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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, 1998
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 Securities
Series A, $1 par value 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 March 1, 1999 was
approximately $11.3 million. The aggregate market value of the shares held by
nonaffiliates on that date was approximately $7.9 million. As of March 1, 1999,
there were 5,471,782 common shares outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
Howell Corporation proxy statement to be filed in connection with the 1999
Annual Shareholders' Meeting (to the extent set forth in Part III of this Form
10-K).
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HOWELL CORPORATION
1998 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
PAGE
----
PART I
ITEM 1. BUSINESS............................................................................. 1
ITEM 2. PROPERTIES........................................................................... 4
ITEM 3. LEGAL PROCEEDINGS.................................................................... 11
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.................................. 11
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS............. 12
ITEM 6. SELECTED FINANCIAL DATA.............................................................. 12
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS....................................................................... 13
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK............................ 19
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.......................................... 19
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE....................................................................... 19
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT................................... 20
ITEM 11. EXECUTIVE COMPENSATION............................................................... 20
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT....................... 20
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS....................................... 21
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K..................... 21
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"), including 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. A
description of the Company's principal business segment and the market in
which it operates is summarized below. For information relating to industry
segments, reference is made to "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the Consolidated Financial
Statements and Notes thereto.
RECENT EVENTS
On January 4, 1999, the Company sold its right to participate in the
future earnings of Specified Fuels & Chemicals, Inc. ("SFC") for $2.0
million. SFC acquired the Company's research and reference fuel business in
July 1997.
On January 29, 1999, the Company sold its interest in the LaBarge field
for $15.8 million.
On March 16, 1999, the Company received a refund of $5.7 million for
Federal taxes paid in prior years.
On March 19, 1999, the Company signed an agreement to sell its interest
in the Pitchfork and Grass Creek Wyoming fields for $12.4 million.
The cumulative proceeds from these events, totaling $35.9 million, have
been or will be used to reduce bank debt. By utilizing this $35.9 million and
part of the $5.9 million cash and cash equivalents available at December 31,
1998, the Company will be able to pay off Tranche B and reduce Tranche A to
approximately $84 million. See Item 2. "Properties" and see Note 6 of Notes
to Consolidated Financial Statements.
OIL AND GAS EXPLORATION AND PRODUCTION
The Company's oil and gas exploration and production activities are
conducted entirely within the United States 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,
1998, the Company's estimated proved reserves were 29.9 million barrels of
oil and plant liquids and 78.8 billion cubic feet ("BCF") of gas. The core
area for the Company includes the Salt Creek, Elk Basin and Grass Creek
fields discussed below. The Company's major producing properties include Salt
Creek, Elk Basin, North Frisco City, Main Pass 64, Grass Creek and LaBarge
fields. These six major fields represent 36.0 million barrels of oil
equivalent ("MMBOE"), or 84% 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 108 employees.
Effective May 22, 1998, HPC entered into a Settlement Agreement and
Release with Amoco Production Company ("Amoco") and Snyder Oil Corporation
("SOCO") whereby the parties agreed to settle the pending litigation between
them styled: SNYDER OIL CORPORATION, PLAINTIFF V. AMOCO PRODUCTION COMPANY
AND HOWELL PETROLEUM CORPORATION, DEFENDANTS in the District Court, Ninth
Judicial District, Civil Action No. 29861, Fremont County, Wyoming. Under the
terms of the settlement, HPC agreed to relinquish its contractual rights to
purchase that portion of the Amoco Wyoming package (the "Package") relating
to the Beaver Creek Unit and the associated facilities. In addition, Amoco
agreed to sell the Company 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 estimate total
proved reserves attributable to these properties are 8.1 BCFE. Net daily
production from the properties was approximately 1.8 million cubic feet
("MMCF") of natural gas with a projected reserve-to-production index of 12
years. This settlement completed the Company's acquisition of properties from
Amoco ("the Acquisition"). The Company purchased proved reserves of 39.1
MMBOE for $126.4 million which is an acquisition cost of $3.23 per barrel of
oil equivalent. At year-end 1997, HPC had previously announced the closing on
$115.4 million of this acquisition.
1
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, the actions of the Organization
of Petroleum Exporting Countries, domestic and foreign governmental
regulations, political stability in the Middle East and other petroleum
producing areas, the foreign and domestic supply of oil and natural gas, the
price of foreign imports, the 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.
TECHNICAL FUELS AND CHEMICAL PROCESSING
On July 31, 1997, Howell Hydrocarbons & Chemicals, Inc. ("Seller"), a
wholly-owned subsidiary of the Company, sold substantially all of the assets
of its research and reference fuels and custom chemical manufacturing
business to SFC.
The assets purchased by SFC included the fee property in Channelview,
Texas, on which Seller's refinery was located, all refining facilities
located on the fee property and all related personal property, all
inventories of finished products, work in process, raw materials and supplies
related to the business, substantially all of the accounts receivable on the
closing date, all transferable intellectual property used primarily in the
business and all of Seller's rights under various contracts and leases
related to the business. In connection with the transaction, (a) SFC received
a license to use the name "Howell Hydrocarbons & Chemicals" for a five-year
period after closing and assumed certain obligations of Seller and the
Company, and (b) the Company agreed not to engage (directly or through
affiliates) in any competing business for a five-year period after the
closing.
The sale resulted in a pre-tax gain of $0.4 million and the proceeds
of the sale were used by the Company to reduce its outstanding indebtedness.
The sale completes the divestiture by the Company of all of its
non-exploration and production businesses. In connection with the sale, the
Company has given and received environmental and other indemnities. Should
claims be made against the Company based on these indemnities, the company
could be required to perform its obligations thereunder.
In consideration for the assets sold to SFC, Seller and the Company
received a payment of $19.8 million in cash, which included $14.8 million for
the property, plant, equipment and related items, and $5.0 million in payment
of working capital items. Seller was entitled to receive an additional
payment equal to 55% of the amount by which SFC's "EBITDA" for each
twelve-month period ending June 30, 1998, 1999, 2000, 2001 and 2002 exceeds
the "Minimum EBITDA" (as defined in the Agreement). The Minimum EBITDA
amounts for those years were $5.0 million, $5.175 million, $5.35 million,
$5.525 million and $5.7 million, respectively. During August 1998, the
Company received the first excess EBITDA payment of $0.7 million. SFC was
entitled to repurchase Seller's rights to these additional payments at any
time after June 30, 1998; generally by paying to Seller an amount equal to
the greater of (a) the product obtained by multiplying the EBITDA payment
amount for the immediately preceding twelve-month period by the number of
twelve-month periods remaining, or (b) an amount fixed by the agreement,
which was initially set at $5.7 million if the repurchase occurred during the
twelve-month period ending on June 30, 1999, and which declines for each
twelve-month period thereafter to $1.2 million if the repurchase occurred
during the twelve-month period ending June 30, 2002. On January 4, 1999, SFC
and Seller agreed that the amount fixed by the Agreement was not reasonable
in light of current performance; therefore, Seller agreed to reduce the
excess EBITDA payment to $2.0 million which SFC agreed to purchase.
2
INVESTMENT IN GENESIS
On December 1, 1996, Genesis Crude Oil, L.P., a Delaware limited
partnership ("Buyer"), Genesis Energy, L.P., a Delaware limited partnership
("MLP") and Genesis Energy, L.L.C., a Delaware limited liability company
("LLC"), (collectively referred to hereinafter as "Genesis"), entered into a
Purchase & Sale and Contribution & Conveyance Agreement ("Agreement") with
Howell Corporation and certain of its subsidiaries ("Howell") and Basis
Petroleum, Inc. ("Basis"), a subsidiary of Salomon Inc. ("Salomon"). Pursuant
to the Agreement, Howell agreed to sell and convey certain of its assets to
Buyer. These assets consisted of the crude oil gathering and marketing
operations and pipeline operations of Howell ("Business").
Buyer was formed by MLP and LLC to acquire the Business from Howell
and similar assets from Basis. MLP is owned 98% by limited partners and 2% by
LLC, which is the general partner. LLC is owned 46% by Howell and 54% by
Basis. As a result of this transaction, Howell owns a subordinated limited
partner interest in Buyer of 9.01%, a direct general partner interest in
Buyer of 0.18% and a general partner interest through MLP of 0.74% of Buyer.
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. The
Company's other business segments also operate under strict governmental
regulations.
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, and violators are subject to
civil and criminal penalties, including fines, injunctions or both. Failure
to obtain or maintain a required permit may also result in the imposition of
civil and criminal penalties. Third parties may have the right to sue to
enforce compliance. The cost of environmental compliance has not had a
materially 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
3
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, 1998, the Company had 126 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, 401(K) Plan and
accidental death and dismemberment insurance plans for its employees.
Historically, the Company provided its employees with a Company stock
purchase plan, a thrift plan and a Simplified Employee Pension Plan. During
1998, the Company replaced these plans with a 401(K) plan with profit
sharing. The company contributed $135,721 in employee matching funds during
1998.
ITEM 2. PROPERTIES
A. SUPPLEMENTARY OIL AND GAS PRODUCING INFORMATION
RECENT EVENTS
The proposed sale of the Pitchfork and Grass Creek, Wyoming fields and
the completed sale of LaBarge, Wyoming fields for a total of $28.2 million
represent 7.0 million barrels of oil equivalent ("MMBOE") out of the 43.1
MMBOE of the Company's proved oil and gas reserves at December 31, 1998 and
approximately 2.2 MBOE per day of the Company's 11.9 MBOE 1998 daily
production. These transactions also represent 460 gross and 135 net oil wells,
21 gross and 9 net gas wells, 10,409 gross and 2,508 net developed acres, and
320 gross and 320 net undeveloped acres.
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, 1998, 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........................................................... 2,615 724
Gas wells........................................................... 601 47
----- ---
Total ....................................................... 3,216 771
----- ---
----- ---
- -----------------
(1) One or more completions in the same well are counted as one well.
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, except for the reserves purchased from Amoco, at December
31, 1998, 1997, and 1996, were reviewed by independent petroleum consultants,
H. J. Gruy and Associates, Inc. The December 31, 1998 and 1997 reserves,
associated with the properties acquired from Amoco, were reviewed by
independent petroleum consultants, Ryder Scott & Associates. The estimates
for 1995 were reviewed by L. A. Martin & Associates, Inc. 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.
4
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
OIL GAS
(BBLs) (MCF)
------- -----
As of December 31, 1995...................................... 8,600,036 60,580,800
Revisions of previous estimates.............................. 459,820 1,007,250
Extensions, discoveries & other additions.................... 122,081 2,424,077
Production................................................... (1,207,906) (3,273,257)
Sales of minerals in place................................... (14,858) (484,520)
----------- ----------
As of December 31, 1996...................................... 7,959,173 60,254,350
Revisions of previous estimates.............................. 623,774 (5,737,208)
Extensions, discoveries & other additions.................... 420,500 4,725,000
Purchases of minerals in place............................... 34,413,669 27,702,395
Production................................................... (1,246,596) (3,311,197)
----------- ----------
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
----------- ----------
----------- ----------
Proved developed reserves:
December 31, 1995............................................ 7,662,263 60,125,223
----------- ----------
----------- ----------
December 31, 1996............................................ 6,995,835 58,444,115
----------- ----------
----------- ----------
December 31, 1997............................................ 40,711,561 81,709,974
----------- ----------
----------- ----------
December 31, 1998............................................ 26,701,736 75,756,389
----------- ----------
----------- ----------
Total proved reserves at year-end 1998 were 43,072 MBOE compared to
56,109 MBOE at year-end 1997. The change was related almost entirely to
downward revisions associated with lower oil and gas prices. The price
sensitivity of the Company's reserve base is illustrated by the fact that if
year-end 1998 reserves were calculated using year-end 1997 pricing, total
proved reserves would have remained basically unchanged at 1997 reserve levels.
Proved oil reserves at December 31, 1998, include 1.4 million
barrels of natural gas liquids ("NGL").
In addition to the oil and gas reserves shown above, the Company,
through its participation in the LaBarge Project in southwestern Wyoming, had
proved carbon dioxide reserves of 57,140 MMCF and proved helium reserves of
2,570 MMCF at December 31, 1998. The LaBarge Project was sold in January 1999.
OIL AND GAS LEASEHOLDS
The following table sets forth the Company's ownership interest in
leaseholds as of December 31, 1998. 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.
5
DEVELOPED(1) UNDEVELOPED
----------------------- --------------------
GROSS NET GROSS NET
ACRES ACRES ACRES ACRES
----- ----- ----- -----
Alabama............................................. 6,543 2,317 3,735 1,283
Louisiana........................................... 2,544 796 567 145
Mississippi......................................... 3,015 946 8,505 2,371
North Dakota........................................ 7,440 1,710 1,040 130
Texas............................................... 14,649 5,845 8,450 2,998
Wyoming............................................. 47,200 21,631 28,524 12,160
All other states combined........................... 3,694 720 3,614 1,844
Offshore............................................ 7,025 5,589 - -
------ ------ ------ ------
Total........................................... 92,110 39,554 54,435 20,931
------ ------ ------ ------
------ ------ ------ ------
(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 WELLS DRY HOLES PRODUCTIVE WELLS DRY HOLES
YEAR GROSS NET GROSS NET GROSS NET GROSS NET
---- ----- --- ----- --- ----- --- ----- ---
1998 1.0 .62 1.0 .08 18.0 4.52 - -
1997 4.0 .89 1.0 .25 1.0 .10 1.0 .6
1996 1.0 .16 4.0 1.45 - - - -
The table above reflects only the drilling activity in which the
Company had a working interest participation. In addition, in 1998, 1997 and
1996, 5, 24 and 22 gross productive wells, respectively, were drilled on the
Company's fee mineral interest acreage, which was sold in December 1998.
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:
1998 1997 1996
---- ---- ----
Average sales prices:
Oil and NGL (per BBL) includes hedging................................. $11.26 $17.15 $17.52
Natural gas (per MCF).................................................. $ 1.86 $ 2.33 $ 2.06
Production (lifting) costs (per equivalent barrel of production)............ $ 5.95 $ 5.92 $ 5.23
Amortization (per equivalent barrel of production).......................... $ 2.68 $ 5.18 $ 5.37
Impairment of oil & gas properties (per equivalent barrel of production).... $23.66 $ - $ -
Natural gas production is converted to barrels using its estimated
energy equivalent of six MCF per barrel.
6
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, 1998 DECEMBER 31, 1997
----------------- -----------------
(In thousands)
Capitalized Costs:
Oil and gas producing properties, all being amortized .... $385,048 $371,975
Unproven properties ...................................... 43,263 41,017
Fee mineral interests, unproven .......................... - 18,123
-------- --------
Total .................................................. $428,311 $431,115
-------- --------
-------- --------
Accumulated depreciation, depletion and amortization
(includes impairment of oil & gas properties) .......... $307,118 $205,199
-------- --------
-------- --------
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,
-----------------------------------------
1998 1997 1996
---- ---- ----
(In thousands)
Property acquisition:
Unproved properties ....... $ 3,627 $ 41,904 $ 1,665
Proved properties ......... 7,614 82,737 -
Exploration ................. 3,460 5,994 3,526
Development ................. 7,626 1,534 384
-------- -------- --------
$ 22,327 $132,169 $ 5,575
-------- -------- --------
-------- -------- --------
In 1998, 1997 and 1996, $18,123,000, $57,000 and $8,000 of costs of
unproved fee mineral interests, respectively, were transferred to the
full-cost pool, representing the costs of fee mineral interests that were
drilled and evaluated during the periods. The 1998 amount also represents the
sale of the fee mineral interests on December 17, 1998. These transfers of
costs are not reflected in the table above. See Note 3 of Notes to the
Consolidated Financial Statement.
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 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,
--------------------------------------
1998 1997 1996
---- ---- ----
(In thousands)
Revenues.................................................. $ 48,538 $ 29,089 $ 28,162
Production (lifting) costs................................ 25,703 10,646 9,174
Depreciation, depletion and amortization.................. 11,589 9,316 9,416
Impairment of oil & gas properties........................ 102,167 - -
-------- -------- --------
(90,921) 9,127 9,572
Income tax (benefit) expense.............................. (30,913) 2,523 3,318
-------- -------- --------
Results of operations (excluding corporate overhead
and interest cost) ................................... $(60,008) $ 6,604 $ 6,254
-------- -------- --------
-------- -------- --------
7
Included in the 1998, 1997 and 1996, amounts above are $1,314,000,
$2,005,000, and $2,301,000 of revenues and $121,000, $174,000, and $181,000
of production costs, respectively, 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 1998 and 1997.
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.
(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, DECEMBER 31,
1998 1997
------------ ------------
(In thousands)
Future cash inflows ............................................................... $388,355 $792,393
Future production costs ........................................................... 249,067 490,059
Future development costs .......................................................... 17,597 16,423
Future income tax expenses ........................................................ 0 42,000
-------- --------
Future net cash flows ............................................................. 121,691 243,911
10% annual discount for estimated timing of cash flows ............................ 60,363 104,336
-------- --------
Standardized measure of discounted future net cash flows relating to proved
oil and gas reserves .......................................................... $ 61,328 $139,575
-------- --------
-------- --------
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 declines in both natural gas and crude oil prices, the reserves may
be subject to material future revisions.
8
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,
---------------------------------------------
1998 1997 1996
---- ---- ----
(In thousands)
Sales and transfers, net of production costs...................... $ (22,836) $ (18,443) $ (18,988)
Net changes in prices and production costs........................ (56,084) (113,015) 58,036
Extensions and discoveries, net of future production and
development costs............................................... 12,775 9,950 5,382
Purchases of minerals in place.................................... 6,586 157,709 -
Sales of minerals in place........................................ 1,425 - (494)
Previously estimated development costs incurred during the
period.......................................................... (30) (178) -
Revisions of quantity estimates................................... (20,512) (1,006) 4,844
Accretion of discount............................................. 13,958 10,406 8,215
Net change in income taxes........................................ 21,017 7,190 (13,930)
Changes in production rates (timing) and other.................... (34,546) (17,093) (21,157)
--------- ---------- ----------
Net change.............................................. $ (78,247) $ 35,520 $ 21,908
--------- ---------- ----------
--------- ---------- ----------
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,
1998, the Company's estimated proved reserves were 29.9 MMBO and plant
liquids and 78.8 BCF of gas. The Company's major producing properties include
Salt Creek, Elk Basin, North Frisco City, Main Pass 64, Grass Creek and
LaBarge fields. These six major fields represent 36.0 MMBOE, or 84% 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.
DESCRIPTION OF SIGNIFICANT PROPERTIES
SALT CREEK. The Company owns and operates the Salt Creek Field in the
Powder River Basin in Natrona County, Wyoming. The Company's working interest
varies from 65% 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 655 producing wells and 588
injection wells located in the LOU on a flood pattern of approximately five
acre well spacing. As of December 31, 1998, the field was producing a net of
approximately 3,050 barrels per day of sweet crude oil, 275 barrels per day
of sour crude and 50 barrels per day of NGLs.
The most prolific producing formation in the LOU is the Wall Creek
2 at a depth of 1,500 feet. It has produced approximately 386 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 believes that the application of horizontal drilling to target
unswept intervals within several of the reservoirs may have positive
production and reserve potential and plans to implement a pilot program in
the future to test the application. In addition, the potential for enhanced
oil recovery through CO2 flooding is under consideration for the Wall Creek 1
and Wall Creek 2 formations. Another opportunity exists in the shallow shale
formations that exist above the Wall Creek 1. The shale was developed in the
1920s and produced over 2 MMBO in the LOU. The Company believes the oil
resided in the extensive vertical fractures and fault systems prevalent in
the shale and the reserves were not completely depleted in all areas of the
field. The Company is investigating the application of horizontal drilling to
connect these fracture systems and faults to a producing wellbore.
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, 1998, the field was producing a net of 1,532
barrels per day of oil and 226 barrels per day of NGLs from 215 producing
wells.
9
The Embar-Tensleep reservoir was an inert gas injection pressure
maintenance project until injection into the gas cap was discontinued in the
1970's. The company successfully re-established the inert gas injection to
increase reservoir pressure in 1998, which is anticipated to have a positive
impact on future production rates. In addition, the Company plans to
supplement this gas cap injection with horizontal and vertical producing
wells located in the oil rim on the edge of the structure, which could
improve the sweep efficiency and ultimate recovery. The shallow Frontier
formation, at a depth of 1,700 feet, holds a significant number of potential
low cost drilling opportunities to extend the production in this field
down-structure to the lowest known oil-water contact. Since 1986, 32 Frontier
wells have been successfully drilled or recompleted within the Frontier Unit.
These wells cost approximately $75,000 each, typically produce at rates of 30
barrels per day of oil and have cumulative recoveries up to 60 thousand
barrels each. The Company has identified numerous potential drilling
locations within the unit and outside the unit on Company leasehold. The
prolific Madison carbonate, at a depth of 5,000', has the potential for
horizontal drilling due to its heterogeneous nature. In addition, this
waterflooded reservoir has the potential to downspace the 72 producers from
the current 40 acres per well to 20 acres per well based on the successful
infill drilling program over the last 10 years.
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 exploitation, 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 17 years has totaled 11.3 MMBO and 26.6 BCF of natural gas. As of
December 31, 1998, daily net production was approximately 706 barrels of oil.
In 1998, after an internal comprehensive reservoir study indicated that the
waterflood pushed the oil column into the original gas cap, the Company
successfully completed a sidetrack operation to confirm and exploit these
previously unrecoverable attic oil reserves. As a result of the drilling
activity, the Company added net reserves of 1.8 MMBOE and has identified an
additional 7 recompletions in the 7,300' Sand Unit.
NORTH FRISCO CITY. The North Frisco City field, located in Monroe
County, Alabama, was discovered in March 1991. Production is predominantly
from the Frisco City sand member of the Haynesville formation at a depth of
about 12,000 feet. Based on seismic data, ten successful development wells
were completed from 1992 though 1994. In 1994, the field was unitized. The
Company currently has a 24.1% working interest in nine gross producing wells
in the unit. As of December 31, 1998, daily net production from this field
was 690 barrels of oil, 173 barrels of natural gas liquids and 765 thousand
cubic feet of natural gas. The Company also owns a royalty interest in this
field.
GRASS CREEK. The Grass Creek Unit, located in the Bighorn Basin in
Hot Springs County, Wyoming, is operated by Marathon Oil Company. Oil was
discovered in the Frontier formation in 1914. The Company's working interest
within the Grass Creek field differs by horizon, varying from 13% in the
Curtis to 37.65% in the Darwin. The company owns a 31% working interest in
the primary horizons, the Phosphoria and Tensleep, which are mature
waterfloods. Current net production is approximately 965 barrels of oil per
day. In February 1996, a 3-D seismic survey was acquired over the field.
Based upon that data, the Company has identified numerous potential drilling
opportunities. In 1998, the operator successfully completed three deepenings
and one drill well in the Phosphoria-Tensleep, confirming these
opportunities. Grass Creek field is also a candidate for enhanced oil
recovery using CO2. On March 19, 1999, the Company entered into an agreement
to sell its interest in Grass Creek and other properties for $12.4 million.
LABARGE PROJECT. The LaBarge Project, operated by Exxon Company USA,
is located in southwestern Wyoming. The Company owns a 4.8% working interest
in the Fogarty Creek Unit. The Company has an interest in 12 gross wells
producing from depths between 14,500 feet to 17,000 feet in the Fogarty Creek
Unit. The Company has significant production and reserves of carbon dioxide
and helium and small amounts of production and reserves of sulfur from its
interest in the LaBarge Project, which are not included in its production and
proved reserves of oil and natural gas discussed elsewhere in Item 2. The
following table presents information on the Company's net production of
natural gas, carbon dioxide and helium attributable to the Company's interest
in the LaBarge Project. The natural gas data from the LaBarge Project is also
included in the other tables set forth elsewhere in Item 2. On January 29,
1999, the Company sold all of its right, title, and interest in and to the
LaBarge Project for $15.75 million.
10
LABARGE PRODUCTION
YEAR ENDED DECEMBER 31,
----------------------------------------
1998 1997 1996
---- ---- ----
(IN THOUSANDS, EXCEPT UNIT PRICES)
Production data (net):
Natural gas (MCF) ............... 1,208 1,291 1,222
Carbon dioxide (MCF)(1) ......... 764 901 603
Helium (MCF) .................... 38 38 27
Average sales price per unit:
Natural gas (MCF) ............... $ 1.81 $ 2.11 $ 1.71
Carbon dioxide (MCF)............. $ 0.28 $ 0.28 $ 0.30
Helium (MCF) .................... $35.33 $34.80 $43.68
Financial data:
Revenues ........................ $3,871 $4,472 $3,558
Processing costs ................ 3,085 3,556 2,825
------ ------ ------
Net cash flows .................. $ 786 $ 916 $ 733
------ ------ ------
------ ------ ------
- -----------------
(1) Because of a lack of market, approximately 80%, 78% and 81% of the
volume produced in 1998, 1997 and 1996, respectively, was vented and not
sold. Amounts included in the table reflect only volumes sold.
B. OTHER PROPERTIES
In addition to the oil and gas properties described above, the Company
and its subsidiaries lease 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 materially adverse effect on the financial condition or
results of operations of the Company. See Note 9 of Notes to Consolidated
Financial Statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
11
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, 1997 ........... 15 7/8 13 5/8 0.04
June 30, 1997 ............ 20 12 3/8 0.04
September 30, 1997 ....... 20 1/2 17 3/8 0.04
December 31, 1997 ........ 20 1/4 16 7/8 0.04
March 31, 1998 ........... 17 1/4 14 0.04
June 30, 1998 ............ 14 1/8 10 1/8 0.04
September 30, 1998 ....... 10 1/2 6 5/16 0.04
December 31, 1998 ........ 6 1/4 2 1/16 0.04
Approximate number of equity shareholders as of December 31, 1998: 1,800.
Due to the current market conditions, the Company's Board of Directors
will evaluate on a quarterly basis whether or not to pay either common or
preferred dividends. 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 loan 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.
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)
----------------------------------------------------------------------------------
1998 (3) 1997 1996 1995 1994
---- ---- ---- ---- ----
(In thousands, except per share amounts)
Revenues from continuing operations ....... $ 51,422 $ 34,663 $ 684,516 $ 645,020 $ 422,206
--------- --------- --------- --------- ---------
Net (loss) earnings from continuing
operations ............................. $ (67,819) $ 3,308 $ 13,779 $ 4,093 $ 2,768
--------- --------- --------- --------- ---------
Basic earnings per common share
from continuing operations ............. $ (12.84) $ 0.17 $ 2.30 $ 0.35 $ 0.07
--------- --------- --------- --------- ---------
Property, plant and equipment, net ........ $ 121,634 $ 226,228 $ 103,495 $ 180,467 $ 108,799
--------- --------- --------- --------- ---------
Total assets .............................. $ 166,291 $ 266,711 $ 157,197 $ 269,030 $ 180,536
--------- --------- --------- --------- ---------
Long-term debt ............................ $ 102,000 $ 117,000 $ 20,581 $ 96,205 $ 33,098
--------- --------- --------- --------- ---------
Shareholders' equity ...................... $ 26,871 $ 97,639 $ 90,048 $ 79,020 $ 75,919
--------- --------- --------- --------- ---------
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 $ 0.00 $ 0.00
--------- --------- --------- --------- ---------
- -----------------
(1) See Note 3 of Notes to Consolidated Financial Statements regarding the
1997 sale of the technical fuels and chemical processing operations.
(2) See Notes 3 and 5 of Notes to Consolidated Financial Statements
regarding the 1996 purchase and 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 & gas
properties in 1998. Summarized below are the Company's quarterly
financial data for 1998 and 1997 continuing operations.
12
Summarized below are the Company's quarterly financial data for 1998 and 1997
continuing operations.
1998 QUARTERS
-----------------------------------------------------------------
FIRST(1) SECOND THIRD FOURTH(1)
----- ------ ----- ------
(In thousands, except per share amounts)
Revenues from continuing operations .................... $ 14,267 $ 12,267 $ 12,525 $ 12,363
-------- -------- -------- --------
(Loss) earnings from continuing operations
before income taxes ................................. $(68,379) $ 237 $ 605 $(36,619)
-------- -------- -------- --------
Net (loss) earnings from continuing operations ......... $(45,156) $ 134 $ 665 $(23,462)
-------- -------- -------- --------
Net (loss) earnings from continuing operations
per common share - basic ............................ $ (8.37) $ (0.09) $ 0.01 $ (4.40)
-------- -------- -------- --------
Net (loss) earnings from continuing operations
per common share - diluted .......................... $ (8.37) $ (0.09) $ 0.01 $ (4.40)
-------- -------- -------- --------
1997 QUARTERS (2)
-----------------------------------------------------------
FIRST SECOND THIRD FOURTH
----- ------ ----- ------
(In thousands, except per share amounts)
Revenues from continuing operations............. $ 9,067 $ 7,904 $ 7,522 $10,170
------- ------- ------- -------
Earnings from continuing operations
before income taxes.......................... $ 1,439 $ 1,056 $ 858 $ 1,427
------- ------- ------- -------
Net earnings from continuing operations......... $ 944 $ 639 $ 708 $ 1,017
------- ------- ------- -------
Net earnings from continuing operations
per common share - basic..................... $ 0.07 $ 0.01 $ 0.02 $ 0.08
------- ------- ------- -------
Net earnings from continuing operations
per common share - diluted................... $ 0.07 $ 0.01 $ 0.02 $ 0.07
------- ------- ------- -------
- -----------
(1) Includes charge for impairment of oil & gas properties (pre-tax) of
$66,118 in the first quarter and $36,049 in the fourth quarter.
(2) See Note 3 of Notes to Consolidated Financial Statements regarding the
1997 sale of the technical fuels and chemical fuels processing
operations.
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 only principal business segment is oil and gas production.
Crude oil marketing and transportation was also a principal segment until its
sale on December 3, 1996. Results of continuing operations by segment for the
three years ended December 31, 1998, are discussed below. The table below for
each segment's revenues does not reflect the elimination of intercompany
revenues. See Notes 3 and 8 of Notes to Consolidated Financial Statements.
13
OIL AND GAS PRODUCTION
YEAR ENDED DECEMBER 31,
-------------------------------------------
1998 1997 1996
---- ---- ----
(IN THOUSANDS)
Revenues:
Sales of oil and natural gas .................................. $ 48,538 $ 29,089 $ 28,162
Sales of LaBarge other products ............................... 1,685 1,493 1,747
Gas marketing ................................................. 758 2,868 3,553
Minerals leasing and other .................................... 441 959 660
-------- -------- --------
Total revenues ........................................... $ 51,422 $ 34,663 $ 33,868
-------- -------- --------
-------- -------- --------
Operating (loss) profit ....................................... $(90,525) $ 8,396 $ 8,682
-------- -------- --------
-------- -------- --------
Operating information:
Average net daily production:
Oil and NGL (BBLs) ........................................ 9,705 3,415 3,300
Natural gas (MCF) ......................................... 12,750 9,072 8,943
Average sales prices:
Oil and NGL (per BBL) (includes effect of hedging) ........ $ 11.26 $ 17.15 $ 17.52
Natural gas (per MCF) ..................................... $ 1.86 $ 2.33 $ 2.06
REVENUES
During 1998 revenues for the oil and gas segment increased 48% when
compared to the year ended 1997 due to the Amoco property Acquisition,
partially offset by a 35% decrease in average oil prices and a 20% decrease
in average natural gas prices. The increase in revenues were partially offset
by the Company's continued reduction of its gas marketing activities.
Revenues for 1997 increased primarily due to an increase in the natural
gas price of 13% to $2.33 per thousand cubic feet. Minerals leasing activity
steadily increased over the last three years. These revenue increases were
partially offset by a decrease in gas marketing revenue due to reduced activity.
Revenues from the sales of the La Barge other products are
attributable to sales of carbon dioxide, helium and sulfur. Increased
production levels of helium and carbon dioxide in 1997 relative to 1996 were
partially offset by reduced product sales prices. Sulfur revenues were
insignificant.
OPERATING PROFIT
Operating profits for the oil and gas segment decreased $98.9 million
primarily due to pre-tax non-cash impairments of $102.2 million. On an
after-tax basis, the impairments amounted to $67.4 million or a loss of
$12.32 per common share. Excluding the impairments, the segment's operating
profits increased 39% when compared to the year ended 1997. The Acquisition
also resulted in increased lease operating expense and production and
severance tax expense of $13.3 million and $2.8 million, respectively. A
reduction of workover expense of $1.1 million helped to offset these
increased costs. The Company's general and administrative expenses decreased
$1.6 million due to increased administrative credits on some of the
properties acquired in late 1997. Also offsetting these costs was a decrease
in depreciation, depletion and amortization, excluding the impairments, per
equivalent barrel of production from $5.18 in 1997 to $2.68 in 1998 due to
the Acquisition.
In 1997, the operating profit of this segment decreased $0.3 million
when compared to 1996. The decrease was primarily due to increased workover
expenses and LaBarge expenses. Workover costs increased from $1.1 million in
1996 to $1.6 million in 1997 primarily due to platform refurbishment on Main
Pass 64.
Howell's average realized oil price, including hedging, for 1998 was
$11.37 per barrel. The crude oil price decline that began in the latter part
of the fourth quarter 1997 continued into early 1999.
Lower oil and gas prices may continue for the near term. During such
period, the Company's cash flow and funds available for reinvestment are
reduced. Accordingly, Howell is currently focusing its 1999 capital
investments on obligatory projects and pilot programs designed to build an
inventory of projects for long-term
14
shareholder value. In the interim, should lower product prices be sustained,
Howell may record a non-cash ceiling test impairment at the end of the first
quarter 1999 to the value of its proved oil and gas properties as determined
by Securities and Exchange Commission guidelines.
CRUDE OIL MARKETING & TRANSPORTATION
There were no revenues or operating profits during 1998 or 1997 in
the crude oil marketing and transportation segment as a result of the sale of
the Business. Revenues and operating profits for 1996 were $666.1 million and
$9.6 million, respectively. However, the Company did retain a direct and
indirect interest in Genesis. As a result of the Company's interest, the
Company recognized net earnings in Genesis of $0.6 million during 1998 and
$0.9 million during 1997. See Note 5 of Notes to Consolidated Financial
Statements.
Effective December 3, 1996, the Company's sale of the assets and
liabilities associated with crude oil marketing and transportation segment
resulted in a pre-tax gain of $13.8 million recognized in other
income/expense.
INTEREST EXPENSE
During 1998, interest expense increased $9.3 million as a result of
the increased short-term and long-term debt ("Debt") necessary for the
Acquisition. Debt averaged $136.8 million during 1998. As a result of the
sale of the fee mineral interests during December 1998, the Company was able
to reduce this Debt by $13.0 million. In early 1999, the Company was able to
further reduce Debt by $17.8 million as a result of the sale of the LaBarge
properties and the buyout by SFC of its remaining excess EBITDA payments.
Interest expense in 1997 decreased $5.3 million below the 1996
level. The primary reason for this decrease was repayment of the term loan
and revolving credit facilities out of funds received from: (i) the December
3, 1996 sale of the Business to Genesis; (ii) the December 31, 1996 sale of
100% of the outstanding common stock of Howell Transportation Services, Inc.
to Lodestar Logistics, Inc.; and (iii) the July 31, 1997, sale of
substantially all of the assets of the Company's research and reference fuels
and custom chemical manufacturing business to SFC. Debt averaged $23.9
million for the first half of 1997. The proceeds of the sale to SFC were used
to reduce debt to an average of $11.8 million for the last half of the year
before the Acquisition and an average of $21.0 million for the last half of
the year including the Acquisition. The average debt during 1996 was $90.5
million. The purchase of the Acqusition, increased debt to $137.0 million at
year-end 1997. See Notes 3, 5 and 6 of Notes to Consolidated Financial
Statements.
PROVISION FOR INCOME TAXES
The Company's approximate effective tax rate of 35% reflects the
statutory federal rate and state income taxes less the effect of statutory
depletion deductions in excess of cost basis.
RESULTS FROM DISCONTINUED OPERATIONS
TECHNICAL FUELS AND CHEMICAL PROCESSING
On July 31, 1997, Seller completed the sale of and disposition of
substantially all of the assets of its research and reference fuels and
custom chemical manufacturing business to SFC.
As a result of the sale, the Company was entitled to receive an
additional payment equal to 55% of the amount by which Buyer's "EBITDA" for
each twelve month period ending June 30, 1998, 1999, 2000, 2001 and 2002
exceeds the "Minimum EBITDA" (as defined in the agreement). The Minimum
EBITDA amounts for those years were $5.0 million, $5.175 million, $5.35
million, $5.525 million and 5.7 million, respectively, SFC was entitled to
repurchase Seller's rights to these additional payments at any time after
June 30, 1998, generally by paying to Seller an amount equal to the greater
(a) the product obtained by multiplying the EBITDA payment amount for the
immediately preceding twelve-month period by the number of twelve-month
periods remaining, or (b) an amount fixed by the agreement, which was
initially set at $5.7 million if the repurchase occurred during the
twelve-month period ending on June 30, 1999, and which declines for each
twelve-month period thereafter to $1.2 million if the repurchase occurred
during the twelve-month period ending June 30, 2002.
During August 1998, the Company received the first excess EBITDA
payment of $0.7 million pre-tax. On January 4, 1999, SFC and Seller agreed
that the amount fixed by the Agreement was not reasonable in light of the
current performance; therefore, Seller agreed to reduce the excess EBITDA
payment to $2.0 million which SFC agreed to purchase.
15
The results of the technical fuels and chemical processing business have
been classified as discontinued operations in the accompanying consolidated
financial statements. Discontinued operations also includes the allocation of
interest expense (based on a ratio of net assets of discontinued operations
to total consolidated net assets). Allocated amounts are as follows:
YEAR ENDED DECEMBER 31,
1998 1997 1996
---- ---- ----
(IN THOUSANDS)
$ - $112 $504
---- ---- ----
---- ---- ----
LIQUIDITY AND CAPITAL RESOURCES
RECENT EVENTS
On January 4, 1999, the Company sold its right to participate in the
future earnings of SFC for $2.0 million. SFC acquired the Company's research
and reference fuel business in July 1997.
On January 29, 1999, the Company sold its interest in the LaBarge field
for $15.8 million.
On March 16, 1999, the Company received a refund of $5.7 million for
Federal taxes paid in prior years.
On March 19, 1999, the Company signed an agreement to sell its interest
in the Pitchfork and Grass Creek, Wyoming fields for $12.4 million.
The cumulative proceeds from these events, totaling $35.9 million, have
been or will be used to reduce bank debt. By utilizing this $35.9 million and
part of the $5.9 million cash and cash equivalents available at December 31,
1998, the Company will be able to pay off Tranche B and reduce Tranche A to
approximately $84 million. See Item 2. "Properties" and Note 6 of Notes to
Consolidated Financial Statements.
CREDIT FACILITY
The Company amended and restated the December 17, 1997 Credit Agreement
effective on 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 was
redetermined to $110 million prior to the 1998 sale of the Company's fee
mineral interest, and to $105 million after the sale. Tranche B is a term
loan with an amended borrowing availability of $30 million. The Company is
required to pay commitment fees on the unused portion of Tranche A at a rate
of 0.375% per annum while Tranche B is outstanding. After Tranche B has been
repaid, the commitment fee will be 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 ("Libor") rate per annum, or
the Base Rate (prime), plus the Applicable Margin. The Applicable Margin is
determined by the Borrowing Base Utilization Percentage. It ranges 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.
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 with
other persons, 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 1.5 to 1.0 at the end of any fiscal quarter.
On December 17, 1998, the Company was able to reduce the outstanding
balance of Tranche A by $5 million and Tranche B by $8 million as a result of
the sale of its fee mineral interests.
16
As of December 31, 1998, the outstanding amounts under Tranche A bore
interest at 8.0625% per annum on $102 million and under Tranche B bore
interest at 10.5625% per annum on $22 million.
OTHER
At December 31, 1998, the Company had negative working capital of $11.4
million, including the $22.0 million Tranche B loan facility referred to
above. In 1998, cash provided from operating activities was $19.6 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. Due to
the current market conditions, the Company's Board of Directors will evaluate
on a quarterly basis whether or not to pay either common or preferred
dividends.
The Company currently anticipates spending approximately $0.1 million
during fiscal years 1999 and 2000 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 1999. The Company spent $0.05 million on such expenditures in
1998. See Note 10 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, 1998, the
Company had cash and cash equivalents of $5.9 million and $3 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 happen in 1999, 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. See "Recent Events".
QUALITATIVE & QUANTITATIVE MATTERS
In order to guarantee the Company a specific minimum sales price for its
crude oil, the Company purchased a put option and sold a call option covering
approximately 3,300 barrels per day of crude oil production for an 18-month
period beginning March 1, 1995. The option strike prices were based on the
average price of crude oil on the organized exchange with monthly settlement.
The strike prices were $17 per barrel for the put option and $20 per barrel
for the call option.
During 1996, the monthly average sales price of crude oil on the
organized exchange was between $17 and $20 per barrel for January and
February; therefore, no options were exercised during the two months. The
monthly average sales price for the remainder of the March 1, 1995 call
option period, March 1996 through August 1996, was above the $20 ceiling.
This resulted in collar payments of $0.9 million, excluding the premium
amortization and were recorded as a reduction of revenue.
Upon the expiration of the 18-month option period, the Company purchased
a $16.50 per barrel put option and sold a $21.10 per barrel call option
covering 100,000 barrels of oil per month for a six-month period ending
February 28, 1997. For September through December 1996, the monthly average
sales price exceeded the ceiling price. This resulted in collar payments for
the four month period of $1.3 million which were recorded as a reduction of
revenue.
In 1997, the monthly average price of crude oil on the organized
exchange exceeded the strike price for the call option during January and
February, the final two months of the options. The payments required in 1997
under the call option totaled $0.5 million and were recorded as a reduction
of revenue.
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.
17
ACCOUNTING PRONOUNCEMENTS
In June 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 130, "Reporting Comprehensive Income",
("SFAS 130"). SFAS 130 is effective for periods beginning after December 15,
1997. SFAS 130 establishes standards for reporting and displaying
comprehensive income and its components. The purpose of reporting
comprehensive income is to report a measure of all changes in equity of an
enterprise that result from recognized transactions and other economic events
of the period other than transactions with owners in their capacity as
owners. In 1998, the Company adopted SFAS 130 and as of December 31, 1998,
there were no adjustments to net income in deriving comprehensive income.
In June 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 131, "Disclosures About Segments of an
Enterprise and Related Information," ("SFAS 131"). SFAS 131 establishes
standards for the way that public business enterprises report information
about operating segments. SFAS 131 is effective for periods beginning after
December 15, 1997. The Company has adopted SFAS 131. See Note 8 of Notes to
the Consolidated Financial Statements.
In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities," ("SFAS 133"). SFAS 133 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 fair value will be reported in the period of
change as either a component of earnings or a component of other
comprehensive income. SFAS 133 is effective for all fiscal quarters of fiscal
years beginning after June 15, 1999. Earlier application of SFAS 133 is
encouraged, but not prior to the beginning of any fiscal quarter that began
after issuance of the Statement. Retroactive application to periods prior to
adoption is not allowed. The Company has not quantified the impact of
adoption of SFAS 133 on its financial statements.
18
YEAR 2000 DATE CONVERSION
The Company has a plan in place that addresses the year 2000 ("Y2K")
conversion issue. The first step in the plan was to evaluate all computer
systems used in its operations. This includes accounting and financial
systems, field and production systems, and other field or office devices that
may not be Y2K compliant. This was followed by a determination of what
remedial action is necessary and initiation of that remedy. The Company's
plan to correct its in-house systems involved installation of new software
and hardware. The Company installed a new accounting package during the
fourth quarter of 1998 which is Y2K compliant. The Company has begun
corrective action on major field systems and anticipates completion during
the third quarter of 1999.
The next step was to determine the Y2K status of relevant outside
suppliers and vendors. While the Company cannot control the Y2K corrective
action of third parties, it has begun the process of identifying and
contacting its critical suppliers and vendors. Based on their status, the
Company will develop contingency plans. These should be completed by the
third quarter of 1999.
Based on preliminary estimates, the cost of implementing this plan is
approximately $300,000. It is not certain that this estimate is correct or
that Year 2000 compliance can be achieved. The Company does not expect a
significant disruption in its operations, but actual results could differ
greatly from these expectations. Some areas that could cause differences to
occur are the availability of personnel trained in this area, the ability to
identify and correct all relevant computer code and non-compliant embedded
systems and the degree of interdependence with third party suppliers and
purchasers. Other areas outside the Company's control such as problems in the
utility, banking, or transportation systems could have a material disruptive
effect on the Company's ability to produce and deliver oil and gas, receive
delivery of materials and supplies, or disburse or receive funds.
One example of a serious Y2K problem would be the shut down of a field which
is on automated controls and/or a monitoring system. As disclosed above, the
Company has examined such controls and systems in all of its major fields and
is taking corrective action, as appropriate. Nevertheless, the Company
intends to prepare a Y2K contingency plan which will address potential risks
in the field, and possible solutions, including manual intervention or
equipment replacement. The Company is unable to anticipate every potential
problem and determine a contingency for every possible Y2K risk. Should
essential services such as electricity be affected adversely, or if other Y2K
related problems limit or restrict production from one of the Company's major
fields, it could have a material adverse affect on the Company.
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 performances, 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 reserve estimates, and changes in
the level and timing of future costs and expenses related to drilling and
operating activities.
Words such as "anticipated", "expect", "project", and similar
expressions are intended to identify forward-looking statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
See discussion under Liquidity and Capital Resources.
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
Not applicable.
19
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 1999 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..................... 62 Chairman and Chief Executive Officer
Richard K. Hebert..................... 47 President and Chief Operating Officer
J. Richard Lisenby.................... 55 Vice President and Chief Financial Officer
Robert T. Moffett..................... 47 Vice President, General Counsel and Secretary
John E. Brewster, Jr.................. 48 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. 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. Richard K. Hebert was elected President and Chief Operating Officer
in May 1997. From 1993 to 1997, he was co-owner of Voyager Energy Corp.
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. J. Richard Lisenby was elected Vice President and Chief Financial
Officer of the Company in December 1996. Prior to that, Mr. Lisenby served as
Treasurer of Columbia Gas Development, a subsidiary of Columbia Gas System.
Mr. Robert T. Moffett was elected Secretary in October 1996 and Vice
President and General Counsel of the Company in January 1994. He had served
as General Counsel of the Company since September 1992. Prior to that time,
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 1996. Prior to that time he was a consultant
for 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 1999 Annual Shareholders' Meeting, is incorporated herein
by reference.
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 1999 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 1999 Annual Shareholders' Meeting, is
incorporated herein by reference.
20
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 1999 Annual
Shareholders' Meeting, is incorporated herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Exhibits - None
(b). Reports on Form 8-K.
A report on Form 8-K was filed December 29, 1998 announcing the
sale of mineral estates and royalty interests located in the
states of Alabama, Mississippi and Louisiana.
21
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/ J. RICHARD LISENBY
------------------------------------
J. Richard Lisenby
Vice President and
Chief Financial Officer
Principal Financial and Accounting Officer
Date: March 22, 1999
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 March 22, 1999
- -----------------------------------
Donald W. Clayton
Chairman
and
Chief Executive Officer
Principal Executive
/s/ RICHARD K. HEBERT Officer and Director March 22, 1999
- -----------------------------------
Richard K. Hebert
President
and
Chief Operating Officer
/s/ PAUL N. HOWELL Director March 22, 1999
- -----------------------------------
Paul N. Howell
/s/ JACK T. TROTTER Director March 22, 1999
- -----------------------------------
Jack T. Trotter
/s/ WALTER M. MISCHER, SR. Director March 22, 1999
- -----------------------------------
Walter M. Mischer, Sr.
22
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.......................................................... 24
Consolidated Financial Statements:
Consolidated Balance Sheets...................................................... 25
Consolidated Statements of Operations............................................ 26
Consolidated Statements of Changes in Shareholders' Equity....................... 27
Consolidated Statements of Cash Flows............................................ 28
Notes to Consolidated Financial Statements....................................... 29
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.
23
INDEPENDENT AUDITORS' REPORT
To Howell Corporation:
We have audited the accompanying consolidated balance sheets of Howell
Corporation and its subsidiaries as of December 31, 1998 and 1997, 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, 1998. 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 generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits provide
a reasonable basis for our opinion.
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, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1998 in conformity with generally accepted accounting
principles.
DELOITTE & TOUCHE LLP
Houston, Texas
March 22, 1999
24
HOWELL CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
DECEMBER 31,
---------------------------
1998 1997
---- ----
(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents................................................. $ 5,871 $ 56
Trade accounts receivable, less allowance for doubtful accounts of
$156 in 1998 and $144 in 1997........................................ 9,230 5,520
Receivable from Genesis................................................... - 2,300
Income tax receivable..................................................... 5,701 1,411
Deferred income taxes..................................................... 3,408 -
Other current assets...................................................... 577 1,489
----------- -----------
Total current assets.................................................. 24,787 10,776
----------- -----------
Property, plant and equipment:
Oil and gas properties, utilizing the full-cost method of accounting...... 385,048 371,975
Unproven properties....................................................... 43,263 41,017
Fee mineral interests, unproven........................................... - 18,123
Other..................................................................... 2,653 2,670
Less accumulated depreciation, depletion and amortization................. (309,330) (207,557)
----------- -----------
Net property, plant and equipment..................................... 121,634 226,228
----------- -----------
Investment in Genesis.......................................................... 16,908 16,432
Other assets................................................................... 2,962 14,686
----------- -----------
Total assets.......................................................... $ 166,291 $ 268,122
----------- -----------
----------- -----------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term debt...................................... $ 22,000 $ 20,000
Accounts payable.......................................................... 8,639 2,165
Accrued liabilities....................................................... 5,520 4,819
----------- -----------
Total current liabilities............................................. 36,159 26,984
----------- -----------
Deferred income taxes.......................................................... - 25,071
----------- -----------
Other liabilities.............................................................. 1,261 1,428
----------- -----------
Long-term debt................................................................. 102,000 117,000
----------- -----------
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; 5,471,782 shares
issued and outstanding in 1998; 5,464,642 shares
issued and outstanding in 1997....................................... 5,472 5,465
Additional paid-in capital................................................ 40,829 40,760
Retained (deficit) earnings............................................... (20,120) 50,724
----------- -----------
Total shareholders' equity............................................ 26,871 97,639
----------- -----------
Total liabilities and shareholders' equity............................ $ 166,291 $ 268,122
----------- -----------
----------- -----------
See accompanying Notes to Consolidated Financial Statements.
25
HOWELL CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations
YEAR ENDED DECEMBER 31,
---------------------------------------------
1998 1997 1996
---- ---- ----
(In thousands, except per share amounts)
Revenues:
Oil & Gas..................................................... $ 51,422 $ 34,663 $ 33,868
Other......................................................... - - 650,648
------------ ---------- -----------
51,422 34,663 684,516
------------ ---------- -----------
Costs and Expenses:
Operating expenses - Oil & Gas................................ 27,764 14,825 13,773
Depreciation, depletion, and amortization..................... 11,703 9,460 9,694
Impairment of oil & gas properties............................ 102,167 - -
General and administrative expenses........................... 3,447 5,093 5,313
Other......................................................... - - 641,037
------------ ---------- -----------
145,081 29,378 669,817
------------ ---------- -----------
Other income (expense):
Interest expense.............................................. (11,005) (1,671) (6,988)
Interest income............................................... 111 145 110
Net earnings of Genesis....................................... 635 906 181
Gain on conveyance of assets.................................. - - 13,841
Other-net..................................................... (238) 115 (69)
------------ ---------- -----------
(10,497) (505) 7,075
------------ ---------- -----------
(Loss) earnings before income taxes................................ (104,156) 4,780 21,774
Income tax (benefit) expense ..................................... (36,337) 1,472 7,995
------------ ---------- -----------
Net (loss) earnings from continuing operations..................... (67,819) 3,308 13,779
------------ ---------- -----------
Discontinued operations:
Net earnings from Howell Hydrocarbons
(less applicable income taxes of $350, $388 and $267
for 1998, 1997 and 1996, respectively)..................... 266 528 298
Gain on sale of Howell Hydrocarbons (less applicable income
taxes of $126 for 1997).................................... - 245 -
------------ ---------- -----------
Net earnings from discontinued operations.......................... 266 773 298
------------ ---------- -----------
Net (loss) earnings................................................ (67,553) 4,081 14,077
Less: cumulative preferred stock dividends.................. (2,415) (2,415) (2,415)
------------ ---------- -----------
Net (loss) earnings applicable to common stock..................... $ (69,968) $ 1,666 $ 11,662
------------ ---------- -----------
------------ ---------- -----------
Basic (loss) earnings per common share:
Continuing operations......................................... $ (12.84) $ 0.17 $ 2.30
Discontinued operations....................................... 0.05 0.10 0.06
Gain on sale of Howell Hydrocarbons........................... - 0.05 -
------------ ---------- -----------
Net (loss) earnings per common share - basic.................. $ (12.79) $ 0.32 $ 2.36
------------ ---------- -----------
------------ ---------- -----------
Weighted average shares outstanding - basic........................ 5,470 5,143 4,937
------------ ---------- -----------
------------ ---------- -----------
Diluted (loss) earnings per common share:
Continuing operations......................................... $ (12.84) $ 0.17 $ 1.93
Discontinued operations....................................... 0.05 0.09 0.04
Gain on sale of Howell Hydrocarbons........................... - 0.05 -
------------ ---------- -----------
Net (loss) earnings per common share - diluted................ $ (12.79) $ 0.31 $ 1.97
------------ ---------- -----------
------------ ---------- -----------
Weighted average shares outstanding - diluted...................... 5,470 5,355 7,129
------------ ---------- -----------
------------ ---------- -----------
See accompanying Notes to Consolidated Financial Statements.
26
HOWELL CORPORATION AND SUBSIDIARIES
Consolidated Statement of Changes in Shareholders' Equity
PREFERRED STOCK COMMON STOCK RETAINED
PAID-IN EARNINGS
SHARES $ SHARES $ CAPITAL (DEFICIT) TOTAL
------- --- --------- ----- ------- -------- -------
(In thousands, except number of shares)
Balances, December 31, 1995 .................. 690,000 $690 4,933,446 $4,933 $34,390 $39,007 $79,020
Net earnings - 1996 .......................... - - - - - 14,077 14,077
Cash dividends - $.16 per
common share .......................... - - - - - (790) (790)
Cash dividends - $3.50 per
preferred share ....................... - - - - - (2,415) (2,415)
Common stock issued to employees
upon exercise of stock options ........ - - 13,750 14 142 - 156
------- ---- --------- ------ ------- -------- --------
Balances, December 31, 1996 .................. 690,000 690 4,947,196 4,947 34,532 49,879 90,048
Net earnings - 1997 ..................... - - - - - 4,081 4,081
Cash dividends - $.16 per
common share .......................... - - - - - (821) (821)
Cash dividends - $3.50 per
preferred share ....................... - - - - - (2,415) (2,415)
Common stock issued to employees
upon purchase of Voyager Energy ....... - - 352,638 353 4,276 - 4,629
Common stock issued to employees
upon exercise of stock options ........ - - 164,808 165 1,608 - 1,773
Tax benefit upon exercise of employee
stock options ......................... - - - - 344 - 344
------- ---- --------- ------ ------- -------- --------
Balances, December 31, 1997 .................. 690,000 690 5,464,642 5,465 40,760 50,724 97,639
Net loss - 1998 ......................... - - - - - (67,553) (67,553)
Cash dividends - $.16 per
common share .......................... - - - - - (876) (876)
Cash dividends - $3.50 per
preferred share ....................... - - - - - (2,415) (2,415)
Common stock issued to
employees and directors upon
exercise of stock options ............. - - 7,140 7 56 - 63
Tax benefit upon exercise of employee
stock options .......................... - - - - 13 - 13
------- ---- --------- ------ ------- -------- --------
Balances, December 31, 1998 .................. 690,000 $690 5,471,782 $5,472 $40,829 $(20,120) $ 26,871
------- ---- --------- ------ ------- -------- --------
------- ---- --------- ------ ------- -------- --------
See accompanying Notes to Consolidated Financial Statements.
27
HOWELL CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows
YEAR ENDED DECEMBER 31,
----------------------------------------------
1998 1997 1996
---- ---- ----
(In thousands)
OPERATING ACTIVITIES:
Net (loss) earnings from continuing operations............... $ (67,819) $ 3,308 $ 13,779
Adjustments for non-cash items:
Depreciation, depletion and amortization................. 113,870 9,460 13,817
Deferred income taxes.................................... (36,337) 1,221 5,219
Equity in earnings of Genesis - net of amortization...... (635) (906) (181)
Dividends received from Genesis.......................... 159 134 -
Gain on sale of assets................................... (2) (132) (13,883)
--------- -------- ---------
Earnings from continuing operations plus non-cash
operating items......................................... 9,236 13,085 18,751
Changes in components of working capital from operations:
(Increase) decrease in trade accounts receivable......... (3,710) (48) 54,979
Decrease (increase) in inventories....................... 5 (7) 2,024
Decrease (increase) in income tax receivable............. 3,486 (3,140) 2,340
Decrease (increase) in other current assets.............. 3,207 (2,558) 394
Increase (decrease) in accounts payable.................. 6,515 (1,763) (54,496)
Increase (decrease) in accrued and other liabilities..... 1,049 (4,369) 1,900
--------- -------- ---------
Cash provided by continuing operations...................... 19,788 1,200 25,892
Cash (utilized by) provided by discontinued operations...... (195) 1,025 1,293
--------- -------- ---------
Cash provided by operating activities............................ 19,593 2,225 27,185
--------- -------- ---------
INVESTING ACTIVITIES:
Proceeds from the disposition of property.................... 13,333 20,053 1,804
Investment in investees...................................... - 2,692 (1,556)
Proceeds from sale of assets to MLP.......................... - - 68,717
Additions to property, plant and equipment................... (22,607) (128,199) (12,378)
Deposit for Amoco Beaver Creek acquisition................... 12,369 (12,369) -
Other, net................................................... (645) (137) 66
--------- -------- ---------
Cash provided by (utilized in) investing activities.............. 2,450 (117,960) 56,653
--------- -------- ---------
FINANCING ACTIVITIES:
Long-term debt:
(Repayments) borrowings under credit
facility-net........................................ (13,000) 137,000 -
Repayments under revolving credit
facility-net........................................ - (18,000) (24,250)
Repayments under term loan agreement..................... - - (54,625)
Repayments to Department of Energy....................... - (4,999) (2,266)
Other repayments......................................... - - ( 133)
Cash dividends:
Common shareholders...................................... (876) (821) (790)
Preferred shareholders................................... (2,415) (2,415) (2,415)
Exercise of stock options.................................... 63 1,773 156
--------- -------- ---------
Cash (utilized in) provided by financing activities.............. (16,228) 112,538 (84,323)
--------- -------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS.................................................. 5,815 (3,197) (485)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR..................... 56 3,253 3,738
--------- -------- ---------
CASH AND CASH EQUIVALENTS, END OF YEAR........................... $ 5,871 $ 56 $ 3,253
--------- -------- ---------
--------- -------- ---------
See accompanying Notes to Consolidated Financial Statements.
28
HOWELL CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. RECENT EVENTS
On January 4, 1999, Howell Corporation and its subsidiaries (the
"Company") sold its right to participate in the future earnings of Specified
Fuels & Chemicals ("SFC") for $2.0 million. SFC acquired the Company's
research and reference fuel business in July 1997.
On January 29, 1999, the Company sold it interest in the LaBarge field for
$15.8 million.
On March 16, 1999, the Company received a refund of $5.7 million for
Federal taxes paid in prior years.
On March 19, 1999, the Company signed an agreement to sell its interest in
the Pitchfork and Grass Creek, Wyoming fields for $12.4 million.
The cumulative proceeds from these events, totaling $35.9 million, have been
or will be used to reduce bank debt. By utilizing this $35.9 million and part
of the $5.9 million cash and cash equivalents available at December 31, 1998,
the Company will be able to pay off Tranche B and reduce Tranche A to
approximately $84 million. See Note 6.
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the
Company. The Company accounts for its investment in less than 50% owned
investees using the equity method of accounting when it has the ability to
exercise significant influence over operating and financial policies of the
investee. All significant intercompany accounts and transactions have been
eliminated.
NATURE OF OPERATIONS
The Company is primarily engaged in the exploration, production,
acquisition and development of oil and gas properties. These operations are
conducted in the United States. The Company has also been involved in
technical fuels and chemical processing and crude oil marketing and
transportation, but has divested itself of these businesses. The Company has
retained an equity investment in a crude oil marketing and transportation
company. See Notes 3, 5, and 8.
PROPERTY, DEPRECIATION, DEPLETION AND AMORTIZATION
The Company follows the full-cost method of accounting for its oil and
gas exploration and production activities, which are conducted solely in the
United States. 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 and fee mineral interests
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.
Due to the perpetual nature of the Company's ownership of the mineral
interests, the drilling of a well, whether successful or unsuccessful, may
not represent a complete test of all depths of interest. Therefore, at the
time that a well is drilled only a portion of the costs allocated to the
acreage drilled may be added to the costs being amortized.
29
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 liability 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 stock options having exercise prices less than the average
market price of the common stock using the treasury stock method.
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 $10,184,000, $1,347,000 and $7,793,000 in 1998, 1997 and 1996,
respectively. In 1998, 1997 and 1996, cash payments for income taxes totaled
$261,000, $6,849,000, and $2,974,000, respectively.
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 as reflected in its balance
sheet approximates fair value.
STOCK BASED COMPENSATION
The intrinsic value method of accounting is used for stock-based
employee compensation whereby no compensation expense is recognized when the
exercise price of an employee stock option is equal to or greater than the
market price of the Company's common stock on the grant date.
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. Information regarding environmental liabilities can be found in
Note 10. Ongoing environmental compliance costs, including maintenance and
monitoring costs, are charged to expense as incurred.
DERIVATIVES
In order to mitigate the effects of future price fluctuations, the
Company has used a limited program of hedging its crude oil production.
Crude oil futures and options contracts are used as the hedging tools.
Changes in the market value of the futures transactions are deferred until
the gain or loss is recognized on the hedged transactions.
In 1995, the Company purchased a put option and sold a call option
covering 3,300 barrels per day of oil production for an 18-month period
beginning March 1, 1995. The option strike prices were based on the average
price of crude oil on the organized exchange, with monthly settlement. The
strike prices were $17 per barrel for the put option and $20 per barrel for
the call option. The premiums for the options were amortized over the option
period. Upon expiration of the 18-month option period, the Company purchased
a put option and sold a call option covering 100,000 barrels of oil per month
for a six-month period ended February 28, 1997. The strike
30
prices were $16.50 per barrel for the put option and $21.10 per barrel for
the call option. There was no premium associated with these options.
During 1996, the monthly average price of crude oil on the organized
exchange exceeded the strike price for the call option in ten months. The
payments required in 1996 under the call options and the premium amortized in
1996 totaled $2.5 million and were recorded as a reduction of revenue.
During 1995, the monthly average price of crude oil on the organized exchange
was between $17 and $20 per barrel; therefore, none of the options were
exercised during this period. Premiums amortized during 1995 totaled $0.4
million and were recorded as a reduction of revenue.
In 1997, the monthly average price of crude oil on the organized
exchange exceeded the strike price for the call option during January and
February, the final two months of the options. The payments required in 1997
under the call option totaled $0.5 million and were recorded as a reduction
of revenue.
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.
Crude oil future contracts and options were also used as a hedging tool in
a limited program of hedging crude oil inventories and fixed purchase price
commitments. Other costs and expenses related to the crude oil marketing and
transportation businesses were reduced by $0.1 million in 1996 from the
effects of futures and options.
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, 1998 or 1997.
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 the 1997 and 1996 financial
presentation to conform with the 1998 presentation. Other revenues and
expenses includes all of the revenues, costs and expenses (operating expenses,
depreciation, selling, general and administrative expenses) associated with
the crude oil gathering and marketing operations, pipeline operations and
transportation services.
NOTE 3. ACQUISITIONS & DISPOSITIONS
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. The
31
company will retain a 10% net profits interest after payout. The net daily
production attributable to these assets is approximately 350 BOE. Proceeds
from the sale were used to retire bank debt. See Note 6.
During November 1998, the Company announced the execution of a letter
agreement with SFC which purchased the Company's research and reference fuel
business on July 31, 1997. As part of the consideration in that sale, the
Company was to receive an additional payment equal to 55% of the amount by
which SFC's "EBITDA" for each twelve-month period ending June 30, 1998, 1999,
2000, 2001 and 2002 exceeds the "Minimum EBITDA" (as defined in the
Agreement). The Minimum EBITDA amounts for those years were $5.0 million,
$5.175 million, $5.35 million, $5.525 million and $5.7 million, respectively.
The Company received $0.7 million pre-tax under that provision in 1998. On
January 4, 1999, SFC and Howell Hydrocarbons & Chemicals, Inc. ("Seller"), a
wholly owned subsidiary of the Company, agreed that the amount fixed by the
Agreement was not reasonable in light of the current performance; therefore,
Seller agreed to reduce the excess EBITDA payment to $2.0 million which SFC
agreed to purchase.
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 ("SOCO") whereby the parties agreed to settle the pending
litigation between them styled: SNYDER OIL CORPORATION, PLAINTIFF V. AMOCO
PRODUCTION COMPANY AND HOWELL PETROLEUM CORPORATION, DEFENDANTS in the
District Court, Ninth Judicial District, Civil Action No. 29861, Fremont
County, Wyoming. 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 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 estimate
total proved reserves attributable to these properties were 8.1 BCFE. Net
daily production from the properties was approximately 1.8 MMCF of natural
gas with a projected reserve-to-production index of 12 years. This
settlement completed HPC's acquisition of the properties from Amoco. HPC
purchased proved reserves of 39.1 MMBOE for $126.4 million which was an
acquisition cost of $3.23 per barrel of oil equivalent. The operating results
of the assets acquired from Amoco have been included in the Company's
Statement of Operations since May 22, 1998. Pro forma information is not
required because of materiality.
1997
On December 18, 1997, the Company purchased certain oil and gas producing
properties (the "Package") in Wyoming from Amoco Production Company
("Amoco"), a subsidiary of Amoco Corporation, for approximately $115.4
million, subject to purchase price adjustments. The effective date of the
Purchase was December 1, 1997. The Package was accounted for using the
purchase method of accounting, and accordingly, the purchase price was
allocated to the assets acquired based on estimated fair values at the date
of acquisition. The operating results of the assets acquired from Amoco have
been included in the Company's Statement of Operations since December 18,
1997. The pro forma information shown below assumes that the Purchase
occurred at January 1, 1997. Adjustments have been made to reflect changes
in the Company's results from revenues and direct operating expenses of the
producing properties acquired from Amoco, additional interest expense to
reflect the acquisition, depreciation, depletion and amortization based on
fair values assigned to the assets acquired, and general and administrative
expenses incurred from hiring additional employees. The pro forma financial
data are based on assumptions and the actual recording of the Purchase could
differ. The unaudited pro forma financial data are not necessarily
indicative of financial results that would have occurred had the Acquisition
occurred on January 1, 1997, and should not be viewed as indicative of
operations in future periods.
PRO FORMA
UNAUDITED
YEAR ENDED DECEMBER 31,
-----------------------
1997 1996
---- ----
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Revenues.............................................................................. $88,394 $745,694
Net earnings from continuing operations............................................... $13,208 $ 26,739
Net earnings from continuing operations per common share - basic...................... $ 2.10 $ 4.93
Net income from continuing operations per common share - diluted...................... $ 1.77 $ 3.75
The acquisition was financed through bank debt. See Note 6.
32
On October 1, 1997, the Company acquired Voyager Energy Corp.
("Voyager"), an oil and gas exploration and production company, for 352,638
shares of common stock of the Company in a tax-free reorganization. The
shares issued by the Company in the merger represent in the aggregate
approximately 6.5 percent of the Company's common stock outstanding after
the transaction. The value of the shares in the tax-free reorganization was
$4.6 million. The shares were distributed as a non-cash transaction and, as
such, are not reflected in the Consolidated Statement of Cash Flows for the
year ended December 31, 1997. The Company assumed approximately $1.3 million
in Voyager indebtedness as a result of the merger.
On July 31, 1997, the Seller completed the previously announced sale and
disposition of substantially all of the assets of its research and reference
fuels and custom chemical manufacturing business to SFC.
The assets purchased by SFC included the fee property in Channelview,
Texas, on which Seller's refinery was located, all refining facilities
located on the fee property and all related personal property, all
inventories of finished products, work in process, raw materials and supplies
related to the business, substantially all of the accounts receivable on the
closing date, all transferable intellectual property used primarily in the
business and all of Seller's rights under various contracts and leases
related to the business. In connection with the transaction, (a) SFC
received a license to use the name "Howell Hydrocarbons & Chemicals" for a
five-year period after closing and assumed certain obligations of Seller and
the Company, and (b) the Company agreed not to engage (directly or through
affiliates) in any competing business for a five-year period after the
closing.
The sale resulted in a pre-tax gain of $0.4 million and the proceeds of
the sale were used by the Company to reduce its outstanding indebtedness.
The sale completes the divestiture by the Company of all of its
non-exploration and production businesses. In connection with the sale, the
Company has given and received environmental and other indemnities. Should
claims be made against the Company based on these indemnities, the Company
could be required to perform its obligations thereunder.
In consideration of the assets sold to SFC, Seller and the Company
received a payment of $19.8 million in cash, which included $14.8 million for
the property, plant, equipment and related items, and $5.0 million in payment
of working capital items. Seller was entitled to receive an additional
payment equal to 55% of the amount by which Buyer's "EBITDA" for each twelve
month period ending June 30, 1998, 1999, 2000, 2001 and 2002 exceeded the
"Minimum EBITDA".
The results of the technical fuels and chemical processing business have
been classified as discontinued operations in the accompanying consolidated
financial statements. Discontinued operations also includes the allocation
of interest expense (based on a ratio of net assets of discontinued
operations to total consolidated net assets). Allocated amounts are as
follows:
YEAR ENDED DECEMBER 31,
1998 1997 1996
----- ---- ----
(IN THOUSANDS)
$ - $112 $504
----- ---- ----
----- ---- ----
1996
On December 31, 1996, the Company sold 100% of the outstanding common
stock of Howell Transportation Services, Inc. ("HTS") to Lodestar Logistics,
Inc. ("Lodestar") for $2.6 million, consisting of $1.8 million in cash, a
$0.5 million note receivable and a $0.3 million receivable in the form of
services to be rendered by HTS for Seller. Lodestar is owned by the former
president of HTS, and the Company believes the sale price was equivalent to
an arm's-length transaction.
The $0.5 million non-revolving note bears interest at the Prime Rate for a
term of no longer than 84 months.
The note receivable and the receivable for future services are non-cash
transactions which are not reflected in the statement of cash flows for the
year ended December 31, 1996.
33
NOTE 4. INCOME TAXES
A summary of the provision for income taxes (benefit) from operations
included in the consolidated statements of earnings is as follows:
YEAR ENDED DECEMBER 31,
-------------------------------
1998 1997 1996
---- ---- ----
(In thousands)
Current:
Federal................................................................. $ - $ 501 $ 5,214
State................................................................... (119) 181 367
Deferred.................................................................... (36,218) 790 2,414
-------- -------- --------
Income taxes from continuing operations..................................... (36,337) 1,472 7,995
Income taxes from discontinued operations................................... 350 388 267
Income taxes from sale of discontinued operations........................... - 126 -
-------- -------- --------
$(35,987) $ 1,986 $ 8,262
-------- -------- --------
-------- -------- --------
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 carry forward were as follows:
YEAR ENDED DECEMBER 31,
-------------------------
1998 1997
---- ----
(In thousands)
Accrual of costs not deductible for tax..................................... $ 789 $ 1,325
Net operating loss carryforward............................................. 7,477 -
-------- --------
Total deferred tax assets................................................... 8,266 1,325
-------- --------
Differences between book and tax bases of property, plant and
equipment............................................................... (4,858) (26,396)
-------- --------
Total deferred tax liabilities.............................................. (4,858) (26,396)
-------- --------
Net deferred income taxes............................................. $ 3,408 $(25,071)
-------- --------
-------- --------
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,
--------------------------------
1998 1997 1996
---- ---- ----
(In thousands)
Provision for income taxes at the statutory rate......................... $(35,373) $1,625 $7,621
Statutory depletion in excess of cost basis.............................. - (278) (292)
State income taxes....................................................... (119) 181 367
Other.................................................................... (845) (56) 299
-------- ------ ------
$(36,337) $1,472 $7,995
-------- ------ ------
-------- ------ ------
As of December 31, 1998, the Company had net operating loss carryforwards
for federal income tax purposes of approximately $22 million, which expire in
2013.
NOTE 5. INVESTMENT IN GENESIS
On December 1, 1996, Genesis Crude Oil, L.P., a Delaware limited
partnership ("Buyer"), Genesis Energy, L.P., a Delaware limited partnership
("MLP") and Genesis Energy, L.L.C., a Delaware limited liability company
("LLC"), (collectively referred to hereinafter as "Genesis"), entered into a
Purchase & Sale and Contribution & Conveyance Agreement ("Agreement") with
Howell Corporation and certain of its subsidiaries ("Howell") and Basis
Petroleum, Inc. ("Basis"), a subsidiary of Salomon Inc. ("Salomon").
Pursuant to the
34
Agreement, Howell agreed to sell and convey certain of its assets to Buyer.
These assets consisted of the crude oil gathering and marketing operations
and pipeline operations of Howell ("Business").
Buyer was formed by MLP and LLC to acquire the Business from Howell and
similar assets from Basis. MLP is owned 98% by limited partners and 2% by
LLC, which is the general partner. LLC is owned 46% by Howell and 54% by
Basis. As a result of this transaction, Howell owns a subordinated limited
partner interest in Buyer of 9.01%, a direct general partner interest in
Buyer of 0.18% and a general partner interest through MLP of 0.74% of Buyer.
In accordance with the Agreement, Howell received cash of approximately
$74.0 million and 991,300 subordinated limited partner units in Buyer in
exchange for its sale and conveyance of the Business and recognized a gain in
the amount of approximately $13.8 million. The receipt of units is a
non-cash transaction which reduced property, plant and equipment and
increased investment in Genesis. Since this was non-cash, it is not
reflected in the statement of cash flows for the year ended December 31,
1996. Except as specifically provided in the Agreement, Howell retained all
liabilities related to the Business 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 Buyer for any breaches thereof. Claims for breaches of such
representations and warranties must be brought before December 3, 2001.
Howell also agreed to perform, and retain the liability for, the cleaning of
certain tanks used in the pipeline operations which cleaning was completed in
1997.
On the closing date, Howell entered into various agreements with Buyer,
MLP and LLC pursuant to the Agreement, including (a) a non-competition
agreement prohibiting Howell from competing with the Business for a period of
ten years; (b) an agreement relating to the purchase of crude oil by Howell
for use in its technical fuels business and the sale of crude oil by Howell
from its oil and gas exploration and production business; (c) an agreement
whereby Howell will provide certain transitional services to Buyer; (d) an
agreement whereby MLP will sell additional limited partner units to the
public and use the proceeds to redeem the subordinated limited partner units
in Buyer owned by Howell after certain conditions are met; and (e) an
agreement whereby one-half of the subordinated limited partner units owned by
Howell are pledged to secure Howell's indemnification of Buyer for
environmental liabilities.
Also at closing, Howell entered into an agreement with Salomon which
provides (a) an unconditional obligation of Howell to buy its 46% share of
additional limited partner interests ("APIs") from Salomon if Howell (as a
member of LLC) has approved an acquisition by Buyer and (b) to the extent
APIs are outstanding, an obligation by Howell to purchase 46% of such
outstanding APIs, but only to the extent of any distribution made to Howell
by Buyer on Howell's subordinated limited partner units.
Summarized financial information for the Buyer for the years ended December
31, 1998 and 1997, respectively, was as follows:
1998 1997
---- ----
(In thousands)
Revenues........................................................................ $ 2,233,475 $ 3,372,928
Net income...................................................................... $ 8,819 $ 9,848
Current assets.................................................................. $ 185,211 $ 232,197
Property & equipment, net....................................................... $ 95,083 $ 88,638
Total assets.................................................................... $ 297,168 $ 331,109
Current liabilities............................................................. $ 183,233 $ 224,533
Partners' capital............................................................... $ 98,135 $ 106,576
At December 31, 1998, the amount of investment in the Buyer includes
goodwill in the amount of $4.9 million which is being amortized over a period
of 20 years. Accumulated amortization at December 31, 1998, was $0.5 million.
Salomon has reported that on May 1, 1997, it sold the stock of Basis to
Valero Energy Corporation ("Valero"). On May 1, 1997, Basis informed the
Company that Basis intends to transfer its interest in LLC back to Salomon.
Pursuant to the agreement forming LLC, the Company had 30 days from the date
of receipt of such
35
notice to make an offer for Basis' interest in LLC. The Company decided not
to make an offer to purchase Basis' interest in LLC.
Basis is party to a number of agreements with Genesis, some of which may
have terminated in connection with the transfer to Valero and others which
may be terminated by Basis pursuant to their terms. Whether such contracts
will be terminated or revised by Basis and/or Genesis in the future and the
ultimate effect on Genesis of any such termination or revision cannot be
determined at this time, but may or may not have a material effect on Howell.
On July 29, 1997, the Board of Directors of LLC cancelled the $3.45
million note payable by Howell Crude Oil Company ("HCO") to LLC. The note was
distributed to HCO as a non-cash transaction and, as such, is not reflected
in the Consolidated Statement of Cash Flows for the year ended December 31,
1998.
NOTE 6. DEBT AND AVAILABLE CREDIT FACILITIES
Short-term and long-term debt of the Company as of December 31, 1998 and
1997, were as follows:
1998 1997
---- ----
(In thousands)
Note payable under a $127 million revolving credit/term loan agreement at December
31, 1998 and $150 million at December 31, 1997..................................... $124,000 $137,000
Less: Current maturities........................................................... 22,000 20,000
-------- --------
Balance, due 2002.................................................................. $102,000 $117,000
-------- --------
-------- --------
The Company had no capital lease obligations.
REVOLVING CREDIT/TERM LOAN AGREEMENT
The Company amended and restated the December 17, 1997 Credit Agreement
effective on 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 was
redetermined to $110 million prior to the 1998 sale of the Company's fee
mineral interest, and to $105 million after the sale. Tranche B is a term
loan with an amended borrowing availability of $30 million. The Company is
required to pay commitment fees on the unused portion of Tranche A at a rate
of 0.375% per annum while Tranche B is outstanding. After Tranche B has been
repaid, the commitment fee will be 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 ("Libor") rate per annum, or
the Base Rate (prime), plus the Applicable Margin. The Applicable Margin is
determined by the Borrowing Base Utilization Percentage. It ranges 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 with
other persons, 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 1.5 to 1.0 at the end of any fiscal quarter.
On December 17, 1998, the Company was able to reduce the outstanding
balance of Tranche A by $5 million and Tranche B by $8 million as a result of
the sale of its fee mineral interest. See Note 3.
As of December 31, 1998, the Tranche A interest rate was 8.0625% per annum
on $102 million and the Tranche B interest rate was 10.5625% per annum on $22
million.
36
At December 31, 1998, the Company had cash and cash equivalents of $5.9
million and $3 million available to it under the Credit Facility. Should a
decline in the value of the Company's proved reserves occur during 1999, the
bank could reduce the Borrowing Base, thereby causing mandatory payments
under the Credit Facility. While the Company does not expect this to happen
in 1999, such payments would adversely affect the Company's ability to carry
out its capital expenditure program and could cause the Company to accelerate
its plans to recapitalize its debt through the public or private placement of
securities. See Note 1 "Recent Events" for proceeds received in 1999 applied
to reduce the outstanding borrowing under the Credit Facility.
The fair value of the Company's long-term debt at December 31, 1998 and 1997,
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, 1998 and 1997, 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, 1998 and 1997, the Company had 50,000,000 shares of
common stock authorized.
EMPLOYEE STOCK OPTIONS
The Company maintains nonqualified stock option plans that provide for
granting of options for the purchase of common stock to key employees. These
stock options may be granted for periods up to 10 years and are generally
subject to vesting up to four years. At December 31, 1998, no shares were
available for future option grants.
Stock option activity for the Company during 1998, 1997, and 1996 was as
follows:
1998 1997 1996
---------------------- --------------------- -----------------------
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.................. 936,030 $12.91 431,914 $11.24 466,217 $10.96
Granted........................ 33,250 $16.50 721,380 $13.37 90,900 $14.51
Exercised...................... (7,140) $8.88 (164,808) $10.76 (13,750) $10.53
Expired........................ - - (10,908)
Forfeited...................... (13,975) (52,456) (100,545)
-------- -------- --------
Stock options outstanding,
end of year........................ 948,165 $13.06 936,030 $12.91 431,914 $11.24
-------- ------ -------- ------ -------- ------
-------- ------ -------- ------ -------- ------
At December 31, 1998, options were exercisable for 400,340 shares at a
weighted average exercise price of $12.37. The range of exercise prices on
outstanding options at December 31, 1998, was $8.31 to $18.75. The remaining
contractual life of these options was approximately 8.5 years.
37
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:
1998 1997 1996
---- ---- ----
Net (loss) earnings.......................... $(67,553,000) $ 4,081,000 $14,077,000
Fair value adjustment........................ (770,000) (482,000) (107,000)
------------ ------------ -----------
Pro Forma net (loss) earnings................ $(68,323,000) $ 3,599,000 $13,970,000
------------ ------------ -----------
------------ ------------ -----------
(Loss) earnings per share as reported - basic $ (12.79) $ 0.32 $ 2.36
------------ ------------ -----------
------------ ------------ -----------
Pro Forma (loss) earnings per share - basic.. $ (12.93) $ 0.23 $ 2.34
------------ ------------ -----------
------------ ------------ -----------
(Loss) earnings per share as reported - diluted $ (12.79) $ 0.31 $ 1.97
------------ ------------ -----------
------------ ------------ -----------
Pro Forma (loss) earnings per share - diluted $ (12.93) $ 0.22 $ 1.96
------------ ------------ -----------
------------ ------------ -----------
The weighted average fair value of options granted during 1998, 1997 and
1996 was $7.94, $5.46 and $8.17, 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 1998, 1997 and 1996.
1998 1997 1996
---- ---- ----
Weighted average expected life: 8.5 years 8.5 years 10 Years
Volatility factor: 42.33% 24.38% 36.20%
Dividend yield: 1.00% 1.00% 1.00%
Weighted average risk free interest: 3.64% 6.19% 8.00%
NOTE 8. SEGMENT INFORMATION
In 1998, the Company adopted Financial Accounting Standards Board
Statement No. 131, "Disclosures About Segments of An Enterprise and Related
Information."
The principal business of the Company consists of the exploration,
development and acquisition of oil and gas properties and the production and
sale of crude oil and liquids and natural gas. The Company has determined
that its reportable segments are those that are based on the Company's
principal and non-principal business activities involved in continuing
operations. The Company's reportable segments are Oil and Gas Production and
Crude Oil Marketing and Transportation. See Note 5 for discussion of the
Crude Oil Marketing and Transportation segment. All of the Company's
operations and assets are conducted and located in the United States.
The accounting policies of the segments are the same as those described
in the "Summary of Significant Accounting Policies." The Company allocates
100% of its resources to its principal business activity.
38
Financial information about the Company's continuing operations for each
of the years ended December 31, 1998, 1997 and 1996, is summarized as follow:
CRUDE OIL
MARKETING
& INTER-
OIL & GAS TRANSPORT- SEGMENT
PRODUCTION ATION OTHER SALES TOTAL
---------- ---------- ----- ------- -----
(In thousands)
DECEMBER 31, 1998
Revenues............................ $ 51,422 $ - $ - $ - $ 51,422
--------- --------- -------- --------- ----------
Operating loss ..................... $ (90,525) $ - $ (24) $ (90,549)
--------- --------- --------
General corporate expense........... (3,110)
Equity in net earnings of Genesis... $ 635 635
---------
Other expense, net.................. (11,132)
----------
Loss from continuing operations
before income taxes............. $ (104,156)
----------
Identifiable assets................. $ 128,475 $ 17,413 $ 11,294 $ 157,182
--------- --------- -------- ----------
Capital expenditures................ $ 22,328 $ - $ 279 $ 22,607
--------- --------- -------- ----------
Depreciation, depletion and
amortization.................... $ 113,756 $ - $ 114 $ 113,870
--------- --------- -------- ----------
DECEMBER 31, 1997
Revenues............................ $ 34,663 $ - $ - $ - $ 34,663
--------- --------- -------- --------- ----------
Operating profit (loss)............. $ 8,396 $ - $ (67) $ 8,329
--------- --------- --------
General corporate expense........... (3,044)
Equity in net earnings of Genesis... $ 906 906
---------
Other expense, net.................. (1,411)
----------
Earnings from continuing operations
before income taxes............. $ 4,780
----------
Identifiable assets................. $ 244,369 $ 19,149 $ 3,193 $ 266,711
--------- --------- -------- ----------
Capital expenditures................ $ 132,169 $ - $ 604 $ 132,773
--------- --------- -------- ----------
Depreciation, depletion and
amortization.................... $ 9,316 $ - $ 144 $ 9,460
--------- --------- -------- ----------
DECEMBER 31, 1996
Revenues............................ $ 33,868 $ 666,086 $ - $ (15,438) $ 684,516
--------- --------- -------- --------- ----------
Operating profit (loss)............. $ 8,682 $ 9,610 $ (136) $ 18,156
--------- --------- --------
General corporate expense........... (3,457)
Equity in net earnings of Genesis... $ 181 181
---------
Other expense, net.................. (6,947)
Gain on conveyance of assets........ $ 13,841 13,841
--------- ----------
Earnings from continuing operations
before income taxes............ $ 21,774
----------
Identifiable assets................. $ 106,989 $ 20,095 $ 30,113 $ 157,197
--------- --------- -------- ----------
Capital expenditures................ $ 5,575 $ 5,150 $ 1,653 $ 12,378
--------- --------- -------- ----------
Depreciation, depletion
and amortization................ $ 9,416 $ 4,123 $ 278 $ 13,817
--------- --------- -------- ----------
39
In addition to the results of the Company's oil and gas exploration and
production activities, the oil and gas production segment information
includes the gas marketing activities of the Company and the results of sales
of production of carbon dioxide, helium and sulfur from the LaBarge Project.
Inter-segment sales by the oil and gas production segment to the crude oil
marketing and transportation segment were $0, $0 and $15,438 in 1998, 1997
and 1996, respectively. These amounts have been eliminated in consolidation.
Marathon Oil Company, a customer of the crude oil marketing and
transportation segment, accounted for approximately 18% of consolidated
revenues in 1996.
As a result of the sale in 1997 to SFC, referred to in Note 3, segment
data for 1996 have been restated to conform to the 1998 presentation.
NOTE 9. LITIGATION
On July 11, 1995, the Company received a demand letter from several
working interest owners in the North Frisco City Field and in the North Rome
Field indicating the Company had not paid according to the terms of a "call
on production." The Company was granted a call on a portion of this
production but never exercised the call. Accordingly, the Company has filed
petitions for declaratory judgment to that effect in cases styled HOWELL
PETROLEUM CORPORATION, ET AL, VS. SHORE OIL COMPANY, ET AL, District Court of
Harris County, Texas; No. 95-037480 and HOWELL PETROLEUM CORPORATION, ET AL,
VS. TENEXCO, INC., ET AL, District Court of Harris County, Texas; No.
95-037970. The defendants in this action have counterclaimed against the
Company. These claims are similar in nature to the Alabama and Mississippi
royalty litigation. One of the defendants, John Faulkinberry, has filed a
counterclaim against the Company seeking actual damages of $75,000 and
punitive damages of $100,000,000. Effective July 14, 1997, the Company
settled with John Faulkinberry as well as several other working interest
owners. The terms of the settlement are confidential, but the amounts paid
in settlement were not material to the Company's financial condition, results
of operations or cash flows. The case (as to the remaining interest owners)
was tried during the week of December 7, 1998. On January 6, 1999 the trial
court granted the request of the Company's subsidiaries for a declaratory
judgment. The trial court ruled that neither of the Company's subsidiaries
had exercised the call and denied the defendants' counterclaim for monetary
damages. The trial court also awarded the subsidiaries attorney fees of
$373,333, plus 10% interest on all sums owing to the subsidiaries.
Subsequently, this case was settled.
Related to this matter, several royalty owners have filed lawsuits against
the Company in Alabama and Mississippi concerning pricing in the North Frisco
City Field. The lawsuits allege the Company violated its contracts with the
plaintiffs by not paying the plaintiffs ". . . the highest available price
for oil." Damages claimed by the plaintiffs include approximately $3.8
million and are based on numerous damage theories including, but not limited
to, allegations of breach of contract and fraud. The complaints also seek
unspecified punitive damages in the Alabama lawsuits and $7 million in
punitive damages in the Mississippi lawsuit. The Company filed answers
denying all charges. The Company does not believe that the ultimate
resolution of these matters will have a materially adverse effect on the
financial position, results of operations or cash flows of the Company. On
July 28, 1997, the Company settled the Mississippi lawsuit. On March 30,
1998 a tentative settlement was reached with the Alabama Class
representative. On February 24, 1999 the trial court entered a preliminary
approval order. The final fairness hearing is scheduled for May 5, 1999.
The amounts paid in settlement of both cases were not material to the
Company's financial condition, results of operations or cash flows.
There are various other lawsuits and claims against the Company, none of
which, in the opinion of management, will have a materially adverse effect on
the Company.
NOTE 10. COMMITMENTS AND CONTINGENCIES
The Company is subject to various environmental regulations and laws.
Procedures exist within the Company to monitor compliance and assess the
potential environmental exposure of the Company. The Company believes that
such exposure is not materially adverse to its financial position, results of
operations or cash flows.
40
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 acquired by Buyer under the Agreement, however, the Company
retained certain environmental liabilities which management believes will not
have a material financial impact on the financial position, results of
operations or cash flows of the Company. See Note 5.
The Channelview facility was discharging wastewater pursuant to a state
wastewater discharge permit. Industries located in the state of Texas are
required to obtain wastewater discharge permits from the state and from the
Environmental Protection Agency ("EPA"). When the Company purchased the
Channelview facility in 1988, it requested and obtained a transfer of these
permits. In 1990, the Company applied for a renewal of both the federal and
the state wastewater permits. The state permit was reissued in 1992. During
1993, the Company determined that the federal wastewater discharge permit may
have expired prior to the EPA's transfer of the permit to the Company. The
EPA has been contacted to resolve this issue, and the Company has been
negotiating to obtain a renewed permit. Penalties may potentially be imposed
upon the Company as a result of this matter; however, until this matter is
resolved, the amount of such penalties, if any, cannot be quantified. While
penalties may be material and the actions of regulatory bodies are not
subject to accurate prediction, based on information currently available to
the Company and on the circumstances present at its Channelview facility
(including the existence of the state permit, the Company's compliance with
the more stringent state permit, and the ability, if required, to operate the
Channelview facility utilizing holding tanks and offsite third party
treatment facilities in the absence of a permit), the Company does not
believe that this matter will have a materially adverse effect on the
financial position, results of operations or cash flows of the Company. In
1997, the Channelview facility was sold to SFC, however, the Company retained
certain environmental liabilities for a period of five years which management
believes will not have a material financial 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.
Amoco has indemnified the Company for non-environmental third party claims
relating to the period of time prior to closing that are identified within
eighteen months after closing if the claims exceed three percent of the
purchase price in the aggregate. Amoco also will indemnify the Company for
environmental third party claims relating to the period of time prior to
closing that are identified within twelve months after closing if the claims
exceed three percent of the purchase price in the aggregate but in no event
to exceed 50% of the purchase price.
Under the terms of the purchase agreement, Amoco has a call on certain oil
production from the properties acquired in the Acquisition. Beginning March
1, 1998, for a fifteen year period Amoco has a call, if exercised, on 4,000
barrels per day of sweet crude oil production net to the Company's interest
from the acquired Salt Creek field at a price per barrel equal to the average
of three postings chosen by the Company from an approved group plus $1.50;
provided, however, the maximum price paid shall not exceed Platt's Wyoming
Sweet Monthly Average and the minimum price paid shall not be less than
Platt's Wyoming Sweet Monthly Average minus $1.00. Beginning March 1, 1998,
for a seven year period Amoco has a call on 2,000 barrels per day of sour
crude oil production net to the Company's interest from the acquired Elk
Basin field and all of the sour crude oil production from the acquired Grass
Creek and Pitchfork fields at a price per barrel equal to the average of
three postings chosen by the Company from an approved group plus $0.25;
provided, however, the maximum price paid shall not exceed Platt's Wyoming
Sweet Monthly Average minus $2.75 and the minimum price paid shall not be
less than Platt's Wyoming Sweet Monthly Average minus $4.75. All crude oil
pricing is subject to gravity adjustment.
The Company occupies office and operational facilities and uses equipment
under operating lease arrangements. Expense of these arrangements amounted
to $425,000 in 1998, $425,000 in 1997 and $2,765,000 in 1996. At December
31, 1998, long-term commitments for lease of facilities and equipment totaled
approximately $4,207,000, consisting of $651,000, $672,000, $672,000,
$672,000 and $672,000 for the years 1999 through 2003, respectively, and
$868,000 thereafter.
41
NOTE 11. 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.
1998
INCREASE IN EARNINGS PER
INCREASE IN NUMBER OF INCREMENTAL
INCOME SHARES SHARE
------------- ----------- ------------
Options.................................... - 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
---------- ------ ---------
$(70,234,000) 5,470,021 $(12.84)
Common stock options....................... - 42,456
------------ --------- -------
$(70,234,000) 5,512,477 $(12.74) Antidilutive
Dividends on convertible preferred stock... $ 2,415,000 2,090,909
------------ --------- -------
$(67,819,000) 7,603,386 $ (8.92) Antidilutive
------------ --------- -------
------------ --------- -------
Note: Because diluted EPS from continuing operations increases from
$(12.84) to $(12.74) when common stock options are included in the
computation and because diluted EPS increases from $(12.74) to $(8.92) 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 $(12.84).
1997
INCREASE IN EARNINGS PER
INCREASE IN NUMBER OF INCREMENTAL
INCOME SHARES SHARE
------------- --------- ------------
Options.................................... - 212,556 -
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
------------- --------- ---------
$ 893,000 5,142,558 $0.17
Common stock options....................... - 212,556
------------- --------- -----
$ 893,000 5,355,114 $0.17 Dilutive
Dividends on convertible preferred stock... $ 2,415,000 2,090,909
------------- --------- -----
$ 3,308,000 7,446,023 $0.44 Antidilutive
------------- --------- -----
------------- --------- -----
42
Note: Because diluted EPS from continuing operations increases from
$0.17 to $0.44 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 $0.17.
1996
EARNINGS
INCREASE IN PER
INCREASE IN NUMBER OF INCREMENTAL
INCOME SHARES SHARE
----------- ----------- -----------
Options.................................... - 100,534 -
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
----------- --------- ---------
$11,364,000 4,937,310 $2.30
Common stock options....................... - 100,534
----------- --------- ---------
$11,364,000 5,037,844 $2.26 Dilutive
Dividends on convertible preferred stock... $ 2,415,000 2,090,909
----------- --------- ---------
$13,779,000 7,128,753 $1.93 Dilutive
----------- --------- ---------
----------- --------- ---------
NOTE 12. SUPPLEMENTARY OIL AND GAS PRODUCING INFORMATION (UNAUDITED)
RECENT EVENTS
The proposed sale of the Pitchfork and Grass Creek, Wyoming fields and the
actual sale of LaBarge, Wyoming fields for a total of $28.2 million represent
7.0 million barrels of oil equivalent ("MMBOE") out of the 43.1 MMBOE of the
Company's proved oil and gas reserves at December 31, 1998 and approximately
2.2 MBOE per day of the Company's 11.9 MBOE 1998 daily production. These
transactions also represent 460 gross and 135 net oil wells, 21 gross and 9
net gas wells, 10,409 gross and 2,508 net developed acres, and 320 gross and
320 net undeveloped acres.
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, except for the reserves purchased from Amoco, at December
31, 1998, 1997, and 1996, were reviewed by independent petroleum consultants,
H. J. Gruy and Associates, Inc. The December 31, 1998 and 1997 reserves,
associated with the Wyoming properties acquired from Amoco, were reviewed by
independent petroleum consultants, Ryder Scott & Associates. The estimates
for 1995 were reviewed by L. A. Martin & Associates, Inc. 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.
43
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
Oil Gas
(BBLs) (MCF)
------ -----
As of December 31, 1995...................................... 8,600,036 60,580,800
Revisions of previous estimates.............................. 459,820 1,007,250
Extensions, discoveries & other additions.................... 122,081 2,424,077
Production................................................... (1,207,906) (3,273,257)
Sales of minerals in place................................... (14,858) (484,520)
---------- ----------
As of December 31, 1996...................................... 7,959,173 60,254,350
Revisions of previous estimates.............................. 623,774 (5,737,208)
Extensions, discoveries & other additions.................... 420,500 4,725,000
Purchases of minerals in place............................... 34,413,669 27,702,395
Production................................................... (1,246,596) (3,311,197)
---------- ----------
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
---------- ----------
---------- ----------
Proved developed reserves:
December 31, 1995............................................ 7,662,263 60,125,223
---------- ----------
---------- ----------
December 31, 1996............................................ 6,995,835 58,444,115
---------- ----------
---------- ----------
December 31, 1997............................................ 40,711,561 81,709,974
---------- ----------
---------- ----------
December 31, 1998............................................ 26,701,736 75,756,389
---------- ----------
---------- ----------
Total proved reserves at year-end 1998 were 43,072 MBOE compared to
56,109 MBOE at year-end 1997. This change was related almost entirely to
downward revisions associated with lower oil and gas prices. The price
sensitivity of the Company's reserve base is illustrated by the fact that if
year-end 1998 reserves were calculated using year-end 1997 pricing, total
proved reserves would have remained basically unchanged at 1997 reserve levels.
Proved oil reserves at December 31, 1998, include 1.4 million barrels of
natural gas liquids ("NGL").
In addition to the oil and gas reserves shown above, the Company, through
its participation in the LaBarge Project in southwestern Wyoming, had proved
carbon dioxide reserves of 57,140 MMCF and proved helium reserves of 2,570
MMCF at December 31, 1998. The LaBarge Project was sold in January 1999.
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, 1998 DECEMBER 31, 1997
----------------- -----------------
(In thousands)
Capitalized Costs:
Oil and gas producing properties, all being amortized... $ 385,048 $ 371,975
Unproven properties..................................... 43,263 41,017
Fee mineral interests, unproven......................... - 18,123
--------- ---------
Total.................................................. $ 428,311 $ 431,115
--------- ---------
--------- ---------
Accumulated depreciation, depletion and amortization
(includes impairment of oil & gas properties).......... $ 307,118 $ 205,199
--------- ---------
--------- ---------
44
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,
---------------------------------
1998 1997 1996
---- ---- ----
(In thousands)
Property acquisition:
Unproved properties..................................... $ 3,627 $ 41,904 $ 1,665
Proved properties....................................... 7,614 82,737 -
Exploration............................................... 3,460 5,994 3,526
Development............................................... 7,626 1,534 384
---------- -------- ---------
$ 22,327 $132,169 $ 5,575
---------- -------- ---------
---------- -------- ---------
In 1998, 1997 and 1996, $18,123,000, $57,000 and $8,000 of costs of
unproved mineral interests, respectively, were transferred to the full-cost
pool, representing the costs of mineral properties that were drilled and
evaluated during the periods. The 1998 amount also represents the sale of the
minerals on December 17, 1998. These transfers of costs are not reflected in
the table above. See Note 3 of Notes to the Consolidated Financial Statement.
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 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
production from its fee mineral interests which was sold in December 1998.
YEAR ENDED DECEMBER 31,
---------------------------------
1998 1997 1996
---- ---- ----
(In thousands)
Revenues.................................................. $ 48,538 $ 29,089 $ 28,162
Production (lifting) costs................................ 25,703 10,646 9,174
Depreciation, depletion and amortization.................. 11,589 9,316 9,416
Impairment of oil & gas properties........................ 102,167 - -
-------- -------- --------
(90,921) 9,127 9,572
Income tax (benefit) expense.............................. (30,913) 2,523 3,318
-------- -------- --------
Results of operations (excluding
corporate overhead and interest cost) ................ $(60,008) $ 6,604 $ 6,254
-------- -------- --------
-------- -------- --------
Included in the 1998, 1997 and 1996, amounts above are $1,314,000,
$2,005,000, and $2,301,000 of revenues and $121,000, $174,000, and $181,000
of production costs, respectively, from the production of the Company's
producing fee mineral interests which was 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 1998 and 1997.
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.
(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.
45
(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, DECEMBER 31,
1998 1997
------------ ------------
(In thousands)
Future cash inflows............................................................... $388,355 $792,393
Future production costs........................................................... 249,066 490,059
Future development costs.......................................................... 17,597 16,423
Future income tax expenses........................................................ 0 42,000
-------- --------
Future net cash flows............................................................. 121,691 243,911
10% annual discount for estimated timing of cash flows............................ 60,363 104,336
-------- --------
Standardized measure of discounted future net cash flows relating to proved
oil and gas reserves.......................................................... $ 61,328 $139,575
-------- --------
-------- --------
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 declines 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,
------------------------------------
1998 1997 1996
---- ---- ----
(In thousands)
Sales and transfers, net of production costs...................... $ (22,836) $ (18,443) $ (18,988)
Net changes in prices and production costs (56,084) (113,015) 58,036
Extensions and discoveries, net of future production and
development costs............................................... 12,775 9,950 5,382
Purchases of minerals in place.................................... 6,586 157,709 -
Sales of minerals in place........................................ 1,425 - (494)
Previously estimated development costs incurred during the
period.......................................................... (30) (178) -
Revisions of quantity estimates................................... (20,512) (1,006) 4,844
Accretion of discount............................................. 13,958 10,406 8,215
Net change in income taxes........................................ 21,017 7,190 (13,930)
Changes in production rates (timing) and other.................... (34,546) (17,093) (21,157)
--------- ---------- ----------
Net change.................................................... $ (78,247) $ 35,520 $ 21,908
--------- ---------- ----------
--------- ---------- ----------
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,
1998, the Company's estimated proved reserves were 29.9 MMBO and plant
liquids and 78.8 BCF of gas. The Company's major producing properties
include Salt Creek, Elk Basin, North Frisco City, Main Pass 64, Grass Creek
and LaBarge fields. These six major fields represent 36.0 MMBOE, or 84% 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.
46
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 from Exhibit 2.1
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 from Exhibit 2 of the Company's
Current Report on Form 8-K dated January 2, 1998.
3.1 ** Certificate of Incorporation, as amended, of the Company.
3.1(a) Certificate of Amendment to the Certificate of Incorporation of the
Company (filed as an exhibit to the Company's Report on Form
10-Q for the quarterly period ended June 30, 1994).
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.
10.4 ** Form of Stock Option Agreement.
10.5 Third Amendment to the Howell Corporation 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.
10.13 ** Split Dollar Life Insurance Agreement dated January 27, 1990,
between the Company, Steven K. Howell, Douglas W. Howell, David
L. Howell, Bradley N. Howell and Charles W. Hall, Trustee of
the Howell 1990 Children's Trusts.
10.14 ** Deferred Compensation and Salary Continuation Agreement dated
January 23, 1990, by and between the Company and Paul N.
Howell.
10.15 ** United States of America Department of Energy Economic Regulatory
Administration Consent Order with the Company dated as of
February 23, 1989.
10.16 ** Letter from the Department of Energy to the Company dated September
10, 1992, modifying the terms of the Consent Order.
10.19 ** United States Department of the Interior Bureau of Land Management
Oil and Gas Lease of Submerged Lands under the Outer
Continental Shelf Land Act by and between the United States of
America and Howell Petroleum Corporation effective as of
December 1, 1981.
47
10.20 ** 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.
10.21 ** Assignment, Bill of Sale and conveyance by Total Petroleum, Inc.,
as assignor, to Oil Acquisitions, Inc., dated January 19, 1989.
10.22 ** Unit Operating Agreement 7300' Sand Unit, Blocks 64 and 65 Main
Pass Area, Offshore Plaquemines Parish, Louisiana, by and among
Howell Petroleum Corporation, Oil Acquisitions, Inc., Woods
Petroleum Corporation, BHP Petroleum (Americas) Inc. and
Challenger Minerals, Inc., dated as of March 1, 1990.
10.23 ** Unit Agreement for Outer Continental Shelf Development and
Production Operations on the 7300' Sand Unit, Blocks 64 and 65,
Main Pass Area, Offshore Plaquemines Parish, Louisiana, by and
among Howell Petroleum Corporation, Oil Acquisitions, Inc.,
Woods Petroleum Corporation, BHP Petroleum (Americas) Inc. and
Challenger Minerals, Inc., dated as of April 19, 1990.
10.24 ** Processing Agreement by and between Howell Petroleum Corporation
and Exxon Company, U.S.A., effective as of August 1, 1988.
10.25 Purchase and Sale Agreement between Federal Intermediate Credit
Bank of Jackson and Howell Petroleum Corporation (filed as an
exhibit to the Company's Report on Form 10-Q for the quarterly
period ended June 30, 1993).
10.26 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).
10.27 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).
10.28 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).
10.29 Howell Corporation 1997 Stock Option Plan.
21 * Subsidiaries of the Company.
23 * Consent of Deloitte & Touche LLP.
27 * Financial Data Schedule.
48