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, 1999
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-8704
HOWELL CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 74-1223027
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1111 Fannin, Suite 1500, Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (713) 658-4000
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
---------- ------------
Common Stock, $1 par value New York Stock Exchange
$3.50 Convertible Preferred Stock, National Association of
Series A, $1 par value Securities Dealers, Inc.
Automated Quotation System
Securities registered pursuant to Section 12(g) of the Act:
NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
|X|
The market value of all shares of Common Stock on March 1, 2000 was
approximately $36.2 million. The aggregate market value of the shares held by
nonaffiliates on that date was approximately $23.7 million. As of March 1, 2000,
there were 5,521,782 common shares outstanding.
Documents Incorporated by Reference:
Howell Corporation proxy statement to be filed in connection with the 2000
Annual Shareholders' Meeting (to the extent set forth in Part III of this Form
10-K).
HOWELL CORPORATION
1999 FORM 10-K ANNUAL REPORT
Table of Contents
PART I
Page
Item 1. Business.................................................... 1
Item 2. Properties.................................................. 3
Item 3. Legal Proceedings........................................... 9
Item 4. Submission of Matters to a Vote of Security Holders......... 9
PART II
Item 5. Market for the Registrant's Common Stock and Related
Stockholder Matters........................................10
Item 6. Selected Financial Data.....................................10
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations........................11
Item 7A. Quantitative and Qualitative Disclosure About Market Risk...15
Item 8. Financial Statements and Supplementary Data.................16
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure...................................16
PART III
Item 10. Directors and Executive Officers of the Registrant..........17
Item 11. Executive Compensation......................................17
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................17
Item 13. Certain Relationships and Related Transactions..............18
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K ..................................................18
This Form 10-K includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements other than
statements of historical facts included in this Form 10-K, including without
limitation the statements under "Business", "Properties" and "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
regarding the nature of the Company's oil and gas reserves, productive wells,
acreage, and drilling activities, the adequacy of the Company's financial
resources, current and future industry conditions and the potential effects of
such matters on the Company's business strategy, results of operations and
financial position, are forward-looking statements. Although the Company
believes that the expectations reflected in the forward-looking statements
contained herein are reasonable, no assurance can be given that such
expectations will prove to have been correct. Certain important factors that
could cause actual results to differ materially from expectations ("Cautionary
Statements"), include without limitation, fluctuations of the prices received
for the Company's oil and natural gas, uncertainty of drilling results and
reserve estimates, competition from other exploration, development and
production companies, operating hazards, abandonment costs, the effects of
governmental regulation and the leveraged nature of the Company, are stated
herein in conjunction with the forward-looking statements or are included
elsewhere in this Form 10-K. All subsequent written and oral forward-looking
statements attributable to the Company or persons acting on its behalf are
expressly qualified in their entirety by the Cautionary Statements.
PART I
Item 1. Business
A. General
Howell Corporation and its subsidiaries ("Company") are engaged in the
exploration, production, acquisition and development of oil and gas properties.
These operations are conducted in the United States. A description of the
Company's business and the market in which it operates is summarized below.
Oil and Gas Exploration and Production
The Company's oil and gas exploration and production activities are
conducted by Howell Petroleum Corporation ("HPC"), a wholly-owned subsidiary of
the Company, and are concentrated in Wyoming and along the Gulf Coast, both
onshore and offshore. At December 31, 1999, the Company's estimated proved
reserves were 34.6 million barrels of oil and plant liquids and 38.6 billion
cubic feet ("BCF") of gas. The core area for the Company includes the Salt Creek
and Elk Basin fields discussed below. The Company's major producing properties
include Salt Creek, Elk Basin, North Frisco City and Main Pass 64. These four
major fields represent 33.2 million barrels of oil equivalent ("MMBOE"), or 81%
of the Company's total proved reserves. Substantially all of the Company's oil
and natural gas production is sold on the spot market or pursuant to contracts
priced according to the spot market. HPC has 118 employees.
The oil and gas industry is highly competitive. Major oil and gas
companies, independent operators, drilling and production purchase programs, and
individual producers and operators are active bidders for desirable oil and gas
properties, as well as the equipment and labor required to operate those
properties. Many competitors have financial resources substantially greater, and
staffs and facilities substantially larger, than those of the Company.
The Company's financial condition, profitability, future rate of growth and
ability to borrow funds or obtain additional capital, as well as the carrying
value of its oil and natural gas properties, are substantially dependent upon
prevailing prices of, and demand for, oil and natural gas. The energy markets
have historically been, and are likely to continue to be volatile, and prices
for oil and natural gas are subject to large fluctuations in response to
relatively minor changes in the supply and demand for oil and natural gas,
market uncertainty and a variety of additional factors beyond the control of the
Company. These factors include the level of consumer product demand, weather
conditions, the actions of the Organization of Petroleum Exporting Countries,
domestic and foreign governmental regulations, political stability in the Middle
East and other petroleum producing areas, the foreign and domestic supply of oil
and natural gas, the price of foreign imports, the price and availability of
alternative fuels and overall economic conditions. A substantial or extended
decline in oil and natural gas prices could have a material adverse effect on
the Company's financial position, results of operations, quantities of oil and
natural gas reserves that may be economically produced, carrying value of its
proved reserves, borrowing capacity and access to capital.
Technical Fuels and Chemical Processing
On July 31, 1997, Howell Hydrocarbons & Chemicals, Inc. ("Seller"), a
wholly-owned subsidiary of the Company, sold substantially all of the assets of
its research and reference fuels and custom chemical manufacturing business to
Specified Fuels & Chemicals, Inc. ("SFC").
In connection with the transaction, SFC received a license to use the name
"Howell Hydrocarbons & Chemicals" for a five-year period after closing and it
assumed certain obligations of Seller and the Company. The Company agreed not to
engage (directly or through affiliates) in any competing business for a
five-year period after the closing.
The sale resulted in a pre-tax gain of $0.4 million and the proceeds of the
sale were used by the Company to reduce its outstanding indebtedness. In
connection with the sale, the Company has given and received environmental and
other indemnities. Claims could arise in the future that would require the
Company to perform under those indemnities.
In consideration for the assets sold to SFC, 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 for working capital
items. The Company was entitled to receive an additional payment equal to 55% of
the
amount by which SFC's EBITDA, for a period of five years, exceeded specific
target levels for the year. During August 1998, the Company received the first
excess EBITDA payment of $0.7 million.
On January 4, 1999, the Company sold its right to participate in the future
earnings of SFC for $2.0 million. The sale and the results of operations of the
research and reference fuel business have been classified as discontinued
operations in the accompanying consolidated financial statements. Technical
Fuels and Chemical Processing had a gain of $1.3 million after tax for the year
ended December 31, 1999, as a result of the sale of its right to participate in
future earnings.
Investment in Genesis
On December 1, 1996, the Company conveyed the assets and business of its
crude oil gathering and marketing operations and pipeline operations to Genesis
Crude Oil, L.P., a Delaware limited partnership ("GCO"). Howell received cash of
approximately $74 million and 991,300 subordinated limited partner units of GCO.
Additionally, the Company received 46% of Genesis Energy, L.L.C., a Delaware
limited liability company ("LLC") which is the General Partner of GCO. Howell
recognized a gain of approximately $13.8 million.
A subsidiary of Salomon Smith Barney Holdings Inc. ("SSB") conveyed similar
assets to GCO. SSB owns 54% of LLC. SSB is obligated to provide distribution
support should GCO have inadequate funds to make the minimum quarterly
distribution to its common unit holders. SSB receives additional partnership
interests ("APIs") to the extent it funds this obligation. Howell is obligated
to purchase from SSB 46% of any outstanding APIs, but only to the extent of any
distribution made to Howell by GCO on Howell's subordinated limited partner
units.
Howell retained all liabilities arising from the operations, activities and
transactions of the business up through the closing date, including various
environmental-related liabilities. Howell made various representations and
warranties as to itself and the business and has agreed to indemnify GCO for any
breaches thereof. Claims for breaches of such representations and warranties
must be brought before December 3, 2001. Howell also agreed to perform, and
retain the liability for, the cleaning of certain tanks used in the pipeline
operations which was completed in 1997.
On the closing date, Howell entered into various agreements with GCO
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 sale of
crude oil by Howell from its oil and gas exploration and production business;
and (c) an agreement whereby one-half of the subordinated limited partner units
owned by Howell are pledged to secure Howell's indemnification of GCO for
environmental liabilities.
The financial results of GCO have recently deteriorated even as the market
has returned to what had historically been a more favorable price environment.
For each of the last three quarters of 1999, SSB has had to perform under its
distribution support agreement. While there are no arrearages with respect to
the common units, GCO has never made a distribution with respect to the
subordinated units held by Howell and SSB. The Company now believes that it is
more likely than not that distributions will never be paid on the subordinated
units.
With only a minority interest in LLC, Howell is not in a position to
substantially influence management of GCO. Accordingly, the Company has decided
to dispose of its interests in GCO and LLC. The Company has recorded an
impairment charge of $13.5 million (pre-tax) to the carrying value of its
investment and classified its operations as discontinued. During 1999, the
investment in Genesis incurred a pre-tax loss of $13.8 million primarily as a
result of the impairment charge. The loss is reflected in Discontinued
Operations. See Notes 4 and 5 of Notes to Consolidated Financial Statements.
On February 28, 2000, the Company entered into a Purchase and Sale
Agreement to sell its 46% interest in LLC to SSB for $3.0 million. The proceeds
from the sale will be used to reduce debt. The Company does not expect to
receive any proceeds for its subordinated units in GCO. No gain or loss will be
recognized on the sale.
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,
2
have issued rules and regulations binding on the oil and gas industry and
its individual members, compliance with which is often difficult and costly and
some of which carry substantial penalties for failure to comply. State statutes
and regulations require permits for drilling operations, drilling bonds and
reports concerning wells. Texas and other states in which the Company conducts
operations also have statutes and regulations governing conservation matters,
including the unitization or pooling of oil and gas properties and establishment
of maximum rates of production from oil and gas wells. The existing statutes or
regulations currently limit the rate at which oil and gas is produced from wells
in which the Company owns an interest.
Environmental Regulations
The Company's operations are subject to extensive and developing federal,
state and local laws and regulations relating to environmental, health and
safety matters; petroleum; chemical products and materials; and waste
management. Permits, registrations or other authorizations are required for the
operation of certain of the Company's facilities and for its oil and gas
exploration and production activities. These permits, registrations or
authorizations are subject to revocation, modification and renewal. Governmental
authorities have the power to enforce compliance with these regulatory
requirements, the provisions of required permits, registrations or other
authorizations, and lease conditions. Third parties may have the right to sue to
enforce compliance. The cost of environmental compliance has not had a material
adverse effect on the Company's operations or financial condition in the past.
However, violations of applicable regulatory requirements, environment-related
lease conditions, or required environmental permits, registrations or other
authorizations can result in substantial civil and criminal penalties as well as
potential court injunctions curtailing operations.
Some risk of costs and liabilities related to environmental, health and
safety matters is inherent in the Company's operations, as it is with other
companies engaged in similar businesses, and there can be no assurance that
material costs or liabilities will not be incurred. In addition, it is possible
that future developments, such as stricter requirements of environmental or
health and safety laws and regulations affecting the Company's business or more
stringent interpretations of, or enforcement policies with respect to, such laws
and regulations, could adversely affect the Company. To meet changing permitting
and operational standards, the Company may be required, over time, to make site
or operational modifications at the Company's facilities, some of which might be
significant and could involve substantial expenditures. In particular, federal
regulatory programs focusing on the increased regulation of storm water runoff,
oil spill prevention and response, and air emissions (especially those that may
be considered toxic) are currently being implemented. There can be no assurance
that material costs or liabilities will not arise from these or additional
environmental matters that may be discovered or otherwise may arise from future
requirements of law.
The Company has made a commitment to comply with environmental regulations.
Personnel with training and experience in safety, health and environmental
matters are responsible for compliance activities. Senior management personnel
are involved in the planning and review of environmental matters.
C. Employment Relations
On December 31, 1999, the Company had 118 employees. The Company's
employees are not represented by a union for collective bargaining purposes. The
Company has experienced no work stoppages or strikes as a result of labor
disputes and considers relations with its employees to be good. The Company
maintains group life, medical, dental, long-term disability, short-term
disability, 401(k) and accidental death and dismemberment insurance plans for
its employees. The Company contributed $413,000 to the 401(k) plan for 1999.
Item 2. Properties
A. Supplementary Oil and Gas Producing Information
The oil and gas producing activities of the Company are summarized below.
Substantially all of the Company's producing properties are subject to certain
restrictions under the Company's credit facility. See Note 6 of Notes to
Consolidated Financial Statements.
3
Oil and Gas Wells
As of December 31, 1999, the Company owned interests in productive oil and
gas wells (including producing wells and wells capable of production) as
follows:
Productive Wells
Gross(1) Net
-------- ---
Oil wells............................. 2,338 809
Gas wells............................. 603 39
----- ---
Total ......................... 2,941 848
===== ===
(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 at December 31, 1999, 1998, 1997 and 1996, except for the reserves
purchased from Amoco, were reviewed by independent petroleum consultants, H. J.
Gruy and Associates, Inc. The December 31, 1999, 1998 and 1997 reserves,
associated with the properties acquired from Amoco, were reviewed by independent
petroleum consultants, Ryder Scott & Associates. These estimates were used in
the computation of depreciation, depletion and amortization included in the
Company's consolidated financial statements and for other reporting purposes.
Estimated Quantities of Proved Oil and Gas Reserves
Oil Gas
(BBLs) (MCF)
------ -----
As of December 31, 1996.................... 7,959,173 60,254,350
Revisions of previous estimates............ 623,774 (5,737,208)
Extensions, discoveries & other additions.. 420,500 4,725,000
Purchases of minerals in place............. 34,413,669 27,702,395
Production................................. (1,246,596) (3,311,197)
---------- ----------
As of December 31, 1997.................... 42,170,520 83,633,340
Revisions of previous estimates............ (11,533,920) (6,313,032)
Extensions, discoveries & other additions.. 4,037,900 3,922,900
Purchases of minerals in place............. 4,634 8,107,918
Production................................. (3,542,465) (4,653,705)
Sales of minerals in place................. (1,196,828) (5,906,751)
---------- ----------
As of December 31, 1998.................... 29,939,841 78,790,670
Revisions of previous estimates............ 5,979,073 3,859,501
Extensions, discoveries & other additions.. 844,984 1,031,232
Purchases of minerals in place............. 685,478 75,751
Production................................. (2,843,055) (2,994,215)
Sales of minerals in place................. (11,575) (42,158,149)
---------- ----------
As of December 31, 1999.................... 34,594,746 38,604,790
========== ==========
Proved developed reserves:
December 31, 1996.......................... 6,995,835 58,444,115
========== ==========
December 31, 1997.......................... 40,711,561 81,709,974
========== ==========
December 31, 1998.......................... 26,701,736 75,756,389
========== ==========
December 31, 1999.......................... 31,530,345 35,890,990
========== ==========
Total proved reserves at year-end 1999 were 41,029 MBOE compared to 43,072
MBOE at year-end 1998. Approximately 7,038 MBOE of the decrease was due to
property sales, partially offset by an increase of 6,622 MBOE in upward
revisions.
Proved oil reserves at December 31, 1999, include 1.6 million barrels of
natural gas liquids ("NGL").
4
Oil and Gas Leaseholds
The following table sets forth the Company's ownership interest in
leaseholds as of December 31, 1999. The oil and gas leases in which the Company
has an interest are for varying primary terms, and many require the payment of
delay rentals to continue the primary term. The leases may be surrendered by the
Company at any time by notice to the lessors, by the cessation of production or
by failure to make timely payment of delay rentals.
Developed(1) Undeveloped
------------- -------------
Gross Net Gross Net
Acres Acres Acres Acres
----- ----- ----- -----
Alabama.................... 5,812 2,189 2,686 1,058
Louisiana.................. 1,682 497 274 73
Mississippi................ 3,015 942 6,639 1,775
North Dakota............... 7,240 1,710 1,040 130
Texas...................... 13,086 5,467 6,345 2,255
Wyoming.................... 38,262 18,316 28,001 11,782
All other states combined.. 3,774 720 3,322 1,738
Offshore................... 7,025 5,589 - -
====== ====== ====== ======
Total.................. 79,896 35,430 48,307 18,811
====== ====== ====== ======
-----------------
(1) Acres spaced or assignable to productive wells.
Drilling Activity
The following table shows the Company's gross and net productive and dry
exploratory and development wells drilled in the United States:
Exploratory Development
----------------------------- -------------------------------
Productive Wells Dry Holes Productive Wells Dry Holes
Year Gross Net Gross Net Gross Net Gross Net
---- ----- --- ----- --- ----- --- ----- ---
1999 - - - - 2.0 2.0 2.0 2.0
1998 1.0 0.6 1.0 0.1 18.0 4.5 - -
1997 4.0 0.9 1.0 0.3 1.0 0.1 1.0 0.6
The table above reflects only the drilling activity in which the Company
had a working interest participation. In addition, in 1998 and 1997, 5 and 24
gross productive wells, respectively, were drilled on the Company's fee mineral
interest acreage, which was sold in December 1998.
Sales Prices and Production Costs
The following table sets forth the average prices received by the Company
for its production, the average production (lifting) costs, and amortization per
equivalent barrel of production ("BOE"):
1999 1998 1997
---- ---- ----
Average sales prices:
Oil and NGL (per BBL) includes effect of hedging... $ 14.77 $11.26 $17.15
Natural gas (per MCF).............................. $ 1.94 $ 1.86 $ 2.33
Production (lifting) costs (per BOE).................. $ 6.84 $ 5.95 $ 5.92
Amortization (per BOE)................................ $ 1.95 $ 2.68 $ 5.18
Impairment of oil & gas properties (per BOE).......... $ - $23.66 $ -
Natural gas production is converted to barrels using its estimated energy
equivalent of six MCF per barrel.
5
Oil and Gas Producing Activities
CAPITALIZED COSTS. The following table presents the Company's aggregate
capitalized costs relating to oil and gas producing activities, all located in
the United States, and the aggregate amount of related depreciation, depletion
and amortization:
December 31, 1999 December 31, 1998
----------------- -----------------
Capitalized Costs: (In thousands)
Oil and gas producing properties, all
being amortized ........................ $ 382,393 $ 385,048
Unproven properties ....................... 21,143 43,263
---------- ----------
Total .................................. $ 403,536 $ 428,311
========== ==========
Accumulated depreciation, depletion and
amortization (includes impairment of oil
& gas properties) ...................... $ 310,897 $ 307,118
========== ==========
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,
-----------------------------------------------
1999 1998 1997
---- ---- ----
Property acquisition: (In thousands)
Unproved properties ................ $ -- $ 3,627 $ 41,904
Proved properties .................. 1,092 7,614 82,737
Exploration ............................. 1,461 3,460 5,994
Development ............................. 4,101 7,626 1,534
-------- -------- --------
$ 6,654 $ 22,327 $132,169
======== ======== ========
In 1998 and 1997, $18,123,000 and $57,000 of costs of unproved fee mineral
interests, respectively, were transferred to the full cost pool, representing
the costs of fee mineral interests that were drilled and evaluated during the
periods. The 1998 amount also represents the sale of the fee mineral interests
on December 17, 1998. These transfers of costs are not reflected in the table
above. See Note 2 of Notes to the Consolidated Financial Statements.
RESULTS OF OPERATIONS. The following table sets forth the results of
operations of the Company's oil and gas producing activities, all in the United
States. The table does not include activities associated with carbon dioxide,
helium and sulfur produced from the LaBarge Project, which was sold in March
1999, or with activities associated with leasing the Company's fee mineral
interests. The table does include the revenues and costs associated with the
Company's fee mineral interests which were sold in December 1998.
Year Ended December 31,
---------------------------------
1999 1998 1997
---- ---- ----
(In thousands)
Revenues .......................................... $47,826 $ 48,538 $29,089
Production (lifting) costs ........................ 22,875 25,703 10,646
Depreciation, depletion and amortization .......... 6,525 11,589 9,316
Impairment of oil & gas properties ................ - 102,167 -
-------- -------- --------
18,426 (90,921) 9,127
Income tax expense (benefit) ...................... 6,265 (30,913) 2,523
-------- -------- --------
Results of operations (excluding corporate overhead
and interest cost) ............................ $12,161 $(60,008) $ 6,604
======== ======== ========
Included in the 1998 and 1997 amounts above are $1,314,000, and $2,005,000
of revenues and $121,000 and $174,000 of production costs, respectively, from
the production of the Company's fee mineral interests which were sold in
December 1998.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED
OIL AND GAS RESERVES. The accompanying table presents a standardized measure of
discounted future net cash flows relating to the production of the Company's
estimated proved oil and gas reserves at the end of 1999 and 1998. The method of
calculating the standardized measure of discounted future net cash flows is as
follows:
6
(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,
------------------
1999 1998
---- ----
(In thousands)
Future cash inflows ............................................. $908,940 $388,355
Future production costs ......................................... 335,742 249,067
Future development costs ........................................ 15,630 17,597
Future income tax expenses ...................................... 155,324 -
-------- --------
Future net cash flows ........................................... 402,244 121,691
10% annual discount for estimated timing of cash flows .......... 196,846 60,363
-------- --------
Standardized measure of discounted future net cash flows relating
to proved oil and gas reserves ................................. $205,398 $ 61,328
======== ========
The standardized measure is not intended to represent the market value of
reserves and, in view of the uncertainties involved in the reserve estimation
process, including the instability of energy markets as evidenced by recent
volatility in both natural gas and crude oil prices, the reserves may be subject
to material future revisions.
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS. The
table below presents a reconciliation of the aggregate change in standardized
measure of discounted future net cash flows:
Year Ended December 31,
-----------------------------
1999 1998 1997
---- ---- ----
(In thousands)
Sales and transfers, net of production costs .................. $(24,951) $(22,836) $(18,443)
Net changes in prices and production costs .................. 242,115 (56,084) (113,015)
Extensions and discoveries, net of future production an
development costs ............................................. 9,829 12,775 9,950
Purchases of minerals in place .................................. 4,348 6,586 157,709
Sales of minerals in place ...................................... (5,047) 1,425 -
Previously estimated development costs incurred during the
period ........................................................ (546) (30) (178)
Revisions of quantity estimates ................................. 47,181 (20,512) (1,006)
Accretion of discount ........................................... 6,133 13,958 10,406
Net change in income taxes ...................................... (79,014) 21,017 7,190
Changes in production rates (timing) and other................... (55,978) (34,546) (17,093)
--------- --------- ---------
Net change .................................................. $144,070 $(78,247) $ 35,520
========= ========= =========
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,
1999, the Company's estimated proved reserves were 34.6 MMBO and plant liquids
and 38.6 BCF of gas. The Company's major producing properties include Salt
Creek, Elk Basin, North Frisco City, and Main Pass 64. These four major fields
represent 33.2 MMBOE, or 81% of the Company's total proved reserves.
Substantially all of the Company's oil and natural gas production is sold on the
spot market or pursuant to contracts priced according to the spot market.
7
Description of Significant Properties
Salt Creek. The Company owns and operates the Salt Creek field in the
Powder River Basin in Natrona County, Wyoming. The Company's working interest
varies from 67.7% 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 668 producing wells and 590 injection
wells located in the LOU on a flood pattern of approximately five acre well
spacing. As of December 31, 1999, the field was producing 3,186 barrels per day
of sweet crude oil, 202 barrels per day of sour crude and 68 barrels per day of
NGLs net to the Company. The most prolific producing formation in the LOU is the
Wall Creek 2 at a depth of 1,500 feet. It has produced approximately 388 MMBO
from an original estimated 950 MMBO in place. In addition, the field has
produced another 269 MMBO from multiple horizons varying in depth down to 4,000
feet.
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, 1999, the field was producing 1,564 barrels per
day of oil and 212 barrels per day of NGLs net to the Company from 225 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 re-established the inert gas injection to initiate an
increased reservoir pressure in 1998, which is anticipated to have a positive
impact on future production rates. The Company is injecting approximately 10
million cubic feet of inert gas per day into this reservoir. In addition, the
Company has supplemented this gas cap injection with additional producing wells
located in the oil rim on the edge of the structure, which has improved 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
typically produce at rates of 30 barrels of oil per day and have cumulative
recoveries up to 60,000 barrels each. The Company has identified numerous
potential drilling locations both within the unit and outside the unit on
Company leasehold. In late 1999, two Frontier wells were drilled to extend the
field down-structure and are currently being completed. The prolific Madison
carbonate, at a depth of 5,000', has the potential to be downspaced from the
current 40 acres per well to 20 acres per well based on the successful infill
drilling program over the last 10 years.
Main Pass Block 64. Main Pass is located in federal waters offshore
Louisiana about 70 miles southeast of New Orleans. The Company, as operator,
discovered oil and gas upon drilling a test well in 1982. In 1989, the Company
unitized portions of Main Pass Blocks 64 and 65, covering the main pay sand (the
"7,300' Sand Unit") and implemented a waterflood project to repressure the
7,300' Sand Unit. Through exploitation, additional acquisitions and field
unitization, the Company currently has a working interest which averages
approximately 80% in 24 gross wells, including 5 injection wells. Gross
cumulative production from the 7,300' Sand Unit over almost 18 years has totaled
11.7 MMBO and 26.8 BCF of natural gas. As of December 31, 1999, daily net
production was approximately 534 barrels of oil. The Company has plans to
continue the development of the oil-filled gas cap with one to three
recompletions in the year 2000.
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 through 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, 1999, daily net production from this field was 555 barrels of oil,
104 barrels of NGLs and 591 MCF of natural gas.
B. Other Properties
The Company leases approximately 52,900 square feet for use as corporate
and administrative offices in Houston, Texas.
8
Item 3. Legal Proceedings
The Company, through its subsidiaries, is involved from time to time in
various claims, lawsuits and administrative proceedings incidental to its
business. In the opinion of management, the ultimate liability thereunder, if
any, will not have a material adverse effect on the financial condition or
results of operations or cash flows of the Company. See Note 8 of Notes to
Consolidated Financial Statements.
Item 4. Submission of Matters to a Vote of Security Holders
None.
9
Part II
Item 5. Market for the Registrant's Common Stock and Related Stockholder
Matters
Howell Corporation common stock is traded on the New York Stock Exchange.
Symbol: HWL
Cash
Price Dividends
------------------ ---------
For quarter ended High Low $
------------------ ------- ------- -------
March 31, 1998................... 17 1/4 14 0.04
June 30, 1998.................... 14 1/8 10 1/8 0.04
September 30, 1998............... 10 1/2 6 5/16 0.04
December 31, 1998................ 6 1/4 2 1/16 0.04
March 31, 1999.................. 3 15/16 1 3/4 0.04
June 30, 1999.................... 5 3/4 3 1/4 0.04
September 30, 1999............... 7 1/2 5 0.04
December 31, 1999................ 6 5/8 5 3/8 0.04
Approximate number of equity shareholders as of December 31, 1999: 1,800.
It is the current intention of the Company to pay quarterly cash dividends
on its common stock. No assurance can be given, however, as to the timing and
amount of any future dividends which necessarily will depend on the earnings and
financial needs of the Company, legal restraints, and other considerations that
the Company's Board of Directors deems relevant. The ability of the Company to
pay dividends on its common stock is currently subject to certain restrictions
contained in its bank credit agreement. See Item 7. Management's Discussion and
Analysis of Financial Condition - Liquidity and Capital Resources.
In addition, the Company has 690,000 shares of convertible preferred stock
outstanding. These shares were issued in April 1993. The $3.50 convertible
preferred stock is traded on the National Association of Securities Dealers,
Inc. Automated Quotation System ("NASDAQ") under the symbol HWLLP. See Note 7 of
Notes to Consolidated Financial Statements.
Item 6. Selected Financial Data
The information below is presented in order to highlight significant trends
in the Company's results from continuing operations and financial condition. See
Consolidated Financial Statements and Notes thereto.
Year Ended December 31, (1) (2)
-------------------------------------------------
1999 1998(3) 1997 1996 1995
---- ---- ---- ---- ----
(In thousands, except per share amounts)
Revenues from continuing operations................... $ 48,310 $ 51,422 $ 34,663 $ 33,868 $ 31,501
--------- --------- --------- --------- ---------
Net earnings (loss) from continuing operations....... $ 4,945 $(68,076) $ 2,887 $ 864 $ 998
--------- --------- --------- --------- ---------
Basic and diluted earnings (loss) per share
common from continuing operations................. $ 0.46 $ (12.89) $ 0.09 $ (0.31) $ (0.29)
--------- --------- --------- --------- ---------
Property, plant and equipment, net.................... $ 93,046 $121,634 $226,228 $103,495 $108,285
--------- --------- --------- --------- ---------
Total assets.......................................... $117,983 $166,291 $268,122 $148,768 $152,166
--------- --------- --------- --------- ---------
Long-term debt........................................ $ 82,000 $102,000 $117,000 $ 20,581 $ 47,249
--------- --------- --------- --------- ---------
Shareholders' equity.................................. $ 20,680 $ 26,871 $ 97,639 $ 90,048 $ 79,020
--------- --------- --------- --------- ---------
Cash dividends per common share....................... $ 0.16 $ 0.16 $ 0.16 $ 0.16 $ 0.16
--------- --------- --------- --------- ---------
Cash dividends per preferred share.................... $ 3.50 $ 3.50 $ 3.50 $ 3.50 $ -
--------- --------- --------- --------- ---------
- - -----------------
(1) See Note 2 of Notes to Consolidated Financial Statements regarding the 1997
sale of the Technical Fuels and Chemical Processing operations.
(2) See Notes 2 and 5 of Notes to Consolidated Financial Statements regarding
the 1999 impairment and sale and the 1996 sale, contribution and conveyance
of the Crude Oil Marketing and Transportation operations.
(3) Includes $102,167 (pre-tax) charge for impairment of oil and gas properties
in 1998.
10
Summarized below are the Company's quarterly financial data for 1999 and 1998.
1999 Quarters(1)
--------------------------------------
First Second Third Fourth(2)
-------- -------- -------- --------
(In thousands, except per share amounts)
Revenues from continuing operations.. $ 8,878 $ 1,182 $13,368 $14,882
Earnings (loss) from continuing
operations before income taxes..... (2,598) 1,814 3,567 4,803
Net earnings (loss) from continuing
operations......................... (1,724) 1,178 2,338 3,153
Net (loss) earnings from
discontinued operations............ 1,307 (103) (93) (8,956)
-------- -------- -------- --------
Net (loss) earnings.................. $ (417) $ 1,075 $ 2,245 $(5,803)
======== ======== ======== ========
Net earnings (loss) from continuing
share - basic ..................... $ (0.43) $ 0.10 $ 0.32 $ 0.47
Net (loss) earnings from
discontinued operations per share-
basic.............................. 0.25 (0.01) (0.02) (1.64)
-------- -------- -------- --------
Net (loss) earnings.................. $ (0.18) $ 0.09 $ 0.30 $ (1.17)
======== ======== ======== ========
Net earnings (loss) from continuing
operations per share - diluted..... $ (0.43) $ 0.10 $ 0.30 $ 0.41
Net (loss) earnings from
discontinued operations per share-
diluted............................ 0.25 (0.01) (0.01) (1.17)
-------- -------- -------- --------
Net (loss) earnings.................. $ (0.18) $ 0.09 $ 0.29 $ (0.76)
======== ======== ======== ========
1998 Quarters(1)
--------------------------------------
First(3) Second Third Fourth(3)
-------- -------- -------- --------
(In thousands, except per share amounts)
Revenues from continuing operations.. $ 14,267 $12,267 $12,525 $ 12,363
(Loss) earnings from continuing
operations before income taxes..... (68,493) 294 464 (36,811)
Net (loss) earnings from continuing
operations......................... (45,231) 172 572 (23,589)
Net (loss) earnings from
discontinued operations............ 75 (97) 548 (3)
--------- -------- -------- ---------
Net (loss) earnings.................. $(45,156) $ 75 $ 1,120 $(23,592)
========= ======== ======== =========
Net (loss) from continuing
operations per share - basic ..... $ (8.39) $ (0.08) $ (0.01) $ (4.42)
Net (loss) earnings from
discontinued operations per share-
basic.............................. 0.02 (0.02) 0.10 -
-------- -------- -------- --------
Net (loss) earnings per share-basic.. $ (8.37) $ (0.10) $ 0.09 $ (4.42)
======== ======== ======== ========
Net (loss) from continuing
operations per share - diluted..... $ (8.39) $ (0.08) $ (0.01) $ (4.42)
Net (loss) earnings from
discontinued operations per share-
diluted............................ 0.02 (0.02) 0.10 -
-------- -------- -------- --------
Net (loss) earnings per share -
diluted............................ $ (8.37) $ (0.10) $ 0.09 $ (4.42)
======== ======== ======== ========
- - -----------------
(1) Includes effect of reclassification of Genesis to discontinued operations.
(2) Includes impairment of Genesis to market value.
(3) Includes charge for impairment of oil and gas properties (pre-tax) of
$66,118 in the first quarter and $36,049 in the fourth quarter.
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
The following is a discussion of the Company's financial condition, results
of operations, capital resources and liquidity. This discussion and analysis
should be read in conjunction with the Consolidated Financial Statements of the
Company and the Notes thereto.
RESULTS OF CONTINUING OPERATIONS
The Company's business is oil and gas exploration, production, acquisition
and development. Results of continuing operations for the three years ended
December 31, 1999, are discussed below. See Note 2 of Notes to Consolidated
Financial Statements.
11
Oil and Gas Production
Year Ended December 31,
---------------------------
1999 1998 1997
---- ---- ----
(In thousands)
Revenues:
Sales of oil and natural gas............ $47,826 $ 48,538 $29,089
Sales of LaBarge other products......... 180 1,685 1,747
Gas marketing........................... 83 758 2,868
Minerals leasing and other.............. 221 441 959
------- --------- -------
Total revenues..................... $48,310 $ 51,422 $34,663
======= ========= =======
Operating profit (loss) ................ $14,752 $(93,659) $ 5,285
======= ========= =======
Operating information:
Average net daily production:
Oil and NGL (BBLs) ................... 7,789 9,705 3,415
Natural gas (MCF)..................... 8,203 12,750 9,072
Average sales prices:
Oil and NGL (per BBL) (includes
effect of hedging).................. $ 14.77 $ 11.26 $17.15
Natural gas (per MCF)................. $ 1.94 $ 1.86 $ 2.33
Revenues
During 1999, revenues decreased 6% when compared to the year ended 1998.
The decrease was primarily due to a 20% decrease in oil production and a 36%
decrease in natural gas production as a result of the Company's sale of the
LaBarge, Grass Creek, and Pitchfork properties in early 1999. The decrease was
partially offset by a 31% increase in average oil prices. See Note 2 of Notes to
Consolidated Financial Statements.
Revenues increased 48% during 1998 when compared to the year ended 1997 due
to the Amoco acquisition, partially offset by a 34% decrease in average oil
prices and a 20% decrease in average natural gas prices. The increase in
revenues was partially offset by the Company's continued reduction of its gas
marketing activities.
Operating Profit
During 1999, operating profits increased $108.4 million primarily as a
result of the 1998 pre-tax non-cash impairment charge of $102.2 million.
Excluding the impairment, operating profits for 1999 increased 73% when compared
to 1998. This improvement was primarily due to a 44% reduction of amortization
expense in 1999 which resulted from the 1998 impairment charge. A $1.3 million
reduction in lease operating expenses also contributed to the increased
operating profits.
Operating profits decreased $98.9 million when comparing 1998 to 1997
primarily due to pre-tax non-cash impairments of $102.2 million. On an after-tax
basis, the impairments amounted to $67.4 million or a loss of $12.32 per common
share. Excluding the impairments, operating profits increased 61% when compared
to the year ended 1997. The Company experienced increased lease operating
expense and production and severance tax expense of $13.3 million and $2.8
million, respectively as a result of the Amoco acquisition. A reduction of
workover expense of $1.1 million helped to offset these increased costs. The
Company's general and administrative expenses decreased $1.6 million due to
increased administrative credits on some of the properties acquired in late
1997. Also offsetting these costs was a decrease in depreciation, depletion and
amortization, excluding the impairments, per equivalent barrel of production,
from $5.18 in 1997 to $2.68 in 1998 due to the Amoco acquisition.
Howell's average realized oil price, including hedging but excluding NGLs,
for 1999 was $14.95 per barrel as compared to $11.37 per barrel in 1998.
12
Interest Expense
Interest expense decreased $3.7 million in 1999 as a result of a decrease
in short-term and long-term debt ("Debt"). The Company reduced Debt by $42.0
million during 1999 as a result of the Company's sale of non-integral properties
for $28.7 million, a tax refund of $5.7 million, the buyout by SFC of its
remaining excess EBITDA payments for $2.0 million, and other cash provided by
continuing operations of $5.6 million.
During 1998, interest expense increased $9.3 million from the 1997 level as
a result of the increased Debt necessary for the Amoco acquisition. Debt
averaged $136.8 million during 1998. As a result of the sale of the fee mineral
interests during December 1998, the Company was able to reduce Debt by $13.0
million.
See Notes 2 and 6 of Notes to Consolidated Financial Statements.
Provision for Income Taxes
The Company's effective tax rate of 34.8% reflects the statutory federal
rate plus state income taxes.
RESULTS FROM DISCONTINUED OPERATIONS
Crude Oil Marketing and Transportation
During 1999, Crude Oil Marketing and Transportation incurred a pre-tax loss
of $13.7 million. The loss is primarily a result of the impairment of the
investment in Genesis to market value. On February 28, 2000, the Company entered
into a Purchase and Sale Agreement to sell its 46% interest in LLC to Salomon
for $3.0 million. The proceeds from the sale will be used to reduce debt. See
Item 1. Business - Investment in Genesis.
There were no revenues or operating profits in the Crude Oil Marketing and
Transportation operation during 1998 or 1997 as a result of the sale of that
business in 1996. As a result of the Company's direct and indirect interest in
Genesis, the Company recognized pre-tax net earnings in Genesis of $0.6 million
and $0.9 million during 1998 and 1997, respectively.
These results have been reclassified as discontinued operations. See Notes
4 and 5 of Notes to Consolidated Financial Statements. There is no allocated
interest as interest expense incurred was strictly for the oil and gas business.
Technical Fuels and Chemical Processing
On July 31, 1997, Seller completed the sale and disposition of
substantially all of the assets of its research and reference fuels and custom
chemical manufacturing business to SFC.
In connection with the transaction, SFC received a license to use the name
"Howell Hydrocarbons & Chemicals" for a five-year period after closing and it
assumed certain obligations of Seller and the Company. The Company agreed not to
engage (directly or through affiliates) in any competing business for a
five-year period after the closing.
The sale resulted in a pre-tax gain of $0.4 million. The proceeds of the
sale were used by the Company to reduce its outstanding indebtedness. In
connection with the sale, the Company has given and received environmental and
other indemnities. Claims could arise in the future that would require the
Company to perform under those indemnities.
In consideration for the assets sold to SFC, 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 for working capital
items. The Company was entitled to receive an additional payment equal to 55% of
the amount by which SFC's EBITDA, for a period of five years, exceeded specific
target levels for the year. During August 1998, the Company received the first
excess EBITDA payment of $0.7 million.
On January 4, 1999, the Company sold its right to participate in the future
earnings of SFC for $2.0 million. The sale and the results of operations of the
Technical Fuels and Chemical Processing business have been classified as
discontinued operations in the accompanying consolidated financial statements.
Technical Fuels and Chemical Processing had a gain of $1.3 million after tax for
the year ended December 31, 1999, as a result of the sale.
Discontinued operations also includes the allocation of $0.1 million of
interest expense (based on a ratio of net assets of discontinued operations to
total consolidated net assets) for 1997.
13
The following table presents the detail of net (loss) income from
discontinued operations as presented on the Consolidated Statements of
Operations:
Year Ended December 31,
----------------------------
1999 1998 1997
---- ---- ----
(in thousands)
Discontinued operations:
Net (loss) earnings of Genesis (less
applicable income taxes of $(4,702),
$133 and $316 for 1999, 1998 and
1997, respectively)...................... $(9,129) $ 257 $ 421
Net earnings from Howell Hydrocarbons
(less applicable income taxes of
$752, $350 and $388 for 1999, 1998
and 1997, respectively).................. 1,284 266 528
Gain on sale of Howell Hydrocarbons
(less applicable income
taxes of $126 for 1997).................. - - 245
-------- -------- --------
Net (loss) earnings from discontinued
operations................................. $(7,845) $ 523 $ 1,194
======== ======== ========
See Notes 2 and 5 of Notes to Consolidated Financial Statements.
LIQUIDITY AND CAPITAL RESOURCES
Recent Events
On February 28, 2000, the Company entered into a Purchase and Sale
Agreement to sell its 46% interest in LLC to Salomon for $3.0 million. The
proceeds from the sale will be used to reduce debt.
Credit Facility
The Company entered into an Amended and Restated Credit Agreement effective
December 1, 1998 ("Credit Facility"). The Credit Facility is comprised of two
tranches. Tranche A is a revolving credit facility with a termination date no
later than December 15, 2002. The Borrowing Base under Tranche A is $100 million
and is redetermined semi-annually by the bank. Availability can be affected
dramatically based upon the volatility of oil and gas prices. Tranche B is a
term loan which was repaid in March 1999.
Outstanding amounts under the Credit Facility bear interest, at the
Company's option, at either the Eurodollar Loan rate ("Libor"), or the Base Rate
(prime), plus the Applicable Margin. The Applicable Margin is determined by the
Borrowing Base Utilization Percentage. As a result, interest rates range from as
low as Libor plus 1.50% or the Base Rate plus 0.00% if 25% or less of the
Borrowing Base is used, to as high as Libor plus 2.50% or the Base Rate plus
0.75% if greater than 90% of the Borrowing Base is used.
The Credit Facility is secured by mortgages on substantially all of the
Company's oil and gas properties. The Credit Facility contains certain other
affirmative and negative covenants, including limitations on the ability of the
Company to incur additional debt, sell assets, merge or consolidate, pay
dividends on its capital in excess of historical levels, and a prohibition on
change of control or management.
As of December 31, 1999, Tranche A bore interest at 9% per annum on the
outstanding amount of $82 million.
Other
At December 31, 1999, the Company had working capital of $3.0 million. In
1999, cash provided from operating activities was $17.4 million.
In 1993, the Company issued 690,000 shares of $3.50 convertible preferred
stock. The net proceeds from the sale were $32.9 million. Dividends on the
convertible preferred stock are to be paid quarterly. Such dividends accrue and
are cumulative.
The Company has paid all dividends on time.
The Company currently anticipates spending approximately $100,000 during
fiscal years 2000 and 2001 at various facilities for capital and operating costs
associated with ongoing environmental compliance and may continue to have
expenditures in connection with environmental matters beyond fiscal year 2001.
The Company spent $36,000 on such expenditures in 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 and capital expenditure requirements. At December 31, 1999, the
Company had cash and cash equivalents of $2.1 million, and $17.8 million
available to it under the Credit Facility. A decline in the value of the
Company's proved reserves could result in the bank reducing the
14
Borrowing Base, thereby causing mandatory payments under the Credit Facility.
While the Company does not expect this to occur in 2000, such payments would
adversely affect the Company's ability to carry out its capital expenditure
program and could cause the Company to recapitalize its debt through the public
or private placement of securities.
ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities," ("SFAS 133"). SFAS 133 establishes accounting and
reporting standards for derivative instruments and hedging activities that
require an entity to recognize all derivatives as an asset or liability measured
at its fair value. Depending on the intended use of the derivative, changes in
its fair value will be reported in the period of change as either a component of
earnings or a component of other comprehensive income. SFAS 133 is effective for
all fiscal quarters of fiscal years beginning after June 15, 2000. Earlier
application of SFAS 133 is encouraged, but not prior to the beginning of any
fiscal quarter that began after issuance of the Statement. Retroactive
application to periods prior to adoption is not allowed. The Company has not
quantified the impact of adoption of SFAS 133 on its financial statements.
YEAR 2000 DATE CONVERSION
The Company implemented its plan that addressed the year 2000 ("Y2K")
conversion issue. The Company evaluated all computer systems used in its
operations, including accounting and financial systems, field and production
systems, and other significant field or office devices that might not have been
Y2K compliant. Further, the Company made a determination of what remedial action
would be necessary and completed corrective action on major office systems and
field systems during 1999.
The Company received assurances from its most important outside suppliers
and vendors that they could provide goods and services without disruption. The
Company has not had any disruption of goods and services.
The cost of Y2K conversion and compliance was approximately $420,000. Other
areas outside the Company's control such as problems in the utility, banking, or
transportation systems have not had a disruptive effect on the Company's ability
to produce and deliver oil and gas, receive delivery of materials and supplies,
or disburse or receive funds.
FORWARD-LOOKING STATEMENTS
Statements contained in this Report and other materials filed or to be
filed by the Company with the Securities and Exchange Commission (as well as
information included in oral or other written statements made or to be made by
the Company or its representatives) that are forward-looking in nature are
intended to be "forward-looking statements" within the meaning of Section 27A of
the Securities Act of 1933, as amended, and Section 21E of the Securities
Exchange Act of 1934, as amended, relating to matters such as anticipated
operating and financial performance, business prospects, developments and
results of the company. Actual performance, prospects, developments and results
may differ materially from any or all anticipated results due to economic
conditions and other risks, uncertainties and circumstances partly or totally
outside the control of the Company, including rates of inflation, oil and
natural gas prices, uncertainty of drilling results and reserve estimates,
changes in the level and timing of future costs and expenses related to drilling
and operating activities, competition from other exploration, development and
production companies, operating hazards, abandonment costs, the effects of
governmental regulation and the leveraged nature of the Company.
Words such as "anticipate", "expect", "project", and similar expressions
are intended to identify forward-looking statements.
Item 7A. Quantitative and Qualitative Disclosure About Market Risk
In order to guarantee the Company a specific minimum sales price for its
crude oil, the Company purchased a $16.50 per barrel put option and sold a
$21.10 per barrel call option covering 100,000 barrels of oil per month for a
six-month period ending February 28, 1997. For September through December 1996,
the monthly average sales price exceeded the ceiling price. This resulted in
collar payments for the four month period of $1.3 million which were recorded as
a reduction of revenue.
15
In 1997, the monthly average price of crude oil on the organized exchange
exceeded the strike price for the call option during January and February, the
final two months of the options. The payments required in 1997 under the call
option totaled $0.5 million and were recorded as a reduction of revenue.
In 1998, the Company purchased a put option and sold a call option covering
4,800 barrels of oil per day for a nine-month period ended December 31, 1998.
The strike prices were $16.00 per barrel for the put option and $19.25 per
barrel for the call option. There was no premium associated with these options.
During 1998, the Company received $2.8 million as a result of the options. These
amounts were recorded as additional revenues. Without the options the average
price per barrel of oil for the year ended December 31, 1998, would have been
reduced from $11.37 to $10.55.
The Company entered into two hedging programs for 1999. The first program
was a purchase of a put option and a sale of a call option covering 1,750
barrels of oil per day effective April 1, 1999, through December 31, 1999. The
strike prices were $15.00 per barrel for the put option and $17.00 per barrel
for the call option. The second program was a purchase of a put option and a
sale of a call option also covering 1,750 barrels of oil per day effective from
May 1, 1999, through December 31, 1999. The strike prices were $14.50 per barrel
for the put option and $18.80 per barrel for the call option. There were no
premiums associated with either of these programs. The strike price of the call
options was exceeded, resulting in a reduction of revenues of $3.5 million from
what would have been received had no hedging programs been in place. Without the
options the average price per barrel of oil for the year ended December 31, 1999
would have increased from $14.95 to $16.23.
The Company has also entered into two hedging programs for the year 2000.
The first program is a purchase of a put option and a sale of a call option
covering 1,700 barrels of oil per day effective January 1, 2000, through
December 31, 2000. The strike prices are $17.25 per barrel for the put option
and $22.00 per barrel for the call option. The second program is a purchase of a
put option and a sale of a call option covering 1,800 barrels of oil per day
effective January 1, 2000, through December 31, 2000. The strike prices are
$18.50 per barrel for the put option and $26.00 per barrel for the call option.
Each program provides for monthly settlements and is based on monthly averages.
There are no premiums associated with either program.
Item 8. Financial Statements and Supplementary Data
The response to this item is submitted as a separate section.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
Not applicable.
16
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 2000
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.... 63 Chairman and Chief Executive Officer
Richard K. Hebert.... 48 President and Chief Operating Officer
Allyn R. Skelton, II. 48 Vice President and Chief Financial Officer
Robert T. Moffett.... 48 Vice President, General Counsel and Secretary
John E. Brewster, Jr. 49 Vice President, Corporate Development and Planning
Mr. Donald W. Clayton was elected Chairman and Chief Executive Officer in
May 1997. From 1993 to 1997, he was co-owner and President of Voyager Energy
Corp. He formerly served as President and Director of Burlington Resources,
Inc., and President and Chief Executive Officer of Meridian Oil, Inc. Prior to
that, he was a senior executive with Superior Oil Company.
Mr. Richard K. Hebert was elected President and Chief Operating Officer in
May 1997. From 1993 to 1997, he was co-owner and Chief Executive Officer of
Voyager Energy Corp. He formerly served as Executive Vice President and Chief
Operating Officer of Meridian Oil, Inc., now Burlington Resources, Inc. Prior to
that, he served in various engineering and management positions with Mobil Oil
Corporation, Superior Oil Company and Amoco Production Company.
Mr. Allyn R. Skelton, II, was elected Vice President and Chief Financial
Officer of the Company in May 1999. He formerly served as Chief Financial
Officer of Genesis Energy, L.P. Prior to that he was Chief Financial Officer of
Howell Corporation.
Mr. Robert T. Moffett was elected Secretary in October 1996 and Vice
President and General Counsel in January 1994. He had served as General Counsel
of the Company since September 1992. Prior to that, Mr. Moffett was a general
partner in the firm of Moffett & Brewster.
Mr. John E. Brewster, Jr. was elected Vice President, Corporate Development
& Planning in May 1997. Prior to that he was a consultant to Voyager Energy
Corp. He has held senior management positions with Santa Fe Minerals, Inc.,
Odyssey Energy, Inc., and Trafalgar House Oil & Gas Inc., and was a general
partner in the firm of Moffett & Brewster.
Regarding delinquent filers pursuant to Item 405 of Regulation S-K, the
information appearing under the caption "Compliance with Section 16(a) of the
Securities Exchange Act of 1934" set forth in the Company's definitive proxy
statement, to be filed within 120 days after the close of the fiscal year in
connection with the 2000 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 2000 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 2000 Annual Shareholders' Meeting, is incorporated herein
by reference.
17
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 2000 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 20).
(a) (3) and (c). The response to this portion of Item 14 is submitted as
a separate section of this report (see page 38).
(b) Reports on Form 8-K. None.
18
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
HOWELL CORPORATION
(Registrant)
By /s/ALLYN R. SKELTON, II
----------------------------
Allyn R. Skelton, II
Vice President and
Chief Financial Officer
Principal Financial and Accounting Officer
Date: February 28, 2000
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 28, 2000
- - -------------------------------
Donald W. Clayton
Chairman
and
Chief Executive Officer
Principal Executive
/s/ RICHARD K. HEBERT Officer and Director February 28, 2000
- - -------------------------------
Richard K. Hebert
President
and
Chief Operating Officer
/s/ PAUL N. HOWELL Director February 28, 2000
- - -------------------------------
Paul N. Howell
/s/ JACK T. TROTTER Director February 28, 2000
- - -------------------------------
Jack T. Trotter
/s/WALTER M. MISCHER, SR. Director February 28, 2000
- - -------------------------------
Walter M. Mischer, Sr.
19
HOWELL CORPORATION AND SUBSIDIARIES
FORM 10-K
ITEMS 8, 14(a) (1) and (2)
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
The following consolidated financial statements of the registrant and its
subsidiaries required to be included in Items 8 and 14(a)(1) are listed below:
Page
Independent Auditors' Report................................... 21
Consolidated Financial Statements:
Consolidated Balance Sheets.................................. 22
Consolidated Statements of Operations........................ 23
Consolidated Statements of Changes in Shareholders' Equity... 24
Consolidated Statements of Cash Flows........................ 25
Notes to Consolidated Financial Statements................... 26
The financial statement schedules are omitted because they are not
applicable, are not required or because the required information is included in
the Consolidated Financial Statements or notes thereto.
20
INDEPENDENT AUDITORS' REPORT
To Howell Corporation:
We have audited the accompanying consolidated balance sheets of Howell
Corporation and its subsidiaries as of December 31, 1999 and 1998, and the
related consolidated statements of operations, changes in shareholders' equity,
and cash flows for each of the three years in the period ended December 31,
1999. 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, 1999 and 1998, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1999 in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Houston, Texas
February 28, 2000
21
HOWELL CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
December 31,
--------------------
1999 1998
---- ----
(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents ...................... $ 2,112 $ 5,871
Trade accounts receivable, less allowance
for doubtful accounts of
$161 in 1999 and $156 in 1998 ............. 10,978 9,230
Income tax receivable .......................... - 5,701
Deferred income taxes .......................... 2,027 7,530
Other current assets ........................... 2,440 577
--------- ---------
Total current assets ........................ 17,557 28,909
--------- ---------
Property, plant and equipment:
Oil and gas properties, utilizing the
full-cost method of accounting ............ 382,393 385,048
Unproven properties ............................ 21,143 43,263
Other .......................................... 2,759 2,653
Less accumulated depreciation, depletion
and amortization .......................... (313,249) (309,330)
--------- ---------
Net property, plant and equipment ........... 93,046 121,634
--------- ---------
Assets related to discontinued operations ......... 3,000 16,908
Deferred income taxes ............................. 3,600 -
Other assets ...................................... 780 2,962
--------- ---------
Total assets ................................ $117,983 $170,413
========= =========
Liabilities and Shareholders' Equity
Current liabilities:
Current maturities of long-term debt ........... $ - $ 22,000
Accounts payable ............................... 10,513 8,639
Accrued liabilities ............................ 3,934 5,520
Income taxes payable ........................... 140 -
--------- ---------
Total current liabilities ................... 14,587 36,159
--------- ---------
Deferred income taxes ............................. - 4,122
--------- ---------
Other liabilities ................................. 716 1,261
--------- ---------
Long-term debt .................................... 82,000 102,000
--------- ---------
Commitments and contingencies Shareholders' equity:
Preferred stock, $1 par value; 690,000
shares issued and outstanding;
liquidation value of $34,500,000 ........... 690 690
Common stock, $1 par value; 5,471,782
shares issued and outstanding .............. 5,472 5,472
Additional paid-in capital ..................... 40,829 40,829
Retained deficit ............................... (26,311) (20,120)
--------- ---------
Total shareholders' equity .................. 20,680 26,871
--------- ---------
Total liabilities and shareholders' equity... $117,983 $170,413
========= =========
See accompanying Notes to Consolidated Financial Statements.
22
HOWELL CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations
Year Ended December 31,
---------------------------------
1999 1998 1997
---- ---- ----
(In thousands, except per share amounts)
Revenues:
Oil & gas ........................... $ 48,310 $ 51,422 $ 34,663
--------- --------- ---------
Costs and expenses:
Operating expenses - oil & gas ....... 23,093 27,764 14,825
Depreciation, depletion and
amortization ....................... 6,671 11,703 9,460
Impairment of oil & gas properties ... - 102,167 -
General and administrative expenses .. 3,794 3,447 5,093
--------- --------- ---------
33,558 145,081 29,378
--------- --------- ---------
Other income (expense):
Interest expense ..................... (7,329) (10,997) (1,490)
Interest income ...................... 118 111 145
Other-net ............................ 45 (1) 103
--------- --------- ---------
(7,166) (10,887) (1,242)
--------- --------- ---------
Earnings (loss) from continuing
operations before income taxes .......... 7,586 (104,546) 4,043
Income tax expense (benefit) ............ 2,641 (36,470) 1,156
--------- --------- ---------
Net earnings (loss) from continuing
operations ........................ 4,945 (68,076) 2,887
Discontinued operations:
Net (loss) earnings (less applicable
income taxes of $(3,950), $483,
and $830 for 1999, 1998 and 1997,
respectively) ..................... (7,845) 523 1,194
--------- --------- ---------
Net (loss) earnings ..................... (2,900) (67,553) 4,081
Less: cumulative preferred stock
dividends .......................... (2,415) (2,415) (2,415)
--------- --------- ---------
Net (loss) earnings applicable to common
stock .............................. $ (5,315) $(69,968) $ 1,666
========= ========= =========
Basic earnings (loss) per common share:
Continuing operations ................ $ 0.46 $ (12.89) $ 0.09
Discontinued operations .............. (1.43) 0.10 0.18
Gain on sale of Howell Hydrocarbons .. - - 0.05
--------- --------- ---------
Net (loss) earnings per common share-
basic .............................. $ (0.97) $ (12.79) $ 0.32
========= ========= =========
Weighted average shares outstanding -
basic .............................. 5,472 5,470 5,143
========= ========= =========
Diluted earnings (loss) per common share:
Continuing operations ................ $ 0.46 $ (12.89) $ 0.09
Discontinued operations .............. (1.42) 0.10 0.17
Gain on sale of Howell Hydrocarbons .. - - 0.05
--------- --------- ---------
Net (loss) earnings per common share-
diluted ............................ $ (0.96) $ (12.79) $ 0.31
========= ========= =========
Weighted average shares outstanding -
diluted ............................ 5,554 5,470 5,355
========= ========= =========
See accompanying Notes to Consolidated Financial Statements.
23
HOWELL CORPORATION AND SUBSIDIARIES
Consolidated Statements of Changes in Shareholders' Equity
Preferred Stock Common Stock Retained
--------------- ------------ Paid-In Earnings
Shares $ Shares $ Capital (Deficit) Total
------ --- ------ --- ------- --------- -----
(In thousands, except number of shares)
Balances, December 31, 1996 ............. 690,000 $690 4,947,196 $4,947 $34,532 $ 49,879 $ 90,048
Net earnings - 1997 ................... - - - - - 4,081 4,081
Cash dividends - $0.16 per
common share ....................... - - - - - (821) (821)
Cash dividends - $3.50 per
preferred share .................... - - - - - (2,415) (2,415)
Common stock issued to employees upon
purchase of Voyager Energy ......... - - 352,638 353 4,276 - 4,629
Common stock issued to employees
upon exercise of stock options ..... - - 164,808 165 1,608 - 1,773
Tax benefit upon exercise of employee
stock options ...................... - - - - 344 - 344
------- ---- --------- ------ ------- --------- ---------
Balances, December 31, 1997 ............. 690,000 $690 5,464,642 $5,465 $40,760 $ 50,724 $ 97,639
Net earnings - 1998 ................... - - - - - (67,553) (67,553)
Cash dividends - $0.16 per
common share ....................... - - - - - (876) (876)
Cash dividends - $3.50 per
preferred share .................... - - - - - (2,415) (2,415)
Common stock issued to employees
upon exercise of stock options ..... - - 7,140 7 56 - 63
Tax benefit upon exercise of employee
stock options ...................... - - - - 13 - 13
------- ---- --------- ------ ------- --------- ---------
Balances, December 31, 1998 ............. 690,000 $690 5,471,782 $5,472 $40,829 $(20,120) $ 26,871
Net earnings - 1999 ................... - - - - - (2,900) (2,900)
Cash dividends - $0.16 per
common share ....................... - - - - - (876) (876)
Cash dividends - $3.50 per
preferred share .................... - - - - - (2,415) (2,415)
------- ---- --------- ------ ------- --------- ---------
Balances, December 31, 1999.............. 690,000 $690 5,471,782 $5,472 $40,829 $(26,311) $ 20,680
======= ==== ========= ====== ======= ========= =========
See accompanying Notes to Consolidated Financial Statements.
24
HOWELL CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Year Ended December 31,
----------------------------------
1999 1998 1997
---- ---- ----
(In thousands)
OPERATING ACTIVITIES:
Net earnings (loss) from continuing operations ............ $ 4,945 $(68,076) $ 2,887
Adjustments for non-cash items:
Depreciation, depletion and amortization................. 6,671 113,870 9,460
Deferred income taxes ................................... 2,548 (36,470) 1,221
Gain on sale of assets .................................. - (2) (132)
--------- --------- ---------
Earnings from continuing operations plus non-cash
operating items.......................................... 14,164 9,322 13,436
Changes in components of working capital from operations:
(Increase) in trade accounts receivable ................. (1,749) (6,005) (351)
Decrease (increase) in inventories ...................... - 5 (7)
Decrease (increase) in income tax receivable ........... 5,701 3,486 (3,455)
(Increase) decrease in other current assets ............. (1,863) 3,203 (2,543)
Increase (decrease) in accounts payable ................. 1,882 6,514 (962)
(Decrease) increase in accrued and other liabilities .... (2,017) 969 (295)
--------- --------- ---------
Cash provided by continuing operations .................... 16,118 17,494 5,823
Cash provided by (utilized by) discontinued operations .... 1,315 2,077 (906)
--------- --------- ---------
Cash provided by operating activities ....................... 17,433 19,571 4,917
--------- --------- ---------
INVESTING ACTIVITIES:
Proceeds from the disposition of property ................. 28,715 13,333 20,053
Additions to property, plant and equipment ................ (6,768) (22,607) (128,199)
Deposit for Amoco Beaver Creek acquisition ................ - 12,369 (12,369)
Other, net ................................................ 2,152 (623) (137)
--------- --------- ---------
Cash provided by (utilized in) investing activities ......... 24,099 2,472 (120,652)
--------- --------- ---------
FINANCING ACTIVITIES:
Long-term debt:
(Repayments) borrowings under credit facilities-net ..... (42,000) (13,000) 119,000
Repayments to Department of Energy ...................... - - (4,999)
Cash dividends:
Common shareholders ..................................... (876) (876) (821)
Preferred shareholders .................................. (2,415) (2,415) (2,415)
Exercise of stock options ............................... - 63 1,773
--------- --------- ---------
Cash utilized in financing activities ....................... (45,291) (16,228) 112,538
--------- --------- ---------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS ........ (3,759) 5,815 (3,197)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR ................ 5,871 56 3,253
--------- --------- ---------
CASH AND CASH EQUIVALENTS, END OF YEAR ...................... $ 2,112 $ 5,871 $ 56
========= ========= =========
See accompanying Notes to Consolidated Financial Statements.
25
HOWELL CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Note 1. Summary of Significant Accounting Policies
Principles of Consolidation
The consolidated financial statements include the accounts of Howell
Corporation and its subsidiaries ("Company"). The Company previously accounted
for its investment in Genesis using the equity method of accounting. See Note 5.
All significant intercompany accounts and transactions have been eliminated.
Nature of Operations
The Company is engaged in the exploration, production, acquisition and
development of oil and gas properties. These operations are conducted in the
United States.
Property, Depreciation, Depletion and Amortization
The Company follows the full cost method of accounting for its oil and gas
exploration and production activities. Consequently, all costs pertaining to the
acquisition, exploration and development of oil and gas reserves are capitalized
and amortized using the unit-of-production method as the remaining proved oil
and gas reserves are produced. The Company's net investment in oil and gas
properties is subject to a quarterly ceiling limitation calculation that is
based on the present value of future net revenues from estimated production of
proved oil and gas reserves valued at current prices. Costs in excess of the
ceiling limitation are currently charged to expense. Gains or losses upon the
disposition of a property, normally treated as an adjustment to capitalized
costs, are recognized currently in the event of a sale of a significant portion
(normally in excess of 25%) of oil and gas reserves.
The costs allocated to the unproven properties of the Company are excluded
from amortization using the full cost method of accounting described above.
These costs are reviewed periodically for impairment. This impairment will
generally be based on geographic or geologic data. At the time of any
impairment, the related costs will be added to the costs being amortized under
the full cost method of accounting. Other property and equipment are carried at
cost. Depreciation is provided principally using the straight-line method over
the estimated useful lives of the assets.
Maintenance and repairs are charged to expense as incurred, while renewals
and betterments are capitalized.
Income Taxes
The Company utilizes a balance sheet approach in the calculation of the
deferred tax balance at each financial statement date by applying the provisions
of enacted tax laws to measure the deferred tax consequences of the differences
in the tax and book bases of assets and liabilities as they result in net
taxable or deductible amounts in future years. The net taxable or deductible
amounts in future years are adjusted for the effect of utilizing the
carryback/carryforward attributes of any net losses generated and available tax
credits. Deferred tax assets are recognized if it is more likely than not that
the future tax benefit will be realized.
Earnings Per Common Share
Basic earnings per common share amounts are calculated using the average
number of common shares outstanding during each period. Diluted earnings per
share assumes conversion of dilutive convertible preferred stocks and exercise
of all outstanding stock options having exercise prices less than the average
market price of the common stock using the treasury stock method.
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
$7,318,000,
26
$10,184,000 and $1,347,000 in 1999, 1998 and 1997, respectively. In 1999, 1998
and 1997, cash payments for income taxes totaled $768,000, $261,000 and
$6,849,000, respectively.
Disclosures About Fair Value of Financial Instruments
The Company estimates that the carrying amount of its cash and cash
equivalents and accounts receivable and payable as reflected in its balance
sheet approximates fair value.
Stock Based Compensation
The intrinsic value method of accounting is used for stock-based employee
compensation whereby no compensation expense is recognized when the exercise
price of an employee stock option is equal to or greater than the market price
of the Company's common stock on the grant date.
Environmental Liabilities
The Company provides for the estimated costs of environmental contingencies
when liabilities are likely to occur and reasonable estimates can be made. In
accordance with full cost accounting rules, the Company provides for future
environmental clean-up costs associated with oil and gas activities as a
component of its depreciation, depletion and amortization expense. Information
regarding environmental liabilities can be found in Note 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.
During 1996, 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. In 1997, the monthly average price of crude oil on the organized
exchange exceeded the strike price for the call option during January and
February, the final two months of the options. The payments required in 1997
under the call option totaled $0.5 million and were recorded as a reduction of
revenue.
In 1998, the Company purchased a put option and sold a call option covering
4,800 barrels of oil per day for a nine-month period ended December 31, 1998.
The strike prices were $16.00 per barrel for the put option and $19.25 per
barrel for the call option. There was no premium associated with these options.
During 1998, the Company received $2.8 million as a result of the options. These
amounts were recorded as additional revenues. Without the options the average
price per barrel of oil for the year ended December 31, 1998, would have been
reduced from $11.37 to $10.55.
The Company entered into two hedging programs for 1999. The first program
was a purchase of a put option and a sale of a call option covering 1,750
barrels of oil per day effective April 1, 1999, through December 31, 1999. The
strike prices were $15.00 per barrel for the put option and $17.00 per barrel
for the call option. The second program was a purchase of a put option and a
sale of a call option also covering 1,750 barrels of oil per day effective from
May 1, 1999, through December 31, 1999. The strike prices were $14.50 per barrel
for the put option and $18.80 per barrel for the call option. There was no
premium associated with either of these programs. The strike price of the call
options was exceeded resulting in a reduction of revenues of $3.5 million from
what would have been received had no hedging programs been in place for 1999.
Without the options the average price per barrel of oil for the year ended
December 31, 1999 would have increased from $14.95 to $16.23.
The Company has also entered into two hedging programs for the year 2000.
The first program is a purchase of a put option and a sale of a call option
covering 1,700 barrels of oil per day effective January 1, 2000, through
December 31, 2000. The strike prices are $17.25 per barrel for the put option
and $22.00 per barrel for the call option. The second program is a purchase of a
put option and a sale of a call option covering 1,800 barrels of oil per day
effective January 1, 2000, through December 31, 2000. The strike prices are
$18.50 per barrel for the put option and $26.00 per barrel for the call option.
There are no premiums associated with either program.
27
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, 1999 or 1998.
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 1998 and 1997 financial
presentation to conform with the 1999 presentation.
Note 2. Acquisitions and Dispositions
1999
- - ----
On January 4, 1999, the Company sold its right to participate in the future
earnings of Specified Fuels & Chemicals, Inc. ("SFC") for $2.0 million. SFC
acquired the Company's Technical Fuels and Chemical Processing business in July
1997. The sale and the results of operations of this business have been
classified as discontinued operations in the accompanying consolidated financial
statements. Discontinued operations include an after-tax gain of $1.3 million
for the year ended December 31, 1999, as a result of the sale.
On January 29, 1999, the Company sold its interest in the LaBarge field,
located in southwestern Wyoming, for $15.8 million. The properties consisted of
three Federal units, 17 producing wells and related field facilities. In
addition to natural gas, the properties produced carbon dioxide, helium and
sulfur.
On March 19, 1999, the Company sold its interests in the Grass Creek Unit
in Hot Springs County, Wyoming, and the Pitchfork Unit in Park County, Wyoming
for $12.6 million, net of closing adjustments. The Company owned a 25% working
interest at Pitchfork and various working interests ranging from 13.08% to
43.14% in different producing horizons at Grass Creek.
The properties sold during 1999 were not considered to be integral to the
Company's future. The cumulative proceeds from these events were used to reduce
debt. See Note 6.
During 1999, the Company recognized a pre-tax loss of $13.8 million with
respect to its equity interest in Genesis. The loss was a result of the
impairment of the investment in Genesis to market value.
On February 28, 2000, the Company entered into a Purchase and Sale
Agreement to sell its 46% interest in LLC to SSB for $3 million. The proceeds
from the sale will be used to reduce debt. The Company does not expect to
receive any proceeds for its subordinated units in GCO. No gain or loss will be
recognized on the sale. See Note 5.
1998
- - ----
On December 17, 1998, the Company sold its fee mineral estates and royalty
interests comprised of approximately 875,000 acres located in the states of
Alabama, Mississippi and Louisiana for $13.0 million. As
28
additional contingent consideration, the Company has the right to receive 10% of
the net profits generated from the properties after payout. The net daily
production attributable to these assets was approximately 350 BOE. Proceeds from
the sale were used to reduce bank debt. See Note 6.
During 1998, the Company received a $0.7 million pre-tax payment from SFC
as stipulated under the Minimum EBITDA provision of the July 31, 1997 sale
agreement.
Effective May 22, 1998, Howell Petroleum Corporation ("HPC"), a wholly
owned subsidiary of Howell Corporation, entered into a Settlement Agreement and
Release with Amoco Production Company ("Amoco") and Snyder Oil Corporation
whereby the parties agreed to settle the litigation that was pending among them.
Under the terms of the settlement, HPC agreed to relinquish its contractual
rights to purchase that portion of the Amoco Wyoming package relating to the
Beaver Creek Unit and the associated facilities. In addition, Amoco agreed to
sell to HPC an approximate 31% working interest in the Higgins Unit located in
Sweetwater County, Wyoming, and a 1.95% overriding royalty interest covering
over 78,000 acres in the Natural Buttes Field located in Uintah County, Utah.
The purchase price for these predominately gas properties was $11 million. HPC's
in-house petroleum engineers estimated total proved reserves of 8.1 BCFE
attributable to these properties. Net daily production from the properties was
approximately 1.8 MMCF of natural gas with a projected reserves-to-production
index of 12 years. The operating results of the assets acquired from Amoco in
this transaction have been included in the Company's Statements of Operations
since May 22, 1998. Pro forma information is not required because of
materiality.
1997
- - ----
On December 18, 1997, the Company purchased certain oil and gas producing
properties ("Package") in Wyoming from 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 Package was
accounted for using the purchase method of accounting, and accordingly, the
purchase price was allocated to the assets acquired based on estimated fair
values at the date of acquisition. The operating results of the Package acquired
from Amoco have been included in the Company's Statement of Operations since
December 18, 1997. The pro forma information shown below assumes that the
effective date of the acquisition was January 1, 1997. Adjustments have been
made to reflect changes in the Company's results from revenues and direct
operating expenses of the producing properties acquired from Amoco, additional
interest expense to reflect the acquisition, depreciation, depletion and
amortization based on fair values assigned to the assets acquired, and general
and administrative expenses incurred from hiring additional employees. The
unaudited pro forma financial data is not necessarily indicative of financial
results that would have occurred had the acquisition occurred on January 1,
1997, and should not be viewed as indicative of operations in future periods.
Pro Forma
Unaudited
Year Ended December 31, 1997
----------------------------
(In thousands, except per share data)
Revenues .................................... $ 88,394
Net earnings from continuing operations ..... $ 12,787
Net earnings from continuing operations per
common share - basic ...................... $ 2.02
Net income from continuing operations per
common share - diluted .................... $ 1.72
The acquisition was financed with bank debt. See Note 6.
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 represented in the aggregate approximately 6.5 percent of
the Company's common stock outstanding after the transaction. The value of the
shares was $4.6 million. The shares were distributed as a non-cash transaction
and, as such, are not reflected in the Consolidated Statements of Cash Flows for
the year ended December 31, 1997. The Company assumed approximately $1.3 million
in Voyager indebtedness as a result of the merger.
On July 31, 1997, the Company completed the sale and disposition of
substantially all of the assets of its Technical Fuels and Chemical Processing
business to SFC.
29
In connection with the transaction, SFC received a license to use the name
"Howell Hydrocarbons & Chemicals" for a five-year period after closing and it
assumed certain obligations of Seller and the Company. The Company agreed not to
engage (directly or through affiliates) in any competing business for a
five-year period after the closing.
The sale resulted in a pre-tax gain of $0.4 million. The proceeds of the
sale were used by the Company to reduce its outstanding indebtedness. In
connection with the sale, the Company has given and received environmental and
other indemnities. Claims could arise in the future that would require the
Company to perform under those indemnities.
In consideration for the assets sold to SFC, 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 for working capital
items. The Company was entitled to receive an additional payment equal to 55% of
the amount by which SFC's EBITDA, for a period of five years, exceeded specific
target levels for each year.
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
$0.1 million of interest expense (based on a ratio of net assets of discontinued
operations to total consolidated net assets) for 1997.
Note 3. Income Taxes
A summary of the provision for income taxes (benefit) from operations
included in the Consolidated Statements of Operations is as follows:
Year Ended December 31,
----------------------------
1999 1998 1997
---- ---- ----
(In thousands)
Current:
Federal................................ $ - $ - $ 285
State.................................. 93 (119) 81
Deferred................................. 2,548 (36,351) 790
-------- --------- -------
Income taxes from continuing operations.. 2,641 (36,470) 1,156
Income taxes from discontinued
operations............................. (3,950) 483 704
Income taxes from sale of discontinued
operations............................. - - 126
-------- --------- -------
$(1,309) $(35,987) $1,986
======== ========= =======
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,
-----------------------
1999 1998
---- ----
(In thousands)
Accrual of costs not deductible for tax......... $ 55 $ 53
Difference between book and tax bases
in investment in Genesis ..................... 1,972 -
Net operating loss carryforward ................ - 7,477
-------- --------
Net current deferred tax assets .............. $ 2,027 $ 7,530
======== ========
Accrual of costs not deductible for tax......... $ 381 $ 736
Differences between book and tax bases ......... - (1,360)
Differences between book and tax bases
of property, plant and equipment ............. 2,541 (3,498)
Alternative minimum tax credit
carryforwards ................................ 1,265 895
Valuation allowance ............................ (587) (895)
-------- --------
Net non-current deferred assets
(liabilities) .............................. $ 3,600 $(4,122)
======== ========
30
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,
-----------------------------
1999 1998 1997
---- ---- ----
(In thousands)
Provision for income taxes at the
statutory rate............................. $ 2,548 $(35,505) $ 1,347
Statutory depletion in excess of cost
basis...................................... - - (278)
State income taxes........................... 93 (119) 81
Other........................................ - (846) 6
-------- --------- --------
$ 2,641 $(36,470) $ 1,156
======== ========= ========
As of December 31, 1999, the Company had no operating loss carryforwards
for federal income tax purposes.
Note 4. Discontinued Operations
The following table presents the detail of net (loss) income from
discontinued operations as presented on the Consolidated Statements of
Operations:
Year Ended December 31,
------------------------------
1999 1998 1997
---- ---- ----
(in thousands)
Discontinued operations:
Net (loss) earnings of Genesis (less
applicable income taxes of $(4,702),
$133 and $316 for 1999, 1998 and
1997, respectively)...................... $(9,129) $ 257 $ 421
Net earnings from Howell Hydrocarbons
(less applicable income taxes of
$752, $350 and $388 for 1999, 1998
and 1997, respectively).................. 1,284 266 528
Gain on sale of Howell Hydrocarbons
(less applicable income
taxes of $126 for 1997).................. - - 245
-------- -------- --------
Net (loss) earnings from discontinued
operations................................. $(7,845) $ 523 $ 1,194
======== ======== ========
See Notes 2 and 5.
Note 5. Investment in Genesis
On December 1, 1996, the Company conveyed the assets and business of its
crude oil gathering and marketing operations and pipeline operations to Genesis
Crude Oil, L.P., a Delaware limited partnership ("GCO"). Howell received cash of
approximately $74 million and 991,300 subordinated limited partner units of GCO.
Additionally, the Company received 46% of Genesis Energy, L.L.C., a Delaware
limited liability company ("LLC") which is the General Partner of GCO. Howell
recognized a gain of approximately $13.8 million.
A subsidiary of Salomon Smith Barney Holdings Inc. ("SSB") conveyed similar
assets to GCO. SSB owns 54% of LLC. SSB is obligated to provide distribution
support to GCO should GCO have inadequate funds to make the minimum quarterly
distribution to its common unit holders. SSB receives additional partnership
interests ("APIs") to the extent it funds this obligation. Howell is obligated
to purchase from SSB 46% of any outstanding APIs, but only to the extent of any
distribution made to Howell by GCO on Howell's subordinated limited partner
units.
Howell retained all liabilities arising from the operations, activities and
transactions of the business up through the closing date, including various
environmental-related liabilities. Howell made various representations and
warranties as to itself and the business and has agreed to indemnify GCO for any
breaches thereof. Claims for breaches of such representations and warranties
must be brought before December 3, 2001. Howell also agreed to perform, and
retain the liability for, the cleaning of certain tanks used in the pipeline
operations which was completed in 1997.
31
On the closing date, Howell entered into various agreements with the buyer
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 sale of
crude oil by Howell from its oil and gas exploration and production business;
and (c) an agreement whereby one-half of the subordinated limited partner units
owned by Howell were pledged to secure Howell's indemnification of GCO for
environmental liabilities.
Summarized financial information for GCO for the years ended December 31,
1999 and 1998, is as follows:
1999 1998
---- ----
(In thousands)
Revenues............................... $2,161,012 $2,233,475
Net income............................. $ 2,915 $ 8,819
Current assets......................... $ 274,712 $ 185,211
Property & equipment, net.............. $ 90,805 $ 95,083
Total assets........................... $ 380,587 $ 297,168
Current liabilities.................... $ 272,677 $ 183,233
Partners' capital...................... $ 84,110 $ 98,135
The financial results of GCO have recently deteriorated even as the market
has returned to what has historically been a more favorable price environment.
For each of the last three quarters of 1999, SSB has had to perform under its
distribution support agreement. While there are no arrearages with respect to
the common units, GCO has never made a distribution with respect to the
subordinated units held by Howell and SSB. The Company now believes that it is
more likely than not that distributions will never be paid on the subordinated
units.
With only a minority interest in LLC, Howell is not in a position to
substantially influence management of GCO. Accordingly, the Company has decided
to dispose of its interests in GCO and LLC. The Company has recorded an
impairment charge of $13.5 million (pre-tax) to the carrying value of its
investment and classified its operations as discontinued. During 1999, the
investment in Genesis incurred a pre-tax loss of $13.8 million primarily as a
result of the impairment charge. The loss is reflected in Discontinued
Operations. See Note 4.
On February 28, 2000, the Company entered into a Purchase and Sale
Agreement to sell its 46% interest in L.L.C. to SSB for $3 million. The proceeds
from the sale will be used to reduce debt. The Company does not expect to
receive any proceeds for its subordinated units in GCO. No gain or loss will be
recognized on the sale.
Note 6. Debt and Available Credit Facilities
Debt of the Company as of December 31, 1999 and 1998, was as follows:
1999 1998
---- ----
(In thousands)
Note payable under a $100 million revolving
credit/term loan agreement at December 31,
1999 and $127 million at December 31, 1998.... $ 82,000 $124,000
Less: Current maturities....................... - 22,000
-------- --------
Balance, due 2002............................... $ 82,000 $102,000
======== ========
The Company entered into an Amended and Restated Credit Agreement effective
December 1, 1998 ("Credit Facility"). The Credit Facility is comprised of two
tranches. Tranche A is a revolving credit facility with a termination date no
later than December 15, 2002. The Borrowing Base under Tranche A is $100 million
and is redetermined semi-annually by the bank. Availability can be affected
dramatically based upon the volatility of oil and gas prices. Tranche B is a
term loan which was repaid in March 1999. The Company was required to pay
commitment fees on the unused portion of Tranche A at a rate of 0.375% per annum
while Tranche B was outstanding. After Tranche B was repaid, the commitment fee
became based upon the Borrowing Base Utilization at a rate of 0.25% per annum if
25% or less of the borrowing base is used, 0.30% if more than 25% and less than
or equal to 75% is used, and 0.375% if more than 75% is used.
Outstanding amounts under the Credit Facility bear interest, at the
Company's option, at either the Eurodollar Loan rate ("Libor") per annum, or the
Base Rate (prime), plus the Applicable Margin. The Applicable Margin is
determined by the Borrowing Base Utilization Percentage. As a result, interest
rates range from as low
32
as Libor plus 1.50% or the Base Rate plus .00% if 25% or less of the borrowing
base is used, to as high as Libor plus 2.50% or the Base Rate plus .75% if
greater than 90% of the borrowing base is used.
The Credit Facility is secured by mortgages on substantially all of the
Company's oil and gas properties. The Credit Facility contains certain other
affirmative and negative covenants, including limitations on the ability of the
Company to incur additional debt, sell assets, merge or consolidate, or pay
dividends on its capital in excess of historical levels and a prohibition on
change of control or management. In addition, the Credit Facility requires the
Company to maintain a ratio of current assets plus Tranche A borrowing capacity
to current liabilities, excluding current maturities of long-term debt, of at
least 1.0 to 1.0 and an interest coverage ratio of not less than 1.5 to 1.0 on a
rolling four quarter basis through June 30, 1999, and beginning in the third
quarter of 1999 and thereafter, of not less than 2.5 to 1.0 at the end of any
fiscal quarter.
The Company reduced debt, including the repayment of Tranche B, by $42.0
million during 1999 as a result of the sale of non-integral properties for $28.7
million, a tax refund of $5.7 million, the buyout by SFC of its remaining excess
EBITDA payments for $2.0 million, and other cash provided by continuing
operations of $5.6 million.
As of December 31, 1999, $82.0 million was outstanding on Tranche A and the
interest rate was 9% per annum.
At December 31, 1999, the Company had cash and cash equivalents of $2.1
million, and $17.8 million available to it under the Credit Facility. Should a
decline in the value of the Company's proved reserves occur, the bank could
reduce the borrowing base, thereby causing mandatory payments under the Credit
Facility.
The fair value of the Company's long-term debt at December 31, 1999 and
1998, was estimated to be the same as its carrying value in the balance sheet
since all significant debt obligations bear interest at floating market rates.
Note 7. Shareholders' Equity
Preferred stock
At December 31, 1999 and 1998, 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, 1999 and 1998, the Company had 50,000,000 shares of common
stock authorized.
Employee stock options
The Company maintains nonqualified stock option plans that allow the
Company to grant stock options and other forms of equity-based incentives to the
Company's executives, key employees, and non-employee directors. Stock options
may be granted for periods up to 10 years and are generally subject to vesting
over a period up to four years. At December 31, 1999, 504,250 shares were
available for future option grants.
33
Stock option activity for the Company during 1999, 1998 and 1997 was as
follows:
1999 1998 1997
-------------------- ------------------- -------------------
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 ....... 948,165 $13.06 936,030 $12.91 431,914 $11.24
Granted.................. 173,000 $ 2.81 33,250 $16.50 721,380 $13.37
Exercised................ - (7,140) $ 8.88 (164,808) $10.76
Expired.................. - - -
Forfeited................ (586,339) (13,975) (52,456)
--------- -------- ---------
Stock options outstanding,
end of year.............. 534,826 $ 9.84 948,165 $13.06 936,030 $12.91
========= ======== =========
At December 31, 1999, options were exercisable for 274,439 shares at a
weighted average exercise price of $12.68. The range of exercise prices on
outstanding options at December 31, 1999, was $2.13 to $18.75. The remaining
contractual life of these options was approximately 8.5 years.
The following pro forma summary of the Company's consolidated results of
operations have been prepared as if the fair value based method of accounting
for stock based compensation had been applied:
1999 1998 1997
---- ---- ----
Net (loss) earnings.................. $(2,900,000) $(67,553,000) $4,081,000
Fair value adjustment................ (742,332) (770,000) (482,000)
------------ ------------- -----------
Pro Forma net (loss) earnings........ $(3,642,332) $(68,323,000) $3,599,000
============ ============= ===========
(Loss) earnings per share as
reported - basic................... $ (0.97) $ (12.79) $ 0.32
============ ============= ===========
Pro Forma (loss) earnings per
share - basic...................... $ (1.11) $ (12.93) $ 0.23
============ ============= ===========
(Loss) earnings per share as
reported - diluted................. $ (0.96) $ (12.79) $ 0.31
============ ============= ===========
Pro Forma (loss) earnings per
share - diluted.................... $ (1.09) $ (12.93) $ 0.22
============ ============= ===========
The weighted average fair value of options granted during 1999, 1998 and
1997 was $3.12, $7.94 and $5.46, 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 1999, 1998 and 1997 were as follows:
1999 1998 1997
---- ---- ----
Weighted average expected life: 8.5 years 8.5 years 8.5 years
Volatility factor: 51.97% 42.33% 24.38%
Dividend yield: 3.06% 1.00% 1.00%
Weighted average risk free interest rate: 5.45% 3.64% 6.19%
Note 8. Litigation
There are various lawsuits and claims arising in the ordinary course of
business against the Company, none of which, in the opinion of management, will
have a material adverse effect on the Company.
Note 9. Commitments and Contingencies
The Company is subject to various environmental regulations and laws.
Procedures exist within the Company to monitor compliance and assess the
potential environmental exposure of the Company. Management believes that such
exposure is not materially adverse to its financial position, results of
operations or cash flows of the Company.
34
The Company has indemnified Exxon for certain environmental claims that may
be made in the future attributable to the time when Exxon owned the crude oil
pipelines that the Company acquired from Exxon. In 1996, the crude oil pipelines
were conveyed to GCO. The Company, however, retained liability under the Exxon
indemnification and for certain other potential environmental claims which
management believes will not have a material impact on the financial position,
results of operations or cash flows of the Company. See Note 5.
In 1997, the Channelview facility was sold to SFC. The Company retained
liability for certain environmental claims for a period of five years, which
management believes will not have a material impact on the financial position,
results of operations or cash flows of the Company.
The Company has indemnified Amoco for all third party claims other than
those for which Amoco is obligated to indemnify the Company regardless of
whether the claims relate to periods of time prior to or after the closing.
Management does not believe that liabilities arising from this indemnity will
have a material impact on the financial position, results of operations or cash
flows of the Company.
Under the terms of the purchase agreement, Amoco has a 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 on up to 4,000 barrels per day
of sweet crude oil production net to the Company's interest from the acquired
Salt Creek field. Beginning March 1, 1998, for a seven-year period, Amoco has a
call on 2,000 barrels per day of sour crude oil production net to the Company's
interest from the acquired Elk Basin field. The prices paid to the Company under
these calls, have fluctuated based on market conditions.
The Company occupies office and operational facilities and uses equipment
under operating lease arrangements. Expense of these arrangements amounted to
$485,000 in 1999, $425,000 in 1998, and $425,000 in 1997. At December 31, 1999,
long-term commitments for lease of facilities and equipment totaled
approximately $3,556,000, consisting of $672,000 for each year 2000 through
2003, and $868,000 thereafter.
35
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.
1999
- - ----
Increase
in Earnings
Increase Number per
in of Incremental
Income Shares Share
----------- --------- -----------
Options...................................... - 81,830 -
Dividends on convertible preferred stock..... $ 2,415,000 2,090,909 $1.16
Computation of Diluted Earnings per Share
Income
Available
from
Continuing Common Per
Operations Shares Share
----------- --------- ---------
$ 2,530,000 5,471,782 $0.46
Common stock options......................... - 81,830 -
----------- --------- ---------
$ 2,530,000 5,553,612 $0.46 Dilutive
Dividends on convertible preferred stock..... $ 2,415,000 2,090,909 -
----------- --------- ---------
$ 4,945,000 7,644,521 $0.65 Antidilutive
=========== ========= =========
Note: Because diluted EPS from continuing operations increases from $0.46
to $0.65 when convertible preferred shares are included in the computation,
those convertible preferred shares are antidilutive and are ignored in the
computation of diluted EPS from continuing operations. Therefore, diluted EPS
from continuing operations is reported as $0.46.
1998
- - ----
Increase
in Earnings
Increase Number per
in of Incremental
Income Shares Share
----------- --------- -----------
Options...................................... - 42,456 -
Dividends on convertible preferred stock..... $ 2,415,000 2,090,909 $1.16
Computation of Diluted Earnings per Share
Loss
from
Continuing Common Per
Operations Shares Share
------------- --------- ---------
$(70,491,000) 5,470,021 $(12.89)
Common stock options....................... - 42,456 -
------------- --------- ---------
$(70,491,000) 5,512,477 $(12.79) Antidilutive
Dividends on convertible preferred stock... $ 2,415,000 2,090,909 -
------------- --------- ---------
$(68,076,000) 7,603,386 $ (8.95) Antidilutive
============= ========= =========
Note: Because diluted EPS from continuing operations increases from
$(12.89) to $(12.79) when common stock options are included in the computation
and because diluted EPS increases from $(12.79) to $(8.95) when convertible
preferred shares are included in the computation, those common stock options and
convertible preferred shares are antidilutive and are ignored in the computation
of diluted EPS from continuing operations. Therefore, diluted EPS from
continuing operations is reported as $(12.89).
36
1997
- - ----
Increase
in Earnings
Increase Number per
in of Incremental
Income Shares Share
----------- --------- -----------
Options...................................... - 212,556 -
Dividends on convertible preferred stock..... $ 2,415,000 2,090,909 $1.16
Computation of Diluted Earnings per Share
Income
Available
from
Continuing Common Per
Operations Shares Share
----------- --------- ---------
$ 472,000 5,142,558 $0.09
Common stock options......................... - 212,556 -
----------- --------- ---------
$ 472,000 5,355,114 $0.09 Dilutive
Dividends on convertible preferred stock..... $2,415,000 2,090,909 -
----------- --------- ---------
$2,887,000 7,446,023 $0.39 Antidilutive
=========== ========= =========
Note: Because diluted EPS from continuing operations increases from $0.09
to $0.39 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 $0.09.
37
HOWELL CORPORATION AND SUBSIDIARIES
Form 10-K
Index to Exhibits
Exhibits not incorporated herein by reference to a prior filing are designated
by an asterisk (*) and are filed herewith. Exhibits designated by two asterisks
(**) are incorporated herein by reference to the Company's Form S-1 Registration
Statement, registration No. 33-59338, filed on March 10, 1993.
Exhibit
Number Description
- - ------ -----------
2.1 Agreement and Plan of Merger dated August 22, 1997 by and among the
Company, Howell Acquisition Corp. and Voyager Energy Corp. (filed as
an exhibit to the Company's Report on Form 10-K for the year ended
December 31, 1998).
2.2 Asset Purchase Agreement dated July 31, 1997 by and among Howell
Hydrocarbons & Chemicals, Inc., the Company and Specified Fuels &
Chemicals, L.L.C. - incorporated by reference from Exhibit 2.1 of the
Company's Current Report on Form 8-K dated August 11, 1997.
2.3 Purchase and Sale Agreement dated November 20, 1997, between Howell
Petroleum Corporation and Amoco Production Company-incorporated by
reference from Exhibit 2 of the Company's Current Report on Form 8-K
dated January 2, 1998.
2.4 Sale Agreement dated March 18, 1999 between Howell Petroleum Corporation
and Marathon Oil Company incorporated by reference from Exhibit 99.1 of
the Company's Current Report on Form 8-K dated March 30, 1999.
3.1** Certificate of Incorporation, as amended, of the Company.
3.1(a) Certificate of Amendment to the Certificate of Incorporation of the
Company (filed as an exhibit to the Company's Report on Form 10-Q for
the quarterly period ended June 30, 1994).
3.2** By-laws of the Company.
10.1** Howell Corporation 1988 Stock Option Plan.
10.2** First Amendment to the Howell Corporation 1988 Stock Option Plan.
10.3** Second Amendment to the Howell Corporation 1988 Stock Option Plan.
10.4** Form of Stock Option Agreement.
10.5 Third Amendment to the Howell Corporation Stock Option Plan (filed as an
Exhibit to the Company's Report on Form 10-Q for the quarterly period
ended June 30, 1994).
10.6** Form of Indemnity Agreement by and between the Company and each of
its directors and executive officers.
10.7 Amended and Restated Credit Agreement dated December 1, 1998 by and
among Howell Petroleum Corporation as Borrower, Bank of Montreal as
Agent, Nationsbank, N.A. as Syndication Agent, Union Bank of California,
N.A., as Documentation Agent and the lenders signatory thereto (filed as
an exhibit to the Company's Report on Form 10-K for the year ended
December 31, 1998).
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.
38
Exhibit
Number Description
- - ------ -----------
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.
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 Nonqualified Stock Option Plan incorporated
by reference from Exhibit 10.1 of the Company's Registration Statement
on Form S-8 dated June 12, 1997.
10.30 Consent Statement to approve the acquisition of Voyager Energy Corp.
and approve the increase of authorized Common Stock shares incorporated
by reference to the Company's Proxy dated September 2, 1997.
10.31* Howell Corporation Omnibus Stock Awards and Incentive Plan.
10.32* Howell Corporation Nonqualified Stock Option Plan for Non-Employee
Directors.
21 * Subsidiaries of the Company.
23 * Consent of Deloitte & Touche LLP.
27 * Financial Data Schedule.
39