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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, 1997
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, Series A, National Association of
$1 par value Securities Dealers, Inc.
Automated Quotation System
Securities registered pursuant to Section 12(g) of the Act:
NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
---- ----
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
|X|
---
The market value of all shares of Common Stock on March 1, 1998 was
approximately $82.0 million. The aggregate market value of the shares held by
nonaffiliates on that date was approximately $57.6 million. As of March 1, 1998,
there were 5,464,642 common shares outstanding.
Documents Incorporated by Reference:
Howell Corporation proxy statement to be filed in connection with the 1998
Annual Shareholders' Meeting (to the extent set forth in Part III of this Form
10-K).
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HOWELL CORPORATION
1997 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 8. Financial Statements and Supplementary Data............... 18
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure....................... 18
PART III
Item 10. Directors and Executive Officers of the Registrant........ 19
Item 11. Executive Compensation.................................... 19
Item 12. Security Ownership of Certain Beneficial Owners and
Management................................................ 20
Item 13. Certain Relationships and Related Transactions............ 20
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K............................................... 20
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 estimate, 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 primarily 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.
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") and are concentrated in Wyoming and along the Gulf Coast, both onshore
and offshore. At December 31, 1997, the Company's estimated proved reserves were
42.2 million barrels of oil and plant liquids and 83.6 billion cubic feet of
gas. Of such reserves, approximately 34.2 million barrels of oil and plant
liquids and 25.9 billion cubic feet of gas are associated with producing
properties located primarily in Wyoming, which were acquired on December 18,
1997, (but effective as of December 1, 1997) for $115.4 million from Amoco
Production Company ("Acquisition"). The Acquisition created a new core area for
the Company and included the Salt Creek, Elk Basin and Grass Creek fields
discussed below. Following the Acquisition, 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 41.7 MMBOE, or 74% of
the Company's total proved reserves. In addition, the Company owns fee mineral
interest in 876,367 net acres in Mississippi, Alabama and Louisiana.
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 43 employees; however, effective March 1, 1998, HPC will add approximately
60 additional employees as a result of the Acquisition.
In the purchase agreement relating to the Acquisition, the Company also
agreed to purchase from Amoco Production Company ("Amoco") the Beaver Creek Unit
in Wyoming ("Beaver Creek Unit") for approximately $187 million. Completion of
the acquisition of the Beaver Creek Unit is subject to the satisfactory
resolution of litigation relating to a preferential purchase right. The Company
is unable to predict at this time whether or when the purchase of the Beaver
Creek Unit will occur.
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, 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 Specified Fuels & Chemicals,
L.L.C. ("Specified").
The assets purchased by Specified 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) Specified 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.
In consideration for the assets sold to Specified, 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 is entitled to receive an additional payment equal
to 55% of the amount by which Specified'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 are $5.0
million, $5.175 million, $5.35 million, $5.525 million and $5.7 million,
respectively. Specified is 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 is initially set at $5.7 million if the repurchase occurs
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 occurs
during the twelve-month period ending June 30, 2002.
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.
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 (referred to hereafter as the "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 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, 1997, the Company had 60 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 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 plans to replace
these plans with a 401(K) plan. Effective March 1, 1998, the Company will add
approximately 60 employees associated with the Acquisition.
Item 2. Properties
A. Supplementary Oil and Gas Producing Information
The oil and gas producing activities of the Company are summarized below.
Substantially all of the Company's producing properties are subject to certain
restrictions under the Company's credit facility. See Note 5 of Notes to
Consolidated Financial Statements.
Oil and Gas Wells
As of December 31, 1997, 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...................................... 1,932 811
Gas wells...................................... 304 25
----- ---
Total..................................... 2,236 836
_________________
(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, 1997,
1996 and 1995, have been audited by independent petroleum consultants, H. J.
Gruy and Associates, Inc. The December 31, 1997, reserves associated with the
Wyoming properties acquired from Amoco were reviewed by independent petroleum
consultants, Ryder Scott & Associates. The estimates for the prior years 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.
Except for the Consent Statement filed on September 2, 1997 concerning the
Voyager acquisition, the Company has not filed any estimates of reserves with
any federal authority or agency during the past year other than reserve
estimates associated with the Voyager acquisition and estimates contained in its
last annual report on Form 10-K. Set forth are estimates of the Company's net
proved oil and gas reserves, all located in the United States.
Estimated Quantities of Proved Oil and Gas Reserves
Oil Gas
(Bbls) (Mcf)
------ -----
As of December 31, 1994................... 7,215,756 70,938,590
Revisions of previous estimates........... (555,469) (11,578,149)
Extensions, discoveries & other additions. 2,523,526 3,893,092
Purchases of minerals in place............ 961,025 1,025,383
Production................................ (1,383,881) (3,526,803)
Sales of minerals in place................ (160,921) (171,313)
---------- -----------
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
========== ===========
Proved developed reserves:
December 31, 1994......................... 6,201,176 63,677,432
========== ===========
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
========== ===========
Proved oil reserves at December 31, 1997, include 2.6 million barrels of
natural gas liquids ("NGL").
The reserves as of December 31, 1997, shown in the table above, include
428,638 barrels of oil and 3,603,136 Mcf of gas attributable to the Company's
producing fee mineral interests.
In addition to the oil and gas reserves shown above, HPC, through its
participation in the LaBarge Project in southwestern Wyoming, had proved carbon
dioxide reserves of 57,988,934 Mcf and proved helium reserves of 2,607,821 Mcf
at December 31, 1997.
Oil and Gas Leaseholds
The table below sets forth the Company's ownership interest in leaseholds
as of December 31, 1997. The oil and gas leases in which the Company has an
interest are for varying primary terms, and many require the payment of delay
rentals to continue the primary term. The leases may be surrendered by the
Company at any time by notice to the lessors, by the cessation of production or
by failure to make timely payment of delay rentals.
Developed(1) Undeveloped
-------------- ---------------
Gross Net Gross Net
Acres Acres Acres Acres
----- ----- ----- -----
Alabama............................. 6,583 2,374 4,093 1,346
Louisiana........................... 2,445 767 3,267 691
Mississippi......................... 3,611 1,095 12,138 3,951
North Dakota........................ 7,440 1,710 1,040 130
Texas............................... 26,509 5,752 9,897 3,390
Wyoming............................. 37,851 16,458 27,811 11,837
All other states combined........... 4,681 470 1,934 450
Offshore............................ 7,025 5,589 - -
------ ------ ------ ------
Total........................... 96,145 34,215 60,180 21,795
====== ====== ====== ======
In addition to the acreage under leaseholds as shown above, the Company
owns the fee mineral acreage shown in the table below:
Developed(1) Undeveloped
-------------- ---------------
Gross Net Gross Net
Acres Acres Acres Acres
----- ----- ----- -----
Alabama............................. 2,909 1,454 618,576 308,909
Louisiana........................... 6,381 907 9,520 4,531
Mississippi......................... 21,917 10,961 1,115,495 549,605
------ ------ --------- -------
Total........................... 31,207 13,322 1,743,591 863,045
====== ====== ========= =======
_________________
(1)Acres spaced or assignable to productive wells.
Drilling Activity
The following table shows the Company's net productive and dry exploratory
and development wells drilled in the United States:
Exploratory Development
------------------ ------------------
Net Net Net Net
Productive Dry Productive Dry
Year Wells Holes Wells Holes
---- ----- ----- ----- -----
1997 .89 .25 .10 .60
==== ==== ==== ====
1996 .16 1.45 - -
==== ==== ==== ====
1995 1.64 1.08 0.72 1.95
==== ==== ==== ====
The table above reflects only the drilling activity in which the Company
had a working interest participation. In addition, in 1997, 1996 and 1995, 24,
22 and 14 gross productive wells, respectively, were drilled on the Company's
fee mineral acreage.
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:
United States
----------------------
1997 1996 1995
---- ---- ----
Average sales prices:
Oil and NGL (per Bbl)............................ $17.15 $17.52 $15.67
Natural gas (per Mcf)............................ $ 2.33 $ 2.06 $ 1.47
Production (lifting) costs (per equivalent barrel of
production)...................................... $ 5.92 $ 5.23 $ 4.47
Amortization (per equivalent barrel of production).. $ 5.18 $ 5.37 $ 5.20
Natural gas production is converted to barrels using its estimated energy
equivalent of six Mcf per barrel.
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, 1997 December 31, 1996
----------------- -----------------
(In thousands)
Capitalized Costs:
Oil and gas producing properties,
all being amortized............... $ 371,975 $ 280,766
Unproven properties................. 41,017 -
Fee mineral interests, unproven..... 18,123 18,180
--------- ---------
Total............................. $ 431,115 $ 298,946
========= =========
Accumulated depreciation, depletion
and amortization.................. $ 205,199 $ 195,883
========= =========
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,
---------------------------
1997 1996 1995
---- ---- ----
(In thousands)
Property acquisition:
Unproved properties................. $ 41,904 $1,665 $ 790
Proved properties................... 82,737 - 6,218
Exploration........................... 5,994 3,526 2,830
Development........................... 1,534 384 5,111
-------- ------ -------
$132,169 $5,575 $14,949
======== ====== =======
In 1997, 1996 and 1995, $57,000, $8,000 and $12,000 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. These transfers of costs are not reflected in the table
above.
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.
Year Ended December 31,
---------------------------
1997 1996 1995
---- ---- ----
(In thousands)
Revenues...................................... $29,089 $28,162 $27,011
Production (lifting) costs.................... 10,646 9,174 8,810
Depreciation, depletion and amortization...... 9,316 9,416 10,259
------- ------- -------
9,127 9,572 7,942
Income tax expense............................ 2,523 3,318 2,396
------- ------- -------
Results of operations (excluding
corporate overhead and interest cost)....... $ 6,604 $ 6,254 $ 5,546
======= ======= =======
Included in the 1997, 1996 and 1995, amounts above are $2,005,000,
$2,301,000 and $1,992,000 of revenues and $174,000, $181,000 and $146,000 of
production costs, respectively, from the production of the Company's producing
fee mineral interests.
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 1997 and 1996. 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,
1997 1996
------------ ------------
(In thousands)
Future cash inflows..................................... $792,393 $398,711
Future production costs................................. 490,059 178,157
Future development costs................................ 16,423 10,583
Future income tax expenses.............................. 42,000 55,675
-------- --------
Future net cash flows................................... 243,911 154,296
10% annual discount for estimated timing of cash flows.. 104,336 50,241
-------- --------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves............... $139,575 $104,055
======== ========
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,
---------------------------
1997 1996 1995
---- ---- ----
(In thousands)
Sales and transfers, net of production costs.... $(18,443) $(18,988) $(18,201)
Net changes in prices and production costs...... (113,015) 58,036 15,492
Extensions and discoveries, net of future
production and development costs............. 9,950 5,382 24,475
Purchases of minerals in place.................. 157,709 - 7,248
Sales of minerals in place...................... - (494) (1,319)
Previously estimated development costs
incurred during the period................... (178) - (1,079)
Revisions of quantity estimates................. (1,006) 4,844 (13,690)
Accretion of discount........................... 10,406 8,215 6,844
Net change in income taxes...................... 7,190 (13,930) (1,706)
Changes in production rates (timing) and other.. (17,093) (21,157 (4,352)
-------- -------- --------
Net change.................................. $ 35,520 $ 21,908 $ 13,712
======== ======== ========
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,
1997, the Company's estimated proved reserves were 42.2 million barrels of oil
and plant liquids and 83.6 billion cubic feet of gas. Of such reserves,
approximately 34.2 million barrels of oil and plant liquids and 25.9 billion
cubic feet of gas are associated with producing properties located primarily in
Wyoming, which were acquired on December 18, 1997, (but effective as of December
1, 1997) for $115.4 million from Amoco. The Acquisition created a new core area
for the Company and included the Salt Creek, Elk Basin and Grass Creek fields
discussed below. Following the Acquisition, 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 41.7 MMBOE, or 74% of
the Company's total proved reserves. In addition, the Company owns fee mineral
interest in 876,367 net acres in Mississippi, Alabama and Louisiana.
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 666 producing wells and 598 injection
wells located in the LOU on a flood pattern of approximately five acre well
spacing. As of December 31, 1997, the field was producing a net of approximately
3,325 barrels per day of sweet crude oil.
The most prolific producing formation in the LOU is the Wall Creek 2 at a
depth of 1,500 feet. It has produced approximately 385 million barrels of oil
from an original estimated 950 million barrels of oil in place. In addition, the
field has produced another 268 million barrels of oil from multiple horizons
varying in depth down to 4,000 feet. The Company believes that the potential
application of horizontal drilling to target unswept intervals within several of
the reservoirs may have significant production and reserve potential. Horizontal
drilling is one of the advanced technologies the Company plans to implement.
Evidence of successful horizontal wells in several of these formations exists in
immediately offsetting fields.
In addition, the potential for enhanced oil recovery through CO2 flooding
is under consideration for the Wall Creek 2 formation. The Company owns an
interest in LaBarge, which currently transports CO2 to an enhanced oil recovery
project located approximately 90 miles from the Salt Creek Field.
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, 1997, the field was producing a net of 1,538
barrels per day of oil from 215 producing wells.
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 is investigating the potential to re-establish the inert gas
injection to increase reservoir pressure, which could have a significant impact
on production rates. In addition, the Company plans to supplement this gas cap
injection with horizontal 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
20 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.
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 five injection wells. Gross
cumulative production from the 7,300' Sand Unit over almost 15 years has totaled
11.1 million barrels of oil and 26.4 billion cubic feet of natural gas. As of
December 31, 1997, daily net production was approximately 758 barrels of oil.
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, 1997, daily net production from this field was 1,102 barrels of
oil, 202 barrels of natural gas liquids and 1,161 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 938 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. Grass Creek field is
also a candidate for enhanced oil recovery using CO2.
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 table on the next page 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.
LaBarge Production
Year Ended December 31,
---------------------------------
1997 1996 1995
---- ---- ----
(in thousands, except unit prices)
Production data (net):
Natural gas (Mcf)............................ 1,291 1,222 1,261
Carbon dioxide (Mcf)(1)...................... 901 603 659
Helium (Mcf)................................. 38 27 31
Average sales price per unit:
Natural gas (Mcf)............................ $ 2.11 $ 1.71 $ 1.41
Carbon dioxide (Mcf)......................... $ .28 $ 0.30 $ 0.39
Helium (Mcf)................................. $34.80 $43.68 $49.44
Financial data:
Revenues..................................... $4,472 $3,558 $3,819
Processing costs............................. 3,556 2,825 3,024
------ ------ ------
Net cash flows............................... $ 916 $ 733 $ 795
====== ====== ======
_________________
(1) Because of a lack of market, approximately 78%, 81% and 80% of the volume
produced in 1997, 1996 and 1995, 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 8 of Notes to Consolidated
Financial Statements.
Item 4. Submission of Matters to a Vote of Security Holders
None.
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, 1996......................... 14 5/8 13 1/2 0.04
June 30, 1996.......................... 15 1/8 13 3/8 0.04
September 30, 1996..................... 15 3/8 12 1/2 0.04
December 31, 1996...................... 16 13 1/2 0.04
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
Approximate number of equity shareholders as of December 31, 1997: 1,800.
It is the current intention of the Company to continue to pay quarterly
cash dividends on its common stock. No assurance can be given, however, as to
the timing and amount of any future dividends which necessarily will depend on
the earnings and financial needs of the Company, legal restraints, and other
considerations that the Company's Board of Directors deems relevant. The ability
of the Company to pay dividends on its common stock is currently subject to
certain restrictions contained in its bank 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 6 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)
----------------------------------------------------
1997(2) 1996(2) 1995(2) 1994 1993
---- ---- ---- ---- ----
(In thousands, except per share amounts)
Revenues from continuing operations.. ... $ 34,663 $684,516 $645,020 $422,206 $388,794
-------- -------- -------- -------- --------
Net earnings from continuing operations.. $ 3,308 $ 13,779 $ 4,093 $ 2,768 $ 2,702
-------- -------- -------- -------- --------
Basic earnings per common share
from continuing operations ............ $ .17 $ 2.30 $ .35 $ .07 $ .22
-------- -------- -------- -------- --------
Property, plant and equipment, net ...... $226,228 $103,495 $180,467 $108,799 $108,460
-------- -------- -------- -------- --------
Total assets ............................ $266,711 $157,197 $269,030 $180,536 $162,400
-------- -------- -------- -------- --------
Long-term debt .......................... $117,000 $ 20,581 $ 96,205 $ 33,098 $ 35,879
-------- -------- -------- -------- --------
Shareholders' equity .................... $ 97,639 $ 90,048 $ 79,020 $ 75,919 $ 76,225
-------- -------- -------- -------- --------
Cash dividends per common share ......... $ .16 $ .16 $ .16 $ .16 $ .16
-------- -------- -------- -------- --------
_________________
(1) See Note 2 of Notes to Consolidated Financial Statements regarding the 1997
sale of the technical fuels and chemical processing operations.
(2) See Note 2 and 4 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, and the
1995 purchase of three pipeline systems.
Summarized below are the Company's quarterly financial data for 1997 and 1996
continuing operations.
1997 Quarters (1)
-----------------------------------------
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.............. $ .07 $ .01 $ .02 $ .08
-------- -------- -------- --------
Net earnings from continuing operations
per common share - diluted............ $ .07 $ .01 $ .02 $ .07
-------- -------- -------- --------
1996 Quarters (1) (2)
-----------------------------------------
First Second Third Fourth
----- ------ ----- ------
(In thousands, except per share amounts)
Revenues from continuing operations ..... $158,464 $174,048 $201,222 $150,782
-------- -------- -------- --------
Earnings from continuing operations
before income taxes .................. $ 1,848 $ 2,837 $ 2,393 $ 14,696
-------- -------- -------- --------
Net earnings from continuing operations.. $ 1,203 $ 1,796 $ 1,506 $ 9,274
-------- -------- -------- --------
Net earnings from continuing operations
per common share - basic ............. $ .12 $ .24 $ .18 $ 1.76
-------- -------- -------- --------
Net earnings from continuing operations
per common share - diluted ........... $ .12 $ .24 $ .18 $ 1.30
-------- -------- -------- --------
_________________
(1) See Note 2 of Notes to Consolidated Financial Statements regarding the 1997
sale of the technical fuels and chemical fuels processing operations.
(2) See Note 2 and 4 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.
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 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, 1997, are discussed below. The table below for each
segment's revenues does not reflect the elimination of intercompany revenues.
See Note 2 and 7 of Notes to Consolidated Financial Statements.
Oil and Gas Production
Year Ended December 31,
---------------------------
1997 1996 1995
Revenues (in thousands):
Sales of oil and natural gas................... $29,089 $28,162 $27,011
Sales of LaBarge other products................ 1,747 1,493 1,990
Gas marketing.................................. 2,868 3,553 2,196
Minerals leasing and other..................... 959 660 304
------- ------- -------
Total revenues............................ $34,663 $33,868 $31,501
======= ======= =======
Operating profit (in thousands)................ $ 8,396 $ 8,682 $ 6,977
======= ======= =======
Operating information:
Average net daily production:
Oil and NGL (Bbls)......................... 3,415 3,300 3,791
Natural gas (Mcf).......................... 9,072 8,943 9,662
Average sales prices:
Oil and NGL (per Bbl)...................... $ 17.15 $17.52 $15.67
Natural gas (per Mcf)...................... $ 2.33 $ 2.06 $ 1.47
Revenues
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 has
been steadily increasing over the last three years. These revenue increases were
partially offset by a decrease in gas marketing revenue due to reduced activity.
Oil and natural gas revenues increased in 1996 primarily due to improved
product prices, partially offset by reduced product volumes. Gas marketing
revenue increased due to increased prices.
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 and 1995 were partially
offset by reduced product sales prices. Sulfur sales revenues have been
insignificant.
Operating Profit
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.
The operating profit of this segment increased $1.7 million when comparing
1996 to 1995. The higher oil and gas sales prices were the largest factors in
this increase in operating profit. The increase in gas marketing revenues was
offset by an increase in gas marketing costs. Partially offsetting these
improvements was an increase in production cost due primarily to workover
expense on an offshore gas supply well. Also reducing operating profit was an
increase in depreciation, depletion and amortization per equivalent barrel of
production from $5.20 in 1995 to $5.37 in 1996. An increase in general and
administrative costs from $1.6 million in 1995 to $1.9 million in 1996 also
partially offset the improvements.
Howell's average realized oil price for the fourth quarter 1997 was $16.66
per barrel. The crude oil price decline that began in the latter part of the
fourth quarter has continued into early 1998.
Management anticipates that 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 1998
capital investments on obligatory projects and pilot programs designed to build
an inventory of projects for long-term shareholder value. In the interim, should
lower product prices be sustained, Howell will record a significant non-cash
ceiling test writedown at the end of the first quarter 1998 to the value of its
proved oil and gas properties.
Crude Oil Marketing & Transportation
Year Ended December 31,
---------------------------
1997 1996 1995
---- ---- ----
(In thousands)
Revenues.................................. ... $ - $666,086 $629,918
===== ======== ========
Operating profit............................... $ - $ 9,610 $ 9,235
===== ======== ========
There were no revenues or operating profits during 1997 in the crude oil
marketing and transportation segment as a result of the December 3, 1996,
Purchase & Sale and Contribution & Conveyance of Howell Crude Oil's and Howell
Transportation's assets and liabilities associated with crude oil gathering.
However, the Company did retain direct and indirect interest in Genesis. As a
result of the Company's interest, the Company recognized net earnings in Genesis
of $0.9 million during 1997. See Note 4 of Notes to Consolidated Financial
Statements.
Revenues increased 6% in 1996 from $629.9 million in 1995 to $666.1 million
in 1996, and operating profit increased 4% in 1996 from $9.2 million in 1995 to
$9.6 million in 1996. The increase can be attributed to the Company's pipeline
activities. Also contributing to the increase in operating profit was a decrease
in general and administrative costs of $0.6 million from 1995 to 1996. The crude
oil marketing activities accounted for an increase in operating profit of $1.1
million offset by a decrease in operating profit for transportation activities
of $0.7 million.
Effective December 3, 1996, the Company's sale of the assets and
liabilities associated with crude oil gathering resulted in a pre-tax gain of
$13.8 million recognized in other income/expense.
Interest Expense
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 assets and liabilities associated with crude oil gathering 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 Specified.
Short-term and long-term debt ("Debt") averaged $23.9 million for the first half
of 1997. The proceeds of the sale to Specified 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
Wyoming properties from Amoco on December 17, 1997, increased Debt to $137.0
million at year-end. See Notes 2, 4 and 5 of Notes to Consolidated Financial
Statements.
Interest expense in 1996 rose $0.4 million over the 1995 level. The primary
reason for this increase was attributable to the funds borrowed by the Company
in March 1995 to finance the acquisitions of three crude oil pipelines from
Exxon and certain oil and gas properties from Norcen. Debt decreased from $104.3
million at December 31, 1995, to $26.4 million at December 31, 1996, due
primarily to the repayment of the term loan and pay down of the revolving credit
facility with proceeds received from the conveyance of the Company's crude
operations to Genesis. See Notes 4 and 5 of Notes to Consolidated Financial
Statements.
Additionally, the increase in interest expense from higher average
outstanding balances in 1996 was slightly offset by decreasing market interest
rates. Market interest rates ranged from 8.25% to 8.5% throughout 1996, while in
1995 the rates fluctuated from 8.5% to 9%. Because substantially all of the
Company's debt is subject to market rates, the lower 1996 rates contributed to
an offset of the increase in 1996 interest expense.
Provision for Income Taxes
In 1997, the Company's effective tax rate of 31% reflects the statutory
federal rate and state income taxes less the effect of statutory depletion
deductions in excess of cost basis. Higher pretax income in 1996, reducing the
effect of these statutory depletion deductions and a higher state tax provision
in 1996 and 1995, increased the effective tax rate in those years to 37% and
36%, respectively.
RESULTS FROM DISCONTINUED OPERATIONS
Technical Fuels and Chemical Processing
On July 31, 1997, 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 Specified.
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,
1997 1996 1995
---- ---- ----
(in thousands)
$112 $504 $476
==== ==== ====
LIQUIDITY AND CAPITAL RESOURCES
On December 17, 1997, the Company replaced its existing revolving
credit/term loan agreement with a new "Credit Facility". The Credit Facility
comprises two tranches. Tranche A is a five-year revolving credit facility with
a maximum credit amount, subject to semi-annual borrowing base redeterminations
based on the Company's oil and natural gas properties, of $130 million. The
Company is required to pay commitment fees on the unused portion of Tranche A at
a rate of .25% per annum, if 50% or less of the borrowing base is unused, or
.30% if more than 50% of the borrowing base is unused. Available credit under
Tranche A may also be used for letters of credit on the Company's behalf.
Tranche B is a one-year term loan facility providing for one $20 million advance
to finance the Acquisition.
Outstanding amounts under the Credit Facility bear interest, at the
Company's option, at either: (i) the higher of the federal funds rate plus .5%
or the bank's prime rate, plus, in either case, the applicable margin (the
"Applicable Margin") provided for in the Credit Facility; or (ii) LIBOR plus the
Applicable Margin.
The Credit Facility is unsecured. The Credit Facility contains certain
other customary affirmative and negative covenants, including limitations on the
ability of the Company to incur additional debt, sell assets, merge or
consolidate with other persons or pay dividends on its capital in excess of
historical levels and a prohibition on change of control or management, as well
as a covenant to raise at least $50 million in equity or subordinated debt by
December 15, 1998. 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 2.0 to 1.0 until the end of
1998 and 2.5 to 1.0 thereafter.
The Credit Facility also provides the Company with additional borrowing
capacity solely for the purpose of financing the acquisition of the Beaver Creek
Unit if such acquisition is consummated on or before December 16, 1998. The
additional capacity comprises $85 million under Tranche A of the Credit Facility
and $85 million under Tranche B (subject to certain reductions based upon
previously raised subordinated capital). Funding of the additional borrowing
capacity is subject to the satisfaction of certain customary conditions,
including that no Material Adverse Effect (as defined in the Credit Facility)
shall have occurred. The Credit Facility also contains certain additional
provisions that will apply only if the acquisition of the Beaver Creek Unit
occurs. These provisions include a change in the covenant to raise capital
described above so that the Company must raise in total at least $175 million in
equity and/or subordinated debt, including at least $75 million of equity, by
December 15, 1998. In addition, if within six months after the consummation of
the acquisition of the Beaver Creek Unit this minimum capital is not raised,
Tranche B has not been repaid or the Company is in Default (as defined in the
Credit Facility) the Credit Facility will become secured by a portion of the
Company's oil and natural gas properties.
On December 18, 1997, the Company drew approximately $117.5 million under
Tranche A of the Credit Facility and $20.0 million under Tranche B to pay the
purchase price in the Acquisition (including fees) and refinance approximately
$21.1 million in previously existing bank debt of which $12.4 million represents
the deposit held by Amoco for the purchase of the Beaver Creek Unit. As of
December 31, 1997, the outstanding amounts under Tranche A bore interest at 8.5%
per annum on $2.0 million, 7.28% on $90.0 million and 7.34% on $25.0 million;
and the outstanding amount under Tranche B bore interest at 7.28% per annum.
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.
At December 31, 1997, the Company had negative working capital of $16.2
million, including the $20.0 million Tranche B, one year loan facility referred
to above. In 1997, cash provided from operating activities was $2.2 million.
The Company currently anticipates spending approximately $.6 million during
fiscal years 1998 and 1999 at various of its 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. See Note 9 of Notes to Consolidated Financial Statements.
The Company believes that its cash flow from operations and amounts
available under the Credit Facility will be sufficient to satisfy its current
liquidity requirements. At December 31, 1997, the Company had $13 million
available to it under the Credit Facility. The decline in the value of the
Company's proved reserves experienced since December 31, 1997, if sustained,
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 1998, 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.
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 1995, the monthly average sales price of crude oil on
the organized exchange was between $17 and $20 per barrel; therefore, no options
were exercised during the period.
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 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.
Subsequent to February 1997, the Company has not engaged in hedging
activities for its oil and gas production, but will consider doing so in the
future.
Beaver Creek Acquisition
The Company's previously announced approximately $187 million acquisition
of the Beaver Creek Unit (the "Beaver Creek Acquisition") from Amoco was not
closed due to litigation initiated by Snyder Oil Corporation over an alleged
preferential right to purchase such property. As described above, the Company
has arranged financing for the Beaver Creek Acquisition, provided such
acquisition is consummated on or before December 16, 1998. Funding of the
additional borrowing capacity is subject to the satisfaction of certain
customary conditions, including that no Material Adverse Effect (as defined in
the Credit Facility) shall have occurred. There can be no assurance that the
litigation can be resolved by such date. Further, if oil and gas prices were to
remain at currently depressed levels, financing may be difficult to obtain.
Accounting Pronouncements
In June 1997, the Financial Accounting Standards Board issued Statement No.
130, "Reporting Comprehensive Income," ("SFAS 130") and Statement No. 131,
"Disclosures About Segments of An Enterprise and Related Information," ("SFAS
131"). SFAS 130 and 131 are effective for periods beginning after December 15,
1997. SFAS 130 establishes standards for reporting and displaying of
comprehensive income and its components. SFAS 131 establishes standards for the
way that public business enterprises report information about operating segments
in interim and annual financial statements. These two Statements will have no
effect on the Company's 1997 financial statements, but management is continuing
to evaluate what, if any, additional disclosures may be required when these two
statements are adopted in 1998.
Year 2000 Date Conversion
The Company is currently working to resolve the potential impact of the
year 2000 on the processing of date-sensitive information by the Company's
computerized information systems. The year 2000 problem is the result of
computer programs being written using two digits (rather than four) to define
the applicable year. Any of the Company's programs that have time-sensitive
software may recognize a date using "00" as the year 1900 rather than the year
2000, which could result in miscalculations or system failures. Based on
preliminary information, costs of addressing potential problems are not
currently expected to have a material adverse impact on the Company's financial
position, results of operations or cash flows in future periods. However, if the
Company, its customers or vendors are unable to resolve such processing issues
in a timely manner, it could result in a material financial risk. Accordingly,
the Company plans to devote the necessary internal and external resources to
resolve all significant year 2000 issues in a timely manner.
Item 8. Financial Statements and Supplementary Data
The response to this item is submitted as a separate section of this report
(see page 22).
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
Not applicable.
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 1998
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 ............... 61 Chairman and Chief Executive Officer
Richard K. Hebert ............... 46 President and Chief Operating Officer
J. Richard Lisenby .............. 54 Vice President and Chief Financial Officer
Robert T. Moffett ............... 46 Vice President, General Counsel and Secretary
John E. Brewster, Jr............. 47 Vice President, Corporate Development and Planning
Mr. Paul N. Howell, who founded Howell Corporation in 1955 and served as
its Chief Executive Officer and President, announced his retirement from those
positions effective May 14, 1997. Mr. Howell remains a member of the Board of
Directors. In conjunction with Mr. Howell's retirement, Ronald E. Hall, Chairman
of the Company's Board of Directors, resigned the Chairmanship, but also remains
a member of the Board of Directors.
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, 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 1998 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 1998 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 1998 Annual Shareholders' Meeting, is incorporated herein
by reference.
Item 13. Certain Relationships and Related Transactions
The information appearing under the caption "Certain Transactions" set
forth in the Company's definitive proxy statement, to be filed within 120 days
after the close of the fiscal year in connection with the 1997 Annual
Shareholders' Meeting, is incorporated herein by reference.
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)(1)and (2). The response to this portion of Item 14 is submitted as a
separate section of this report (see page 22).
(a)(3)and (c). The response to this portion of Item 14 is submitted as a
separate section of this report (see page 44).
(b). Reports on Form 8-K.
A report on Form 8-K/A was filed March 3, 1998, to disclose the
Pro Forma financial statements required by the January 2, 1998,
Form 8-K regarding the purchase of certain Wyoming oil and gas
properties from Amoco.
A report on Form 8-K was filed January 2, 1998, to disclose the
purchase of certain Wyoming oil and gas properties from Amoco.
A report on Form 8-K was filed July 31, 1997, to disclose the
sale of Howell Hydrocarbons & Chemicals, Inc. to Specified Fuels &
Chemicals, L.L.C.
A report on Form 8-K was filed May 14, 1997, to report (i) the
retirement of Paul N. Howell; (ii) the election of Donald W.
Clayton, Chairman & Chief Executive Officer, and Richard K.
Hebert, President & Chief Operating Officer; (iii) the adoption of
the 1997 Nonqualified Stock Option Plan; and (iv) the letter of
intent to acquire Voyager Energy Corp., a company founded by
Donald W. Clayton and Richard K. Hebert.
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: February 27, 19987
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.
Signature Title Date
--------- ----- ----
Principal Executive
/s/ Donald W. Clayton Officer and Director February 27, 1998
____________________________________
Donald W. Clayton
Chairman
and
Chief Executive Officer
Principal Executive
/s/ Richard K. Hebert Officer and Director February 27, 1998
____________________________________
Richard K. Hebert
President
and
Chief Operating Officer
/s/ Paul N. Howell Director February 27, 1998
____________________________________
Paul N. Howell
/s/ Jack T. Trotter Director February 27, 1998
____________________________________
Jack T. Trotter
/s/ Walter M. Mischer, Sr. Director February 27, 1998
____________________________________
Walter M. Mischer, Sr.
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..................................... 23
Consolidated Financial Statements:
Consolidated Balance Sheets................................... 24
Consolidated Statements of Earnings........................... 25
Consolidated Statements of Changes in Shareholders' Equity.... 26
Consolidated Statements of Cash Flows......................... 27
Notes to Consolidated Financial Statements.................... 28
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.
INDEPENDENT AUDITORS' REPORT
To Howell Corporation:
We have audited the accompanying consolidated balance sheets of Howell
Corporation and its subsidiaries as of December 31, 1997 and 1996, and the
related consolidated statements of earnings, changes in shareholders' equity,
and cash flows for each of the three years in the period ended December 31,
1997. 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, 1997 and 1996, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1997 in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Houston, Texas
February 27, 1998
HOWELL CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
December 31,
----------------------
1997 1996
---- ----
(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents ................................................. $ 56 $ 3,253
Trade accounts receivable, less allowance for doubtful accounts of
$144 in 1997 and $262 in 1996 ........................................ 5,520 5,472
Accounts receivable from investees ........................................ 2,300 --
Other current assets ...................................................... 1,489 1,223
--------- ---------
Total current assets ................................................... 9,365 9,948
--------- ---------
Property, plant and equipment:
Oil and gas properties, utilizing the full-cost method of accounting....... 371,975 280,766
Unproven properties ....................................................... 41,017 --
Fee mineral interests, unproven ........................................... 18,123 18,180
Other ..................................................................... 2,670 2,601
Less accumulated depreciation, depletion and amortization ................. (207,557) (198,052)
--------- ---------
Net property, plant and equipment ...................................... 226,228 103,495
--------- ---------
Investments in investees ..................................................... 16,432 21,802
Property to be disposed of ................................................... -- 19,772
Other assets ................................................................. 14,686 2,180
--------- ---------
Total assets ........................................................... $ 266,711 $ 157,197
========= =========
Liabilities and Shareholders' Equity
Current liabilities:
Current maturities of long-term debt ...................................... $ 20,000 $ 5,868
Accounts payable .......................................................... 2,165 3,928
Accrued liabilities ....................................................... 4,819 8,872
Income tax payable ........................................................ (1,411) 2,340
--------- ---------
Total current liabilities .............................................. 25,573 21,008
--------- ---------
Deferred income taxes ........................................................ 25,071 23,850
--------- ---------
Other liabilities ............................................................ 1,428 1,710
--------- ---------
Long-term debt ............................................................... 117,000 20,581
--------- ---------
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; 5,464,642 shares
issued and outstanding in 1997; 4,947,196 shares
issued and outstanding in 1996 ....................................... 5,465 4,947
Additional paid-in capital ................................................ 40,760 34,532
Retained earnings ......................................................... 50,724 49,879
--------- ---------
Total shareholders' equity ............................................. 97,639 90,048
--------- ---------
Total liabilities and shareholders' equity ............................. $ 266,711 $ 157,197
========= =========
See accompanying Notes to Consolidated Financial Statements.
HOWELL CORPORATION AND SUBSIDIARIES
Consolidated Statements of Earnings
Year Ended December 31,
-----------------------------------
1997 1996 1995
---- ---- ----
(In thousands, except per share amounts)
Revenues:
Oil & Gas .................................................... $ 34,663 $ 33,868 $ 31,501
Other ........................................................ -- 650,648 613,519
--------- --------- ---------
34,663 684,516 645,020
--------- --------- ---------
Costs and Expenses:
Operating expenses - Oil & Gas ............................... 14,825 13,773 12,457
Depreciation, depletion, and amortization .................... 9,460 9,694 10,569
General and administrative expenses .......................... 5,093 5,313 5,076
Other ........................................................ -- 641,037 604,283
--------- --------- ---------
29,378 669,817 632,385
--------- --------- ---------
Other income (expense):
Interest expense ............................................. (1,671) (6,988) (6,633)
Interest income .............................................. 145 110 229
Net earnings of investees .................................... 906 181 --
Gain on conveyance of assets ................................. -- 13,841 --
Other-net .................................................... 115 (69) 154
--------- --------- ---------
(505) 7,075 (6,250)
--------- --------- ---------
Earnings before income taxes .................................... 4,780 21,774 6,385
Provision for income taxes ...................................... 1,472 7,995 2,292
--------- --------- ---------
Net earnings from continuing operations ......................... 3,308 13,779 4,093
--------- --------- ---------
Discontinued operations:
Net earnings from Howell Hydrocarbons
(less applicable income taxes of $388, $267 and $769 ...... 528 298 1,233
for 1997, 1996 and 1995, respectively) ....................
Gain on sale of Howell Hydrocarbons (less applicable income... 245 -- --
taxes of $126 for 1997)
--------- --------- ---------
Net earnings from discontinued operations ....................... 773 298 1,233
========= ========= =========
Net earnings .................................................... $ 4,081 $ 14,077 $ 5,326
========= ========= =========
Basic earnings per common share:
Continuing operations ........................................ $ 0.17 $ 2.30 $ 0.35
Discontinued operations ...................................... 0.10 0.06 0.25
Gain on sale of Howell Hydrocarbons .......................... 0.05 -- --
========= ========= =========
Net earnings per common share - basic ........................ $ 0.32 $ 2.36 $ 0.60
========= ========= =========
Weighted average shares outstanding - basic ..................... 5,143 4,937 4,869
========= ========= =========
Diluted earnings per common share:
Continuing operations ........................................ $ 0.17 $ 1.93 $ 0.34
Discontinued operations ...................................... 0.09 0.04 0.25
Gain on sale of Howell Hydrocarbons .......................... 0.05 -- --
========= ========= =========
Net earnings per common share - diluted ...................... $ 0.31 $ 1.97 $ 0.59
========= ========= =========
Weighted average shares outstanding - diluted ................... 5,355 7,129 4,969
========= ========= =========
See accompanying Notes to Consolidated Financial Statements.
HOWELL CORPORATION AND SUBSIDIARIES
Consolidated Statement of Changes in Shareholders' Equity
Preferred Stock Common Stock
--------------- ------------
Paid-In Retained
Shares $ Shares $ Capital Earnings Total
------ - ------ - ------- --------
(In thousands, except number of shares)
Balances, December 31, 1994 ............... 690,000 $690 4,836,876 $4,837 $33,518 $36,874 $75,919
Net earnings - 1995 ................... -- -- -- -- -- 5,326 5,326
Cash dividends - $.16 per
common share ....................... -- -- -- -- -- (778) (778)
Cash dividends - $3.50 per
preferred share .................... -- -- -- -- -- (2,415) (2,415)
Common stock issued to
employees and directors upon
exercise of stock options .......... -- -- 96,570 96 872 -- 968
------- ---- --------- ------ ------- ------- -------
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
======= ==== ========= ====== ======= ======= =======
See accompanying Notes to Consolidated Financial Statements.
HOWELL CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Year Ended December 31,
--------------------------------
1997 1996 1995
---- ---- ----
(In thousands)
OPERATING ACTIVITIES:
Net earnings from continuing operations...................... $ 3,308 $ 13,779 $ 4,093
Adjustments for non-cash items:
Depreciation, depletion and amortization ................ 9,460 13,817 14,252
Deferred income taxes ................................... 1,221 5,219 1,698
Equity in earnings of investees - net of amortization ... (906) (181) --
Investee dividends ...................................... 134 -- --
Gain on sale(s) of asset(s) ............................. (132) (13,883) (34)
-------- -------- --------
Earnings from continuing operations plus non-cash
operating items ........................................ 13,085 18,751 20,009
Changes in components of working capital from operations:
(Increase) decrease in trade accounts receivable ........ (48) 54,979 (15,672)
(Increase) decrease in inventories ...................... (7) 2,024 (1,598)
(Increase) decrease in other current assets ............. (2,558) 394 (296)
(Decrease) increase in accounts payable ................. (1,763) (54,496) 13,848
(Decrease) increase in accrued and other liabilities .... (7,509) 4,240 1,342
-------- -------- --------
Cash provided by continuing operations .......................... 1,200 25,892 17,633
Cash provided by discontinued operations ........................ 1,025 1,293 3,522
-------- -------- --------
Cash provided by operating activities ........................... 2,225 27,185 21,155
-------- -------- --------
INVESTING ACTIVITIES:
Proceeds from the disposition of discontinued operations .... 19,778 -- --
Proceeds from the disposition of other property ............. 275 1,804 1,629
Investment in investees ..................................... 2,692 (1,556) --
Proceeds from sale of assets to MLP ......................... -- 68,717 --
Additions to property, plant and equipment .................. (128,199) (12,378) (88,282)
Deposit for Amoco Beaver Creek acquisition .................. (12,369) -- --
Other, net .................................................. (137) 66 (380)
-------- -------- --------
Cash (utilized in) provided by investing activities ............. (117,960) 56,653 (87,033)
-------- -------- --------
FINANCING ACTIVITIES:
Long-term debt:
Borrowings under revolving credit agreement, net-
Bank of Montreal ................................... 137,000 -- --
(Repayments) Borrowings under revolving credit
agreement; net-Bank One ............................ (18,000) (24,250) 18,050
(Repayments) borrowings under term loan
agreement, net ..................................... -- (54,625) 54,625
(Repayments) to Department of Energy .................... (4,999) (2,266) (2,122)
Other repayments ........................................ -- (133) (2,048)
Cash dividends:
Common shareholders ..................................... (821) (790) (778)
Preferred shareholders .................................. (2,415) (2,415) (2,415)
Exercise of stock options ................................... 1,773 156 968
-------- -------- --------
Cash provided by (utilized in) financing activities ............. 112,538 (84,323) 66,280
-------- -------- --------
NET (DECREASE) INCREASE IN CASH AND CASH
EQUIVALENTS ................................................. (3,197) (485) 402
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR .................... 3,253 3,738 3,336
======== ======== ========
CASH AND CASH EQUIVALENTS, END OF YEAR .......................... $ 56 $ 3,253 $ 3,738
======== ======== ========
See accompanying Notes to Consolidated Financial Statements.
HOWELL CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Note 1. Summary of Significant Accounting Policies
Principles of Consolidation
The consolidated financial statements include the accounts of Howell
Corporation and its subsidiaries (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. See Notes 2 and 7.
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.
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 financial (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.
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. The earnings per share data
for prior years has been restated following the standards in Statement of
Financial Accounting Standards No. 128, "Earnings Per Share".
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
$1,347,000, $7,793,000 and $6,435,000 in 1997, 1996 and 1995, respectively. In
1997, 1996 and 1995, cash payments for income taxes totaled $6,849,000,
$2,974,000 and $1,158,000, respectively.
Supplementary Oil and Gas Producing Information (Unaudited)
The supplementary oil and gas producing information required by Statement
of Financial Accounting Standards No. 69 ("SFAS 69"), "Disclosures About Oil and
Gas Producing Activities," is included in Item 2. "Properties" in this Annual
Report on Form 10-K.
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.
Information on the fair value of the Company's Debt can be found in Note 5.
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 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 9. 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 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.
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 and 1995 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, 1997 or 1996.
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 1996 and 1995 financial
presentation to conform with the 1997 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. See Notes 2 and 4.
Note 2. Acquisitions & Dispositions
1997
On December 18, 1997, the Company purchased certain oil and gas producing
properties (the "Acquisition") 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 Acquisition was
December 1, 1997. The Acquisition was accounted for using the purchase method of
accounting, and accordingly, the purchase price has been preliminarily 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 Earnings since December 18, 1997. The pro
forma information shown below assumes that the Acquisition occurred at January
1, 1997 and January 1, 1996, respectively. 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 Acquisition 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 January 1, 1996, 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
Of the properties purchased, the two largest fields are Elk Basin, which is
in the Bighorn Basin, and Salt Creek, which is in the Powder River Basin. Each
field has approximately 30 people managing day-to-day operations. The Wyoming
properties acquired from Amoco have total proved reserves of 34.2 million
barrels of liquids and 25.9 billion cubic feet of gas, or a total of 38.5
million barrels of oil equivalent.
The acquisition was financed through a credit facility provided by Bank of
Montreal. See Note 5. Howell expects to recapitalize a portion of its debt in
1998.
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, Howell Hydrocarbons & Chemicals, Inc. (the "Seller"), a
wholly-owned subsidiary of the Company, 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 Specified Fuels & Chemicals,
L. L. C. ("Specified").
The assets purchased by Specified 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) Specified 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.
In consideration of the assets sold to Specified, 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 is 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 are $5.0
million, $5.175 million, $5.35 million, $5.525 million and $5.7 million,
respectively. Specified is 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 is initially set at $5.7 million if the repurchase occurs
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 occurs
during the twelve-month period ending June 30, 2002.
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.
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,
1997 1996 1995
---- ---- ----
(in thousands)
$112 $504 $476
==== ==== ====
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 Howell Hydrocarbons & Chemicals, Inc. 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 (as
defined below) based on a year of 360 days for the actual number of days
elapsed. Prime Rate shall mean a fluctuating interest rate per annum as shall be
in effect on the first day of each calendar quarter equal to the rate of
interest published by The Wall Street Journal on such day as the prime rate,
principal amount of the loan during each calendar quarter shall be determined as
of the opening of business on the first day of such calendar quarter. The term
of the note shall be 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.
1995
- ----
On March 31, 1995, the Company's crude oil marketing and transportation
segment acquired from Exxon Pipeline Company ("Exxon"), two interstate crude oil
pipeline systems and one intrastate crude oil pipeline system. The interstate
pipeline systems were located in Florida/Alabama ("Jay System") and
Mississippi/Louisiana ("MS System"). The intrastate system was located in Texas
("Texas System"). Collectively, the purchase of these pipelines and related
assets comprise the "Exxon Transaction."
The Texas System consisted of a 555-mile pipeline system extending from
Groesbeck, Texas, south to Texas City, Texas, and tanks for crude oil storage
with a total capacity of approximately 1.9 million barrels. The Jay System
consisted of a 90-mile pipeline system extending west from Santa Rosa County,
Florida, to Mobile County, Alabama, and included tanks with approximately 0.2
million barrels of storage capacity. The MS System consisted of a 230-mile
pipeline system extending from Jones County, Mississippi, to Baton Rouge,
Louisiana, and included storage capacity of approximately 0.2 million barrels.
The total negotiated purchase price paid to Exxon for the Exxon Transaction
was $63.5 million. The Exxon Transaction was financed through borrowings from
banks.
On April 21, 1992, the Company sold its San Antonio, Texas, refinery for a
sales price of $2.2 million. The Company received a down payment of $0.4 million
and a note requiring monthly principal and interest payments for three years. In
1993, the time period for repayment was extended one additional year. The
interest rate for the note was 10%. Due to the uncertainty about the ultimate
collection of the note receivable, the Company did not recognize gain on the
sale or interest income on the note as payments were not made. In 1995, the
Company agreed to accept $0.5 million in settlement of the balance remaining
under the note. This settlement resulted in $0.4 million of income for the
Company that is included in other income (expense) in the Consolidated Statement
of Earnings for 1995.
Note 3. Income Taxes
A summary of the provision for income taxes from operations included in the
consolidated statements of earnings is as follows:
Year Ended December 31,
-------------------------
1997 1996 1995
---- ---- ----
(In thousands)
Current:
Federal......................................... $ 501 $5,214 $ (80)
State........................................... 181 367 336
Deferred............................................ 790 2,414 2,036
------ ------ ------
Income taxes from continuing operations............. 1,472 7,995 2,292
Income taxes from discontinued operations........... 388 267 769
Income taxes from sale of discontinued operations... 126 - -
====== ====== =====
$1,986 $8,262 $3,061
====== ====== ======
Deferred income taxes are provided on all temporary differences between
financial and taxable income. The approximate tax effects of each significant
type of temporary difference and carryforward were as follows:
Year Ended December 31,
------------------------
1997 1996
---- ----
(In thousands)
Accrual of costs not deductible for tax............. $ 1,325 $ 2,146
-------- --------
Total deferred tax assets........................... 1,325 2,146
-------- --------
Differences between book and tax bases of property,
plant and equipment............................. (26,396) (25,991)
Other............................................... - (5)
-------- --------
Total deferred tax liabilities...................... (26,396) (25,996)
-------- --------
Net deferred income taxes.................... $(25,071) $(23,850)
======== =========
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,
---------------------------
1997 1996 1995
---- ---- ----
(In thousands)
Provision for income taxes at the statutory rate.. $1,625 $7,621 $2,171
Statutory depletion in excess of cost basis....... (278) (292) (327)
State income taxes................................ 181 367 336
Other............................................. (56) 299 112
------ ------ ------
$1,472 $7,995 $2,292
====== ====== ======
Note 4. 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 (referred to hereafter as the "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 has also agreed to perform, and retain the liability for, the cleaning of
certain tanks used in the pipeline operations.
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 twelve-month and
one-month periods ended December 31, 1997 and 1996, respectively, was as
follows:
1997 1996
---- ----
(In thousands)
Revenues............................................... $3,372,928 $371,985
Net income............................................. $ 9,848 $ 1,684
Current assets......................................... $ 232,197 $410,603
Property & equipment, net.............................. $ 88,638 $ 88,937
Current liabilities.................................... $ 224,533 $398,794
Partners' capital...................................... $ 106,576 $111,338
At December 31, 1997, 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, 1997, was $0.2 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 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, 1997.
Note 5. Debt and Available Credit Facilities
Short-term and long-term debt of the Company as of December 31, 1997 and
1996, were as follows:
1997 1996
---- ----
(In thousands)
Note payable to Genesis LLC ............................................... $ -- $ 3,450
Note payable under a $40.5 million revolving credit/term loan agreement ... -- 18,000
Note payable under a $150.0 million revolving credit/term loan agreement .. 137,000 --
Note payable to Department of Energy (DOE) ................................ -- 4,999
-------- -------
137,000 26,449
Less: Current maturities ................................................. 20,000 5,868
-------- -------
$117,000 $20,581
======== =======
Maturities of short-term and long-term debt for the five years subsequent
to December 31, 1997, are as follows (in thousands):
Total
1998.............................. $ 20,000
1999.............................. 0
2000.............................. 0
2001.............................. 0
2002.............................. 117,000
Thereafter........................ 0
--------
$137,000
========
As of December 31, 1997 the Company had no capital lease obligations.
Revolving credit/term loan agreement
On December 17, 1997, the Company replaced its existing revolving
credit/term loan agreement with a new "Credit Facility". The Credit Facility
comprises two tranches. Tranche A is a five-year revolving credit facility with
a maximum credit amount, subject to semi-annual borrowing base redeterminations
based on the Company's oil and natural gas properties, of $130 million. The
Company is required to pay commitment fees on the unused portion of Tranche A at
a rate of .25% per annum, if 50% or less of the borrowing base is unused, or
.30% if more than 50% of the borrowing base is unused. Available credit under
Tranche A may also be used for letters of credit on the Company's behalf.
Tranche B is a one-year term loan facility providing for one $20 million advance
to finance the Acquisition.
Outstanding amounts under the Credit Facility bear interest, at the
Company's option, at either: (i) the higher of the federal funds rate plus .5%
or the bank's prime rate, plus, in either case, the applicable margin (the
"Applicable Margin") provided for in the Credit Facility; or (ii) LIBOR plus the
Applicable Margin.
The Credit Facility is unsecured. The Credit Facility contains certain
other customary affirmative and negative covenants, including limitations on the
ability of the Company to incur additional debt, sell assets, merge or
consolidate with other persons or pay dividends on its capital in excess of
historical levels and a prohibition on change of control or management, as well
as a covenant to raise at least $50 million in equity or subordinated debt by
December 15, 1998. 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 2.0 to 1.0 until the end of
1998 and 2.5 to 1.0 thereafter.
The Credit Facility also provides the Company with additional borrowing
capacity solely for the purpose of financing the acquisition of the Beaver Creek
Unit if such acquisition is consummated on or before December 16, 1998. The
additional capacity comprises $85 million under Tranche A of the Credit Facility
and $85 million under Tranche B (subject to certain reductions based upon
previously raised subordinated capital). Funding of the additional borrowing
capacity is subject to the satisfaction of certain customary conditions,
including that no Material Adverse Effect (as defined in the Credit Facility)
shall have occurred. The Credit Facility also contains certain additional
provisions that will apply only if the acquisition of the Beaver Creek Unit
occurs. These provisions include a change in the covenant to raise capital
described above so that the Company must raise in total at least $175 million in
equity and/or subordinated debt, including at least $75 million of equity, by
December 15, 1998. In addition, if within six months after the consummation of
the acquisition of the Beaver Creek Unit this minimum capital is not raised,
Tranche B has not been repaid or the Company is in Default (as defined in the
Credit Facility) the Credit Facility will become secured by a portion of the
Company's oil and natural gas properties.
On December 18, 1997, the Company drew approximately $117.5 million under
Tranche A of the Credit Facility and $20.0 million under Tranche B to pay the
purchase price of the Acquisition (including fees) and refinance approximately
$21.1 million in previously existing bank debt of which $12.4 million represents
the deposit held by Amoco for the purchase of the Beaver Creek Unit. As of
December 31, 1997, the outstanding amounts under Tranche A bore interest at 8.5%
per annum on $2.0 million, 7.28% on $90.0 million and 7.34% on $25.0 million;
and the outstanding amount under Tranche B bore interest at 7.28% per annum.
At December 31, 1997, the Company had $13 million available to it under the
Credit Facility. The decline in the value of the Company's proved reserves
experienced since December 31, 1997, if sustained, 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 1998, 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.
Term loan agreement
From March 31, 1995 to December 31, 1996, the Company had a term loan
agreement outstanding that was repaid with the proceeds from the sale and
conveyance referred to in Note 4.
Department of Energy
The remaining balance owed at December 31, 1996, was $5.0 million. The
obligation bore interest at a trailing average prime rate. At December 31, 1996,
the rate was 8.25%.
As a result of the sale of the Company's assets to Genesis in December
1996, the Company repaid the remaining obligation in January 1997.
Other
In July 1992, the Company entered into a capital lease for transportation
equipment. The obligation was repaid in 1996.
Fair value of long-term debt
The fair value of the Company's long-term debt at December 31, 1997 and
1996, 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 6. Shareholders' Equity
Preferred stock
At December 31, 1997 and 1996, 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, 1997 and 1996, the Company had 50,000,000 and 10,000,000
shares of common stock authorized, respectively.
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.
Stock option activity for the Company during 1997, 1996, and 1995 was as
follows:
1997 1996 1995
-------------------- ------------------ -------------------
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 .......... 431,914 $11.24 466,217 $10.96 443,173 $10.56
Granted ................. 721,380 $13.37 90,900 $14.51 209,760 $11.44
Exercised ............... (164,808) $10.76 (13,750) $10.53 (96,570) $10.03
Expired ................. 0 (10,908) (7,476)
Forfeited ............... (52,456) (100,545) (82,670)
--------- --------- --------
Stock options
outstanding, end of year ... 936,030 $12.91 431,914 $11.24 466,217 $10.96
========= ======== =========
At December 31, 1997, options were exercisable for 227,555 shares at a
weighted average exercise price of $11.51. The range of exercise prices on
outstanding options at December 31, 1997, was $8.31 to $18.75. The remaining
contractual life of these options was approximately 8.5 years. At December 31,
1997, 33,470 shares were available for future option grants.
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:
1997 1996 1995
---- ---- ----
Net income .................................... $4,081,000 $14,077,000 $5,326,000
SFAS No. 123 adjustment ....................... 482,000 107,000 91,000
========== =========== ==========
Pro Forma net income .......................... $3,599,000 $13,970,000 $5,235,000
========== =========== ==========
Earnings per share as reported - basic ........ $ 0.32 $ 2.36 $ 0.60
========== =========== ==========
Pro Forma earnings per share - basic .......... $ 0.23 $ 2.34 $ 0.58
========== =========== ==========
Earnings per share as reported - diluted ... $ 0.31 $ 1.97 $ 0.59
========== =========== ==========
Pro Forma earnings per share - diluted ........ $ 0.22 $ 1.96 $ 0.57
========== =========== ==========
The weighted average fair value of options granted during 1997, 1996 and
1995 was $5.46, $8.17 and $5.20, 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 1997, 1996 and 1995.
1997 1996 1995
---- ---- ----
Weighted average expected life: 8.5 years 10 years 8 years
Volitility factor: 24.38% 36.20% 28.00%
Dividend yield: 1.00% 1.00% 1.00%
Weighted average risk free interest: 6.19% 8.00% 7.50%
Note 7. Segment Information
Financial information about the Company's continuing operations for each of
the years ended December 31, 1997, 1996 and 1995, is summarized as follows:
Crude Oil
Marketing
& Inter-
Oil & Gas Transport- segment
Production ation Other Sales Total
---------- ---------- ----- ------- -----
(In thousands)
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 investees $ 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 investees $ 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
--------- -------- -------- --------
December 31, 1995
Revenues ......................... $ 31,501 $629,918 $ -- $(16,399) $645,020
--------- -------- -------- -------- --------
Operating profit (loss) ........... $ 6,977 $ 9,235 $ (157) $ 16,055
--------- -------- --------
General corporate expense ......... (3,420)
Other expense, net ................ (6,250)
--------
Earnings from continuing operations
before income taxes ........... $ 6,385
--------
Identifiable assets ............... $ 109,755 $129,505 $ 29,770 $269,030
--------- -------- -------- --------
Capital expenditures .............. $ 14,949 $ 72,190 $ 1,143 $ 88,282
--------- -------- -------- --------
Depreciation, depletion and
amortization .................. $ 10,259 $ 3,683 $ 310 $ 14,252
--------- -------- -------- --------
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 production of
carbon dioxide, helium and sulfur from the LaBarge Project.
Intersegment sales by the oil and gas production segment to the crude oil
marketing and transportation segment were $0, $15,438 and $16,399 in 1997, 1996
and 1995, 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% and 12% of consolidated
revenues in 1996 and 1995, respectively.
As a result of the sale in 1997 to Specified, referred to in Note 2,
segment data for 1996 and 1995 have been restated to conform to the 1997
presentation.
Note 8. Litigation
Donna Refinery Partners, Ltd. v. Howell Crude Oil Company and Howell
Corporation; Texas District Court; No. 89-033634. In December 1993, a jury
verdict of $1.9 million was rendered against the Company which was subsequently
reduced by the judge to approximately $675,000. The Company filed a motion for a
new trial that was denied, so the Company appealed the decision. The plaintiff
filed an appeal to increase the recovery by $1.25 million. On June 6, 1996, the
Fourteenth Court of Appeals affirmed the judgment of the lower court. The
Company's appeal of this case to the Texas Supreme Court was denied, and the
Company paid the judgment. The resolution of this matter did not have a
materially adverse effect on the financial position, results of operations or
cash flows of the Company.
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
has 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) is currently set for trial on June 15, 1998.
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. 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.
On December 3, 1997, Snyder Oil Corporation sued Amoco Production Company
and Howell Petroleum Corporation to enjoin the sale of the Beaver Creek Unit to
Howell Petroleum until such time as Amoco complies with Snyder's preferential
right to purchase the unit. Snyder Oil Corporation v. Amoco Production Company
and Howell Petroleum Corporation; District Court, Ninth Judicial District,
Fremont County, Wyoming; Civil Action No. 29861. The lawsuit is based upon two
theories: (i) the Beaver Creek Unit should not have been sold in a package with
other properties, and (ii) Amoco and Howell Petroleum inflated the value of the
unit in order to make it too costly for Snyder to buy the unit. Answers have
been filed and discovery has begun.
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 9. 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.
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 4.
In January 1995, an Agreed Order with the Texas Natural Resource
Conservation Commission was signed by the Company with respect to alleged
violations of rules regarding the permitting and storage of hazardous wastes at
the San Antonio facility that was previously owned by the Company. Penalties
totaling $26,000 were assessed and paid by the Company. During 1995, the Company
incurred costs of $28,000 related to remediation and disposal of the hazardous
wastes. Additional testing and monitoring of the groundwater and formal approval
of the remediation work are still required. The Company has completed the
remediation work related to hazardous waste storage rule violations. 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.
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 Specified, 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's previously announced approximately $187 million acquisition
of the Beaver Creek Unit (the "Beaver Creek Acquisition") from Amoco was not
closed due to litigation initiated by Snyder Oil Corporation over an alleged
preferential right to purchase such property. As described above, the Company
has arranged financing for the Beaver Creek Acquisition, provided such
acquisition is consummated on or before December 16, 1998. Funding of the
additional borrowing capacity is subject to the satisfaction of certain
customary conditions, including that no Material Adverse Effect (as defined in
the Credit Facility) shall have occurred. There can be no assurance that the
litigation can be resolved by such date. Further, if oil and gas prices were to
remain at currently depressed levels, financing may be difficult to obtain.
The Company occupies office and operational facilities and uses equipment
under operating lease arrangements. Expense of these arrangements amounted to
$425,000 in 1997, $2,765,000 in 1996 and $2,201,000 in 1995. At December 31,
1997, long-term commitments for lease of facilities and equipment totaled
approximately $4,777,000, consisting of $570,000, $651,000, $672,000, $672,000
and $672,000 for the years 1998 through 2002, respectively, and $1,540,000
thereafter.
Note 10. Determination of Earnings per Incremental Share
The following tables present the reconciliation of the numerators and
denominators in calculating diluted earnings per share ("EPS") from continuing
operations in accordance with Statement of Financial Accounting Standards No.
128.
1997
Earnings
Increase per
Increase in Number Incremental
in Income of 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
========== ========== =====
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 per
Increase in Number Incremental
in Income of 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
=========== ========= =====
1995
Earnings
Increase per
Increase in Number Incremental
in Income of Shares Share
----------- ----------- ----------
Options.................................... - 99,820 -
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
----------- ----------- ----------
$1,678,000 4,869,277 $0.35
Common stock options..................... - 99,820
---------- --------- -----
$1,678,000 4,969,097 $0.34 Dilutive
Dividends on convertible preferred stock... $2,415,000 2,090,909
---------- --------- -----
$4,093,000 7,060,006 $0.58 Antidilutive
========== ========= =====
Note: Because diluted EPS from continuing operations increases from $0.34 to
$0.58 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 $0.34.
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
- ------- -----------
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 Credit Agreement Among Howell Petroleum Corporation, as Borrower, Bank
One, Texas, N.A., as Agent and as a Lender, Bank of Montreal, as a
Lender, Compass Bank - Houston, as a Lender, and Den norske Bank AS,
as a Lender, dated as of March 31, 1995 (filed as an Exhibit to the
Company's Report on Form 10-Q for the quarterly period ended March
31, 1995).
10.8 Guaranty by Howell Corporation in Favor of Bank One, Texas, National
Association, as Agent, dated as of March 31, 1995 - Credit Facility
to Howell Petroleum Corporation (filed as an Exhibit to the
Company's Report on Form 10-Q for the quarterly period ended March
31, 1995).
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.
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.
Exhibit
Number Description
- ------- -----------
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.
10.30 Consent Statement to approve the acquisition of Voyager Energy Corp.
and approve the increase of authorized Common Stock shares.
21 * Subsidiaries of the Company.
23 * Consent of Deloitte & Touche LLP.
27 * Financial Data Schedule.
EXHIBIT 21
HOWELL CORPORATION
Parent and Subsidiaries
December 31, 1997
The following is a list of all significant operating subsidiaries of the
Company on December 31, 1997. Each of the subsidiaries is included in the
Company's Consolidated Financial Statements.
Percentage of
Voting Securities
Jurisdiction of Held by
Incorporation Immediate Parent
--------------- -----------------
Howell Corporation ......................... Delaware (1)
Howell Hydrocarbons & Chemicals, Inc..... Delaware 100%
Howell Petroleum Corporation............. Delaware 100%
Howell Crude Oil Company................. Delaware 100%
__________________________
(1) Paul N. Howell may be considered a "parent" of the Company. On
December 31, 1997, Mr. Howell is deemed to own "beneficially," as that
term is defined in Rule 13(d)(3) of the General Rules and Regulations
under the Securities Exchange Act of 1934, 22% of the voting securities
of the Company.
EXHIBIT 23
HOWELL CORPORATION
Independent Auditors' Consent
To Howell Corporation:
We consent to the incorporation by reference in Registration Statement
No. 33-28389 of Howell Corporation on Form S-8 of our report dated February
27, 1998, appearing in this Annual Report on Form 10-K of Howell Corporation
for the year ended December 31, 1997.
DELOITTE & TOUCHE LLP
Houston, Texas
March 20, 1998