UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the fiscal year ended December 31, 2000
OR
__ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934

Commission file number 1-8704
HOWELL CORPORATION
(Exact name of registrant as specified in its charter)

Delaware 74-1223027
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

1111 Fannin, Suite 1500, Houston, Texas 77002
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: (713) 658-4000

Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
---------- ------------

Common Stock, $1 par value New York Stock Exchange
$3.50 Convertible Preferred Stock, National Association of
Series A, $1 par value Securities Dealers, Inc.
Automated Quotation System

Securities registered pursuant to Section 12(g) of the Act:
NONE

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No __

Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
|X|

The market value of all shares of Common Stock on February 22, 2001 was
approximately $62.1 million. The aggregate market value of the shares held by
nonaffiliates on that date was approximately $40.7 million. As of February 22,
2001, there were 5,535,733 common shares outstanding. See Note 11 of Notes to
Consolidated Financial Statements.

Documents Incorporated by Reference:
Howell Corporation proxy statement to be filed in connection with the 2001
Annual Shareholders' Meeting (to the extent set forth in Part III of this Form
10-K).

HOWELL CORPORATION

2000 FORM 10-K ANNUAL REPORT

Table of Contents

PART I
Page
Item 1. Business....................................................... 1
Item 2. Properties..................................................... 3
Item 3. Legal Proceedings.............................................. 9
Item 4. Submission of Matters to a Vote of Security Holders............ 9

PART II

Item 5. Market for the Registrant's Common Stock and Related
Stockholder Matters......................................... 10
Item 6. Selected Financial Data........................................ 11
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations..........................13
Item 7A. Quantitative and Qualitative Disclosure About Market Risk.......16
Item 8. Financial Statements and Supplementary Data.................... 17
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 17

PART III

Item 10. Directors and Executive Officers of the Registrant............. 17
Item 11. Executive Compensation......................................... 18
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 18
Item 13. Certain Relationships and Related Transactions................. 18

PART IV

Item 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K ....................................................18

This Form 10-K includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements other than
statements of historical facts included in this Form 10-K, including without
limitation the statements under "Business", "Properties" and "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
regarding the nature of the Company's oil and gas reserves, productive wells,
acreage, and drilling activities, the adequacy of the Company's financial
resources, current and future industry conditions and the potential effects of
such matters on the Company's business strategy, results of operations and
financial position, are forward-looking statements. Although the Company
believes that the expectations reflected in the forward-looking statements
contained herein are reasonable, no assurance can be given that such
expectations will prove to have been correct. Certain important factors that
could cause actual results to differ materially from expectations ("Cautionary
Statements"), include without limitation, fluctuations of the prices received
for the Company's oil and natural gas, uncertainty of drilling results and
reserve estimates, competition from other exploration, development and
production companies, operating hazards, abandonment costs, the effects of
governmental regulation and the leveraged nature of the Company, are stated
herein in conjunction with the forward-looking statements or are included
elsewhere in this Form 10-K. All subsequent written and oral forward-looking
statements attributable to the Company or persons acting on its behalf are
expressly qualified in their entirety by the Cautionary Statements.

PART I

Item 1. Business

A. General

Howell Corporation and its subsidiaries ("Company") are engaged in the
exploration, production, acquisition and development of oil and gas properties.
These operations are conducted in the United States.

The Company's oil and gas exploration and production activities are
conducted by Howell Petroleum Corporation ("HPC"), a wholly-owned subsidiary of
the Company, and are concentrated in Wyoming and along the Gulf Coast, both
onshore and offshore. At December 31, 2000, the Company's estimated proved
reserves were 34.8 million barrels of oil and plant liquids and 39.1 billion
cubic feet ("BCF") of gas. The core area for the Company includes the Salt Creek
and Elk Basin fields discussed below. The Company's major producing properties
include Salt Creek, Elk Basin, and Main Pass 64. These three major fields
represent 31.4 million barrels of oil equivalent ("MMBOE"), or 76%, of the
Company's total proved reserves. Substantially all of the Company's oil and
natural gas production is sold on the spot market or pursuant to contracts
priced according to the spot market. HPC has 125 employees.

The oil and gas industry is highly competitive. Major oil and gas
companies, independent operators, drilling and production purchase programs, and
individual producers and operators are active bidders for desirable oil and gas
properties, as well as the equipment and labor required to operate those
properties. Many competitors have financial resources substantially greater, and
staffs and facilities substantially larger, than those of the Company.

The Company's financial condition, profitability, future rate of growth and
ability to borrow funds or obtain additional capital, as well as the carrying
value of its oil and natural gas properties, are substantially dependent upon
prevailing prices of, and demand for, oil and natural gas. The energy markets
have historically been, and are likely to continue to be volatile, and prices
for oil and natural gas are subject to large fluctuations in response to
relatively minor changes in the supply and demand for oil and natural gas,
market uncertainty and a variety of additional factors beyond the control of the
Company. These factors include the level of consumer product demand, weather
conditions, actions of the Organization of Petroleum Exporting Countries,
domestic and foreign governmental regulations, political stability in the Middle
East and other petroleum producing areas, foreign and domestic supply of oil and
natural gas, price of foreign imports, price and availability of alternative
fuels and overall economic conditions. A substantial or extended decline in oil
and natural gas prices could have a material adverse effect on the Company's
financial position, results of operations, quantities of oil and natural gas
reserves that may be economically produced, carrying value of its proved
reserves, borrowing capacity and access to capital.

Discontinued Operations

Technical Fuels and Chemical Processing - In 1997, the Company sold
substantially all of the assets of its technical fuels and chemical processing
business. In connection with the transaction, the Company agreed not to engage
in any competing business for a five-year period after the closing. As
additional consideration for the sale, the Company retained the right to
participate in the future earnings of the business. On January 4, 1999, the
Company sold that right for $2.0 million. The sale and the results of operations
of the technical fuels and chemical processing business have been classified as
discontinued operations in the accompanying consolidated financial statements.

Investment in Genesis - In 1996, the Company conveyed the assets and
business of its crude oil gathering and marketing operations and pipeline
operations to Genesis Crude Oil, L.P., a Delaware limited partnership ("GCO").
Howell received cash of approximately $74 million and 991,300 subordinated
limited partner units of GCO. Additionally, the Company received 46% of Genesis
Energy, L.L.C., a Delaware limited liability company ("LLC") which is the
General Partner of GCO. Howell recognized a gain of approximately $13.8 million.

With only a minority interest in LLC, Howell was not in a position to
substantially influence management of GCO. During 1999, the Company decided to
dispose of its interests in GCO and LLC and recorded an impairment charge of
$13.5 million (pre-tax) attributable thereto and classified its operations as
discontinued. See Notes 4 and 5 of Notes to Consolidated Financial Statements.

The Company sold its interest in LLC during the first quarter of 2000 for
$3.0 million. The proceeds from the sale were used to reduce debt. The
subordinated limited partner units were eliminated in December 2000, as a result
of a restructuring of GCO. The Company did not receive any proceeds for its
subordinated units in GCO. No gain or loss was recognized on the sale or on the
elimination of the subordinated units.

B. Governmental and Environmental Regulations

Governmental Regulations

Domestic development, production and sale of oil and gas are extensively
regulated at both the federal and state levels. Legislation affecting the oil
and gas industry is under constant review for amendment or expansion, frequently
increasing the regulatory burden. Also, numerous departments and agencies, both
federal and state, have issued rules and regulations binding on the oil and gas
industry and its individual members, compliance with which is often difficult
and costly and some of which carry substantial penalties for failure to comply.
State statutes and regulations require permits for drilling operations, drilling
bonds and reports concerning wells. Texas and other states in which the Company
conducts operations also have statutes and regulations governing conservation
matters, including the unitization or pooling of oil and gas properties and
establishment of maximum rates of production from oil and gas wells. The
existing statutes or regulations currently limit the rate at which oil and gas
is produced from wells in which the Company owns an interest.

Environmental Regulations

The Company's operations are subject to extensive and developing federal,
state and local laws and regulations relating to environmental, health and
safety matters; petroleum; chemical products and materials; and waste
management. Permits, registrations or other authorizations are required for the
operation of certain of the Company's facilities and for its oil and gas
exploration and production activities. These permits, registrations or
authorizations are subject to revocation, modification and renewal. Governmental
authorities have the power to enforce compliance with these regulatory
requirements, the provisions of required permits, registrations or other
authorizations, and lease conditions. Third parties may have the right to sue to
enforce compliance. The cost of environmental compliance has not had a material
adverse effect on the Company's operations or financial condition in the past.
However, violations of applicable regulatory requirements, environment-related
lease conditions, or required environmental permits, registrations or other
authorizations can result in substantial civil and criminal penalties as well as
potential court injunctions curtailing operations.

Some risk of costs and liabilities related to environmental, health and
safety matters is inherent in the Company's operations, as it is with other
companies engaged in similar businesses, and there can be no assurance that
material costs or liabilities will not be incurred. In addition, it is possible
that future developments, such as stricter requirements of environmental or
health and safety laws and regulations affecting the Company's business or more
stringent interpretations of, or enforcement policies with respect to, such laws
and regulations, could adversely affect the Company. To meet changing permitting
and operational standards, the Company may be required, over time, to make site
or operational modifications at the Company's facilities, some of which might be
significant and could involve substantial expenditures. In particular, federal
regulatory programs focusing on the increased regulation of storm water runoff,
oil spill prevention and response, and air emissions (especially those that may
be considered toxic) are currently being implemented. There can be no assurance
that material costs or liabilities will not arise from these or additional
environmental matters that may be discovered or otherwise may arise from future
requirements of law.

The Company has made a commitment to comply with environmental regulations.
Personnel with training and experience in safety, health and environmental
matters are responsible for compliance activities. Senior management personnel
are involved in the planning and review of environmental matters.

C. Employment Relations

On December 31, 2000, the Company had 125 employees. The Company's
employees are not represented by a union for collective bargaining purposes. The
Company has experienced no work stoppages or strikes as a result of labor
disputes and considers relations with its employees to be good. The Company
maintains group life, medical, dental, long-term disability, short-term
disability, 401(k) and accidental death and dismemberment insurance plans for
its employees. The Company contributed $0.6 million to the 401(k) plan for 2000.

-2-

Item 2. Properties

A. Supplementary Oil and Gas Producing Information

The oil and gas producing activities of the Company are summarized below.
Substantially all of the Company's producing properties are subject to certain
restrictions under the Company's credit facility. See Note 6 of Notes to
Consolidated Financial Statements.

Oil and Gas Wells

As of December 31, 2000, the Company owned interests in productive oil and
gas wells (including producing wells and wells capable of production) as
follows:

Productive Wells
Gross(1) Net
-------- ---

Oil wells............................. 2,614 1,019
Gas wells............................. 627 52
----- -----
Total ......................... 3,241 1,071
===== =====

(1) One or more completions in the same well are counted as one well.

-3-

Reserves

The Company's net proved reserves of crude oil, condensate and natural gas
liquids (referred to herein collectively as "oil") and its net proved reserves
of gas have been estimated by the Company's engineers in accordance with
guidelines established by the Securities and Exchange Commission. The reserve
estimates at December 31, 2000, 1999, 1998, and 1997, except for the reserves
purchased from Amoco, were reviewed by independent petroleum consultants, H. J.
Gruy and Associates, Inc. The December 31, 2000, 1999, 1998 and 1997 reserves,
associated with the properties acquired from Amoco, were reviewed by independent
petroleum consultants, Ryder Scott & Associates. These estimates were used in
the computation of depreciation, depletion and amortization included in the
Company's consolidated financial statements and for other reporting purposes.

Estimated Quantities of Proved Oil and Gas Reserves

Oil Gas
(BBLs) (MCF)
------ -----

As of December 31, 1997........... 42,170,520 83,633,340
Revisions of previous estimates... (11,533,920) (6,313,032)
Extensions, discoveries & other
additions.................... 4,037,900 3,922,900
Purchases of minerals in place.... 4,634 8,107,918
Production........................ (3,542,465) (4,653,705)
Sales of minerals in place........ (1,196,828) (5,906,751)
------------ ------------
As of December 31, 1998........... 29,939,841 78,790,670
Revisions of previous estimates... 5,979,073 3,859,501
Extensions, discoveries & other
additions.................... 844,984 1,031,232
Purchases of minerals in place.... 685,478 75,751
Production........................ (2,843,055) (2,994,215)
Sales of minerals in place........ (11,575) (42,158,149)
------------ ------------
As of December 31, 1999........... 34,594,746 38,604,790
Revisions of previous estimates... (388,542) (501,401)
Extensions, discoveries & other
additions.................... 1,888,000 1,664,700
Purchases of minerals in place.... 1,552,400 2,126,500
Production........................ (2,834,567) (2,831,188)
------------ ------------
As of December 31, 2000........... 34,812,037 39,063,401
============ ============

Proved developed reserves:
December 31, 1997................. 40,711,561 81,709,974
============ ============
December 31, 1998................. 26,701,736 75,756,389
============ ============
December 31, 1999................. 31,530,345 35,890,990
============ ============
December 31, 2000................. 31,988,737 36,349,611
============ ============

Total proved reserves at year-end 2000 were 41.3 MMBOE compared to 41.0
MMBOE at year-end 1999. The change was primarily due to an increase of 2.2 MMBOE
in extensions and discoveries, and 1.9 MMBOE in purchases of minerals in place
partially offset by production. See Note 2 of Notes to Consolidated Financial
Statements.

Proved oil reserves at December 31, 2000, include 1.7 million barrels of
natural gas liquids ("NGL").

-4-

Oil and Gas Leaseholds

The following table sets forth the Company's ownership interest in
leaseholds as of December 31, 2000. The oil and gas leases in which the Company
has an interest are for varying primary terms, and many require the payment of
delay rentals to continue the primary term. The leases may be surrendered by the
Company at any time by notice to the lessors, by the cessation of production or
by failure to make timely payment of delay rentals.

Developed(1) Undeveloped
--------------- ---------------
Gross Net Gross Net
Acres Acres Acres Acres
----- ----- ----- -----

Alabama.................... 5,805 2,174 2,707 1,060
Louisiana.................. 2,495 686 46 39
Mississippi................ 2,876 840 3,367 834
Montana.................... 106 10 29,326 29,256
North Dakota............... 6,878 1,394 800 50
Texas...................... 12,518 5,233 5,938 2,555
Wyoming.................... 48,668 26,207 47,285 25,450
All other states combined.. 3,694 710 3,242 1,728
Offshore................... 7,025 5,589 - -
====== ====== ====== ======
Total.................. 90,065 42,843 92,711 60,972
====== ====== ====== ======
- --------------

(1) Acres spaced or assignable to productive wells.

Drilling Activity

The following table shows the Company's gross and net productive and dry
exploratory and development wells drilled in the United States:

Exploratory Development
------------------------- --------------------------
Productive Dry Productive Dry
Wells Holes Wells Holes
Year Gross Net Gross Net Gross Net Gross Net
---- ----- --- ----- --- ----- --- ----- ---

2000 - - - - 19.0 12.0 2.0 1.0
1999 - - - - 2.0 2.0 2.0 2.0
1998 1.0 0.6 1.0 0.1 18.0 4.5 - -

The table above reflects only the drilling activity in which the Company
had a working interest participation.

Sales Prices and Production Costs

The following table sets forth the average prices received by the Company
for its production, the average production (lifting) costs, and amortization per
equivalent barrel of production ("BOE"):

2000 1999 1998
---- ---- ----

Average sales prices:
Oil and NGL (per BBL) includes effect of hedging.. $25.03 $14.77 $11.26
Natural gas (per MCF)............................. $ 3.50 $ 1.94 $ 1.86
Production (lifting) costs (per BOE)................. $ 9.21 $ 6.84 $ 5.95
Amortization (per BOE)............................... $ 2.18 $ 1.95 $ 2.68
Impairment of oil & gas properties (per BOE)......... $ - $ - $23.66

Natural gas production is converted to barrels using its estimated energy
equivalent of six MCF per barrel.

-5-

Oil and Gas Producing Activities

CAPITALIZED COSTS. The following table presents the Company's aggregate
capitalized costs relating to oil and gas producing activities, all located in
the United States, and the aggregate amount of related depreciation, depletion
and amortization:

December 31,
2000 1999
---- ----
(In thousands)

Capitalized Costs:
Oil and gas producing properties....... $ 401,851 $ 382,393
Unproven properties.................... 20,174 21,143
---------- ----------
Total............................... $ 422,025 $ 403,536
========== ==========

Accumulated depreciation,
depletion and amortization........ $ 318,111 $ 310,897
========== ==========

COSTS INCURRED. The following table presents costs incurred by the Company,
all in the United States, in oil and gas property acquisition, exploration and
development activities:

Year Ended December 31,
2000 1999 1998
---- ---- ----
(In thousands)

Property acquisition:
Unproved properties............... $ - $ - $ 3,627
Proved properties................. 6,917 1,092 7,614
Exploration............................ 789 1,461 3,460
Development............................ 10,783 4,101 7,626
---------- ---------- ----------
$ 18,489 $ 6,654 $ 22,327
========== ========== ==========

RESULTS OF OPERATIONS. The following table sets forth the results of
operations of the Company's oil and gas producing activities, all in the United
States. The table does not include activities associated with carbon dioxide,
helium and sulfur produced from the LaBarge Project, which was sold in March
1999, or with activities associated with leasing the Company's fee mineral
interests. The table does include the revenues and costs associated with the
Company's fee mineral interests which were sold in December 1998.

Year Ended December 31,
2000 1999 1998
---- ---- ----
(In thousands)

Revenues............................... $ 80,865 $ 47,826 $ 48,538
Production (lifting) costs............. 30,436 22,875 25,703
Depreciation, depletion and
amortization...................... 7,213 6,525 11,589
Impairment of oil & gas
properties........................ - - 102,167
---------- ---------- ----------
43,216 18,426 (90,921)
Income tax expense (benefit)........... 15,558 6,265 (30,913)
---------- ---------- ----------
Results of operations (excluding
corporate overhead and interest
cost)............................. $ 27,658 $ 12,161 $ (60,008)
========== ========== ==========

Included in the 1998 amounts above are $1.3 million of revenues and $0.1
million of production costs from the production of the Company's fee mineral
interests which were sold in December 1998.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED
OIL AND GAS RESERVES. The accompanying table presents a standardized measure of
discounted future net cash flows relating to the production of the Company's
estimated proved oil and gas reserves at the end of 2000 and 1999. The method of
calculating the standardized measure of discounted future net cash flows is as
follows:

(1) Future cash inflows are computed by applying year-end prices of oil and
gas to the Company's year-end quantities of proved oil and gas reserves.
Future price changes are considered only to the extent provided by
contractual arrangements in existence at year-end.

-6-

(2) Future development and production costs are estimates of expenditures
to be incurred in developing and producing the proved oil and gas
reserves at year-end, based on year-end costs and assuming continuation
of existing economic conditions.

(3) Future income tax expenses are calculated by applying the applicable
statutory federal income tax rate to future pretax net cash flows. Future
income tax expenses reflect the permanent differences, tax credits and
allowances related to the Company's oil and gas producing activities
included in the Company's consolidated income tax expense.

(4) The discount, calculated at ten percent per year, reflects an estimate
of the timing of future net cash flows to give effect to the time value
of money.

December 31,
2000 1999
---- ----
(In thousands)

Future cash inflows.................... $1,194,169 $ 908,940
Future production costs................ 411,678 335,742
Future development costs............... 14,831 15,630
Future income tax expenses............. 233,079 155,324
----------- -----------
Future net cash flows.................. 534,581 402,244
10% annual discount for estimated
timing of cash flows.............. 254,919 196,846
----------- -----------
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves.... $ 279,662 $ 205,398
=========== ===========

The standardized measure is not intended to represent the market value of
reserves and, in view of the uncertainties involved in the reserve estimation
process, including the instability of energy markets as evidenced by recent
volatility in both natural gas and crude oil prices, the reserves may be subject
to material future revisions.

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS. The
table below presents a reconciliation of the aggregate change in standardized
measure of discounted future net cash flows:

Year Ended December 31,
2000 1999 1998
---- ---- ----
(In thousands)

Sales and transfers, net of production
costs............................. $ (50,429) $ (24,951) $ (22,836)
Net changes in prices and production
costs............................. 113,507 242,115 (56,084)
Extensions and discoveries, net of
future production and development
development costs................. 19,831 9,829 12,775
Purchases of minerals in place......... 13,284 4,348 6,586
Sales of minerals in place............. - (5,047) 1,425
Previously estimated development
costs incurred during the period.. (717) (546) (30)
Revisions of quantity estimates........ (4,673) 47,181 (20,512)
Accretion of discount.................. 20,540 6,133 13,958
Net change in income taxes............. (42,618) (79,014) 21,017
Changes in production rates (timing)
and other......................... 5,539 (55,978) (34,546)
---------- ---------- ----------

Net change......................... $ 74,264 $ 144,070 $ (78,247)
========== ========== ==========

The Company's oil and gas exploration and production activities are
conducted entirely within the United States by HPC and are concentrated in
Wyoming and along the Gulf Coast, both onshore and offshore. At December 31,
2000, the Company's estimated proved reserves were 34.8 MMBO and 39.1 BCF of
gas. The Company's major producing properties include Salt Creek, Elk Basin, and
Main Pass 64. These three major fields represent 31.4 MMBOE, or 76% of the
Company's total proved reserves. Substantially all of the Company's oil and
natural gas production is sold on the spot market or pursuant to contracts
priced according to the spot market.

-7-

Description of Significant Properties

Salt Creek. The Company owns and operates the Salt Creek field located in
the Powder River Basin in Natrona County, Wyoming. The Company's working
interest varies from 71.8% to 100% in this multi-pay field. The field underwent
primary development beginning in 1908. In the 1960's, a waterflood was installed
in the "Light Oil Unit" ("LOU") which is unitized from the surface to the base
of the Sundance 3 formation. There are currently 726 producing wells and 584
injection wells located in the LOU on a flood pattern of approximately five acre
well spacing. As of December 31, 2000, the field was producing 3,397 barrels per
day of sweet crude oil, 177 barrels per day of sour crude and 36 barrels per day
of NGLs net to the Company. The most prolific producing formation in the LOU is
the Wall Creek 2 at a depth of 1,500 feet. It has produced approximately 390
MMBO from an original estimated 950 MMBO in place. In addition, the field has
produced another 269 MMBO from multiple horizons varying in depth down to 4,000
feet.

The Company continues to actively pursue opportunities to optimize this
massive waterflood. A balanced program of establishing effective injection rates
and pressures within waterflood patterns has been combined with appropriate
artificial lift enhancements. In addition, recompletions of shut-in or plugged
wellbores into minor horizons have been successful and more are planned in 2001.
These low cost exploitation activities have eliminated the production decline in
the field over the last three years.

Elk Basin. The Company owns and operates the Elk Basin field, located in
the Bighorn Basin in Park County, Wyoming and Carbon County, Montana. The
productive horizons range in depth from 1,700 feet to 6,000 feet, with the
majority of the production coming from the Embar-Tensleep and the Madison
formations. As of December 31, 2000, the field was producing 1,746 barrels per
day of oil and 180 barrels per day of NGLs net to the Company from 229 producing
wells and 72 injecting wells.

The Embar-Tensleep reservoir was under flue gas injection
pressure-maintenance from 1949 until 1974 when injection into the gas cap was
discontinued. The Company re-established flue gas injection to initiate an
increase in reservoir pressure in 1998. Pressure monitoring wells in the gas cap
indicate that the reservoir pressure increased throughout the year. Through a
combination of increasing reservoir pressure and continued successful capital
and expense projects in the field, production from the Embar-Tensleep reservoir
remained essentially flat throughout the year.

The Company has plans to drill additional Embar-Tensleep wells in 2001
which are intended to serve as both in-fill and down-dip extension tests on the
west flank of the structure.

The Madison formation, a heterogeneous carbonate reservoir with an interval
thickness of 800 feet, is currently under waterflood. This reservoir remains a
significant source for potential production uplift through in-fill drilling,
horizontal re-entry of existing producing wellbores, or enhanced secondary and
tertiary recovery methods. The Company's technical staff is presently studying
the formation to determine the most economical means of exploiting this
resource.

Main Pass Block 64. Main Pass is located in federal waters offshore
Louisiana about 70 miles southeast of New Orleans. The Company, as operator,
discovered oil and gas upon drilling a test well in 1982. In 1989, the Company
unitized portions of Main Pass blocks 64 and 65, covering the main pay sand (the
"7,300' Sand Unit") and implemented a waterflood project to repressure the
7,300' Sand Unit. Through continued drilling, additional acquisitions and field
unitization, the Company currently has a working interest which averages
approximately 80% in 24 gross wells, including 5 injection wells. Gross
cumulative production from the 7,300' Sand Unit over almost 18 years has totaled
12.0 MMBO and 27.0 BCF of natural gas. As of December 31, 2000, daily net
production was approximately 530 barrels of oil.

Unproven Properties. The Company acquired significant oil and gas
properties from Amoco Production Company in 1997. A portion of the acquisition
cost was allocated to an oil property that is a potential CO2 flood candidate.
In light of the unusually low oil price environment for nearly two years
following the acquisition, limited evaluation work was done during that period.
With the strong rebound of oil prices, Company personnel and consultants are now
studying the properties to determine the feasibility of such a project. It is
expected that during the next year management will have enough information to
make an informed judgment about whether to implement the CO2 flood project.

-8-

At December 31, 2000, $14.6 million attributable to this property is
included in unproven properties on the balance sheet. If the evaluation
determines that the CO2 flood project is not feasible, the associated costs will
be transferred to the full cost pool and would result in increasing depletion
expense by approximately 15% in future periods. The Company has not recognized
any proved reserves attributable to the CO2 potential of this property. If the
Company decides to go forward with the project, one or more successful pilot
programs will be necessary in order to record any proved reserves. It is
expected that the development costs would be funded from cash flow from
operations.

B. Other Properties

The Company leases approximately 52,900 square feet for use as corporate
and administrative offices in Houston, Texas.

Item 3. Legal Proceedings

The Company, through its subsidiaries, is involved from time to time in
various claims, lawsuits and administrative proceedings incidental to its
business. In the opinion of management, the ultimate liability thereunder, if
any, will not have a material adverse effect on the financial condition or
results of operations or cash flows of the Company. See Note 8 of Notes to
Consolidated Financial Statements.

Item 4. Submission of Matters to a Vote of Security Holders

None.

-9-

Part II

Item 5. Market for the Registrant's Common Stock and Related Stockholder
Matters

Howell Corporation common stock is traded on the New York Stock Exchange.
Symbol: HWL

Cash
Price Dividends
For quarter ended High Low $
------------------ ---- --- ----

March 31, 1999................... 3.94 1.75 0.04
June 30, 1999.................... 5.75 3.25 0.04
September 30, 1999............... 7.50 5.00 0.04
December 31, 1999................ 6.63 5.38 0.04
March 31, 2000................... 7.44 5.56 0.04
June 30, 2000.................... 10.31 6.50 0.04
September 30, 2000............... 13.63 9.13 0.04
December 31, 2000................ 13.38 11.13 0.04

Approximate number of equity shareholders as of December 31, 2000: 1,800.

It is the current intention of the Company to pay quarterly cash dividends
on its common stock. No assurance can be given, however, as to the timing and
amount of any future dividends which necessarily will depend on the earnings and
financial needs of the Company, legal restraints, and other considerations that
the Company's Board of Directors deems relevant. The ability of the Company to
pay dividends on its common stock is currently subject to certain restrictions
contained in its bank credit agreement. See Item 7, "Management's Discussion and
Analysis of Financial Condition - Liquidity and Capital Resources."

In addition, the Company has 690,000 shares of convertible preferred stock
outstanding. These shares were issued in April 1993. The $3.50 convertible
preferred stock is traded on the National Association of Securities Dealers,
Inc. Automated Quotation System ("NASDAQ") under the symbol HWLLP. See Note 7 of
Notes to Consolidated Financial Statements.

Subsequent Event

On January 30, 2001, the Company declared a 10% stock dividend to be paid
on March 22, 2001, for common shareholders of record on March 8, 2001. The
number of common shares outstanding will increase by 10% when the dividend is
paid. Additionally, the price at which the convertible preferred stock may be
converted into common shares will be reduced from $16.50 to approximately $15.00
after the dividend. See Note 11 of Notes to Consolidated Financial Statements.

-10-

Item 6. Selected Financial Data

The information below is presented in order to highlight significant trends
in the Company's results from continuing operations and financial condition. See
Consolidated Financial Statements and Notes thereto.

Year Ended December 31, (1) (2)
2000 1999 1998(3) 1997 1996
---- ---- ------- ---- ----
(In thousands, except per share amounts)

Revenues from continuing
operations.............. $ 81,065 $ 48,310 $ 51,422 $ 34,663 $ 33,868
--------- --------- --------- --------- ---------
Net earnings (loss) from
continuing operations... $ 21,443 $ 4,945 $(68,076) $ 2,887 $ 864
--------- --------- --------- --------- ---------
Basic earnings (loss) per
common share from
continuing operations... $ 3.48 $ 0.46 $ (12.89) $ 0.09 $ (0.31)
--------- --------- --------- --------- ---------
Diluted earnings (loss) per
common share from
continuing operations... $ 2.75 $ 0.46 $ (12.89) $ 0.09 $ (0.31)
--------- --------- --------- --------- ---------
Property, plant and
equipment, net.......... $105,160 $ 93,046 $121,634 $226,228 $103,495
--------- --------- --------- --------- ---------
Total assets................. $125,414 $117,983 $166,291 $268,122 $148,768
--------- --------- --------- --------- ---------
Long-term debt............... $ 67,000 $ 82,000 $102,000 $117,000 $ 20,581
--------- --------- --------- --------- ---------

Shareholders' equity......... $ 38,919 $ 20,680 $ 26,871 $ 97,639 $ 90,048
--------- --------- --------- --------- ---------
Cash dividends per common
share................... $ 0.16 $ 0.16 $ 0.16 $ 0.16 $ 0.16
--------- --------- --------- --------- ---------
Cash dividends per preferred
share................... $ 3.50 $ 3.50 $ 3.50 $ 3.50 $ 3.50
--------- --------- --------- --------- ---------

- -----------

(1) See Note 2 of Notes to Consolidated Financial Statements regarding the 1997
sale of the technical fuels and chemical processing operations.
(2) See Notes 2 and 5 of Notes to Consolidated Financial Statements regarding
the 1999 impairment and sale and the 1996 sale, contribution and conveyance
of crude oil gathering and marketing, pipeline, and transportation
operations.
(3) Includes $102,167 (pre-tax) charge for impairment of oil and gas properties
in 1998.

-11-

Summarized below are the Company's quarterly financial data for 2000 and 1999.

2000 Quarters
First Second Third Fourth
----- ------ ----- ------
(In thousands, except per share amounts)

Revenues from continuing operations.. $ 18,276 $ 18,789 $ 21,300 $ 22,700
Earnings from continuing operations
before income taxes............. 6,985 7,306 8,916 10,297
Net earnings from continuing
operations...................... 4,540 4,678 5,634 6,591
Net earnings from continuing
operations per share - basic.... 0.71 0.74 0.91 1.09
Net earnings from continuing
operations per share - diluted.. 0.59 0.60 0.72 0.84

1999 Quarters (1)
First Second Third Fourth(2)
----- ------ ----- ---------
(In thousands, except per share amounts)

Revenues from continuing operations.. $ 8,878 $ 1,182 $ 13,368 $ 14,882
Earnings (loss) from continuing
operations before income taxes.. (2,598) 1,814 3,567 4,803
Net earnings (loss) from continuing
operations...................... (1,724) 1,178 2,338 3,153
Net earnings (loss) from
discontinued operations......... 1,307 (103) (93) (8,956)
--------- --------- --------- ---------
Net earnings (loss).................. $ (417) $ 1,075 $ 2,245 $ (5,803)
========= ========= ========= =========

Net earnings (loss) from continuing
operations per share - basic.... $ (0.43) $ 0.10 $ 0.32 $ 0.47
Net earnings (loss) from
discontinued operations per
share - basic................... 0.25 (0.01) (0.02) (1.64)
--------- --------- --------- ---------
Net earnings (loss).................. $ (0.18) $ 0.09 $ 0.30 $ (1.17)
========= ========= ========= =========

Net earnings (loss) from continuing
operations per share - diluted.. $ (0.43) $ 0.10 $ 0.30 $ 0.41
Net earnings (loss) from
discontinued operations per
share - diluted................. 0.25 (0.01) (0.01) (1.17)
--------- --------- --------- ---------
Net earnings (loss).................. $ (0.18) $ 0.09 $ 0.29 $ (0.76)
========= ========= ========= =========

- -----------------

(1) Includes effect of reclassification of Genesis to discontinued operations.
(2) Includes impairment of Genesis to market value.

-12-

Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations

The following is a discussion of the Company's financial condition, results
of operations, capital resources and liquidity. This discussion and analysis
should be read in conjunction with the Consolidated Financial Statements of the
Company and the Notes thereto.

RESULTS OF CONTINUING OPERATIONS

The Company's business is oil and gas exploration, production, acquisition
and development. Results of continuing operations for the three years ended
December 31, 2000, are discussed below. See Note 2 of Notes to Consolidated
Financial Statements.

Oil and Gas Production

Year Ended December 31,
2000 1999 1998
---- ---- ----
(In thousands)

Revenues:
Sales of oil and natural gas........... $ 80,865 $ 47,826 $ 48,538
Sales of LaBarge other products........ - 180 1,685
Gas marketing.......................... - 83 758
Minerals leasing and other............. 200 221 441
---------- ---------- ----------
Total revenues.................... $ 81,065 $ 48,310 $ 51,422
========== ========== ==========

Operating profit (loss) ............... $ 39,647 $ 14,752 $ (93,659)
========== ========== ==========

Operating information:
Average net daily production:
Oil and NGL (BBLs) ................ 7,745 7,789 9,705
Natural gas (MCF).................. 7,735 8,203 12,750

Average sales prices:
Oil and NGL (per BBL) (includes
effect of hedging)................ $ 25.03 $ 14.77 $ 11.26
Natural gas (per MCF).............. $ 3.50 $ 1.94 $ 1.86

Revenues

During 2000, revenues increased 68% when compared to the year ended 1999.
The increase was primarily due to a 69% increase in average oil and NGL prices
and an 80% increase in average natural gas prices. These were partially offset
by a 6% decrease in natural gas production as a result of the Company's sale of
the LaBarge property in early 1999. See Note 2 of Notes to Consolidated
Financial Statements.

Revenues decreased 6% during 1999 when compared to the year ended 1998
primarily due to a 20% decrease in oil production and a 36% decrease in natural
gas production as a result of the Company's sale of the LaBarge, Grass Creek,
and Pitchfork properties in early 1999. The decrease was partially offset by a
31% increase in average oil prices.

Operating Profit

During 2000, operating profits increased $24.9 million primarily as a
result of increased average energy prices. The increase was partially offset by
a $7.6 million increase in operating expenses primarily due to higher severance
and production taxes of $4.3 million. Operating profits were also offset by an
11% increase in amortization expense.

During 1999, operating profits increased $108.4 million primarily as a
result of the 1998 pre-tax non-cash impairment charge of $102.2 million.
Excluding the impairment, operating profits for 1999 increased 73% when compared
to 1998. This improvement was primarily due to a 44% reduction of amortization
expense in 1999 which resulted from the 1998 impairment charge. A $1.3 million
reduction in lease operating expenses also contributed to the increased
operating profits.

Howell's average realized oil price, including hedging but excluding NGLs,
for 2000 was $25.22 per barrel as compared to $14.95 per barrel in 1999.

-13-

Interest Expense

Interest expense decreased $1.0 million in 2000 as a result of a decrease
in long-term debt. The Company reduced debt by $15.0 million during 2000 as a
result of cash flows from continuing operations of $38.4 million. The sale of
LLC for $3.0 million also contributed to the reduced debt.

During 1999, interest expense decreased $3.7 million from 1998 as a result
of a decrease in debt. The Company reduced debt by $42.0 million during 1999 as
a result of the Company's sale of non-integral properties for $28.7 million, a
tax refund of $5.7 million, the sale of its right to participate in the future
profits of the technical fuels business for $2.0 million, and other cash
provided by continuing operations of $5.7 million.

See Notes 2 and 6 of Notes to Consolidated Financial Statements.

Provision for Income Taxes

The Company's effective tax rate of 36% reflects the statutory federal rate
plus state income taxes.

RESULTS FROM DISCONTINUED OPERATIONS

Crude Oil Marketing & Transportation

During the first quarter of 2000, the Company sold its 46% interest in LLC
for $3.0 million. The proceeds from the sale were used to reduce debt. During
1999, crude oil marketing and transportation incurred a pre-tax loss of $13.8
million. The loss is primarily a result of the impairment of the investment in
Genesis to market value. There were no revenues or operating profits in the
crude oil marketing and transportation operation during 1998 as a result of the
sale of that business in 1996. As a result of the Company's direct and indirect
interest in Genesis, the Company recognized pre-tax net earnings in Genesis of
$0.4 million during 1998.

Technical Fuels and Chemical Processing

In 1997, the Company sold substantially all of the assets of its technical
fuels and chemical processing business. In connection with the transaction, the
Company agreed not to engage in any competing business for a five-year period
after the closing. The Company has given and received environmental and other
indemnities. Claims could arise in the future that would require the Company to
perform under those indemnities. As additional consideration for the sale, the
Company retained the right to participate in the future earnings of the
business. On January 4, 1999, the Company sold that right for $2.0 million. The
sale and the results of operations of the technical fuels and chemical
processing business have been classified as discontinued operations in the
accompanying consolidated financial statements.

These results have been reclassified as discontinued operations. See Notes
2, 4 and 5 of Notes to Consolidated Financial Statements. There is no allocated
interest as interest expense incurred was strictly for the oil and gas business.
The following table presents the detail of net income (loss) from discontinued
operations as presented on the Consolidated Statements of Operations:

Year Ended December 31,
2000 1999 1998
---- ---- ----
(in thousands)

Discontinued operations:
Net earnings (loss) of Genesis (less
applicable income taxes of
$(4,702) and $133 for 1999
and 1998, respectively)........... $ - $ (9,129) $ 257
Net earnings from technical fuels
(less applicable income taxes of
$752 and $350 for 1999 and 1998,
respectively)..................... - 1,284 266
========== ========== ==========
Net earnings (loss) from discontinued
operations........................ $ - $ (7,845) $ 523
========== ========== ==========

-14-

LIQUIDITY AND CAPITAL RESOURCES

Credit Facility

Outstanding amounts under the Credit Facility bear interest, at the
Company's option, at either the Eurodollar Loan rate ("Libor"), or the Base Rate
(prime), plus the Applicable Margin. The Applicable Margin is determined by the
Borrowing Base Utilization Percentage. As a result, interest rates range from as
low as Libor plus 1.50% or the Base Rate plus 0.00% if 25% or less of the
Borrowing Base is used, to as high as Libor plus 2.50% or the Base Rate plus
0.75% if greater than 90% of the Borrowing Base is used.

As of December 31, 2000, Tranche A bore interest at 8.75% per annum on
$62.0 million and 9.75% on $5.0 million for the Libor and Base Rate portions,
respectively.

Other

At December 31, 2000 the Company had working capital of $1.3 million. In
2000, cash provided from operating activities was $38.1 million.

In 1993, the Company issued 690,000 shares of $3.50 convertible preferred
stock. The net proceeds from the sale were $32.9 million. Dividends on the
convertible preferred stock are to be paid quarterly. Such dividends accrue and
are cumulative.
The Company has paid all dividends on time.

The Company currently anticipates spending approximately $0.1 million
during fiscal years 2001 and 2002 at various facilities for capital and
operating costs associated with ongoing environmental compliance and may
continue to have expenditures in connection with environmental matters beyond
fiscal year 2002. The Company spent $0.2 million on such expenditures in 2000.
See Note 9 of Notes to Consolidated Financial Statements.

The Company believes that its cash flow from operations, and amounts
available under the Credit Facility, will be sufficient to satisfy its current
liquidity and capital expenditure requirements. At December 31, 2000, the
Company had cash and cash equivalents of $5.6 million, and $32.8 million
available to it under the Credit Facility. A decline in the value of the
Company's proved reserves could result in the bank reducing the Borrowing Base,
thereby causing mandatory payments under the Credit Facility. While the Company
does not expect this to occur in 2001, such payments would adversely affect the
Company's ability to carry out its capital expenditure program and could cause
the Company to recapitalize its debt through the public or private placement of
securities.

ACCOUNTING PRONOUNCEMENTS

In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities." SFAS No. 133, was amended in
June 1999 by SFAS No. 137, "Accounting for Derivative Instruments and Hedging
Activities - Deferral of Effective Date of FASB Statement No. 133 - an amendment
of FASB Statement No. 133." SFAS No. 133 as amended, is effective for fiscal
years beginning after June 15, 2000, and establishes accounting and reporting
standards for derivative instruments and hedging activities that require an
entity to recognize all derivatives as an asset or liability measured at its
fair value. Depending on the intended use of the derivative, changes in its
asset or liability measured at its fair value will be reported in the period of
change as either a component of earnings or a component of other comprehensive
income. Retroactive application to periods prior to adoption is not allowed. The
Company has reviewed all of its contracts to determine which, if any, contain
derivatives. As of January 1, 2001, the Company has only one derivative contract
and it is accounted for and carried at market value. Therefore, upon adoption of
SFAS No. 133, no transition adjustment will be recorded by the Company. The
Company adopted SFAS No. 133 effective January 1, 2001 and no cumulative effect
adjustment was required.

The Company adopted the provisions of Staff Accounting Bulletin ("SAB") No.
101 issued by the Securities and Exchange Commission. The impact of adopting SAB
No. 101 was not material to the Company.

-15-

FORWARD-LOOKING STATEMENTS

Statements contained in this Report and other materials filed or to be
filed by the Company with the Securities and Exchange Commission (as well as
information included in oral or other written statements made or to be made by
the Company or its representatives) that are forward-looking in nature are
intended to be "forward-looking statements" within the meaning of Section 27A of
the Securities Act of 1933, as amended, and Section 21E of the Securities
Exchange Act of 1934, as amended, relating to matters such as anticipated
operating and financial performance, business prospects, developments and
results of the company. Actual performance, prospects, developments and results
may differ materially from any or all anticipated results due to economic
conditions and other risks, uncertainties and circumstances partly or totally
outside the control of the Company, including rates of inflation, oil and
natural gas prices, uncertainty of drilling results and reserve estimates,
changes in the level and timing of future costs and expenses related to drilling
and operating activities, competition from other exploration, development and
production companies, operating hazards, abandonment costs, the effects of
governmental regulation and the leveraged nature of the Company.

Words such as "anticipate", "expect", "project", and similar expressions
are intended to identify forward-looking statements.

Item 7A. Quantitative and Qualitative Disclosure About Market Risk

In order to mitigate the effects of future price fluctuations, the Company
from time to time uses limited programs to hedge its production. Futures and
options contracts are used as the hedging tools. Changes in the market value of
the hedge transactions are deferred until the gain or loss is recognized on the
hedged transactions. In addition, the Company may, on a limited basis, enter
into market related commodity contracts which are marked-to-market.

In 1998, the Company purchased a put option and sold a call option covering
4,800 barrels of oil per day for a nine-month period ended December 31, 1998.
The strike prices were $16.00 per barrel for the put option and $19.25 per
barrel for the call option. There was no premium associated with these options.
During 1998, the Company received $2.8 million as a result of the options. These
amounts were recorded as additional revenues. Without the options the average
price per barrel of oil for the year ended December 31, 1998, would have been
reduced from $11.37 to $10.55.

The Company entered into two hedging programs for 1999. The first program
was a purchase of a put option and a sale of a call option covering 1,750
barrels of oil per day effective April 1, 1999, through December 31, 1999. The
strike prices were $15.00 per barrel for the put option and $17.00 per barrel
for the call option. The second program was a purchase of a put option and a
sale of a call option also covering 1,750 barrels of oil per day effective from
May 1, 1999, through December 31, 1999. The strike prices were $14.50 per barrel
for the put option and $18.80 per barrel for the call option. There were no
premiums associated with either of these programs. The strike price of the call
options was exceeded, resulting in a reduction of revenues of $3.5 million from
what would have been received had no hedging programs been in place. Without the
options the average price per barrel of oil for the year ended December 31,
1999, would have increased from $14.95 to $16.23.

The Company also entered into two hedging programs for the year 2000. The
first program was a purchase of a put option and a sale of a call option
covering 1,700 barrels of oil per day effective January 1, 2000, through
December 31, 2000. The strike prices were $17.25 per barrel for the put option
and $22.00 per barrel for the call option. The second program was a purchase of
a put option and a sale of a call option covering 1,800 barrels of oil per day
effective January 1, 2000, through December 31, 2000. The strike prices were
$18.50 per barrel for the put option and $26.00 per barrel for the call option.
Each program provided for monthly settlements and was based on monthly averages.
There were no premiums associated with either program. The strike price of the
call options was exceeded, resulting in a reduction of revenues of $7.9 million
from what would have been received had no hedging programs been in place.
Without the options the average price per barrel of oil for the year ended
December 31, 2000, would have increased from $25.22 to $28.15.

During the fourth quarter of 2000, the Company purchased a put option
covering 7,500 MMBTU per day for NYMEX contract months March through December
2001, allowing it to benefit should gas prices fall. The premium paid was $0.3
million and the market value of the position and its carrying value at December
31, 2000, was $0.2 million.

-16-

Item 8. Financial Statements and Supplementary Data

The response to this item is submitted as a separate section.

Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure

None.

Part III

Item 10. Directors and Executive Officers of the Registrant

Regarding Directors, the information appearing under the caption "Election
of Directors" set forth in the Company's definitive proxy statement, to be filed
within 120 days after the close of the fiscal year in connection with the 2001
Annual Shareholders' Meeting, is incorporated herein by reference. Regarding
executive officers, information is set forth below.

The executive officers are elected annually.

Name Age Position
---- --- --------

Donald W. Clayton.... 64 Chairman
Richard K. Hebert.... 49 President and Chief Executive Officer
Allyn R. Skelton, II. 49 Vice President and Chief Financial Officer
Robert T. Moffett.... 49 Vice President, General Counsel and Secretary
John E. Brewster, Jr. 50 Vice President, Corporate Development and
Planning

Mr. Donald W. Clayton was elected Chairman and Chief Executive Officer in
May 1997. From 1993 to 1997, he was co-owner and President of Voyager Energy
Corp. He formerly served as President and Director of Burlington Resources,
Inc., and President and Chief Executive Officer of Meridian Oil, Inc. Prior to
that, he was a senior executive with Superior Oil Company. Mr. Clayton remained
Chairman of the Company when Mr. Hebert succeeded him as Chief Executive Officer
in January 2001.

Mr. Richard K. Hebert was elected President and Chief Operating Officer in
May 1997. From 1993 to 1997, he was co-owner and Chief Executive Officer of
Voyager Energy Corp. He formerly served as Executive Vice President and Chief
Operating Officer of Meridian Oil, Inc., now Burlington Resources, Inc. Prior to
that, he served in various engineering and management positions with Mobil Oil
Corporation, Superior Oil Company and Amoco Production Company. Mr. Hebert
assumed the additional duties of Chief Executive Officer in January 2001.

Mr. Allyn R. Skelton, II, was elected Vice President and Chief Financial
Officer of the Company in May 1999. Mr. Skelton was formerly Chief Financial
Officer of Genesis Energy, L.P. Prior to that he was Chief Financial Officer of
Howell Corporation.

Mr. Robert T. Moffett was elected Secretary in October 1996, and Vice
President and General Counsel in January 1994. He had served as General Counsel
of the Company since September 1992. Prior to that, Mr. Moffett was a general
partner in the firm of Moffett & Brewster.

Mr. John E. Brewster, Jr. was elected Vice President, Corporate Development
& Planning in May 1997. Prior to that he was a consultant to Voyager Energy
Corp. He has held senior management positions with Santa Fe Minerals, Inc.,
Odyssey Energy, Inc., and Trafalgar House Oil & Gas Inc., and was a general
partner in the firm of Moffett & Brewster.

Regarding delinquent filers pursuant to Item 405 of Regulation S-K, the
information appearing under the caption "Compliance with Section 16(a) of the
Securities Exchange Act of 1934" set forth in the Company's definitive proxy
statement, to be filed within 120 days after the close of the fiscal year in
connection with the 2001 Annual Shareholders' Meeting, is incorporated herein by
reference.

-17-

Item 11. Executive Compensation

The information appearing under the captions "Compensation of Executive
Officers" and "Certain Transactions" set forth in the Company's definitive proxy
statement, to be filed within 120 days after the close of the fiscal year in
connection with the 2001 Annual Shareholders' Meeting, is incorporated herein by
reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management

The information appearing under the caption "Security Ownership of
Management and Certain Beneficial Owners" set forth in the Company's definitive
proxy statement, to be filed within 120 days after the close of the fiscal year
in connection with the 2001 Annual Shareholders' Meeting, is incorporated herein
by reference.

Item 13. Certain Relationships and Related Transactions

The information appearing under the caption "Certain Transactions" set
forth in the Company's definitive proxy statement, to be filed within 120 days
after the close of the fiscal year in connection with the 2001Annual
Shareholders' Meeting, is incorporated herein by reference.

Part IV

Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K

(a) (1) and (2). The response to this portion of Item 14 is submitted as
a separate section of this report (see page 20).

(a) (3) and (c). The response to this portion of Item 14 is submitted as
a separate section of this report (see page 37).

(b) Reports on Form 8-K. None.

-18-

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.

HOWELL CORPORATION
(Registrant)

By /s/ALLYN R. SKELTON, II
----------------------------
Allyn R. Skelton, II
Vice President and
Chief Financial Officer
Principal Financial and Accounting Officer

Date: February 26, 2001

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.

Signature Title Date

Principal Executive
/s/ DONALD W. CLAYTON Officer and Director February 26, 2001
- -------------------------------
Donald W. Clayton
Chairman

Principal Executive
/s/ RICHARD K. HEBERT Officer and Director February 26, 2001
- -------------------------------
Richard K. Hebert
President
and
Chief Executive Officer

/s/ PAUL N. HOWELL Director February 26, 2001
- -------------------------------
Paul N. Howell

/s/ JACK T. TROTTER Director February 26, 2001
- -------------------------------
Jack T. Trotter

/s/ RONALD E. HALL Director February 26, 2001
- -------------------------------
Ronald E. Hall

-19-

HOWELL CORPORATION AND SUBSIDIARIES

FORM 10-K

ITEMS 8, 14(a) (1) and (2)

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

The following consolidated financial statements of the registrant and its
subsidiaries required to be included in Items 8 and 14(a)(1) are listed below:

Page
Independent Auditors' Report.................................. 21
Consolidated Financial Statements:
Consolidated Balance Sheets................................. 22
Consolidated Statements of Operations....................... 23
Consolidated Statements of Changes in Shareholders' Equity.. 24
Consolidated Statements of Cash Flows....................... 25
Notes to Consolidated Financial Statements.................. 26

The financial statement schedules are omitted because they are not
applicable, are not required or because the required information is included in
the Consolidated Financial Statements or notes thereto.

-20-

INDEPENDENT AUDITORS' REPORT

To Howell Corporation:

We have audited the accompanying consolidated balance sheets of Howell
Corporation and its subsidiaries as of December 31, 2000 and 1999, and the
related consolidated statements of operations, changes in shareholders' equity,
and cash flows for each of the three years in the period ended December 31,
2000. These financial statements are the responsibility of the Corporation'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 of America. 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, such consolidated financial statements present fairly, in
all material respects, the financial position of Howell Corporation and its
subsidiaries at December 31, 2000 and 1999, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2000 in conformity with auditing principles generally accepted in the United
States of America.

DELOITTE & TOUCHE LLP

Houston, Texas
February 26, 2001

-21-

HOWELL CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets

December 31,
2000 1999
---- ----
(In thousands, except share data)

Assets
Current assets:
Cash and cash equivalents................ $ 5,553 $ 2,112
Trade accounts receivable, less allowance
for doubtful accounts of $66 in 2000
and $161 in 1999...................... 12,515 10,978
Income tax receivable - federal.......... 705 -
Deferred income taxes.................... 59 2,027
Other current assets..................... 750 2,440
---------- ----------
Total current assets.................. 19,582 17,557
---------- ----------
Property, plant and equipment:
Oil and gas properties, utilizing the
full cost method of accounting........ 401,851 382,393
Unproven properties...................... 20,174 21,143
Other.................................... 3,737 2,759
Less accumulated depreciation, depletion
and amortization...................... (320,602) (313,249)
---------- ----------
Net property, plant and equipment..... 105,160 93,046
---------- ----------
Other assets................................ 672 780
Deferred income taxes....................... - 3,600
Assets related to discontinued operations... - 3,000
========== ==========
Total assets.......................... $ 125,414 $ 117,983
========== ==========

Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable......................... $ 12,880 $ 10,513
Accrued liabilities - oil and gas
properties............................ 2,521 1,097
Accrued liabilities - other.............. 2,605 2,837
Income taxes payable - state............. 319 140
---------- ----------
Total current liabilities............. 18,325 14,587
---------- ----------
Deferred income taxes....................... 625 -
---------- ----------
Other liabilities........................... 545 716
---------- ----------
Long-term debt.............................. 67,000 82,000
---------- ----------
Commitments and contingencies Shareholders'
equity:
Preferred stock, $1 par value; 690,000
shares issued and Outstanding;
liquidation value of
$34,500,000........................... 690 690
Common stock, $1 par value; 5,524,907
shares issued and outstanding
in 2000 (5,471,782 shares in 1999) -
see Note 11........................... 5,525 5,472
Additional paid-in capital............... 41,079 40,829
Deferred compensation.................... (209) -
Retained deficit......................... (8,166) (26,311)
---------- ----------
Total shareholders' equity............ 38,919 20,680
---------- ----------
Total liabilities and shareholders'
equity.............................. $ 125,414 $ 117,983
========== ==========

See accompanying Notes to Consolidated Financial Statements.

-22-

HOWELL CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations

Year Ended December 31,
2000 1999 1998
---- ---- ----
(In thousands, except per share amounts)

Revenues.................................... $ 81,065 $ 48,310 $ 51,422
---------- ---------- ----------

Costs and expenses:
Operating expenses....................... 30,436 23,093 27,764
Depreciation, depletion and
amortization.......................... 7,353 6,671 11,703
Impairment of oil and gas properties..... - - 102,167
General and administrative expenses...... 3,629 3,794 3,447
---------- ---------- ----------
41,418 33,558 145,081
---------- ---------- ----------
Other income (expense):
Interest expense......................... (6,283) (7,329) (10,997)
Interest income.......................... 142 118 111
Other-net................................ (2) 45 (1)
---------- ---------- ----------
(6,143) (7,166) (10,887)
---------- ---------- ----------
Earnings (loss) from continuing operations
before income taxes................... 33,504 7,586 (104,546)
Income tax expense (benefit) ............... 12,061 2,641 (36,470)
---------- ---------- ----------
Net earnings (loss) from continuing
operations............................ 21,443 4,945 (68,076)

Discontinued operations:
Net earnings (loss) (less applicable
income taxes of $(3,950) and $483
for 1999 and 1998, respectively)...... - (7,845) 523
---------- ---------- ----------
Net earnings (loss)......................... 21,443 (2,900) (67,553)
Less: cumulative preferred stock
dividends............................. (2,415) (2,415) (2,415)
---------- ---------- ----------
Net earnings (loss) applicable to common
stock................................. $ 19,028 $ (5,315) $ (69,968)
========== ========== ==========

Basic earnings (loss) per common share - see
Note 11:
Continuing operations.................... $ 3.48 0.46 (12.89)
Discontinued operations.................. - (1.43) 0.10
---------- ---------- ----------
Net earnings (loss) per common share -
basic................................. $ 3.48 $ (0.97) $ (12.79)
========== ========== ==========

Weighted average shares outstanding -
basic.................................... 5,473 5,472 5,470
========== ========== ==========

Diluted earnings (loss) per common share -
see Note 11:
Continuing operations.................... $ 2.75 $ 0.46 $ (12.89)
Discontinued operations.................. - (1.42) 0.10
---------- ---------- ----------
Net earnings (loss) per common share -
diluted............................... $ 2.75 $ (0.96) $ (12.79)
========== ========== ==========

Weighted average shares outstanding -
diluted.................................. 7,786 5,554 5,470
========== ========== ==========

See accompanying Notes to Consolidated Financial Statements.

-23-

HOWELL CORPORATION AND SUBSIDIARIES
Consolidated Statements of Changes in Shareholders' Equity

Additional Retained
Preferred Stock Common Stock Paid-In Deferred Earnings
Shares $ Shares $ Capital Compensation (Deficit) Total
------ - ------ - ------- ------------ --------- -----
(In thousands, except number of shares)

Balances, December 31, 1997................. 690,000 $ 690 5,464,642 $ 5,465 $ 40,760 $ - $ 50,724 $ 97,639
Net earnings - 1998...................... - - - - - - (67,553) (67,553)
Cash dividends - $0.16 per Common share.. - - - - - - (876) (876)
Cash dividends - $3.50 per Preferred
share................................. - - - - - - (2,415) (2,415)
Common stock issued to employees upon
exercise of stock options............. - - 7,140 7 69 - - 76
--------- --------- --------- --------- --------- --------- --------- ---------
Balances, December 31, 1998................. 690,000 $ 690 5,471,782 $ 5,472 $ 40,829 $ - $(20,120) $ 26,871
Net earnings - 1999...................... - - - - - - (2,900) (2,900)
Cash dividends - $0.16 per Common share.. - - - - - - (876) (876)
Cash dividends - $3.50 per Preferred
share................................. - - - - - - (2,415) (2,415)
--------- --------- --------- --------- --------- --------- --------- ---------
Balances, December 31, 1999................. 690,000 $ 690 5,471,782 $ 5,472 $ 40,829 $ - $(26,311) $ 20,680
Net earnings - 2000...................... - - - - - - 21,443 21,443
Cash dividends - $0.16 per Common share.. - - - - - - (883) (883)
Cash dividends - $3.50 per Preferred
share................................. - - - - - - (2,415) (2,415)
Common stock issued to employees:
Upon exercise of stock options........ - - 3,125 3 22 - - 25
Restricted............................ - - 50,000 50 228 (209) - 69
--------- --------- --------- --------- --------- --------- --------- ---------
Balances, December 31, 2000................. 690,000 $ 690 5,524,907 $ 5,525 $ 41,079 $ (209) $ (8,166) $ 38,919
========= ========= ========= ========= ========= ========= ========= =========

See accompanying Notes to Consolidated Financial Statements.

-24-

HOWELL CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows

Year Ended December 31,
2000 1999 1998
---- ---- ----
(In thousands)

OPERATING ACTIVITIES:
Net earnings (loss) from
continuing operations................ $ 21,443 $ 4,945 $ (68,076)
Adjustments for non-cash items:
Depreciation, depletion and
amortization....................... 7,353 6,671 113,870
Deferred income taxes................ 6,348 2,548 (36,351)
Other................................ (86) - (121)
---------- ---------- ----------
Earnings from continuing operations
plus non-cash operating items........ 35,058 14,164 9,322
Changes in components of working
capital from operations:
Increase in trade accounts
receivable......................... (1,537) (1,749) (6,005)
Decrease (increase) in income
tax receivable..................... (705) 5,701 3,486
Decrease (increase) in other
current assets..................... 1,690 (1,863) 3,208
Increase in accounts payable......... 2,350 1,882 6,514
Increase (decrease) in accrued
and other liabilities.............. 1,525 (2,017) 969
---------- ---------- ----------
Cash provided by continuing
operations........................... 38,381 16,118 17,494
Cash provided by (utilized in)
discontinued operations.............. (307) 1,315 2,077
---------- ---------- ----------
Cash provided by operating activities...... 38,074 17,433 19,571
---------- ---------- ----------
INVESTING ACTIVITIES:
Proceeds from the disposition of
property............................. - 28,715 13,333
Additions to property, plant and
equipment............................ (19,467) (6,768) (22,607)
Deposit for Amoco Beaver Creek
acquisition.......................... - - 12,369
Other, net............................. 3,107 2,152 (636)
---------- ---------- ----------
Cash provided by (utilized in)investing
activities............................. (16,360) 24,099 2,459
---------- ---------- ----------
FINANCING ACTIVITIES:
Long-term debt:
Repayments under credit
facilities - net................... (15,000) (42,000) (13,000)
Cash dividends:
Common shareholders.................. (883) (876) (876)
Preferred shareholders............... (2,415) (2,415) (2,415)
Exercise of stock options.............. 25 - 76
---------- ---------- ----------
Cash utilized in financing activities...... (18,273) (45,291) (16,215)
---------- ---------- ----------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS............................ 3,441 (3,759) 5,815
CASH AND CASH EQUIVALENTS, BEGINNING
OF YEAR................................ 2,112 5,871 56
---------- ---------- ----------

CASH AND CASH EQUIVALENTS, END OF YEAR..... $ 5,553 $ 2,112 $ 5,871
========== ========== ==========

See accompanying Notes to Consolidated Financial Statements.

-25-

HOWELL CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Note 1. Summary of Significant Accounting Policies

Principles of Consolidation

The consolidated financial statements include the accounts of Howell
Corporation and its subsidiaries ("Howell" or "Company"). All significant
intercompany accounts and transactions have been eliminated.

Nature of Operations

The Company is engaged in the exploration, production, acquisition and
development of oil and gas properties. These operations are conducted in the
United States.

Property, Depreciation, Depletion and Amortization

The Company follows the full cost method of accounting for its oil and gas
exploration and production activities. Consequently, all costs pertaining to the
acquisition, exploration and development of oil and gas reserves are capitalized
and amortized using the unit-of-production method as the remaining proved oil
and gas reserves are produced. The Company's net investment in oil and gas
properties is subject to a quarterly ceiling limitation calculation that is
based on the present value of future net revenues from estimated production of
proved oil and gas reserves valued at current prices. Costs in excess of the
ceiling limitation are currently charged to expense. Gains or losses upon the
disposition of a property, normally treated as an adjustment to capitalized
costs, are recognized currently in the event of a sale of a significant portion
(normally in excess of 25%) of oil and gas reserves.

The costs allocated to the unproven properties of the Company are excluded
from amortization using the full cost method of accounting described above.
These costs are reviewed periodically for impairment. This impairment will
generally be based on geographic or geologic data. At the time of any
impairment, the related costs will be added to the costs being amortized under
the full cost method of accounting.

Other property and equipment are carried at cost. Depreciation is provided
principally using the straight-line method over the estimated useful lives of
the assets. Maintenance and repairs are charged to expense as incurred, while
renewals and betterments are capitalized.

Income Taxes

The Company utilizes a balance sheet approach in the calculation of the
deferred tax balance at each financial statement date by applying the provisions
of enacted tax laws to measure the deferred tax consequences of the differences
in the tax and book bases of assets and liabilities as they result in net
taxable or deductible amounts in future years. The net taxable or deductible
amounts in future years are adjusted for the effect of utilizing the
carryback/carryforward attributes of any net losses generated and available tax
credits. Deferred tax assets are recognized if it is more likely than not that
the future tax benefit will be realized.

Earnings Per Common Share

Basic earnings per common share amounts are calculated using the average
number of common shares outstanding during each period. Diluted earnings per
share assumes conversion of dilutive convertible preferred stocks and exercise
of all outstanding stock options having exercise prices less than the average
market price of the common stock using the treasury stock method. See Note 11.

Consolidated Statements of Cash Flows

Included in the statements of cash flows are cash equivalents defined as
short-term, highly liquid investments that are readily convertible to cash and
so near to maturity that their value would not change significantly because of
changes in interest rates. The Company made cash payments for interest of
$5,877,000, $7,318,000, and $10,184,000 in 2000, 1999 and 1998, respectively. In
2000, 1999 and 1998, cash payments for income taxes totaled $6,346,000,
$768,000, and $261,000, respectively.

-26-

Disclosures About Fair Value of Financial Instruments

The Company estimates that the carrying amount of its cash and cash
equivalents and accounts receivable and payable and debt as reflected in its
balance sheet approximates fair value.

Stock Based Compensation

The Company continues to account for stock-based compensation using the
intrinsic value method prescribed in Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees". Compensation cost for stock options,
if any, is measured as the excess of the quoted market price of the Company's
stock at the date of grant over the amount an employee must pay to acquire the
stock. Restricted stock is recorded as compensation cost over the requisite
vesting periods based on the market value on the date of grant.

Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting
for Stock-Based Compensation," established accounting and disclosure
requirements using a fair-value-based method of accounting for stock-based
employee compensation plans. The Company has elected to remain on its current
method of accounting as described above, and has adopted the disclosure
requirements of SFAS No. 123.

Environmental Liabilities

The Company provides for the estimated costs of environmental contingencies
when liabilities are likely to occur and reasonable estimates can be made. In
accordance with full cost accounting rules, the Company provides for future
environmental clean-up costs associated with oil and gas activities as a
component of its depreciation, depletion and amortization expense. Ongoing
environmental compliance costs, including maintenance and monitoring costs, are
charged to expense as incurred. See Note 9.

Derivatives

In order to mitigate the effects of future price fluctuations, the Company
has used a limited program of hedging its production. Futures and options
contracts are used as the hedging tools. Changes in the market value of the
hedge transactions are deferred until the gain or loss is recognized on the
hedged transactions.

The Company entered into two hedging programs for 1999. The first program
was a purchase of a put option and a sale of a call option covering 1,750
barrels of oil per day effective April 1, 1999, through December 31, 1999. The
strike prices were $15.00 per barrel for the put option and $17.00 per barrel
for the call option. The second program was a purchase of a put option and a
sale of a call option also covering 1,750 barrels of oil per day effective from
May 1, 1999, through December 31, 1999. The strike prices were $14.50 per barrel
for the put option and $18.80 per barrel for the call option. There was no
premium associated with either of these programs. The strike price of the call
options was exceeded resulting in a reduction of revenues of $3.5 million from
what would have been received had no hedging programs been in place for 1999.
Without the options the average price per barrel of oil for the year ended
December 31, 1999, would have increased from $14.95 to $16.23.

The Company also entered into two hedging programs for the year 2000. The
first program was a purchase of a put option and a sale of a call option
covering 1,700 barrels of oil per day effective January 1, 2000, through
December 31, 2000. The strike prices were $17.25 per barrel for the put option
and $22.00 per barrel for the call option. The second program was a purchase of
a put option and a sale of a call option covering 1,800 barrels of oil per day
effective January 1, 2000, through December 31, 2000. The strike prices were
$18.50 per barrel for the put option and $26.00 per barrel for the call option.
There were no premiums associated with either program. The strike price of the
call options was exceeded resulting in a reduction of revenues of $7.9 million
from what would have been received had no hedging programs been in place for
2000. Without the options the average price per barrel of oil for the year ended
December 31, 2000, would have increased from $25.22 to $28.15.

-27-

The Company adopted Statement of Financial Accounting Standards ("SFAS")
No. 133 effective January 1, 2001. The Company has reviewed all of its contracts
to determine which, if any, contain derivatives. As of January 1, 2001, the
Company has only one derivative contract and it is accounted for and carried at
market value. Therefore, upon adoption of SFAS No. 133, no transition adjustment
will be recorded by the Company.

Revenue Recognition

The Company recognizes oil and gas revenue from its interests in producing
wells as oil and gas is sold from those wells. Oil and gas sold in production
operations is not significantly different from the Company's share of
production.

The Company utilizes the sales method to account for gas production volume
imbalances. Under this method, income is recorded based on the Company's net
revenue interest in production taken for delivery. Management does not believe
that the Company had any material gas imbalances at December 31, 2000 or 1999.

The Company adopted the provisions of Staff Accounting Bulletin ("SAB") No.
101 issued by the Securities and Exchange Commission. The impact of adopting SAB
No. 101 was not material to the Company.

Concentration of Risk

Substantially all of the Company's accounts receivable result from oil and
gas sales and joint interest billings to third parties in the oil and gas
industry. This concentration of customers and joint owners may impact the
Company's overall credit risk in that these entities may be similarly affected
by changes in economic and other conditions.

Use of Estimates

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.

Reclassifications

Certain reclassifications have been made to prior year balances to conform
to the current year presentation.

Note 2. Acquisitions & Dispositions

2000

During the second quarter of 2000, the Company purchased certain interests
in the Salt Creek and Salt Creek South fields for $2.4 million. During the forth
quarter of 2000, the Company purchased certain interests in the South Elk Basin
field for $3.4 million.

The Company sold its interest in Genesis Energy, L.L.C. ("LLC") during the
first quarter of 2000 for $3.0 million. The proceeds from the sale were used to
reduce debt. In addition, the subordinated limited partner units in Genesis
Crude Oil, L.P. ("GCO") were eliminated in December 2000 as a result of a
restructuring of GCO. The Company did not receive any proceeds for the
subordinated units in GCO. No gain or loss was recognized on the sale or on the
elimination of the subordinated units. See Note 5.

1999

On January 4, 1999, the Company received $2.0 million when it sold its
right to participate in the future earnings of its technical fuels and chemical
processing business, which it sold in July 1997. The sale and the results of
operations of the technical fuels and chemical processing business have been
classified as discontinued operations in the accompanying consolidated financial
statements. Discontinued operations includes an after-tax gain of $1.3 million
for the year ended December 31, 1999, as a result of the sale.

-28-

On January 29, 1999, the Company sold its interest in the LaBarge field,
located in southwestern Wyoming, for $15.8 million. The properties consisted of
three Federal units, 17 producing wells and related field facilities. In
addition to natural gas, the properties produced carbon dioxide, helium and
sulfur.

On March 19, 1999, the Company sold its interests in the Grass Creek Unit
in Hot Springs County, Wyoming, and the Pitchfork Unit in Park County, Wyoming
for $12.6 million, net of closing adjustments. The Company owned a 25% working
interest at Pitchfork and various working interests ranging from 13.08% to
43.14% in different producing horizons at Grass Creek.

The properties sold during 1999 were not considered to be integral to the
Company's future. The cumulative proceeds from these events, totaling $29.8
million, were used to reduce debt.
See Note 6.

During 1999, the Company recognized a pre-tax loss of $13.8 million with
respect to its equity interest in Genesis. The loss was a result of the
impairment of the investment in Genesis to market value.

1998

On December 17, 1998, the Company sold its fee mineral estates and royalty
interests comprised of approximately 875,000 acres located in the states of
Alabama, Mississippi and Louisiana for $13.0 million. As additional contingent
consideration, the Company has the right to receive 10% of the net profits
generated from the properties after payout. The net daily production
attributable to these assets was approximately 350 BOE. Proceeds from the sale
were used to retire bank debt. See Note 6.

Effective May 22, 1998, Howell Petroleum Corporation ("HPC"), a wholly
owned subsidiary of Howell Corporation, entered into a Settlement Agreement and
Release with Amoco Production Company ("Amoco") and Snyder Oil Corporation
whereby the parties agreed to settle the litigation that was pending among them.
Under the terms of the settlement, HPC agreed to relinquish its contractual
rights to purchase that portion of the Amoco Wyoming package relating to the
Beaver Creek Unit and the associated facilities. In addition, Amoco agreed to
sell to HPC an approximate 31% working interest in the Higgins Unit located in
Sweetwater County, Wyoming, and a 1.95% overriding royalty interest covering
over 78,000 acres in the Natural Buttes Field located in Uintah County, Utah.
The purchase price for these predominately gas properties was $11 million. HPC's
in-house petroleum engineers estimated total proved reserves of 8.1 BCFE
attributable to these properties. Net daily production from the properties was
approximately 1.8 MMCF of natural gas with a projected reserves-to-production
index of 12 years. The operating results of the assets acquired from Amoco in
this transaction have been included in the Company's Statements of Operations
since May 22, 1998. Pro forma information is not required because of
materiality.

Note 3. Income Taxes

A summary of the provision for income taxes (benefit) from operations
included in the Consolidated Statements of Operations is as follows:

Year Ended December 31,
2000 1999 1998
---- ---- ----
(In thousands)

Current:
Federal............................ $ 5,395 $ - $ -
State.............................. 318 93 (119)
Deferred.............................. 6,348 2,548 (36,351)
---------- ---------- ----------
Income taxes from continuing
operations......................... 12,061 2,641 (36,470)
Income taxes from discontinued
operations......................... - (3,950) 483
---------- ---------- ----------
$ 12,061 $ (1,309) $ (35,987)
========== ========== ==========

-29-

Deferred income taxes are provided on all temporary differences between
financial and taxable income. The approximate tax effects of each significant
type of temporary difference and carryforward were as follows:

Year Ended December 31,
2000 1999
---- ----
(In thousands)

Accrual of costs not deductible for tax.... $ 59 $ 55
Difference between book and tax bases in
investment in Genesis.................. - 1,972
---------- ----------
Net current deferred tax assets........ $ 59 $ 2,027
========== ==========

Accrual of costs not deductible for tax.... $ 196 $ 381
Differences between book and tax bases of
property, plant and equipment.......... (821) 2,541
Alternative minimum tax credit
carryforwards.......................... - 1,265
Valuation allowance........................ - (587)
---------- ----------
Net non-current deferred assets
(liabilities)........................ $ (625) $ 3,600
========== ==========

The following table accounts for the difference between the actual tax
provision and the amounts obtained by applying the applicable statutory U.S.
federal income tax rate to the earnings from continuing operations before income
taxes:

Year Ended December 31,
2000 1999 1998
---- ---- ----
(In thousands)

Provision for income taxes at the
statutory rate......................... $ 11,726 $ 2,548 $ (35,505)
State income taxes......................... 318 93 (119)
Other...................................... 17 - (846)
---------- ---------- ----------
$ 12,061 $ 2,641 $ (36,470)
========== ========== ==========

As of December 31, 2000, the Company had no loss or credit carryforwards
for federal income tax purposes.

Note 4. Discontinued Operations

The following table presents the detail of net income (loss) from
discontinued operations (see Notes 2 and 5) as presented on the Consolidated
Statements of Operations:

Year Ended December 31,
2000 1999 1998
---- ---- ----
(In thousands)

Discontinued operations:
Net earnings (loss) of Genesis (less
applicable income taxes of $(4,702)
and $133 for 1999 and 1998,
respectively)........................ $ - $ (9,129) $ 257
Net earnings from technical fuels (less
applicable income taxes of $752
and $350 for 1999 and 1998,
respectively)........................ - 1,284 266
---------- ---------- ----------
Net earnings (loss) from discontinued
operations............................. $ - $ (7,845) $ 523
========== ========== ==========

Note 5. Investment in Genesis

In 1996, the Company conveyed the assets and business of its crude oil
gathering and marketing operations and pipeline operations to GCO, a Delaware
limited partnership. Howell received cash of approximately $74 million and
991,300 subordinated limited partner units of GCO. Additionally, the Company
received 46% of LLC, a Delaware limited liability company which is the General
Partner of GCO. Howell recognized a gain of approximately $13.8 million.

Howell retained all liabilities arising from the operations, activities and
transactions of the business up through the closing date, including various
environmental-related liabilities. Howell made various representations and
warranties as to itself and the business and has agreed to indemnify GCO for any
breaches thereof. Claims for breaches of such representations and warranties
must be brought before December 3, 2001.

-30-

With only a minority interest in LLC, Howell was not in a position to
substantially influence management of GCO. Accordingly, the Company decided to
dispose of its interests in GCO and LLC. The Company recorded an impairment
charge of $13.5 million (pre-tax) to the carrying value of its investment and
classified its operations as discontinued. During 1999, the investment in
Genesis incurred a pre-tax loss of $13.8 million primarily as a result of the
impairment charge. The loss is reflected in Discontinued Operations. See Note 4.

The Company sold its interest in LLC during the first quarter of 2000 for
$3.0 million. The proceeds from the sale were used to reduce debt. The
subordinated limited partner units were eliminated in December 2000 as a result
of a restructuring of GCO. The Company did not receive any proceeds for its
subordinated units in GCO. No gain or loss was recognized on the sale or on the
elimination of the subordinated units.

Summarized financial information for GCO for the years ended December 31,
1999 and 1998, respectively, is as follows:

1999 1998
---- ----
(In thousands)

Revenues............................. $2,161,012 $2,233,475
Net income........................... $ 2,915 $ 8,819
Current assets....................... $ 274,712 $ 185,211
Property & equipment, net............ $ 90,805 $ 95,083
Total assets......................... $ 380,587 $ 297,168
Current liabilities.................. $ 272,677 $ 183,233
Partners' capital.................... $ 84,110 $ 98,135

Note 6. Debt and Available Credit Facilities

Debt of the Company under its $100 million revolving credit loan agreement,
due in 2002, was $67 million and $82 million at December 31, 2000, and December
31, 1999, respectively.

The Company entered into an Amended and Restated Credit Agreement effective
December 1, 1998 ("Credit Facility"). The Credit Facility is comprised of two
tranches. Tranche A is a revolving credit facility with a termination date no
later than December 15, 2002. The Borrowing Base under Tranche A is $100 million
and is redetermined semi-annually by the bank. Availability can be affected
dramatically based upon the volatility of oil and gas prices. Tranche B was a
term loan which was repaid in March 1999. The Company was required to pay
commitment fees on the unused portion of Tranche A at a rate of 0.375% per annum
while Tranche B was outstanding. After Tranche B was repaid, the commitment fee
became based upon the Borrowing Base Utilization at a rate of 0.25% per annum if
25% or less of the borrowing base is used, 0.30% if more than 25% and less than
or equal to 75% is used, and 0.375% if more than 75% is used.

Outstanding amounts under the Credit Facility bear interest, at the
Company's option, at either the Eurodollar Loan rate ("Libor") per annum, or the
Base Rate (prime), plus the Applicable Margin. The Applicable Margin is
determined by the Borrowing Base Utilization Percentage. As a result, interest
rates range from as low as Libor plus 1.50% or the Base Rate plus .00% if 25% or
less of the borrowing base is used, to as high as Libor plus 2.50% or the Base
Rate plus .75% if greater than 90% of the borrowing base is used.

The Credit Facility is secured by mortgages on substantially all of the
Company's oil and gas properties. The Credit Facility contains certain other
affirmative and negative covenants, including limitations on the ability of the
Company to incur additional debt, sell assets, merge or consolidate, or pay
dividends on its capital in excess of historical levels and a prohibition on
change of control or management. In addition, the Credit Facility requires the
Company to maintain a ratio of current assets plus Tranche A borrowing capacity
to current liabilities, excluding current maturities of long-term debt, of at
least 1.0 to 1.0 and an interest coverage ratio of not less than 1.5 to 1.0 on a
rolling four quarter basis through June 30, 1999, and beginning in the third
quarter of 1999 and thereafter, of not less than 2.5 to 1.0 at the end of any
fiscal quarter.

The Company reduced debt by $15.0 million during 2000 as a result of
increased cash flows and the sale of the Company's interest in Genesis.

-31-

As of December 31, 2000, Tranche A bore interest at 8.75% per annum on
$62.0 million and 9.75% on $5.0 million for the Libor and Base Rate portions,
respectively.

At December 31, 2000, the Company had cash and cash equivalents of $5.6
million, and $32.8 million available to it under the Credit Facility. Should a
decline in the value of the Company's proved reserves occur, the bank could
reduce the borrowing base, thereby causing mandatory payments under the Credit
Facility.

The fair value of the Company's long-term debt at December 31, 2000 and
1999, was estimated to be the same as its carrying value in the balance sheet
since all significant debt obligations bear interest at floating market rates.

Note 7. Shareholders' Equity

Preferred stock

At December 31, 2000 and 1999, the Company had 3,000,000 shares of
preferred stock authorized.

In April 1993, the Company completed a public offering of 690,000 shares of
$3.50 convertible preferred stock. The offering was priced at $50 per share to
yield 7%. The convertible preferred stock is convertible into common stock of
the Company at the option of the holder, at any time, at a conversion rate equal
to, approximately, 3.03 common shares for each preferred share, with fractional
shares paid in cash. The Company has the option to redeem the convertible
preferred stock at a declining premium redemption price beginning in 1996.

Dividends on the convertible preferred stock are to be paid quarterly. Such
dividends accrue and are cumulative. Holders of the preferred stock have no
voting rights except on matters affecting the rights of preferred shareholders.
If at any time the equivalent of six quarterly dividends payable on the
preferred stock are accrued and unpaid, the preferred shareholders will be
entitled to elect two additional directors to the Company's Board of Directors.
The Company is current in the payment of preferred dividends.

Common stock

At December 31, 2000 and 1999, the Company had 50,000,000 shares of common
stock authorized. See Note 11.

Restricted stock

During 2000, 50,000 shares of restricted stock were awarded having a market
value of $5.56 per share as of the award date. The total market value of such
awards has been recorded as deferred compensation and is shown as a separate
component of stockholder's equity and is amortized to expense over the vesting
period.

Employee stock options

The Company maintains nonqualified stock option plans that allow the
Company to grant stock options and other forms of equity-based incentives to the
Company's executives, key employees, and non-employee directors. Stock options
may be granted for periods up to 10 years and are generally subject to vesting
over a period up to four years. At December 31, 2000, 123,450 shares were
available for future option grants.

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Stock option activity for the Company during 2000, 1999 and 1998 was as
follows:

2000 1999 1998
------------------- ------------------- --------------------
Weighted Weighted Weighted
Average Average Average
Number Exercise Number Exercise Number Exercise
of Shares Price of Shares Price of Shares Price
--------- --------- --------- --------- --------- ---------

Stock options outstanding,
Beginning of year......... 534,826 $9.84 948,165 $13.06 936,030 $12.91
Granted................. 205,700 $5.69 173,000 $ 2.81 33,250 $16.50
Exercised............... (3,125) $2.13 - $ - (7,140) $ 8.88
Expired................. (7,000) $9.81 (27,964) $ 8.33 - $ -
Forfeited............... (2,500) $13.13 (558,375) $13.21 (13,975) $13.13
--------- --------- ---------
Stock options outstanding,
end of year........... 727,901 $8.69 534,826 $9.84 948,165 $13.06
========= ========= =========

At December 31, 2000, options were exercisable for 346,451 shares at a
weighted average exercise price of $11.83. The range of exercise prices on
outstanding options at December 31, 2000, was $2.13 to $18.75. The remaining
contractual life of these options was approximately 6.8 years.

The following pro forma summary of the Company's consolidated results of
operations have been prepared as if the fair value based method of accounting
for stock based compensation had been applied:

2000 1999 1998
---- ---- ----

Net earnings (loss)............... $ 21,443,000 $(2,900,000) $(67,553,000)
Fair value adjustment............. (727,093) (742,332) (770,000)
------------- ------------ -------------

Pro forma net earnings (loss)..... $ 20,715,907 $(3,642,332) $(68,323,000)
============= ============ =============
Earnings (loss) per share as
reported - basic................ $ 3.48 $ (0.97) $ (12.79)
============= ============ =============
Pro forma earnings (loss) per
share - basic................... $ 3.34 $ (1.11) $ (12.93)
============= ============ =============
Earnings (loss) per share as
reported - diluted.............. $ 2.75 $ (0.96) $ (12.79)
============= ============ =============
Pro forma earnings (loss) per
share - diluted................. $ 2.66 $ (1.09) $ (12.93)
============= ============ =============

The weighted average fair value of options granted during 2000, 1999 and
1998 was $2.22, $3.12, and $7.94, respectively.

Fair value of the options estimated at the date of grant using a
Black-Scholes option pricing model with the following weighted average
assumptions for 2000, 1999 and 1998.

2000 1999 1998
---- ---- ----

Weighted average expected life: 8.5 years 8.5 years 8.5 years
Volatility factor: 35.79% 51.97% 42.33%
Dividend yield: 2.83% 3.06% 1.00%
Weighted average risk free interest: 6.63% 5.45% 3.64%

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Note 8. Litigation

Howell Pipeline Texas, Inc. v. Exxon Pipeline Company, 125th Judicial
District, District Court of Harris County, Texas, Cause No. 1999 - 32526. On
June 25, 1999, Howell Pipeline Texas, Inc. ("HPTex") sued Exxon Pipeline Company
("Exxon") for failure to pay rent for the use of certain crude oil storage tanks
("Tanks"). Exxon notified HPTex of its intention to cancel a lease on the Tanks
effective March 31, 1996. Exxon stopped paying rent but did not vacate the
premises after notification of the lease cancellation. Exxon continued to store
crude oil and hydrostatic test water for an additional eighteen months. HPTex
claims Exxon owes in excess of $2 million in rent plus interest and attorney's
fees.

Exxon filed a counterclaim against HPTex in which Exxon claims that HPTex
is responsible for the removal costs associated with certain contents of the
Tanks. Exxon claims it "has incurred actual damages in an amount not to exceed
$2 million."

The Company believes that the ultimate resolution will not have a material
adverse impact on its results of operations, financial position or cash flows.

There are various lawsuits and claims arising in the ordinary course of
business against the Company, none of which, in the opinion of management, will
have a material adverse effect on the Company.

Note 9. Commitments and Contingencies

The Company is subject to various contingencies including income taxes,
environmental regulations and laws. Procedures exist within the Company to
monitor compliance and assess the potential exposure of the Company. Management
believes that such exposure is not materially adverse to its financial position,
results of operations or cash flows of the Company.

The Company has indemnified Exxon for certain environmental claims that may
be made in the future attributable to the time when Exxon owned the crude oil
pipelines that the Company acquired from Exxon. In 1996, the crude oil pipelines
were conveyed to GCO. The Company, however, retained liability under the Exxon
indemnification and for certain other potential environmental claims which
management believes will not have a material impact on the financial position,
results of operations or cash flows of the Company. See Note 5.

In 1997, the technical fuels and chemical processing business was sold. The
Company retained liability for certain environmental claims for a period of five
years, which management believes will not have a material impact on the
financial position, results of operations or cash flows of the Company.

The Company has indemnified Amoco for all third party claims other than
those for which Amoco is obligated to indemnify the Company regardless of
whether the claims relate to periods of time prior to or after the closing.
Management does not believe that liabilities arising from this indemnity will
have a material impact on the financial position, results of operations or cash
flows of the Company.

Under the terms of the purchase agreement, Amoco has a right to purchase
certain oil production from the properties acquired in the acquisition.
Beginning March 1, 1998, for a fifteen-year period, Amoco has a right to
purchase up to 4,000 barrels per day of sweet crude oil production net to the
Company's interest from the acquired Salt Creek field. Beginning March 1, 1998,
for a seven-year period, Amoco has a right to purchase 2,000 barrels per day of
sour crude oil production net to the Company's interest from the acquired Elk
Basin field. The prices paid to the Company have fluctuated based on market
conditions.

The Company occupies office and operational facilities and uses equipment
under operating lease arrangements. Expense of these arrangements amounted to
$0.5 million in 2000 and 1999 and $0.4 million in 1998. At December 31, 2000,
long term commitments for lease of facilities and equipment totaled
approximately $2.9 million, consisting of $0.7 million for each year 2001
through 2004, and $0.2 million thereafter.

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Note 10. Determination of Earnings per Incremental Share

The following tables present the reconciliation of the numerators and
denominators in calculating diluted earnings per share ("EPS") from continuing
operations in accordance with Statement of Financial Accounting Standards No.
128.

2000

Increase in Earnings per
Increase in Number of Incremental
Income Shares Share
------------ ------------ ------------

Options and restricted stock................ - 221,845 -
Dividends on convertible preferred stock.... $ 2,415,000 2,090,909 $1.16

Computation of Diluted Earnings per Share

Income
Available from
Continuing Common
Operations Shares Per Share
------------ ------------ ------------

$19,028,000 5,473,331 $3.48
Common stock options and restricted stock.. - 221,845 -
------------ ------------ ------------
19,028,000 5,695,176 3.34 Dilutive

Dividends on convertible preferred stock... 2,415,000 2,090,909 -
------------ ------------ ------------
$21,443,000 7,786,085 $2.75 Dilutive
============ ============ ============

Note: Because diluted EPS from continuing operations decreases from $3.48
to $2.75 when common stock options, restricted stock and convertible preferred
shares are included in the computation, those common stock options, restricted
stock and convertible preferred shares are dilutive. Therefore, diluted EPS from
continuing operations is reported as $2.75.

1999

Increase in Earnings per
Increase in Number of Incremental
Income Shares Share
------------ ------------ ------------

Options and restricted stock................ - 81,830 -
Dividends on convertible preferred stock.... $ 2,415,000 2,090,909 $1.16

Computation of Diluted Earnings per Share

Income
Available from
Continuing Common
Operations Shares Per Share
------------ ------------ ------------

$ 2,530,000 5,471,782 $0.46
Common stock options....................... - 81,830 -
------------ ------------ ------------
2,530,000 5,553,612 0.46 Dilutive

Dividends on convertible preferred stock... 2,415,000 2,090,909 -
------------ ------------ ------------
$ 4,945,000 7,644,521 $0.65 Antidilutive
============ ============ ============

Note: Because diluted EPS from continuing operations increases from $0.46
to $0.65 when convertible preferred shares are included in the computation,
those convertible preferred shares are antidilutive and are ignored in the
computation of diluted EPS from continuing operations. Therefore, diluted EPS
from continuing operations is reported as $0.46.

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1998

Increase in Earnings per
Increase in Number of Incremental
Income Shares Share
------------ ------------ ------------

Options and restricted stock................ - 42,456 -
Dividends on convertible preferred stock.... $ 2,415,000 2,090,909 $1.16

Computation of Diluted Earnings per Share

Loss from
Continuing Common
Operations Shares Per Share
------------- ------------ ------------

$(70,491,000) 5,470,021 $(12.89)
Common stock options....................... - 42,456 -
------------- ------------ ------------
(70,491,000) 5,512,477 (12.79) Antidilutive

Dividends on convertible preferred stock... 2,415,000 2,090,909 -
------------- ------------ ------------
$(68,076,000) 7,603,386 $ (8.95) Antidilutive
============= ============ ============

Note: Because diluted EPS from continuing operations increases from
$(12.89) to $(12.79) when common stock options are included in the computation
and because diluted EPS increases from $(12.79) to $(8.95) when convertible
preferred shares are included in the computation, those common stock options and
convertible preferred shares are antidilutive and are ignored in the computation
of diluted EPS from continuing operations. Therefore, diluted EPS from
continuing operations is reported as $(12.89).

Note 11. Subsequent Event

On January 30, 2001, the Company declared a 10% stock dividend to be paid
on March 22, 2001, for common shareholders of record on March 8, 2001. The
following table reflects pro forma earnings per common share for the periods
presented as though the stock dividend had been paid on December 31, 2000.

Year Ended December 31,
2000 1999 1998
---- ---- ----
(In thousands)

Basic earnings (loss) per common share:
Continuing operations.................. $ 3.16 $ 0.42 $ (11.72)
Discontinued operations................ - (1.30) 0.09
---------- ---------- ----------
Net earnings (loss) per common share
- basic.............................. $ 3.16 $ (0.88) $ (11.63)
========== ========== ==========

Weighted average shares outstanding -
basic.................................. 6,021 6,019 6,017
========== ========== ==========

Diluted earnings (loss) per common share:
Continuing operations.................. $ 2.50 $ 0.41 $ (11.72)
Discontinued operations................ - (1.28) 0.09
---------- ---------- ----------
Net earnings (loss) per common share
- diluted............................ $ 2.50 $ (0.87) $ (11.63)
========== ========== ==========

Weighted average shares outstanding -
diluted................................ 8,565 6,109 6,017
========== ========== ==========

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HOWELL CORPORATION AND SUBSIDIARIES

Form 10-K
Index to Exhibits

Exhibits not incorporated herein by reference to a prior filing are designated
by an asterisk (*) and are filed herewith. Exhibits designated by two asterisks
(**) are incorporated herein by reference to the Company's Form S-1 Registration
Statement, registration No. 33-59338, filed on March 10, 1993.

Exhibit
Number Description

2.1 Agreement and Plan of Merger dated August 22, 1997 by and among the
Company, Howell Acquisition Corp. and Voyager Energy Corp.

2.2 Asset Purchase Agreement dated July 31, 1997 by and among Howell
Hydrocarbons & Chemicals, Inc., the Company and Specified Fuels &
Chemicals, L.L.C. - incorporated by reference to Exhibit 2.1 of the
Company's Current Report on Form 8-K dated August 11, 1997.

2.3 Purchase and Sale Agreement dated November 20, 1997, between Howell
Petroleum Corporation and Amoco Production Company-incorporated by
reference to Exhibit 2 of the Company's Current Report on Form 8-K dated
January 2, 1998.

2.4 Sale Agreement dated March 18, 1999 between Howell Petroleum Corporation
and Marathon Oil Company incorporated by reference to Exhibit 99.1 of
the Company's Current Report on Form 8-K dated March 30, 1999.

3.1 * Certificate of Incorporation, as amended, of the Company.

3.2 ** By-laws of the Company.

10.1 ** Howell Corporation 1988 Stock Option Plan.

10.2 ** First Amendment to the Howell Corporation 1988 Stock Option Plan.

10.3 ** Second Amendment to the Howell Corporation 1988 Stock Option Plan.

10.5 Third Amendment to the Howell Corporation 1998 Stock Option Plan (filed
as an Exhibit to the Company's Report on Form 10-Q for the quarterly
period ended June 30, 1994).

10.6 ** Form of Indemnity Agreement by and between the Company and each of its
directors and executive officers.

10.7 Amended and Restated Credit Agreement dated December 1, 1998 by and
among Howell Petroleum Corporation as Borrower, Bank of Montreal as
Agent, Nationsbank, N.A. as Syndication Agent, Union Bank of California,
N.A., as Documentation Agent and the lenders signatory thereto.

10.8 ** United States Department of the Interior Bureau of Land Management Oil
and Gas Lease of Submerged Lands under the Outer Continental Shelf
Lands Act by and between the United States of America and Howell
Petroleum Corporation effective as of December 1, 1981.

10.9 ** United States Department of the Interior Minerals Management Service Oil
and Gas Lease of Submerged Lands under the Outer Continental Shelf
Lands Act by and between the United States of America and Total
Petroleum, Inc., effective as of July 1, 1983.

10.10 Lease Agreement by and between Texas Commerce Bank National Association
and Howell Corporation dated as of December 13, 1993 (filed as an
exhibit to the Company's Report on Form 10-K for the year ended December
31, 1993).

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Exhibit
Number Description

10.11 First Amendment to Lease Agreement by and between Texas Commerce Bank
National Association and Howell Corporation effective as of October 5,
1995 (filed as an exhibit to the Company's Report on Form 10-K for the
year ended December 31, 1995).

10.12 Second Amendment to Lease Agreement by and between Texas Commerce Bank
National Association and Howell Corporation effective as of November 21,
1995 (filed as an exhibit to the Company's Report on Form 10-K for the
year ended December 31, 1995).

10.13 Howell Corporation 1997 Nonqualified Stock Option Plan incorporated by
reference to Exhibit 10.1 of the Company's Registration Statement on
Form S-8 dated June 12, 1997.

10.14 Consent Statement to approve the acquisition of Voyager Energy Corp. and
approve the increase of authorized Common Stock shares.

10.15 Howell Corporation Omnibus Stock Awards and Incentive Plan -
incorporated by reference to Exhibit 10.3 of the Company's Registration
Statement on Form S-8 dated June
23, 2000.

10.16 Howell Corporation Nonqualified Stock Option Plan for Non-Employee
Directors - incorporated by reference to Exhibit 10.1 of the Company's
Registration Statement on Form S-8 dated June 23, 2000.

21 * Subsidiaries of the Company.

23 * Consent of Deloitte & Touche LLP.

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EXHIBIT 21

HOWELL CORPORATION

Parent and Subsidiaries

December 31, 2000

The following is a list of all significant operating subsidiaries of the
Company on December 31, 2000. Each of the subsidiaries is included in the
Company's Consolidated Financial Statements.

Percentage of
Voting Securities
Jurisdiction of Held by
Incorporation Immediate Parent
------------- ----------------
Howell Corporation ..................... Delaware -

Howell Petroleum Corporation............ Delaware 100%

*Howell Crude Oil Company............... Delaware 100%

*Howell Hydrocarbons & Chemicals, Inc... Delaware 100%

--------------------------
* Discontinued Operations

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EXHIBIT 23

HOWELL CORPORATION
Independent Auditors' Consent

To Howell Corporation:

We consent to the incorporation by reference in Registration Statement
Nos. 333-29089 and 333-40022 of Howell Corporation on Form S-8 of our report
dated February 26, 2001, appearing in the Annual Report on Form 10-K of Howell
Corporation for the year
ended December 31, 2000.

DELOITTE & TOUCHE LLP

Houston, Texas
February 26, 2001

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