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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, 2001
OR
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______________ to _________________
Commission file number: 0-10990
CASTLE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 76-0035225
(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
(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-- $.50 par value and related Rights
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ X ].
As of December 14, 2001, there were 6,632,884 shares of the
registrant's Common Stock ($.50 par value) outstanding. The aggregate market
value of voting stock held by non-affiliates of the registrant as of such date
was $29,637,835 (5,049,035 shares at $5.87 per share).
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Proxy Statement for the 2002 Annual Meeting of
Stockholders are incorporated by reference in Items 10, 11, 12 and 13
CASTLE ENERGY CORPORATION
2001 FORM 10-K
TABLE OF CONTENTS
Item Page
- ---- ----
PART I
1. and 2. Business and Properties...................................... 1
3. Legal Proceedings............................................ 6
4. Submission of Matters to a Vote of Security Holders.......... 10
PART II
5. Market for the Registrant's Common Equity and Related
Stockholder Matters.......................................... 11
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.................. 26
9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure..................................... 59
PART III
10. Directors and Executive Officers of the Registrant........... 60
11. Executive Compensation....................................... 60
12. Security Ownership of Certain Beneficial Owners and
Management................................................... 60
13. Certain Relationships and Related Transactions............... 60
PART IV
14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K..................................................... 61
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
INTRODUCTION
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
sources and expected cash uses discussed below. All forward-looking statements
in this Form 10-K are expressly qualified in their entirety by the cautionary
statements in this paragraph.
Castle Energy Corporation (the "Company") is currently engaged in oil
and gas exploration and production in the United States and Romania. References
to the Company mean Castle Energy Corporation, the parent, and/or one or more of
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 of the Company, owned the Indian Refinery, an 86,000 barrel per day
(B/D) refinery located in Lawrenceville, Illinois ("Indian Refinery"). 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 ("Powerine Refinery"). By September 30, 1995, the Company's refining
subsidiaries had terminated and discontinued all of their refining operations.
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
of this Form 10-K).
During the period from December 31, 1992 to May 31, 1999, the Company,
through two of its subsidiaries, was also engaged in natural gas marketing and
transmission operations. During this period one of the Company's subsidiaries
sold natural gas to Lone Star Gas Company ("Lone Star") under a long-term gas
sales contract. The subsidiaries also entered into two long-term gas sales
contracts and one long-term gas supply contract with MG Natural Gas Corp.
("MGNG"), a subsidiary of MG Corp. ("MG"), whose parent is Metallgesellschaft
A.G. ("MGAG"), a large German conglomerate. All of the subsidiaries' gas
contracts terminated on May 31, 1999. The Company has not replaced these
contracts because it sold its pipeline assets to a subsidiary of Union Pacific
Resources Corporation ("UPRC") in May 1997 and because it was unable to
negotiate similar profitable long-term contracts since most gas purchasers now
buy gas on the spot market. The Company is currently operating exclusively in
the exploration and production segment of the energy industry.
From inception to the present, the Company continues to operate in the
exploration and production segment of the energy business. During the fiscal
years ended September 30, 2001, 2000 and 1999 the Company invested $15,449,000,
$11,226,000 and $23,964,000 respectively, in oil and gas property acquisition,
exploration and development, including $3,707,000 in Romania. The Company is
currently planning to participate in the drilling of a wildcat well in the Black
Sea in the spring or early summer of 2002. As of September 30, 2001, the
Company's exploration and production subsidiaries owned interests in 522
producing oil and gas wells located in fourteen states. Of these interests, 430
were working interests, where the Company is responsible for operating costs
applicable to the well, and 92 were royalty interests, where the Company bears
no expense burden. The subsidiaries operate approximately half of the wells that
are working interests. At September 30, 2001, the Company's exploration and
production assets included proved reserves of approximately 31 billion cubic
feet of natural gas and approximately 3,400,000 barrels of oil.
In July 2000, the Company engaged Energy Spectrum Advisors of Dallas,
Texas to advise the Company concerning strategic alternatives including the
possible sale of its oil and gas assets. In December 2000, several companies
submitted bids for the Company's domestic oil and gas assets. The total of the
highest bids for all of the Company's properties aggregated approximately
$48,000,000 with an effective date of October 1, 2000. The Company's Board of
Directors decided not to sell its oil and gas assets at the prices offered.
-1-
In August 2000, the Company purchased thirty-five percent (35%) of the
membership interests of Networked Energy LLC ("Network") for $500,000. Network
is a private company engaged in the planning and operation of energy facilities
that supply power, heating and cooling services directly to retail customers.
On December 11, 2001, the Company entered into a letter of intent to
sell all of its domestic oil and gas assets to Delta Petroleum Company ("Delta")
for $20,000,000 cash and 9,566,000 shares of common stock of Delta. The
effective date of the sale is October 1, 2001 and the expected closing date is
April 30, 2002 or later. The sale is subject to execution of a definitive
purchase and sale agreement by both parties, approval of the transaction by the
boards of directors of the Company and Delta and approval by Delta's
shareholders of the issuance of the Delta shares to Castle.
In October 1996, the Company commenced a program to repurchase shares of
its common stock at stock prices beneficial to the Company. At December 14,
2001, 4,871,020 shares, representing approximately 69% of previously outstanding
shares, had been repurchased and the Company's Board of Directors has authorized
the purchase of up to 396,946 additional shares.
OIL AND GAS EXPLORATION AND PRODUCTION
General
On June 1, 1999, the Company consummated the purchase of all of the oil
and gas properties of AmBrit Energy Corp. ("AmBrit"). The oil and gas properties
purchased include interests in approximately 180 oil and gas wells in Alabama,
Louisiana, Mississippi, Montana, New Mexico, Oklahoma, Texas and Wyoming, as
well as undrilled acreage in several of these states. The effective date of the
sale was January 1, 1999. The adjusted purchase price after accounting for all
transactions between the effective date, January 1, 1999, and the closing date
was $20,170,000. The entire adjusted purchase price was allocated to "Oil and
Gas Properties - Proved Properties". Based upon reserve reports initially
prepared by the Company's petroleum reservoir engineers, the proved reserves
(unaudited) associated with the AmBrit oil and gas assets approximated 2,000,000
barrels of crude oil and 12,500,000 mcf (thousand cubic feet) of natural gas,
which, together, approximated 150% of the Company's oil and gas reserves before
the acquisition. In addition, the production acquired initially increased the
Company's consolidated production by approximately 425%.
In fiscal 1999, the Company entered into two drilling ventures to
participate in the drilling of up to sixteen exploratory wells in south Texas.
During fiscal 2000, the Company participated in the drilling of nine exploratory
wells pursuant to the related joint venture operating agreements. Eight wells
drilled resulted in dry holes and one well was completed as a producer. The
Company has no further drilling obligations under these joint ventures and has
terminated participation in each drilling venture. The total cost incurred to
participate in the drilling of the exploratory wells was $6,003,000.
In December 1999, a subsidiary of the Company purchased majority
interests in twenty-six offshore Louisiana wells from Whiting Petroleum Company
("Whiting"), a public company engaged in oil and gas exploration and
development. The adjusted purchase price was $890,000.
In September 2000, the subsidiary sold its interests in the offshore
Louisiana wells to Delta. The effective date of the sale was July 1, 2000. The
adjusted purchase price of $3,059,000 consisted of $1,122,000 cash plus 382,289
shares of Delta's common stock valued at the closing market price of $1,937,000
(see Note 8 to the Company's Consolidated Financial Statements included in Item
8 of this Form 10-K).
In April 1999, the Company purchased an option to acquire a fifty
percent (50%) interest in three oil and gas concessions granted to a subsidiary
of Costilla Energy Corporation ("Costilla"), a public oil and gas exploration
and production company, by the Romanian government. The Company paid Costilla
$65,000 for the option. In May 1999, the Company exercised the option. As of
September 30, 2001, the Company had participated in the drilling of five wildcat
wells in Romania. Four of those wells resulted in dry holes. Although the fifth
well produced some volumes of natural gas when tested, the Company has not been
able to obtain a sufficiently high gas price to justify future production and
has elected at the present time not to undertake an offset drilling program in
the acreage surrounding the fifth well. The Company has agreed to participate in
the drilling of a sixth well in the Black Sea in the spring or early summer of
2002.
-2-
In November and December 1999, the Company acquired additional outside
interests in several Alabama and Pennsylvania wells, which it operates, for
$2,580,000.
On April 30, 2001, the Company consummated the purchase of several East
Texas oil and gas properties from a private company. The effective date of the
purchase was April 1, 2001. These properties included majority interests in
twenty-one (21) operated producing oil and gas wells and interests in
approximately 6,500 gross acres in three counties in East Texas. The Company
estimated the proved reserves acquired to be approximately 12.5 billion cubic
feet of natural gas and 191,000 barrels of crude oil. The consideration paid,
net of purchase price adjustments, was $10,040,000. The Company used its own
internally generated funds to make the purchase.
Properties
Proved Oil and Gas Reserves
The following is a summary of the Company's oil and gas reserves as of
September 30, 2001. All estimates of reserves are based upon engineering
evaluations prepared by the Company's independent petroleum reservoir engineers,
Huntley & Huntley and Ralph E. Davis Associates, Inc., 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, 2001
were as follows:
Net MCF (1) of gas:
Proved developed............................................. 26,480,000
Proved undeveloped........................................... 4,212,000
----------
Total........................................................ 30,692,000
==========
Net barrels of oil:
Proved developed............................................. 1,890,000
Proved undeveloped........................................... 1,470,000
----------
Total........................................................ 3,360,000
==========
- -----------------
(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, 2001, including production from acquired properties since the date
of acquisition.
Fiscal Year Ended September 30,
2001 2000 1999
---- ---- ----
Oil -- Bbls (barrels)................................. 262,000 279,000 124,000
Gas -- MCF............................................ 3,083,000 3,547,000 1,971,000
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, including hedging adjustments, 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.
-3-
Fiscal Year Ended September 30,
2001 2000 1999
---- ---- ----
Average Sales Price per Barrel of Oil.......................... $27.39 $27.94 $18.36
Average Sales Price per MCF of Gas............................. $ 4.53 $ 2.87 $ 2.25
Average Production Cost per Equivalent MCF(1).................. $ 1.59 $ 1.19 $ .70
--------------
(1) For purposes of equivalency of units, a barrel of oil is assumed
equal to six MCF of gas, based upon relative energy content.
No production was hedged in fiscal 2001.
The average sales price per barrel of crude oil decreased $4.64 per
barrel for the year ending September 30, 2000 and increased $.11 per barrel for
the year ended September 30, 1999 as a result of hedging. The average sales
price per mcf (thousand cubic feet) of natural gas decreased $.07 for each of
the years ended September 30, 2000 and 1999 as a result of hedging. Oil and gas
sales were not hedged after July 2000.
Productive Wells and Acreage
The following table presents the oil and gas properties in which the
Company held an interest as of September 30, 2001. The wells and acreage owned
by the Company and its subsidiaries are located primarily in Alabama,
California, Illinois, Louisiana, Mississippi, Montana, New Mexico, Oklahoma,
Pennsylvania, Texas and Wyoming.
As of
September 30, 2001
Gross(2) Net (3)
------------ ----------
Productive Wells:(1)
Gas Wells................................................. 521 203
Oil Wells................................................. 103 49
Acreage:
Developed Acreage......................................... 129,517 31,351
Undeveloped Acreage....................................... 85,686 29,678
In addition, one of the Company's subsidiaries has a fifty percent
interest in approximately 3,100,000 gross undeveloped acres in Romania
(approximately 1,550,000 net acres).
----------------
(1) A "productive well" is a producing well or a well capable of
production. Fifty-nine 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, 2001 the number of gross and net productive and dry
developmental wells drilled, including wells drilled on acquired properties
since the dates of acquisition.
-4-
Fiscal Year Ended September 30,
----------------------------------------------------------------------------------------------------
2001 2000 1999
------------------------------------- --------------------------------------- -----------------
United States Romania United States Romania United States
------------------ ----------------- ----------------- -------------------- -----------------
Productive Dry Productive Dry Productive Dry Productive Dry Productive Dry
---------- --- ---------- --- ---------- --- ---------- --- ---------- ---
Developmental:
Gross........... 17 4 -- -- 9 -- -- 5 3
Net............. 4 1.3 -- -- 4.5 -- -- 2.3 1.2
Exploratory:
Gross........... -- 3* 1 8 -- 2 -- --
Net............. -- 1.5* .5 3.75 -- 1 -- --
All wells drilled by the Company in fiscal 1999 were drilled in the
United States.
* One well, in which the Company has a fifty percent (50%) interest,
produced some volumes of natural gas when tested but the Company has
not been able to obtain a price for its production that makes future
operations economical.
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 and Note 12 to the consolidated financial statements included in Item 8
of this Form 10-K.
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 subsidiaries has
not resulted in material expenditures.
Most 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. 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. In recent years 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 although compliance requirements continue to absorb
an increasing percentage of management's time.
The Company plans to participate in the drilling of a wildcat well in
the Black Sea in the spring or early summer of 2002. Participation in the
drilling of this well will expose the Company to several risks not commonly
associated with the Company's domestic onshore operations including drilling
offshore, using foreign contractors to drill, political and governmental
regulatory risks and possible delays in obtaining permits, parts and supplies.
In addition, if the well is successful, a pipeline may have to be installed to
transport the crude oil or natural gas discovered to onshore collection
facilities.
The Company is also subject to various state and Federal laws regarding
environmental and ecological matters because it acquires, drills and operates
oil and gas properties. To alleviate the environmental risk, the Company carries
$25,000,000 of liability insurance and $3,000,000 of special operator's extra
expense (blowout) insurance for wells it drills, including the well planned to
be drilled in the Black Sea.
-5-
EMPLOYEES AND OFFICE FACILITIES
As of November 30, 2001, the Company, through its subsidiaries, employed
30 personnel. The Company also established an Oklahoma City office in February
of 2000.
The Company leases certain offices as follows:
Office Location Function
--------------- --------
Radnor, PA Corporate Headquarters
Blue Bell, PA Accounting and Land
Mt. Pleasant, PA Gas Production Office
Pittsburgh, PA Drilling and Exploration Office
Tuscaloosa, Alabama Oil and Gas Production Office
Oklahoma City, Oklahoma Legal and International Operations
ITEM 3. LEGAL PROCEEDINGS
Contingent Environmental Liabilities
In December 1995, IRLP, an inactive subsidiary of the Company, sold its
refinery, the Indian Refinery, to American Western Refining L.P. ("American
Western"), an unaffiliated party. As part of the related purchase and sale
agreement, American Western assumed all environmental liabilities and
indemnified IRLP with respect thereto. Subsequently, American Western filed for
bankruptcy and sold the Indian Refinery to an outside party pursuant to a
bankruptcy proceeding. The outside party has substantially dismantled the Indian
Refinery. American Western recently filed a Plan of Liquidation. American
Western anticipates that the Plan of Liquidation expects to be confirmed in
January 2002.
During fiscal 1998, the Company was informed that the United States
Environmental Protection Agency ("EPA") had investigated offsite acid sludge
waste found near the Indian Refinery and had investigated and remediated surface
contamination on the Indian Refinery property. Neither the Company nor IRLP was
initially named with respect to these two actions.
In October 1998, the EPA named the Company and two of its inactive
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. ("Texaco"), the refinery operator
for over 50 years. A subsidiary of Texaco had owned the refinery until December
of 1988. The Company subsequently responded to the EPA indicating that it was
neither the owner nor the operator of the Indian Refinery and thus not
responsible for its remediation.
In November 1999, the Company received a request for information from
the EPA concerning the Company's involvement in the ownership and operation of
the Indian Refinery. The Company responded to the EPA information request in
January 2000.
On August 7, 2000, the Company received notice of a claim against it and
two of its inactive refining subsidiaries from Texaco and its parent. Texaco had
made no previous claims against the Company although the Company's subsidiaries
had owned the refinery from August 1989 until December 1995. In its claim,
Texaco demanded that the Company and its former subsidiaries indemnify Texaco
for all liability resulting from environmental contamination at and around the
Indian Refinery. In addition, Texaco demanded that the Company assume Texaco's
defense in all matters relating to environmental contamination at and around the
Indian Refinery, including lawsuits, claims and administrative actions initiated
by the EPA and indemnify Texaco for costs that Texaco has already incurred
addressing environmental contamination at the Indian Refinery. Finally, Texaco
also claimed that the Company and two of its inactive subsidiaries are liable to
Texaco under the Federal Comprehensive Environmental Response Compensation and
Liability Act as owners and operators of the Indian Refinery. The Company
responded to Texaco disputing the factual and theoretical basis for Texaco's
claims against the Company. The Company's management and special counsel
subsequently met with representatives of Texaco but the parties disagreed
concerning Texaco's claims.
-6-
The Company and its special counsel believe that Texaco's claims are
utterly without merit and the Company intends to vigorously defend itself
against Texaco's claims and any lawsuits that may follow. In addition to the
numerous defenses that the Company has against Texaco's contractual claim for
indemnity, the Company and its special counsel believe that by the express
language of the agreement which Texaco construes to create an indemnity, Texaco
has irrevocably elected to forgo all rights of contractual indemnification it
might otherwise have had against any person, including the Company.
In September 1995, Powerine sold the Powerine Refinery to Kenyen
Resources ("Kenyen"), an unaffiliated party. In January 1996, Powerine merged
into a subsidiary of Energy Merchant Corp. ("EMC"), an unaffiliated party, and
EMC assumed all environmental liabilities. In August 1998, EMC sold the Powerine
Refinery to a third party, which, we are informed, continues to seek 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, which we understand
is still seeking financing to restart that refinery. Furthermore, as noted
above, the EPA named the Company as a potentially responsible party for
remediation of the Indian Refinery and has requested and received relevant
information from the Company. Estimated gross undiscounted clean-up costs for
this refinery are at least $80,000,000 - $150,000,000 according to third
parties. If the Company were found liable for the remediation of the Indian
Refinery, it could be required to pay a percentage of the clean-up costs. Since
the Company's subsidiary only operated the Indian Refinery five years, whereas
Texaco and others operated it over fifty years, the Company would expect that
its share of remediation liability would be proportional to its years of
operation, although such may not be the case. Furthermore, as noted above,
Texaco has claimed that the Company indemnified it for all environmental
liabilities related to the Indian Refinery. If Texaco were to sue the Company on
this theory and prevail in court, the Company could be held responsible for the
entire estimated clean up costs of $80,000,000-$150,000,000 or more. In such a
case, this cost would be far in excess of the Company's financial capability.
An opinion issued by the U.S. Supreme Court in June 1998 in a comparable
matter and a recent opinion by the U.S. Appeals Court for the Fifth Circuit
support the Company's positions. Nevertheless, 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
parties 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.
General
Long Trusts Lawsuit
In November 2000, the Company and three of its subsidiaries were
defendants in a jury trial in Rusk County, Texas. The plaintiffs in the case,
the Long Trusts, are non-operating working interest owners in wells previously
operated by Castle Texas Production Limited Partnership ("CTPLP"), an inactive
exploration and production subsidiary of the Company. The wells were among those
sold to UPRC in May 1997. The Long Trusts claimed that CTPLP did not allow them
to sell gas from March 1, 1996 to January 31, 1997 as required by applicable
joint operating agreements, and they sued CTPLP and the other defendants,
claiming (among other things) breach of contract, breach of fiduciary duty,
conversion and conspiracy. The plaintiffs sought actual damages, exemplary
damages, pre-judgment and post-judgment interest, attorney's fees and court
costs. CTPLP counterclaimed for approximately $150,000 of unpaid joint interests
billings, interest, attorneys' fees and court costs.
After a three-week trial, the District Court in Rusk County submitted 36
questions to the jury which covered all of the claims and counterclaims in the
lawsuit. Based upon the jury's answers, the District Court entered judgement
granting plaintiffs' claims against the Company and its subsidiaries, as well as
CTPLP's counterclaim against the plaintiffs. The District Court issued an
amended judgement on September 5, 2001 which became final December 19, 2001. The
net amount awarded to the plaintiffs was approximately $2,700,000. The Company
and its subsidiaries have filed a notice of appeal with the Tyler Court of
Appeals and will continue to vigorously contest this matter.
-7-
Special counsel to the Company does not consider an unfavorable outcome
to this lawsuit probable. The Company's management and special counsel believe
that several of the plaintiffs' primary legal theories are contrary to
established Texas law and that the Court's charge to the jury was fatally
defective. They further believe that any judgment for plaintiffs based on those
theories or on the jury's answers to certain questions in the charge cannot
stand and will be reversed on appeal. As a result, the Company has not accrued
any liability for this litigation. Nevertheless, to pursue the appeal, the
Company and its subsidiaries will be required to post a bond to cover the net
amount of damages awarded to the plaintiffs and to maintain that bond until the
resolution of the appeal (which may take several years). The Company has
included the letter of credit to support the bond, estimated at approximately
$3,000,000, in its line of credit with a major energy bank. See Note 21 to the
consolidated financial statements which are included in Item 8 to this Form
10-K.
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, Atlantic Richfield Company ("ARCO"), B&A Pipeline Company, a
former subsidiary of ARCO ("B&A"), 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 $40,000,000.
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 and MGNG were dropped as defendants.
Although it is not completely clear from the amended petition, the plaintiffs
apparently 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.
In April 2000, Larry Long withdrew as a named plaintiff and in
September 2000, the Company and the remaining named plaintiff agreed to settle
the case for a payment of $250,000 by the Company. As of December 27, 2001, the
Company had paid $259,000, representing the $250,000 settlement amount plus $
9,000 of interest, to the plaintiffs and their lawyers.
MGNG Litigation
On May 4, 1998, CTPLP, 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. One of the Company's exploration and
production subsidiaries sought to recover gas measurement and transportation
expenses charged by the defendants in breach of a certain gas purchase contract.
Improper charges exceeded $750,000 before interest. In October of 1998, MGNG and
MGC filed a suit in Harris County, Texas. This suit sought indemnification from
two of the Company's subsidiaries in the event CTPLP won its lawsuit against
MGNG and MGC. The MG entities cited no basis for their claim of indemnification.
The management of the Company and special counsel retained by the Company
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 parties participated in mediation but were not
able to resolve the issue.
In October 1999, MGNG filed a second lawsuit against the Company and
three of its subsidiaries claiming $772,000 was owed to MGNG under a gas supply
contract between one of the Company's subsidiaries and MGNG. The suit was filed
in the district court of Harris County, Texas. The Company and its subsidiaries
believed that they do not owe $772,000 and were entitled to legally offset some
or all of the $772,000 claimed against amounts owed to CTPLP by MGNG for
improper gas measurement and transportation deductions. The Castle entities
answered this suit denying MGNG's claims based partially on the right of offset.
-8-
In September 2000, the parties agreed to settle all lawsuits. Under the
terms of the settlement the amount claimed by MGNG under a gas supply contract
was reduced by $325,000 and the net amount payable to MGNG was set at $400,000
and the parties signed mutual releases. The Company paid MGNG $400,000 in
November 2001.
Pilgreen Litigation
As part of the AmBrit purchase, Castle Exploration Company, Inc.
("CECI") acquired a 10.65% overriding royalty interest ("ORRI") in the Pilgreen
#2ST gas well in Texas. Because of title disputes, AmBrit and other interest
owners had previously filed claims against the operator of the Pilgreen well,
and CECI acquired post January 1, 1999 rights in that litigation. Although
revenue attributed to the ORRI has been suspended by the operator since first
production, because of recent related appellate decisions and settlement
negotiations, the Company believes that revenue attributable to the ORRI should
be released to CECI in the near future. As of September 30, 2001, approximately
$415,000 attributable to CECI's share of the ORRI revenue was suspended. The
Company's policy is to recognize the suspended revenue only when and if it is
received.
-9-
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 2001.
-10-
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:
On December 29, 1999, the Company's Board of Directors declared a stock
split in the form of a 200% stock dividend applicable to all stockholders of
record on January 12, 2000. The additional shares were paid on January 31, 2000
and the Company's shares first traded at post split prices on February 1, 2000.
The stock split applied only to the Company's outstanding shares on January 12,
2000 (2,337,629 shares) and did not apply to treasury shares (4,491,017 shares)
on that date. As a result of the stock split 4,675,258 additional shares were
issued. All share changes have been recorded retroactively in these data and
elsewhere in this Form 10-K.
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 three
fiscal years ended September 30, 2001.
2001 2000 1999
-------------- --------------- ---------------
High Low High Low High Low
---- --- ---- --- ---- ---
First Quarter (December 31)..................... $7.73 $5.92 $ 9.67 $5.50 $6.46 $5.63
Second Quarter (March 31)....................... $6.94 $5.60 $ 10.56 $4.81 $5.96 $5.25
Third Quarter (June 30)......................... $6.92 $5.67 $ 6.50 $4.63 $6.42 $5.00
Fourth Quarter (September 30)................... $6.47 $4.21 $ 7.75 $6.25 $6.08 $5.50
The final sale of the Company's Common Stock as reported by the NNM on
November 30, 2001 was at $5.87.
Dividends:
On June 30, 1997, the Company's Board of Directors adopted a policy of
paying regular quarterly cash dividends of $.05 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 - including a covenant in the Company's letter of credit facility that
limits dividends to 50% of the Company's net income.
Approximate Number of Holders of Common Stock
As of November 30, 2001, the Company's Common Stock was held by
approximately 3,000 stockholders.
ITEM 6. SELECTED FINANCIAL DATA
During the five fiscal years ended September 30, 2001, the Company
consummated a number of transactions affecting the comparability of the
financial information set forth below. In May 1997, the Company sold its Rusk
County, Texas oil and gas properties and pipeline to UPRC and one of its
subsidiaries. In June 1999, CECI acquired all of the oil and gas assets of
AmBrit. 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.
-11-
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, 2001. The information should be read in conjunction with the
Consolidated Financial Statements and notes thereto included in Item 8 of this
Form 10-K.
Earnings per share have been retroactively restated in accordance with
SFAS 128.
For the Fiscal Year Ended September 30,
------------------------------------------------------------------
(in Thousands, except per share amounts)
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
Revenues:
Natural gas marketing and transmission........ $ 50,067 $ 70,001 $ 64,606
Exploration and production ................... $21,144 $ 17,959 7,190 2,603 7,113
Gross Margin:
Natural gas marketing and transmission ....... 19,005 26,747 24,640
Exploration and production ................... 13,745 11,765 4,802 1,828 5,173
Earnings before interest, taxes, depreciation, and
amortization and impairment of unproven
properties:
Natural gas marketing and transmission ..... 17,847 25,162 23,054
Exploration and production ................. 11,917 9,727 3,764 836 4,036
Corporate general and administrative expenses .... (4,169) (3,717) (4,112) (3,081) (3,370)
Depreciation, depletion and amortization and
impairment of unproven properties ............ (6,235) (4,041) (8,330) (9,885) (12,250)
Interest expense ................................. (2) (1,038)
Interest income and other income ................. 584 809 2,053 2,230 21,097(1)
-------- -------- -------- -------- --------
Income from continuing operations before income
taxes ........................................ 2,097 2,778 11,222 15,260 31,529
Provision for (benefit of) income taxes related to
continuing operations ........................ 381 (2,291) 2,956 1,204 4,663
-------- -------- -------- -------- --------
Net income ....................................... $ 1,716 $ 5,069 $ 8,266 $ 14,056 $ 26,866
======== ======== ======== ======== ========
Dividends ........................................ $ 1,322 $ 1,363 $ 2,048 $ 1,688 $ 1,446
======== ======== ======== ======== ========
Net income per share (diluted) ................... $ .25 $ .71 $ .99 $ 1.22 $ 1.55
======== ======== ======== ======== ========
Dividends per share .............................. $ .20 $ .20 $ .25 $ .15 $ .10
======== ======== ======== ======== ========
September 30,
-----------------------------------------------------------
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
Working capital ................................. $10,409 $22,304 $26,489 $40,271 $46,384
Property, plant and equipment, net, including oil
and gas properties ........................... 40,226 30,978 26,985 4,969 2,998
Total assets .................................... 59,118 63,295 60,796 67,004 82,717
Long-term debt, including current maturities
Stockholders' equity ............................ 51,027 54,276 53,503 51,553 67,765
Share data have been retroactively restated to reflect the 200% stock
dividend which was effective January 31, 2000.
- --------------------
(1) Includes a $19,667 non-recurring gain on sale of assets.
-12-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
("$000's" Omitted Except Per Unit Amounts)
- --------------------------------------------------------------------------------
RESULTS OF OPERATIONS
GENERAL
From August 1989 to September 30, 1995, two 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 merged into a subsidiary of EMC and was no longer a subsidiary of the
Company. The Company's other refining subsidiary, IRLP, owns no refining assets
and is 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 Company's
remaining inactive refining subsidiary and contingent environmental liabilities
of the Company or its refining subsidiaries.
Also, as noted above, CECI acquired the oil and gas properties of AmBrit
on June 1, 1999. The oil and gas reserves associated with the acquisition were
estimated at approximately 12.5 billion cubic feet of natural gas and 2,000,000
barrels of crude oil, roughly 150% of the reserves owned by the Company before
the acquisition. Furthermore, as a result of the acquisition, the Company's
production of oil and gas increased by approximately 425%. This acquisition
impacted consolidated operations for the last four months of fiscal 1999 only.
Gas marketing sales and purchases ceased effective May 31, 1999 by
virtue of the scheduled termination of its subsidiaries' gas sales and gas
purchase contracts with Lone Star and MGNG. The Company has not replaced these
contracts although it continues to seek similar gas marketing acquisitions. As a
result, natural gas marketing operations impacted consolidated operations for
all of fiscal 1999 and none of fiscal 2000 or fiscal 2001.
Fiscal 2001 vs Fiscal 2000
OIL AND GAS SALES
Oil and gas sales increased $3,185 or 17.7% from fiscal 2000 to fiscal
2001. An analysis of the increase is as follows:
Fiscal Year Ended September 30, Increase
2001 2000 (Decrease)
---- ---- ----------
Production (Net):
Barrels of crude oil .............................................. 262,000 279,000 (17,000)
Mcf of natural gas ................................................ 3,083,000 3,547,000 (464,000)
Equivalent net of natural gas ..................................... 4,655,000 5,221,000 (566,000)
Oil and Gas Sales:
Before hedging .................................................... $ 21,144 $ 19,487 $ 1,657
Effect of hedging ................................................. (1,528) 1,528
----------- ----------- -----------
Net of hedging .................................................... $ 21,144 $ 17,959 $ 3,185
=========== =========== ===========
Average Price/MCFE:
Before hedging ......................................................... $ 4.54 $ 3.73 $ .81
Effect of hedging ...................................................... (0.29) 0.29
----------- ----------- -----------
Net .................................................................... $ 4.54 $ 3.44 $ 1.10
=========== =========== ===========
Analysis of Increase:
Price (5,221,000 mcfe x $.81/mcfe) ..................................... $ 4,229
Volume (566,000 mcfe x $4.54/mcfe) ..................................... (2,570)
Decrease in hedging losses ............................................. 1,528
Rounding ............................................................... (2)
-----------
$ 3,185
===========
-13-
For the year ended September 30, 2001, the Company's net production
averaged 718 barrels of crude per day and 8,447 mcfe of natural gas per day
versus 764 barrels of crude oil per day and 9,718 mcf of natural gas per day for
the year ended September 30, 2000.
The decline in production volumes is primarily attributable to the
depletion of the Company's oil and gas reserves and the fact that all but one of
the exploratory wells drilled in fiscal 2000 and 2001 by the Company resulted in
dry holes rather than production. The decline in production would have been
greater by 467,000 mcfe had the Company not acquired twenty- one producing East
Texas properties in April 2001 (see Items 1 and 2 above).
At the present time, natural gas spot prices are averaging less than
$3.00/mcf - far less than the average price of $4.53/mcf for the year ended
September 30, 2001 and the record prices of $9.00/mcf received for some
production in January 2001. In addition, current crude prices are slightly below
$20.00 per barrel - significantly less than the average price of $27.39 received
by the Company for the year ended September 30, 2001. Since the Company has not
hedged its production and since most credible experts are not predicting
significant increases for oil and gas prices in the short term, the Company
expects that its oil and gas revenues will decrease significantly in fiscal 2002
unless the Company successfully drills or acquires new reserves and/or oil and
as prices increase significantly. If the Company consummates the intended sale
of its domestic oil and gas properties to Delta (see Items 1 and 2 above), oil
and gas price or volume increases will affect both operations until closing of
the sale and the ultimate purchase price the Company receives. Net cash flow
between October 1, 2001, the effective date, and the closing date, would be
retained by the Company but would reduce the purchase price paid by Delta.
Oil and gas production expenses increased $1,205 or 19.5% from fiscal
2000 to fiscal 2001. The increase is primarily attributable to the acquisition
of twenty-one (21) producing properties in East Texas in April 2001. For the
year ended September 30, 2001 oil and gas production expenses, net of income
from well operations, were $1.59 per equivalent mcf sold versus $1.19 per
equivalent mcf sold for the year ended September 30, 2000. The increase results
primarily from two factors. When oil and gas prices increased substantially in
the beginning of fiscal 2001, so did operating costs. Such operating costs,
however, did not decrease or decreased less than oil and gas prices when oil and
gas prices receded sharply later in the fiscal year. A second factor
contributing to the increase is the fact that the average age of the Company's
producing properties is increasing - especially given the unsuccessful results
of the Company's exploratory drilling programs and the resultant lack of
reserves added by new drilling. Mature wells typically carry a higher production
expense burden than do newer wells that have not yet been significantly
depleted.
GENERAL AND ADMINISTRATIVE COSTS
General and administrative costs decreased $210 or 10.3% from fiscal
2000 to fiscal 2001. The decrease is primarily attributable to transferring some
costs associated with the Company's Oklahoma City office to corporate, general
and administrative costs and decreased consulting costs. Also, see "Corporate
General and Administrative Expenses" below.
DEPRECIATION, DEPLETION AND AMORTIZATION
Depreciation, depletion and amortization increased $261 on 8.1% from
fiscal 2000 to fiscal 2001. The components of depreciation, depletion and
amortization were as follows:
Year Ended September 30,
Increase
2001 2000 (Decrease)
---- ---- --------
Depreciation and amortization of furniture and fixtures and equipment...... $ 122 $ 219 ($ 97)
Depreciation, depletion and amortization of oil and gas properties......... 3,348 2,990 358
------- ------- ----
$ 3,470 $ 3,209 $261
======= ======= ====
Depreciation and amortization of furniture and fixtures and equipment
decreased $97 from fiscal 2000 to fiscal 2001 primarily because certain
furniture and fixture assets and vehicles were fully depreciated in fiscal 2000.
For the year ended September 30, 2001, the depletion rate per equivalent
mcf was $.72 in fiscal 2001 versus $.57 in fiscal 2000. The increase resulted
primarily from two factors. First, in April 2001, the Company acquired
twenty-one (21) East Texas wells at a higher cost per equivalent mcfe of
reserves than that for the Company's existing reserves, causing the Company's
average cost per mcfe of reserves to increase. Second, the depletion rate
increased significantly because of significantly lower reserves at September 30,
2001 compared to those at September 30, 2000. Reserves decreased primarily
because of much lower oil and gas prices at September 30, 2001 compared to
September 30, 2000. The lower reserves and higher costs at September 30, 2001
caused the depletion rate to increase.
-14-
IMPAIRMENT OF UNPROVED PROPERTIES
The impairment reserve for unproved properties increased $1,933 from
fiscal 2000 to fiscal 2001. To date, the Company has spent $3,597 participating
in the drilling of five dry holes or uneconomical wells on three concessions in
Romania and $110 with respect to the planned drilling of a sixth wildcat well in
the Black Sea on a second phase of one concession. In fiscal 2000, the Company
recorded an $832 reserve related to one drilling concession. The $2,765 reserve
incurred in 2001 relates to the other two drilling concessions. At September 30,
2001, impairment reserves have been provided for all costs incurred in Romania
except the $110 applicable to the planned sixth well in the Black Sea (see Note
4 to the Consolidated Financial Statements included in Item 8 of this Form
10-K).
CORPORATE GENERAL AND ADMINISTRATIVE EXPENSES
Corporate, general and administrative expenses increased $452 or 12.2%
from fiscal 2000 to fiscal 2001. The increase is primarily attributable to legal
costs related to the Long Trusts Litigation and the Texaco claim and $181
related to the Company's effort to sell its oil and gas properties earlier in
the fiscal year.
OTHER INCOME (EXPENSE)
Interest income decreased $143 or 18.2% from fiscal 2000 to fiscal 2001.
The decrease is primarily attributable to a decrease in the average balance of
cash invested during the periods being compared and to a decrease in the
interest rate received by the Company on invested funds.
The composition of other income (expense) for the years ended September
30, 2001 and 2000 is as follows:
Year Ended September 30,
2001 2000
---- ----
Litigation recovery (costs)........................................................... ($45)
Miscellaneous......................................................................... $42 70
--- ---
$42 $25
=== ===
PROVISION FOR INCOME TAXES
The tax provisions (benefit) for the years ended September 30, 2001 and
2000 consist of the following components:
Year Ended September 30,
2001 2000
---- ----
1. Decrease in net deferred tax asset using 36% Federal and state blended
tax rate..................................................................... $808 $ 948
2. Change in valuation allowance................................................ (431) (3,204)
4. Other (primarily revisions of previous estimates)............................ 4 (35)
---- ------
$381 ($2,291)
==== ======
The tax provision for the year ended September 30, 2001 consists
primarily of deferred taxes of $808 related to timing differences originating in
fiscal 2001 and a decrease of $431 in the valuation allowance from fiscal 2000.
The decrease in the valuation allowance resulted because the Company determined
that a portion of the deferred tax asset would more likely than not be realized
based upon estimates of future taxable income and upon the projected taxable
income resulting from the anticipated sale of its oil and gas assets to Delta
and, accordingly, decreased the valuation allowance by $431 to $3,559.
-15-
If recent decreases in oil and gas prices continue and if the sale of
the Company's oil and gas assets to Delta is not consummated, the Company may be
required to increase its valuation allowance.
The tax provision for the year ended September 30, 2000 consists
primarily of deferred taxes of $948 related to timing differences originating in
fiscal 2000 and the reversal of a $3,204 valuation reserve from fiscal 1999. The
reversal of the valuation reserve resulted because of positive evidence that the
Company would be able to generate sufficient taxable income in the future to
utilize its deferred tax asset. Such positive evidence consists primarily of the
increased value of the Company's oil and gas reserves as a result of
substantially higher oil and gas prices.
EARNINGS PER SHARE
Since November 1996, the Company has repurchased 4,871,020 or 69% of its
common shares. As a result of these share acquisitions, earnings per share are
significantly higher than they would be if no shares had been repurchased.
Fiscal 2000 vs Fiscal 1999
OIL AND GAS SALES
Oil and gas sales increased $11,247 or 167.6% from fiscal 1999 to fiscal
2000. An analysis of the increase is as follows:
Year Ended September 30,
-------------------------------------
2000 1999 Increase
---- ---- --------
Production (Net):
Barrels of crude oil............................................. 279,000 124,000 155,000
Mcf of natural gas............................................... 3,547,000 1,971,000 1,576,000
Equivalent net of natural gas.................................... 5,221,000 2,715,000 2,506,000
Oil and Gas Sales:
Before hedging................................................... $ 19,487 $ 6,862 $ 12,625
Effect of hedging................................................ (1,528) (150) (1,378)
--------- --------- ---------
Net of hedging................................................... $ 17,959 $ 6,712 $ 11,247
========= ========= =========
Average Price/MCFE:
Before hedging........................................................ $ 3.73 $ 2.53 $ 1.20
Effect of hedging..................................................... (0.29) (0.06) (0.23)
--------- --------- ---------
Net................................................................... $ 3.44 $ 2.47 $ .97
========= ========= =========
An analysis of the increase in oil and gas sales is as follows:
Analysis of Increase Before Hedging:
Price (2,715,000 mcfe x $1.20/mcfe)................................... $ 3,258
Volume (2,506,000 mcfe x $3.73/mcfe).................................. 9,347
Rounding.............................................................. 20
---------
$ 12,625
=========
Analysis of Increase After Hedging:
Price (2,715,000 mcfe x $.97/mcfe).................................... $ 2,634
Volume (2,506,000 mcfe x $3.44/mcfe).................................. 8,621
Rounding.............................................................. (8)
---------
$ 11,247
=========
The increase in production volumes is primarily attributable to the
acquisition of the AmBrit properties on June 1, 1999. As a result of this
acquisition, the production volumes attributable to the AmBrit properties
contributed twelve months of oil and gas sales for the year ended September 30,
2000 versus only four months of oil and gas sales for the year ended September
30, 1999.
For the year ended September 30, 2000, net production averaged 764
barrels of crude oil a day and 9,718 mcf of natural gas per day. A year ago the
Company had anticipated that such volumes would attain approximately 1,000
barrels of crude oil and approximately 13,000 mcf of natural gas per day. The
Company has not attained 1,000 net barrels a day of crude oil or 13,000 net mcf
of natural gas per day because it drilled eight dry holes out of nine
exploratory wells drilled in two exploratory drilling ventures in the United
States and because both of its wildcat wells drilled in Romania also resulted in
unproductive wells.
-16-
Oil and Gas Production Expenses
Oil and gas production expenses increased $4,284 or 224% from fiscal
1999 to fiscal 2000. The increase is primarily attributable to the acquisition
of the AmBrit Energy Corp. ("AmBrit") properties in June 1999. For the year
ended September 30, 2000 oil and gas production expenses, net of income from
well operations, were $1.19 per equivalent mcf sold versus only $.70 per
equivalent mcf sold for the year ended September 30, 1999. The increase results
primarily from two factors. The Company is not the operator for most of the
wells it acquired from AmBrit and, as a result, must pay the operator of such
wells monthly administrative reimbursement fees pursuant to the terms of the
governing joint operating agreements. Some of these fees are substantial and the
aggregate amount of such fees is much greater than that payable on the Company's
non- AmBrit properties. A second factor contributing to the increase is the fact
that the average age of the Company's producing properties is increasing -
especially given the unsuccessful results of the Company's exploratory drilling
programs. Mature wells typically carry a higher production expense burden than
do newer wells that have not yet been significantly depleted.
GENERAL AND ADMINISTRATIVE COSTS
General and administrative costs increased $1,000 or 96.3% from fiscal
1999 to fiscal 2000. The increase is primarily attributable to the Company's
establishment of an Oklahoma City office in February 2000, increased legal,
consulting and reservoir engineering fees and increased employee costs. Also,
see "Corporate General and Administrative Expenses" below.
DEPRECIATION, DEPLETION AND AMORTIZATION
Depreciation, depletion and amortization increased $1,163 or 56.8% from
fiscal 1999 to fiscal 2000. The components of depreciation, depletion and
amortization were as follows:
Year Ended September 30,
---------------------------------
2000 1999 Increase
---- ---- --------
Depreciation and amortization of furniture and fixtures and equipment....... $ 219 $ 109 $ 110
Depreciation, depletion and amortization of oil and gas properties.......... 2,990 1,937 1,053
------- ------- -------
$ 3,209 $ 2,046 $ 1,163
======= ======= =======
Depreciation and amortization of furniture and fixtures and equipment
increased $110 from fiscal 1999 to fiscal 2000 primarily because of depreciation
related to new vehicles purchased in late fiscal 1999 and early fiscal 2000 and
because of amortization of computer software commencing in the first quarter of
fiscal 2000.
For the year ended September 30, 2000, the depletion rate per
equivalent mcf was $.57 in fiscal 2000 versus $.71 in fiscal 1999. The net
decrease is the result of offsetting factors. The depletion rate indirectly
decreased because of substantially higher energy prices at September 30, 2000
versus those at September 30, 1999. As a result of such higher prices, the
Company's net economic oil and gas reserves increased substantially from 1999 to
2000 and related depreciation, depletion and amortization decreased
substantially because more equivalent mcfs of gas were allocated to essentially
the same depletable costs. This decrease was offset by the Company's expenditure
of approximately $7,600 in the acquisition of drilling acreage and drilling of
eight dry holes in the United States and two unproductive wells in Romania.
These expenditures increased the depletion rate because the related costs of
these drilling ventures were added to the Company's amortization base without a
concomitant increase in oil and gas reserves to be depleted.
-17-
IMPAIRMENT OF UNPROVED PROPERTIES
The Company recorded an impairment reserve for unproved property in
fiscal 2000 because the Company drilled an unproductive well on one of its three
Romanian concessions and does not plan to drill any additional onshore wells on
that concession hence it provided a reserve for the costs allocated to that
concession.
CORPORATE GENERAL AND ADMINISTRATIVE EXPENSES
Corporate, general and administrative expenses decreased $395 or 9.6%
from fiscal 1999 to fiscal 2000. The decrease is primarily attributable to
decreased insurance and legal costs. The $395 decrease in corporate, general and
administrative expenses was, however, offset by an increase of $1,000 in
exploration and production general and administrative expenses. (See above.) A
significant portion of the general and administrative expenses allocated to
corporate overhead in fiscal 1999 have been allocated to exploration and
production general and administrative costs in fiscal 2000 and are expected to
be so allocated in the future.
OTHER INCOME (EXPENSE)
Interest income decreased $917 or 53.9% from fiscal 1999 to fiscal 2000.
The decrease is primarily attributable to a decrease in the average balance of
cash outstanding during the periods being compared.
The composition of other income (expense) for the years ended September
30, 2000 and 1999 is as follows:
Year Ended September 30,
-----------------------
2000 1999
---- ----
Litigation recovery (costs).................................................... ($45) $355
Write-down of investment in Penn Octane Corporation preferred stock............ (423)
Market price adjustment of investment in Penn Octane Corporation common
stock.................................................................... 431
Miscellaneous.................................................................. 70 (11)
---- ----
$ 25 $352
==== ====
PROVISION FOR INCOME TAXES
The tax provision (benefit) for the years ended September 30, 2000 and
1999 consist of the following components:
Year Ended September 30,
2000 1999
---- ----
1. Increase in net deferred tax asset using 36% Federal and state blended tax rate.. ($2,256)
2. Utilization of deferred tax asset, net of related valuation reserves, using 36%
blended Federal and state tax rate............................................... $2,765
3. A tax provision of 2% on all net income in excess of that required to
realize the net deferred tax asset. (This 2% rate represents alternative
minimum Federal corporate taxes the Company must pay despite having tax
carryforwards and credits available to offset regular Federal corporate tax)..... 71
4. Other (primarily revisions of previous estimates)................................ (35) 120
------ ------
$2,291 $2,956
====== ======
The tax provision for the year ended September 30, 2000, consists
primarily of deferred taxes of $948 related to timing differences originating in
fiscal 2000 and the reversal of a $3,204 valuation reserve from fiscal 1999. The
reversal of the valuation reserve resulted because of positive evidence that the
Company will be able to generate sufficient taxable income in the future to
utilize its deferred tax asset. Such positive evidence consists primarily of the
increased value of the Company's oil and gas reserves as a result of
substantially higher oil and gas prices.
-18-
The tax provision for the year ended September 30, 1999 consists of
utilization of the $2,765 of remaining net deferred tax assets at September 30,
1998, $71 of Federal alternative minimum taxes on net income in excess of that
required to fully utilize the $2,765 net deferred tax asset using a 36% blended
tax rate and $120 of other taxes related to revisions to the prior year's
taxable income. The fiscal 1999 blended Federal and state income tax rate was
26%, which is lower than the statutory rate due to the utilization of statutory
depletion and tax credits. The Company did not record a net deferred tax asset
at September 30, 1999 because it determined that future taxable income was less
certain given the Company's large exploratory and wildcat drilling programs, the
expiration of the Lone Star Contract, contingent environmental liabilities and
other factors.
EARNINGS PER SHARE
Since November 1996, the Company has repurchased 4,831,020 or 69% of its
common shares. As a result of these share acquisitions, earnings per share are
significantly higher than they would be if no shares had been repurchased.
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
sources and expected cash obligations discussed below. All forward-looking
statements in this Form 10-K are expressly qualified in their entirety by the
cautionary statements in this paragraph.
During the year ended September 30, 2001, the Company generated $11,884
from operating activities. During the same period the Company invested $15,449
in oil and gas properties and $572 to reacquire shares of its common stock. In
addition, it paid $1,326 in stockholder dividends. At September 30, 2001, the
Company had $5,844 of unrestricted cash, $10,409 of working capital and no
long-term debt.
Discontinued Refining Operations
Although the Company's former and present 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 12 to the
consolidated financial statements included in Item 8 of this Form 10-K).
As noted previously, the Company entered into a letter of intent to sell
all of its domestic oil and gas properties to Delta. Closing of the transaction
is anticipated between March 31, 2002 and June 30, 2002. The Company's expected
uses and sources of funds assuming this transaction closes on April 30, 2002 are
as follows:
Expected Uses of Funds
----------------------
Funds to support bond for appeal of verdict in Long Trusts Lawsuit..................... $3,000
Reduction of trade payables............................................................ 1,025
Estimated drilling costs for wildcat in Black Sea (excludes completion costs if well
successful)......................................................................... 1,000
Dividends to shareholders.............................................................. 990
Recompletions and reworks on existing wells............................................ 600
--------
$6,615
========
If sufficient funds are available, the Company may also consider an
additional investment in Networked. The Company does not expect to undertake any
significant developmental drilling since it has entered into a letter of intent
to sell its oil and gas properties to Delta for a fixed price (see Items 1 and 2
above) effective October 1, 2001. The Company may also continue to repurchase
its shares if funds are available.
-19-
Expected Sources of Funds
-------------------------
Proceeds of sale of oil/gas properties to Delta at closing............................ $15,500
Unrestricted cash - September 30, 2001................................................ 5,844
Letter of credit portion of credit facility........................................... 3,000
---------
$24,344
=========
The Company expects only marginally positive cash flow from operations
during the period from October 1, 2001 to April 30, 2002 given current low oil
and gas prices. If such prices increase, the Company may be able to fund some of
its expected expenditures from cash flow from oil and gas operations.
Conversely, the Company could experience negative cash flow from oil and gas
operations if oil and gas prices decrease from present levels.
In addition, the Company owns marketable securities which had a market
value (also book value) of $6,722 at September 30, 2001 and the Company could
liquidate these and use the proceeds to fund planned expenditures if needed.
Most of the marketable securities owned by the Company, however, are the common
stocks of Delta (382,289 shares) and Penn Octane Corporation ("Penn Octane"), a
small public company involved in the sale of liquid propane gas in Mexico
(1,343,600 shares). Both of these companies are thinly traded and volatile and
the Company may, therefore, not be able to liquidate its shares in Delta and
Penn Octane at recorded values - especially if such shares must be liquidated
quickly in the market.
If the sale to Delta is consummated as planned, the Company will also
receive 9,566,000 shares of Delta common stock.
The closing of the sale of the Company's domestic oil and gas properties
to Delta is subject to numerous conditions, including execution of a definitive
agreement by December 31, 2001, approval of the sale by the Company's and
Delta's boards of directors and approval by Delta's shareholders. Accordingly,
there can be no assurance that the contemplated sale will close or that it will
close when anticipated. In addition, economic conditions could change between
the present time and closing and either Delta or the Company may not conclude
the transaction, although the party failing to close could be subject to
significant penalties pursuant to the terms of the letter of intent.
If the Delta transaction does not close, the Company's expected uses and
sources of funds for the period October 1, 2001 to September 30, 2002 are
approximately as follows:
Expected Uses of Funds
----------------------
Developmental drilling.................................................................... $ 5,286
Funds to support bond for appeal of verdict in Long Trusts lawsuit........................ 3,000
Reduction of trade payables............................................................... 1,025
Estimated drilling costs for wildcat well in the Black Sea................................ 1,000
Recompletions and reworks on existing wells............................................... 600
Dividends to shareholders................................................................. 1,320
---------
$ 12,231
=========
As noted above, the Company may also consider additional investments in
Networked and further repurchase of its shares if sufficient cash is available.
In addition, the Company may consider acquisitions of other properties or
exploration and production companies, as it has in the past.
Expected Sources of Funds
-------------------------
Unrestricted cash - September 30, 2001.................................................... $ 5,844
Letter of credit portion of credit facility............................................... 3,000
Expected minimum cash available for drilling under credit facility ($12,500-$3,000
letter of credit)...................................................................... 9,500
--------
$ 18,344
========
The amount that can be borrowed under the Company's line of credit will
be determined by the energy bank making the loan based upon its parameters and
will probably change based upon past production, changes in oil and gas prices
and other factors.
-20-
In addition, the same comments, as above, apply concerning the Company's
possible use of its marketable securities or cash flow from operations to fund
expected expenditures.
The Company's future operations are subject to the following risks:
a. Failure of Delta Transaction to Close
-------------------------------------
There are several reasons why the Delta transaction may not
ultimately close - including but not limited to failure of the
parties to enter into a definitive purchase and sale agreement,
failure to approve the transaction by the boards of directors of
Delta and/or the Company or both, failure of the Delta shareholders
to approve the transaction and failure of either party to consummate
the transaction. In addition, the Securities and Exchange Commission
may review Delta's proxy to its shareholders and such review may
delay closing.
If the transaction does not close the Company may miss drilling or
acquisition opportunities and may suffer the loss of key employees -
thus impeding its future operations. The Company has only thirty
employees. It cannot simply switch gears from a divestiture mode to
an acquisition mode without major disruption to its operations as
can much larger exploration and production companies. The Company
may find it difficult to retain key employees given that it has
formally put its assets up for sale twice in the last year. Loss of
key employees could negatively impact the Company's ability to meet
the myriad of accounting and regulatory requirements to which the
Company is subject as a public company.
b. 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 claimed 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 was initially 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, 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. In November 1999, the
Company received a request for information from the EPA concerning
the Company's involvement in the ownership and operation of the
Indian Refinery. The Company responded to the EPA in January 2000
and has received no further correspondence from the EPA. On August
7, 2000, the Company received notice of a claim against it and two
of its inactive refining subsidiaries from Texaco and its parent. In
its claim, Texaco demanded that the Company and its former
subsidiaries indemnify Texaco for all liability resulting from
environmental contamination at and around the Indian Refinery. In
addition, Texaco demanded that the Company assume Texaco's defense
in all matters relating to environmental contamination at and around
the Indian Refinery, including lawsuits, claims and administrative
actions initiated by the EPA as well as indemnify Texaco for costs
that Texaco had already incurred addressing environmental
contamination at the Indian Refinery. Finally, Texaco also claimed
that the Company and its two inactive subsidiaries are liable to
Texaco under the Federal Comprehensive Environmental Response
Compensation and Liability Act as owners and operators of the Indian
Refinery. The Company's management and special counsel subsequently
met and continue to discuss Texaco's claims with representatives of
Chevron/Texaco but the parties disagree concerning the validity of
Texaco's claims. The Company and its special counsel believe that
Texaco's claims are utterly without merit and the Company intends to
vigorously defend itself against Texaco's claims and any lawsuits
that may follow.
-21-
Estimated undiscounted clean-up costs for the Indian Refinery are
$80,000 to $150,000 according to third parties. If the Company were
found liable for the remediation of the Indian Refinery, it could be
required to pay a percentage of the clean-up costs. Since the
Company's subsidiary only operated the Indian Refinery five years
whereas Texaco and others operated it over 50 years, the Company
would expect that its share of any remediation liability would be
proportional to its years of operation although such may not be the
case. 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 decision by
the U.S. Supreme Court in June 1998 in a comparable case and a
recent decision by a U.S. Appeal Court for the Fifth Circuit support
the Company's positions.
The above estimate of expected cash resources and cash uses assumes
no expenditure for contingent environmental liabilities or legal
defense costs related to the Indian Refinery. If the Company is sued
and related legal proceedings continue longer than expected
(environmental litigation often continues 3-5 years or more) and/or
the Company is found liable for a portion of the environmental
remediation of either the Indian Refinery or Powerine Refinery,
estimated cash uses will be increased and such increase could be
significant.
c. IRLP Vendor Liabilities:
-----------------------
IRLP owes its vendors approximately $5,000. Its only major asset was
a $5,388 note due from the purchaser of the Indian Refinery,
American Western. IRLP has agreed to settle its $5,388 note for $612
in exchange for a covenant of the EPA not to sue IRLP. These
provisions are included in the Plan of Liquidation of American
Western which American Western expects to be confirmed in January
2002. Assuming American Western's Plan of Liquidation is confirmed,
IRLP will be able to pay its creditors only a small portion of the
amounts owed to them.
d. 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
repurchased 4,871,020 shares or 69% of its outstanding common stock
since November of 1996 and was the major market maker in the
Company's stock for much of the period. If the Company ceases
repurchasing shares, the market value of the Company's stock may be
adversely affected.
e. Foreign Operating Risks
-----------------------
As of September 30, 2001, the Company had incurred $3,597 drilling
five wildcat wells (resulting in dry holes or uneconomic wells) on
three Romanian concessions. The Company plans to drill a sixth
wildcat well in the Black Sea in the spring or early summer of 2002.
The Company's Romanian operations are subject to certain foreign
country risks over which the Company has no control - including
political risk, currency risk, the risk of additional taxation and
the possibility that foreign operating requirements and procedures
may reduce or eliminate estimated profitability.
f. Exploration and Production Reserve Risk
---------------------------------------
The Company plans to participate in the drilling of a sixth Romanian
wildcat well in the Black Sea whether or not it closes the sale of
its domestic properties to Delta (see page 2). The planned wildcat
well in the Black Sea involves high risk wildcat drilling where the
probability of discovering commercial oil and gas reserves is less
than twenty percent (20%). If the sale to Delta or a similar sale
does not occur, the Company may also participate in the drilling of
several domestic development wells and recompletions of existing
wells to other producing zones. Drilling investments are essentially
sunk cost. Reserve risk is the possibility that the reserves
discovered, if any, will not approximate those the Company has
estimated before drilling. If commercial reserves are not found or
not found in the quantities anticipated, the Company's future
operations and cash flow will be adversely affected and the Company
could be required to record an impairment provision for its oil and
gas properties pursuant to the full cost accounting method. (See
Note 2 to the financial statements included as Item 8 to this Form
10-K).
-22-
g. Exploration and Production Price Risk
-------------------------------------
The Company did not hedge any of its anticipated future oil and gas
production because the cost to do so appeared excessive when
compared to the risk involved. As a result, the Company remains
exposed to future oil and gas price changes with respect to all of
its anticipated future oil and gas production. Such exposure could
be considerable given the volatility of oil and gas prices. For
example, from January 2001 to November 2001, crude oil prices
decreased approximately 25% and natural gas prices decreased
approximately 65%. Current oil and gas prices are low and are
generally not predicted to increase appreciably over the next 2-4
years. In the past crude oil prices and gas prices have shown
general volatility over short periods of time and it is possible
that prices could change significantly and suddenly as they have in
the past.
The Company follows the full-cost method of accounting for oil and
gas properties and equipment costs. Under this method of accounting
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% and the cost of properties not being amortized, if
any, are charged to expense (full cost ceiling test). If at a future
reporting date oil and gas prices decline below the prices used to
perform the full cost ceiling test at September 30, 2001, the
Company estimates that it would likely incur a charge to expense.
h. Exploration and Production Operating Risk
-----------------------------------------
All of the Company's current oil and gas properties are onshore
properties with relatively low operating risk. Nevertheless, the
Company faces the risks encountered from operating over 250 oil and
gas wells in several states - including the risks of oil and gas
spills, resulting environmental damage, third party liability claims
related to operations, including claims by landowners where the
operated wells are located, and general operating risks.
i. Other Risks
-----------
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 and the risks associated with the increased litigation that
appear to affect most corporations.
j. Future of the Company
---------------------
In the last three years the regulatory burdens and related costs of
being a public company have increased significantly. New
requirements have been added by the Securities and Exchange
Commission, the Nasdaq stock market and the Financial Accounting
Standards Board at an accelerated pace including but not limited to
requiring reviews of quarterly financial statements, increased Audit
Committee procedures and protocol and compliance with new accounting
and disclosure requirements. This has resulted in increased fees
paid by the Company and diversion of management's efforts. In short,
the Company's current level of operations are not sufficiently large
to bear the Company's current general and administrative burden. In
addition, the Company's high oil and gas production expense burden
is at least partially attributable to the fact that the Company's
fixed production costs are not spread over a larger number of and
more productive oil and gas wells. As a result of these and other
factors, the Company has not only aggressively sought to acquire
properties to achieve a critical mass over which to apply its
general and administrative expenses but has also sought to sell it
properties when the conditions appeared most favorable. Although the
Company has purchased approximately $34,000 of producing properties
in the last three years, it has still not achieved the critical mass
necessary to support its general and administrative burden.
As noted earlier, the Company has entered into a letter of intent to
sell all of its domestic oil and gas properties to Delta on terms
the Company's management consider favorable. The Company's
management considers such a transaction prudent given the
uncertainty of oil and gas prices and the significant costs to
operate a public company. If the Delta transaction fails to close as
planned, the Company expects to continue to seek similar
transactions on similar or better terms. The Company may also seek a
merger with another company although to date the claims made by
Texaco against the Company have hindered this process. Nevertheless,
there can be no assurance that the Company will be able to succeed
in this endeavor and the Company's management and board of directors
may decide to continue to seek future acquisitions in the oil and
gas sector when conditions are favorable and to attain the needed
critical mass in that manner.
-23-
QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The Company has not hedged its anticipated oil and gas production and
thus remains at risk with respect to the prices it receives for such production.
If oil and gas prices increase, the Company's oil and gas revenues will
increase. Conversely, if oil and gas prices decrease, the Company's oil and gas
revenues will also decrease. Oil and gas prices are currently much lower than
they have been in several months and many forecasters are anticipating continued
lower oil and gas prices for several years. There can be, however, no assurance
that such prices will increase in the future or even remain at current levels
given recent oil and gas price volatility.
INFLATION AND CHANGING PRICES
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
Statement of Financial Accounting Standards No. 133, as amended,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS No. 133"),
was issued by the Financial Accounting Standards Board in June 1998.
Subsequently, SFAS No. 138 "Accounting for Certain Derivative Instruments"
("SFAS No. 138"), an amendment of SFAS No. 133, was issued. SFAS 133 and SFAS
138 standardize 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 such instrument
has been designated and qualifies as part of a hedging relationship and, if so,
depends 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 (not included in 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 adopted
SFAS No. 133 and SFAS No. 138 effective October 1, 2000. The Company ceased
hedging its oil and gas production in July 2000. At September 30, 2001 and 2000,
the Company had no freestanding derivative instruments in place and had no
embedded derivative instruments. As a result, the Company's adoption of SFAS No.
133 and SFAS No. 138 had no impact on its results of operations or financial
condition.
Statement of Financial Accounting Standards No. 141, "Business
Combinations" ("SFAS No. 141") and Statement of Financial Accounting Standards
No. 142, "Goodwill and Other Intangible Assets" ("SFAS No. 142") were issued in
July 2001. SFAS No. 141 requires that all business combinations entered into
subsequent to June 30, 2001 be accounted for under the purchase method of
accounting and that certain acquired intangible assets in a business combination
be recognized and reported as assets apart from goodwill. SFAS No. 142 requires
that amortization of goodwill be replaced with periodic tests of the goodwill's
impairment at least annually in accordance with the provisions of SFAS No. 142
and that intangible assets other than goodwill be amortized over their useful
lives. The Company adopted SFAS No. 141 in July 2001 and will adopt SFAS No. 142
in the first quarter of fiscal 2003. The Company does not believe that its
future adoption of SFAS No. 142 will have a material effect on its results of
operations.
In June 2001, the FASB issued Statement No. 143, "Accounting for Asset
Retirement Obligations" ("SFAS No. 143"), which provides accounting requirements
for retirement obligations associated with tangible long-lived assets,
including: 1) the timing of liability recognition; 2) initial measurement of the
liability; 3) allocation of asset retirement cost to expense; 4) subsequent
measurement of the liability; and 5) financial statement disclosures. SFAS No.
143 requires that asset retirement cost be capitalized as part of the cost of
the related long-lived asset and subsequently allocated to expense using a
systematic and rational method. Any transition adjustment resulting from the
adoption of SFAS No. 143 would be reported as a cumulative effect of a change in
accounting principle. The Company will adopt the statement effective October 1,
2002. At this time, the Company cannot reasonably estimate the effect of the
adoption of this statement on either its financial position or results of
operations.
-24-
In August 2001, the FASB issued Statement No. 144, "Accounting for
the Impairment or Disposal of Long-Lived Assets" ("SFAS No. 144"), which will be
effective for financial statements issued for fiscal years beginning after
December 15, 2001 and interim periods within those fiscal years. SFAS No. 144
requires that long-lived assets to be disposed of by sale be measured at the
lower of the carrying amount or fair value less cost to sell, whether reported
in continuing operations or in discontinued operations. SFAS No. 144 broadens
the reporting of discontinued operations to include all components of an entity
with operations that can be distinguished from the rest of the entity and that
will be eliminated from the ongoing operations of the entity in a disposal
transaction. After its effective date, SFAS No. 144 will be applied to those
transactions where appropriate. The Company will adopt SFAS No 144 effective
October 1, 2002. At this time the Company is unable to determine what the future
impact of adopting this statement will have on its financial position or results
of operations.
-24-
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
----
CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Statements of Operations for the Years Ended September 30, 2001, 2000 and 1999................. 27
Consolidated Balance Sheets as of September 30, 2001 and 2000............................................... 28
Consolidated Statements of Cash Flows for the Years Ended Sep