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, 1995
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission file number 1-8704
HOWELL CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 74-1223027
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1111 Fannin, Suite 1500, Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (713) 658-4000
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
------------------- ---------------------
Common Stock, $1 par value New York Stock Exchange
$3.50 Convertible Preferred Stock, Series A, National Association of
$1 par value Securities Dealers, Inc.
Automated Quotation System
Securities registered pursuant to Section 12(g) of the Act:
NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
----- -----
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
X
-------
The market value of all shares of Common Stock on March 1, 1996 was
approximately $67.2 million. The aggregate market value of the shares held by
nonaffiliates on that date was approximately $49.3 million. As of March 1,
1996, there were 4,933,446 common shares outstanding.
Documents Incorporated by Reference:
Howell Corporation proxy statement to be filed in connection with the 1996
Annual Shareholders' Meeting (to the extent set forth in Part III of this Form
10-K).
HOWELL CORPORATION
1995 FORM 10-K ANNUAL REPORT
Table of Contents
Page
----
PART I
Item 1. Business 1
Item 2. Properties 4
Item 3. Legal Proceedings 11
Item 4. Submission of Matters to a Vote of Security Holders 11
PART II
Item 5. Market for the Registrant's Common Stock and
Related Stockholder Matters 12
Item 6. Selected Financial Data 12
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 13
Item 8. Financial Statements and Supplementary Data 19
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 19
PART III
Item 10. Directors and Executive Officers of the Registrant 19
Item 11. Executive Compensation 20
Item 12. Security Ownership of Certain Beneficial Owners
and Management 20
Item 13. Certain Relationships and Related Transactions 20
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K 20
PART I
Item 1. Business
A. General
Howell Corporation and its subsidiaries (the "Company") is primarily engaged
in exploration, production, acquisition and development of oil and gas
properties. The Company is also involved in compatible crude oil marketing,
technical fuels and chemical processing, and transportation. A description of
each of the Company's principal business segments and the markets in which they
operate is summarized below. For information relating to industry segments,
reference is made to "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the Consolidated Financial Statements
and notes thereto.
Oil and Gas Exploration and Production
The Company's oil and gas exploration and production activities are
conducted entirely within the United States by Howell Petroleum Corporation
("HPC") and are concentrated along the Gulf Coast, both offshore and onshore and
in Wyoming. At December 31, 1995, the Company's estimated proved oil reserves
were 8,600 MBbl and estimated proved natural gas reserves were 60,581 MMcf. The
Company's three major producing properties, Main Pass Block 64 ("Main Pass"),
the LaBarge Project and the North Frisco City Field, together represented 5,819
MBbl and 50,086 MMcf of the Company's estimated proved reserves of oil and
natural gas, respectively, at December 31, 1995. The Company's interest in the
LaBarge Project is also the source of all of the Company's proved reserves of
carbon dioxide and helium (114,253 MMcf and 2,326 MMcf, respectively, at
December 31, 1995). In addition, the Company owns fee mineral interests in
876,000 net acres in Mississippi, Alabama and Louisiana. Substantially all of
the Company's oil and natural gas production is sold on the spot market or
pursuant to contracts priced according to the spot market. HPC has 56
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
availability of a ready market for the oil and gas production of the Company
depends in part on the cost and availability of alternative fuels, the level of
consumer demand, the extent of other domestic production of oil and gas, the
extent of importation of foreign oil and gas, the cost of and proximity to
pipelines and other transportation facilities, regulations by state and federal
authorities, and the cost of complying with applicable environmental
regulations.
Crude Oil Marketing
Howell Crude Oil Company ("HCO"), a wholly-owned subsidiary with 57
employees, conducts the operations of the Company's crude oil marketing segment
and owns and operates three crude oil pipelines. HCO has the responsibility for
supplying the Company's technical fuels segment with crude oil and purchases,
markets and exchanges about 95,000 BPD of crude oil and condensate from
approximately 400 operators and marketers. The Company moves crude oil by
common carrier pipelines or by Company trucks to pipeline injection points and
to customers' facilities. HCO focuses its third-party operations on smaller
producers, emphasizing service to the producer as a way to distinguish HCO from
its competitors. HCO has access to 27 pipeline injection points in Texas,
Mississippi, Louisiana and Florida. In seeking the best price for the crude
oil, HCO often enters into exchange agreements with others to take advantage of
quality and location differentials. Sales of crude oil to Marathon Oil Company
accounted for approximately 12% of the Company's consolidated revenues in 1995.
HCO also owns a 5.5 mile pipeline in the Gulf of Mexico, which is used to
transport the Company's Main Pass production, a 555 mile pipeline in Texas
("Texas System"), a 230 mile pipeline that runs south from Jones County,
Mississippi to Baton Rouge, Louisiana, ("MS System") and a 90 mile pipeline that
runs from Santa Rosa County, Florida to a point near Mobile, Alabama ("Jay
System"). The Texas pipeline is an intrastate system extending from Groesbeck,
Texas, south to Texas City, Texas, and includes tanks for crude oil storage with
total capacity of 1.9 million barrels. HCO also has storage capacity of 0.2
million barrels on both the MS System and the Jay System. In 1995, 1.2 million
barrels of storage on the Texas System was leased to Exxon Pipeline Company
("Exxon") under a one-year lease. This lease ends in March 1996.
Profit margins in crude oil marketing are small and significantly
influenced by both the real and expected volatility in crude oil prices as well
as intense competition throughout the industry. The Company competes with four
national and six regional gatherers. In 1993, the Company initiated a limited
program of hedging its crude oil inventories to minimize the effects of future
price fluctuations. With the continuing decline in domestic crude oil
production, larger companies with the financial ability to withstand significant
market swings might have an advantage.
Profit margins of crude oil common carrier pipelines are not affected by
the volatility of crude oil prices; however, competition for barrels to
transport exists with other pipelines. Competitive crude oil pipelines lie near
the Company's pipelines.
Technical Fuels and Chemical Processing
The Company develops, manufactures and markets hydrocarbons-based research
and reference fuels and provides chemical toll processing services through its
wholly-owned subsidiary Howell Hydrocarbons & Chemicals, Inc. ("HHC"), which has
56 employees. The Company conducts its research and reference fuels operations
and its chemical processing operations at its modern, 50-acre facility in
Channelview, Texas. Extensive construction at the facility since 1988 has
expanded the available office, laboratory and warehouse space to 24,500 square
feet. The Company now has available for the technical fuels operations an 1,800
BPD sweet crude unit and a 400 BPD sour crude unit, as well as extensive
laboratory blending and dedicated storage facilities, including leased storage
near its major customers in Detroit, Michigan. For the chemical processing
operations, the facility includes three large-diameter stainless steel
distillation columns for batch or continuous processing and extensive stainless
steel and carbon steel tankage. In the second half of 1993, the Company
constructed a synthesis reaction unit that became operational in 1994. The
modern facilities afforded the Company the ability to obtain expanded air
permits that enhance its competitive position.
The technical fuels business involves the processing of crude oil and
blending of petroleum products and additives to create specialty fuels used for
testing such things as lubricants and engine emissions. HHC's customer base for
its technical fuels products includes the U.S. Government and automobile
manufacturers worldwide. HHC has relatively few competitors in the technical
fuels market; however, each is substantially larger and has greater financial
resources than HHC. Environmental and other governmental regulations relating
to combustion product emissions, mileage criteria and equipment design continue
to increase. As a result, the Company continues to develop new products to meet
customer requirements and serve the demand for technical fuels.
HHC has conducted chemical toll processing and product terminalling
activities at the Channelview facility for seven years. In 1993 and 1994, toll
processing campaigns were short-term in nature and consisted primarily of
reprocessing customers' chemicals that did not meet product specifications and
standby processing when the customer's own plant was unable to handle the
processing.
In 1995, HHC obtained contracts that are longer term and involve the use of
the synthesis reaction unit. The Company has concentrated its marketing efforts
on customers who are manufacturers of acetates and esters for the paint and
coatings industry. Additionally, in 1995, HHC recognized income in conjunction
with the cancellation by a customer of a long-term contract. The customer
determined that demand for the product to be processed by HHC was not sufficient
to warrant production and released the Company from further requirements under
the contract.
HHC has competition for long-term toll manufacturing contracts from
numerous companies offering similar services in the Houston area and worldwide.
HHC believes its modern computer process control equipment and its access to
rail and water transportation give it an advantage over some of its competitors.
Transportation
Howell Transportation Services, Inc. ("HTS"), a wholly-owned subsidiary
with 173 employees, conducts the Company's bulk liquids truck transportation
operations. With Interstate Commerce Commission authority to provide
transportation services throughout the United States, HTS can satisfy the
existing needs of its affiliates and seek opportunities to haul bulk liquids for
third parties as well. In 1994 and 1995, HTS saw a significant increase in its
revenues from third party carriage.
HTS operates a fleet of 77 tractors and 124 trailers used to haul crude
oil, petroleum specialty products, petrochemicals and chemicals. HTS' trailer
fleet consists of 55 aluminum crude oil trailers, each capable of hauling about
200 barrels of oil, 39 stainless steel and 11 carbon steel trailers, each
capable of hauling up to 6,950 gallons of chemicals, 5 aluminum pneumatic
trailers for hauling dry bulk chemicals and 14 specially designed, high volume
aluminum product trailers, each capable of hauling up to 8,500 gallons of
compatible chemicals and petroleum products. The addition of specially designed
aluminum trailers to the fleet has given HTS a cost advantage over its
competitors, which generally provide only the lower volume stainless steel
trailers. HTS expends considerable effort on driver safety and training
programs and has been successful in reducing employee turnover. HTS competes
with many other entities in providing transportation services. Many of these
competitors have greater financial resources and a larger number of trucks than
HTS. HTS competes with other entities on the basis of price, quality of
equipment and personnel, safety record and service. Meeting tight product
quality specifications and delivery deadlines has been important to Howell since
it began operating trucks for its own products in 1955.
B. Governmental and Environmental Regulation
Governmental Regulation
Domestic development, production and sale of oil and gas are extensively
regulated at both the federal and state levels. Legislation affecting the oil
and gas industry is under constant review for amendment or expansion, frequently
increasing the regulatory burden. Also, numerous departments and agencies, both
federal and state, have issued rules and regulations binding on the oil and gas
industry and its individual members, compliance with which is often difficult
and costly and some of which carry substantial penalties for failure to comply.
State statutes and regulations require permits for drilling operations, drilling
bonds and reports concerning wells. Texas and other states in which the Company
conducts operations also have statutes and regulations governing conservation
matters, including the unitization or pooling of oil and gas properties and
establishment of maximum rates of production from oil and gas wells. The
existing statutes or regulations currently limit the rate at which oil and gas
is produced from wells in which the Company owns an interest. The Company's
other business segments also operate under strict governmental regulation. The
refining and processing of fuels and chemicals is subject to state and federal
regulations regarding air and water emissions and the disposal of wastes.
Federal and state authorities also regulate the transportation of crude oil,
petroleum products and chemicals and the tariff rates that may be charged for
the transportation by pipelines of crude oil.
Some local government jurisdictions in Texas have taken or are proposing to
take actions to force pipeline transmission companies, including crude oil
pipelines, to pay fees for pipelines that pass through their jurisdictions or
that cross city streets. Should these governmental jurisdictions be successful
in their efforts, the Company may be required to pay additional fees.
Environmental Regulation
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, production, transportation, processing and chemical toll processing
activities. These permits, registrations or authorizations are subject to
revocation, modification and renewal. The Company has determined that the
federal wastewater discharge permit at its Channelview facility may have expired
prior to the transfer of the permit to the Company. The Company has taken steps
to resolve this matter. In addition, the Company has been penalized for the
failure to properly handle and dispose of some wastes at the facility it
formerly owned in San Antonio, Texas. See Note 10 of Notes to Consolidated
Financial Statements. Governmental authorities have the power to enforce
compliance with these regulatory requirements, the provisions of required
permits, registrations or other authorizations, and lease conditions, and
violators are subject to civil and criminal penalties, including fines,
injunctions or both. Failure to obtain or maintain a required permit may also
result in the imposition of civil and criminal penalties. Third parties may
have the right to sue to enforce compliance. The cost of environmental
compliance has not had a 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 run-off, 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
In addition to the employees of the four main business segments, the Company
has 22 other employees, for a total of 364 employees. The Company's employees
are not represented by a union for collective bargaining purposes. The Company
has experienced no work stoppages or strikes as a result of labor disputes and
considers relations with its employees to be good. The Company maintains group
life, medical, dental, long-term disability and accidental death and
dismemberment insurance plans for its employees. In addition, the Company
provides its employees with a Company stock purchase plan, a thrift plan and a
Simplified Employee Pension Plan.
Item 2. Properties
A. Supplementary Oil and Gas Producing Information (Unaudited)
The oil and gas producing activities of the Company are summarized below.
Substantially all of the Company's producing properties are subject to a lien
held by a bank. See Note 6 of Notes to Consolidated Financial Statements.
Oil and Gas Wells
As of December 31, 1995, 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 295 83
Gas wells 129 23
--- --
Total 424 106
=== ===
- - - -------------
(1) One or more completions in the same well are counted as one well; 2 of the
wells have multiple completions.
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, 1995 and 1994, have been audited by independent
petroleum consultants, H. J. Gruy and Associates, Inc. The estimates for the
prior years were audited by L. A. Martin & Associates, Inc. These estimates
were used in the computation of depreciation, depletion and amortization
included in the Company's consolidated financial statements and for other
reporting purposes. The Company has not filed any estimates of reserves with
any federal authority or agency during the past year other than estimates
contained in its last annual report on Form 10-K. Set forth below are estimates
of the Company's net proved oil and gas reserves, all located in the United
States.
Estimated Quantities of Proved Oil and Gas Reserves
Oil Gas
(Bbls) (Mcf)
------ -----
As of December 31, 1992 6,860,384 69,096,470
Revisions of previous estimates 115,544 770,842
Extensions, discoveries & other additions 1,026,261 2,358,595
Purchases of minerals in place 567,901 2,723,519
Production (1,204,948) (3,652,022)
Sales of minerals in place (94,221) (603,424)
---------- ----------
As of December 31, 1993 7,270,921 70,693,980
Revisions of previous estimates (37,261) (1,656,466)
Extensions, discoveries & other additions 1,523,356 5,327,274
Production (1,336,937) (3,208,139)
Sales of minerals in place (204,323) (218,059)
---------- ----------
As of December 31, 1994 7,215,756 70,938,590
Revisions of previous estimates (555,469) (11,578,149)
Extensions, discoveries & other additions 2,523,526 3,893,092
Purchases of minerals in place 961,025 1,025,383
Production (1,383,881) (3,526,803)
Sales of minerals in place (160,921) (171,313)
---------- ----------
As of December 31, 1995 8,600,036 60,580,800
========== ==========
Proved developed reserves:
December 31, 1992 4,167,854 68,001,964
December 31, 1993 6,782,015 63,618,243
December 31, 1994 6,201,176 63,677,432
December 31, 1995 7,662,263 60,125,223
Proved oil reserves at December 31, 1995 include 423,754 barrels of natural
gas liquids.
The reserves as of December 31, 1995, shown in the table above include
475,426 barrels of oil and 2,911,220 Mcf of gas attributable to the Company's
producing fee mineral interests.
In addition to the oil and gas reserves shown above, HPC, through its
participation in the LaBarge Project in southwestern Wyoming, had proved carbon
dioxide reserves of 114,252,900 Mcf and proved helium reserves of 2,326,388 Mcf
at December 31, 1995.
Oil and Gas Leaseholds
The following table sets forth the Company's ownership interest in
leaseholds as of December 31, 1995. 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 15,296 6,126 13,945 6,579
Louisiana 1,051 222 240 39
Mississippi 3,376 1,045 24,022 7,713
Texas 13,140 5,098 13,823 4,640
Wyoming 17,279 2,487 17,461 3,086
All other states combined 2,522 470 1,864 513
Offshore 7,025 5,589 15,000 15,000
------ ------ ------ ------
Total 59,689 21,037 86,355 37,570
====== ====== ====== ======
In addition to the acreage under leaseholds as shown above, the Company
owns the fee mineral acreage shown in the table below:
Developed(1) Undeveloped
---------------- ----------------
Gross Net Gross Net
Acres Acres Acres Acres
----- ----- ----- -----
Alabama 3,699 1,850 617,787 308,513
Louisiana 6,342 934 9,558 4,462
Mississippi 18,565 9,283 1,118,851 551,283
------ ------ --------- -------
Total 28,606 12,067 1,746,196 864,258
====== ====== ========= =======
_________________
(1) Acres spaced or assignable to productive wells.
Drilling Activity
The following table shows the Company's net productive and dry exploratory
and development wells drilled in the United States:
Exploratory Development
---------------- ----------------
Net Net Net Net
Productive Dry Productive Dry
Year Wells Holes Wells Holes
---- ----- ----- ----- -----
1995 1.64 1.08 0.72 1.95
==== ==== ==== ====
1994 0.53 2.17 2.03 -
==== ==== ==== ====
1993 0.05 0.79 3.34 0.67
==== ==== ==== ====
The table above reflects only the drilling activity in which the Company
had a working interest participation. In addition, in 1995 and 1994, 14 and 18
gross productive wells were drilled on the Company's fee mineral acreage,
respectively.
Sales Prices and Production Costs
The following table sets forth the average prices received by the Company
for its production, the average production (lifting) costs and amortization per
equivalent barrel of production:
United States
--------------------------
1995 1994 1993
---- ---- ----
Average sales prices:
Crude oil, condensate and natural gas liquids (per Bbl) $15.67 $14.40 $15.86
Natural gas (per Mcf) $1.47 $1.70 $1.87
Production (lifting) costs (per equivalent barrel of production) $4.47 $4.23 $5.18
Amortization (per equivalent barrel of production) $5.20 $4.96 $4.68
Natural gas production is converted to barrels using its estimated energy
equivalent of six Mcf per barrel.
Oil and Gas Producing Activities
CAPITALIZED COSTS. The following table presents the Company's aggregate
capitalized costs relating to oil and gas producing activities, all located in
the United States, and the aggregate amount of related depreciation, depletion
and amortization:
December 31, 1995 December 31, 1994
----------------- -----------------
(In thousands)
Capitalized Costs:
Oil and gas producing properties, all being amortized $278,505 $264,430
Fee mineral interests, unproven 18,188 18,200
-------- --------
Total $296,693 $282,630
======== ========
Accumulated depreciation, depletion
and amortization $188,972 $178,147
======== ========
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,
--------------------------
1995 1994 1993
---- ---- ----
(In thousands)
Property acquisition:
Unproved fee mineral interests $ - $ 3 $18,260
Unproved leaseholds 790 792 225
Proved properties 6,218 - 6,868
Exploration 2,830 3,252 2,794
Development 5,111 5,559 7,622
------- ------ -------
$14,949 $9,606 $35,769
======= ====== =======
Included in proved property acquisition costs for the year ended December
31, 1993, is $6,061,000 expended for the producing fee mineral interests
acquired from the Federal Intermediate Credit Bank of Jackson, Mississippi.
In 1995 and 1994, $12,000 and $63,000 of costs of unproved mineral
interests, respectively, were transferred to the full-cost pool, representing
the costs of mineral properties that were drilled and evaluated during the
periods. These transfers of costs are not reflected in the table above.
RESULTS OF OPERATIONS. The following table sets forth the results of
operations of the Company's oil and gas producing activities, all in the United
States. The table does not include activities associated with carbon dioxide,
helium and sulfur produced from the LaBarge Project or with activities
associated with leasing the Company's fee mineral interests. The table does
include the revenues and costs associated with the Company's production from its
fee mineral interests.
Year Ended December 31,
----------------------------
1995 1994 1993
---- ---- ----
(In thousands)
Revenues $27,011 $24,608 $26,757
Production (lifting) costs 8,810 7,914 9,393
Depreciation, depletion and amortization 10,259 9,282 8,483
------- ------- -------
7,942 7,412 8,881
Income tax expense 2,396 2,283 2,800
------- ------- -------
Results of operations (excluding
corporate overhead and interest cost) $5,546 $5,129 $6,081
====== ====== ======
Included in the 1995, 1994 and 1993 amounts above are $1,992,000,
$1,908,000 and $1,104,000 of revenues and $146,000, $141,000 and $76,000 of
production costs, respectively, from the production from the Company's producing
fee mineral interests.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED
OIL AND GAS RESERVES. The accompanying table presents a standardized measure of
discounted future net cash flows relating to the production of the Company's
estimated proved oil and gas reserves at the end of 1995 and 1994. The method
of calculating the standardized measure of discounted future net cash flows is
as follows:
(1) Future cash inflows are computed by applying year-end prices of oil and gas
to the Company's year-end quantities of proved oil and gas reserves. Future
price changes are considered only to the extent provided by contractual
arrangements in existence at year-end.
(2) Future development and production costs are estimates of expenditures to be
incurred in developing and producing the proved oil and gas reserves at year-
end, based on year-end costs and assuming continuation of existing economic
conditions.
(3) Future income tax expenses are calculated by applying the applicable
statutory federal income tax rate to future pretax net cash flows. Future
income tax expenses reflect the permanent differences, tax credits and
allowances related to the Company's oil and gas producing activities included in
the Company's consolidated income tax expense.
(4) The discount, calculated at ten percent per year, reflects an estimate of
the timing of future net cash flows to give effect to the time value of money.
December 31, December 31,
1995 1994
---------- -----------
(In thousands)
Future cash inflows $253,239 $218,234
Future production costs 97,093 83,823
Future development costs 9,963 11,057
Future income tax expenses 32,531 25,286
-------- -------
Future net cash flows 113,652 98,068
10% annual discount for estimated timing of cash flows 31,505 29,633
-------- -------
Standardized measure of discounted future net cash
flows relating to proved oil and gas reserves $ 82,147 $68,435
======== =======
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,
----------------------------
1995 1994 1993
---- ---- ----
(In thousands)
Sales and transfers, net of production costs $(18,201) $(16,693) $(17,363)
Net changes in prices and production costs 15,492 7,354 (12,012)
Extensions and discoveries, net of future production and
development costs 24,475 17,850 12,325
Purchases of minerals in place 7,248 - 7,967
Sales of minerals in place (1,319) (1,546) (1,145)
Previously estimated development costs incurred during the
period (1,079) (446) (1,811)
Revisions of quantity estimates (13,690) (1,453) 1,018
Accretion of discount 6,844 6,426 5,802
Net change in income taxes (1,706) (994) 5,334
Changes in production rates (timing) and other (4,352) (6,324) 6,124
------- ------ ------
Net change $13,712 $4,174 $6,239
======= ====== ======
Description of Significant Properties
The three producing properties of major significance to the Company are
Main Pass Block 64, located in federal waters offshore Louisiana, the North
Frisco City Field in Alabama and the LaBarge Project located in southwestern
Wyoming. These properties represent, in total, 5,819 MBbl and 50,086 MMcf of
the Company's estimated proved reserves of oil and natural gas, respectively, at
December 31, 1995. In addition, the Company owns fee mineral interests in
876,000 net acres in Mississippi, Alabama and Louisiana. The following sets
forth certain information with respect to the Company's interest in its most
significant properties.
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. By August 1983, the
Company had completed nine producing wells and one gas injection well, and
designed, constructed and placed on-line a production platform and oil pipeline
facilities. Since then, the Company has completed eight more wells, tied into
an interstate natural gas pipeline system, converted the gas injection well to a
producing well and increased its working interest from 52% to almost 80%. In
1989, the Company acquired an 80% working interest in an adjacent block with
five wells, a production platform and oil and gas pipelines. The Company
subsequently unitized portions of these two blocks covering the then known
limits of the main pay sand (the "7,300' Sand Unit"), and then designed,
constructed and placed on-line a waterflood project intended to repressure the
7,300' Sand Unit. Gross cumulative production from the field over almost
thirteen years has totaled 9,442 MBbl of oil and 25,016 MMcf of natural gas.
During 1995, net production averaged 1,154 BOPD and 338 McfPD of natural gas.
Under a farm-out arrangement from the Company, a third party drilled,
completed and tested a deep test well in 1993. During 1994, the Company and its
partners in the 7300' Sand Unit acquired the deep well from the third party.
The consideration for this acquisition was the Company's acceptance of liability
to plug the deep well when it is abandoned. In December 1994, the Company
connected this well to the existing platform and production began in January
1995.
The Company currently has a working interest which averages approximately
80% in 24 gross (19.1 net) wells, five of which are water injection wells. All
of the water injection wells are located on the adjacent block, utilizing the
production platform as a water injection facility.
Proved reserves attributable to Main Pass at December 31, 1995 were 3,538
MBbl of oil and 2,883 MMcf of natural gas, representing 41% and 5%,
respectively, of the Company's proved oil and natural gas reserves.
North Frisco City Field. The North Frisco City Field ("North Frisco
City"), located in Monroe County, Alabama, was discovered in March 1991. After
the discovery well was completed, the structural complexity of this find led the
Company and its partners to run a 3-D seismic program over the potential field
area. Based on this data, five successful development wells were completed
during 1992, two in 1993 and three in 1994. Only one dry hole has been drilled
to date, thereby establishing an eastern limit to the field. In the fourth
quarter of 1994, the field was unitized. The Company currently has a 24.1%
working interest in nine gross (2.2 net) producing wells in the Unit, each of
which is producing from the Frisco City sand member of the Haynesville formation
at a depth of about 12,000 feet. In addition, the Company has interests in two
wells not included in the Unit. Aggregate net production from this field
averaged 1,041 BPD of crude oil, 204 BPD of natural gas liquids and 1,180 McfPD
of natural gas during the fourth quarter of 1995.
The Company's estimated proved reserves from its working interest in North
Frisco City at December 31, 1995 were 2,236 MBbl of oil and 2,632 MMcf of
natural gas, representing approximately 26% and 4%, respectively, of the
Company's total proved oil and natural gas reserves. The Company also owns a
royalty interest in this field through its ownership of the fee mineral
properties discussed below.
Fee Mineral Properties. In August 1993, the Company acquired all of the
fee mineral properties of the Federal Intermediate Credit Bank of Jackson,
Mississippi ("FICBJ"). The Company paid FICBJ $24.1 million for these
properties and expended an additional $0.2 million for costs related to the
acquisition.
The properties consist of 876,000 net acres of fee mineral interests
located in Mississippi (64%), Alabama (35%) and Louisiana (1%). The purchase
price was allocated $6.1 million to producing acreage and $18.2 million to non-
producing acreage. The value assigned to the producing acreage is included in
the full cost pool being amortized as described in Note 1 of Notes to the
Consolidated Financial Statements.
In 1995 the producing acreage produced 76 MBbl of oil and 465 MMcf of
natural gas at average sales prices of $15.91 per Bbl and $1.58 per Mcf,
respectively. Proved reserves attributable to the producing acreage at December
31, 1995, were 475 MBbl of oil and 2,911 MMcf of natural gas.
The non-producing fee mineral properties generate lease bonus and delay
rental revenues. During 1995, 1994 and the period in 1993 while the Company
owned the properties, revenues of $0.2 million, $0.5 million and $0.1 million,
respectively, were generated from these types of activities.
LaBarge Project. The LaBarge Project, located in southwestern Wyoming,
consists of three federal units, seventeen producing wells, a field gathering
system, a dehydration plant, a 32-mile dehydrated raw gas pipeline, a gas
processing plant with a capacity for processing up to 600,000 McfPD of raw gas
into natural gas, carbon dioxide, helium and sulfur, and marketing facilities
for the sale of the plant products. The Company has a 4.8% working interest in
one of the units, the Fogarty Creek Unit. The Company has an interest in 12
gross (0.6 net) wells producing from depths between 14,500 feet to 17,000 feet
in the Fogarty Creek Unit. Exxon Company USA ("Exxon USA") holds a 92% interest
in the Fogarty Creek Unit and a 100% interest in each of the other two units,
the plants and the marketing facilities.
The Company's raw gas is processed pursuant to an agreement with Exxon USA
which provided for an initial processing fee equal to 65% of the sales value of
the plant products through August 1991, increasing to 75% from that date forward
until the sooner of payout of the gas processing plant or September 2021, at
which time it will adjust to a cost-plus fee, not to exceed 50% of the sales
value of the products. The processing agreement also provides for Exxon to
market all of the Company's products from the LaBarge Project.
The Company has significant production and reserves of carbon dioxide and
helium and small amounts of production and reserves of sulfur from its interest
in the LaBarge Project, which are not included in its production and proved
reserves of oil and natural gas discussed elsewhere in Item 2. The table below
presents information on the Company's net production of natural gas, carbon
dioxide and helium attributable to the Company's interest in the LaBarge
Project. The natural gas data from the LaBarge Project is also included in the
other tables set forth elsewhere in Item 2.
LaBarge Production
Year Ended December 31,
--------------------------------
1995 1994 1993
---- ---- ----
(in thousands, except unit prices)
Production data (net):
Natural gas (Mcf) 1,261 1,141 1,162
Carbon dioxide (Mcf)<F1> 659 843 1,311
Helium (Mcf) 31 34 35
Average sales price per unit:
Natural gas (Mcf) $ 1.41 $ 1.53 $ 1.67
Carbon dioxide (Mcf) $ 0.39 $ 0.56 $ 0.58
Helium (Mcf) $49.44 $51.61 $50.95
Financial data:
Revenues $3,819 $3,975 $4,927
Processing costs 3,024 3,141 3,948
------ ------ ------
Cash flows $ 795 $ 834 $ 979
====== ====== ======
- - - -------------------
<FN>
<F1>
Because of a lack of market, approximately 80%, 74% and 64% of the volume
produced in 1995, 1994 and 1993, respectively, was vented and not sold.
Amounts included in the table reflect only volumes sold.
</FN>
B. Other Properties
In addition to the oil and gas properties described above, the Company and
its subsidiaries lease approximately 52,900 sq. ft. for use as corporate and
administrative offices in Houston, Texas. The Company's technical fuels and
chemical processing operations are conducted at a 50 acre facility owned by the
Company. The facility, located in Channelview, Texas, includes buildings
covering 24,500 sq. ft. The Company's crude oil marketing segment owns a 98-
acre site in northwest Houston that includes tank storage and serves as the
operations center for its pipeline operations. This location includes buildings
covering 8,000 sq. ft.
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 of the Company. See Note 9 of Notes to Consolidated
Financial Statements.
Item 4. Submission of Matters to a Vote of Security Holders
None
Part II
Item 5. Market for the Registrant's Common Stock and Related Stockholder
Matters
Howell Corporation common stock is traded on the New York Stock Exchange.
Symbol: HWL
Cash
Price Dividends
---------------- ----------
For quarter ending High Low $
----------------- ---- --- -----
March 31, 1994 13 5/8 11 0.04
June 30, 1994 12 1/8 10 1/2 0.04
September 30, 1994 12 1/4 10 7/8 0.04
December 31, 1994 13 1/4 11 1/4 0.04
March 31, 1995 13 3/4 10 3/8 0.04
June 30, 1995 14 7/8 12 7/8 0.04
September 30, 1995 16 3/8 13 7/8 0.04
December 31, 1995 14 3/8 11 13/16 0.04
Approximate number of equity shareholders as of December 31, 1995: 1,800.
It is the current intention of the Company to continue to pay quarterly cash
dividends on its common stock. No assurance can be given, however, as to timing
and amount of any future dividends which necessarily will depend on the earnings
and financial needs of the Company, legal restraints and other considerations
that the Company's Board of Directors deems relevant. The ability of the
Company to pay dividends on its common stock is currently subject to certain
restrictions contained in its bank loan agreement. See Item 7 Management's
Discussion and Analysis of Financial Condition - Liquidity and Capital
Resources.
In addition, the Company has 690,000 shares of convertible preferred stock
outstanding. These shares were issued in April 1993. The $3.50 convertible
preferred stock is traded on the National Association of Securities Dealers,
Inc. Automated Quotation System ("NASDAQ") under the symbol HWLLP. See Note 7
of Notes to Consolidated Financial Statements.
Item 6. Selected Financial Data
The information below is presented in order to highlight significant trends
in the Company's results from continuing operations and financial condition.
See Consolidated Financial Statements and notes thereto.
Year Ended December 31,
------------------------------------------------
1995 1994 1993 1992 1991
---- ---- ---- ---- ----
(In thousands, except per share amounts)
Revenues $673,537 $448,952 $411,736 $461,316 $478,325
======== ======== ======== ======== ========
Net earnings (loss) from operations $ 5,326 $ 2,883 $ 2,527 $ 431 $ (7,626)
======== ======== ======== ======== ========
Net earnings (loss) per common share
from operations $ .60 $ .10 $ .18 $ .09 $ (1.58)
======== ======== ======== ======== ========
Property, plant and equipment, net $195,341 $124,773 $125,113 $ 98,552 $ 98,450
======== ======== ======== ======== ========
Total assets $273,326 $182,440 $164,542 $158,181 $149,319
======== ======== ======== ======== ========
Long-term debt $ 96,205 $ 33,098 $ 35,879 $ 42,491 $ 39,232
======== ======== ======== ======== ========
Shareholders' equity $ 79,020 $ 75,919 $ 76,225 $ 43,089 $ 43,304
======== ======== ======== ======== ========
Cash dividends per common share $ .16 $ .16 $ .16 $ .16 $ .32
======== ======== ======== ======== ========
The loss from operations in 1991 includes a pre-tax write-down of the
Company's oil and gas assets of $11,830,000.
Summarized below are the Company's unaudited quarterly financial data for
1995 and 1994.
1995 Quarters
--------------------------------------
First Second Third Fourth
----- ------ ----- ------
(In thousands, except per share amounts)
Revenues $151,516 $169,768 $172,972 $179,281
======== ======== ======== ========
Earnings before income taxes $ 1,249 $ 2,756 $ 1,712 $ 2,670
======== ======== ======== ========
Net earnings $ 832 $ 1,757 $ 1,085 $ 1,652
======== ======== ======== ========
Net earnings per common share $ .05 $ .24 $ .10 $ .21
======== ======== ======== ========
1994 Quarters
--------------------------------------
First Second Third Fourth
----- ------ ----- ------
(In thousands, except per share amounts)
Revenues $ 87,674 $109,013 $120,530 $131,735
======== ======== ======== ========
Earnings before income taxes $ 505 $ 1,330 $ 1,309 $ 1,107
======== ======== ======== ========
Net earnings $ 352 $ 905 $ 876 $ 750
======== ======== ======== ========
Net earnings (loss) per common share $ (.05) $ .06 $ .06 $ .03
======== ======== ======== ========
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 OPERATIONS
The Company's principal business segments are oil and gas production, crude
oil marketing, technical fuels and chemical processing, and transportation.
Results of operations by segment for the three years ended December 31, 1995 are
discussed below. The table below for each segment's revenues does not reflect
the elimination of intercompany revenues. See Note 8 of Notes to Consolidated
Financial Statements.
Oil and Gas Production
Year Ended December 31,
---------------------------
1995 1994 1993
---- ---- ----
Revenues (in thousands):
Sales of oil and natural gas $27,011 $24,608 $26,757
Sales of LaBarge other products 1,990 2,227 2,582
Gas marketing 2,196 1,560 1,842
Minerals leasing and other 304 523 100
------- ------- -------
Total revenues $31,501 $28,918 $31,281
======= ======= =======
Operating profit (in thousands) $ 6,977 $ 6,224 $ 7,287
======= ======= =======
Operating information:
Average net daily production:
Oil (barrels) 3,791 3,663 3,301
Natural gas (Mcf) 9,662 8,789 10,006
Average sales prices:
Oil (per barrel) $15.67 $14.40 $15.86
Natural gas (per Mcf $ 1.47 $ 1.70 $ 1.87
Revenues
Revenues from sales of oil and natural gas increased in 1995 when compared
to 1994 due to both an increase in the Company's average daily oil production
and an increase in the average sales price of the oil. Daily oil production
increased 3% and average oil sales prices increased 9%. The positive effects of
an increase in daily gas production of 10% were offset by a 14% decline in the
average sales price of the gas.
The increase in oil and gas production volumes can be attributed primarily
to the acquisition of certain properties from Norcen Explorer, Inc. ("Norcen")
in March 1995. These properties increased the daily average production of oil
and gas for 1995 by 371 barrels and 272 Mcf, respectively. In addition to the
Norcen properties, an exploratory discovery well, the Cauthen 6-15 #1,
contributed 287 Mcf per day to the increased daily gas production. Negatively
impacting daily oil production was the shut-in of the Company's Main Pass Field
for 19 days in the fourth quarter of 1995 due to Hurricane Opal. While the
Company experienced minimal damage from the hurricane, shore facilities owned by
Chevron USA into which the Company's oil production is shipped were severely
damaged. Additionally, Chevron shut in the Company's Main Pass Field for three
additional days in the fourth quarter while Chevron conducted maintenance
activities. Average daily oil production at the Main Pass Field fell from 1,250
barrels per day in 1994 to 1,154 barrels per day in 1995. Without the lost
production days, average daily production would have been approximately the
same.
The Company has a revenue interest in eleven successful horizontal wells in
central Texas. Horizontal wells have short lives, typically producing half of
their reserves in the first six months. In 1995, oil and gas production from
horizontal wells averaged 192 barrels and 306 Mcf per day. In 1994, horizontal
well production contributed 244 barrels and 216 Mcf per day.
The effect on the annual average daily oil production of the Company's
mineral fee properties in 1995 and 1994 was 208 and 199 barrels, respectively.
Revenues from the sales of LaBarge other products are attributable to sales
of carbon dioxide, helium and sulfur. The production level of helium was
relatively stable in 1995 when compared to 1994; however, carbon dioxide sales
volumes declined due to a lack of market. The Company was also affected by a
decline in helium and carbon dioxide per unit sales prices. Sulfur sales
revenues in both years were insignificant. Gas marketing revenues increased in
1995 due to slightly higher volumes marketed for third parties.
Total revenues decreased in 1994 when compared to 1993, primarily due to
lower average oil and gas sales prices. These prices declined 9% and 12%,
respectively. These decreases were partially offset by an 11% increase in
average daily oil production from horizontal well successes, a full year of
production from the minerals properties acquired in August 1993, and a slight
increase in oil production at the Company's Main Pass Field. Revenues from the
sales of LaBarge other products in 1994 decreased from 1993 levels due to
declines in carbon dioxide sold. Gas marketing revenues fell as a result of
lower natural gas sales prices.
Operating Profit
In 1995, the operating profit of this segment increased $0.8 million when
compared to 1994. The higher average oil sales price combined with higher oil
production was the largest factor in this increase in operating profit. Also
contributing to this improvement was a $0.4 million decrease in general and
administrative costs resulting from lower salary expense while the Company was
making personnel changes to allow it to revitalize and refocus its drilling
efforts. General and administrative costs fell from $2.0 million in 1994 to
$1.6 million in 1995.
Partially offsetting these improvements in operating profit was an increase
in depreciation, depletion and amortization ("DD&A") per equivalent barrel of
production from $4.96 in 1994 to $5.20 in 1995. The increase in the DD&A rate
is attributable to lower equivalent barrels of reserves and higher capitalized
costs. Overall, combined with the higher production levels, DD&A rose from $9.3
million in 1994 to $10.3 million in 1995.
The decrease in operating profit in 1994 when compared to 1993 was $1.1
million. Lower natural gas production combined with lower average gas sales
prices were the largest factors in this decline. Partially offsetting this
factor was a decrease in production costs per equivalent barrel of production
from $5.18 in 1993 to $4.23 in 1994, which can be attributed to the effects of
the producing fee mineral interests where the Company does not have to share in
operating costs.
In 1996, the Company expects to use seismic data to identify prospects to
drill in its core areas of emphasis. These areas are Texas, Louisiana,
Mississippi and Alabama. The Company has also signed an agreement to work with
an exploration company to assist in prospect generation. The Company also plans
to perform additional horizontal drilling in central Texas and developmental
drilling in Mississippi on acreage that it acquired in 1995 from Norcen.
Crude Oil Marketing
Year Ended December 31,
---------------------------------
1995 1994 1993
---- ---- ----
(In thousands)
Revenues $622,657 $402,855 $369,054
======== ======== ========
Operating profit $ 8,288 $ 2,085 $ 844
======== ======== ========
Revenues increased 55% in 1995 due to a 42% increase in barrels sold per
day and higher average crude oil prices. In 1994, the Company sold 67,174
barrels per day of crude oil. In 1995, that average daily sales quantity
increased to 95,384 barrels. Also increasing revenues were the crude oil
pipeline transmission activities of the segment. On March 31, 1995, the Company
acquired three crude oil pipelines from Exxon. During the nine months the
Company owned these pipelines, an average of 90,375 barrels per day were
transported, generating revenues of $13.4 million. These revenues also include
$1.0 million received from Exxon representing nine months of rent under the
terms of a one-year lease of the 1.2 million barrels of tank space the Company
owns in northwest Houston.
Operating profits of the crude oil marketing segment increased 298% from
$2.1 million in 1994 to $8.3 million in 1995. This increase can be attributed
to the Company's pipeline activities.
Revenues increased 9% in 1994 over 1993 levels despite a drop in crude oil
sales prices. The Company sold 67,174 barrels per day of crude oil in 1994, an
increase of 10,093 barrels per day from 1993. The acquisition of the pipeline
injection points from a small gatherer provided the Company with additional
marketing locations beginning in March 1994, allowing the Company to be more
competitive in these areas, which contributed significantly to this increase in
barrels. Operating profits in 1994 improved significantly over 1993 levels.
The increase in barrels sold combined with improved margins, due partly to the
limited use of hedging techniques, were factors resulting in the improved
operating profits.
In 1996, the crude oil marketing segment will concentrate on increasing
throughput on the MS System where the loss of a significant shipper has dropped
volumes to a lower level than anticipated. Overall, the Company has been
pleased with the financial stability of the pipeline acquisition and plans to
extend the Jay System 13 miles into south Alabama at a cost of $1.5 million.
This extension is expected to enhance transportation economics for shippers in
the area, increasing throughput volumes for the Company. Additionally, the
Company will reactivate the northern end of the Texas System, opening up
alternative markets to the north. The Company will also search for customers to
lease the tankage upon the expiration of Exxon's lease in March 1996.
Technical Fuels and Chemical Processing
Year Ended December 31,
---------------------------------
1995 1994 1993
---- ---- ----
(In thousands)
Revenues $30,951 $29,580 $25,300
======= ======= =======
Operating profit (loss) $ 2,479 $ 579 $ 85
======= ======= =======
The technical fuels and chemical processing segment experienced a 5% increase
in revenues and a 328% increase in operating profit when comparing 1995 to 1994.
Revenues from chemical sales and toll processing rose slightly in 1995 resulting
from a focus on acetate and ester manufacturers for the paint and coatings
industry. Revenues from sales of research and reference fuels declined $2.4
million in 1995. Volumes sold decreased by 11%. These decreases are
attributable to a focus by lubricant manufacturers and laboratories on product
certification rather than testing to develop and certify products to meet new
standards. Development is expected to increase again in 1997 in order to prepare
to meet 1998 performance standards. Also contributing to the higher revenues
and to the improved operating results was the revenue recognized upon the
cancellation of a long-term contract to process for a customer. The customer
decided that demand for its product was not sufficient to warrant continuation
of the contract and released the Company from further requirements under the
contract. The loss of this contract opens up the Company's synthesis reaction
unit for availability to other customers. The revenue and operating profit
recognized by this contract cancellation was $1.1 million.
As stated above, the $1.9 million improvement in operating profit from the
1994 level is partially attributable to the $1.1 million recognized upon the
cancellation of a contract. The remaining $0.8 million operating profit
improvement resulted from higher gross margins on the research and reference
fuels sold and a higher level of toll processing activities without a
corresponding increase in costs.
In 1994, the technical fuels and chemical processing segment not only had a
17% improvement in revenues, but also enjoyed a significant improvement in
operating results from the breakeven result in 1993. Revenues increased in 1994
from both increased sales of research and reference fuels and higher revenues
from chemical toll processing activities. A combination of new environmental
mandates and development in 1992 of new test procedures by the American Society
of Testing and Materials ("ASTM") produced opportunities in 1993 and 1994 for
development of new research and reference fuels. Volumes sold of these fuels
increased from 215,628 in 1993 to 257,604 in 1994.
Chemical processing revenues improved in 1994 as a result of the availability
of synthesis reaction capabilities beginning in February 1994 after completion
of the related construction. Revenues from chemical processing suffered in 1993
from a cyclical downturn in the chemical industry.
The improvement in 1994 operating profit of the technical fuels and chemical
processing segment over 1993 was the result of improved levels of chemical toll
processing activities and the higher level of research and reference fuel sales.
Transportation
Year Ended December 31,
---------------------------------
1995 1994 1993
---- ---- ----
(In thousands)
Revenues $16,119 $12,418 $9,247
======= ======= ======
Operating profit $ 947 $ 1,289 $ 585
======= ======= ======
Revenues from hauling for third parties increased 118% in 1995 from 1994
levels, while revenues from transporting for the Company's crude oil marketing
segment and technical fuels and chemical processing segment increased 8%. In
the latter half of 1994, the Company obtained a contract with Lyondell
Petrochemical Company to service substantially all of their outbound bulk truck
transportation needs. This contract was in effect for all of 1995. The
contract allowed the transportation segment to increase its exposure to other
potential customers. In 1995 and 1994, approximately 34% and 20%, respectively,
of the transportation segment's revenues resulted from transporting for third
parties.
The improvement in revenues from 1993 to 1994 was due to a $1.6 million
increase in revenues from third party hauls and a $1.1 million increase in
revenues from transporting crude oil for the Company's crude oil marketing
segment. As stated above, the contract with Lyondell Petrochemical Company was
obtained in the third quarter of 1994.
Operating profit of the transportation segment declined in 1995 despite the
increased revenues. Two factors contributed to this decrease. In 1995, the
deregulation of truck transportation made a Texas common carrier authority
acquired by the Company in 1990 worthless. The write-off of this asset lowered
operating profit by $0.2 million. Additionally, due to the highly competitive
nature of third party business, operating margins from this type of
transportation decreased.
Certain costs of the transportation segment are fixed in nature; therefore,
all costs in 1994 did not increase as the volume of hauls increased. The
improvement in revenues in 1994 without an equal increase in costs resulted in
the improvement in operating profit in 1994 over the 1993 level.
Net Interest Expense
Interest expense in 1995 rose $4.9 million over the 1994 level. The primary
reason for this increase was funds borrowed by the Company in March 1995 to
finance the acquisitions of three crude oil pipelines from Exxon and certain oil
and gas properties from Norcen. Long-term debt rose from $35.8 million at
December 31, 1994 to $104.3 million at December 31, 1995. See Notes 4 and 6 of
Notes to Consolidated Financial Statements.
Additionally, market interest rates ranged from 8.5% to 9% throughout 1995,
while in 1994 the rates fluctuated from 6% to 8.5%. Because substantially all
of the Company's debt is subject to market rates, the higher 1995 rates
contributed to the increase in 1995 interest expense. The rise in rates in 1994
led to the increase in interest expense in 1994 over 1993. Additionally, in
1994 the Company had a higher level of average debt outstanding than in 1993.
Provision for Income Taxes
In 1995, the Company's effective tax rate of 36.5% reflects the statutory
federal rate and state income taxes less the effect of statutory depletion
deductions in excess of cost basis. As the Company's pretax income increased,
the effect of these deductions on the tax rate was less pronounced than in 1994
and 1993. In those years, these deductions contributed to an effective tax rate
that was less than the statutory federal rate.
Under the methodology of Statement of Financial Accounting Standards No. 109,
"Accounting for Income Taxes," the Revenue Reconciliation Act of 1993 (the
"Act") did not have a material impact on the tax provision of the Company in
1993, and the Act is not expected to have a material impact on the tax provision
in future years. In addition, the Act had no effect on the Company's recorded
deferred tax liability.
LIQUIDITY AND CAPITAL RESOURCES
On March 31, 1995, the Company replaced its existing revolving credit/term
loan agreement and letter of credit facility with two new credit facilities.
The revolving credit/term loan agreement was replaced with a new credit facility
among Howell Petroleum Corporation and Bank One, Texas, N.A., Bank of Montreal,
Compass Bank - Houston and Den norske Bank AS (the "HPC Credit Facility"). The
borrowing base under the HPC Credit Facility was $44.5 million at December 31,
1995 and declines monthly by $0.7 million until such time as it is redetermined.
The borrowing base is reviewed semi-annually by the banks with mandatory
payments if the borrowing base, as determined solely by the banks based on the
Company's interest in proved oil and gas reserves, is less than the outstanding
balance on the loan. The Company has assumed that, although the borrowing base
will decrease in 1996, the decrease would not result in a mandatory repayment
under the terms of the HPC Credit Facility and, therefore, none of the debt is
reflected as a current obligation. The HPC Credit Facility provides for a
revolving period until June 1, 1997, with interest to be paid monthly at the
rate selected by the Company of either (1) a Floating Base Rate (as defined in
the HPC Credit Facility) that is generally the prevailing prime rate or (2) a
rate based on LIBOR. A LIBOR-based rate of 7.9375% was applicable to $34.5
million of the outstanding balance under the HPC Credit Facility at December 31,
1995. The remainder of the outstanding balance of $7.8 million was subject to
the Floating Base Rate of 8.5%. At the end of the revolving period, the
revolving loan converts automatically to a four-year term loan, with principal
payments to be made in sixteen quarterly installments along with accrued
interest on the unpaid principal balance. The HPC Credit Facility also provides
for the issuance of letters of credit in an amount up to $5.0 million. The
amount of letters of credit outstanding reduces the amount of the available
commitment.
The HPC Credit Facility is collateralized by mortgages on substantially all
of the Company's producing oil and gas properties, the common stock of HPC, the
common stock of HCO and the guarantee of the Company. There is no compensating
balance requirement, and the HPC Credit Facility carries a commitment fee of
3/8% on the available portion of the commitment. The HPC Credit Facility limits
the ability of the Company, without the banks' prior approval, to (i) declare or
pay dividends on shares of any class of its capital stock any time a default or
event of default (as defined in the HPC Credit Facility) exists or will result
from such declaration or payment; (ii) enter into certain extraordinary
corporate transactions, including a merger, consolidation, liquidation or
dissolution; or (iii) during any 12-month period, dispose of assets having an
aggregate book value of more than five percent of the Company's net worth.
Material covenants and restrictions include requirements to maintain a ratio of
current assets plus the available portion of the commitment to current
liabilities of at least 1:1, to maintain tangible net worth, as defined in the
HPC Credit Facility, of a floating amount that was $68.6 million at December 31,
1995, and to prohibit certain defined types of additional indebtedness and the
granting of certain liens on the Company's assets without the banks' approval.
Based on the terms of the HPC Credit Facility, at December 31, 1995, $9.2
million of the Company's retained earnings was unrestricted as to the payment of
common and preferred dividends. This amount varies based on changes in the
shareholders' equity of the Company.
The letter of credit facility was replaced with a new credit facility among
Howell Crude Oil Company, Bank One, Texas, N.A., Bank of Montreal, Compass Bank
- - - - Houston and Den norske Bank AS (the "HCO Credit Facility"). The HCO Credit
Facility provides for a term loan in an amount of $57.5 million and for the
issuance of letters of credit in the aggregate not to exceed the lesser of the
commitment of $15 million or the Borrowing Base, as defined in the HCO Credit
Facility.
Repayment of the term loan will occur over a period not to exceed seven
years. In July 1995, the Company began making principal payments in quarterly
installments of $1.4 million. In addition, the Company is required to make
additional repayments of the term loan, beginning in the second quarter of 1996,
equal to 60% of Excess Cash Flow, as defined in the HCO Credit Facility.
Interest will be paid monthly at the rate selected by the Company of either (1)
a Floating Base Rate (as defined in the HCO Credit Facility) that is generally
the prevailing prime rate or (2) a rate based on LIBOR. A LIBOR-based rate of
7.9375% was applicable to the outstanding balance under the HCO Credit Facility
at December 31, 1995.
The HCO Credit Facility carries a commitment fee of 1/4% on the available
portion of the commitment for letters of credit. There is no compensating
balance requirement. The HCO Credit Facility is collateralized by the inventory
and accounts receivable of HCO, the pipeline properties acquired from Exxon, the
common stock of HCO and its subsidiaries, the common stock of HPC, and the
guarantee of the Company. Material covenants and restrictions are the same as
those described above for the HPC Credit Facility.
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 timely.
At December 31, 1995, the Company had negative working capital of $0.8
million. In 1995, it generated cash flow from operating activities of $21.2
million. The transportation, crude oil marketing and technical fuels and
chemical processing segments are expected by the Company to continue to
positively impact 1996 operating cash flow, offset to some extent by the impact
of higher interest expense due to higher debt levels.
The Company currently anticipates spending approximately $0.8 million during
fiscal 1996 and approximately $0.8 million during fiscal 1997 at various of its
facilities for capital and operating costs associated with ongoing environmental
compliance and will continue to have expenditures in connection with
environmental matters beyond fiscal 1997. The Company's Channelview facility,
most of which has been constructed since 1988, was designed and engineered to
comply with the more stringent current regulations. The Company has determined
that the federal wastewater discharge permit at its Channelview facility may
have expired prior to the transfer of the permit to the Company. The Company is
taking steps to resolve this matter. See Note 10 of Notes to Consolidated
Financial Statements.
The Company believes that its cash flow from operations and amounts available
under the HPC Credit Facility will be sufficient to satisfy its current
liquidity requirements. At December 31, 1995, the Company had $2.3 million
available to it under the HPC Credit Facility. A significant decline in the
value of the Company's proved reserves could result in the bank reducing the
borrowing base, causing mandatory payments under the HPC Credit Facility. While
the Company does not expect this to happen in 1996, such payments would
adversely affect the Company's ability to carry out its capital expenditure
program.
In order to guarantee the Company a specific minimum sales price for its
crude oil, the Company purchased a put option and sold a call option covering
approximately 3,300 barrels per day of crude oil production for an eighteen
month period beginning March 1, 1995. The option strike prices are based on the
average price of crude oil on the organized exchange, with monthly settlement.
The strike prices are $17 per barrel for the put option and $20 per barrel for
the call option. During 1995, the monthly average sales price of crude oil on
the organized exchange was between $17 and $20 per barrel; therefore, no options
were exercised during the period.
In 1995 the Company announced that it was seeking an exchange of its Main
Pass offshore property for onshore producing properties. While the Company is
not actively pursuing an exchange, it will consider trading Main Pass for
onshore properties with similar cash flow and reserve characteristics. The
Company also offered its minerals properties for sale. These properties
produced net cash flow from production of $1.8 million and an additional $0.2
million from leasing activities in 1995. A sale of these properties would not
be expected to have a significant impact on the Company.
In 1995 the Financial Accounting Standards Board issued Statements of
Financial Accounting Standards Nos. 121 and 123 entitled "Impairment of Long-
Lived Assets" and "Stock-Based Compensation," respectively. Statement 121
contains provisions for recording impairment of long-lived assets that are not
expected to produce net cash flows in the future to fully recover the remaining
cost of the related assets. The Company does not plan to adopt Statement 121
until 1996 and does not expect to record impairment on any of its assets.
Statement 123 permits, but does not require, a fair value based method of
accounting for employee stock option plans which results in compensation expense
being recognized in the results of operations when stock options are granted.
The company plans to continue the use of its current intrinsic value based
method of accounting for such plans where no compensation expense is recognized.
However, as required by Statement 123, the Company will provide pro forma
disclosure of net income and earnings per share in the notes to the consolidated
financial statements as if the fair value based method of accounting had been
applied. Statement 123 is effective for the Company in 1996.
Item 8. Financial Statements and Supplementary Data
The response to this item is submitted as a separate section of this report
(see page 22).
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
Not applicable.
Part III
Item 10. Directors and Executive Officers of the Registrant
Regarding Directors, the information appearing under the caption "Election of
Directors" set forth in the Company's definitive proxy statement, to be filed
within 120 days after the close of the fiscal year in connection with the 1996
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
---- --- --------
Paul N. Howell 77 President and Chief Executive Officer
Allyn R. Skelton, II 44 Senior Vice President, Chief Financial
Officer and Secretary
Robert T. Moffett 44 Vice President and General Counsel
Mr. Paul N. Howell is President and Chief Executive Officer of the Company.
He has been Chief Executive Officer since 1955. He was elected President in
September 1995. Prior to that time he served as Chief Executive Officer and
Chairman of the Board.
Mr. Allyn R. Skelton, II, was elected Senior Vice President of the Company in
July 1993, Chief Financial Officer in May 1989, Vice President in July 1988 and
Secretary in February 1990. He had served as the Controller of the Company
since April 1985. Mr. Skelton also served as Secretary of the Company from
October 1985 until October 1988. He joined the Company in 1983.
Mr. Robert T. Moffett was elected Vice President and General Counsel of the
Company in January 1994. He had served as General Counsel of the Company since
September 1992. Prior to that time, Mr. Moffett was associated with 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 1996 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 1996 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 1996 Annual Shareholders' Meeting, is incorporated herein by
reference.
Item 13. Certain Relationships and Related Transactions
The information appearing under the caption "Certain Transactions" set forth
in the Company's definitive proxy statement, to be filed within 120 days after
the close of the fiscal year in connection with the 1996 Annual Shareholders'
Meeting, is incorporated herein by reference.
Part IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a)(1) and (2). The response to this portion of Item 14 is submitted as a
separate section of this report (see page 22).
(a)(3) and (c). The response to this portion of Item 14 is submitted as a
separate section of this report (see page 41).
(b). Reports on Form 8-K. None were filed during the last quarter of the
Registrant's fiscal year ended December 31, 1995.
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
Senior Vice President,
Chief Financial Officer and
Secretary
Principal Financial and Accounting Officer
Date: February 27, 1996
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/ Paul N. Howell Officer and Director February 27, 1996
----------------------
Paul N. Howell
President
and
Chief Executive Officer
/s/ Ronald E. Hall Director February 27, 1996
----------------------
Ronald E. Hall
Chairman of the Board
/s/ Jack T. Trotter Director February 27, 1996
----------------------
Jack T. Trotter
/s/ Robert M. Ayres, Jr. Director February 27, 1996
----------------------
Robert M. Ayres, Jr.
/s/ Walter M. Mischer, Sr. Director February 27, 1996
----------------------
Walter M. Mischer, Sr.
HOWELL CORPORATION AND SUBSIDIARIES
FORM 10-K
ITEMS 8, 14(a) (1) and (2)
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES
The following consolidated financial statements of the registrant and its
subsidiaries required to be included in Items 8 and 14(a)(1) are listed below:
Page
----
Independent Auditors' Report 23
Consolidated Financial Statements:
Consolidated Balance Sheets 24
Consolidated Statements of Earnings 25
Consolidated Statements of Shareholders' Equity 26
Consolidated Statements of Cash Flows 27
Notes to Consolidated Financial Statements 28
The following consolidated supplemental schedules of the registrant and its
subsidiaries are included in Item 14(a)(1):
Page
----
Supplemental Schedules:
Property, Plant and Equipment 39
Accumulated Depreciation, Depletion and Amortization
of Property, Plant and Equipment 40
The financial statement schedules are omitted because they are not
applicable, are not required or because the required information is included in
the Consolidated Financial Statements or notes thereto.
INDEPENDENT AUDITORS' REPORT
To Howell Corporation:
We have audited the accompanying consolidated balance sheets of Howell
Corporation and its subsidiaries as of December 31, 1995 and 1994, and the
related consolidated statements of earnings, shareholders' equity, and cash
flows for each of the three years in the period ended December 31, 1995. 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, 1995 and 1994, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1995 in conformity with generally accepted accounting principles.
Our audits were conducted for the purpose of forming an opinion on the
basic financial statements taken as a whole. The supplemental schedules listed
in the Index on page 22 are presented for the purpose of additional analysis and
are not a required part of the basic financial statements. These schedules are
the responsibility of the Company's management. Such schedules have been
subjected to the auditing procedures applied in our audits of the basic
financial statements and, in our opinion, are fairly stated in all material
respects when considered in relation to the basic financial statements taken as
a whole.
DELOITTE & TOUCHE LLP
Houston, Texas
February 27, 1996
HOWELL CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
December 31,
1995 1994
---- ----
(In thousands)
Assets
Current assets:
Cash and cash equivalents $ 3,742 $ 3,340
Trade accounts receivable, less allowance
for doubtful accounts of $239,000 in
1995 and $214,000 in 1994 65,288 48,432
Inventories 5,428 2,655
Other current assets 1,712 1,520
-------- --------
Total current assets 76,170 55,947
Property, plant and equipment:
Oil and gas properties, utilizing the
full-cost method of accounting 278,505 264,430
Fee mineral interests, unproven 18,188 18,200
Other 107,735 34,837
Less accumulated depreciation, depletion
and amortization (209,087) (192,694)
-------- --------
Net property, plant and equipment 195,341 124,773
-------- --------
Other assets, net of accumulated amortization of
$51,000 in 1995 1,815 1,720
-------- --------
Total assets $273,326 $182,440
======== ========
Liabilities and Shareholders' Equity
Current liabilities:
Current maturities of long-term debt $ 8,068 $ 2,670
Accounts payable 61,771 46,178
Accrued liabilities 7,141 5,152
-------- --------
Total current liabilities 76,980 54,000
-------- --------
Deferred income taxes 20,971 19,273
-------- --------
Other liabilities 150 150
-------- --------
Long-term debt and capital lease obligation 96,205 33,098
-------- --------
Commitments and contingencies
Shareholders' equity:
Preferred stock, $1 par value; 690,000
shares issued and outstanding;
liquidation value of $17,250,000 690 690
Common stock, $1 par value; 4,933,446 shares
issued and outstanding in 1995;
4,836,876 shares issued and outstanding
in 1994 4,933 4,837
Additional paid-in capital 34,390 33,518
Retained earnings 39,007 36,874
-------- --------
Total shareholders' equity 79,020 75,919
-------- --------
Total liabilities and shareholders'
equity $273,326 $182,440
======== ========
See accompanying Notes to Consolidated Financial Statements.
HOWELL CORPORATION AND SUBSIDIARIES
Consolidated Statements of Earnings
Year Ended December 31,
----------------------------
1995 1994 1993
---- ---- ----
(In thousands, except per share amounts)
Revenues $673,537 $448,952 $411,736
-------- -------- --------
Costs and expenses:
Products including operating expenses 646,676 431,783 396,556
Selling, general and administrative expenses 11,748 10,992 9,912
-------- -------- --------
658,424 442,775 406,468
-------- -------- --------
Other income (expense):
Interest expense (7,109) (2,237) (1,915)
Interest income 229 131 308
Other, net 154 180 (70)
-------- -------- --------
(6,726) (1,926) (1,677)
-------- -------- --------
Earnings from operations before income taxes 8,387 4,251 3,591
Provision for income taxes 3,061 1,368 1,064
-------- -------- --------
Net earnings $ 5,326 $ 2,883 $ 2,527
======== ======== ========
Weighted average shares outstanding 4,869 4,837 4,823
======== ======== ========
Net earnings per common share $ 0.60 $ 0.10 $ 0.18
======== ======== ========
See accompanying Notes to Consolidated Financial Statements.
HOWELL CORPORATION AND SUBSIDIARIES
Consolidated Statements of Shareholders' Equity
Preferred Stock Common Stock Treasury Stock
--------------- ------------ Additional --------------
Paid-In Retained
Shares $ Shares $ Capital Earnings Shares $ Total
------ --- ------ --- ------- -------- ------ --- -----
(In thousands, except number of shares)
Balances, December 31, 1992 - $ - 4,829,376 $4,829 $ 1,293 $37,082 10,000 $(115) $43,089
Net earnings - 1993 - - - - - 2,527 - - 2,527
Cash dividends - $.16 per
common share - - - - - (772) - - (772)
Cash dividends - $2.40 per
preferred share - - - - - (1,657) - - (1,657)
Common stock issued to
director upon exercise
of stock options - - 7,500 8 55 - - - 63
Sale of preferred stock 690,000 690 - - 32,170 - - - 32,860
Sale of treasury stock (10,000) 115 115
------- ------- --------- ------ ------- ------- ------- ----- -------
Balances, December 31, 1993 690,000 690 4,836,876 4,837 33,518 37,180 - - 76,225
Net earnings - 1994 - - - - - 2,883 - - 2,883
Cash dividends - $.16 per
common share - - - - - (774) - - (774)
Cash dividends - $3.50 per
preferred share (2,415) - - (2,415)
------- ------- --------- ------ ------- ------- ------- ----- -------
Balances, December 31, 1994 690,000 690 4,836,876 4,837 33,518 36,874 - - 75,919
Net earnings - 1995 - - - - - 5,326 - - 5,326
Cash dividends - $.16 per
common share - - - - - (778) - - (778)
Cash dividends - $3.50 per
preferred share - - - - - (2,415) - - (2,415)
Common stock issued to
employees and directors
upon exercise of
stock options 96,570 96 872 - - - 968
------- ------- --------- ------ ------- ------- ------- ----- -------
Balances, December 31, 1995 690,000 $ 690 4,933,446 $4,933 $34,390 $39,007 - $ - $79,020
======= ======= ========= ====== ======= ======= ======= ===== =======
See accompanying Notes to Consolidated Financial Statements.
HOWELL CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Year Ended December 31,
--------------------------
1995 1994 1993
---- ---- ----
(In thousands)
OPERATING ACTIVITIES:
Net earnings $ 5,326 $ 2,883 $ 2,527
Adjustments to reconcile net earnings to
cash provided by operations:
Depreciation, depletion and amortization 16,404 12,323 11,070
Deferred income taxes 1,698 1,057 1,032
Gain on sale(s) of asset(s) (34) (25) (11)
(Increase) decrease in accounts receivable (16,856) (18,080) 21,519
Increase in inventories (2,773) (82) (86)
(Increase) decrease in other current assets (192) 478 (580)
Increase (decrease) in accounts payable 15,593 18,657 (20,650)
Increase (decrease) in accrued and other
liabilities 1,989 656 (1,147)
-------- -------- --------
Cash provided by operating activities 21,155 17,867 13,674
-------- -------- --------
INVESTING ACTIVITIES:
Proceeds from the disposition of assets 1,629 1,450 1,491
Additions to property, plant and equipment (88,282) (13,408) (39,111)
Other, net (380) (551) 28
-------- -------- --------
Cash utilized in investing activities (87,033) (12,509) (37,592)
-------- -------- --------
FINANCING ACTIVITIES:
Long-term debt:
Borrowings (repayments) under revolving credit
agreement, net 18,050 (300) (4,550)
Borrowings under term loan agreements, net 54,625 - -
Payments to Department of Energy (2,122) (1,047) (981)
Other repayments (2,048) (819) (479)
Cash dividends:
Common shareholders (778) (774) (772)
Preferred shareholders (2,415) (2,415) (1,657)
Issuance of preferred stock - - 32,860
Exercise of stock options 968 - 63
Sale of treasury shares - - 115
-------- -------- --------
Cash provided by (utilized in) financing
activities 66,280 (5,355) 24,599
-------- -------- --------
NET INCREASE IN CASH BALANCE 402 3 681
CASH, BEGINNING OF YEAR 3,340 3,337 2,656
-------- -------- --------
CASH, END OF YEAR $ 3,742 $ 3,340 $ 3,337
======== ======== ========
See accompanying Notes to Consolidated Financial Statements.
HOWELL CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Years Ended December 31, 1995, 1994 and 1993
Note 1. Summary of Significant Accounting Policies
Principles of Consolidation
The consolidated financial statements include the accounts of Howell
Corporation and its subsidiaries (the "Company"). All significant intercompany
accounts and transactions have been eliminated.
Nature of Operations
The Company is primarily engaged in exploration, production, acquisition
and development of oil and gas properties. The Company is also involved in
compatible crude oil marketing, technical fuels and chemical processing and
transportation. These operations are conducted in the United States.
Information on the relative importance of the segments can be found in Note 8.
Inventories
Inventories of crude oil and refined products are stated at the lower of
market value or monthly weighted average cost. Crude oil exchange transactions
are included as additions to or reductions of inventories at the time title
passes. The Company has a limited program of hedging its crude oil inventories
and fixed purchase price commitments. Crude oil future contracts and options
are being used as the hedging tools. Changes in the market value of the
financial instruments are deferred until the gain or loss is recognized on the
hedged transactions.
Other inventories are stated at the lower of average cost or market value.
Property, Depreciation, Depletion and Amortization
The Company follows the full-cost method of accounting for its oil and gas
exploration and production activities, which are conducted solely in the United
States. Consequently, all costs pertaining to the acquisition, exploration and
development of oil and gas reserves are capitalized and amortized using the
unit-of-production method as the remaining proved oil and gas reserves are
produced. The Company's net investment in oil and gas properties is subject to
a quarterly ceiling limitation calculation that is based on the present value of
future net revenues from estimated production of proved oil and gas reserves
valued at current prices. Costs in excess of the ceiling limitation are
currently charged to expense. Gains or losses upon the disposition of a
property, normally treated as an adjustment to capitalized costs, are
recognized currently in the event of a sale of a significant portion
(normally in excess of 25%) of oil and gas reserves.
The costs allocated to the unproven fee mineral interests of the Company
are excluded from amortization under the full-cost method of accounting
described above. These costs are reviewed periodically for impairment. This
impairment will generally be based on geographic or geologic data. At the time
of any impairment, the related costs will be added to the costs being amortized
under the full-cost method of accounting. Due to the perpetual nature of the
Company's ownership of these mineral interests, the drilling of a well, whether
successful or unsuccessful, may not represent a complete test of all depths of
interest. Therefore, at the time that a well is drilled only a portion of the
costs allocated to the acreage drilled may be added to the costs being
amortized.
Other property and equipment are carried at cost. Depreciation is provided
principally using the straight-line method over the estimated useful lives of
the assets, primarily 10 to 15 years for technical fuels and chemical processing
and terminalling facilities and improvements, 20 years for pipelines and related
assets, 20 to 25 years for buildings, and 2 to 5 years for transportation and
operating equipment.
Maintenance and repairs are charged to expense as incurred, while renewals
and betterments are capitalized.
Income Taxes
In 1991, the Company adopted the provisions of Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes" ("Statement 109"),
which governs the accounting recognition of income taxes in its financial
statements. Statement 109 defines a balance sheet (liability) approach in the
calculation of the deferred tax balance at each financial statement date by
applying the provisions of enacted tax laws to measure the deferred tax
consequences of the differences in the tax and financial (book) bases of assets
and liabilities as they result in net taxable or deductible amounts in future
years. The net taxable or deductible amounts in future years are adjusted for
the effect of utilizing the carryback/carryforward attributes of any net losses
generated and available tax credits.
Earnings per Common Share
Earnings per common share has been computed by dividing net earnings, after
reduction for preferred stock dividends, by the weighted average number of
common shares outstanding. Shares issuable in connection with stock options are
not included in the per share computations since their dilutive effect is less
than 3%. Earnings per share assuming full dilution does not result in a
difference from earnings per share assuming no dilution. The common shares
issuable upon conversion of the convertible preferred stock are anti-dilutive,
and the common shares issuable in connection with stock options result in a
dilutive effect of less than 3%.
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
$6,435,000, $2,179,000 and $1,816,000 in 1995, 1994 and 1993, respectively. In
1995, 1994 and 1993 cash payments for income taxes totaled $1,157,650, $126,000
and $171,000, respectively.
Supplementary Oil and Gas Producing Information (Unaudited)
The supplementary oil and gas producing information required by Statement
of Financial Accounting Standards No. 69, "Disclosures about Oil and Gas
Producing Activities," is included in Item 2 Properties in this annual report on
Form 10-K.
Disclosures About Fair Value of Financial Instruments
The Company estimates that the carrying amount of its cash and cash
equivalents as reflected in its balance sheet approximates fair value because of
the short-term maturity of those items.
Information on the fair value of the Company's long-term debt and capital
lease obligation can be found in Note 6.
Environmental Liabilities
The Company provides for the estimated costs of environmental contingencies
when liabilities are likely to occur and reasonable estimates can be made. In
accordance with full cost accounting rules, the Company provides for future
environmental clean-up costs associated with oil and gas activities as a
component of its depreciation, depletion and amortization expense. Information
regarding environmental liabilities can be found in Note 10. Ongoing
environmental compliance costs, including maintenance and monitoring costs, are
charged to expense as incurred.
Derivatives
As stated above, crude oil future contracts and options are being used as a
hedging tool in a limited program of hedging crude oil inventories and fixed
purchase price commitments. Product costs of the crude oil marketing segment
were reduced by $0.1 million in both 1995 and 1994 from the effects of futures
and options.
In addition, for the second half of 1994, the Company purchased a put
option for its crude oil production to guarantee the Company a specific minimum
sales price for the volume of production hedged. Because market prices were
higher than the option strike price, the option was not exercised.
In 1995, the Company purchased a put option and sold a call option covering
3,300 barrels per day of oil production for an eighteen month period beginning
March 1, 1995. The option strike prices are based on the average price of crude
oil on the organized exchange, with monthly settlement. The strike prices are
$17 per barrel for the put option and $20 per barrel for the call option. The
premiums for the options are being amortized over the period.
During 1995, the monthly average price of crude oil on the organized
exchange was between $17 and $20 per barrel; therefore, none of the options were
exercised during this period. Premiums amortized during 1995 totaled $0.4
million and were recorded as a reduction of revenue. In 1994, premiums
amortized reduced revenues by $0.1 million.
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.
Impairment of Long-Lived Assets
In 1995, Statement of Financial Accounting Standards No. 121, "Impairment
of Long-Lived Assets" ("Statement 121") was issued. Statement 121 contains
provisions for recording impairment of long-lived assets that are not expected
to produce net cash flows in the future to fully recover the remaining cost of
the related assets. The Company does not plan to adopt Statement 121 until
1996. The Company does not expect to record impairment on any of its assets.
Stock-Based Compensation
In October 1995, Statement of Financial Accounting Standards No. 123,
"Stock-Based Compensation" ("Statement 123") was issued. Statement 123 permits,
but does not require, a fair value based method of accounting for employee stock
option plans which results in compensation expense being recognized in the
results of operations when stock options are granted. The Company plans to
continue the use of its current intrinsic value based method of accounting for
such plans where no compensation expense is recognized. However, as required by
Statement 123, the Company will provide pro forma disclosure of net income and
earnings per share in the notes to the consolidated financial statements as if
the fair value based method of accounting had been applied. Statement 123 is
effective for the Company in 1996.
Note 2. Inventories
The major classes of inventory at December 31, 1995 and 1994 were as follows:
1995 1994
---- ----
(In thousands)
Refined products $1,494 $1,333
Crude oil 2,140 578
Chemicals 1,695 665
Other materials and supplies 99 79
------ ------
$5,428 $2,655
====== ======
Note 3. Note Receivable
On April 21, 1992, the Company sold its San Antonio, Texas, refinery for a
sales price of $2.2 million. The Company received a downpayment of $0.4 million
and a note requiring monthly principal and interest payments for three years.
In 1993, the time period for repayment was extended one additional year. The
interest rate for the note was 10%. Due to the uncertainty about the ultimate
collection of the note receivable, the Company did not recognize gain on the
sale or interest income on the note as payments were made. In 1995, the Company
agreed to accept $0.5 million in settlement of the balance remaining under the
note. This settlement resulted in $0.4 million of income for the Company that
is included in other income (expense) in the Consolidated Statement of Earnings
for 1995.
Note 4 - Acquisition of Pipeline Assets
On March 31, 1995, the Company's crude oil marketing segment acquired from
Exxon Pipeline Company ("Exxon") two interstate crude oil pipeline systems and
one intrastate crude oil pipeline system. The interstate pipeline systems are
located in Florida/Alabama ("Jay System") and Mississippi/Louisiana ("MS
System"). The intrastate system is located in Texas ("Texas System").
Collectively, the purchase of these pipelines and related assets comprise the
"Exxon Transaction".
The Texas System consists of a 555-mile pipeline system extending from
Groesbeck, Texas, south to Texas City, Texas, and tanks for crude oil storage
with a total capacity of approximately 1.9 million barrels. The Jay System
consists of a 90-mile pipeline system that extends west from Santa Rosa County,
Florida, to Mobile County, Alabama, and includes tanks with approximately 0.2
million barrels of storage capacity. The MS System consists of a 230-mile
pipeline system extending from Jones County, Mississippi, to Baton Rouge,
Louisiana, and includes storage capacity of approximately 0.2 million barrels.
The total negotiated purchase price paid to Exxon for the Exxon Transaction
was $63.5 million. The Exxon Transaction was financed through borrowings from
banks. See Note 6 below.
The following unaudited pro forma information represents the consolidated
statements of earnings, assuming the Exxon Transaction had occurred at the
beginning of each period presented.
Year Ended December 31
------------------
1995 1994
---- ----
(In thousands, except per share)
Revenues $679,245 $469,002
Net earnings 6,173 4,854
Net earnings per common share 0.77 0.50
The above amounts are based upon certain assumptions and estimates which the
Company believes are reasonable. The pro forma results do not necessarily
represent results which would have occurred if the acquisition had taken place
on the basis assumed above, nor are they indicative of the results of future
combined operations.
Note 5. Income Taxes
A summary of the provision (credit) for income taxes included in the
consolidated statements of earnings is as follows:
Year Ended December 31,
------------------------
1995 1994 1993
---- ---- ----
(In thousands)
Current:
Federal $ 356 $ - $ -
State 438 161 32
Deferred 2,267 1,207 1,032
------ ------ ------
$3,061 $1,368 $1,064
====== ====== ======
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,
----------------------
1995 1994
---- ----
(In thousands)
Accrual of costs not deductible for tax $ 864 $ 841
Difference in book and tax basis of note receivable - 391
Statutory depletion carryforwards 1,274 1,043
Minimum tax credit carryforwards 418 -
Net operating loss carryforwards 2,507 3,421
Other 44 -
-------- --------
Total deferred tax assets 5,107 5,696
-------- --------
Differences between book and tax bases of
property, plant and equipment (26,078) (24,858)
Other - (111)
-------- --------
Total deferred tax liabilities (26,078) (24,969)
-------- --------
Net deferred income taxes $(20,971) $(19,273)
======== ========
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 of 34% to the earnings before income taxes:
Year Ended December 31,
-----------------------
1995 1994 1993
---- ---- ----
(In thousands)
Provision for income taxes at the statutory rate $2,852 $1,445 $1,221
Statutory depletion in excess of cost basis (327) (237) (310)
State income taxes 438 161 32
Other 98 (1) 121
------ ------ ------
$3,061 $1,368 $1,064
====== ====== ======
At December 31, 1995, the Company, for tax reporting purposes, has a net
operating loss carryforward of $6,973,000 that has been recognized as a
reduction of the deferred tax liability. The carryforward, if not previously
utilized, expires as follows: $1,542,000 in 2006, $4,128,000 in 2007 and
$1,303,000 in 2008. In addition, the Company, for tax reporting purposes, has a
statutory depletion carryforward of $3,573,000 and a minimum tax credit
carryforward of $418,000 that have been recognized as reductions of the deferred
tax liability. These carryforwards have no expiration.
Note 6. Debt and Available Credit Facilities
Long-term debt and the capital lease obligation of the Company as of December
31, 1995 and 1994 were as follows:
1995 1994
---- ----
(In thousands)
Note payable under a $44.5 million revolving credit/term loan agreement $42,250 $24,200
Note payable under a term loan agreement 54,625 -
Note payable to Department of Energy (DOE) 7,265 9,387
Note payable to Paul N. Howell - 2,000
Capital lease obligation for transportation equipment 133 181
------- -------
104,273 35,768
Less: Current maturities 8,068 2,670
------- -------
$96,205 $33,098
======= =======
Maturities of long-term debt for the five years subsequent to December 31,
1995 are as follows (in thousands):
Bank Bank
Total Revolver Term DOE
----- -------- ---- ---
1996 $ 8,016 $ - $ 5,750 $2,266
1997 13,449 5,281 5,750 2,418
1998 18,894 10,563 5,750 2,581
1999 16,312 10,562 5,750 -
2000 16,313 10,563 5,750 -
Thereafter 31,156 5,281 25,875 -
-------- ------- ------- ------
$104,140 $42,250 $54,625 $7,265
======== ======= ======= ======
The following is a schedule by years of future minimum lease payments for the
capital lease obligation, together with the present value of the net minimum
lease payments as of December 31, 1995 (in thousands):
1996 $ 60
1997 83
----
Total minimum lease payments $143
Less: Amount representing interest 10
----
Present value of net minimum lease payments $133
====
Revolving credit/term loan agreement
On March 31, 1995, the Company replaced its existing revolving credit/term
loan agreement and letter of credit facility with two new credit facilities.
The revolving credit/term loan agreement was replaced with a new credit facility
among Howell Petroleum Corporation and Bank One, Texas, N.A., Bank of Montreal,
Compass Bank - Houston and Den norske Bank AS (the "HPC Credit Facility"). The
borrowing base under the HPC Credit Facility was $44.5 million at December 31,
1995 and declines monthly by $0.7 million until such time as it is redetermined.
The borrowing base is reviewed semi-annually by the banks with mandatory
payments if the borrowing base, as determined solely by the banks based on the
Company's interest in proved oil and gas reserves, is less than the outstanding
balance on the loan. The Company has assumed that, although the borrowing base
will decrease in 1996, the decrease would not result in a mandatory repayment
under the terms of the HPC Credit Facility and, therefore, none of the debt is
reflected as a current obligation. The HPC Credit Facility provides for a
revolving period until June 1, 1997, with interest to be paid monthly at the
rate selected by the Company of either (1) a Floating Base Rate (as defined in
the HPC Credit Facility) that is generally the prevailing prime rate or (2) a
rate based on LIBOR. A LIBOR-based rate of 7.9375% was applicable to $34.5
million of the outstanding balance under the HPC Credit Facility at December 31,
1995. The remainder of the outstanding balance of $7.8 million was subject to
the Floating Base Rate of 8.5%. At the end of the revolving period, the
revolving loan converts automatically to a four-year term loan, with principal
payments to be made in sixteen quarterly installments along with accrued
interest on the unpaid principal balance. The HPC Credit Facility also provides
for the issuance of letters of credit in an amount up to $5.0 million. The
amount of letters of credit outstanding reduces the amount of the available
commitment.
The HPC Credit Facility is collateralized by mortgages on substantially all
of the Company's producing oil and gas properties, the common stock of Howell
Petroleum Corporation ("HPC"), the common stock of Howell Crude Oil Company
("HCO") and the guarantee of the Company. There is no compensating balance
requirement, and the HPC Credit Facility carries a commitment fee of 3/8% on the
available portion of the commitment. The HPC Credit Facility limits the ability
of the Company, without the banks' prior approval, to (i) declare or pay
dividends on shares of any class of its capital stock any time a default or
event of default (as defined in the HPC Credit Facility) exists or will result
from such declaration or payment; (ii) enter into certain extraordinary
corporate transactions, including a merger, consolidation, liquidation or
dissolution; or (iii) during any 12-month period, dispose of assets having an
aggregate book value of more than five percent of the Company's net worth.
Material covenants and restrictions include requirements to maintain a ratio of
current assets plus the available portion of the commitment to current
liabilities of at least 1:1, to maintain tangible net worth, as defined in the
HPC Credit Facility, of a floating amount that was $68.6 million at December 31,
1995, and to prohibit certain defined types of additional indebtedness and the
granting of certain liens on the Company's assets without the banks' approval.
Based on the terms of the HPC Credit Facility, at December 31, 1995, $9.2
million of the Company's retained earnings was unrestricted as to the payment of
common and preferred dividends. This amount varies based on changes in the
shareholders' equity of the Company.
Term loan agreement
The letter of credit facility was replaced with a new credit facility among
Howell Crude Oil Company, Bank One, Texas, N.A., Bank of Montreal, Compass Bank
- - - - Houston and Den norske Bank AS (the "HCO Credit Facility"). The HCO Credit
Facility provides for a term loan in an amount of $57.5 million and for the
issuance of letters of credit in the aggregate not to exceed the lesser of the
commitment of $15 million or the Borrowing Base, as defined in the HCO Credit
Facility.
Repayment of the term loan will occur over a period not to exceed seven
years. In July 1995, the Company began making principal payments in quarterly
installments of $1.4 million. In addition, the Company is required to make
additional repayments of the term loan, beginning in the second quarter of 1996,
equal to 60% of Excess Cash Flow, as defined in the HCO Credit Facility.
Interest will be paid monthly at the rate selected by the Company of either (1)
a Floating Base Rate (as defined in the HCO Credit Facility) that is generally
the prevailing prime rate or (2) a rate based on LIBOR. A LIBOR-based rate of
7.9375% was applicable to the outstanding balance under the HCO Credit Facility
at December 31, 1995.
The HCO Credit Facility carries a commitment fee of 1/4% on the available
portion of the commitment for letters of credit. There is no compensating
balance requirement. The HCO Credit Facility is collateralized by the inventory
and accounts receivable of HCO, the pipeline properties acquired from Exxon, the
common stock of HCO and its subsidiaries, the common stock of HPC, and the
guarantee of the Company. Material covenants and restrictions are the same as
those described above for the HPC Credit Facility.
Department of Energy
As a result of an agreement settling allegations by the DOE against the
Company related to crude oil pricing and allocation regulation violations in the
1970's, the Company agreed, in 1989, to pay $19.4 million to the DOE. The
remaining balance owed at December 31, 1995 was $7.3 million. The obligation
bears interest at a trailing average prime rate. At December 31, 1995, that
rate was 8.85%.
The payments required by the agreement may be accelerated at the Company's
discretion or pursuant to a formula based on proceeds from any significant sale
of assets by the Company or its affiliates. Asset sales in 1990 through 1995,
based on the formula contained in the final order, did not result in an
acceleration of principal payments. There is a provision in the agreement for
securing the installment payments due the DOE, but only under certain conditions
which are applicable in the event the Company's current secured lender releases
its security. Other than the financial obligations discussed above, the
agreement does not impose any restrictions or limitations on the manner in which
the Company may conduct its business in the future.
Other
During 1982, the Company borrowed $4.5 million from Paul N. Howell,
President and Chief Executive Officer of the Company. In 1987, 1988 and 1991
the Company made partial repayments of the term note totaling $2.5 million. In
November 1995, the term note was repaid.
In July 1992, the Company entered into a capital lease for transportation
equipment. The obligation is payable in monthly installments with interest at
7.4%. The obligation is secured by the equipment. Included in property at
December 31, 1995, is the cost of the transportation equipment under capital
lease of $0.3 million and accumulated depreciation of $0.1 million on the
equipment.
Fair value of long-term debt
The fair value of the Company's long-term debt and its capital lease
obligation at December 31, 1995 was estimated to be the same as its carrying
value in the balance sheet, as all significant debt obligations bear interest at
floating market rates.
Note 7. Shareholders' Equity
Preferred stock
At December 31, 1995 and 1994, 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, 1995 and 1994, the Company had 10,000,000 shares of common
stock authorized.
Under the Company's 1975 Nonqualified Stock Option Plan (the "1975 Plan"),
options to purchase 180,000 shares could be granted. At December 31, 1994,
options to acquire 4,020 shares were outstanding and exercisable, at an average
price of $14.88 per share. No options were exercised pursuant to the 1975 Plan
during 1995 and no additional options may be granted under this plan. At
December 31, 1995, all options issued pursuant to the 1975 Plan had expired.
Under the Company's 1988 Stock Option Plan, options to purchase 750,000
shares may be granted. At December 31, 1994, options to acquire 443,173 shares
were outstanding, of which 209,758 were exercisable at an average price of
$10.12 per share. The average exercise price of all options outstanding at
December 31, 1994 was $10.56 per share. At December 31, 1995, options to
acquire 466,217 shares were outstanding, of which 182,670 were exercisable at an
average price of $10.32 per share. The average exercise price of all options
outstanding at December 31, 1995 was $10.96 per share. Options to acquire
96,570 and 7,500 shares were exercised in 1995 and 1993, respectively, at
average exercise prices of $10.03 and $8.32 per share, respectively.
Note 8. Segment Information
Financial information about the Company's continuing operations for each of
the years ended December 31, 1995, 1994 and 1993 is summarized as follows:
Technical
Fuels
& Inter-
Oil & Gas Crude Oil Chemical Trans- segment
Production Marketing Processing portation Other Sales Total
---------- --------- ---------- --------- ----- ----- -----
(In thousands)
December 31, 1995
Revenues $ 31,501 $622,657 $30,951 $16,119 $ - $(27,691) $673,537
-------- -------- ------- ------- ------- -------- --------
Operating profit (loss) $ 6,977 $ 8,288 $ 2,479 $ 947 $ (157) $ 18,534
-------- -------- ------- ------- ------- --------
General corporate expense $ (3,421)
Other income (expense), net $ (6,726)
--------
Earnings from operations
before income taxes $ 8,387
--------
Identifiable assets $109,755 $125,316 $23,275 $ 4,189 $10,791 $273,326
-------- -------- ------- ------- ------- --------
Capital expenditures $ 14,949 $ 69,997 $ 1,052 $ 2,193 $ 91 $ 88,282
-------- -------- ------- ------- ------- --------
Depreciation, depletion and
amortization $ 10,259 $ 2,919 $ 2,152 $ 764 $ 310 $ 16,404
-------- -------- ------- ------- ------- --------
December 31, 1994
Revenues $ 28,918 $402,855 $29,580 $12,418 $ 16 $(24,835) $448,952
-------- -------- ------- ------- ------- -------- --------
Operating profit (loss) $ 6,224 $ 2,085 $ 579 $ 1,289 $ (342) $ 9,835
-------- -------- ------- ------- ------- --------
General corporate expense $ (3,658)
Other income (expense), net $ (1,926)
--------
Earnings from operations
before income taxes $ 4,251
--------
Identifiable assets $105,806 $ 42,794 $22,377 $ 2,894 $ 8,569 $182,440
-------- -------- ------- ------- ------- --------
Capital expenditures $ 9,606 $ 765 $ 1,345 $ 1,407 $ 285 $ 13,408
-------- -------- ------- ------- ------- --------
Depreciation, depletion and
amortization $ 9,282 $ 280 $ 2,024 $ 410 $ 327 $ 12,323
-------- -------- ------- ------- ------- --------
December 31, 1993
Revenues $ 31,281 $369,054 $25,300 $ 9,247 $ - $(23,146) $411,736
-------- -------- ------- ------- ------- -------- --------
Operating profit (loss) $ 7,287 $ 844 $ 85 $ 585 $ (61) $ 8,740
-------- -------- ------- ------- ------- --------
General corporate expense $ (3,472)
Other income (expense), net $ (1,677)
--------
Earnings from operations
before income taxes $ 3,591
--------
Identifiable assets $107,996 $ 24,111 $22,306 $ 1,506 $ 8,623 $164,542
-------- -------- ------- ------- ------- --------
Capital expenditures $ 35,769 $ 296 $ 2,423 $ 338 $ 285 $ 39,111
-------- -------- ------- ------- ------- --------
Depreciation, depletion
and amortization $ 8,483 $ 213 $ 1,851 $ 264 $ 259 $ 11,070
-------- -------- ------- ------- ------- --------
In addition to the results of the Company's oil and gas exploration and
production activities, the oil and gas production segment information includes
the gas marketing activities of the Company and the results of production of
carbon dioxide, helium and sulfur from the LaBarge Project.
Intersegment sales by the oil and gas production segment to the crude oil
marketing segment were $16,399,000, $14,258,000 and $14,146,000 in 1995, 1994
and 1993, respectively. Intersegment sales by the transportation segment to the
crude oil marketing segment in 1995, 1994 and 1993 were $8,858,000, $7,743,000
and $6,642,000, respectively. Intersegment sales by the transportation segment
to the technical fuels and chemical processing segment in 1995, 1994 and 1993
were $1,697,000, $2,066,000 and $1,683,000, respectively. Intersegment sales by
the oil and gas production segment to the technical fuels and chemical
processing segment in 1995, 1994 and 1993 were $737,000, $768,000 and $675,000,
respectively. These amounts have been eliminated in consolidation.
Marathon Oil Company, a customer of the crude oil marketing segment,
accounted for approximately 12%, 18% and 11% of consolidated revenues in 1995,
1994 and 1993, respectively.
Note 9. Litigation
Donna Refinery Partners, Ltd. v. Howell Crude Oil Company and Howell
Corporation; Texas District Court; No. 89-033634. In December 1993, a jury
verdict of $1.9 million was rendered against the Company in this lawsuit
alleging breach of contract. The trial judge reduced the jury verdict to
approximately $675,000. The Company believes the judgment is in error. The
Company filed a motion for a new trial that was denied, so the Company appealed
the decision. Donna has filed an appeal to increase the recovery by $1.25
million. Briefs have been filed and arguments heard, and a decision on the
appeal is pending. The Company does not believe that the ultimate resolution of
this matter will have a material adverse effect on the financial condition or
results of operations of the Company.
Mobile Mineral Corporation, et al, v. Howell Crude Oil Company, et al;
Circuit Court of Mobile County, Alabama; CV-95-1564. This lawsuit was filed as
a class action in May 1995 by one working interest owner and two royalty owners
in the North Frisco City Field alleging breach of contracts by not paying the
plaintiffs " . . . the highest available price for oil". Damages claimed by the
plaintiffs are approximately $3.8 million and are based on numerous damage
theories including, but not limited to, allegations of breach of contract and
fraud. The complaint also seeks punitive damages. The Company has filed an
answer denying all charges.
Related to this matter, the Company, on July 11, 1995, received a demand
letter from the working interest owners in the North Frisco City Field and in
the North Rome Field indicating the Company had not paid according to the terms
of a "call on production".
The Company was granted a call on a portion of this production but has never
exercised the call. Accordingly, the Company has filed a petition for a
declaratory judgment to that effect in Texas District Court. The defendants in
this action have counterclaimed against the Company. These claims are similar
in nature to the Alabama litigation. One of the defendants, John Faulkinberry,
has filed a counterclaim against the Company seeking actual damages of $75,000
and punitive damages of $100,000,000. The Company does not believe that the
ultimate resolution of these matters will have a material adverse effect on the
financial condition or results of operations of the Company.
There are various other lawsuits and claims against the Company, none of
which, in the opinion of management, will have a material adverse effect on the
Company.
Note 10. Commitments and Contingencies
In January 1995, an Agreed Order with the Texas Natural Resource Conservation
Commission was signed by the Company with respect to alleged violations of rules
regarding the permitting and storage of hazardous wastes at a facility that was
previously owned by the Company. Penalties totaling $26,000 were assessed and
paid by the Company. During 1995 and 1994, the Company incurred costs of
$28,000 and $213,000, respectively, related to remediation and disposal of the
hazardous wastes. Additional testing and monitoring of the groundwater and
formal approval of the remediation work is still required. The Company has
completed the remediation work related to hazardous waste storage rule
violations. The new owner of the facility has accepted responsibility for the
first $100,000 of costs related to additional testing, monitoring and
remediation, if necessary, of the groundwater. Should the costs for these
activities exceed $100,000, the Company could be responsible for some portion of
the additional costs. The Company does not believe that this matter will have a
material adverse effect on the financial condition or results of operations of
the Company.
The Channelview facility is discharging wastewater pursuant to a state
wastewater discharge permit. Industries located in the state of Texas are
required to obtain wastewater discharge permits from the state and from the
Environmental Protection Agency ("EPA"). When the Company purchased the
Channelview facility in 1988, it requested and obtained a transfer of these
permits. In 1990, the Company applied for a renewal of both the federal and the
state wastewater permits. The state permit was reissued in 1992. During 1993,
the Company determined that the federal wastewater discharge permit may have
expired prior to the EPA's transfer of the permit to the Company. The EPA has
been contacted to resolve this issue, and the Company will be negotiating to
obtain a renewed permit. Penalties may potentially be imposed upon the Company
as a result of this matter; however, until this matter is resolved, the amount
of such penalties, if any, cannot be quantified. While penalties may be
material and the actions of regulatory bodies are not subject to accurate
prediction, based on information currently available to the Company and on the
circumstances present at its Channelview facility (including the existence of
the state permit, the Company's compliance with the more stringent state permit
and the ability, if required, to operate the Channelview facility utilizing
holding tanks and offsite third party treatment facilities in the absence of a
permit), the Company does not believe that this matter will have a material
adverse effect on the financial condition or results of operations of the
Company.
The Company occupies office and operational facilities and uses equipment
under operating lease arrangements. Expense of these arrangements amounted to
$2,201,000 in 1995, $2,078,000 in 1994 and $1,729,000 in 1993. At December 31,
1995, long-term commitments for lease of facilities and equipment totaled
approximately $11,583,000, consisting of $2,752,000, $1,913,000, $1,689,000,
$1,609,000 and $736,000 for the years 1996 through 2000, respectively, and
$2,884,000 thereafter.
HOWELL CORPORATION AND SUBSIDIARIES
Supplemental Schedule of
Property, Plant and Equipment
Balance Transfers
at and Balance
Beginning Additions Retirements Other at End
Classification of Year at Cost and Sales Adjustments of Year
-------- --------- ---------- ----------- -------
(In thousands)
Year ended December 31, 1993:
Land $ 488 $ - $ - $ - $ 488
Technical fuels and chemical
processing facilities 21,149 - 21 806 21,934
Construction in progress 30 2,423 - (492) 1,961
Transportation equipment 2,130 282 70 (178) 2,164
Other facilities and equipment 4,057 637 93 68 4,669
Oil and gas properties 241,156 17,509 2,438 - 256,227
Fee mineral interests - 18,260 - - 18,260
Crude oil pipelines 1,300 - - - 1,300
-------- ------- ------ ------ --------
Total $270,310 $39,111 $2,622 $ 204 $307,003
======== ======= ====== ====== ========
Year ended December 31, 1994:
Land $ 488 $ 16 $ - $ - $ 504
Technical fuels and chemical
processing facilities 21,934 - 26 3,097 25,005
Construction in progress 1,961 1,345 - (3,097) 209
Transportation equipment 2,164 1,312 277 (95) 3,104
Other facilities and equipment 4,669 1,129 1,178 95 4,715
Oil and gas properties 256,227 9,603 1,463 63 264,430
Fee mineral interests 18,260 3 - (63) 18,200
Crude oil pipelines 1,300 - - - 1,300
-------- ------- ------ ------ --------
Total $307,003 $13,408 $2,944 $ - $317,467
======== ======= ====== ====== ========
Year ended December 31, 1995:
Land $ 504 $ 2,109 $ - $ - $ 2,613
Technical fuels and chemical
processing facilities 25,005 - 45 817 25,777
Construction in progress 209 2,276 - (817) 1,668
Transportation equipment 3,104 2,119 243 - 4,980
Other facilities and equipment 4,715 739 147 - 5,307
Oil and gas properties 264,430 14,949 886 12 278,505
Fee mineral interests 18,200 - - (12) 18,188
Crude oil pipelines 1,300 66,090 - - 67,390
-------- ------- ------ ------ --------
Total $317,467 $88,282 $1,321 $ - $404,428
======== ======= ====== ====== ========
HOWELL CORPORATION AND SUBSIDIARIES
Supplemental Schedule of
Accumulated Depreciation, Depletion and
Amortization of Property, Plant and Equipment
Balance Transfers
at and Balance
Beginning Additions Retirements Other at End
Classification of Year at Cost and Sales Adjustments of Year
-------- --------- ---------- ----------- -------
(In thousands)
Year ended December 31, 1993:
Technical fuels and chemical
processing facilities $ 5,777 $ 1,851 $ 21 $123 $ 7,730
Transportation equipment 929 223 65 (42) 1,045
Other facilities and equipment 2,576 411 75 123 3,035
Oil and gas properties 161,640 8,483 981 - 169,142
Crude oil pipelines 836 102 - - 938
-------- ------- ------ ---- --------
Total $171,758 $11,070 $1,142 $204 $181,890
======== ======= ====== ==== ========
Year ended December 31, 1994:
Technical fuels and chemical
processing facilities $ 7,730 $ 2,024 $ 26 $ - $ 9,728
Transportation equipment 1,045 357 46 (65) 1,291
Other facilities and equipment 3,035 558 1,170 65 2,488
Oil and gas properties 169,142 9,282 277 - 178,147
Crude oil pipelines 938 102 - - 1,040
-------- ------- ------ ---- --------
Total $181,890 $12,323 $1,519 $ - $192,694
======== ======= ====== ==== ========
Year ended December 31, 1995:
Technical fuels and chemical
processing facilities $ 9,728 $ 2,152 $ 45 $ - $ 11,835
Transportation equipment 1,291 471 146 - 1,616
Other facilities and equipment 2,488 712 101 - 3,099
Oil and gas properties 178,147 10,259 (566) - 188,972
Crude oil pipelines 1,040 2,525 - - 3,565
-------- ------- ------ ---- --------
Total $192,694 $16,119 $(274) $ - $209,087
======== ======= ====== ==== ========
HOWELL CORPORATION AND SUBSIDIARIES
Form 10-K
Index to Exhibits
Exhibits not incorporated herein by reference to a prior filing are designated
by an asterisk (*) and are filed herewith. Exhibits designated by two asterisks
(**) are incorporated herein by reference to the Company's Form S-1 Registration
Statement, registration No. 33-59338, filed on March 10, 1993.
Exhibit
Number Description
- - - ------ -----------
3.1 ** Certificate of Incorporation, as amended, of the Company.
3.1(a) Certificate of Amendment to the Certificate of Incorporation of the
Company (filed as an exhibit to the Company's Report on Form 10-Q for
the quarterly period ended June 30, 1994).
3.2 ** By-laws of the Company.
10.1 ** Howell Corporation 1988 Stock Option Plan.
10.2 ** First Amendment to the Howell Corporation 1988 Stock Option Plan.
10.3 ** Second Amendment to the Howell Corporation 1988 Stock Option Plan.
10.4 ** Form of Stock Option Agreement.
10.5 Third Amendment to the Howell Corporation Stock Option Plan
(filed as an Exhibit to the Company's Report on Form 10-Q for the
quarterly period ended June 30, 1994).
10.6 ** Form of Indemnity Agreement by and between the Company and each of its
directors and executive officers.
10.7 Credit Agreement Among Howell Petroleum Corporation, as Borrower,
Bank One, Texas, N.A. as Agent and as a Lender, Bank of Montreal, as a
Lender, Compass Bank - Houston as a Lender and Den norske Bank AS, as
a Lender, dated as of March 31, 1995 (filed as an Exhibit to the
Company's Report on Form 10-Q for the quarterly period ended March 31,
1995).
10.8 Guaranty by Howell Corporation in Favor of Bank One, Texas,
National Association, as Agent, dated as of March 31, 1995 - Credit
Facility to Howell Petroleum Corporation (filed as an Exhibit to the
Company's Report on Form 10-Q for the quarterly period ended March 31,
1995).
10.9 Credit Agreement Among Howell Crude Oil Company, as Borrower,
Bank One, Texas, N.A. as Agent and as a Lender, Bank of Montreal, as a
Lender, Compass Bank - Houston as a Lender and Den norske Bank AS, as
a Lender, dated as of March 31, 1995 (filed as an Exhibit to the
Company's Report on Form 10-Q for the quarterly period ended March 31,
1995).
10.10 Guaranty by Howell Corporation in Favor of Bank One, Texas, National
Association, as Agent, dated as of March 31, 1995 - Credit Facility to
Howell Crude Oil Company (filed as an Exhibit to the Company's Report
on Form 10-Q for the quarterly period ended March 31, 1995).
10.11 Guaranty by Howell Pipeline Texas, Inc., in Favor of Bank One, Texas,
National Association, as Agent, dated as of March 3,1 1995 - Credit
Facility to Howell Crude Oil Company (filed as an Exhibit to the
Company's Report on Form 10-Q for the quarterly period ended March 31,
1995).
10.12 Guaranty by Howell Pipeline USA, Inc. in Favor of Bank One, Texas,
National Association, as Agent, dated as of March 31, 1995 - Credit
Facility to Howell Crude Oil Company (filed as an Exhibit to the
Company's Report on Form 10-Q for the quarterly period ended March 31,
1995).
10.13 ** Split Dollar Life Insurance Agreement dated January 27, 1990 between
the Company, Steven K. Howell, Douglas W. Howell, David L. Howell,
Bradley N. Howell and Charles W. Hall, Trustee of the Howell 1990
Children's Trusts.
10.14 ** Deferred Compensation and Salary Continuation Agreement dated January
23, 1990 by and between the Company and Paul N. Howell.
10.15 ** United States of America Department of Energy Economic Regulatory
Administration Consent Order with the Company dated as of February 23,
1989.
10.16 ** Letter from the Department of Energy to the Company dated September
10, 1992 modifying the terms of the Consent Order.
10.19 ** United States Department of the Interior Bureau of Land Management Oil
and Gas Lease of Submerged Lands under the Outer Continental Shelf
Land Act by and between the United States of America and Howell
Petroleum Corporation effective as of December 1, 1981.
10.20 ** United States Department of the Interior Minerals Management Service
Oil and Gas Lease of Submerged Lands under the Outer Continental Shelf
Lands Act by and between the United States of America and Total
Petroleum, Inc., effective as of July 1, 1983.
10.21 ** Assignment, Bill of Sale and conveyance by Total Petroleum, Inc., as
assignor, to Oil Acquisitions, Inc., dated January 19, 1989.
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.
10.28* Second Amendment to Lease Agreement by and between Texas Commerce Bank
National Association and Howell Corporation effective as of November
21, 1995.
11 * Computation of Earnings per Share.
21 * Subsidiaries of the Company.
23 * Consent of Deloitte & Touche LLP.