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 September 30, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______________ to _________________
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Commission file number: 0-10990
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CASTLE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 76-0035225
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
One Radnor Corporate Center
Suite 250, 100 Matsonford Road
Radnor, Pennsylvania 19087
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number: (610) 995-9400
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: Common
Stock -- $.50 par value and related Rights
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X].
As of November 20, 1998, there were 2,940,729 shares of the
registrant's Common Stock ($.50 par value) outstanding. The aggregate market
value of voting stock held by non-affiliates of the registrant as of such date
was $46,555,086 (2,418,446 shares at $19.25 per share).
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Proxy Statement for the 1999 Annual Meeting of
Stockholders are incorporated by reference in Items 10, 11, 12 and 13
CASTLE ENERGY CORPORATION
1998 FORM 10-K
TABLE OF CONTENTS
Item Page
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PART I
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1. and 2. Business and Properties......................................... 1
3. Legal Proceedings...................................................... 7
4. Submission of Matters to a Vote of Security Holders.................... 9
PART II
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5. Market for the Registrant's Common Equity and Related
Stockholder Matters................................................. 10
6. Selected Financial Data............................................... 11
7. Management's Discussion and Analysis of Financial Condition and
Results of Operations............................................... 13
8. Financial Statements and Supplementary Data........................... 28
PART III
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9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure................................................ 59
10. Directors and Executive Officers of the Registrant.................... 59
11. Executive Compensation................................................ 59
12. Security Ownership of Certain Beneficial Owners and Management........ 59
13. Certain Relationships and Related Transactions........................ 59
PART IV
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14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K...... 60
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
INTRODUCTION
Castle Energy Corporation (the "Company") is engaged in natural gas
marketing and oil and gas exploration and production in the United States.
References to the Company mean Castle Energy Corporation, the parent, and its
subsidiaries. Such references are for convenience only and are not intended to
describe legal relationships. During the period from August of 1989 through
September 30, 1995, the Company, through certain subsidiaries, was primarily
engaged in petroleum refining. Indian Refining I Limited Partnership (formerly
Indian Refining Limited Partnership) ("IRLP"), an indirect wholly-owned
subsidiary limited partnership of the Company, owned the Indian Refinery, an
86,000 barrel per day (B/D) refinery located in Lawrenceville, Illinois.
Powerine Oil Company ("Powerine"), a former indirect wholly-owned subsidiary of
the Company, owned and operated a 49,500 B/D refinery located in Santa Fe
Springs, California. By September 30, 1995, the Company's refining subsidiaries
had terminated and discontinued all of their refining operations.
The Company engages in natural gas marketing operations which provide
gas to Lone Star Gas Company ("Lone Star"), a division of Texas Utilities Mining
Company ("TUMCO"), pursuant to an essentially fixed price take-or-pay contract
for natural gas through May 31, 1999 ("Lone Star Contract"). At September 30,
1998 approximately 12.5 billion cubic feet of natural gas remained to be sold to
Lone Star. The Company has a fixed price gas purchase contract in place for
substantially all of the supply of natural gas necessary to fulfill its
commitments under the Lone Star Contract and, accordingly, has essentially fixed
its gross margin with respect to the Lone Star Contract. The Company delivers
natural gas to Lone Star through a 77-mile intrastate pipeline located in Rusk
County, Texas. The pipeline is owned by Union Pacific Intrastate Pipeline
Company ("UPIPC"), a wholly-owned subsidiary of Union Pacific Resources Company
("UPRC"). The Company's gas marketing subsidiary has a gas transportation
contract with UPIPC for the transportation of the gas sales volumes remaining
under the Lone Star Contract. The pipeline was previously owned by the Company
but was sold to UPIPC in May 1997.
In addition to the Lone Star Contract, the Company entered into a
contract to sell 7,356,000 MMbtu's (million British thermal units) of natural
gas to MG Natural Gas Corp. ("MGNG") at a fixed price from June 1, 1996 to May
31, 1999. MGNG is a subsidiary of Metallgesellschaft Corp. ("MG"), a
wholly-owned subsidiary of Metallgesellschaft A.G., a German conglomerate.
In addition to its natural gas marketing operations, the Company,
through its subsidiaries, conducts oil and gas exploration and production
operations. As of September 30, 1998, the Company's exploration and production
subsidiaries owned interests in 392 producing oil and gas wells located in eight
states. The subsidiaries operate most of the wells. At September 30, 1998, the
Company's exploration and production assets included proved reserves of 15.3
billion cubic feet of natural gas and 255,000 barrels of oil.
During the period from September 1989 to October 14, 1994, a significant
but minority portion of the Company's stock was owned by MG. During this period,
MG provided financing and crude supplies to IRLP and Powerine and entered into
processing and product offtake agreements with them. In December 1993, it was
reported that MG AG had incurred substantial losses as a result of hedging and
other related activities. Thereafter, MG sought to terminate its on-going
relationships with the Company. In October 1994, the Company and MG completed
the restructuring of such relationships ("MG Settlement"). As a result,
substantially all of the Company's contractual relationships with MG and its
affiliates were amended or terminated. Subsequent to the MG Settlement, the
Company's subsidiaries sought to dispose of their two refineries. Operations at
the Powerine Refinery ceased in July 1995 and operations at the Indian Refinery
ceased by September 30, 1995. On September 29, 1995, Powerine sold the Powerine
Refinery to Kenyen Projects Limited ("Kenyen"). On January 16, 1996, Powerine
merged into a subsidiary of Energy Merchant Corp. ("EMC"). On December 12, 1995,
IRLP sold the Indian Refinery to American Western Refining L.P. ("American
Western"), a subsidiary of Gadgil Western Corporation ("Gadgil"). For accounting
purposes, refining operations were classified as discontinued operations in the
Company's Consolidated Financial Statements as of September 30, 1995 (see Note 3
to the consolidated financial statements included in Item 8 to this Form 10-K).
See Note 20 to the Company's Consolidated Financial Statements for
information with respect to the Company's identifiable business segments for the
years ended September 30, 1998, 1997 and 1996.
-1-
On May 30, 1997, the Company consummated the sale of its Texas oil and
gas properties and pipeline to UPRC and UPIPC, respectively. The effective date
of the sale was May 1, 1997. The assets sold included approximately 8,150 net
acres, 100 producing oil and gas wells and a 77-mile pipeline which gathers gas
from the producing wells and delivers it to a pipeline owned by Lone Star. The
proved reserves associated with the oil and gas properties that were sold
comprised approximately 84% of the Company's proved reserves. The Company still
owns its non-Texas oil and gas properties and its gas sales contract with Lone
Star.
In October 1996 the Company commenced a program to repurchase shares of
its common stock at stock prices beneficial to the Company. At November 20,
1998, 3,862,917 shares had been repurchased and the Company's Board of Directors
had authorized the purchase of up to 387,083 additional shares.
NATURAL GAS MARKETING
General
On December 3, 1992, the Company, through three wholly-owned subsidiary
limited partnerships, CEC Gas Marketing Limited Partnership ("Marketing"),
Castle Texas Pipeline Limited Partnership ("Pipeline") and Castle Texas
Production Limited Partnership ("Production"), acquired from Atlantic Richfield
Company ("ARCO"), a gas contract with Lone Star, a 77-mile pipeline in Rusk
County, Texas (the "Castle Pipeline"), majority working interests in
approximately 100 producing oil and gas wells and several gas supply contracts
for an aggregate purchase price of approximately $103.7 million, including cash,
assumption of debt and certain transaction costs. Upon acquiring these assets,
the Company entered a new segment of the petroleum business, natural gas
marketing and transmission.
Assets
Gas Contract
Pursuant to the terms of the Lone Star Contract, Marketing sells natural
gas to Lone Star at a fixed price per million British thermal units ("MMBtu"),
plus transportation and severance tax reimbursement. The Lone Star Contract,
which expires on May 31, 1999, provides for minimum average deliveries of 45
million cubic feet per day through May 31, 1999. The contract also includes
take-or-pay provisions whereby Lone Star must pay for 60% of the monthly
contract volume and 100% of the annual contract volume whether or not it takes
such volumes (although deficiencies in one month or in one year may, subject to
certain limitations, be taken in subsequent months or years without additional
payments). Pursuant to a gas purchase contract between Marketing and MGNG, MGNG
is supplying essentially all of the natural gas required to meet the
requirements of the Lone Star Contract at fixed prices. None of the Company's
own gas production is supplied to the Lone Star Contract. All of the gas sold to
Lone Star is delivered through a 77-mile pipeline in Rusk County, Texas. The
pipeline is now owned by UPIPC. As part of the sale of the pipeline to UPIPC
(see above), Marketing entered into a gas transportation contract whereby UPIPC
agreed to transport all of the gas remaining to be delivered under the Lone Star
Contract. The transportation costs for such transportation were prepaid as part
of the sale to UPIPC.
The fixed price received by Marketing for gas sold to Lone Star has been
substantially in excess of the spot (market) price during virtually all of the
term of the Lone Star Contract from December 3, 1992, the date acquired, through
September 30, 1998 and also through November 20, 1998. The fixed price also
exceeds the fixed price of gas purchased from MGNG for the Lone Star Contract.
As a result, Marketing has substantially locked in a gross margin equal to the
excess of the price received from Lone Star over the price paid to MGNG. Such
"locked in" gross margins are, however, subject to the supply risk of MGNG, the
credit risk of Lone Star and other contractual risks in the Lone Star Contract
and the gas supply contract with MGNG.
In September 1993, Production entered into a contract to sell 7,356,000
MMBtu's of gas to MGNG. The gas is to be provided to MGNG ratably from June 1,
1996 through May 31, 1999 at a fixed price. Production is buying the gas to be
sold to MGNG on the spot market and from MGNG. Production has hedged all of the
remaining gas to be sold to MGNG at a price in excess of the fixed price it
receives from MGNG. During fiscal 1998, the sales price received from MGNG was
significantly less than the cost of the gas sold to MGNG, net of hedging
adjustments.
-2-
OIL AND GAS EXPLORATION AND PRODUCTION
General
The Company's oil and gas exploration and production business is
currently conducted through Castle Exploration Company, Inc. ("CECI"), a
wholly-owned subsidiary, and Petroleum Reserve Corporation ("PRC"), a division
of the Company, and includes interests in 392 producing oil and gas wells
located in eight states. From December 3, 1992 to May 30, 1997 Production, the
Company's other wholly-owned exploration and production subsidiary, owned and
operated approximately 115 oil and gas wells in Rusk County, Texas. On May 30,
1997, Production sold these wells and related undrilled acreage to UPRC. As a
result, production from these wells is included in the data below only through
May 30, 1997 and proved oil and gas reserves related to these wells and related
acreage are excluded from Company reserve and acreage data as of September 30,
1998 and 1997.
Properties
Proved Oil and Gas Reserves
The following is a summary of the Company's oil and gas reserves as of
September 30, 1998. All estimates of reserves are based upon engineering
evaluations prepared by Huntley & Huntley, independent petroleum reservoir
engineers, in accordance with the requirements of the Securities and Exchange
Commission. Such estimates include only proved reserves. The Company reports its
reserves annually to the Department of Energy. The Company's estimated reserves
as of September 30, 1998 are as follows:
Net MCF (1) of gas:
Proved developed producing.................................... 12,733,000
Proved developed non-producing................................ 856,000
Proved undeveloped............................................ 1,735,000
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Total......................................................... 15,324,000
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Net barrels of oil:
Proved developed producing.................................... 162,000
Proved developed non-producing................................
Proved undeveloped............................................ 93,000
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Total......................................................... 255,000
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(1) Thousand cubic feet
Oil and Gas Production
The following table summarizes the net quantities of oil and gas
production of the Company for each of the three fiscal years in the period ended
September 30, 1998, including production from acquired properties since the date
of acquisition.
Fiscal Year Ended September 30,
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1998 1997 1996
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Oil -- Bbls (barrels)................... 20,000 36,000 46,000
Gas -- MCF.............................. 869,000 2,454,000 3,349,000
-3-
Average Sales Price and Production Cost Per Unit
The following table sets forth the average sales price per barrel of oil
and MCF of gas produced by the Company and the average production cost (lifting
cost) per equivalent unit of production for the periods indicated. Production
costs include applicable operating costs and maintenance costs of support
equipment and facilities, labor, repairs, severance taxes, property taxes,
insurance, materials, supplies and fuel consumed in operating the wells and
related equipment and facilities.
Fiscal Year Ended September 30,
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1998 1997 1996
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Average Sales Price per Barrel of Oil..................... $15.46 $19.94 $17.33
Average Sales Price per MCF of Gas........................ $ 2.38 $ 2.46 $ 2.38
Average Production Cost per Equivalent MCF(1)............. $ 0.78 $ .73 $ 0.56
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(1) For purposes of equivalency of units, a barrel of oil is assumed equal to
six MCF of gas, based upon relative energy content.
Approximately 55% and 75% of gas volumes sold during the fiscal years
ended September 30, 1997 and 1996, respectively, were sold to Lone Star to
partially provide the volumes needed for the Lone Star Contract. After the sale
of the Texas oil and gas properties to UPRC in May 1997, none of the Company's
remaining gas production was sold to Lone Star.
Productive Wells and Acreage
The following table presents the oil and gas properties in which the
Company held an interest as of September 30, 1998. The wells and acreage owned
by the Company and its subsidiaries are located primarily in Alabama,
California, Illinois, Louisiana, Mississippi, New Mexico, Oklahoma and
Pennsylvania.
As of
September 30, 1998
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Gross(2) Net (3)
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Productive Wells:(1)
Gas Wells.......................................... 353 134
Oil Wells.......................................... 23 6
Acreage:
Developed Acreage.................................. 58,720 15,023
Undeveloped Acreage................................ 24,200 12,650
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(1) A "productive well" is a producing well or a well capable of production.
Forty-eight wells are dual wells producing oil and gas. Such wells are
classified according to the dominant mineral being produced.
(2) A gross well or acre is a well or acre in which a working interest is owned.
The number of gross wells is the total number of wells in which a working
interest is owned.
(3) A net well or acre is deemed to exist when the sum of fractional working
interests owned in gross wells or acres equals one. The number of net wells
or acres is the sum of the fractional working interests owned in gross wells
or acres.
Drilling Activity
The table below sets forth for each of the three fiscal years in the
period ended September 30, 1998 the number of gross and net productive and dry
developmental wells drilled including wells drilled on acquired properties since
the dates of acquisition. No exploratory wells were drilled during the periods
presented.
-4-
Fiscal Year Ended September 30,
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1998 1997 1996
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Productive Dry Productive Dry Productive Dry
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Developmental:
Gross.................................. 23.0 -- 3.0 -- -- --
Net.................................... 15.2 -- 1.4 -- -- --
The Company is currently concluding a ten well drilling program on its
undrilled Alabama coalbed methane acreage and has participated in drilling
twelve wells in Pennsylvania as part of a joint venture to drill up to 100 wells
in Pennsylvania over the next 3-5 years.
REFINING
Until September 30, 1995, two of the Company's subsidiaries operated in
the refining segment of the petroleum industry. The two subsidiaries owned and
operated refineries with a combined refining (distillation) capacity of 135,500
barrels per day. IRLP owned and operated the Indian Refinery in Lawrenceville,
Illinois and Powerine owned and operated the Powerine Refinery in Santa Fe
Springs, California. On September 29, 1995, Powerine sold the Powerine Refinery
to Kenyen. On December 12, 1995, IRLP sold the Indian Refinery to American
Western. In addition, Powerine merged into a subsidiary of EMC on January 16,
1996 and is no longer a subsidiary of the Company. The Company still owns IRLP,
which is inactive and owns no refining assets.
As a result of the foregoing, refining operations were classified as
discontinued operations in the Company's financial statements as of September
30, 1995 and retroactively.
REGULATIONS
Since the Company's subsidiaries have disposed of their refineries and
third parties have assumed environmental liabilities associated with the
refineries, the Company's current activities are not subject to environmental
regulations that generally pertain to refineries, e.g., the generation,
treatment, storage, transportation and disposal of hazardous wastes, the
discharge of pollutants into the air and water and other environmental laws.
Nevertheless, the Company has some contingent environmental exposures. See Items
3 and 7 to this Form 10-K and Note 13 to the financial statements.
The oil and gas exploration and production operations of the Company are
subject to a number of local, state and federal environmental laws and
regulations. To date, compliance with such regulations by the Company's natural
gas marketing and transmission and exploration and production segments has not
resulted in material expenditures.
All states in which the Company conducts oil and gas exploration and
production activities have laws regulating the production and sale of oil and
gas. Such laws and regulations generally are intended to prevent waste of oil
and gas and to protect correlative rights and opportunities to produce oil and
gas as between owners of interests in a common reservoir. Some state regulatory
authorities also regulate the amount of oil and gas produced by assigning
allowable rates of production to each well or unit. Most states also have
regulations requiring permits for the drilling of wells and regulations
governing the method of drilling, casing and operating wells, the surface use
and restoration of properties upon which wells are drilled and the plugging and
abandonment of wells. Recently there has been a significant increase in the
amount of state regulation, including increased bonding, plugging and
operational requirements. Such increased state regulation has resulted in, and
is anticipated to continue to result in, increased legal and compliance costs
being incurred by the Company. Based on past costs and even considering recent
increases, management of the Company does not believe such legal and compliance
costs will have a material adverse effect on the financial condition or results
of operations of the Company.
-5-
EMPLOYEES AND OFFICE FACILITIES
As of November 20, 1998, the Company, through its subsidiaries, employed
21 personnel. Until June 30, 1998, the Company outsourced all of its
administrative, land and accounting functions. Effective July 1, 1998, the
Company exercised its option to acquire the computer equipment and software of
the company providing the outsourcing services and also hired most of that
company's employees. As a result the Company now performs all administrative,
land and accounting functions in-house.
The Company leases certain offices as follows:
Office Location Function
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Radnor, PA Corporate Headquarters
Plymouth Meeting, PA Accounting Office
Mt. Pleasant, PA Oil and Gas Production Office
Pittsburgh, PA Drilling and Exploration Office
Tuscaloosa, Alabama Gas Production Office
-6-
ITEM 3. LEGAL PROCEEDINGS
Contingent Environmental Liabilities - Refining
Until September 30, 1995, the Company, through its subsidiaries,
operated in the refining segment of the petroleum business. As operators of
refineries, certain of the Company's subsidiaries were potentially liable for
environmental costs related to air emissions, ground and water contamination,
hazardous waste disposal and third party claims related to the foregoing.
Between September 29, 1995 and December 12, 1995 both of the refineries owned by
the Company's refining subsidiaries were sold to outside parties. In each case
the purchaser assumed all environmental liabilities. Furthermore, on January 16,
1996, Powerine, the subsidiary that previously owned the Powerine Refinery, was
effectively acquired by EMC, an unrelated party.
As of November 20, 1998, neither of the refineries had restarted. The
Powerine Refinery has recently been sold to an unrelated party, which, the
Company has been informed, is seeking financing to restart that Refinery. The
purchaser of the Indian Refinery, American Western, defaulted on its $5 million
note to IRLP, filed a voluntary petition for bankruptcy in the United States
Bankruptcy Court in the District of Delaware under Chapter 11 of the United
States Bankruptcy Code and sold the Indian Refinery to another unrelated party.
The new owner is in the process of dismantling much of the Indian Refinery.
During fiscal 1998, the Company was also informed that the United States
Environmental Protection Agency ("EPA") was investigating offsite acid sludge
waste found near the Indian Refinery and was also investigating and remediating
surface contamination in the Indian Refinery property. Neither the Company nor
IRLP was named with respect to these two actions.
In October 1998, the EPA named the Company and two of its subsidiaries
as potentially responsible parties for the expected overall clean-up of the
Indian Refinery. In addition, eighteen other parties were named including Texaco
Refining and Marketing, Inc., the refinery operator for over 50 years. The
Company subsequently responded to the EPA indicating that it was neither the
owner nor operator of the Indian Refinery and thus not responsible for its
remediation. Estimated undiscounted clean-up costs for the Indian Refinery are
$80,000,000 to $150,000,000 according to third parties. Although the Company
does not believe it has any liabilities with respect to the environmental
liabilities of the refineries, a court of competent jurisdiction may find
otherwise. A recent decision by the U.S. Supreme Court supports the Company's
position.
In September 1995, Powerine sold the Powerine Refinery to EMC. In
January 1996, Powerine merged into a subsidiary of EMC and EMC assumed all
environmental liabilities. In July of 1996, the Company was named a defendant in
a class action lawsuit concerning emissions from the Powerine Refinery. In April
of 1997, the court granted the Company's motion to quash the plaintiff's
complaint based upon lack of jurisdiction and the Company is no longer involved
in the case. In August 1998, EMC sold the Powerine Refinery to an unrelated
party which, the Company understands, is currently seeking financing to restart
the Powerine Refinery.
Although the environmental liabilities related to the Indian Refinery
and Powerine Refinery have been transferred to others, there can be no assurance
that the parties assuming such liabilities will be able to pay them. American
Western, purchaser of the Indian Refinery, filed for bankruptcy and is in the
process of liquidation. The current owner of the Powerine Refinery is still
seeking financing to restart the refinery. Furthermore, the Company and two of
its subsidiaries have been named as potentially responsible parties by the U.S.
Environmental Protection Agency.
If funds for environmental clean-up are not provided by these former
and/or present owners, it is possible that the Company and/or one of its former
refining subsidiaries could be named a party in additional legal actions to
recover remediation costs. In recent years, government and other plaintiffs have
often sought redress for environmental liabilities from the party most capable
of payment without regard to responsibility or fault. Whether or not the Company
ultimately prevails in such a circumstance, should litigation involving the
Company, IRLP or Powerine occur, the Company would probably incur substantial
legal fees and experience a diversion of management resources from other
operations.
Although the Company does not believe it is liable for any of its
subsidiaries' clean-up costs and intends to vigorously defend itself in such
regard, the Company cannot predict the ultimate outcome of these matters.
-7-
General
Powerine Arbitration
In June 1997, an arbitrator ruled in the Company's favor in an
arbitration hearing concerning a contract dispute between MGNG and Powerine
which had been assigned to the Company. In October 1997, the Company recovered
$8,700,000 from the arbitration. The Company believes it is entitled to an
additional $2,142,000 plus interest and its special legal counsel presented
arguments to the arbitrator to recover this amount. On January 27, 1998, the
arbitrator ruled against the Company. The Company is currently pursuing other
measures to recover the $2,142,000 plus interest.
SWAP Agreement - MGNG
In January 1998, IRLP filed suit against MG Refining and Marketing, Inc.
("MGR&M"), a subsidiary of MG, to collect $704,000 plus interest. The dispute
concerns funds belonging to IRLP but received and held by MGR&M. In February
1998, MG contended that the $704,000 is not owed to IRLP and that it had
liquidated MGR&M. Management and special counsel believe that IRLP has a strong
breach of contract claim against MGR&M and that MG's counterclaims are not
supported by the facts or Delaware law. Discovery related to the lawsuit is
commencing. IRLP intends to file an amended complaint and pursue all other
available legal remedies in the near future.
MGNG Litigation
On May 4, 1998, Production filed a lawsuit against MGNG and MG Gathering
Company ("MGC"), two subsidiaries of MG, in the district court of Harris County,
Texas. Production seeks to recover gas measurement and transportation expenses
charged by the defendants in breach of a certain gas purchase contract. Improper
charges exceed $750,000 before interest. In October of 1998, MGNG and MGC filed
a suit in Harris County, Texas. This suit seeks indemnification from two of the
Company's subsidiaries in the event the Company's subsidiary wins the lawsuit
against MGNG and MGC. The MG entities have cited no basis for their claim of
indemnification. The management of the Company and special counsel believe that
the Company's subsidiary is entitled to at least $750,000 plus interest and that
the Company's two subsidiaries have no indemnification obligations to MGNG or
MGC. The Company intends to pursue this case using all legal remedies.
Larry Long Litigation
In May 1996, Larry Long, representing himself and allegedly "others
similarly situated," filed suit against the Company, three of the Company's
natural gas marketing and transmission and exploration and production
subsidiaries, ARCO, B&A Pipeline Company (a former subsidiary of ARCO), and MGNG
in the Fourth Judicial District Court of Rusk County, Texas. The plaintiff
originally claimed, among other things, that the defendants underpaid
non-operating working interest owners, royalty interest owners, and overriding
royalty interest owners with respect to gas sold to Lone Star pursuant to the
Lone Star Contract. Although no amount of actual damages was specified in the
plaintiff's initial pleadings, it appeared that, based upon the volumes of gas
sold to Lone Star, the plaintiff may have been seeking actual damages in excess
of $40 million.
After some initial discovery, the plaintiff's pleadings were
significantly amended. Another purported class representative, Travis Crim, was
added as a plaintiff, and ARCO, B&A Pipeline Company and MGNG were dropped as
defendants. Although it is not completely clear from the amended petition, the
plaintiffs have apparently now limited their proposed class of plaintiffs to
royalty owners and overriding royalty owners in leases owned by the Company's
exploration and production subsidiary limited partnership. In amending their
pleadings, the plaintiffs revised their basic claim to seeking royalties on
certain operating fees paid by Lone Star to the Company's natural gas marketing
subsidiary limited partnership. No hearing has been held on the plaintiffs'
request for class certification. After a lengthy period of inactivity the
plaintiff's counsel has only recently sought to continue or settle the case. The
case is still in its preliminary stages. No class has been certified and no
trial date set.
Based upon the revised pleadings, management of the Company initially
determined that the possible exposure of the Company and its subsidiary limited
partnerships for all gas sold to Lone Star in the past and in the future, were
they to lose the case on all points, was less than $3,000,000. However, the
Company sold all of its Rusk County oil and gas properties to Union Pacific
Resources Company ("UPRC") in May of 1997. The sale to UPRC effectively removed
any possibility of exposure by the Company or its subsidiary limited
partnerships to claims for additional royalties with respect to future
production, thus reducing the exposure of the Company and its subsidiaries to
less than $2,000,000 in actual damages if they were to lose the case on all
points.
-8-
EMC Litigation
In August 1998, the Company obtained a judgement against EMC for
$330,000 plus $57,000 interest. The judgement relates to EMC's failure to pay
third parties it was obligated to pay and which the Company had to pay in its
place. Subsequently EMC had the judgment vacated. The Company's management
believes it is entitled to the $330,000 plus $57,000 interest and that EMC is
engaging in legal tactics to avoid paying the Company. Legal counsel retained by
the Company is seeking to discover and attach EMC's assets and restore the
judgement against EMC.
Powerine Class Action Lawsuit
In July 1996, Powerine was served with a suit concerning operations of
the Powerine Refinery in the Superior Court of the State of California in Los
Angeles, California. The suit claims the Powerine Refinery is a public nuisance,
that it has released excessive toxic and noxious emissions and caused physical
and emotional distress and property damage affecting residents living nearby.
The Company was also named as a defendant in the suit. In March 1997, the
Company was served with the lawsuit. In April 1997, the Company filed a notion
to quash the plaintiffs' summons based upon the lack of jurisdiction. On May 2,
1997, the court granted the Company's motion. As a result, the Company is no
longer a defendant in the Powerine Class Action Lawsuit.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company did not hold a meeting of stockholders or otherwise submit
any matter to a vote of stockholders during the fourth quarter of fiscal 1998.
-9-
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
Principal Market
The Company's Common Stock is quoted on the Nasdaq National Market
("NNM") under the trading symbol "CECX."
Stock Price and Dividend Information
Stock Price:
The table below presents the high and low sales prices of the Company's
Common Stock as reported by the NNM for each of the quarters during the two
fiscal years ended September 30, 1998.
1998 1997
-------------------------- ------------------------
High Low High Low
------ ------ ------ -------
First Quarter (December 31)................................. $15.06 $12.75 $11.50 $ 6.63
Second Quarter (March 31)................................... $18.00 $13.50 $13.75 $10.25
Third Quarter (June 30)..................................... $20.63 $17.50 $13.75 $10.50
Fourth Quarter (September 30)............................... $19.69 $16.50 $15.25 $12.75
The final sale of the Company's Common Stock as reported by the NNM on
November 20, 1998 was at $19.25.
Dividends:
On June 30, 1997, the Company's Board of Directors adopted a policy of
paying regular quarterly cash dividends of $.15 per share on the Company's
common stock. Commencing July 15, 1997, dividends have been paid quarterly. As
with any company the declaration and payment of future dividends are subject to
the discretion of the Company's Board of Directors and will depend on various
factors.
Approximate Number of Holders of Common Stock
As of November 20, 1998, the Company's Common Stock was held by
approximately 3,000 stockholders.
-10-
ITEM 6. SELECTED FINANCIAL DATA
During the Company's five fiscal years ended September 30, 1998, the
Company consummated a number of transactions affecting the comparability of the
financial information set forth below. In August 1989, one of the Company's
subsidiaries acquired the Indian Refinery. From April 1990 until November 1990,
the Company's subsidiary , IRLP, performed refurbishment work on the Indian
Refinery and commenced operations in November 1990. In February 1992, IRLP
entered into a product offtake agreement with MGRM ("Indian Offtake Agreement")
which was restructured and extended in May 1993. In December 1992, the Company
acquired certain oil and gas and pipeline assets from ARCO. In October 1993, the
Company acquired Powerine, which owned the Powerine Refinery. During fiscal
1995, the Company reached a settlement with MG and its affiliates and terminated
most of its transactions and relationships with MG. By September 1995, the
Company had discontinued its refining operations. In May 1997, the Company sold
its Rusk County, Texas oil and gas properties and pipeline to UPRC and one of
its subsidiaries. See Item 7 - "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and Note 4 to the Company's
Consolidated Financial Statements included in Item 8 of this Form 10-K.
The following selected financial data have been derived from the
Consolidated Financial Statements of the Company for each of the five years
ended September 30, 1998. Certain information in the Consolidated Statements of
Operations has been reclassified to give effect to the discontinuance of
refining operations. The information should be read in conjunction with the
Consolidated Financial Statements and notes thereto included in Item 8 -
"Financial Statements and Supplementary Data" and Item 7 - "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
Earnings per share have been restated in accordance with SFAS 128 (see
Item 7).
For the Fiscal Years Ended September 30,
---------------------------------------------------------------------
(in Thousands, except per share amounts)
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
Revenues:
Natural gas marketing and transmission............. $70,001 $64,606 $59,471 $70,402 $61,259
Exploration and production......................... 2,603 7,113 9,224 9,197 8,552
Gross Margin:
Natural gas marketing and transmission............. 26,747 24,640 25,238 30,242 24,199
Exploration and production......................... 1,828 5,173 7,179 6,831 5,923
Earnings before interest, taxes, depreciation, and
amortization:
Natural gas marketing and transmission............. 25,162 23,054 23,162 28,252 22,003
Exploration and production......................... 836 4,036 5,944 5,761 4,494
Corporate general and administrative expenses.......... (3,081) (3,370) (3,499) (4,995) (5,499)
Depreciation, depletion and amortization............... (9,885) (12,250) (13,717) (14,155) (13,452)
Interest expense....................................... (2) (1,038) (1,959) (4,046) (9,233)
Interest income and other income....................... 2,230 21,097(1) 3,884 966 950
------- ------- -------- ------- -------
Income (loss) from continuing operations before
income taxes....................................... 15,260 31,529 13,815 11,783 (737)
Provision for (benefit of) income taxes related to
continuing operations.............................. 1,204 4,663 (11,259) 37,823 (17,077)
------- ------- ------- ------- -------
Income (loss) from continuing operations 14,056 26,866 25,074 (26,040) 16,340
Income from discontinued refining operations net of
applicable income taxes............................ 40,937 22,577
------- ------- ------- ------- -------
Net income............................................. $14,056 $26,866 $25,074 $14,897 $38,917
======= ======= ======= ======= =======
Dividends.............................................. $ 1,688 $ 1,446
======= =======
Net income (loss) per share (diluted):
Continuing operations.............................. $ 3.66 $ 4.64 $ 3.73 ($ 3.84) $ 1.46
Discontinued operations............................ 6.04 2.01
------- ------- ------- ------- -------
$ 3.66 $ 4.64 $ 3.73 $ 2.20 $ 3.47
======= ======= ======= ======= =======
Dividends per share.................................... $ .45 $ .30
======= =======
(Continued on next page)
- ------------------
(1)Incudes a $19,667 non-recurring gain on sale of assets.
-11-
September 30,
---------------------------------------------------------------------
(in Thousands)
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
Balance Sheet Data:
Working capital (deficit)........................... 40,271 $46,384 ($ 4,452) ($ 12,474) ($ 22,769)
Property, plant and equipment, net, including oil
and gas properties............................... 4,969 2,998 36,223 40,406 339,876
Total assets........................................ 67,004 82,717 101,230 116,904 646,491
Long-term debt, including current maturities........ 14,006 35,946 394,123
Stockholders' equity................................ 51,553 67,765 66,711 41,637 37,920
-12-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
("000's" Omitted Except Share Amounts)
- --------------------------------------------------------------------------------
RESULTS OF OPERATIONS
GENERAL
From August 1989 to September 30, 1995, one or more of the Company's
subsidiaries conducted refining operations. By December 12, 1995, the Company's
refining subsidiaries had sold all of their refining assets. In addition,
Powerine, one of the Company's refining subsidiaries, merged into a subsidiary
of EMC and was no longer a subsidiary of the Company. The Company's other
refining subsidiaries own no refining assets and are in the process of
liquidation. As a result, the Company has accounted for its refining operations
as discontinued operations in the Company's financial statements as of September
30, 1995 and retroactively. Accordingly, discussion of results of operations has
been confined to the results of continuing operations and the anticipated
impact, if any, of liquidation of the remaining inactive refining subsidiaries
and contingent environmental liabilities of the Company or its refining
subsidiaries, if any.
As noted above, the Company sold its Rusk County, Texas oil and gas
properties and pipeline to UPRC and UPIPC, respectively, in May 1997. The oil
and gas reserves sold approximated 84% of the Company's proved oil and gas
reserves at the date of sale. As a result operations applicable to the assets
sold impacted consolidated operations for twelve months in fiscal 1996, eight
months in fiscal 1997 and no months in fiscal 1998.
Fiscal 1998 vs Fiscal 1997
Natural Gas Marketing and Transmission
Gas sales from natural gas marketing increased $5,402 or 8.4% from
fiscal 1997 to 1998. Gas sales in each fiscal year consist of the following:
September 30,
----------------------------
1998 1997
---- ----
Gas sales to Lone Star...................... $64,619 $59,695
Gas sales to MGNG........................... 4,904 4,904
Gas sales to third parties.................. 478
------- -------
$70,001 $64,599
======= =======
Lone Star Contract
Natural gas sales under the Lone Star Contract increased $4,924 or 8.2%
from fiscal 1997 to fiscal 1998. Under the Company's long-term gas sales
contract with Lone Star, the price received for gas is essentially fixed through
May 31, 1999. The variance in gas sales, therefore, is almost entirely
attributable to the volumes of gas delivered. Although the volumes sold to Lone
Star annually are essentially fixed (the Lone Star Contract has a take-or-pay
provision), the Lone Star Contract year is from February 1 to January 31 whereas
the Company's fiscal year is from October 1 to September 30. Furthermore,
although the volumes to be taken by Lone Star in a given contract year are
fixed, there is no provision requiring equal monthly or daily volumes and
deliveries accordingly vary with Lone Star's seasonal and peak demands. Such
variances have been significant. As a result, Lone Star deliveries, although
fixed for a contract year, may be skewed and not proportional for the Company's
fiscal periods.
For fiscal 1998, sales to Lone Star were approximately $735 more than
those which would have resulted if daily deliveries had been fixed and equal. At
September 30, 1998, the remaining volumes to be delivered under the Lone Star
Contract were approximately 8.4% greater than those that would be delivered if
daily deliveries were fixed and equal. As a result, future revenues from the
Lone Star Contract are expected to be higher than those that would result if
remaining Lone Star deliveries were fixed and equal.
-13-
Gas sales to MGNG remained the same in fiscal 1998 as in fiscal 1997
because the gas sales contract with MGNG requires a fixed daily volume of gas at
a fixed price and the MGNG contract was in force for all of the periods being
compared.
Gas purchases increased $3,288 or 8.2% from fiscal 1997 to fiscal 1998.
Gas purchases in each of the fiscal years consist of the following:
September 30
--------------------------
1998 1997
---- ----
Gas purchases - Lone Star Contract.......... $36,898 $34,686
Gas purchases - MGNG Contract............... 5,897 5,280
Gas purchases - sales to third parties...... 459
------- -------
$43,254 $39,966
======= =======
Gas purchases for the Lone Star Contract increased $2,212 or 6.4% from
fiscal 1997 to fiscal 1998. For fiscal 1997 gas purchases comprised 58.1% of gas
sales versus 57.1% of gas sales for fiscal 1998. From 1997 to 1998 the gross
margin increased $2,712 or 10.8%. During the same periods the gross margin
percentage ((gas sales - gas purchases) as a percentage of gas sales) increased
1.0% from 41.9% for fiscal 1997 to 42.9% for fiscal 1998.
The decrease in gas purchases as a percentage of gas sales and the
concomitant increase in gross margin percentage for the Lone Star Contract
resulted primarily from non-recurring favorable adjustments of gas purchase
costs in fiscal 1998 and the replacement of high price gas contracts expiring in
April 1997 with lower market price contracts.
Gas purchases for the contract with MGNG increased $617 or 11.7% from
fiscal 1997 to fiscal 1998. The gas sales volumes sold to MGNG for each of the
two years being compared were equal; hence the increase is entirely attributable
to increased market prices for gas, net of hedging effects.
Gas purchased for third parties increased from zero in fiscal 1997 to
$459 in fiscal 1998. The gas sales to third parties in fiscal 1998 resulted
because Lone Star limited its daily gas purchases to 103% of volumes nominated
and the Company had to sell the excess gas elsewhere. The restriction of daily
sales to 103% of volumes nominated did not, however, affect annual volumes that
Lone Star was required to take under the Lone Star Contract.
In August 1998, the Company hedged all of its remaining unhedged gas
requirements. As a result of such hedging, the Company has fixed its price
exposure on its gas sales contract with MGNG through May 31, 1999, the
termination date for the contract.
Operating Costs
Operating costs decreased to a recovery of $16 for the year ended
September 30, 1998 from $472 for the year ended September 30, 1997 because the
Texas pipeline was sold to UPRC in May 1997 and as of June 1, 1997 the Company
no longer incurred operating costs to operate the Texas pipeline.
General and Administrative
General and administrative expenses decreased $714 from $776 for the
year ended September 30, 1997 to $62 for the year ended September 30, 1998. Most
general and administrative expenses incurred during the year ended September 30,
1997 related to the Texas pipeline, which was sold in May 1997. The remaining
administrative expenses consist primarily of consulting fees for on-going gas
marketing operations.
Transportation
Transportation expense increased $1,201 from $338 for the year ended
September 30, 1997 to $1,539 for the year ended September 30, 1998. During the
period October 1, 1996 to May 31, 1997, one of the Company's subsidiaries owned
and operated the Texas pipeline and all transportation revenues were for
intercompany transportation and were accordingly
-14-
eliminated in consolidation of the Company's financial statements. On May 30,
1997, the Company sold the Texas pipeline to UPIPC. In both 1997 and 1998,
transportation expense consisted entirely of the amortization of a $3,000
prepaid transportation asset. Amortization is based upon and thus proportional
to deliveries made to Lone Star. In fiscal 1997, four months' transportation
expense was recorded versus twelve months' transportation expense in fiscal
1998.
Depreciation and Amortization
Depreciation and amortization decreased $1,177 or 11.1% from fiscal 1997
fiscal 1998. The decrease is attributable to the sale of the Texas pipeline to
UPRC in May 1997. As a result of the sale, the Company no longer owned or
depreciated the Texas pipeline.
EXPLORATION AND PRODUCTION
As noted above, the Company sold its Texas oil and gas properties to
UPRC in May 1997. The reserves sold represented approximately 84% of the
Company's proved oil and gas reserves and 60%-65% of the Company's oil and gas
production at the time of sale. Comparison of fiscal 1998 oil and gas sales,
production expenses, general and administrative expenses and depletion,
depreciation and amortization to those in fiscal 1997 is thus not meaningful.
Accordingly, exploration and production operations comparisons and analysis have
been limited to operations from those oil and gas properties which were not sold
to UPRC. The related operating results for such properties are as follows:
Year Ended September 30,
------------------------
1998 1997
---- ----
Revenues:
Oil and gas sales......................... $2,373 $3,111
Well operations........................... 230 287
------ ------
2,603 3,398
------ ------
Expenses:
Oil and gas production.................... 775 528
General and administrative................ 992 745
Depreciation, depletion and
amortization............................ 423 653
------ ------
2,190 1,926
------ ------
Operating income............................... $ 413 $1,472
====== ======
Revenues
Oil and Gas Sales
Oil and gas sales decreased $738 or 23.7% from fiscal 1997 to fiscal
1998. The decrease is attributable to decreased oil and gas prices and decreased
production. Many of the Company's oil and gas reserves are mature reserves and
such decreased production is expected. Although the Company has participated in
drilling twenty-three new wells and several reworks on existing wells from July
1997 through September 30, 1998, production from such new drilling activities
has only recently begun impacting operations. The Company is currently
participating in two drilling programs and expects to participate in at least
ten additional new wells in fiscal 1999. The Company is also reviewing possible
investments in other oil and gas drilling programs and oil and gas property
acquisitions, including several requiring substantial investment. As a result,
the Company expects that, if it is successful in making acquisitions, its oil
and gas sales will eventually increase given stable oil and gas sales prices.
However, there can be no assurance that wells expected to be drilled will
actually be drilled, that such drilling will be successful or that the Company
will be successful in making acquisitions or that oil and gas sales will
increase.
Well Operations
Revenue from well operations decreased $57 or 19.9% from fiscal 1997 to
fiscal 1998. The decrease is attributable to the Company's resignation as
operator on certain Appalachian wells in fiscal 1997 where a non-operator
offered to operate the wells at a cost significantly less than that being
incurred by the Company in performing such operations. The related well
operations revenues were not replaced.
-15-
Expenses
Oil and Gas Production
Oil and gas production expenses increased $247 or 46.8% from fiscal
1997 to fiscal 1998. The increase in oil and gas production expenses results
from the general maturing of the Company's oil and gas properties and the
tendency for older, depleting properties to carry a higher production expense
burden than recently drilled properties. Furthermore, oil and gas production
expenses, especially non-capitalized repairs, do not generally occur evenly each
year and are best compared on a cumulative rather than on an annual basis. The
Company expects that, although oil and gas production expense will increase as a
result of its new drilling activities, such expenses will decline as a
percentage of oil and gas sales given the lower production costs typically
associated with new production. There can be no assurance, however, that such
will be the case.
General and Administrative
General and administrative costs increased $247 or 33.2% from fiscal
1997 to the fiscal 1998. The net increase was primarily attributable to higher
employee costs and bonuses, higher consulting fees and increased legal costs.
The increase was offset to a minor extent by tax refunds and vendor settlements
in fiscal 1998 for which there was no counterpart in fiscal 1997.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization decreased $230 or 35.2% from
fiscal 1997 to the fiscal 1998. The decrease is attributable to slightly
decreased production and significantly lower depletion rate per unit of
production. The lower depletion rate results primarily from the Company's sale
of 84% of its proved oil and gas reserves to UPRC.
OTHER INCOME (EXPENSE)
Gain on Sale of Assets
In May 1997, the Company's subsidiaries sold their Texas oil and gas
assets and pipeline to UPRC, resulting in a $19,667 gain. There was no
counterpart in fiscal 1998.
Interest Income
Interest income increased $786 or 52.9% from fiscal 1997 to fiscal 1998.
The increase is primarily attributable to an increase in the average balance of
invested unrestricted cash. For the year ended September 30, 1997, $800 of
interest income was attributable to a note receivable from MG related to the
Powerine Arbitration and $685 resulted from the investment of excess cash. For
the year ended September 30, 1998, $31 was attributable to interest on the MG
note, $94 was attributable to interest on a note from Penn Octane Corporation
("Penn Octane"), a public company involved in liquid petroleum and compressed
natural gas business, and the remaining $2,146 was attributable to the
investment of excess cash. Interest on the MG note ceased on October 14, 1997.
Interest Expense
Interest expense decreased $1,036 from $1,038 for the year ended
September 30, 1997 to $2 for the year ended September 30, 1998 because the
Company repaid all of its long-term debt in May 1997 with a portion of the
proceeds from the sale of its Texas oil and gas properties and pipeline to UPRC.
Penn Octane Note
In October 1997, the Company invested $1,000 in a promissary note of
Penn Octane. The note bears interest at 10% payable quarterly and was due on
June 30, 1998. At June 30, 1998, Penn Octane did not repay the note. In May of
1998, Penn Octane was awarded a judgement against a bank and such judgement is
in excess of the $1,000 owed to the Company by Penn Octane. In December 1998,
Penn Octane assigned its interest in the bank judgement to the extent of the
Company's note to the Company in return for an extension of the note until June
30, 1999. The Company also received 225,000 warrants to purchase the common
stock of Penn Octane for one dollar and seventy-five cents per share as
consideration for the
-16-
extension. The bank owing the judgement has appealed it and such appeal may not
be resolved for a year or more. As a result, there can be no assurance that the
judgement will be upheld upon appeal or that the bank will ultimately pay the
judgement won by Penn Octane to the Company. If the note is not repaid by its
extended due date, the Company intends to reduce the Penn Octane note to its
estimated realizable value, if any.
On February 27, 1998, the Company entered into an agreement with
Alexander Allen, Inc. ("AA") concerning amounts owed to the Company by AA and
its subsidiary, GAMXX Energy, Inc. ("GAMXX"). The Company had made loans to
GAMXX through 1991 in the aggregate amount of approximately $8,000. When GAMXX
was unable to obtain financing, the Company recorded a one hundred percent loss
provision on its loans to GAMXX while still retaining its lender's lien against
GAMXX.
Pursuant to the terms of the GAMXX Agreement, the Company is to receive
$1,000 cash in settlement for its loans when GAMXX closes on its financing.
GAMXX expected such closing not later than May 31, 1998 but such closing has not
yet occurred.
The Company has carried its loans to GAMXX at zero the last six years.
The Company will record the $1,000 proceeds as "other income" if and when it
collects such amount. There can be no assurance that GAMXX will close on its
financing.
Tax Provision
As a result of the tax benefit recorded in fiscal 1996, the Company
expected to provide for income taxes at a 36% blended statutory rate for the
remainder of the Lone Star Contract for book purposes. During this period the
Company expected to pay income taxes, however, at a 2% effective rate,
consisting of Federal alternative minimum tax.
The Company's tax provision for fiscal 1997 consists of two components:
a. The tax provision on pre-tax accounting income, exclusive of the
$19,667 gain on the sale of assets, aggregates $4,270 and
essentially represents the partial utilization of the $7,716
deferred tax asset recorded at September 30, 1996 at an effective
rate of 36% of earnings. If future events change the Company's
estimate concerning the probability of utilizing its tax assets,
appropriate adjustments will be made when such a conclusion is
reached.
b. The tax provision on the $19,667 gain equals the Company's expected
tax liability for the income related to the sale and aggregates
$393. The tax rate used in such calculation was 2%, the Federal
alternative minimum tax rate. The Company is not yet subject to a
higher tax rate due to its tax carryforwards. A tax provision of 36%
was not provided for the gain because a related deferred tax asset
was not previously provided since the Company did not anticipate
selling the properties and had previously taken the properties off
the market.
The tax provision for the year ended September 30, 1998 consists
primarily of a tax provision of $4,992 (utilization of deferred tax asset) and
an offsetting reversal of tax estimates and contingencies of $3,463. The Company
evaluated its need for a deferred tax valuation allowance at September 30, 1998
based upon recent positive evidence confirming the Company's ability to utilize
its tax carryforwards. The Company expects that its future tax expense for
fiscal 1999 for book purposes is expected to be 36% although the Company only
expects to pay taxes at a 2% rate. The 2% rate results from Federal alternative
minimum taxes.
Earnings Per Share
Since November 1996, the Company has reacquired 3,862,917 shares of its
common stock representing approximately 56.8% of shares outstanding. As a result
of these share acquisitions, earnings per outstanding share have increased
significantly.
-17-
Fiscal 1997 vs Fiscal 1996
Natural Gas Marketing and Transmission
Gas sales from natural gas marketing and transmission increased $5,128
or 8.6% from fiscal 1996 to 1997. The increase consists of the following:
September 30,
--------------------------
1997 1996
---- ----
Gas sales to Lone Star........................... $59,695 $57,823
Gas sales to MGNG................................ 4,904 1,648
------- -------
$64,599 $59,471
======= =======
Lone Star Contact
Natural gas sales under the Lone Star Contract increased $1,872 or 3.2%
from fiscal 1996 to fiscal 1997. Under the Company's long-term gas sales
contract with Lone Star, the price received for gas is essentially fixed through
May 31, 1999. The variance in gas sales, therefore, is almost entirely
attributable to the volumes of gas delivered. Although the volumes sold to Lone
Star annually are essentially fixed (the Lone Star Contract has a take-or-pay
provision), the Lone Star Contract year is from February 1 to January 31 whereas
the Company's fiscal year is from October 1 to September 30. Furthermore,
although the volumes to be taken by Lone Star in a given contract year are
fixed, there is no provision requiring fixed monthly or daily volumes and
deliveries accordingly vary with Lone Star's seasonal and peak demands. Such
variances have been significant. As a result, Lone Star deliveries, although
fixed for a contract year, may be skewed and not proportional for the Company's
fiscal periods.
For fiscal 1997, deliveries and sales to Lone Star, including those
derived from the Company's own production, were approximately $220 less than
those which would have resulted if daily deliveries had been fixed and equal. At
September 30, 1997, the remaining volumes to be delivered under the Lone Star
Contract were approximately 4.2% greater than those that would be delivered to
Lone Star if daily deliveries were fixed and equal.
Gas sales to MGNG increased $3,256 or 197.6% from fiscal 1996 to fiscal
1997 because such sales commenced June 1, 1996. Since sales to MGNG are for
equal daily volumes at fixed prices the increase in gas sales is directly
proportional to the increase in the sales period.
Gas purchases increased $5,733 or 16.7% from fiscal 1996 to fiscal 1997.
The increase consists of the following:
September 30,
--------------------------
1997 1996
---- ----
Gas purchases - Lone Star Contract................ $34,686 $32,878
Gas purchases - MGNG Contract..................... 5,280 1,355
------- -------
$39,966 $34,233
======= =======
Gas purchases for the Lone Star Contract increased $1,808 or 5.5% from
fiscal 1996 to fiscal 1997. For fiscal 1996 gas purchases comprised 56.9% of gas
sales versus 58.1% of gas sales for fiscal 1997. From 1996 to 1997 the gross
margin increased $64 or .3%. During the same periods the gross margin percentage
((gas sales - gas purchases) as a percentage of gas sales) decreased 1.2% from
43.1% for fiscal 1996 to 41.9% for fiscal 1997.
The increase in gas purchases as a percentage of gas sales and the
concomitant decrease in the gross margin percentage result from offsetting
factors. The cost of gas decreased because the Company replaced gas contracts
that expired in April 1997 with market price contracts. The expiring contracts
called for gas prices substantially in excess of market prices whereas the
replacement gas contracts are at market prices, resulting in the decreased costs
to the Company for a portion of the gas it supplies to Lone Star. This reduction
was offset by the higher gas prices that the Company had to pay for the 10% of
its gas that it supplies to Lone Star and that is not hedged and to a minor
degree by a $251 non-recurring favorable gas purchase adjustment in the first
quarter of fiscal 1996 which had no counterpart in fiscal 1997.
-18-
Gas purchases applicable to the MGNG Contract as a percentage of related
sales increased from 82.2% in fiscal 1996 to 107.7% in fiscal 1997. In fiscal
1996 the gross margin was $293 versus a deficit of $376 in fiscal 1997. The
increase in the cost of gas purchases and related decrease in the gross margin
were caused by increases in spot gas prices, net of hedging adjustments.
Operating costs decreased $373 or 44.1% from fiscal 1996 to fiscal 1997.
Most of the decrease is attributable to the sale of the Castle Pipeline to UPIPC
on May 30, 1997. Other factors accounting for the decrease include the
termination of two pipeline employees in January 1997, when the Company still
operated the Castle Pipeline and decreased insurance costs, property taxes and
compressor maintenance costs during the first eight months of fiscal 1997 versus
the first eight months of fiscal 1996.
General and administrative costs decreased $455 or 40% from fiscal 1996
to fiscal 1997. The primary factor causing the decrease was the sale of the
Castle Pipeline to UPIPC on May 30, 1997, resulting in only minor general and
administrative expense thereafter. Other factors causing the decrease were the
termination of management agreements with subsidiaries of MG in January 1997 and
the performance of their functions internally without additional costs and
decreased insurance cost. These were offset by an increase due to a $165
severance payment to the former President of the Company's natural gas marketing
subsidiary in January 1997.
Although the Company still markets natural gas, it no longer owns or
operates its Texas pipeline. Future natural gas marketing general and
administrative expenses are expected to be immaterial.
Transportation
Transportation expense increased from zero for fiscal 1996 to $338 for
fiscal 1997. All of the transportation expense for fiscal 1997 was incurred from
June 1, 1997 to September 30, 1997 and results from the amortization of the
prepaid transportation asset received from UPIPC in the sale of the Castle
Pipeline (see Note 4 to the financial statements). Prior to the sale to UPIPC,
the Company owned and operated the Castle Pipeline and intercompany
transportation charges were eliminated in consolidation. Commencing June 1,
1997, the Company commenced amortizing the $3,000 prepaid transportation asset
over the remaining term of the Lone Star Contract, which expires on May 31,
1999.
Depreciation and Amortization
Depreciation and amortization decreased $754 or 6.6% from fiscal 1996 to
fiscal 1997. The decrease results from the sale of the Castle Pipeline to UPIPC
on May 30, 1997. The decrease approximates the amount of depreciation and
depletion that would have been incurred had the Castle Pipeline not been sold.
Exploration and Production
Oil and gas sales decreased $2,042 or 23.3% from fiscal 1996 to fiscal
1997. The decrease results primarily from the sale of 84% of the Company's
proved reserves to UPRC on May 30, 1997 (see Note 4 to the financial
statements). In fiscal 1996 oil and gas sales applicable to such reserves were
for twelve months versus only eight months in fiscal 1997. In addition to the
sale of the properties to UPRC, two other offsetting factors are relevant. Oil
and gas sales decreased due to a decrease in production volumes. The decline in
production volumes results from the general maturing of the Company's reserves
since the Company has not made any significant reserve acquisitions and did not
conduct any significant drilling until July 1997. This decrease was offset by an
increase in oil and gas prices in fiscal 1997.
As a result of the sale to UPRC, the Company's oil and gas production is
expected to decrease by at least 60% - 65%. Nevertheless, the Company has
recently entered into a joint venture with another operator to drill up to 100
Appalachian wells over the next three to four years and is also in the process
of drilling approximately 10 - 13 coalbed methane wells in Alabama. In addition,
the Company is currently reviewing several possible acquisitions of oil and gas
assets. As a result the Company expects to replace some of the production and
reserves that it sold to UPRC.
Revenues from well operations decreased $69 or 15.6% from fiscal 1996 to
fiscal 1997. The decrease results primarily from operating revenues lost when
the Company sold its Rusk County, Texas oil and gas properties to UPRC in May
1997.
Oil and gas production expenses decreased $105 or 5.1% from fiscal 1996
to fiscal 1997. The decrease was caused by the sale of the Company's Rusk County
oil and gas properties to UPRC on May 30, 1997. In fiscal 1997 oil and gas
-19-
production expenses were 28.8% of oil and gas sales versus 23.3% of oil and gas
sales in fiscal 1996. The increase in production expenses as a percentage of oil
and gas sales results from the general maturing of the Company's oil and gas
properties, the lack of new drilling by the Company for most of the recent
fiscal year and the tendency for older depleting properties to carry a higher
production expense burden than recently drilled properties. As noted above, the
Company has commenced several drilling activities and the oil and gas production
expense ratio may improve in the future, although there can be no assurance such
will be the case.
General and administrative expenses decreased $98 or 7.9% from fiscal
1996 to fiscal 1997. The decrease results from offsetting factors. General and
administrative expenses decreased because the Company closed its Tulsa office in
June 1996 and because the Company sold its Rusk County, Texas oil and gas
properties to UPRC in May 1997. These decreases were offset, however, by
increased legal fees due to the Larry Long litigation which was filed in July
1996. (See Note 14 to the financial statements.)
Depreciation, depletion and amortization decreased $713 or 30.7% from
fiscal 1996 to fiscal 1997. The decrease was primarily caused by the sale of the
Company's Rusk County, Texas oil and gas properties to UPRC on May 30, 1997. Had
the properties not been sold to UPRC, depreciation, depletion and amortization
for fiscal 1997 would have been approximately $450 higher.
On May 30, 1997, the Company sold its Texas oil and gas properties and
pipeline (see Note 4 to the financial statements). The sale resulted in a
$19,667 non-recurring gain. There was no counterpart in fiscal 1996.
Interest income increased $524 or 54.5% primarily because of interest
earned from June 1, 1997 to September 30, 1997 on the unspent proceeds from the
sale of the Company's Texas oil and gas properties and pipeline (see Note 4 to
the financial statements).
Other income (expense) decreased $2,978 from $2,923 of other income for
fiscal 1996 to other expenses of $55 for fiscal 1997. Of the $2,923 of other
income in 1996, $2,725 represented recoveries from a plaintiff class escrow fund
related to stockholder litigation. The parties reached a settlement with respect
to the stockholder litigation in October 1994. The proceeds to the Company
represent unclaimed funds that were to revert to the Company pursuant to the
settlement order for the litigation.
Interest expense decreased $921 or 47.0% from fiscal 1996 to fiscal
1997. The net decrease in interest expense is attributable to offsetting
factors. Amortization of debt issuance costs, which is treated as interest
expense under generally accepted accounting principles, increased $169 from $174
for fiscal 1996 to $343 for fiscal 1997. The increase is attributable to debt
issuance costs incurred in connection with the Company's refinancing of its
senior debt. Interest expense, on the other hand, decreased $1,090 from $1,785
for fiscal 1996 to $695 for fiscal 1997 primarily because the average debt
outstanding during fiscal 1997 was less than that outstanding during fiscal
1996. On May 30, 1997, the Company repaid its debt. The Company does not
anticipate that it will need debt financing in the foreseeable future.
Tax Provision
As a result of the tax benefit recorded in fiscal 1996, the Company
expected to provide for income taxes at a 36% blended statutory rate for the
remainder of the Lone Star Contract for book purposes. During this period the
Company expected to pay income taxes, however, at a 2% effective rate,
consisting of Federal alternative minimum tax.
The Company's tax provision for fiscal 1997 consists of two components:
a. The tax provision on pre-tax accounting income, exclusive of the
$19,667 gain on the sale of assets, aggregates $4,270 and
essentially represents the amortization of the $7,716 deferred tax
asset recorded at September 30, 1996 at an effective rate of 36% of
earnings. If future events change the Company's estimate concerning
the probability of utilizing its tax assets, appropriate adjustments
will be made when such a conclusion is reached.
b. The tax provision on the $19,667 gain equals the Company's expected
tax liability for the income related to the sale and aggregates
$393. The tax rate used in such calculation was 2%, the Federal
alternative minimum tax rate. The Company is not subject to a higher
tax rate due to its carryforwards. A tax provision of 36% was not
provided for the gain because a related deferred tax asset was not
previously provided since the Company did not anticipate selling the
properties and had previously taken the properties off the market.
-20-
LIQUIDITY AND CAPITAL RESOURCES
All statements other than statements of historical fact contained in
this report are forward-looking statements. Forward-looking statements in this
report generally are accompanied by words such as "anticipate," "believe,"
"estimate," or "expect" or similar statements. Although the Company believes
that the expectations reflected in such forward-looking statements are
reasonable, no assurance can be given that such expectations will prove correct.
Factors that could cause the Company's results to differ materially from the
results discussed in such forward-looking statements are disclosed in this
report, including without limitation in conjunction with the expected cash
receipts and expected cash obligations included below. All forward-looking
statements in this Form 10-K are expressly qualified in their entirety by the
cautionary statements in this paragraph. Furthermore, this statement constitutes
a Year 2000 Readiness Disclosure Statement and the statements contained herein
are subject to the Year 2000 Information and Readiness Disclosure Act ("Act").
In case of a dispute, this document and information contained herein are
entitled to protection of the Act.
During the year ended September 30, 1998, the Company generated $36,075
from operating activities. Of this amount, $8,700 represented the collection of
a portion of the MG Note. During the same period the Company invested $1,000 in
a note from Penn Octane, $2,212 in oil and gas properties and $28,644 to
reacquire shares of its common stock. In addition, it paid $2,393 in stockholder
dividends. At September 30, 1998, the Company had $36,600 of unrestricted cash,
$40,271 of working capital and no long-term debt.
Discontinued Refining Operations
Although the Company's subsidiaries have exited the refining business
and third parties have assumed environmental liabilities, if any, of such
subsidiaries, the Company and several of its subsidiaries remain liable for
contingent environmental liabilities (see Item 3 and Note 13 to the financial
statements).
At the present time the probable future cash expenditures of the Company
consist of the following:
a. Investments in Oil and Gas Properties and Energy Sector - in fiscal
1998, the Company drilled 10 new coalbed methane wells in Alabama
and participated in drilling twelve new wells in Pennsylvania as
part of a joint venture to drill up to 100 wells in Appalachia over
the next three to four years. At least ten new Appalachian wells
are planned by the joint venture over the next year and the Company
may drill additional coalbed methane wells in Alabama. In addition,
the Company is also reviewing several possible joint ventures,
reserve acquisitions and drilling ventures, including several
overseas, as well as other investments in the energy sector. The
Company believes that low oil and gas prices will increase the
probability that the Company can conclude a transaction or several
transactions on terms favorable to the Company. There can be no
assurance, however, that oil and gas prices will decrease or remain
low or that a transaction will be closed even if such prices
decrease or remain low. Selling companies may decide not to sell or
delay selling in the hope of higher oil and gas prices. Several
competitors have significantly more resources than the Company and
may outbid it in future acquisitions.
b. Repurchase of Company Shares - as of November 20, 1998, the Company
had repurchased 3,862,917 of its shares of common stock at a cost
of $53,807. The Company's Board of Directors has authorized the
repurchase of up to 4,250,000 shares to provide an exit vehicle for
investors who want to liquidate their investment in the Company. As
a result, 387,083 shares can be repurchased under the current
authorization of the Board of Directors. The decision whether to
repurchase additional shares will depend upon the market price of
the Company's stock, tax considerations, the number of stockholders
seeking to sell their shares and other factors.
c. Recurring Dividends - the Company's Board of Directors adopted a
policy of paying a $.60 per share annual dividend ($.15 per share
quarterly) in June of 1997. The Company expects to continue to pay
such dividend until the Board of Directors, in its sole discretion,
changes such policy.
-21-
An estimate of the Company's expected cash resources and obligations
from October 1, 1998 to September 30, 1999, the fiscal year end during which the
Lone Star Contract expires, is as follows:
Expected Cash Resources: ("000's" Omitted)
Unrestricted cash on hand - September 30, 1998................... $36,600
Cash flow - gas marketing and exploration and production
operations..................................................... 17,748
Repayment of Penn Octane Corporation note........................ 1,000
Proceeds from SWAP litigation - IRLP............................. 704
Proceeds from American Western note.............................. 2,919
Interest......................................................... 2,455
Proceeds from MGNG contract litigation........................... 750
-------
62,176
-------
Expected Cash Obligations:
New drilling..................................................... 1,787
Quarterly dividends (based on outstanding shares at November
20, 1998)...................................................... 1,764
Assumed IRLP payment of vendors and funding of
environmental reserves....................................... 3,622
Legal defense costs - environmental litigation................... 200
-------
7,373
-------
Excess of Expected Cash Resources Over Expected Cash Obligations.... $54,803
=======
The following apply to the Company's expected cash resources and
obligations:
a. Interest income on cash has been computed at 5%. If unanticipated
expenditures are made or interest rates decrease, interest income
will decrease.
b. The Company is currently evaluating several investments in the
energy sector but has not yet made any additional expenditures or
commitments. It may, nevertheless, do so in the future. The above
cash estimates do not include any expenditures for such investments.
c. The Company's Board of Directors has authorized the purchase by the
Company of up to 4,250,000 shares of common stock in the open
market. To date, 3,862,917 shares have been repurchased. The Company
may or may not repurchase the remaining 387,083 shares available and
the Board of Directors may or may not increase the current
authorization, depending on market prices and other factors. No
additional repurchases are assumed in the above estimates.
d. Although the Company's Board of Directors has adopted a quarterly
dividend policy of $.15 per share, the Board may elect to change
such policy at any time.
e. The Company has assumed certain cash flow returns from its recently
completed and planned drilling activities. There can be no assurance
that such drilling activities will be successful or that the
projected returns will be achieved.
f. The Company is pursuing a line of credit from a financial
institution in case it decides to make an investment or acquisition
requiring more cash than the Company currently has.
In addition to the foregoing, the above estimates assume that the
Company will not be adversely impacted by any of the following risk factors. If
such events occur, the Company's estimated cash flow will probably be adversely
affected and such effects may be material.
-22-
1. Contingent Environmental Liabilities
Although the Company has never itself conducted refining operations
and its refining subsidiaries have exited the refining business and
the Company does not anticipate any required expenditures related
to discontinued refining operations, interested parties could seek
redress from the Company for environmental liabilities. In the
past, government and other plaintiffs have often named the most
financially capable parties in such cases regardless of the
existence or extent of actual liability. As a result there exists
the possibility that the Company could be named for any
environmental claims related to discontinued refining operations of
its present and former refining subsidiaries.
The Company was informed that the EPA has investigated offsite acid
sludge waste found near the Indian Refinery and was also
remediating surface contamination in the Indian Refinery property.
Neither the Company nor IRLP has been named with respect to these
two actions.
In October 1998, the EPA named the Company and two of its
subsidiaries as potentially responsible parties for the expected
clean-up of the Indian Refinery. In addition, eighteen other
parties were named including Texaco Refining and Marketing, Inc.,
the refinery operator for over 50 years. The Company subsequently
responded to the EPA indicating that it was neither the owner nor
operator of the Indian Refinery and thus not responsible for its
remediation. Estimated undiscounted clean-up costs for the Indian
Refinery are $80,000 to $150,000 according to third parties.
Although the Company does not believe it has any liabilities with
respect to the environmental liabilities of the refineries, a court
of competent jurisdiction may find otherwise. A recent decision by
the U.S. Supreme Court has supported the Company's position.
The above statement of expected cash resources and obligations
assume a $200 expenditure for legal defense costs related to the
Indian Refinery. If related legal proceedings continue longer than
expected (environmental litigation often continues 3-5 years or
more) or the Company is found liable for a portion of the
environmental remediation of either the Indian Refinery or Powerine
Refinery, estimated cash flow would be decreased and the decrease
would be significant.
2. IRLP Vendor Liabilities:
IRLP owes its vendors approximately $4,873. Its only major asset is
a $5,388 note due from the purchaser of the Indian Refinery,
American Western. In November 1996, American Western filed for
bankruptcy and has since sold the Indian Refinery to an outside
party. Management estimates that IRLP may recover $3,623 which will
be available for creditors of IRLP and environmental reserves.
Although IRLP holds a first mortgage on the Indian Refinery, other
creditors of American Western may attempt to circumvent IRLP's
first mortgage. It is, therefore, unlikely that IRLP's share of the
proceeds will be sufficient to settle its vendor liabilities. If
IRLP cannot settle its vendor liabilities, IRLP may file for
bankruptcy since its only significant asset is its note due from
American Western. In addition, in fiscal 1997 the Illinois
Department of Revenue filed to assess two present officers of the
Company and two former officers of the Company for certain tax
liabilities of IRLP. The Company has responded that its officers
are not liable for the taxes. Although the Company does not believe
such developments will affect its estimated cash flow, such may not
be the case. IRLP's vendors may attempt to hold the Company liable
for IRLP's debts and/or the Illinois Department of Revenue may
prevail in its efforts to assess officers of the Company for IRLP
liabilities, in which case the Company would have indemnification
obligations to such officers. In either case the Company's
estimated cash flow would be adversely affected.
3. Larry Long Litigation:
The above cash flow assumes the Company will not have to pay any
claim related to the Larry Long litigation. Although the sale of
the Company's Texas oil and gas properties and pipeline to UPRC
have significantly reduced the Company's exposure, there can be no
assurance that the plaintiffs will not file new lawsuits, having
already amended their original complaint three times. In such case,
the Company would be exposed to the continuing legal costs of
defending the amended petitions, and, if it is determined that
settlement is in the Company's best interest, the cost to settle
the lawsuit. No such costs are included in the above estimate of
cash flow.
-23-
4. Credit Risk - Lone Star:
At the current time, in excess of 92% of the Company's gas
marketing sales are to a single customer, Lone Star, under a
long-term gas sale contract, which terminates on May 31, 1999.
Although Lone Star has paid for all gas purchased, any inability of
Lone Star to continue to pay for gas purchased would adversely
affect the Company's cash flow.
5. Supply Risk - MGNG:
The Company now purchases virtually all of its gas supplies for the
Lone Star Contract from MGNG at fixed prices. If spot gas prices
increase significantly and MGNG has not hedged its future
commitment to supply gas to the Company or if MGNG experiences
financial problems, MGNG may be unable to meet its gas supply
commitments to the Company. If MGNG does not fulfill its gas supply
commitment to the Company, the Company may not be able to fulfill
its gas delivery commitment to Lone Star through May 31, 1999, the
termination of the Lone Star Contract, or to earn the gross margins
currently being earned. This would adversely impact the Company's
cash flow. Under such circumstances the Company may not be able to
recover lost profits and cash flow from MGNG despite contractual
provisions providing for such recovery.
6. Gas Contract Litigation:
The Company's natural gas marketing subsidiaries and MGNG are
parties to several natural gas contracts. One subsidiary has sued
MGNG to recover gas measurement and transportation costs in excess
of $750 (see Item 3 to this 10-K). Although the Company believes it
is entitled to in excess of $750 plus interest and has included
such recovery in its estimated cash flow, it is possible that a
court of competent jurisdiction may find otherwise. It is also
possible that the Company and MG may litigate other issues related
to the gas supply contract with MGNG. To the extent the Company
does not recover at least $750 from present or future gas contract
litigation with MGNG, the Company's projected cash flow will be
decreased.
7. Public Market for the Company's Stock:
Although there presently exists a market for the Company's stock,
such market is volatile and the Company's stock is thinly traded.
Such volatility may adversely affect the market price and liquidity
of the Company's common stock.
In addition, the Company, through its stock repurchase program, has
effectively become the major market maker in the Company's stock.
If the Company ceases repurchasing shares the market value of the
Company's stock may be adversely affected.
8. Future of the Company:
As noted in Item I and Note 3 to the financial statements (Item 8
of this Form 10-K), the Company recently sold 84% of its proved oil
and gas reserves and its Texas pipeline. The Company's primary
remaining asset is its gas sales contract with Lone Star, which
expires on May 31, 1999. Although the Company is reviewing and
seeking investments in the energy sector, including oil and gas
property acquisitions and drilling ventures , the Company has not
yet been able to acquire such investments at a favorable price.
There are also many competitors with resources greater than those
of the Company. If the Company does not acquire additional assets,
its Board of Directors may decide to pursue other courses of
action, including but not limited to liquidation, sale of assets,
merger or other reorganization.
9. Year 2000
The Company has recently completed a study of the Year 2000 issue
and related risks. As a result of the study, the Company has
replaced its oil and gas and general ledger software with new
software which is Year 2000 compliant. The Company expects the cost
to approximate $100. At September 30, 1998, $83 had been incurred.
The Company commenced using the new software in the first quarter
of fiscal 1999. The Company has also made
-24-
inquiries to outside parties who process transactions of the
Company, e.g., payroll, commercial banks, transfer agent, reserve
engineers, etc. While some outside parties have confirmed they are
Year 2000 compliant, others have not done so to the Company's
satisfaction. The Company is continuing to pursue the vendors whose
responses appear to provide insufficient assurance.
The most important systems operated by the Company are its revenue
distributions, joint interest billing and general ledger. The
Company replaced its software because the new systems are Year 2000
compliant. If a Year 2000 problem nevertheless occurred, the
Company could process transactions for several months manually or
using small computers but only with increased administrative costs.
Nevertheless, in many cases, the Company is not the operator of a
given well or purchaser of oil and gas production. In those cases
the Company is dependent upon the operator and/or gas/oil purchaser
for accurate volumetric, cost and sales information and for
payments. Although the Company has made Year 2000 inquiries of such
operators and purchasers and generally received satisfactory
responses, there can be no assurance that such operators and
purchasers will actually be Year 2000 compliant. If such is the
case, the Company could find a major portion of its production
revenue held in escrow until Year 2000 compliance was achieved or
resulting litigation settled. The related legal cost and resulting
administrative confusion could be substantial. The Company expects
to make any necessary contingency plans in fiscal 1999 in the event
of non-compliance of its systems, customers or suppliers.
The Company and its subsidiaries are not aware of any material Year
2000 operational risks.
10. Exploration and Production Price Risk
The Company has not hedged its existing oil and gas price
production and is thus exposed to oil and gas price risk. Most of
the Company's oil and gas sales are at spot prices. If such spot
prices decrease, the Company's sales and operating income from oil
and gas sales will likewise decrease.
11. Exploration and Production - Drilling and Production Risk
The Company is subject to reserve and price risk on the oil and gas
properties it owns. Reserve risk is the possibility that the
reserves produced will not approximate the reserves the Company has
estimated. Price risk is the possibility that the price the Company
receives for its production will vary from current oil/gas prices.
Since the Company has not hedged its future production, changes in
oil and gas prices will affect cash flow from its exploration and
production operations. If oil and gas prices are lower than
expected, cash flow will be less than that anticipated above.
The Company is currently considering several oil and gas reserve
acquisitions through purchase or new drilling. Although the
Company's management estimates the proved reserves associated with
such acquisitions, there can be no assurance that production or
related oil and gas reserves will be as estimated. Furthermore,
such reserve risk also applies to the Company's existing reserves.
Production and resulting cash flow may vary significantly from the
Company's estimates and those of its independent petroleum
reservoir engineer.
12. Other Risks
UPRC has recently terminated several employees responsible for the
UPRC deliveries of the Company's gas to Lone Star. If deliveries to
Lone Star are hindered by UPRC's reduced workforce or related
pipeline operational problems, the Company could fail to deliver
amounts of gas nominated by Lone Star and by so doing lose the high
gross margins realized on the sale of such gas.
The Company has assumed that its note due from Penn Octane will be
paid on its extended due date, June 30, 1999. Interest on the note
has been paid to June 30, 1998 but not thereafter. Penn Octane
failed to pay it the note on its original due date, June 30, 1998.
Although the Company received an assignment of a judgement due to
Penn Octane from a bank in return for extending the due date of the
note to June 30, 1999, there can be no assurance that the Company
will ultimately collect the note. In such case the estimated cash
flow will be adversely affected.
-25-
In addition to the specific risks noted above, the Company is
subject to general business risks, including insurance claims in
excess of insurance coverage, tax liabilities resulting from tax
audits, drilling risks that new drilling will result in dry holes
or marginal wells and the risks and costs of unending litigation.
If any or several of these risks materialize, the Company's
estimated cash flow and results of operations will probably be adversely
impacted and the impact may be material. The estimated cash flow above assumes
none of these risks materializes. Given the number and variety of risks and the
litigiousness of today's corporate world, it is reasonably possible that one or
more of these risks may occur.
QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
One of the Company's subsidiaries has hedged all of the gas it must
purchase for the remaining term of the Lone Star Contract and the contract with
MGNG. The subsidiary used fixed price swaps to hedge such gas. The subsidiary
purchases gas on the open market and pays the trading party if the market price
is below the fixed price or is paid by the trading party if the market price
exceeds the fixed price. The result is that the Company's subsidiary has
essentially fixed the price of future gas purchases and is not subject to
commodity price risk related to its gas marketing activities. The subsidiary
continues to be exposed to the difference between the wellhead gas price and the
price used in the hedge but such differences are expected to be immaterial.
See Note 14 to the Consolidated Financial Statements included in
Item 8 of this Form 10-K.
INFLATION AND CHANGING PRICES
Natural Gas Marketing
The Company's gas sales contract with Lone Star is essentially a
fixed price contract. It continues through May 1999. The Company's gas supply
contract with MGNG is also a fixed price contract. The result is that the
Company's gross margin is essentially "locked in" and does not change with
inflation. The Company's gas sales contract with MGNG is also at a fixed price.
The Company has hedged all of the gas supplies needed for this contract at a
price in excess of that received from MGNG. As a result, the Company's gross
margins on the gas contract with MGNG is also "locked in" and not subject to
inflation and changing prices. Although there are some operating costs
applicable to the natural gas marketing segment, which tend to increase or
decrease with inflation, these are minor and inflation of such costs without
concomitant inflation in revenues does not significantly impact operating
profits.
Exploration and Production
Oil and gas sales are determined by markets locally and worldwide
and often move inversely to inflation. Whereas operating expenses related to oil
and gas sales may be expected to parallel inflation, such costs have often
tended to move more in response to oil and gas sales prices than in response to
inflation.
NEW ACCOUNTING PRONOUNCEMENTS
In February 1997, the Financial Accounting Standards Board (FASB)
issued Statement of Financial Accounting Standards No. 128 ("SFAS 128"),
"Earnings Per Share," which establishes standards for computing and presenting
earnings per share ("EPS") for entities with publicly held common stock. SFAS
128 simplifies the standards for computing EPS previously found in Accounting
Principles Board Opinion No. 15, "Earnings Per Share," and makes them comparable
to international EPS standards. It replaces the presentation of primary EPS with
a presentation of basic EPS, and requires dual presentations of basic and
diluted EPS on the face of the income statement. SFAS 128 is effective for
fiscal years ending after December 15, 1997, and early adoption is not
permitted. The Company has adopted SFAS 128 for the fiscal year ending September
30, 1998 and has recomputed EPS for fiscal 1997 and 1996 in accordance with SFAS
128.
In June 1997, FASB issued Statement of Financial Accounting
Standards No. 130 ("SFAS 130") regarding reporting comprehensive income, which
establishes standards for reporting and display of comprehensive income and its
components. The components of comprehensive income refer to revenues, expenses,
gains and losses that are excluded from net income under current accounting
standards, including foreign currency translation items, minimum pension
liability adjustments and
-26-
unrealized gains and losses on certain investments in debt and equity
securities. SFAS 130 requires that all items recognized under accounting
standards as components of comprehensive income be reported in a financial
statement displayed in equal prominence with the other financial statements; the
total of other comprehensive income for a period is required to be transferred
to a component of equity that is separately displayed in a statement of
financial condition at the end of an accounting period. SFAS 130 is effective
for both interim and annual periods for companies having fiscal years beginning
after December 15, 1997. Reclassification of financial statements for earlier
periods provided for comparative purposes is required. The Company will adopt
SFAS 130 for the fiscal year ending September 30, 1999.
In June 1997, FASB issued Financial Accounting Standards Board No.
131 ("SFAS 131") regarding disclosures about segments of an enterprise and
related information. SFAS 131 establishes standards for reporting information
about operating segments in annual financial statements and requires the
reporting of selected information about operating segments in interim financial
reports issued to stockholders. It also establishes standards for related
disclosures about products and services, geographic areas and major customers.
SFAS 131 is effective for companies having fiscal years beginning after December
15, 1997. The Company will adopt SFAS No. 131 for the fiscal year ending
September 30, 1999.
Statement of Financial Accounting Standards No. 133, Accounting for
Derivative Instruments and Hedging Activities ("SFAS 133"), was issued by the
Financial Accounting Standards Board in June 1998. SFAS 133 standardizes the
accounting for derivative instruments, including certain derivative instruments
embedded in other contracts. Under the standard, entities are required to carry
all derivative instruments in the statement of financial position at fair value.
The accounting for changes in the fair value (i.e., gains or losses) of a
derivative instrument depends on whether it has been designated and qualifies as
part of a hedging relationship and, if so, on the reason for holding it. If
certain conditions are met, entities may elect to designate a derivative
instrument as a hedge of exposures to changes in fair values, cash flows, or
foreign currencies. If the hedged exposure is a fair value exposure, the gain or
loss on the derivative instrument is recognized in earnings in the period of
change together with the offsetting loss or gain on the hedged item attributable
to the risk being hedged. If the hedged exposure is a cash flow exposure, the
effective portion of the gain or loss on the derivative instrument is reported
initially as a component of other comprehensive income (outside earnings) and
subsequently reclassified into earnings when the forecasted transaction affects
earnings. Any amounts excluded from the assessment of hedge effectiveness, as
well as the ineffective portion of the gain or loss, is reported in earnings
immediately. Accounting for foreign currency hedges is similar to the accounting
for fair value and cash flow hedges. If the derivative instrument is not
designated as a hedge, the gain or loss is recognized in earnings in the period
of change.
The Company expects to adopt SFAS 133 in fiscal 2000. To date all
hedging by the Company has been applicable to the Company's gas marketing
operations. Those operations are expected to end on May 31, 1999 when the
related gas contracts terminate. As a result, the Company believes SFAS 133 will
not affect existing operations and cannot make a determination as to whether it
will effect future operations until it engages in such operations.
The Company believes that adoption of these financial accounting
standards will not have a material effect on its financial condition or results
of operations.
RISK FACTORS
See above.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
----
CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Statements of Operations for the Years Ended September 30, 1998, 1997 and 1996................. 29
Consolidated Balance Sheets, as of September 30, 1998 and 1997.............................................. 30
Consolidated Statements of Cash Flows for the Years Ended September 30, 1998, 1997 and 1996................. 31
Consolidated Statements of Stockholders' Equity for the Years Ended September 30, 1998, 1997 33
and 1996............................................................................................
Notes to the Consolidated Financial Statements.............................................................. 34
REPORTS OF INDEPENDENT ACCOUNTANTS.......................................................................... 57
All other schedules are omitted because they are not applicable or the
required information is shown in the financial statements or notes thereto.
-28-
CASTLE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
("000's" Omitted Except Per Share Amounts)
Year Ended September 30,
-----------------------------------------------------
1998 1997 1996
---- ---- ----
Revenues:
Natural gas marketing and transmission:
Gas sales.............................................. $ 70,001 $ 64,599 $ 59,471
Transportation......................................... 7
------------ ----------- ------------
70,001 64,606 59,471
------------ ----------- ------------
Exploration and production:
Oil and gas sales...................................... 2,373 6,740 8,782
Well operations........................................ 230 373 442
------------ ----------- ------------
2,603 7,113 9,224
------------ ----------- ------------
72,604 71,719 68,695
------------ ----------- ------------
Expenses:
Natural gas marketing and transmission:
Gas purchases.......................................... 43,254 39,966 34,233
Operating costs........................................ (16) 472 845
General and administrative............................. 62 776 1,231
Transportation......................................... 1,539 338
Depreciation and amortization.......................... 9,462 10,639 11,393
------------ ----------- ------------
54,301 52,191 47,702
------------ ----------- ------------
Exploration and production:
Oil and gas production................................. 775 1,940 2,045
General and administrative............................. 992 1,137 1,235
Depreciation, depletion and amortization............... 423 1,611 2,324
------------ ----------- ------------
2,190 4,688 5,604
------------ ----------- ------------
Corporate general and administrative..................... 3,081 3,370 3,499
------------ ----------- ------------
59,572 60,249 56,805
------------ ----------- ------------
Operating income............................................. 13,032 11,470 11,890
------------ ----------- ------------
Other income (expense):
Gain on sale of assets................................... 19,667
Interest income.......................................... 2,271 1,485 961
Other income (expense)................................... (41) (55) 2,923
Interest expense......................................... (2) (1,038) (1,959)
------------ ----------- ------------
2,228 20,059 1,925
------------ ----------- ------------
Income from continuing operations before provision for
(benefit of) income taxes................................ 15,260 31,529 13,815
------------ ----------- ------------
Provision for (benefit of) income taxes:
State................................................ 40 119 (309)
Federal.............................................. 1,164 4,544 (10,950)
------------ ----------- ------------
1,204 4,663 (11,259)
------------ ----------- ------------
Net income from continuing operations........................ 14,056 26,866 25,074
Income from discontinued refining operations, net of
applicable income taxes..................................
Net income................................................... $ 14,056 $ 26,866 $ 25,074
============ ============ ============
Net income per share:
Basic.................................................... $ 3.71 $ 4.66 $ 3.75
============ ============ ============
Diluted.................................................. $ 3.66 $ 4.64 $ 3.73
============ ============ ============
Weighted average number of common and potential dilutive
shares outstanding:
Basic.............................................. 3,790,100 5,764,045 6,693,646
============ ============ ============
Diluted............................................ 3,837,903 5,795,341 6,718,534
============ ============ ============
The accompanying notes are an integral part of these financial statements
-29-
CASTLE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
("000's" Omitted Except Share Amounts)
September 30,
--------------------------
1998 1997
---- ----
ASSETS
Current assets:
Cash and cash equivalents......................................................... $ 36,600 $36,338
Restricted cash................................................................... 613 497
Accounts receivable............................................................... 8,381 5,868
Marketable securities............................................................. 471
Prepaid transportation, net....................................................... 1,123 1,500
Prepaid expenses and other current assets......................................... 293 452
Prepaid gas purchases............................................................. 852
Deferred income taxes............................................................. 2,765 2,239
Note receivable - Penn Octane Corporation......................................... 1,000
Note receivable - MG.............................................................. 10,000
Estimated realizable value of discontinued net refining assets.................... 3,623 4,422
-------- -------
Total current assets............................................................ 55,721 61,316
Property, plant and equipment, net:
Natural gas transmission.......................................................... 62
Furniture, fixtures and equipment................................................. 307 180
Oil and gas properties, net (full cost method)........................................ 4,600 2,818
Gas contracts, net.................................................................... 6,285 15,747
Prepaid transportation, net........................................................... 1,162
Deferred income taxes................................................................. 1,494
Other assets.......................................................................... 29
-------- -------
Total assets...................................................................... $ 67,004 $82,717
======== =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Dividend payable.................................................................. $ 707
Accounts payable.................................................................. $ 8,658 5,615
Accrued expenses.................................................................. 1,663 1,257
Net refining liabilities retained................................................. 5,129 7,353
-------- -------
Total current liabilities....................................................... 15,450 14,932
Other long-term liabilities........................................................... 1 20
-------- -------
Total liabilities............................................................... 15,451 14,952
-------- -------
Commitments and contingencies
Stockholders' equity:
Series B participating preferred stock; par value - $1.00; 10,000,000 shares
authorized; no shares issued
Common stock; par value - $0.50; 25,000,000 shares authorized;
6,803,646 issued in 1998 and 6,798,646 issued in 1997........................... 3,402 3,399
Additional paid-in capital............................................................ 67,122 67,061
Retained earnings..................................................................... 34,836 22,468
-------- -------
105,360 92,928
Treasury stock at cost - 3,862,917 shares in 1998 and 2,085,100 shares in 1997........ (53,807) (25,163)
-------- -------
Total stockholders' equity...................................................... 51,553 67,765
-------- -------
Total liabilities and stockholders' equity...................................... $ 67,004 $82,717
======== =======
The accompanying notes are an integral part of these financial statements
-30-
CASTLE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
("000's" Omitted Except Share Amounts)
Year Ended September 30,
------------------------------------------
1998 1997 1996
---- ---- ----
Cash flows from operating activities:
Net income ............................................................... $14,056 $26,866 $ 25,074
------- ------- --------
Adjustments to reconcile net income to cash provided by operating
activities:
Depreciation, depletion and amortization............................... 9,885 12,250 13,612
Amortization of deferred debt issue costs.............................. 343 356
Deferred income taxes.................................................. 968 3,983 (10,667)
Gain on sale of assets................................................. (19,667)
Write-off of debt acquisition costs.................................... 161
Changes in assets and liabilities:
(Increase) decrease in restricted cash.............................. (116) 1,246 5,942
(Increase) in marketable securities................................. (471)
(Increase) decrease in accounts receivable.......................... (2,513) 4,349 22,658
Decrease in inventory............................................... 22,914
Decrease in note receivable......................................... 10,000
Decrease in prepaid transportation.................................. 1,539 338
(Increase) decrease in prepaid expenses and other current assets.... 159 (379) 903
(Increase) decrease in other assets................................. (29) 371 (103)
(Increase) in prepaid gas purchases................................. (852)
Increase (decrease) in accounts payable............................. 3,043 1,798 (1,744)
Increase (decrease) in accrued expenses............................. 406 (3,351) (28,105)
(Decrease) in other current liabilities............................. (2,037) (329)
(Decrease) in other long-term liabilities........................... (62) (23,265)
(Decrease) in due to related parties................................ (385)
------- ------- --------
Total adjustments............................................... 22,019 (818) 1,948
------- ------- --------
Net cash flow provided by operating activities.................. 36,075 26,048 27,022
------- ------- --------
Cash flows from investment activities:
Investment in Penn Octane Note............................................ (1,000)
Proceeds from sale of oil and gas assets and pipeline..................... 50,184
Realization from (liquidation of) discontinued net refining assets........ (1,425) (1,860) 4,000
Investment in oil and gas properties...................................... (2,212) (1,540) (34)
Investment in pipelines................................................... (63) (59) (140)
Purchase of furniture, fixtures and equipment............................. (182) (4) (1)
Other..................................................................... 42 (359)
------- ------- --------
Net cash provided by (used in) investing activities............. (4,840) 46,362 3,825
------- ------- --------
(continued on next page)
The accompanying notes are an integral part of these financial statements
-31-
CASTLE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
("000's" Omitted Except Share Amounts)
(continued from previous page)
Year Ended September 30,
--------------------------------------------
1998 1997 1996
---- ---- ----
Cash flows from financing activities:
Acquisition of treasury stock ............................................ ($28,644) ($25,163)
Dividends paid to shareholders ........................................... (2,393) (739)
Proceeds of long-term debt................................................ 17,658 $ 3,800
Proceeds from exercise of stock options................................... 64 797
Repayment of long-term debt - related party............................... (250)
Repayment of long-term debt............................................... (31,664) (37,984)
Payment of debt issuance costs............................................ (418) (486)
-------- -------- --------
Net cash (used in) financing activities............................. (30,973) (39,529) (34,920)
-------- -------- --------
Net increase (decrease) in cash and cash equivalents......................... 262 32,881 (4,073)
Cash and cash equivalents - beginning of period.............................. 36,338 3,457 7,530
-------- -------- --------
Cash and cash equivalents - end of period.................................... $36,600 $ 36,338 $ 3,457
======== ======== ========
Supplemental disclosures of cash flow information are as follows:
Cash paid during the period:
Interest............................................................... $ 2 $ 1,137 $ 2,086
======== ======== ========
Income taxes........................................................... $ 128 $ 863 $ 536
======== ======== ========
Supplemental schedule of non-cash investing and financing activities.........
Sale of oil and gas assets and pipeline:
Prepaid transportation received from purchaser......................... ($ 3,000)
========
Accrued expenses offset against gain................................... ($ 2,733)
========
Other liabilities assumed by purchaser................................. $ 1,623
========
Accrued dividends............................................................ $ 707
========
The accompanying notes are an integral part of these financial statements
-32-
CASTLE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
("000's" Omitted Except Share Amounts)
Years Ended September 30, 1998, 1997 and 1996
----------------------------------------------------------------------------------------------
Common Stock Additional Retained Treasury Stock
----------------- Paid-In Earnings ---------------------
Shares Amount Capital (Deficit) Shares Amount Total
------ ------ ---------- --------- ------ ------ ---------
Balance - October 1, 1995........ 6,693,646 $3,347 $66,316 ($28,026) $41,637
Net income....................... 25,074 25,074
--------- ------ ------- -------- -------
Balance - September 30, 1996..... 6,693,646 3,347 66,316 (2,952) 66,711
Stock acquired................... 2,085,100 ($25,163) (25,163)
Options exercised................ 105,000 52 745 797
Dividends........................ (1,446) (1,446)
Net income....................... 26,866 26,866
--------- ------ ------- -------- --------- -------- -------
Balance - September 30, 1997..... 6,798,646 3,399 67,061 22,468 2,085,100 (25,163) 67,765
Stock acquired................... 1,777,817 (28,644) (28,644)
Options exercised................ 5,000 3 61 64
Dividends........................ (1,688) (1,688)
Net income....................... 14,056 14,056
--------- ------ ------- -------- --------- -------- -------
Balance - September 30, 1998..... 6,803,646 $3,402 $67,122 $34,836 3,862,917 ($53,807) $51,553
========= ====== ======= ======== ========= ======== =======
Dividends per share were $.30 and $.45 in fiscal 1997 and 1998, respectively.
The accompanying notes are an integral part of these financial statements
-33-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
NOTE 1 -- BUSINESS AND ORGANIZATION
Business Segments
Castle Energy Corporation's ("the Company") principal lines of business
as of September 30, 1998 are natural gas marketing and oil and gas exploration
and production. Until September 30, 1995, the Company's major business segment
was refining. The Company's operations are conducted within the United States.
References to the Company mean Castle Energy Corporation, the parent,
and its subsidiaries. Such references are used for convenience and are not
intended to describe legal relationships.
Natural Gas Marketing
On December 3, 1992, the Company acquired from Atlantic Richfield
Company ("ARCO") a long-term natural gas sales agreement (the "Lone Star
Contract") with the Lone Star Gas Company ("Lone Star"), a 77-mile pipeline in
Rusk County, Texas (the "Castle Pipeline"), majority working interests in
approximately 100 producing oil and gas wells and several gas supply contracts.
The acquisition of the Castle Pipeline and the gas contracts created a new
business segment for the Company - the natural gas marketing and transmission
business.
The Lone Star Contract expires May 31, 1999. This contract provides for
minimum annual deliveries of gas at specific fixed prices, and also includes
certain minimum payments under take-or-pay provisions. The Company also entered
into a long-term contract with MG Natural Gas Corp. ("MGNG"), a subsidiary of
Metallgesellschaft Corp. ("MG"), to supply gas volumes needed for the Lone Star
Contract. This contract also expires May 31, 1999. The Company anticipates that
it will acquire the remaining gas volumes needed to supply the Lone Star
Contract through its expiration from MGNG.
In addition to the Lone Star Contract, a subsidiary of the Company
entered into a contract to sell 7,356 MMbtu's (million British thermal units) of
natural gas to MGNG at a fixed price from June 1, 1996 to May 31, 1999.
In May 1997, the Company sold the Castle Pipeline to a subsidiary of
Union Pacific Resources Company ("UPRC"). As part of the sale, the Company
entered into a transportation agreement with the UPRC subsidiary which provides
for the transportation of the remaining gas deliveries under the Lone Star
Contract (see Note 4). As a result of this sale, the Company no longer has
material operations in the natural gas transmission business.
Oil and Gas Exploration and Production
In May 1997, the Company sold the Rusk County, Texas oil and gas
properties it acquired from ARCO to UPRC. The reserves associated with such
properties constituted approximately 84% of the Company's proved oil and gas
reserves (see Note 4).
The Company's remaining oil and gas exploration and production assets at
September 30, 1998 include interests in 392 oil and gas wells located in eight
states. The Company is the operator of most of the wells. None of the Company's
gas production from these wells is sold to Lone Star.
Refining
IRLP
The Company indirectly entered the refining business in 1989 when one of
its subsidiaries acquired the operating assets of an idle refinery located in
Lawrenceville, Illinois (the "Indian Refinery"). The Indian Refinery was
subsequently operated by one of the Company's subsidiaries, Indian Refining I
Limited Partnership ("IRLP"), until September 30, 1995 when it was shut down. On
December 12, 1995, IRLP sold the Indian Refinery assets to American Western
Refining, L.P. ("American Western"). American Western subsequently filed for
bankruptcy and sold the Indian Refinery to an outside party which is in the
process of dismantling it.
-34-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
Powerine
In October 1993, a subsidiary of the Company purchased Powerine Oil
Company ("Powerine"), the owner of a refinery located in Santa Fe Springs,
California (the "Powerine Refinery") from MG. From October 1, 1993 to February
1, 1995, Powerine sold all of its refined products to MG Refining and Marketing,
Inc. ("MGRM"), a subsidiary of MG, under a product offtake agreement (the
"Powerine Offtake Agreement") subject to MGRM's obligation to purchase refined
products from raw materials on hand at the Powerine Refinery at (or subject to
contracts calling for delivery to the Powerine Refinery by) February 1, 1995.
MGRM's failure to purchase products refined after February 1, 1995 was at issue
in the Powerine Arbitration (see Note 14). On September 29, 1995, Powerine sold
substantially all of its refining plant to Kenyen Projects Limited ("Kenyen").
On January 16, 1996, Powerine merged into a subsidiary of Energy Merchant Corp.
("EMC") and EMC reacquired the refinery from Kenyen. EMC subsequently sold the
refinery to an outside party which, we are informed, is seeking financing to
restart it.
As a result of the transactions with American Western, Kenyen and EMC,
the Company disposed of its interests in the refining segment. The results of
refining operations were shown as discontinued operations in the Consolidated
Statement of Operations as of September 30, 1995 and retroactively. Discontinued
refining operations have not impacted operations since fiscal 1995.
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
The significant accounting policies discussed are limited to those
applicable to the Company's continuing business segments - natural gas marketing
and exploration and production. References should be made to previous Forms 10-K
for summaries of accounting principles applicable to the discontinued refining
segment.
Principles of Consolidation
The consolidated financial statements presented include the accounts of
the Company and all of its subsidiaries. All significant intercompany
transactions have been eliminated in consolidation.
Revenue Recognition
Natural Gas Marketing
Revenues are recorded when deliveries are made. Essentially all of
the Company's deliveries are made under two contracts, the Lone Star Contract
and a contract with MGNG.
Exploration and Production
Oil and gas revenues are recorded when oil and gas volumes are
delivered to the purchaser. Fees from well operations are recorded when earned.
Cash and Cash Equivalents
The Company considers all highly liquid investments, such as time
deposits and money market instruments, purchased with a maturity of three months
or less, to be cash equivalents.
Natural Gas Transmission
Natural gas transmission assets include gathering systems and pipelines.
They are stated at the lower of cost or impaired (fair market) value. They are
depreciated on a straight-line basis over fifteen years, their estimated useful
life.
-35-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
Marketable Securities
The Company classifies its investment securities as trading securities.
Pursuant to Statement of Financial Accounting Standards No. 115 ("SFAS 115"),
such securities are measured at fair market value in the financial statements
with unrealized gains or losses included in earnings.
Prepaid Gas Purchases
Prepaid gas purchases represent payments made by one of the Company's
subsidiaries for gas the subsidiary was required to take but did not. All
prepaid gas purchases relate to gas purchases from MGNG. Under the terms of the
related gas purchase contracts, the subsidiary is entitled to make up the
prepaid gas, i.e., to take it and not pay for it, once it has taken the required
minimum contract volume for the contract year. Prepaid gas purchase costs are
expensed as the subsidiary takes delivery of gas.
Furniture, Fixtures and Equipment
Furniture, fixtures and equipment are stated at the lower of cost or
impaired (fair market) value. Depreciation is recorded on a straight-line basis
over the estimated useful life of the assets. Furniture, fixtures and equipment
are depreciated on a straight-line basis over periods of three to ten years and
rolling stock is depreciated on a straight-line basis over four to five years,
the estimated useful lives of the assets.
Oil and Gas Properties
The Company follows the full-cost method of accounting for oil and gas
properties and equipment costs. Under this method of accounting, all productive
and nonproductive costs incurred in the acquisition, exploration and development
of oil and gas reserves are capitalized. Capitalized costs are amortized on a
composite unit-of-production method using estimates of proved reserves.
Capitalized costs which relate to unevaluated oil and gas properties are not
amortized until proved reserves are associated with such costs or impairment of
the property occurs. Management and drilling fees earned in connection with the
transfer of oil and gas properties to a joint venture and proceeds from the sale
of oil and gas properties are recorded as reductions in capitalized costs unless
such sales are material and involve a significant change in the relationship
between cost and the value of proved reserves in which case a gain or loss is
recognized. Expenditures for repairs and maintenance of wellhead equipment are
expensed as incurred. Net capitalized costs, less related deferred income taxes,
in excess of the present value of net future cash inflows (oil and gas sales
less production expenses) from proved reserves, tax-effected and discounted at
10%, if any, are charged to current expense.
Dismantlement, Restoration and Environmental Costs
The Company is subject to extensive federal, state and local
environmental laws and regulations. These laws, which are constantly changing,
regulate the discharge of materials into the environment and may require the
Company to remove or mitigate the environmental effects of the disposal or
release of petroleum or chemical substances at various sites. Environmental
expenditures are expensed or capitalized depending on their future economic
benefit. Expenditures that relate to an existing condition caused by past
operations and that have no future economic benefits are expensed. Liabilities
for expenditures of noncapital nature are recorded when environmental assessment
and/or remediation is probable, and the costs can be reasonably estimated.
Impairment of Long-Term Assets
The Company adopted Statement of Financial Accounting Standard No. 121,
"Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to Be
Disposed Of" during the second quarter of fiscal 1995. There was no effect from
such adoption. Accordingly, the Company reviews its long-term assets other than
oil and gas properties for impairment whenever events or changes in circumstance
indicate that the carrying amount of an asset may not be recoverable. If the sum
of the expected future cash flows expected to result from the use of the asset
and its eventual disposition is less than the
-36-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
carrying amount of the asset, an impairment loss is recognized. Measurement of
an impairment loss would be based on the fair market value of the asset.
Impairment for oil and gas properties is computed in the manner described above
under "Oil and Gas Properties."
Hedging Activities
The Company employs hedging strategies to hedge its future natural gas
purchase requirements for its gas sales contracts to Lone Star and MGNG (see
Notes 1 and 14). The Company hedges future commitments with natural gas swaps,
which are accounted for on a settlement basis. Gains and losses from hedging
activities are credited or debited to the item being hedged, the cost of gas
purchased for the Lone Star Contract or the gas contract with MGNG. In order to
qualify as a hedge, the change in fair market value of the hedging instrument
must be highly correlated to the corresponding changes in the hedged item. When
the hedging instrument ceases to qualify as a hedge, the change in fair value is
charged against or credited to operations.
Other Assets
Costs applicable to the issuance of debt are capitalized and amortized
using the interest method based upon the scheduled debt repayment terms.
Unamortized debt issuance costs are written off when the related debt is repaid.
Gas Contracts
The purchase price allocated to the Lone Star Contract was capitalized
and is being amortized over the term of the related contract, 6.5 years.
Gas Balancing
The Company operates under several natural gas sales contracts where one
interest owner is entitled to sell other owners' shares of natural gas produced
if such other owners do not elect to sell their shares of production. Under the
terms of the related joint operating agreements, the non-selling owners are
entitled to make up gas sales from the selling owner's share of production in
the future. The Company records sales of other owners' production as deferred
revenue and recognizes such deferred revenue when the other owners make up their
gas balancing deficiency from the Company's share of production. The Company
records sales of its production by other owners as deferred assets and
recognizes such deferred assets when the Company makes up its gas balancing
deficiency from the other owners' share of production. Deferred assets and
liabilities are recorded at cost at the production date.
Stock Based Compensation
Effective July 1, 1996, the Company adopted Statement of Financial
Accounting Standards No. 123, ("SFAS 123"). SFAS 123 allows an entity to
continue to measure compensation costs in accordance with Accounting Principle
Board Opinion ("APB") No. 25. The Company has elected to continue to measure
compensation cost in accordance with APB No. 25 and to comply with the required
disclosure-only provisions of SFAS 123.
Income Taxes
The Company follows Statement of Financial Accounting Standards No. 109
("SFAS 109"), "Accounting for Income Taxes." SFAS 109 is an accounting approach
that requires the recognition of deferred tax assets and liabilities for the
expected future tax consequences of events that have been recognized in the
Company's financial statements or tax returns. In estimating future tax
consequences, SFAS 109 generally considers all expected future events other than
anticipated enactments of changes in the tax law or rates (see Note 18). SFAS
109 also requires that tax provisions and recoveries related to changes in the
valuation reserve for deferred tax assets because of a change in circumstances
that causes a change in judgement about the realizability of the related
deferred tax asset in future years be allocated entirely to continuing
operations.
-37-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
Earnings Per Share
Basic earnings per common share are based upon the weighted average
number of common shares outstanding. Diluted earnings per common share are based
upon maximum possible dilution calculated using average stock prices during the
year.
In February 1997, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 128 ("SFAS 128"), "Earnings Per
Share," which establishes standards for computing and presenting earnings per
share ("EPS") for entities with publicly held common stock. SFAS 128 simplifies
the standards for computing EPS previously found in Accounting Principles Board
Opinion No. 15, "Earnings Per Share," and makes them comparable to international
EPS standards. It replaces the presentation of primary EPS with a presentation
of basic EPS, and requires dual presentations of basic and diluted EPS on the
face of the income statement. SFAS 128 is effective for fiscal years ending
after December 15, 1997, and early adoption is not permitted. The Company has
adopted SFAS 128 for the fiscal year ended September 30, 1998 and has
retroactively restated EPS for fiscal 1997 and 1996 in accordance with SFAS 128.
Reclassifications
Certain reclassifications have been made to make the periods presented
comparable.
Use of Estimates
The preparation of financial statements in accordance with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosures 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 these estimates.
New Accounting Pronouncements
In June 1997, FASB issued Statement of Financial Accounting Standards No.
130 ("SFAS 130") regarding reporting comprehensive income, which establishes
standards for reporting and display of comprehensive income and its components.
The components of comprehensive income refer to revenues, expenses, gains and
losses that are excluded from net income under current accounting standards,
including foreign currency translation items, minimum pension liability
adjustments and unrealized gains and losses on certain investments in debt and
equity securities. SFAS 130 requires that all items recognized under accounting
standards as components of comprehensive income be reported in a financial
statement displayed in equal prominence with the other financial statements; the
total of other comprehensive income for a period is required to be transferred
to a component of equity that is separately displayed in a statement of
financial condition at the end of an accounting period. SFAS 130 is effective
for both interim and annual periods for companies having fiscal years beginning
after December 15, 1997. Reclassification of financial statements for earlier
periods provided for comparative purposes is required. The Company will adopt
SFAS 130 for the fiscal year ending September 30, 1999.
In June 1997, FASB issued Financial Accounting Standards Board No. 131
("SFAS 131") regarding disclosures about segments of an enterprise and related
information. SFAS 131 establishes standards for reporting information about
operating segments in annual financial statements and requires the reporting of
selected information about operating segments in interim financial reports
issued to stockholders. It also establishes standards for related disclosures
about products and services, geographic areas and major customers. SFAS 131 is
effective for companies having fiscal years beginning after December 15, 1997.
The Company will adopt SFAS No. 131 for the fiscal year ending September 30,
1999.
Statement of Financial Accounting Standards No. 133, Accounting for
Derivative Instruments and Hedging Activities ("SFAS 133"), was issued by the
Financial Accounting Standards Board in June 1998. SFAS 133 standardizes the
accounting for derivative instruments, including certain derivative instruments
embedded in other contracts. Under the standard, entities are required to carry
all derivative instruments in the statement of financial position at fair value.
The accounting for changes in the fair value (i.e., gains or losses) of a
derivative instrument depends on whether it has been designated and qualifies as
part of a hedging relationship and, if so, the reason for holding it. If
certain conditions are met, entities may elect to
-38-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
designate a derivative instrument as a hedge of exposures to changes in fair
values, cash flows, or foreign currencies. If the hedged exposure is a fair
value exposure, the gain or loss on the derivative instrument is recognized in
earnings in the period of change together with the offsetting loss or gain on
the hedged item attributable to the risk being hedged. If the hedged exposure is
a cash flow exposure, the effective portion of the gain or loss on the
derivative instrument is reported initially as a component of other
comprehensive income (outside earnings) and subsequently reclassified into
earnings when the forecasted transaction affects earnings. Any amounts excluded
from the assessment of hedge effectiveness, as well as the ineffective portion
of the gain or loss, is reported in earnings immediately. Accounting for foreign
currency hedges is similar to the accounting for fair value and cash flow
hedges. If the derivative instrument is not designated as a hedge, the gain or
loss is recognized in earnings in the period of change.
The Company expects to adopt SFAS 133 in fiscal 2000. To date all hedging
by the Company has been applicable to the Company's gas marketing operations.
Those operations are expected to end on May 31, 1999 when the related gas
contracts terminate. As a result, the Company believes SFAS 133 will not affect
existing operations and cannot make a determination as to whether it will effect
future operations until it engages in such operations.
The Company believes that adoption of these financial accounting
standards will not have a material effect on its financial condition or results
of operations.
NOTE 3 - DISCONTINUED REFINING OPERATIONS
Effective September 30, 1995, the Company's refining subsidiaries
discontinued their refining operations.
An analysis of the assets and liabilities related to the refining
segment for the period October 1, 1995 to September 30, 1998 is as follows:
Estimated
Realizable Value
of Discontinued Net Refining
Net Refining Assets Liabilities Retained
------------------- --------------------
Balance - October 1, 1995........................................ $10,803 $20,342
Cash transactions................................................ (4,000) (9,263)
Other, net....................................................... (515)
------- -------
Balance - September 30, 1996..................................... 6,288 11,079
Recovery related to the MG SWAP litigation....................... 703
Provision for platinum recovery.................................. (100)
Provision for American Western Note.............................. (2,469)
Cash transactions................................................ (1,860)
Adjustments to vendor liabilities................................ (1,722)
Other............................................................ (144)
------- -------
Balance - September 30, 1997..................................... 4,422 7,353
Reduction in estimated platinum recovery......................... (364)
Excess of MG Note over actual recovery in Powerine
Arbitration.............................................. (1,300)
Recovery of platinum proceeds.................................... (435)
Adjustment of vendor liabilities................................. (732)
Cash transactions................................................ (192)
------- -------
Balance - September 30, 1998..................................... $ 3,623 $ 5,129
======= =======
As of September 30, 1998, the estimated realizable value of discontinued
net refining assets consists of $2,919 of estimated recoverable proceeds from
the American Western note and $704 of estimated recoveries from the SWAP
Litigation (see Note 14). The estimated value of net refining liabilities
retained consists of vendor liabilities of $3,623 and accrued costs related to
discontinued refining operations of $1,506.
-39-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
"Estimated realizable value of discontinued net refining assets" is
based on the transactions consummated by the Company with American Western and
EMC and transactions consummated by American Western and EMC subsequently and
includes management's best estimates of the amounts expected to be realized on
the disposal of the refining segment. "Net refining liabilities retained"
includes management's best estimates of amounts expected to be paid and amounts
expected to be realized on the settlement of this net liability. The amounts the
Company ultimately realizes or pays could differ materially in the near term
from such amounts.
NOTE 4 - SALE OF ASSETS
On May 30, 1997, the Company consummated the sale of its Texas oil and
gas properties and pipeline to UPRC and Union Pacific Intrastate Pipeline
Company ("UPIPC"), a wholly-owned subsidiary of UPRC, respectively. The
effective date of the sale was May 1, 1997. The assets sold include
approximately 8,150 net acres, 100 producing oil and gas wells and a 77-mile
pipeline which gathers gas from the producing wells and delivers it to a
pipeline owned by Lone Star. The proved reserves associated with the oil and gas
properties that were sold comprised approximately 84% of the Company's proved
reserves. The Company still owns its non-Texas oil and gas properties and its
gas sales contracts with Lone Star and MGNG.
Both contracts expire on May 31, 1999.
The purchase price received by the Company was $54,759 and consisted of
$50,184 cash, $1,575 of liabilities assumed by UPRC and $3,000 of prepaid gas
transportation expense. The gas transportation prepayment relates to
transportation of natural gas that the Company is required to supply to Lone
Star through May 31, 1999. As a result of the sale, the Company realized a gain
of $19,667 in fiscal 1997.
NOTE 5 - RESTRICTED CASH
Restricted cash consists of the following:
September 30,
------------------------
1998 1997
---- ----
Funds supporting letters of credit issued for operating bonds................. $218 $217
Other......................................................................... 395 280
---- ----
$613 $497
==== ====
NOTE 6 - ACCOUNTS RECEIVABLE
Based upon past customer experiences, the limited number of customer
accounts receivable relationships, and the fact that the Company's subsidiaries
can generally offset unpaid accounts receivable against an outside owner's share
of oil and gas revenues, management believes substantially all receivables are
collectible. Accounts receivable consist of the following:
September 30,
------------------------
1998 1997
---- ----
Natural gas marketing......................................................... $6,870 $3,844
Oil and gas................................................................... 1,343 1,364
Other......................................................................... 168 660
------ ------
$8,381 $5,868
====== ======
Accounts receivable due from Lone Star aggregated $6,719 and $3,441 at
September 30, 1998 and 1997, respectively.
-40-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
NOTE 7 - MARKETABLE SECURITIES AND NOTE RECEIVABLE - PENN OCTANE CORPORATION
The Company's marketable securities consist of 301,000 shares of the
common stock of Penn Octane Corporation ("Penn Octane"), a public company. The
gross cost, unrealized loss and net book value as of September 30, 1998 are as
follows:
Gross cost................................................ $575
Unrealized loss........................................... (104)
----
Balance - September 30, 1998.............................. $471
====
The unrealized loss has been charged to earnings.
In October 1997, the Company invested $1,000 in a promissary note of
Penn Octane. The note bears interest at 10% payable quarterly and was due on
June 30, 1998. At June 30, 1998, Penn Octane did not repay the note. In May of
1998, Penn Octane was awarded a judgement against a bank and such judgement is
in excess of the $1,000 owed to the Company by Penn Octane. In December of 1998,
Penn Octane assigned its interest in the bank judgement to the extent of the
Company's note to the Company in return for an extension of the note until June
30, 1999 and for warrants to buy 225,000 shares of Penn Octane common stock at
one dollar and seventy-five cents per share. The bank owing the judgement has
appealed it and such appeal may not be resolved for a year or more. As a result,
there can be no assurance that the judgement will be upheld upon appeal or that
the bank will ultimately pay the judgement won by Penn Octane to the Company. If
the note is not repaid by its extended due date, the Company intends to reduce
the Penn Octane note to its estimated realizable value, if any.
NOTE 8 - FURNITURE, FIXTURES AND EQUIPMENT
Furniture, fixtures and equipment are as follows:
September 30,
---------------------
1998 1997
---- ----
Cost
Furniture and fixtures.......................... $532 $426
Automobile and trucks........................... 76
---- ----
608 426
Accumulated depreciation........................ (301) (246)
---- ----
$307 $180
==== ====
NOTE 9 - GAS CONTRACTS
Gas contracts consist of the following:
September 30,
------------------------
1998 1997
---- ----
Gas contracts................................... $61,151 $61,151
Less: Accumulated amortization.................. (54,866) (45,404)
------- -------
$ 6,285 $15,747
======= =======
-41-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
NOTE 10 - OIL AND GAS PROPERTIES
Oil and gas properties consist of the following:
September 30,
-------------------------
1998 1997
----- ----
Proved properties......................................................... $12,367 $10,118
Less: Accumulated depreciation, depletion and amortization............ (7,885) (7,418)
Accumulated full cost ceiling reserve..................................... (97) (97)
------- -------
4,385 2,603
Unproved properties....................................................... 215 215
------- -------
$ 4,600 $ 2,818
======= =======
Capital costs incurred by the Company in oil and gas activities, all of
which are located in the United States, are as follows:
Year Ended September 30,
------------------------------------------
1998 1997 1996
---- ---- ----
Purchase of proved properties....................................... $ 59
Property acquisition costs - proved properties...................... $ 17 215
Development costs................................................... 2,195 1,266 $34
------- ------- ---
$2,212 $1,540 $34
====== ====== ===
Results of operations, excluding corporate overhead and interest
expense, from the Company's oil and gas producing activities are as follows:
Year Ended September 30,
-----------------------------------------
1998 1997 1996
---- ---- ----
Revenues:
Crude oil, condensate, natural gas liquids and natural gas
sales......................................................... $2,373 $6,740 $8,782
------ ------ ------
Costs and expenses:
Production costs................................................ 775 1,940 2,045
Depreciation, depletion and amortization........................ 367 1,560 2,311
------ ------ ------
Total costs and expenses........................................ 1,142 3,500 4,356
------ ------ ------
Income tax provision................................................ 443 1,166 1,593
------ ------ ------
Income from oil and gas producing activities........................ $ 788 $2,074 $2,833
====== ====== ======
The income tax provision is computed at a blended rate (Federal and
state combined) of 36%.
Assuming conversion of oil and gas production into common equivalent
units of measure on the basis of energy content, depletion rates per equivalent
MCF (thousand cubic feet) of natural gas were as follows:
Year Ended September 30,
--------------------------------------------
1998 1997 1996
---- ---- ----
Depletion rate per equivalent MCF of natural gas.................... $0.37 $ 0.58 $ 0.64
===== ======= =======
The significant decrease in the depletion rate in fiscal 1998 results
from the Company's sale of its oil and gas assets to UPRC in May 1997. After the
sale, the cost per cubic foot equivalent of natural gas for the Company's
remaining reserves was significantly less than before the sale as a result of
accounting for the sale to UPRC under the full cost method.
-42-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
NOTE 11 - PROVED OIL AND GAS RESERVES AND RESERVE VALUATION (UNAUDITED)
Reserve estimates are based upon subjective engineering judgements made
by the Company's independent petroleum reservoir engineers, Huntley & Huntley
(fiscal 1998, 1997 and 1996) and Ryder Scott Company Petroleum Engineers (fiscal
1996), and may be affected by the limitations inherent in such estimations. The
process of estimating reserves is subject to continuous revisions as additional
information is made available through drilling, testing, reservoir studies and
production history. There can be no assurance such estimates will not be
materially revised in subsequent periods.
Estimated quantities of proved reserves and changes therein, all of which
are domestic reserves, are summarized below:
Oil (BBLS) Natural Gas (MCF)
---------- -----------------
Proved developed and undeveloped reserves:
As of October 1, 1995......................................... 351 56,568
Revisions of previous estimates............................ 157 16,410
Production................................................. (46) (3,349)
--- -------
As of September 30, 1996...................................... 462 69,629
Revisions of previous estimates............................ 59 5,591
Sale of minerals in place.................................. (279) (57,074)
Production................................................. (36) (2,454)
--- -------
As of September 30, 1997...................................... 206 15,692
Revisions of previous estimates............................ 69 501
Production................................................. (20) (869)
--- -------
As of September 30, 1998...................................... 255 15,324
=== =======
Proved developed reserves:
September 30, 1995............................................ 248 31,535
=== =======
September 30, 1996............................................ 312 34,764
=== =======
September 30, 1997............................................ 206 11,480
=== =======
September 30, 1998............................................ 162 13,589
=== =======
The revisions of previous estimates result from significant additions of
proved undeveloped and proved developed non-producing reserves.
All of the Company's oil and gas reserves are located in United States.
The following is a standardized measure of discounted future net cash
flows and changes therein relating to estimated proved oil and gas reserves, as
prescribed in Statement of Financial Accounting Standards No. 69. The
standardized measure of discounted future net cash flows does not purport to
present the fair market value of the Company's oil and gas properties. An
estimate of fair value would also take into account, among other factors, the
likelihood of future recoveries of oil and gas in excess of proved reserves,
anticipated future changes in prices of oil and gas and related development and
production costs, a discount factor based on market interest rates in effect at
the date of valuation and the risks inherent in reserve estimates.
September 30,
--------------------------------------------
1998 1997 1996
---- ---- ----
Future cash inflows................................................ $40,576 $46,595 $138,327
Future production costs............................................ (14,141) (13,979) (46,835)
Future development costs........................................... (1,283) (2,025) (31,195)
Future income tax expense.......................................... (4,868) (7,045) (7,451)
------- ------- --------
Future net cash flows.............................................. 20,284 23,546 52,846
Discount factor of 10% for estimated timing of future cash flows... (10,338) (12,779) (28,352)
------- ------- --------
Standardized measure of discounted future cash flows............... $ 9,946 $10,767 $ 24,494
======= ======= ========
-43-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
The future cash flows were computed using the applicable year-end prices
and costs that related to then existing proved oil and gas reserves in which the
Company has mineral interests. The estimates of future income tax expense are
computed at the blended rate (Federal and state combined) of 36%.
The following were the sources of changes in the standardized measure of
discounted future net cash flows:
September 30,
-------------------------------------------
1998 1997 1996
---- ---- ----
Standardized measure, beginning of year............................. $10,767 $24,494 $21,373
Sale of oil and gas, net of production costs........................ (1,598) (4,800) (6,737)
Net changes in prices............................................... (2,498) 1,461 2,094
Sale of reserves in place........................................... (17,849)
Changes in estimated future development costs....................... (615) (120) (2,617)
Development costs incurred during the period that reduced future
development costs................................................ 2,195 349
Revisions in reserve quantity estimates............................. 594 4,675 10,391
Net changes in income taxes......................................... 831 529 66
Accretion of discount............................................... 1,077 2,449 2,137
Other, principal changes in timing of production.................... (807) (421) (2,213)
------- ------- -------
Standardized measure, end of year................................... $ 9,946 $10,767 $24,494
======= ======= =======
NOTE 12 -ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES
Accrued expenses consist of the following:
September 30,
--------------------------
1998 1997
---- ----
Officer retention.................................................................... $ 567 $1,032
Employee related costs............................................................... 19 23
Taxes, including payroll taxes....................................................... 353 127
Other................................................................................ 724 75
------ ------
$1,663 $1,257
====== ======
NOTE 13 - ENVIRONMENTAL MATTERS
In December 1995, IRLP sold the Indian Refinery to American Western. As
part of the related purchase and sale agreement, American Western assumed all
environmental liabilities and indemnified the Company with respect thereto.
Subsequently American Western filed for bankruptcy and sold the Indian Refinery
to an outside party pursuant to a bankruptcy proceeding. The new owner is
currently dismantling the Indian Refinery.
During fiscal 1998, the Company was also informed that the United States
Environmental Protection Agency ("EPA") has investigated offsite acid sludge
waste found near the Indian Refinery and was also investigating and remediating
surface contamination in the Indian Refinery property. Neither the Company nor
IRLP was named with respect to these two actions.
In October 1998, the EPA named the Company and two of its refining
subsidiaries as potentially responsible parties for the expected clean-up of the
Indian Refinery. In addition, eighteen other parties were named including Texaco
Refining and Marketing, Inc., the refinery operator for over 50 years. The
Company subsequently responded to the EPA indicating that it was neither the
owner nor operator of the Indian Refinery and thus not responsible for its
remediation. Estimated undiscounted clean-up costs for the Indian Refinery are
$80,000 - $150,000, according to third parties. A recent decision by the U.S.
Supreme Court has supported the Company's position. Although the Company does
not believe it has any liabilities with respect to the environmental liabilities
of the refineries, a court of competent jurisdiction may find otherwise.
-44-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
In September 1995, Powerine sold the Powerine Refinery to Kenyen. In
January 1996, Powerine merged into a subsidiary of EMC and EMC assumed all
environmental liabilities. In August 1998, EMC sold the Powerine Refinery to a
third party which is seeking financing to restart the Powerine Refinery. In July
of 1996, the Company was named a defendant in a class action lawsuit concerning
emissions from the Powerine Refinery. In April of 1997, the court granted the
Company's motion to quash the plaintiff's summons based upon lack of
jurisdiction and the Company is no longer involved in the case.
Although the environmental liabilities related to the Indian Refinery
and Powerine Refinery have been transferred to others, there can be no assurance
that the parties assuming such liabilities will be able to pay them. American
Western, owner of the Indian Refinery, filed for bankruptcy and is in the
process of liquidation. EMC, which assumed the environmental liabilities of
Powerine, sold the Powerine Refinery to an unrelated party. Furthermore, the
Company and two of its subsidiaries have been named as potentially responsible
parties with respect to the Indian Refinery by the EPA.
If funds for environmental clean-up are not provided by these former
and/or present owners, it is possible that the Company and/or one of its former
refining subsidiaries could be named a party in additional legal actions to
recover remediation costs. In recent years, government and other plaintiffs have
often sought redress for environmental liabilities from the party most capable
of payment without regard to responsibility or fault. Whether or not the Company
is ultimately held liable in such a circumstance, should litigation involving
the Company and/or IRLP occur, the Company would probably incur substantial
legal fees and experience a diversion of management resources from other
operations.
Although the Company does not believe it is liable for any of its
subsidiaries' clean-up costs and intends to vigorously defend itself in such
regard, the Company cannot predict the ultimate outcome of these matters due to
inherent uncertainties.
NOTE 14- COMMITMENTS AND CONTINGENCIES
Operating Lease Commitments
The Company has the following noncancellable operating lease commitments
and noncancellable sublease rentals at September 30, 1998:
Lease Sublease
Year Ending September 30, Commitments Rentals
- ------------------------- ----------- ---------
1999.................................. $ 281 $ 60
2000.................................. 313 63
2001.................................. 313 64
2002.................................. 284 65
2003.................................. 249 66
Thereafter............................ 34 11
------ ----
$1,474 $329
====== ====
Rent expense for the years ended September 30, 1998, 1997 and 1996 was
$245, $200 and $236, respectively.
Severance/Retention Obligations
The Company and one of its subsidiaries have severance agreements with
substantially all of their employees that provide for severance compensation in
the event substantially all of the Company's or the subsidiary's assets are sold
and the employees are terminated as a result of such sale. Such termination
severance commitments aggregated $1,234 at September 30, 1998. No severance
obligations are outstanding at September 30, 1998. In addition, in the case of
four of its officers, such
-45-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
severance agreements include retention clauses that provide that the officers
will receive one year's compensation if they remained with the Company through
June 1, 1998 - whether or not they are terminated. As of September 30, 1998
accrued retention obligations totaled $567.
Letters of Credit
At September 30, 1998, the Company had issued letters of credit of $218
for oil and gas drilling, operating and plugging bonds. The letters of credit
are renewed semi-annually or annually.
At September 30, 1998, the Company had also guaranteed up to $500 of gas
purchase obligations of one of its subsidiaries. The guaranty expires May 31,
1999.
Long Term Supply Commitments
The Company has a long-term gas supply contract with MGNG. This contract
requires the Company to purchase fixed gas volumes from MGNG at fixed prices.
The Company anticipates that it will purchase all gas supplies needed for the
Lone Star Contract, through its expiration, from MGNG. Aggregate future purchase
commitments under this long-term supply commitment with MGNG are approximately
as follows:
MMBTU's
(British Thermal Units)
-----------------------
Year Ending September 30,
- -------------------------
1999.................................... 12,637
======
If MGNG fails to perform its obligations under this contract, there is
no assurance that the Company's marketing subsidiary could fulfill its
obligations under the Lone Star Contract in a manner which would permit the
subsidiary to maintain its current profit margin on sales of natural gas.
The Company also has a commitment to sell 7,356 MMbtu's of natural gas
at a fixed price from June 1, 1996 to May 31, 1999 to MGNG. The Company
anticipates supplying the gas from gas purchases on the spot market including
gas purchased from MGNG. The Company's remaining obligations to sell natural gas
to MGNG at September 30, 1998 are as follows:
MMBTU's
(British Thermal Units)
-----------------------
Year Ending September 30,
- -------------------------
1999.................................... 1,632
=====
At September 30, 1998, Castle Texas Production Limited Partnership
("Production"), a wholly-owned subsidiary limited partnership of the Company,
had entered fixed price contracts to hedge all of the unhedged gas supply for
both the Lone Star Contract and the gas supply contract with MGNG.
At September 30, 1998, the market value of the hedges was $419. In
addition, Production has also provided a hedging margin account deposit
consisting of certificates of deposit, for $395.
-46-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
The notional dollar amounts and volumes related to fixed price swap
contracts for natural gas were as follows:
September 30, 1998
-----------------------
$ MMbtu
- -----
Fixed price contracts to buy gas.............. $9,960 4,210
====== =====
Fixed price contracts to sell gas............. $4,592 1,840
====== =====
Lone Star Contract
The Company's natural gas marketing segment sells 88% of gas volumes it
purchases to Lone Star. Sales to Lone Star by the natural gas marketing segment,
including sales of gas volumes produced by one of the Company's exploration and
production subsidiaries through May 31, 1997, aggregated $64,619, $63,118 and
$62,140 for the fiscal years ended September 30, 1998, 1997 and 1996,
respectively. At September 30, 1998, approximately 12,451 MMbtu's remained to be
sold to Lone Star. All of Lone Star's requirements are currently provided to the
Company's natural gas marketing segment by MGNG. If MGNG were to fail to perform
its supply obligations under a long-term gas supply agreement, there could be no
assurance that the Company could fulfill its remaining gas sales obligations
under the Lone Star Contract in a manner which would permit the Company to
maintain its current profit margin on such sales.
Management Agreements
The Company entered into two long-term management agreements with a
subsidiary of Terrapin Resources, Inc. ("Terrapin") to provide accounting and
management with respect to the Company's exploration and production assets and
to provide corporate accounting services. Terrapin is wholly-owned by an officer
of the Company.
In June 1997, the Company purchased one of these contracts for $692 in
conjunction with the sale of its Rusk County, Texas oil and gas properties to
UPRC (see Note 4). Terrapin had provided the accounting and land services with
respect to such properties prior to the sale to UPRC. The other contract expired
in June 1996 and was extended on a month to month basis.
Effective June 30, 1998, the Company exercised its option to acquire
Terrapin's accounting software and computer equipment for one dollar. The
Company also hired virtually all Terrapin employees (see Note 19). As a result
the Company now performs the accounting and land services in-house.
Legal Proceedings
Powerine Arbitration
In June 1997, an arbitrator ruled in the Company's favor in an
arbitration hearing concerning a contract dispute between MGNG and Powerine
which had been assigned to the Company. In October 1997, the Company recovered
$8,700 from the arbitration. The Company believes it is entitled to an
additional $2,142 plus interest and its special legal counsel presented
arguments to the arbitrator to recover this amount. On January 27, 1998, the
arbitrator ruled against the Company. The Company is currently pursuing other
measures to recover the $2,142 plus interest.
SWAP Agreement - MGNG
In January 1998, IRLP filed suit against MGR&M to collect $704 plus
interest. The dispute concerns funds belonging to IRLP but received and held by
MGR&M. In February 1998, MG contended that the $704 is not owed to IRLP and that
it had liquidated MGR&M. Management and special counsel believe that IRLP has a
strong breach of contract claim against MGR&M and that MG's counterclaims are
not supported by the facts or Delaware law. Discovery related to the lawsuit is
commencing. IRLP intends to file an amended complaint and pursue all other
available legal remedies in the near future.
-47-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
MGNG Litigation
On May 4, 1998, a subsidiary of the Company filed a lawsuit against MGNG
and MG Gathering Company ("MGC"), two subsidiaries of MG, in the district court
of Harris County, Texas. The Castle subsidiary seeks to recover gas measurement
and transportation expenses charged by the defendants in breach of a certain gas
purchase contract. Improper charges exceed $750 before interest. In October of
1998, MGNG and MGC filed a suit in Harris County, Texas. The suit seeks
indemnification from two of the Company's subsidiaries in the event the
Company's subsidiary wins the lawsuit against MGNG and MGC. The MG entities have
cited no basis for their claim of indemnification. The Company and special
counsel believe that the Company's subsidiary is entitled to at least $750 plus
interest and that the Company's two subsidiaries have no indemnification
obligations to MGNG or MGC. The Company intends to pursue this case using all
legal remedies.
Larry Long Litigation
In May 1996, Larry Long, representing himself and allegedly "others
similarly situated," filed suit against the Company, three of the Company's
natural gas marketing and transmission and exploration and production
subsidiaries, ARCO, B&A Pipeline Company (a former subsidiary of ARCO), and MGNG
in the Fourth Judicial District Court of Rusk County, Texas. The plaintiff
originally claimed, among other things, that the defendants underpaid
non-operating working interest owners, royalty interest owners, and overriding
royalty interest owners with respect to gas sold to Lone Star Gas Company ("Lone
Star") pursuant to a long-term contract ("Lone Star Contract"). Although no
amount of actual damages was specified in the plaintiff's initial pleadings, it
appeared that, based upon the volumes of gas sold to Lone Star, the plaintiff
may have been seeking actual damages in excess of $40,000.
After some initial discovery, the plaintiff's pleadings were
significantly amended. Another purported class representative, Travis Crim, was
added as a plaintiff, and ARCO, B&A Pipeline Company and MGNG were dropped as
defendants. Although it is not completely clear from the amended petition, the
plaintiffs have apparently now limited their proposed class of plaintiffs to
royalty owners and overriding royalty owners in leases owned by the Company's
exploration and production subsidiary limited partnership. In amending their
pleadings, the plaintiffs revised their basic claim to seeking royalties on
certain operating fees paid by Lone Star to the Company's natural gas marketing
subsidiary limited partnership. No hearing has been held on the plaintiffs'
request for class certification, however. After a lengthy period of inactivity
the plaintiff's counsel has only recently sought to continue or settle the case.
The case is still in its preliminary stages. No class has been certified and no
trial date set.
Based upon the revised pleadings, management of the Company initially
determined that the possible exposure of the Company and its subsidiary limited
partnerships for all gas sold to Lone Star in the past and in the future, were
they to lose the case, was less than $3,000. However, the Company sold all of
its Rusk County oil and gas properties to Union Pacific Resources Company
("UPRC") in May of 1997. The sale to UPRC effectively removed any possibility of
exposure by the Company or its subsidiary limited partnerships to claims for
additional royalties with respect to future production, thus reducing the
exposure of the Company and its subsidiaries to less than $2,000 in actual
damages if they were to lose the case on all points.
EMC Litigation
In August 1998, the Company obtained a judgement against EMC for $330
plus $57 interest. The judgement relates to EMC's failure to pay third parties
it was obligated to pay and which the Company had to pay in its place.
Subsequently, EMC had the judgement vacated. The Company's management believes
it is entitled to the $330 plus $57 interest and that EMC simply is engaging in
legal tactics to avoid paying the Company. Legal counsel retained by the Company
is seeking to discover and attach EMC's assets and restore the judgement against
EMC.
-48-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
Powerine Class Action Lawsuit
In July 1996, Powerine was served with a suit concerning operations of
the Powerine Refinery in the Superior Court of the State of California in Los
Angeles, California. The suit claims the Powerine Refinery is a public nuisance,
that it has released excessive toxic and noxious emissions and caused physical
and emotional distress and property damage affecting residents living nearby.
The Company was also named as a defendant in the suit. In March 1997, the
Company was served with the lawsuit. In April 1997, the Company filed a notion
to quash the plaintiffs' summons based upon the lack of jurisdiction. On May 2,
1997, the court granted the Company's motion. As a result, the Company is no
longer a defendant in the Powerine Class Action Lawsuit.
Stockholder Litigation Recovery
In December 1995, the Company received $2,725 from a plaintiff class
escrow fund related to stockholder litigation. The parties reached a settlement
with respect to the stockholder litigation in October 1994. The proceeds to the
Company represent unclaimed funds that were to revert to the Company pursuant to
the Settlement Order for the litigation. The recovery is shown as "Other Income"
in the Consolidated Statement of Operations.
NOTE 15 -- EMPLOYEE BENEFIT PLAN
401-K PLAN
On October 1, 1995, the Company adopted a 401(k) plan (the "Plan") for
its employees and those of its subsidiaries. All employees are eligible to
participate. Employees participating in the Plan can authorize the Company to
contribute up to 15% of their gross compensation to the Plan. The Company
matches such voluntary employee contributions up to 3% of employee gross
compensation. Employees' contributions to the Plan cannot exceed thresholds set
by the Secretary of the Treasury. Vesting of Company contributions is immediate.
During the years ended September 30, 1998, 1997 and 1996, the Company's
contributions to the Plan aggregated $23, $38 and $26, respectively.
Post Retirement Benefits
Neither the Company nor its subsidiaries provide any other post
retirement plans for employees.
NOTE 16 -- STOCKHOLDERS' EQUITY
In fiscal 1997 and fiscal 1998, the Company's Board of Directors
authorized the Company to purchase up to 4,250,000 of its outstanding shares of
common stock on the open market. As of September 30 and November 20 , 1998,
3,862,917 shares had been repurchased at a cost of $53,807. The repurchased
shares are held in treasury.
On June 30, 1997, the Company's Board of Directors approved a dividend
policy of $.60 per share per year, payable quarterly. The dividend policy
remains in effect until rescinded or changed by the Board of Directors.
Quarterly dividends of $.15 per share have subsequently been paid.
-49-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
NOTE 17 -- STOCK OPTIONS AND WARRANTS
Option and warrant activities during each of the three years ended
September 30, 1998 are as follows (in whole units):
Non- Incentive
Incentive Qualified Plan Other
Warrants Options Options Options Options Total
-------- --------- --------- --------- ------- -----
Outstanding-October 1, 1995................ 22,500 2,500 67,500 543,834 135,000 771,334
Issued..................................... 10,000 15,000 25,000
Expired.................................... (22,500) (270,834) (15,000) (308,334)
Cancelled.................................. (100,000) (100,000)
------- ------ ------- ---------- -------- --------
Outstanding - September 30, 1996........... 2,500 77,500 288,000 20,000 388,000
Issued..................................... 57,000 20,000 77,000
Exercised.................................. (2,500) (67,500) (35,000) (105,000)
Cancelled.................................. (10,000) (10,000)
Expired.................................... (147,500) (15,000) (162,500)
------- ------ ------- --------- -------- --------
Outstanding at September 30, 1997.......... 162,500 25,000 187,500
Issued..................................... 55,000 55,000
Exercised.................................. (5,000) (5,000)
Repurchased................................ (17,500) (5,000) (22,500)
Expired....................................
------- ------- ------- --------- -------- --------
Outstanding at September 30, 1998.......... 195,000 20,000 215,000
======= ======= ======= ========= ======== ========
Exercisable at September 30, 1998.......... 155,000 20,000 175,000
========= ======== ========
Become exercisable during fiscal year ended:
September 30, 1999.................. 40,000 40,000
September 30, 2000..................
September 30, 2001..................
--------- -------- --------
40,000 40,000
========= ======== ========
Reserved at September 30, 1998............. 562,500 20,000 582,500
======= ======= ======= ========= ======== ========
Reserved at September 30, 1997............. 562,500 25,000 587,500
======= ======= ======= ========= ======== ========
Reserved at September 30, 1996............. 2,500 77,500 562,500 20,000 662,500
======= ======= ======= ========= ======== ========
Exercise prices at:
September 30, 1998.................. N/A N/A N/A $10.25- $10.75-
$17.25 $11.375
September 30, 1997.................. N/A N/A N/A $ 8.44- $11.00-
$14.25 $11.375
September 30, 1996.................. N/A $6.00 $6.00- $ 8.44- $11.00
$8.00 $14.25
Exercise Termination Dates.......... N/A N/A N/A 5/17/2003- 6/30/1999- 6/30/1999-
7/22/2008 4/23/2007 7/22/2008
In fiscal 1993, the Company adopted the 1992 Executive Equity Incentive
Plan (the "Incentive Plan"). The purpose of the Incentive Plan is to increase
the ownership of common stock of the Company by those non-union key employees
(including officers and directors who are officers) and outside directors who
contribute to the continued growth, development and financial success of the
Company and its subsidiaries, and to attract and retain key employees and reward
them for the Company's profitable performance.
The Incentive Plan provides that an aggregate of 562,500 shares of
common stock of the Company will be available for awards in the form of stock
options, including incentive stock options and non-qualified stock options
generally at prices at or in excess of market prices at the date of grant.
-50-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
The Incentive Plan also provides that each outside director of the
Company will annually be granted an option to purchase 5,000 shares of common
stock at fair market value on the date of grant.
The Company applies Accounting Principles Board Opinion Number 25 in
accounting for options and warrants and accordingly recognizes no compensation
cost for its stock options and warrants for grants with an exercise price equal
to the current fair market value. The following reflect the Company's pro-forma
net income and net income per share had the Company determined compensation
costs based upon fair market values of options and warrants at the grant date
pursuant to SFAS 123 as well as the related disclosures required by SFAS 123.
A summary of the Company's stock option and warrant activity from
October 1, 1996 to September 30, 1998 is as follows:
Weighted
Average
Warrants Options Total Price
-------- ------- ----- --------
Balance outstanding - October 1, 1996...... 388,000 388,000 10.59
Issued..................................... 77,000 77,000 10.78
Exercised.................................. (105,000) (105,000) 7.60
Cancelled.................................. (10,000) (10,000) 8.00
Expired.................................... (162,500) (162,500) 11.50
------- -------- -------- -----
Outstanding - September 30, 1997........... 187,500 187,500 11.69
Issued..................................... 55,000 55,000 16.23
Exercised.................................. (5,000) (5,000) 12.65
Repurchased................................ (22,500) (22,500) 10.43
------- -------- -------- -----
Outstanding - September 30, 1998........... 215,000 215,000 12.96
======= ======== ======== =====
At September 30, 1998 exercise prices for outstanding options ranged
from $10.25 to $17.25. The weighted average remaining contractual life of such
options was seven years.
The per share weighted average fair values of stock options issued
during fiscal 1998 , fiscal 1997 and fiscal 1996 were $3.92, $2.84 and $2.19,
respectively, on the date of issuance using the Black-Scholes option pricing
model with the following weighted average assumptions: expected dividend yield -
3.6% in 1998 and 4.3% in 1997 and 1996; risk free interest rate - 5.03% in 1998
and 5.81% in 1997 and 1996; expected life of 10 years and volatility factor of
.24 in 1998 and .30 in 1997 and 1996.
The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. Because the Company's employee stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimate, in
management's opinion, the existing models do not necessarily provide a reliable
single measure of the fair value of its employee stock options.
-51-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
Pro-forma net income and earnings per share had the Company accounted
for its options under the fair value method of SFAS 123 is as follows:
Year Ending September 30,
--------------------------------------------
1998 1997 1996
---- ---- ----
Net income as reported.......................................... $14,056 $26,866 $25,074
Adjustment required by FAS 123.................................. (132) (214) (65)
------- ------- -------
Pro-forma net income............................................ $13,924 $26,652 $25,009
======= ======= =======
Pro-forma net income per share:
Basic........................................................ $ 3.67 $ 4.62 $ 3.74
======= ======= =======
Diluted...................................................... $ 3.63 $ 4.60 $ 3.72
======= ======= =======
NOTE 18-- INCOME TAXES
Provisions for (benefit of) income taxes consist of:
September 30,
--------------------------------------------------
1998 1997 1996
---- ---- ----
Provision for (benefit of) income taxes:
Current:
Federal....................................................... $ 223 $ 862 $ 300
State......................................................... 13 37 11
Deferred:
Federal....................................................... 1,653 13,506 4,462
State......................................................... 47 362 128
Adjustment to the valuation reserve for deferred taxes:
Federal....................................................... (712) (9,824) (15,712)
State......................................................... (20) (280) (448)
------ ------- --------
$1,204 $ 4,663 ($11,259)
====== ======= ========
Deferred tax assets (liabilities) are comprised of the following at
September 30, 1998 and 1997:
September 30,
--------------------------
1998 1997
---- ----
Operating loss and other tax carryforwards.......................................... $5,781 $8,962
Depletion accounting................................................................ (890) (544)
Amortization (gas contracts)........................................................ 439 1,048
Discontinued net refining operations................................................ 543 1,057
Other............................................................................... (2,950)
------ ------
5,873 7,573
Valuation allowance................................................................. (3,108) (3,840)
------ ------
$2,765 $3,733
====== ======
Deferred tax assets - current....................................................... $2,765 $2,239
Deferred tax assets - non-current................................................... 1,494
------ ------
$2,765 $3,733
====== ======
In fiscal 1998, the Company reduced its valuation reserve to $3,108
based upon the decreased probability of additional losses related to
discontinued refining operations. In fiscal 1997, the Company reduced its
valuation reserve to $3,840 in anticipation of future taxable income from the
Lone Star Contract.
-52-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
The Company has recorded a net deferred tax asset of $2,765 at
September 30, 1998. Realization is dependent on generating sufficient taxable
income through the remaining term of the Lone Star Contract. Although
realization is not assured, management believes it is more likely than not that
the deferred tax asset will be realized.
The income tax provision (benefit) differs from the amount computed by
applying the statutory federal income tax rate to income (loss) before income
taxes as follows:
Year Ended September 30,
--------------------------------------
1998 1997 1996
---- ---- ----
Tax at statutory rate.................................................... $5,341 $11,035 $ 4,835
State taxes, net of federal benefit...................................... 26 315 138
Reversal of tax estimates and contingencies.............................. (3,463)
Adjustment related to statutory depletion................................ 4,312
Changes in valuation allowance........................................... (732) (10,104) (16,160)
Other.................................................................... 32 (895) (72)
------ ------- -------
$1,204 $ 4,663 ($11,259)
====== ======= =======
At September 30, 1998, the Company had the following tax carryforwards
available:
Federal Tax
-----------------------------
Alternative
Minimum
Regular Tax
--------- ------------
Net operating loss................................................................... $ 6,109 $31,380
Alternative minimum tax credits...................................................... $ 3,582 N/A
Statutory depletion.................................................................. $12,632 $ 315
Investment tax credit................................................................ $ 88 N/A
The net operating loss and investment tax credit carryforwards expire
from 1999 through 2008.
On September 9, 1994, the Company experienced a change of ownership for
tax purposes. As a result of such change of ownership, the Company's net
operating loss became subject to an annual limitation of $7,845. Such annual
limitation, however, was increased by the amount of net built-in gain at the
time of the change of ownership. Such net built-in gain aggregated $219,430.
During the fiscal years ended September 30, 1998, 1997 and 1996 the Company used
$10,295, $45,499 and $5,740, respectively, of its net operating loss
carryforwards including $35,485 of built-in gains.
The Company also has approximately $52,000 in individual state tax loss
carryforwards available at September 30, 1998. Such carryforwards are primarily
available to offset taxable income apportioned to certain states in which the
Company's refining subsidiaries previously incurred refining losses and
currently have no plans for future operations. As a result it is probable most
of such state tax carryforwards will expire unused.
NOTE 19- RELATED PARTIES
Sale of Subsidiaries
On March 31, 1993, the Company entered into an agreement to sell to
Terrapin its oil and gas partnership management businesses for $1,100 ($800 note
bearing interest at 8% per annum and $300 cash) which approximated book value.
The closing of the stock purchase transaction occurred on June 30, 1993.
Terrapin is wholly-owned by an officer and director of the Company who left the
Company in June 1993 and rejoined the Company in November 1994. In December
1994, the note was repaid.
-53-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
In conjunction with the sale of its partnership management business,
the Company and one of its exploration and production subsidiaries entered into
two management agreements with Terrapin to manage its exploration and production
operations. The second agreement was amended in 1996 to include corporate
accounting functions.
In June 1997, the Company purchased one of the Terrapin management
agreements in conjunction with the sale of the Company's Rusk County, Texas oil
and gas properties to UPRC (see Note 14). The remaining contract with Terrapin
was month to month.
In September 1997, Terrapin granted the Company an option to acquire
its accounting software and computer equipment. The option price was one dollar
plus assumption of Terrapin's office and equipment rentals and employee
obligations. Effective June 30, 1998, the Company exercised the option and hired
most of Terrapin's employees.
Management fees incurred to Terrapin for the years ended September 30,
1998, 1997 and 1996 aggregated $292, $561 and $613, respectively.
Professional Fees
A former member of the Board of Directors is also a partner in a law
firm which currently serves as general counsel for the Company. Legal fees
incurred by the Company to this firm during fiscal 1998, 1997 and 1996 were
$114, $161, and $317, respectively. The partner in the law firm resigned as a
director of the Company on October 6, 1995.
NOTE 20 - BUSINESS SEGMENTS
As of September 30, 1995, the Company had disposed of its refining
segment (see Note 3) and operated in only two business segments - natural gas
marketing and transmission and exploration and production. In May 1997, the
Company sold its pipeline (natural gas transmission) to a subsidiary of UPRC
(see Note 4). As a result, the Company was no longer in the natural gas
transmission segment but continues to operate in the natural gas marketing and
exploration and production segments.
Year Ended September 30, 1998
------------------------------------------------------------------------------------------
Natural Gas Oil & Gas Eliminations
Marketing Exploration and
and and Refining Corporate
Transmission Production (Discontinued) Items Consolidated
------------ ---------- -------------- ------------- ------------
Revenues........................... $70,001 $ 2,603 $72,604
Operating income (loss)............ 15,700 413 ($ 3,081) 13,032
Identifiable assets................ 62,424 49,724 (45,144) 67,004
Capital expenditures............... 2,457 2,457
Depreciation, depletion and
amortization.................... 9,462 423 9,885
-54-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
Year Ended September 30, 1997
---------------------------------------------------------------------------------------
Natural Gas Oil & Gas Eliminations
Marketing Exploration and
and and Refining Corporate
Transmission Production (Discontinued) Items Consolidated
------------ ---------- -------------- ------------- ------------
Revenues........................... $68,029 $ 7,113 ($3,423) $71,719
Operating income (loss)............ 12,415 2,425 (3,370) 11,470
Identifiable assets................ 41,667 48,666 (7,616) 82,717
Capital expenditures............... 59 1,544 1,603
Depreciation, depletion and
amortization.................... 10,639 1,611 12,250
Year Ended September 30, 1996
---------------------------------------------------------------------------------------
Natural Gas Oil & Gas Eliminations
Marketing Exploration and
and and Refining Corporate
Transmission Production (Discontinued) Items Consolidated
------------ ---------- -------------- ------------- ------------
Revenues........................... $63,789 $ 9,224 ($ 4,318) $ 68,695
Operating income (loss)............ 11,769 3,620 (3,499) 11,890
Identifiable assets................ 58,368 27,281 15,581 101,230
Capital expenditures............... 140 34 1 175
Depreciation, depletion and
amortization.................... 11,393 2,324 251 13,968
NOTE 21 -- DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
Cash and Cash Equivalents and Marketable Securities -- For those
short-term instruments, the carrying amount is a reasonable estimate of fair
value.
Hedges -- At September 30, 1998, the Company had hedged approximately
2,370 MMbtu of gas (net) that it expects to purchase to sell to Lone Star and
MGNG. The book value of such hedges is zero. The fair market value of the
natural gas commodity price swaps based upon the market value of the related
fixed price hedge contracts, was $419 at September 30, 1998. (See Note 14.)
Other Current Assets and Current Liabilities - the Company believes that
the book values of other current assets and current liabilities approximate the
market values.
NOTE 22 - QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
First Second Third Fourth
Quarter Quarter Quarter Quarter
(December 31) (March 31) (June 30) (September 30)
------------- ---------- --------- --------------
Fiscal 1998:
Revenues................................ $20,979 $18,504 $17,464 $15,657
Operating income before interest and
income taxes......................... 3,752 3,369 3,525 2,386
Net income.............................. 2,822 2,542 6,864 1,828
Net income per share (diluted).......... $ .60 $ .61 $ 2.02 $ .60
-55-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
First Second Third Fourth
Quarter Quarter Quarter Quarter
(December 31) (March 31) (June 30) (September 30)
------------- ---------- --------- --------------
Fiscal 1997:
Revenues................................ $20,625 $23,178 $15,265 $12,651
Operating income before interest and
income taxes.......................... 3,508 4,901 2,030 1,031
Net income.............................. 2,236 2,910 20,363* 1,357
Net income per share (diluted).......... $ .33 $ .50 $ 3.72 $ .28
* Includes $19,667 non-recurring gain on sale of assets (see Note 4).
The sums of the quarterly per share amounts for 1998 ($3.83) and for
1997 ($4.83) differ from the annual per share amounts of $3.66 in fiscal 1998
and $4.64 in fiscal 1997 primarily because the stock purchases made by the
Company were not made in equal amounts and at corresponding times each quarter.
NOTE 23 - SUBSEQUENT EVENTS
On October 1, 1998, the Company's Board of Directors declared a
dividend of $.15 per common share outstanding.
Subsequent to September 30, 1998, the Company repurchased 10,000
options from a former officer of the Company and several of its subsidiaries for
$55.
At November 20, 1998, the market value of the Company's marketable
securities was $292.
-56-
Independent Auditors' Report
The Board of Directors
Castle Energy Corporation:
We have audited the accompanying consolidated balance sheet of Castle Energy
Corporation and subsidiaries as of September 30, 1998 and 1997, and the related
consolidated statements of operations, stockholders' equity, and cash flows for
the years then ended. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audit.
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, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Castle Energy
Corporation and subsidiaries as of September 30, 1998 and 1997, and the results
of their operations and their cash flows for the years then ended in conformity
with generally accepted accounting principles.
KPMG PEAT MARWICK LLP
Houston, Texas
December 9, 1998
-57-
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of Directors
CASTLE ENERGY CORPORATION
In our opinion, the consolidated statements of income, of cash flows and of
changes in stockholders' equity for the year ended September 30, 1996 present
fairly, in all material respects, the results of operations and cash flows of
Castle Energy Corporation and its subsidiaries for the year ended September 30,
1996, in conformity with generally accepted accounting principles. These
financial statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audit. We conducted our audit of these statements in accordance with
generally accepted auditing standards which 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,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audit provides a reasonable basis for the opinion expressed
above. We have not audited the consolidated financial statements of Castle
Energy Corporation for any period subsequent to September 30, 1996.
PRICE WATERHOUSE LLP
Philadelphia, PA
January 9, 1997
-58-
PART III
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
The Company's independent accountants for the fiscal year ended September
30, 1996 were the firm of Price Waterhouse LLP ("Price Waterhouse"). Price
Waterhouse resigned as the Company's independent accountants on February 11,
1997. The reports of Price Waterhouse on the financial statements for the two
prior fiscal years contained no adverse opinion or disclaimer of opinion and
were not qualified or modified as to uncertainty, audit scope or accounting
principle. In connection with its audits for the fiscal year ending September
30, 1996 and through February 11, 1997, there were no disagreements with Price
Waterhouse on any matter of accounting practices, financial statement
disclosure, or auditing scope or procedure, which disagreements if not resolved
to the satisfaction of Price Waterhouse would have caused them to make reference
thereto in their reports on the financial statements for such years. Price
Waterhouse has furnished the Company with a letter stating that it agrees with
the above statements in this paragraph.
In March 1997, the Company's Board of Directors appointed KPMG Peat Marwick
LLP as the Company's independent accountants. This firm has no material
relationship with the Company and its subsidiaries.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT**
ITEM 11. EXECUTIVE COMPENSATION**
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT**
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS**
- --------------
** The information required by Item 10, 11, 12 and 13 is incorporated by
reference to the Registrant's Proxy Statement for its 1998 Annual Meeting
of Stockholders.
-59-
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. and 2. Financial Statements and Financial Statement Schedules
Financial statements and schedules filed as part of this Report on Form 10-K
are listed in Item 8 to this Form 10-K.
3. Exhibits
The Exhibits required by Item 601 of Regulation S-K and filed herewith or
incorporated by reference herein are listed in the Exhibit Index below.
Exhibit Number Description of Document
------------- -----------------------
3.1 Restated Certificate of Incorporation(15)
3.2 Bylaws(10)
4.1 Specimen Stock Certificate representing Common Stock(8)
4.2 Rights Agreement between Castle Energy Corporation and American Stock Transfer and Trust
Company as Rights Agent, dated as of April 21, 1994(10)
10.15 Replacement Gas Purchase Contract, effective February 1, 1992, between ARCO Oil and Gas
Company and Lone Star Gas Company(8)
10.17 Swap Agreement, dated May 27, 1993, between Indian Refining Limited Partnership and MG
Refining and Marketing, Inc.(8)
10.18 Amendment to Swap Agreement, dated July 29, 1993, between Indian Refining Limited Partnership
and MG Refining and Marketing, Inc.(8)
10.19 Amended and Restated Pipeline Management Agreement, effective as of December 1, 1992, between
Castle Texas Pipeline Limited Partnership and MG Gathering Corp.(8)
10.20 Amended and Restated Service Agreement, effective as of December 1, 1992, between CEC Gas
Marketing Limited Partnership and MG Natural Gas Corp.(8)
10.31 Management Agreement, dated July 1, 1993, between Castle Energy Corporation and Terrapin
Resources, Inc.(8)
10.33 Castle Energy Corporation 1992 Executive Equity Incentive Plan(8)
10.34 First Amendment to Castle Energy Corporation 1992 Executive Equity Incentive Plan, effective
May 11, 1993(8)
10.37 Amended and Restated Gas Purchase Contract, dated as of August 1, 1993, between MG Natural Gas
Corp. and CEC Gas Marketing Limited Partnership(8)
10.61 Letter agreement (re Gas Purchase Contract), dated September 30, 1993, between Castle Texas
Production Limited Partnership and MG Natural Gas Corp.(8)
10.68 Employment Agreement, dated as of January 1, 1994, by and between Castle Energy Corporation and
Joseph L. Castle II(11)
10.84 Natural Gas Swap Agreement, dated October 14, 1994, between MG Natural Gas Corp. and Indian
Refining Limited Partnership(13)
10.111 Stock and Asset Purchase Agreement, dated November 21, 1995, among Castle Energy Corporation,
Indian Refining I, Limited Partnership, Indian Refining and Marketing I, Inc. and AM West G.P., Inc.(18)
10.112 Agreement and Plan of Merger by and among Energy Merchant Corp., POC Acquisition Corporation,
Powerine Holding Corp., Castle Energy Corporation and Powerine Oil Company, dated January 10,
1996.(18)
-60-
Exhibit Number Description of Document
-------------- -----------------------
10.116 Amendment No. 1 to Stock and Asset Purchase Agreement Dated as of November 21, 1995.(18)
10.117 Loan Agreement among Castle Exploration Company, Inc.; Castle Texas Production Limited
Partnership; Castle Texas Pipeline Limited Partnership; and CEC Gas Marketing Limited
Partnership, as Borrowers, Castle Pipeline Company; CEC Marketing Company and Castle Production
Company, as General Partners, Castle Energy Corporation and Commercial National Bank in
Shreveport as of April 30, 1996 (19)
10.118 First Amendment to Loan Agreement, dated November 8, 1996, Castle Exploration Company, Inc.; Castle Texas
Production Limited Partnership; Castle Texas Pipeline Limited Partnership; and CEC Gas Marketing
Limited Partnership, as Borrowers, Castle Pipeline Company; CEC Marketing Company and Castle
Production Company, as General Partners, Castle Energy Corporation and Commercial National Bank
in Shreveport (19)
10.119 Amended and Restated Loan Agreement, dated November 26, 1996, among Commercial National Bank in
Shreveport, As Agent, the Several Financial Institutions From Time to Time thereto, and Castle
Exploration Company, Inc.; Castle Texas Production Limited Partnership; Castle Texas Pipeline
Limited Partnership; and CEC Gas Marketing Limited Partnership, as Borrowers, Castle Pipeline
Company; CEC Marketing Company and Castle Production Company, as General Partners, and Castle
Energy Corporation (19
10.120 Option Agreement dated July 10, 1997 between Terrapin Resources, Inc. and Castle Energy
Corporation
10.121 Closing Agreement, dated May 30, 1997 by and among Castle Energy Corporation, Castle Texas Production
L.P., Union Pacific Resources Company and Castle Exploration Company, Inc.
10.122 Purchase and Sale Agreement by and among Castle Energy Corporation and Castle Texas Pipeline
L.P. and Union Pacific Intrastate Pipeline Company, dated May 16, 1997 (20)
10.123 Purchase and Sale Agreement by and among Castle Energy Corporation and Castle Texas Production
L.P. and Union Pacific Resources Company dated May 16, 1997 (20)
10.124 Asset Purchase Agreement dated February 27, 1998 by and between Castle Energy Corporation and
Alexander Allen, Inc. (21)
11.1 Statement re: Computation of Earnings Per Share
21 List of subsidiaries of Registrant
23.1 Consent of PricewaterhouseCoopers LLP
23.2 Consent of Ryder Scott Company
23.3 Consent of Huntley & Huntley
23.4 Consent of KPMG Peat Marwick LLP
27 Financial Data Schedule
(b) Reports on Form 8-K
The Company filed no reports on Form 8-K during the last quarter of
the Company's fiscal year ended September 30, 1998.
- ----------------
** The confidential portion of this document has been omitted and filed
with the Securities and Exchange Commission
(3) Incorporated by reference to the Registrant's Form 10-K for the fiscal
year ended September 30, 1991
(8) Incorporated by reference to the Registrant's Form S-1 (Registration
Statement), dated September 29, 1993
(10) Incorporated by reference to the Registrant's Form 10-Q for the second
quarter ended March 31, 1994
(11) Incorporated by reference to the Registrant's Form 10-Q/A for the third
quarter ended June 30, 1994
(12) Incorporated by reference to the Registrant's Form 8-K, dated August 31,
1994
(13) Incorporated by reference to the Registrant's Form 8-K, dated November 3,
1994
(15) Incorporated by reference to the Registrant's Form 10-K for the fiscal
year ended September 30, 1994
-61-
(17) Incorporated by reference to the Registrant's Form 10-Q for the quarter
ended June 30, 1995
(18) Incorporated by reference to the Registrant's Form 10-K for the fiscal
year ended September 30, 1995
(19) Incorporated by reference to Registrant's Form 10-K for the fiscal year
ended September 30, 1996
(20) Incorporated by reference to the Registrant's Form 8-K dated May 30, 1997
(21) Incorporated by reference to the Registrant's Form 10-Q for quarter ended
March 31, 1998
-62-
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.
CASTLE ENERGY CORPORATION
Date: December 9, 1998 By:/s/JOSEPH L. CASTLE II
-----------------------------------
Joseph L. Castle II
Chairman of the Board
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed by the following persons on behalf of the registrant
in the capacities and on the dates indicated.
/s/JOSEPH L. CASTLE II Chairman of the Board and Chief December 3, 1998
- --------------------------------- Executive Officer
Joseph L. Castle II Director
/s/MARTIN R. HOFFMANN Director December 3, 1998
- --------------------------------
Martin R. Hoffmann
/S/JOHN P. KELLER Director December 3, 1998
- --------------------------------
John P. Keller
/s/RICHARD E. STAEDTLER Senior Vice President December 3, 1998
- ------------------------------- Chief Financial Officer
Richard E. Staedtler Chief Accounting Officer
Director
/s/SIDNEY F. WENTZ Director December 3, 1998
- -------------------------------
Sidney F. Wentz
-63-
DIRECTORS AND OFFICERS
BOARD OF DIRECTORS
(November 20, 1998)
JOSEPH L. CASTLE II RICHARD E. STAEDTLER
Chairman & Chief Executive Officer Chief Financial Officer and Chief
Accounting Officer
MARTIN R. HOFFMANN SIDNEY F. WENTZ
Of Counsel to Washington, D.C. Chairman of The Robert Wood Johnson
Office of Skadden, Arps, Slate, Foundation
Meagher & Flom
JOHN P. KELLER
President, Keller Group, Inc.
OPERATING OFFICERS
JOSEPH L. CASTLE II RICHARD E. STAEDTLER
Chief Executive Officer Chief Financial Officer
Chief Accounting Officer
PRINCIPAL OFFICES
One Radnor Corporate Center 531 Plymouth Road, Suite 525
Suite 250 Plymouth Meeting, PA 19462
100 Matsonford Road
Radnor, PA 19087
13760 Deerlick Creek Road 61 McMurray Road, Suite 204
Tuscaloosa, Alabama 35406 Pittsburgh, PA 15241-1633
AGENTS
Counsel Independent Reservoir Engineers
Duane, Morris & Heckscher LLP Huntley & Huntley, Inc.
One Liberty Place, 42nd Floor Corporate One II, Suite 100
Philadelphia, PA 19103-7396 4075 Monroeville Blvd.
Monroeville, PA 15146
Independent Accountants
KPMG Peat Marwick LLP
700 Louisiana, Floor 32
Houston, Texas 77002
Registrar and Transfer Agent
American Stock Transfer & Trust Company
40 Wall Street, 46th Floor
New York, New York 10005