangible assets are accounted for subsequent to their initial
recognition. SFAS No. 142 is effective for fiscal years beginning after December
15, 2001, with early adoption permitted; however, all goodwill and intangible
assets acquired after June 30, 2001, are immediately subject to the provisions
of this statement. The Company will adopt the standard effective August 1, 2002
and believes that there will be no material effect on its financial condition,
results of operations, or cash flows.
SFAS No. 143 "Accounting for Asset Retirement Obligations"
In June 2001, FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." This statement requires that the fair value for an asset
retirement obligation be capitalized as part of the carrying amount of the
long-lived asset if a reasonable estimate of fair value can be made. SFAS No.
143 is effective for fiscal years beginning after June 15, 2002, with early
adoption permitted. The Company will adopt the standard effective August 1, 2002
and believes that there will be no material effect on its financial condition,
results of operations, or cash flows.
SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets"
In August 2001, FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets". This statement supersedes SFAS No. 121
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of", but carries over the key guidance from SFAS No. 121 in
establishing the framework for the recognition and measurement of long-lived
assets to be disposed of by sale and addresses significant implementation
issues. SFAS No. 144 is effective for fiscal years beginning after December 15,
2001, with early adoption permitted. The Company will adopt the standard
effective August 1, 2002 and believes that there will be no material effect on
its financial condition, results of operations, or cash flows.
SFAS No. 146 "Accounting for Certain Costs Associated with Exit or Disposal
Activities"
In June 2002, FASB issued SFAS No. 146, "Accounting for Certain Costs Associated
with Exit or Disposal Activities" which nullifies Emerging Issues Task Force
("EITF") 94-3 and requires that a liability for a cost associated with an exit
or disposal activity be recognized when the liability is incurred and
establishes fair value as the objective for initial measurement of liabilities.
This differs from EITF 94-3 which stated that liabilities for exit costs were to
be recognized as of the date of an entity's commitment to an exit plan. SFAS No.
146 is effective for exit or disposal activities that are initiated after
December 31, 2002, though early adoption is permitted. The Company does not
believe the adoption of this standard will have a material effect on its
financial condition, results of operations, or cash flows upon adoption.
The American Institute of Certified Public Accountants has issued an Exposure
Draft for a Proposed Statement of Position, "Accounting for Certain Costs and
Activities Related to Property, Plant and Equipment" which would require major
maintenance activities to be expensed as costs are incurred. As of July 31,
2002, the Company had approximately $13.8 million of deferred maintenance costs
which are being amortized at a rate of approximately $691,000 per month. If this
proposed Statement of Position had been adopted in its current form, as of July
31, 2002, the Company would have been required to expense, as of July 31, 2002,
$13.8 million of deferred maintenance costs and would be required to expense all
future turnaround costs as incurred.
-40-
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See "Risk Management" under "Management's Discussion and Analysis of Financial
Condition and Results of Operations."
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements
Page
Reference
---------
Report of Independent Auditors .................................................................... 42
Consolidated Balance Sheet at July 31, 2002 and 2001 .............................................. 43
Consolidated Statement of Income for the years ended July 31, 2002, 2001 and 2000 ................. 44
Consolidated Statement of Cash Flows for the years ended July 31, 2002, 2001 and 2000 ............. 45
Consolidated Statement of Stockholders' Equity for the years ended July 31, 2002, 2001 and 2000.... 46
Consolidated Statement of Comprehensive Income for the years ended July 31, 2002, 2001, and 2000... 47
Notes to Consolidated Financial Statements ........................................................ 48
-41-
REPORT OF INDEPENDENT AUDITORS
The Board of Directors
and Stockholders of Holly Corporation
We have audited the accompanying consolidated balance sheet of Holly Corporation
at July 31, 2002 and 2001, and the related consolidated statements of income,
cash flows, stockholders' equity and comprehensive income for each of the three
years in the period ended July 31, 2002. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the consolidated financial position of Holly
Corporation at July 31, 2002 and 2001, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended
July 31, 2002, in conformity with accounting principles generally accepted in
the United States.
/s/ ERNST & YOUNG LLP
Dallas, Texas
September 19, 2002
-42-
HOLLY CORPORATION
CONSOLIDATED BALANCE SHEET
JULY 31,
----------------------
2002 2001
--------- ---------
(In thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents ................................................. $ 71,630 $ 65,840
Accounts receivable (Notes 3 and 7) ....................................... 135,395 146,074
Inventories (Notes 4 and 7) ............................................... 45,308 50,136
Income taxes receivable ................................................... 8,699 3,514
Prepayments and other ..................................................... 17,812 18,566
--------- ---------
TOTAL CURRENT ASSETS ................................................. 278,844 284,130
Properties, plants and equipment, net (Note 5) ............................... 199,461 184,155
Investments in and advances to joint ventures (Note 6) ....................... 15,732 16,303
Other assets ................................................................. 8,269 5,841
--------- ---------
TOTAL ASSETS ......................................................... $ 502,306 $ 490,429
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable (Note 3) ................................................. $ 185,058 $ 181,182
Accrued liabilities (Notes 10 and 13) ..................................... 25,342 31,985
Income taxes payable ...................................................... - 4,661
Current maturities of long-term debt (Note 7) ............................. 8,571 8,571
--------- ---------
TOTAL CURRENT LIABILITIES ............................................ 218,971 226,399
Deferred income taxes (Note 8) ............................................... 29,065 28,010
Long-term debt, less current maturities (Note 7) ............................. 25,714 34,286
Commitments and contingencies (Notes 12 and 13)
STOCKHOLDERS' EQUITY (Notes 7 and 9)
Preferred stock, $1.00 par value - 1,000,000
shares authorized; none issued .......................................... - -
Common stock, $.01 par value - 20,000,000 shares authorized;
16,759,396 and 16,580,096 shares issued as of July 31, 2002 and 2001 .... 168 166
Additional capital ........................................................ 14,013 11,568
Retained earnings ......................................................... 223,770 198,118
--------- ---------
237,951 209,852
Common stock held in treasury, at cost - 1,197,968 and 1,099,468 shares
as of July 31, 2002 and 2001 (9,395) (7,793)
Accumulated other comprehensive loss ...................................... - (325)
--------- ---------
TOTAL STOCKHOLDERS' EQUITY ........................................... 228,556 201,734
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ........................... $ 502,306 $ 490,429
========= =========
See accompanying notes.
-43-
HOLLY CORPORATION
CONSOLIDATED STATEMENT OF INCOME
YEARS ENDED JULY 31,
-----------------------------------------
2002 2001 2000
----------- ----------- -----------
(In thousands, except per share data)
SALES AND OTHER REVENUES (Note 15) ................................ $ 888,906 $ 1,142,130 $ 965,946
OPERATING COSTS AND EXPENSES
Cost of products sold (exclusive of depreciation,depletion
and amortization) ........................................... 698,245 871,321 800,663
Operating expenses (exclusive of depreciation,depletion and
amortization) ............................................... 96,289 100,410 88,550
Selling, general and administrative expenses (exclusive of
depreciation,depletion, and amortization) ................... 22,248 23,123 20,724
Depreciation, depletion and amortization ....................... 27,699 27,327 27,496
Exploration expenses, including dry holes ...................... 1,379 2,042 1,729
Voluntary early retirement costs (Note 10) ..................... - - 6,783
----------- ----------- -----------
TOTAL OPERATING COSTS AND EXPENSES ........................ 845,860 1,024,223 945,945
----------- ----------- -----------
INCOME FROM OPERATIONS ............................................ 43,046 117,907 20,001
OTHER INCOME (EXPENSE)
Equity in earnings of joint ventures ........................... 7,753 5,302 1,586
Interest income ................................................ 1,528 2,513 761
Interest expense (Note 7) ...................................... (2,953) (4,980) (5,914)
Other income (Note 16) ......................................... 1,522 1,153 2,200
----------- ----------- -----------
7,850 3,988 (1,367)
----------- ----------- -----------
INCOME BEFORE INCOME TAXES ........................................ 50,896 121,895 18,634
Income tax provision (benefit) (Note 8)
Current ........................................................ 14,533 44,577 11,319
Deferred ....................................................... 4,334 3,868 (4,130)
----------- ----------- -----------
18,867 48,445 7,189
----------- ----------- -----------
NET INCOME ........................................................ $ 32,029 $ 73,450 $ 11,445
=========== =========== ===========
NET INCOME PER COMMON SHARE - BASIC ............................... $ 2.06 $ 4.84 $ 0.71
=========== =========== ===========
NET INCOME PER COMMON SHARE - DILUTED ............................. $ 2.01 $ 4.77 $ 0.71
=========== =========== ===========
CASH DIVIDENDS DECLARED PER COMMON SHARE .......................... $ 0.41 $ 0.37 $ 0.34
=========== =========== ===========
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING
Basic .......................................................... 15,560 15,187 16,131
Diluted ........................................................ 15,971 15,387 16,131
See accompanying notes.
-44-
HOLLY CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
YEARS ENDED JULY 31,
-------------------------------
2002 2001 2000
-------- --------- --------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income ................................................. $ 32,029 $ 73,450 $ 11,445
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation, depletion and amortization ............... 27,699 27,327 27,496
Deferred income taxes .................................. 4,334 3,868 (4,130)
Equity in earnings of joint ventures ................... (7,753) (5,302) (1,586)
Dry hole costs and leasehold impairment ................ 289 955 663
(Increase) decrease in current assets
Accounts receivable .................................. 10,107 44,821 (66,464)
Inventories .......................................... 4,828 6,463 (2,603)
Income taxes receivable .............................. (5,185) (3,514) -
Prepayments and other ................................ (4,186) (378) 72
Increase (decrease) in current liabilities
Accounts payable ..................................... 3,876 (42,688) 79,583
Accrued liabilities .................................. (4,630) 6,967 8,268
Income taxes payable ................................. (4,661) (1,516) (2,029)
Turnaround expenditures ................................ (13,931) (4,820) (3,289)
Other, net ............................................. (969) 8 (622)
-------- --------- --------
NET CASH PROVIDED BY OPERATING ACTIVITIES ............. 41,847 105,641 46,804
CASH FLOWS FROM FINANCING ACTIVITIES
Payment of long-term debt .................................. (8,572) (13,738) (13,746)
Debt issuance costs ........................................ - (829) (764)
Issuance of common stock upon exercise of stock options .... 2,447 5,515 -
Purchase of treasury stock ................................. (1,602) - (7,224)
Cash dividends ............................................. (6,377) (5,625) (5,493)
-------- --------- --------
NET CASH USED FOR FINANCING ACTIVITIES ................ (14,104) (14,677) (27,227)
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to properties, plants and equipment .............. (35,313) (28,571) (19,261)
Investments and advances to joint ventures ................. (3,250) (5,874) (3,282)
Distributions and repayments from joint ventures ........... 11,650 5,693 2,400
Proceeds from sale of marketable equity securities ......... 4,500 - -
Other ...................................................... 460 - -
-------- --------- --------
NET CASH USED FOR INVESTING ACTIVITIES ................ (21,953) (28,752) (20,143)
-------- --------- --------
CASH AND CASH EQUIVALENTS
INCREASE (DECREASE) FOR THE YEAR ........................... 5,790 62,212 (566)
Beginning of year .......................................... 65,840 3,628 4,194
-------- --------- --------
END OF YEAR ................................................ $ 71,630 $ 65,840 $ 3,628
======== ========= ========
See accompanying notes.
-45-
HOLLY CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
ACCUMULATED
OTHER
COMPREHENSIVE TOTAL
COMMON ADDITIONAL RETAINED TREASURY INCOME STOCKHOLDERS'
STOCK CAPITAL EARNINGS STOCK (LOSS) EQUITY
------ ---------- -------- -------- ------------- -------------
(In thousands)
BALANCE AT JULY 31, 1999 ................................... $ 87 $ 6,132 $ 124,341 $ (569) $(1,111) $ 128,880
Net income ................................................. - - 11,445 - - 11,445
Dividends paid ............................................. - - (5,493) - - (5,493)
Other comprehensive income ................................. - - - - 1,973 1,973
Purchase of treasury stock ................................. - - - (7,224) - (7,224)
------ -------- --------- ------- ------- ---------
BALANCE AT JULY 31, 2000 ................................... 87 6,132 130,293 (7,793) 862 129,581
Net income ................................................. - - 73,450 - - 73,450
Dividends paid ............................................. - - (5,625) - - (5,625)
Other comprehensive loss ................................... - - - - (1,187) (1,187)
Issuance of common stock upon exercise of stock options .... 1 5,514 - - - 5,515
Two-for-one stock split .................................... 78 (78) - - - -
------ -------- --------- ------- ------- ---------
BALANCE AT JULY 31, 2001 ................................... 166 11,568 198,118 (7,793) (325) 201,734
Net income ................................................. - - 32,029 - - 32,029
Dividends paid ............................................. - - (6,377) - - (6,377)
Other comprehensive income ................................. - - - - 325 325
Issuance of common stock upon exercise of stock options .... 2 2,445 - - - 2,447
Purchase of treasury stock ................................. - - - (1,602) - (1,602)
------ -------- --------- ------- ------- ---------
BALANCE AT JULY 31, 2002 ................................... $ 168 $ 14,013 $ 223,770 $(9,395) $ - $ 228,556
====== ======== ========= ======= ======= =========
See accompanying notes
46
HOLLY CORPORATION
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
YEARS ENDED JULY 31,
-------------------------------
2002 2001 2000
-------- -------- -------
(In thousands)
NET INCOME ................................................. $ 32,029 $ 73,450 $11,445
Other comprehensive income (loss)
Unrealized income on securities available for sale ...... - 88 3,281
Reclassification adjustment to net income on sale of
equity securities ...................................... (1,522) - -
Derivative instruments qualifying as cash flow
hedging instruments
Change in fair value of derivative instruments ....... (1,188) (2,669) -
Reclassification adjustment into net income .......... 3,250 607 -
-------- -------- -------
Total gain (loss) on cash flow hedges ................... 2,062 (2,062) -
-------- -------- -------
Other comprehensive income (loss) before income taxes .... 540 (1,974) 3,281
Income tax provision (benefit) .......................... 215 (787) 1,308
-------- -------- -------
Other comprehensive income (loss) .......................... 325 (1,187) 1,973
-------- -------- -------
TOTAL COMPREHENSIVE INCOME ................................. $ 32,354 $ 72,263 $13,418
======== ======== =======
See accompanying notes.
47
HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1: DESCRIPTION OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
DESCRIPTION OF BUSINESS: Holly Corporation, and its consolidated subsidiaries,
herein referred to as the "Company" unless the context otherwise indicates, is
principally an independent petroleum refiner, which produces high value refined
products such as gasoline, diesel fuel and jet fuel. Navajo Refining Company,
L.P., ("Navajo"), one of the Company's wholly-owned subsidiaries, owns a
high-conversion petroleum refinery in Artesia, New Mexico, which Navajo operates
in conjunction with crude, vacuum distillation and other facilities situated 65
miles away in Lovington, New Mexico (collectively, the "Navajo Refinery"). The
Navajo Refinery has a crude capacity of 60,000 barrels-per-day ("BPD"), can
process a variety of sour (high sulfur) crude oils and serves markets in the
southwestern United States and northern Mexico. The Company also owns Montana
Refining Company, a Partnership ("MRC"), which owns a 7,000 BPD petroleum
refinery in Great Falls, Montana ("Montana Refinery"), which can process a
variety of sour crude oils and which primarily serves markets in Montana. In
conjunction with its refining operations, the Company operates approximately
1,400 miles of pipelines as part of the supply and distribution network of the
refineries. In recent years, the Company has made an effort to develop and
expand a pipeline transportation segment which generates revenues from
unaffiliated parties. The pipeline transportation operations include
approximately 1,000 miles of pipelines, of which approximately 400 miles are
also used as part of the supply and distribution network of the Navajo Refinery.
Additionally, the Company has a 25% interest in Rio Grande Pipeline Company,
which provides transportation of liquid petroleum gases ("LPG") to northern
Mexico, and a 49% interest (50% prior to January 1, 2002) in NK Asphalt
Partners, which manufactures and markets asphalt and asphalt products in Arizona
and New Mexico. The Company also conducts a small-scale oil and gas exploration
and production program and has a small investment in a joint venture operating
retail gasoline stations and convenience stores in Montana.
PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include the
accounts of the Company and its subsidiary corporations, partnerships and
limited liability companies. All significant intercompany transactions and
balances have been eliminated.
USE OF ESTIMATES: The preparation of financial statements in accordance with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the amounts reported in the financial statements and
accompanying notes. Actual results could differ from those estimates.
RECLASSIFICATIONS: Certain reclassifications have been made in the 2001 notes to
consolidated financial statements to conform to the classifications used in
2002.
CASH EQUIVALENTS: For purposes of the statement of cash flows, the Company
considers all highly liquid investments with a maturity of three months or less
at the time of purchase to be cash equivalents.
ACCOUNTS RECEIVABLE: The majority of the accounts receivable are due from
companies in the petroleum industry. Credit is extended based on evaluation of
the customer's financial condition and in certain circumstances, collateral,
such as letters of credit or guarantees, is required. Credit losses are charged
to income when accounts are deemed uncollectible and consistently have been
minimal.
INVENTORIES: Inventories are stated at the lower of cost, using the last-in,
first-out ("LIFO") method for crude oil and refined products and the average
cost method for materials and supplies, or market.
LONG-LIVED ASSETS: The Company evaluates long-lived assets for potential
impairment by identifying whether indicators of impairment exist and, if so,
assessing whether the long-lived assets are recoverable from estimated future
undiscounted cash flows. The actual amount of impairment loss, if any, to be
recorded is equal to the amount by which a long-lived asset's carrying value
exceeds its fair value. No impairments of long-lived assets were recorded during
the fiscal years ended July 31, 2002, 2001 and 2000.
INVESTMENTS IN JOINT VENTURES: The Company accounts for investments in and
earnings from joint ventures where it has ownership of 50% or less using the
equity method.
-48-
HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
INVESTMENTS IN EQUITY SECURITIES: Investments in equity securities are
classified as available-for-sale and are reported at fair value with unrealized
gains or losses, net of tax, recorded as other comprehensive income.
REVENUE RECOGNITION: Refined product sales and related cost of sales are
recognized when products are shipped and title has passed to customers. Pipeline
transportation revenues are recognized as products are shipped through Company
operated pipelines. Crude oil buy/sell exchanges are customarily used in
association with operation of the pipelines, with only the net differential of
such transactions reflected as revenues. Additional pipeline transportation
revenues result from the lease of an interest in the capacity of a Company
operated pipeline. All revenues are reported inclusive of shipping and handling
costs billed and exclusive of excise taxes. Shipping and handling costs incurred
are reported in cost of goods sold. Intercompany sales are eliminated in
consolidation and were insignificant.
COST CLASSIFICATIONS: Costs of products sold include the cost of crude oil,
other feedstocks, blendstocks and purchased finished products, inclusive of
transportation costs. Operating expenses include direct costs of labor,
maintenance materials and services, utilities, and other direct operating costs.
Selling, general and administrative expenses include compensation, marketing
expense, professional services and other support costs.
DEPRECIATION: Depreciation is provided by the straight-line method over the
estimated useful lives of the assets, primarily 10 to 16 years for refining and
pipeline terminal facilities, 23 to 33 years for certain regulated pipelines and
3 to 10 years for corporate and other assets.
TURNAROUND COSTS: Turnarounds consist of preventive maintenance on major
processing units as well as the shutdown and restart of all units, and generally
are scheduled at two to five year intervals. Turnaround costs are deferred and
amortized over the period until the next scheduled turnaround.
ENVIRONMENTAL COSTS: Environmental costs are expensed if they relate to an
existing condition caused by past operations and do not contribute to current or
future revenue generation. Liabilities are recorded when site restoration and
environmental remediation and cleanup obligations are either known or considered
probable and can be reasonably estimated. Recoveries of environmental costs
through insurance, indemnification arrangements or other sources are included in
other assets to the extent such recoveries are considered probable.
OIL AND GAS EXPLORATION AND DEVELOPMENT: The Company accounts for the
acquisition, exploration, development and production costs of its oil and gas
activities using the successful efforts method of accounting. Lease acquisition
costs are capitalized; undeveloped leases are written down when determined to be
impaired and written off upon expiration or surrender. Geological and
geophysical costs and delay rentals are expensed as incurred. Exploratory well
costs are initially capitalized, but if the effort is unsuccessful, the costs
are charged against earnings. Development costs, whether or not successful, are
capitalized. Productive properties are stated at the lower of amortized cost or
estimated realizable value of underlying proved oil and gas reserves.
Depreciation, depletion and amortization of such properties is computed by the
units-of-production method. At July 31, 2002, the Company did not own a material
amount of proven reserves.
INCOME TAXES: Provisions for income taxes include deferred taxes resulting from
temporary differences in income for financial and tax purposes, using the
liability method of accounting for income taxes. The liability method requires
the effect of tax rate changes on current and accumulated deferred income taxes
to be reflected in the period in which the rate change was enacted. The
liability method also requires that deferred tax assets be reduced by a
valuation allowance unless it is more likely than not that the assets will be
realized.
STOCK-BASED COMPENSATION: Statement of Financial Accounting Standards ("SFAS")
No. 123, "Accounting for Stock-Based Compensation" encourages companies to adopt
a fair value approach to valuing stock options that would require compensation
cost to be recognized based on the fair value of stock options granted. The
Company has elected, as permitted by the standard, to continue to follow its
intrinsic value based method of accounting for stock options consistent with
Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock issued
to Employees." Under the intrinsic value method, compensation cost for stock
options is measured as the excess, if any, of the quoted market price of the
Company's stock at the measurement date over the exercise price.
-49-
HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DERIVATIVE INSTRUMENTS: Effective as of August 1, 2000, the Company adopted SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities," as
amended. This Statement established accounting and reporting standards for
derivative instruments and for hedging activities. It requires that all
derivative instruments be recognized as either assets or liabilities in the
balance sheet and be measured at their fair value. The Statement requires that
changes in the derivative instrument's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met. See Note 11 for
additional information on derivative instruments and hedging activities.
NEW ACCOUNTING PRONOUNCEMENTS:
SFAS No. 142 "Goodwill and Other Intangible Assets"
In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No.
142, "Goodwill and Other Intangible Assets." This statement changes how goodwill
and other intangible assets are accounted for subsequent to their initial
recognition. SFAS No. 142 is effective for fiscal years beginning after December
15, 2001, with early adoption permitted; however, all goodwill and intangible
assets acquired after June 30, 2001, are immediately subject to the provisions
of this statement. The Company will adopt the standard effective August 1, 2002
and believes that this statement will have no material effect on its financial
condition, results of operations or cash flows.
SFAS No. 143 "Accounting for Asset Retirement Obligations"
In June 2001, FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." This statement requires that the fair value for an asset
retirement obligation be capitalized as part of the carrying amount of the
long-lived asset if a reasonable estimate of fair value can be made. SFAS No.
143 is effective for fiscal years beginning after June 15, 2002, with early
adoption permitted. The Company will adopt the standard effective August 1, 2002
and believes that this statement will have no material effect on its financial
condition, results of operations or cash flows.
SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets"
In August 2001, FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets." This statement supersedes SFAS No. 121
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed of", but carries over the key guidance from SFAS No. 121 in
establishing the framework for the recognition and measurement of long-lived
assets to be disposed of by sale and addresses significant implementation
issues. SFAS No. 144 is effective for fiscal years beginning after December 15,
2001, with early adoption permitted. The Company will adopt the standard
effective August 1, 2002 and believes that this statement will have no material
effect on its financial condition, results of operations or cash flows.
SFAS No. 146 "Accounting for Certain Costs Associated with Exit or Disposal
Activities"
In June 2002, FASB issued SFAS No. 146, "Accounting for Costs Associated with
Exit or Disposal Activities" which nullifies Emerging Issues Task Force ("EITF")
94-3 and requires that a liability for a cost associated with an exit or
disposal activity be recognized when the liability is incurred and establishes
fair value as the objective for initial measurement of liabilities. This differs
from EITF 94-3 which stated that liabilities for exit costs were to be
recognized as of the date of an entity's commitment to an exit plan. SFAS No.
146 is effective for exit or disposal activities that are initiated after
December 31, 2002, though early adoption is permitted. The Company does not
believe the adoption of this standard will have a material effect on its
financial condition, results of operations or cash flows upon adoption.
The American Institute of Certified Public Accountants has issued an Exposure
Draft for a Proposed Statement of Position, "Accounting for Certain Costs and
Activities Related to Property, Plant and Equipment" which would require major
maintenance activities to be expensed as costs are incurred. As of July 31,
2002, the Company had approximately $13.8 million of deferred maintenance costs
which are being amortized at a rate of approximately $691,000 per month. If this
proposed Statement of Position had been adopted in its current form as of July
31, 2002, the Company would have been required to expense, as of July 31, 2002,
$13.8 million of deferred maintenance costs and would be required to expense all
future turnaround costs as incurred.
NOTE 2: EARNINGS PER SHARE
-50-
HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Basic income per share is calculated as net income divided by average number of
shares of common stock outstanding. Diluted income per share assumes, when
dilutive, issuance of the net incremental shares from stock options. Income per
share amounts reflect the two-for-one stock split in July 2001. In 2000 options
to purchase 50,000 shares of common stock were not included in computing diluted
income per share because their effects were antidilutive. The following is a
reconciliation of the numerators and denominators of the basic and diluted per
share computations for income:
YEARS ENDED JULY 31,
------------------------------------------
2002 2001 2000
------------ ------------ ------------
(In thousands, except per share data)
Net income .................................. $ 32,029 $ 73,450 $ 11,445
Average number of shares of common
stock outstanding ......................... 15,560 15,187 16,131
Effect of dilutive stock options ............ 411 200 -
------------ ------------ ------------
Average number of shares of common
stock outstanding assuming dilution ....... 15,971 15,387 16,131
============ ============ ============
Income per share - basic .................... $ 2.06 $ 4.84 $ 0.71
============ ============ ============
Income per share - diluted .................. $ 2.01 $ 4.77 $ 0.71
============ ============ ============
On October 30, 2001, the Company announced plans to repurchase up to $20 million
of the Company's common stock. During fiscal 2002, 98,500 shares were
repurchased for approximately $1,602,000 or $16.26 per share. In fiscal 2003, an
additional 63,500 shares were repurchased through September 19, 2002 for
approximately $1,058,000 or $16.66 per share.
NOTE 3: ACCOUNTS RECEIVABLE
JULY 31,
-----------------------------
2002 2001
------------- -------------
(In thousands)
Product and transportation ........ $ 46,929 $ 50,364
Crude oil resales ................. 88,466 95,710
---------- ----------
$ 135,395 $ 146,074
========== ==========
Crude oil resales accounts receivable represent the sell side of reciprocal
crude oil buy/sell exchange arrangements, with an approximate like amount
reflected in accounts payable. The net differential of these crude oil buy/sell
exchanges involved in supplying crude oil to the refineries is reflected in cost
of sales and results principally from crude oil type and location differences.
The net differential of crude oil buy/sell exchanges involved in pipeline
transportation is reflected in revenue since the exchanges were entered into as
a means of compensation for pipeline services.
-51-
HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 4: INVENTORIES
JULY 31,
-----------------
2002 2001
------- -------
(In thousands)
Crude Oil ............................................. $ 5,431 $ 8,050
Other raw materials and unfinished products (1) ....... 5,706 3,671
Finished products (2) ................................. 23,983 28,323
Process chemicals (3) ................................. 3,986 4,161
Repairs and maintenance supplies and other ............ 6,202 5,931
------- -------
$45,308 $50,136
======= =======
(1) Other raw materials and unfinished products include feedstocks and
blendstocks, other than crude. The carrying value includes the cost of
the raw material and transportation.
(2) Finished products include gasolines, jet fuels, diesels, asphalts, LPGs
and residual fuels. The inventory carrying value includes the cost of
raw materials including transportation and direct production costs.
(3) Process chemicals include catalysts, additives and other chemicals. The
inventory carrying value includes the cost of the purchased chemicals
and related freight.
The excess of current cost over the LIFO value of inventory was $30,148,000 at
July 31, 2002 and $28,861,000 at July 31, 2001. The Company recognized
$2,253,000 and $3,796,000 in income in 2002 and 2001 respectively resulting from
liquidations of certain LIFO inventory quantities that were carried at lower
costs as compared to current costs in 2002 and 2001.
NOTE 5: PROPERTIES, PLANTS AND EQUIPMENT
JULY 31,
----------------------
2002 2001
--------- ---------
(In thousands)
Land, buildings and improvements ........................... $ 15,082 $ 14,101
Refining facilities ........................................ 210,806 207,004
Pipelines and terminals .................................... 119,581 104,314
Transportation vehicles .................................... 16,595 10,898
Oil and gas exploration and development .................... 14,729 21,708
Other fixed assets ......................................... 9,244 8,040
Construction in progress ................................... 24,950 18,718
--------- ---------
410,987 384,783
Accumulated depreciation, depletion and amortization ....... (211,526) (200,628)
--------- ---------
$ 199,461 $ 184,155
========= =========
During fiscal years ended July 31, 2002 and 2001, the Company capitalized
$1,138,000 and $894,000 respectively of interest related to major construction
projects.
-52-
HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 6: INVESTMENTS IN JOINT VENTURES
In fiscal 1996, the Company entered into a joint venture to transport liquid
petroleum gas to Mexico. The Company has a 25% interest in the joint venture and
accounts for earnings using the equity method.
In fiscal 1998, the Company invested in a joint venture (a limited liability
company) to operate retail service stations and convenience stores in Montana.
The Company has a 49% interest in the joint venture and accounts for earnings
using the equity method. The Company has reserved approximately $800,000 related
to the collectability of advances of $1,755,000 associated with this joint
venture.
In fiscal 2000, the Company entered into a joint venture to manufacture and
market asphalt products from various terminals in Arizona and New Mexico. The
Company currently has a 49% interest in the joint venture and accounts for
earnings using the equity method. In fiscal 2000, the Company contributed cash
of $2,182,000, inventories with a net book value of $928,000 and properties with
a net book value of $4,311,000 for a 50% ownership interest in the joint
venture. Effective January 2002, the Company sold 1% of its 50% equity interest
to the other joint venture partner. The Company is required to make additional
contributions to the joint venture of up to $3,250,000 for each of the next
eight years contingent on the earnings level of the joint venture.
The Company's Navajo Refinery sells at market prices all of its produced asphalt
to the NK Partners joint venture. Sales to the joint venture during the fiscal
years ended July 31, 2002, 2001 and 2000 were $22.6 million, $25.3 million and
$1.4 million, respectively.
NK Asphalt Partners Joint Venture (Unaudited):
JULY 31,
---------------------
2002 2001
---- ----
(In thousands)
Current assets ........... $24,631 $28,866
Other assets ............. 13,263 14,468
------- -------
Total .................... $37,894 $43,334
======= =======
Current liabilities ...... $ 8,878 $13,969
Long-term liabilities .... 51 75
Equity ................... 28,965 29,290
------- -------
Total .................... $37,894 $43,334
======= =======
Sales (net) .............. $86,596 $92,775
======= =======
Gross Profit ............. $22,618 $20,551
======= =======
Income from operations ... $13,217 $ 9,264
======= =======
Net income before taxes .. $13,425 $ 9,184
======= =======
-53-
HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 7: DEBT
JULY 31,
------------------------
2002 2001
---- ----
(In thousands)
Senior Notes
Series C ............................ $ 22,285 $ 27,857
Series D ............................ 12,000 15,000
-------- --------
34,285 42,857
Current maturities of long-term debt .. (8,571) (8,571)
-------- --------
$ 25,714 $ 34,286
======== ========
SENIOR NOTES: In November 1995, the Company completed the funding from a group
of insurance companies of a new private placement of Senior Notes in the amount
of $39 million and the extension of $21 million of previously outstanding Senior
Notes. The $39 million Series C Notes have a 10-year life, require equal annual
principal payments beginning December 15, 1999, and bear interest at 7.62%. The
$21 million Series D Notes, have a 10-year life, require equal annual principal
payments beginning December 15, 1999, and bear interest at an initial rate of
10.16%, with reductions to 7.82% for the periods subsequent to June 15, 2001.
The Senior Notes are unsecured and the note agreements impose certain
restrictive covenants, including limitations on liens, additional indebtedness,
sales of assets, investments, business combinations and dividends, which
collectively are less restrictive than the terms of the bank Credit Agreement.
CREDIT AGREEMENT: In April 2000, the Company and its subsidiaries entered into a
credit agreement ("Credit Agreement") with a group of banks. The Credit
Agreement was scheduled to expire on October 10, 2001, however the Company and
the banks entered into an amendment to the Credit Agreement in April 2001, to
extend the expiration date. The expiration date of the Credit Agreement was to
be October 10, 2003 if there was a satisfactory resolution in the Longhorn Suit
(see Note 13) prior to October 10, 2002 and October 10, 2002 if there was not
such a satisfactory resolution by October 10, 2002. In August 2002, the Company
and the banks entered into an amendment to the Credit Agreement reducing their
commitment from $90 million to $75 million and extending the expiration date.
The expiration of the Credit Agreement will be October 10, 2004 if there is a
satisfactory resolution of the Longhorn suit prior to October 10, 2003 and will
be October 10, 2003 if there is not a satisfactory resolution by October 10,
2003. The Credit Agreement now provides a $75 million facility for letters of
credit or for direct borrowings of $37.5 million. Interest on borrowings is
based upon, at the Company's option, (i) the higher of the agent bank's prime
rate plus a margin ranging from .25% to 1% or the Federal funds rate plus .50%
per annum; or (ii) the London interbank offered rate ("LIBOR") plus a margin
ranging from 1.25% to 2.5%. A fee ranging from 1.25% to 2.5% per annum is
payable on the outstanding balance of all letters of credit and a commitment fee
ranging from .30% to .50% per annum is payable on the unused portion of the
facility. Such interest rate margins and fees are determined based on a
quarterly calculation of the ratio of cash flow to debt of the Company. Until
there is a satisfactory resolution of the Longhorn Suit, the minimum interest
rate margins and fees will be near the highest amounts indicated. The borrowing
base, which secures the facility, consists of accounts receivable and inventory,
and at the option of the Company, cash and cash equivalents. The Credit
Agreement imposes certain requirements, including: (i) a prohibition of other
indebtedness in excess of $5 million with exceptions for, among other things,
indebtedness under the Company's Senior Notes; (ii) maintenance of certain
levels of net worth, working capital and a cash-flow-to-debt ratio; (iii)
limitations on investments, capital expenditures and dividends; and (iv) a
prohibition of changes in controlling ownership.
At July 31, 2002, the Company had outstanding letters of credit totaling
$19,185,000, and no borrowings outstanding. At that level of usage, the unused
commitment under the current Credit Agreement would be $55,815,000, which could
be used for letters of credit or for additional direct borrowings of
$37,500,000.
-54-
HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The average and maximum amounts outstanding and the effective average interest
rate for borrowings under the Company's current and prior credit agreements were
as follows:
YEARS ENDED JULY, 31
----------------------------
2002 2001 2000
---- ---- ----
(In thousands)
Average amount outstanding $ - $ - $ 784
Maximum balance $ - $ - $ 11,000
Effective average interest rate - - 9.5%
The Senior Notes and Credit Agreement restrict investments and distributions,
including dividends. Under the most restrictive of these covenants, at July 31,
2002 approximately $43.5 million was available for the payment of dividends,
subject to a maximum of $10 million per fiscal year which is permitted under the
current Credit Agreement.
Maturities of long-term debt for the next five fiscal years are as follows: 2003
- $8,571,000; 2004 - $8,571,000; 2005 - $8,571,000; 2006 - $8,571,000 and 2007 -
- none.
The Company made interest payments of $3,765,501 in 2002, $5,552,000 in 2001,
and $6,192,000 in 2000.
Based on the borrowing rates that the Company believes would be available for
replacement loans with similar terms and maturities of the debt of the Company
now outstanding, the Company estimates fair value of long-term debt including
current maturities to be approximately equal to the amount currently on the
balance sheet of $34.3 million at July 31, 2002.
NOTE 8: INCOME TAXES
The provision for income taxes is comprised of the following:
YEARS ENDED JULY 31,
-----------------------------------
2002 2001 2000
---- ---- ----
(In thousands)
Current
Federal ..... $12,317 $36,337 $ 9,166
State ....... 2,216 8,240 2,153
Deferred
Federal ..... 4,072 3,184 (3,302)
State ....... 262 684 (828)
------- ------- -------
$18,867 $48,445 $ 7,189
======= ======= =======
-55-
HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The statutory federal income tax rate applied to pre-tax book income reconciles
to income tax expense as follows:
YEARS ENDED JULY 31,
------------------------------------------
2002 2001 2000
---- ---- ----
(In thousands)
Tax computed at statutory rate ........................ $ 17,814 $ 42,663 $ 6,522
State income taxes, net of federal tax benefit ........ 1,985 5,942 908
Other ................................................. (932) (160) (241)
-------- -------- --------
$ 18,867 $ 48,445 $ 7,189
======== ======== ========
Prior to the acquisition of MRC by the Company, operations of the corporation
that was the sole limited partner of MRC resulted in unused net operating loss
carryforwards of approximately $9,000,000, which are expected to be available to
the Company to a limited extent each year through 2006. As of July 31, 2002,
approximately $2,100,000 of these net operating loss carryforwards remain
available to offset future income. In fiscal 2002, the Company recognized a
benefit of approximately $455,000 associated with these net operating loss
carryforwards for losses it believes are more likely than not to be realized by
the Company in future years. For financial reporting purposes, the unrecognized
portion of the benefit of these net operating loss carryforwards is being offset
against contingent future payments of up to $95,000 per year through 2005
relating to the acquisition of such corporation.
Deferred income taxes reflect the net tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amount used for income tax purposes. The Company's deferred
income tax assets and liabilities as of July 31, 2002 and 2001 are as follows:
-56-
HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JULY 31, 2002
------------------------------------------------
ASSETS LIABILITIES TOTAL
------ ----------- -----
(In thousands)
Deferred taxes
Accrued employee benefits ........................... $ 2,016 $ (755) $ 1,261
Accrued postretirement benefits ..................... 1,820 - 1,820
Inventory valuation reserve ......................... 712 - 712
Deferred turnaround costs ........................... - (2,828) (2,828)
Pipeline lease ...................................... 746 - 746
Prepayments and other ............................... 550 (2,311) (1,761)
-------- -------- --------
Total current ......................................... 5,844 (5,894) (50)
Properties, plants and equipment (due primarily to
tax in excess of book depreciation) ............... - (25,563) (25,563)
Deferred turnaround costs ........................... - (2,504) (2,504)
Investments in joint ventures ....................... - (1,638) (1,638)
Other ............................................... 1,282 (642) 640
-------- -------- --------
Total noncurrent ...................................... 1,282 (30,347) (29,065)
-------- -------- --------
Total ................................................. $ 7,126 $(36,241) $(29,115)
======== ======== ========
JULY 31, 2001
---------------------------------------
ASSETS LIABILITIES TOTAL
------ ----------- -----
(In thousands)
Deferred taxes
Accrued employee benefits ................................ $ 2,262 $ - $ 2,262
Accrued postretirement benefits .......................... 1,965 - 1,965
Inventory valuation reserve .............................. 936 - 936
Deferred turnaround costs ................................ - (1,710) (1,710)
Pipeline lease ........................................... 920 - 920
Investments in equity securities ......................... - (607) (607)
Prepayments and other .................................... 1,549 (1,870) (321)
-------- -------- --------
Total current .............................................. 7,632 (4,187) 3,445
Properties, plants and equipment (due primarily to
tax in excess of book depreciation) .................... - (24,978) (24,978)
Deferred oil and gas costs ............................... 813 - 813
Deferred turnaround costs ................................ - (1,347) (1,347)
Investments in joint ventures ............................ 140 (1,947) (1,807)
Other .................................................... 489 (1,180) (691)
-------- -------- --------
Total noncurrent ........................................... 1,442 (29,452) (28,010)
-------- -------- --------
Total ...................................................... $ 9,074 $(33,639) $(24,565)
======== ======== ========
The Company made income tax payments of $24,135,000 in fiscal 2002, $48,356,000
in fiscal 2001, and $13,301,000 in fiscal 2000.
-57-
HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 9: STOCKHOLDERS' EQUITY
STOCK SPLIT: In June 2001, the Board of Directors declared a two-for-one stock
split, effected in the form of a 100-percent stock dividend which was
distributed in July 2001. All references to the number of shares (other than
common stock on the Consolidated Balance Sheet) and per share amounts in the
Consolidated Financial Statements and the accompanying Notes to Consolidated
Financial Statements have been adjusted to reflect the split on a retroactive
basis. Previously awarded stock options, and all other compensation arrangements
based on the market value of the Company's common stock have been adjusted to
reflect the split.
STOCK OPTION PLANS: The Company has stock option plans under which certain
officers and employees have been granted options. All of the options have been
granted at prices equal to the market value of the shares at the time of grant
and expire on the tenth anniversary of the grant date. The options are subject
to forfeiture with vesting for all options outstanding at July 31, 1999 of 20%
at the time of grant and 20% in each of the four years thereafter and vesting
for all options granted subsequent to July 31, 1999 of 20% at the end of each of
the five years after the grant date. At July 31, 2002 and 2001, 944,000 and
994,000 shares of common stock were reserved for future grants under the current
stock option plan.
The following summarizes stock option transactions:
WEIGHTED
AVERAGE
EXERCISE
SHARES PRICE
------ -----
Balance at July 31, 1999 ......................... 680,000 $ 13.38
Granted .......................................... 790,000 6.95
Forfeited ........................................ (104,000) 9.08
--------- ---------
Balance at July 31, 2000 ......................... 1,366,000 9.99
Granted .......................................... 642,000 11.05
Forfeited ........................................ (6,000) 13.38
Exercised ........................................ (379,000) 11.57
--------- ---------
Balance at July 31, 2001 ......................... 1,623,000 10.02
Granted .......................................... 50,000 19.80
Forfeited ........................................ - -
Exercised ........................................ (179,300) 11.11
--------- ---------
Balance at July 31, 2002 ......................... 1,493,700 $ 10.22
========= =========
Options exercisable at July 31,
2002 ........................................... 513,700 $ 11.12
2001 ........................................... 315,000 $ 11.96
2000 ........................................... 390,000 $ 13.38
-58-
HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following summarizes information about stock options outstanding at July 31,
2002:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------- -----------------------
WEIGHTED
AVERAGE WEIGHTED WEIGHTED
REMAINING AVERAGE AVERAGE
NUMBER CONTRACTUAL EXERCISE NUMBER EXERCISE
RANGE OF EXERCISE PRICE OUTSTANDING LIFE (YRS) PRICE EXERCISABLE PRICE
----------------------------- ----------- ----------- --------- ----------- --------
$5.06 - $8.63................ 690,400 7.38 $ 7.11 165,200 $ 7.04
$11.90 - $13.38.............. 753,300 7.52 12.43 348,500 13.06
$19.80....................... 50,000 9.41 19.80 - -
--------- ---- --------- ------- --------
$5.06 - $19.80............... 1,493,700 7.52 $ 10.22 513,700 $ 11.12
========= ==== ========= ======= ========
As required by SFAS No. 123, the Company has determined pro-forma information as
if it had accounted for stock options granted under the fair value method of
SFAS No. 123. The weighted-average fair value of options granted was $4.25 per
share in 2002 and $3.17 per share in 2001. The Black-Scholes option pricing
model was used to estimate the fair value of options at the respective grant
date with the following weighted-average assumptions:
NOTE 9 - STOCK OPTION PLAN
YEARS ENDED JULY 31,
-----------------------------
2002 2001 2000
------- ------- -------
Risk-free interest rates ............................... 4.8% 4.9% 6.0%
Dividend yield ......................................... 3.0% 3.0% 3.0%
Expected common stock market price voliatility factor... 49.6% 32.0% 27.0%
Weighted-average expected life of options .............. 6 years 6 years 6 years
The pro-forma effect of these options on net income and basic and diluted income
per share is as follows:
YEARS ENDED JULY 31,
------------------------------------------
2002 2001 2000
--------- ---------- ---------
(In thousands, except share data)
Net income
As reported................................................................ $ 32,029 $ 73,450 $ 11,445
Pro forma.................................................................. $ 31,564 $ 72,859 $ 11,001
Net income per share - basic
As reported................................................................ $ 2.06 $ 4.84 $ 0.71
Pro forma.................................................................. $ 2.03 $ 4.80 $ 0.68
Net income per share - diluted
As reported................................................................ $ 2.01 $ 4.77 $ 0.71
Pro forma.................................................................. $ 1.98 $ 4.74 $ 0.68
COMMON STOCK REPURCHASE: On April 18, 2000, the Company repurchased 1,405,400
shares of its outstanding common stock, for $7,224,000, or approximately $5.14
per share. The repurchase, which was made from an institutional shareholder, was
funded from existing working capital. On October 30, 2001, the Company announced
plans to repurchase up to $20 million of the Company's common stock. Such
repurchases are expected to be made from time to time in open market purchases
or privately negotiated transactions, subject to price and availability. An
amendment to the Company's Credit Agreement was made to allow for the
repurchases. During fiscal 2002,
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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
98,500 shares were repurchased for approximately $1,602,000 or $16.26 per share.
In fiscal 2003, an additional 63,500 shares were repurchased through September
19, 2002 for approximately $1,058,000 or $16.66 per share.
NOTE 10: RETIREMENT PLANS
RETIREMENT PLAN: The Company has a non-contributory defined benefit retirement
plan that covers substantially all employees. The Company's policy is to make
contributions annually of not less than the minimum funding requirements of the
Employee Retirement Income Security Act of 1974. Benefits are based on the
employee's years of service and compensation.
The following table sets forth the changes in the benefit obligation and plan
assets of the Company's retirement plan for the years ended July 31, 2002 and
2001:
JULY 31,
-----------------------
2002 2001
-------- --------
(In thousands)
Change in plan's benefit obligation
Pension plan's benefit obligation - beginning of year... $ 33,402 $ 38,346
Service cost............................................ 1,458 1,297
Interest cost........................................... 2,448 2,558
Benefits paid........................................... (2,785) (4,529)
Early retirement lump sum cash settlements.............. - (10,013)
Actuarial (gain) loss................................... 2,361 5,743
Plan amendments......................................... 3,904 -
-------- --------
Pension plan's benefit obligation - end of year......... 40,788 33,402
Change in pension plan assets
Fair value of plan assets - beginning of year........... 25,451 34,269
Actual return (loss) on plan assets..................... (3,140) 3,983
Benefits paid........................................... (2,785) (4,529)
Early retirement lump sum cash settlements.............. - (10,013)
Employer contributions.................................. 4,500 1,741
-------- --------
Fair value of plan assets - end of year................. 24,026 25,451
Reconciliation of funded status
Under-funded balance.................................... (16,762) (7,951)
Unrecognized prior service cost......................... 3,904 -
Unrecognized net loss (gain)............................ 10,298 2,593
-------- --------
Accrued pension liability (net amount recognized)....... $ (2,560) $ (5,358)
======== ========
Amounts recognized in consolidated balance sheet
Intangible asset........................................ $ 3,386 $ -
Accrued pension liability............................... (5,946) (5,358)
-------- --------
Accrued pension liability (net amount recognized)....... $ (2,560) $ (5,358)
======== ========
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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Net periodic pension expense consisted of the following components:
YEARS ENDED JULY 31,
--------------------------------
2002 2001 2000
------- ------- -------
(In thousands)
Service cost - benefit earned during the year..................... $ 1,458 1,297 $ 1,544
Interest cost on projected benefit obligations.................... 2,448 2,558 2,469
Expected return on plan assets.................................... (2,203) (2,321) (3,377)
Recognized actuarial gain......................................... - - (265)
Amortization of transition asset.................................. - (115) (213)
------- ----- -------
Net periodic pension expense...................................... $ 1,703 1,419 $ 158
======= ===== =======
The principal actuarial assumptions as of July 31 were:
YEARS ENDED JULY 31,
------------------------------------
2002 2001 2000
---- ---- ----
Discount rate..................................................... 7.25% 7.50% 7.75%
Rate of future compensation increases............................. 5.00% 5.00% 5.00%
Expected long-term rate of return on assets....................... 8.50% 8.50% 8.50%
Pension costs are determined using assumptions as of the beginning of the year.
The funded status is determined using the assumptions as of the end of the year.
At July 31, 2002, approximately 64% of plan assets is invested in equity
securities and 36% is invested in fixed income securities and other instruments.
During fiscal 2001, the Company amended its defined retirement plan to include
the option for participants to elect a lump-sum payout upon retirement.
VOLUNTARY EARLY RETIREMENT PROGRAM: As part of the Company's cost reduction and
production efficiency program initiated in the fourth quarter of fiscal 2000, a
voluntary early retirement package was offered to eligible employees. Prior to
July 31, 2000, a total of 55 employees elected to retire under this program, all
of whom retired in fiscal 2001. The Company recorded a charge in 2000 of
$6,783,000 relating to the voluntary early retirement program. The charge was
based on estimates of the cost for the early retirement program, consisting of
an enhancement to the Company's Retirement Plan and the Company's agreement to
allow employees retiring under the program to continue coverage at a reduced
cost under Company group medical plans until normal retirement age.
RETIREMENT RESTORATION PLAN: The Company has adopted an unfunded retirement
restoration plan that provides for additional payments from the Company so that
total retirement plan benefits for certain executives will be maintained at the
levels provided in the retirement plan before the application of Internal
Revenue Code limitations. The Company expensed $347,000 in 2002, $357,000 in
2001, and $311,000 in 2000 in connection with this plan. The accrued liability
reflected in the consolidated balance sheet was $2,047,000 at July 31, 2002 and
$2,170,000 at July 31, 2001. As of July 31, 2002, the projected benefit
obligation under this plan was $2,928,000.
DEFINED CONTRIBUTION PLANS: The Company has defined contribution ("401(k)")
plans that cover substantially all employees. Company contributions are based on
employee's compensation and partially match employee contributions. The Company
has expensed $1,106,000 in 2002, $1,158,000 in 2001, and $1,224,000 in 2000 in
connection with these plans.
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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
POSTRETIREMENT MEDICAL PLAN: The Company has adopted an unfunded postretirement
medical plan as part of the voluntary early retirement program offered to
eligible employees in fiscal 2000. As part of the early retirement program, the
Company agreed to allow retiring employees to continue coverage at a reduced
cost under Company group medical plans until normal retirement age. In fiscal
2000, the Company recorded a charge of $2,860,000 in connection with this plan.
The accrued liability reflected in the consolidated balance sheet was $2,974,000
at July 31, 2002 and $2,991,000 at July 31, 2001 related to this plan.
Additionally, the Company maintains an unfunded postretirement medical plan
whereby certain retirees between the ages of 62 and 65 can receive company paid
benefits. Periodic costs under this plan have historically been insignificant.
As of July 31, 2002, the total accumulated postretirement benefit obligation
under the Company's postretirement medical plans was $4,732,000.
NOTE 11: DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
The Company periodically utilizes petroleum commodity futures contracts to
reduce its exposure to the price fluctuations associated with crude oil and
refined products. Such contracts historically have been used principally to help
manage the price risk inherent in purchasing crude oil in advance of the
delivery date and as a hedge for fixed-price sales contracts of refined
products. No such contracts were outstanding at July 31, 2002. The Company has
also utilized commodity price swaps and collar options to help manage the
exposure to price volatility relating to forecasted purchases of natural gas. No
commodity price swaps or collar options were outstanding at July 31, 2002. The
Company regularly utilizes contracts that provide for the purchase of crude oil
and other feedstocks and for the sale of refined products. Certain of these
contracts may meet the definition of a derivative instrument in accordance with
SFAS No. 133, as amended. The Company believes these contracts qualify for the
normal purchases and normal sales exception under SFAS No. 133, as amended,
because deliveries under the contracts will be in quantities expected to be used
or sold over a reasonable period of time in the normal course of business.
Accordingly, these contracts are designated as normal purchases and normal sales
contracts and are not required to be recorded as derivative instruments under
SFAS No. 133, as amended.
In fiscal 2001, the Company entered into energy commodity futures contracts to
hedge certain commitments to purchase crude oil and deliver gasoline in March
2001. The purpose of the hedge was to help protect the Company from the risk
that the refined product margins with respect to the hedged gasoline sales would
decline. Due to the strict requirements of SFAS No. 133 in measuring
effectiveness of hedges, this particular hedge transaction did not qualify for
hedge accounting. The energy commodity futures contracts entered into resulted
in a loss of $161,000 for the year ended July 31, 2001, which was included in
cost of products sold.
In fiscal 2001, the Company entered into commodity price swaps and collar
options to help manage the exposure to price volatility relating to forecasted
purchases of natural gas in March 2001 and from May 2001 to May 2002. These
transactions were designated as cash flow hedges of forecasted purchases. As of
July 31, 2001, approximately $2.1 million of net losses were recorded to
comprehensive income as the Company marked the value of the outstanding hedges
to fair value. In fiscal 2002, the Company recorded net adjustments of $2.1
million to equity, which included actual losses of approximately $3.3 million
that were reclassified from equity to operating expenses as the transactions
occurred under the swap and collar arrangements. There were no commodity price
swaps or collar options outstanding at July 31, 2002.
NOTE 12: LEASE COMMITMENTS
The Company leases certain facilities, pipelines and equipment under operating
leases, most of which contain renewal options. At July 31, 2002, the minimum
future rental commitments under operating leases having noncancellable lease
terms in excess of one year total in the aggregate $29,020,000, of which the
following amounts are payable over the next five years: 2003 -- $6,091,000; 2004
-- $6,087,000; 2005 -- $5,889,000; 2006 -- $5,721,000 and 2007 -- $4,945,000.
Rental expense charged to operations was $6,894,000 in 2002, $6,359,000 in 2001,
and $7,131,000 in 2000.
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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 13: CONTINGENCIES
In August 1998, a lawsuit (the "El Paso Lawsuit") was filed in state district
court in El Paso, Texas against the Company and two of its subsidiaries (along
with an Austin, Texas law firm which was subsequently dropped from the case).
The suit was filed by Longhorn Partners Pipeline, L.P. ("Longhorn Partners"), a
Delaware limited partnership composed of Longhorn Partners GP, L.L.C. as general
partner and affiliates of ExxonMobil Pipeline Company, BP Pipeline (North
America), Inc., Williams Pipe Line Company, and the Beacon Group Energy
Investment Fund, L.P. and Chisholm Holdings as limited partners. The suit, as
most recently amended by Longhorn Partners in September 2000, seeks damages
alleged to total up to $1,050,000,000 (after trebling) based on claims of
violations of the Texas Free Enterprise and Antitrust Act, unlawful interference
with existing and prospective contractual relations, and conspiracy to abuse
process. The specific actions of the Company complained of in the El Paso
Lawsuit, as currently amended, are alleged solicitation of and support for
allegedly baseless lawsuits brought by Texas ranchers in federal and state
courts to challenge the proposed Longhorn Pipeline project, support of allegedly
fraudulent public relations activities against the proposed Longhorn Pipeline
project, entry into a contractual "alliance" with Fina Oil and Chemical Company,
threatening litigation against certain partners in Longhorn Partners, and
alleged interference with the federal court settlement agreement that provided
for an Environmental Assessment of the Longhorn Pipeline. In April 2002, the
state district court in El Paso denied the Company's motion for summary judgment
which had been pending for more than a year and which sought a court ruling that
would have terminated the litigation. The Company filed an appeal seeking review
by the state appeals court in El Paso of the district court's denial of summary
judgment; in late August 2002, the state appeals court in El Paso issued an
order dismissing the appeal for want of jurisdiction. In early October 2002 the
Company filed a petition seeking review by the Texas Supreme Court of the
decision of the state appeals court. In the trial court, a motion filed by the
Company to transfer the venue for trial of the case from the El Paso trial court
to another Texas court has been pending since May 2000, and no hearing on this
motion is currently scheduled. The Company believes that the El Paso Lawsuit is
wholly without merit and plans to continue to defend itself vigorously. In
August 2002, the Company filed a lawsuit in New Mexico state court in Carlsbad,
New Mexico (the "Carlsbad Lawsuit") against Longhorn Partners and its major
owners concerning the El Paso Lawsuit; the Carlsbad Lawsuit seeks actual and
punitive damages for tortious interference with existing business relations,
malicious abuse of process, unfair competition, prima facie tort and conspiracy.
In December 2001, with the consent of the Company, a Consent Decree (the
"Consent Decree") was filed in the United States District Court for the District
of New Mexico in the case of United States of America v. Navajo Refining
Company, L.P. and Montana Refining Company. The Consent Decree resulted from
negotiations which were initiated by the Company and which began in July 2001
involving representatives of the Company, the Environmental Protection Agency,
the New Mexico Environment Department, and the Montana Department of
Environmental Quality with respect to a possible settlement of issues concerning
the application of federal and state air quality requirements to past and future
operations of the Company's refineries. The Consent Decree was approved and
entered by the Court in March 2002. The Consent Decree requires investments by
the Company expected to total between $15 million and $20 million over a number
of years at the Company's New Mexico and Montana refineries for the installation
of certain state of the art pollution control equipment and requires changes in
operational practices at these refineries that go beyond current regulatory
requirements to reduce air emissions. In addition, the Consent Decree provides
to the Company and its subsidiaries releases from liability for enforcement
actions with respect to a number of possible issues relating to the application
of air quality regulations to the Company's refineries. The Consent Decree also
provides for payment by the Company of penalties to Federal, New Mexico and
Montana regulatory authorities in the total amount of $750,000 and expenditures
of approximately $1.5 million for environmentally beneficial projects and
provides for the payment by the Company of agreed monetary penalties in the
event of noncompliance with specified requirements of the Consent Decree. The
Company is currently implementing provisions of the Consent Decree applicable to
current operations and is preparing to implement those Consent Decree provisions
that require future capital investments or operational changes.
In September 2002, the Federal Energy Regulatory Commission ("FERC") issued an
order (the "Order") in proceedings brought by the Company and other parties
against SFPP, L.P. ("SFPP") relating to tariffs of common carrier pipelines,
which are owned and operated by SFPP, for shipments of refined products in the
period from 1993 through July 2000 from El Paso, Texas to Tucson and Phoenix,
Arizona and from points in California to points in
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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Arizona. The Company is one of several refiners that regularly utilize an SFPP
pipeline to ship refined products from El Paso, Texas to Tucson and Phoenix,
Arizona. The Order appears to resolve most remaining issues relating to SFPP's
tariffs on the pipelines to points in Arizona from 1993 through July 2000 and is
expected to be followed by a final FERC ruling after completion of computations
based on the guidance provided by the Order. Based on prior preliminary
computations and the rulings made in the Order, the Company expects that the
final FERC ruling for the years at issue would result in a refund to the Company
of approximately $15 million. The final FERC decision on this matter will be
subject to judicial review by the Court of Appeals for the District of Columbia
Circuit. At the date of this Report, it is not possible to predict when amounts
may be payable to the Company under the anticipated final FERC decision on this
matter, whether a final settlement may be reached with SFPP based on the Order,
or what may be the result of judicial review proceedings on this matter in the
Court of Appeals for the District of Columbia Circuit.
The Company is a party to various other litigation and proceedings which it
believes, based on advice of counsel, will not have a materially adverse impact
on the Company's financial condition, results of operations or cash flows.
NOTE 14: SEGMENT INFORMATION
The Company has two major business segments: Refining and Pipeline
Transportation. The Refining segment involves the refining of crude oil and
wholesale marketing of refined products, such as gasoline, diesel fuel and jet
fuel, and includes the Company's Navajo Refinery and Montana Refinery. The
petroleum products produced by the Refining segment are marketed in the
southwestern United States, Montana and northern Mexico. Certain pipelines and
terminals operate in conjunction with the Refining segment as part of the supply
and distribution networks of the refineries. The Refining segment also includes
the equity earnings from the Company's 49% (50% prior to January 1, 2002)
interest in NK Asphalt Partners, which manufactures and markets asphalt and
asphalt products in Arizona and New Mexico. The Pipeline Transportation segment
includes approximately 1,000 miles of the Company's pipeline assets in Texas and
New Mexico. Revenues from the Pipeline Transportation segment are earned through
transactions with unaffiliated parties for pipeline transportation, rental and
terminalling operations. Pipeline Transportation segment revenues do not include
any amount relating to pipeline transportation services provided for the
Company's refining operations. The Pipeline Transportation segment also includes
the equity earnings from the Company's 25% interest in Rio Grande Pipeline
Company, which provides petroleum products transportation. Operations of the
Company that are not included in the two reportable segments are included in
Corporate and other, which includes costs of Holly Corporation, the parent
company, consisting primarily of general and administrative expenses and
interest charges, as well as a small-scale oil and gas exploration and
production program, a small equity investment in retail gasoline stations and
convenience stores and the voluntary early retirement charge in fiscal 2000.
The accounting policies for the segments are the same as those described in the
summary of significant accounting policies. The Company evaluates performance
based on earnings before interest, taxes and depreciation and amortization
(EBITDA). The Company's reportable segments are strategic business units that
offer different products and services.
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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
TOTAL FOR
PIPELINE REPORTABLE CORPORATE CONSOLIDATED
REFINING TRANSPORTATION SEGMENTS & OTHER TOTAL
---------- -------------- ---------- ----------- ------------
(In thousands)
YEAR ENDED JULY 31, 2002
Sales and other revenues.............. $ 868,730 $ 18,588 $ 887,318 $ 1,588 $ 888,906
Depreciation and amortization......... $ 24,789 $ 1,394 $ 26,183 $ 1,516 $ 27,699
Income (loss) from operations......... $ 42,725 $ 10,621 $ 53,346 $ (10,300) $ 43,046
Income (loss) before income taxes..... $ 48,597 $ 12,220 $ 60,817 $ (9,921) $ 50,896
Total assets.......................... $ 391,635 $ 22,109 $ 413,744 $ 88,562 $ 502,306
YEAR ENDED JULY 31, 2001
Sales and other revenues.............. $1,120,248 $ 18,454 $1,138,702 $ 3,428 $1,142,130
Depreciation and amortization......... $ 24,818 $ 1,487 $ 26,305 $ 1,022 $ 27,327
Income (loss) from operations......... $ 116,218 $ 10,243 $ 126,461 $ (8,554) $ 117,907
Income (loss) before income taxes..... $ 119,563 $ 12,551 $ 132,114 $ (10,219) $ 121,895
Total assets.......................... $ 384,844 $ 22,516 $ 407,360 $ 83,069 $ 490,429
YEAR ENDED JULY 31, 2000
Sales and other revenues.............. $ 947,317 $ 14,861 $ 962,178 $ 3,768 $ 965,946
Depreciation and amortization......... $ 24,542 $ 1,251 $ 25,793 $ 1,703 $ 27,496
Income (loss) from operations......... $ 25,480 $ 7,859 $ 33,339 $ (13,338) $ 20,001
Income (loss) before income taxes..... $ 27,487 $ 9,210 $ 36,697 $ (18,063) $ 18,634
Total assets.......................... $ 426,394 $ 20,941 $ 447,335 $ 17,027 $ 464,362
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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 15: SIGNIFICANT CUSTOMERS
All revenues were domestic revenues, except for sales of gasoline and diesel
fuel for export into Mexico by the Refining segment. The export sales were to an
affiliate of PEMEX (the government-owned energy company of Mexico) and accounted
for approximately $45,000,000 (5%) of the Company's revenues for 2002,
$97,000,000 (8%) of revenues for fiscal 2001, and $100,000,000 (10%) of revenues
for fiscal 2000. Sales of military jet fuel to the United States Government by
the Refining segment accounted for approximately $78,000,000 (9%) of the
Company's revenues for 2002, $113,000,000 (10%) of revenues for fiscal 2001, and
$90,000,000 (9%) of revenues for fiscal 2000. In addition to the United States
Government and PEMEX, other significant sales by the Refining segment were made
to two petroleum companies, one of which accounted for approximately
$131,000,000 (15%) of the Company's revenues in fiscal 2002, $184,000,000 (16%)
of revenues in fiscal 2001, and $143,000,000 (15%) of the revenues in fiscal
2000, and the other accounted for $116,000,000 (13%) of the Company's revenues
in fiscal 2002, $147,000,000 (13%) of revenues in fiscal 2001, $109,000,000
(11%) of revenues for fiscal 2000.
NOTE 16: OTHER INCOME
In fiscal 2002, the Company realized a $1,522,000 million gain on the sale of
marketable equity securities held for investment.
In fiscal 2001, the Company agreed to a settlement of all claims relating to the
Company's purchase of certain pipeline assets in fiscal 1998. The Company
recognized $1,153,000 as income in fiscal 2001 relating to this settlement.
In fiscal 2000, the Company agreed to terminate a long-term sulfur recovery
agreement with an unaffiliated party. As compensation for the termination of the
agreement, the Company recognized $2,200,000 as income in fiscal 2000.
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HOLLY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 17: QUARTERLY INFORMATION (UNAUDITED)
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER YEAR
---------- ---------- ----------- ---------- ----------
(In thousands, except share data)
YEAR ENDED JULY 31, 2002
Sales and other revenues............. $ 257,947 $ 166,754 $ 210,327 $ 253,878 $ 888,906
Operating costs and expenses......... $ 228,890 $ 169,473 $ 201,685 $ 245,812 $ 845,860
Income (loss) from operations........ $ 29,057 $ (2,719) $ 8,642 $ 8,066 $ 43,046
Income (loss) before income taxes.... $ 33,069 $ (792) $ 9,808 $ 8,811 $ 50,896
Net income (loss).................... $ 20,222 $ (485) $ 6,199 $ 6,093 $ 32,029
Net income (loss) per common
share - basic....................... $ 1.30 $ (0.03) $ 0.40 $ 0.39 $ 2.06
Net income (loss) per common
share - diluted..................... $ 1.27 $ (0.03) $ 0.39 $ 0.38 $ 2.01
Dividends per common share........... $ 0.10 $ 0.10 $ 0.10 $ 0.11 $ 0.41
Average number of shares of
common stock outstanding
Basic............................... 15,508 15,559 15,581 15,593 15,560
Diluted............................. 15,944 15,996 16,016 15,947 15,971
YEAR ENDED JULY 31, 2001
Sales and other revenues............. $ 325,963 $ 283,140 $ 268,190 $ 264,837 $1,142,130
Operating costs and expenses......... $ 292,376 $ 262,764 $ 233,796 $ 235,287 $1,024,223
Income from operations............... $ 33,587 $ 20,376 $ 34,394 $ 29,550 $ 117,907
Income before income taxes........... $ 33,794 $ 20,765 $ 34,585 $ 32,751 $ 121,895
Net income........................... $ 20,412 $ 12,542 $ 20,889 $ 19,607 $ 73,450
Net income per common
share - basic....................... $ 1.35 $ 0.83 $ 1.38 $ 1.27 $ 4.84
Net income per common
share - diluted..................... $ 1.35 $ 0.83 $ 1.36 $ 1.24 $ 4.77
Dividends per common share........... $ 0.09 $ 0.09 $ 0.09 $ 0.10 $ 0.37
Average number of shares of
common stock outstanding
Basic............................... 15,102 15,102 15,124 15,418 15,187
Diluted............................. 15,102 15,102 15,333 15,829 15,387
-67-
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
The Company has had no change in, or disagreement with, its independent
certified public accountants on matters involving accounting and financial
disclosure.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Set forth below is certain information about each director of the Company,
including principal occupations for at least five years. Offices with the
Company have been held for at least five years, unless otherwise indicated.
Membership on certain committees of the Board of Directors is indicated by (A)
for Audit Committee, by (C) for Compensation Committee, by (P) for Public Policy
Committee and by (E) for Executive Committee:
Matthew P. Clifton, 51, a director since 1995, has been with the Company in
various positions for over twenty years and has been President of the Company
since 1995. (E)
W. John Glancy, 60, a director from 1975 to 1995 and since September 1999, is
Senior Vice President, General Counsel and Secretary of the Company. From
December 1998 to September 1999, he was Senior Vice President, Legal of the
Company and he has held the office of Secretary since April 1999. From 1997
through March 1999, he practiced law in the Law Offices of W. John Glancy in
Dallas, Texas. (E)
William J. Gray, 61, a director since September 1996, was a consultant to the
Company from October 1999 through September 2001. From 1981 until October 1999,
Mr. Gray was Senior Vice President, Marketing and Supply of the Company. (P)
Marcus R. Hickerson, 76, a director since 1960, was a consultant to Centex
Development Company, a full-service real estate company, from 1987 to 1999 and
has been President of Waxahachie Community Development Corporation, a city-owned
corporation operating and maintaining a civic center and recreational complex in
Waxahachie, Texas, since October 1999. (A)(C)(P)
Thomas K. Matthews, II, 76, a director since 1978, has been a private financial
consultant since 1989. Robert G. McKenzie, 64, a director since 1992, has been a
private consultant since August 1999. From January 1990 to August 1999, he was
Executive Vice President and Chief Operating Officer of Brown Brothers Harriman
Trust Company of Texas, a company that provides corporate and individual trust
services. (A)(C)(P)
Lamar Norsworthy, 56, a director since 1967, is Chairman of the Board and Chief
Executive Officer of the Company. Mr. Norsworthy is also a director of Cooper
Cameron Corporation, a petroleum and industrial equipment company. (E)
Jack P. Reid, 66, a director since 1977, was a consultant to the Company on
engineering and operational matters from August 1999 through March 2003. From
1976 until August 1999, Mr. Reid was Executive Vice President, Refining, of the
Company. (E)(P)
Paul T. Stoffel, 68, a director since 2001, has since 1986 been Chairman of
Triple S Capital Corp. and of Paul Stoffel Investments, both of which are
engaged in public and private equity investments. Mr. Stoffel is also a director
of Centex Corporation, a nationwide home building and mortgage banking company.
(A)
All other required information regarding the directors of the Company is
incorporated herein by this reference to information set forth under the caption
"Election of Directors" in the Company's Proxy Statement for its Annual Meeting
of Stockholders to be held in December 2002 which will be filed within 120 days
of July 31, 2002 (the "Proxy Statement").
-68-
The required information regarding compliance with Section 16(a) of the
Securities Exchange Act of 1934, as amended, is incorporated herein by this
reference to information set forth under the caption "Section 16(a) Beneficial
Ownership Reporting Compliance" in the Proxy Statement.
The required information regarding the executive officers of the Company is
included herein in Part I, Item 4.
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION (1)
------------------------------------------
LONG-TERM ALL
NAME AND COMPENSATION OTHER
PRINCIPAL FISCAL AWARDS COMPENSATION
POSITION YEAR SALARY BONUS OPTIONS (#) (2)
--------- ----- -------- --------- ------------- ------------
Lamar Norsworthy....................... 2002 $510,000 $ 280,500 -- $ 14,511
Chairman of the Board and 2001 $490,576 $ 765,000 120,000 (3) $ 6,994
Chief Executive Officer 2000 $471,668 $ 131,000 200,000 (4) $ 19,853
Matthew P. Clifton..................... 2002 $422,004 $ 198,342 -- $ 7,499
President 2001 $405,600 $ 632,000 106,000 (5) $ 7,311
2000 $390,000 $ 109,000 80,000 (6) $ 7,311
W. John Glancy......................... 2002 $221,004 $ 87,518 -- $ 6,634
Senior Vice President, General 2001 $210,160 $ 211,000 56,000 (7) $ 8,406
Counsel and Secretary 2000 $203,680 $ 70,000 50,000 (8) $ 2,787
Stephen J. McDonnell.......... 2002 $207,800 $ 62,500 -- $ 7,979
Vice President and 2001 $193,302 $ 100,000 60,000 (9) $ --
Chief Financial Officer
John A. Knorr.......................... 2002 $176,640 $ 50,000 -- $ 6,911
Vice President, Crude Oil 2001 $168,340 $ 95,000 24,000 (10) $ 6,853
Supply and Trading 2000 $161,370 $ 38,000 40,000 (11) $ 6,720
-------------------
(1) Any perquisites or other personal benefits received from the Company by
any of the named executives were substantially less than the reporting
thresholds established by the SEC (the lesser of $50,000 or 10% of the
individual's total annual salary and bonus).
(2) All Other Compensation - details for fiscal 2002:
DIVIDENDS COMPANY
ON MATCHING
PHANTOM THRIFT
NAME SHARES PLAN OTHER TOTAL
---- --------- -------- ----- --------
Lamar Norsworthy........................ $ 8,111 $ 6,400 -- $ 14,511
Matthew P. Clifton...................... $ 1,099 $ 6,400 -- $ 7,499
W. John Glancy.......................... $ -- $ 6,634 -- $ 6,634
Stephen J. McDonnell.................... $ -- $ 7,979 -- $ 7,979
John A. Knorr........................... $ 319 $ 6,592 -- $ 6,911
(3) Options expire on March 9, 2011 and have an exercise price of $11.90
per share.
(4) Options expire on September 24, 2009 and have an exercise price of
$7.00 per share.
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(5) Options to purchase 80,000 shares of the Company's common stock expire
on September 24, 2009 and have an exercise price of $7.00 per share.
Options to purchase 26,000 shares of Company common stock expire on
December 20, 2010 and have an exercise price of $8.625 per share.
(6) Options expire on March 9, 2011 and have an exercise price of $11.90
per share.
(7) Options to purchase 16,000 shares of the Company's common stock expire
on December 20, 2010 and have an exercise price of $8.625 per share.
Options to purchase 40,000 shares of the Company's common stock expire
on March 9, 2011 and have an exercise price of $11.90 per share.
(8) Options expire on September 24, 2009 and have an exercise price of
$7.00 per share.
(9) Options to purchase 40,000 shares of the Company's common stock expire
on August 14, 2010 and have an exercise price of $6.09375 per share.
Options to purchase 20,000 shares of the Company's common stock expire
on March 9, 2011 and have an exercise price of $11.90 per share.
(10) Options to purchase 4,000 shares of the Company's common stock expire
on December 20, 2010 and have an exercise price of $8.625 per share.
Options to purchase 20,000 shares of the Company's common stock expire
on March 9, 2011 and have an exercise price of $11.90 per share.
(11) Options expire on September 24, 2009 and have an exercise price of
$7.00 per share.
All other information regarding executive compensation is incorporated herein by
this reference to information set forth under the captions "Executive
Compensation and Other Information" and "Compensation Committee Report on
Executive Compensation" in the Proxy Statement.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information concerning all equity
compensation plans previously approved by stockholders and all equity
compensation plans not previously approved by stockholders as of July 31, 2002.
Equity Compensation Plan Information as of July 31, 2002
Number of
Securities Number of securities remaining
to be issued upon Weighted average available for future issuance
exercise of exercise price of under equity compensation plans
outstanding options, outstanding options, (excluding securities reflected
Plan Category warrants and rights warrants and rights in the first column)
--------------------------------- -------------------- --------------------- -------------------------------
Equity compensation plans
approved by security holders .... 1,493,700 $ 10.22 944,000
Equity compensation plans not
approved by security holders .... N/A N/A N/A
-------------------- ---------------------- -------------------------------
1,493,700 $ 10.22 944,000
==================== ====================== ===============================
Information regarding security ownership of certain beneficial owners and
management is incorporated herein by this reference to information set forth
under the captions "Ownership of Securities" and "Election of Directors" in the
Proxy Statement.
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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information regarding certain relationships and related transactions is
incorporated herein by this reference to information set forth under the caption
"Election of Directors" in the Proxy Statement.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Documents filed as part of this report
(1) Index to Consolidated Financial Statements
Page in
Form 10-K/A
-----------
Report of Independent Auditors ................... 42
Consolidated Balance Sheet at
July 31, 2002 and 2001............... .......... 43
Consolidated Statement of Income for
the years ended July 31, 2002,
2001, and 2000 ................................. 44
Consolidated Statement of Cash Flows
for the years ended July 31, 2002,
2001, and 2000 ....................... ......... 45
Consolidated Statement of Stockholders'
Equity for the years ended July 31,
2002, 2001 and 2000................... ......... 46
Consolidated Statement of Comprehensive
Income for the years ended July 31,
2002, 2001 and 2000 ............................ 47
Notes to Consolidated Financial
Statements...................................... 48
(2) Index to Consolidated Financial Statement Schedules
All schedules are omitted since the required information is not present or
is not present in amounts sufficient to require submission of the schedule,
or because the information required is included in the consolidated
financial statements or notes thereto.
(3) Exhibits
See Index to Exhibits on pages 75 to 77.
(b) Reports on Form 8-K
No reports on Form 8-K were filed during the Company's fourth quarter that
ended July 31, 2002.
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SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS
BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
HOLLY CORPORATION
(Registrant)
/s/ Stephen J. McDonnell
------------------------------------
Stephen J. McDonnell
Vice President and Chief Financial Officer
/s/ Kathryn H. Walker
----------------------------
Kathryn H. Walker
Vice President, Accounting (Principal
Accounting Officer)
Date: November 3, 2003
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CERTIFICATION
I, Lamar Norsworthy, Chairman of the Board and Chief Executive Officer of Holly
Corporation, certify that:
1. I have reviewed this annual report on Form 10-K/A of Holly
Corporation;
2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report.
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this annual report (the "Evaluation Date");
and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and
the audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves
management or other employees who have a significant role in
the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in
this annual report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: November 3, 2003 /s/ C. Lamar Norsworthy
--------------------------------------------
C. Lamar Norsworthy
Chairman of the Board and Chief Executive Officer
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CERTIFICATION
I, Stephen J. McDonnell, Vice President and Chief Financial Officer of Holly
Corporation, certify that:
1. I have reviewed this annual report on Form 10-K/A of Holly
Corporation;
2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report.
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this annual report (the "Evaluation Date");
and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and
the audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves
management or other employees who have a significant role in
the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in
this annual report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: November 3, 2003 /s/ Stephen J. McDonnell
--------------------------------------------
Stephen J. McDonnell
Vice President and Chief Financial Officer
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HOLLY CORPORATION
INDEX TO EXHIBITS
(Exhibits are numbered to correspond to the exhibit table
in Item 601 of Regulation S-K)
EXHIBIT
NUMBER DESCRIPTION
------ -----------
3.1 Restated Certificate of Incorporation of the Registrant, as amended
(incorporated by reference to Exhibit 3(a), of Amendment No. 1 dated
December 13, 1988 to Registrant's Annual Report on Form 10-K for its
fiscal year ended July 31, 1988, File No. 1-3876).
3.2 By-Laws of Holly Corporation as amended and restated March 9, 2001
(incorporated by reference to Exhibit 3 of Registrant's Quarterly
Report on Form 10-Q for its quarterly period ended January 31, 2001,
File No. 1-3876).
10.1 7.62% Series C Senior Note of Holly Corporation, dated as of November
21, 1995, to John Hancock Mutual Life Insurance Company, with schedule
attached thereto of five other substantially identical Notes which
differ only in the respects set forth in such schedule (incorporated by
reference to Exhibit 4.4 of Registrant's Quarterly Report on Form 10-Q
for the quarterly period ended October 31, 1995, File No. 1-3876).
10.2 Series D Senior Note of Holly Corporation, dated as of November 21,
1995, to John Hancock Mutual Life Insurance Company, with schedule
attached thereto of three other substantially identical Notes which
differ only in the respects set forth in such schedule (incorporated by
reference to Exhibit 4.5 of Registrant's Quarterly Report on Form 10-Q
for the quarterly period ended October 31, 1995, File No. 1-3876).
10.3 Note Agreement of Holly Corporation, dated as of November 15, 1995, to
John Hancock Mutual Life Insurance Company, with schedule attached
thereto of five other substantially identical Note Agreements which
differ only in the respects set forth in such schedule (incorporated by
reference to Exhibit 4.6 of Registrant's Quarterly Report on Form 10-Q
for the quarterly period ended October 31, 1995, File No. 1-3876).
10.4 Guaranty, dated as of November 15, 1995, of Navajo Refining Company,
Navajo Pipeline Company, Lea Refining Company, Navajo Holdings, Inc.,
Navajo Western Asphalt Company and Navajo Crude Oil Marketing Company
in favor of John Hancock Mutual Life Insurance Company, John Hancock
Variable Life Insurance Company, Alexander Hamilton Life Insurance
Company of America, The Penn Mutual Life Insurance Company, AIG Life
Insurance Company and Pan-American Life Insurance Company (incorporated
by reference to Exhibit 4.7 of Registrant's Quarterly Report on Form
10-Q for the quarterly period ended October 31, 1995, File No. 1-3876).
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EXHIBIT
NUMBER DESCRIPTION
------ -----------
10.5 Guaranty, dated as of October 10, 1997, of Navajo Corp., Navajo
Southern, Inc., Navajo Crude Oil Purchasing, Inc. and Lorefco, Inc in
favor of the Holders to the Note Agreements dated as of November 15,
1995 (incorporated by reference to Exhibit 4.29 of Registrant's Annual
Report on Form 10-K for its fiscal year ended July 31, 1997, File No.
1-3876).
10.6 Letter of Consent, Waiver and Amendment, dated as of November 15, 1995,
among Holly Corporation, and New York Life Insurance Company, John
Hancock Mutual Life Insurance Company, John Hancock Variable Life
Insurance Company, Confederation Life Insurance Company, The Penn
Insurance and Annuity Company, The Penn Mutual Life Insurance Company,
The Manhattan Life Insurance Company, The Union Central Life Insurance
Company, Safeco Life Insurance Company, American International Life
Assurance Company of New York, Pan-American Life Insurance Company and
Jefferson-Pilot Life Insurance Company (incorporated by reference to
Exhibit 4.3 of Registrant's Quarterly Report on Form 10-Q for the
quarterly period ended October 31, 1995, File No. 1-3876).
10.7 The First Amendment to Note Agreement, dated as of July 31, 2001, by
Holly Corporation, John Hancock Mutual Life Insurance Company and each
other Purchaser to that Note Agreement, dated as of November 15, 1995,
between the Company, John Hancock and the Other Purchasers
(incorporated by reference to Exhibit 10.7 of Registrant's Annual
Report on Form 10-K for its fiscal year ended July 31, 2001, File No.
1-3876).
10.8 $100,000,000 Amended and Restated Credit and Reimbursement Agreement,
dated as of April 14, 2000, among Holly Corporation, Navajo Refining
Company, Black Eagle, Inc., Navajo Corp., Navajo Southern, Inc., Navajo
Northern, Inc., Lorefco, Inc., Navajo Crude Oil Purchasing, Inc.,
Navajo Holdings, Inc., Holly Petroleum, Inc., Navajo Pipeline Co., Lea
Refining Company, Navajo Western Asphalt Company and Montana Refining
Company, A Partnership, as Borrowers and Guarantors, the Banks listed
herein, Canadian Imperial Bank of Commerce, as Administrative Agent,
CIBC Inc., as Collateral Agent, Fleet National Bank, as Collateral
Monitor and Documentation Agent and CIBC World Markets Corp., as sole
Lead Arranger and Bookrunner, with schedules and exhibits (incorporated
by reference to Exhibit 4 of Registrant's Quarterly Report on Form 10-Q
for its quarterly period ended April 30, 2000, File No. 1-3876).
10.9 Amendment No. 1 dated as of July 14, 2000, of Amended and Restated
Credit Agreement dated as of April 14, 2000 (incorporated by reference
to Exhibit 4.13 of Registrant's Annual Report on Form 10-K for its
fiscal year ended July 31, 2000, File No. 1-3876).
10.10 Agreement of Increased Commitment as of August 2, 2000, of Amended and
Restated Credit Agreement dated as of April 14, 2000 (incorporated by
reference to Exhibit 4.14 of Registrant's Annual Report on Form 10-K
for its fiscal year ended July 31, 2000, File No. 1-3876).
10.11 Letter Agreement as of August 2, 2000, with respect to the Amended and
Restated Credit Agreement dated as of April 14, 2000 (incorporated by
reference to Exhibit 4.15 of Registrant's Annual Report on Form 10-K
for its fiscal year ended July 31, 2000, File No. 1-3876).
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EXHIBIT
NUMBER DESCRIPTION
------ -----------
10.12 Amendment No. 2 dated as of April 4, 2001 of Amended and Restated
Credit Agreement dated as of April 14, 2000 (incorporated by reference
to Exhibit 4 of Registrant's Quarterly Report on Form 10-Q for its
quarterly period ended April 30, 2001, File No. 1-3876).
10.13 Amendment No. 3 dated as of August 7, 2001 of Amended and Restated
Credit Agreement dated as of April 14, 2000 (incorporated by reference
to Exhibit 10.13 of Registrant's Annual Report on Form 10-K for its
fiscal year ended July 31, 2001, File No. 1-3876).
10.14 Amendment No. 4 dated as of September 26, 2001 of Amended and Restated
Credit Agreement dated as of April 14, 2000 (incorporated by reference
to Exhibit 10.14 of Registrant's Annual Report on Form 10-K for its
fiscal year ended July 31, 2001, File No. 1-3876).
10.15 Holly Corporation Stock Option Plan - As adopted at the Annual Meeting
of Stockholders of Holly Corporation on December 13, 1990 (incorporated
by reference to Exhibit 4(i) of Registrant's Annual Report on Form 10-K
for its fiscal year ended July 31, 1991, File No. 1-3876).
10.16 Holly Corporation 2000 Stock Option Plan - As adopted at the Annual
Meeting of Stockholders of Holly Corporation on December 14, 2000
(incorporated by reference to Exhibit 10 of Registrant's Quarterly
Report on Form 10-Q for its quarterly period ended October 31, 2000,
File No. 1-3876).
10.17* Supplemental Payment Agreement, dated as of July 8, 1993, between Lamar
Norsworthy and Holly Corporation (incorporated by reference to Exhibit
10(a) of Registrant's Annual Report on Form 10-K for its fiscal year
ended July 31, 1993, File No. 1-3876).
10.18* Supplemental Payment Agreement, dated as of July 8, 1993, between Jack
P. Reid and Holly Corporation (incorporated by reference to Exhibit
10(b) of Registrant's Annual Report on Form 10-K for its fiscal year
ended July 31, 1993, File No. 1-3876).
10.19* Holly Corporation - Supplemental Payment Agreement for 2001 Service as
Director
10.20* Holly Corporation - Supplemental Payment Agreement for 2002 Service as
Director
10.21 Amendment No. 5 dated May 6, 2002, of Amended and Restated Credit
Agreement dated as of April 14, 2000.
10.22 Amendment No. 6 dated August 6, 2002, of Amended and Restated Credit
Agreement dated as of April 14, 2000.
21.1 Subsidiaries of Registrant
23.1 Consent of Independent Auditors
99.1 Certification of Chief Executive Officer
99.2 Certification of Chief Financial Officer
* Constitute management contracts or compensatory plans or arrangements.
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