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U.S. Securities and Exchange Commission
Washington, D.C. 20549
Form 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 For the fiscal year ended December 31, 2001
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 For the transition period from to
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Commission File No.: 0-20760
GREKA Energy Corporation
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(Name of issuer in its charter)
Colorado 84-1091986
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(State or other jurisdiction (I.R.S. Employer
incorporation or organization) Identification Number)
630 Fifth Avenue, Suite 1501 New York, NY 10111
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(Address of principal executive offices) (Zip Code)
Issuer's telephone number: (212) 218-4680
Securities registered under Section 12(b) of the Exchange Act:
None
Securities registered under Section 12(g) of the Exchange Act:
No Par Value Common Stock.
Check whether the issuer (1) filed all reports required to be filed by Section
13 or 15(d) of the Exchange Act during the past 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 [ ]
Check if there is no disclosure of delinquent filers in response to Item 405 of
Regulation S-B contained in this form, and no disclosure will be contained, to
the best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
The issuer's revenues for 2001 were $40,755,282.
The aggregate market value of 4,391,644 shares of common stock held by
non-affiliates of the issuer, based on the closing bid price of the common stock
on April 30, 2002 of $6.11 as reported on the Nasdaq National Market System and
based on a total of 4,698,368 shares being outstanding on that date, was
$26,832,945.
(ISSUERS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PAST FIVE YEARS)
Check whether the issuer has filed all documents and reports required to be
filed by Section 12, 13 or 15(d) of the Exchange Act after the distribution of
securities under a plan confirmed by a court. Yes [X] No [ ]
Transitional Small Business Disclosure Format (check one).
Yes [ ] No [X]
Table of Contents
PART I ............................................................... 5
Item 1. Description of Business........................................ 5
Item 2. Description of Property........................................ 13
Item 3. Legal Proceedings.............................................. 22
Item 4. Submission of Matters to a Vote of Security Holders............ 22
PART II. ............................................................... 23
Item 5. Market for Common Equity and Related Stockholder Matters....... 23
Item 6. Selected Financial Data........................................ 23
Item 7. Management's Discussion and Analysis of Financial
Conditions and Results of Operation............................ 24
Item 7A. Quantitative and Qualitative Disclosures About Market Risk..... 27
Item 8. Financial Statements........................................... 28
Item 9. Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure............................ 28
PART III. ............................................................... 29
Item 10. Directors, Executive Officers, Promoters and Control Persons;
Compliance With Section 16(a) of the Exchange Act.............. 29
Item 11. Executive Compensation......................................... 31
Item 12. Security Ownership of Certain Beneficial Owners
and Management................................................. 34
Item 13. Certain Relationships and Related Transactions................. 35
Part IV. ............................................................... 36
Item 14. Exhibits and Reports on Form 8-K............................... 36
Definitions
The terms below are used in this document and have specific SEC
definitions as follows:
Proved oil and gas reserves. Proved oil and gas reserves are the
estimated quantities of crude oil and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate is made. Prices
include consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions.
Proved developed oil and gas reserves. Proved developed oil and gas
reserves are reserves that can be expected to be recovered through existing
wells with existing equipment and operating methods. Additional oil and gas
expected to be obtained through the application of fluid injection or other
improved recovery techniques for implementing the natural forces and mechanisms
of primary recovery is included as "proved developed reserves" only after
testing by a pilot project or after the operation of an installed program has
confirmed through production response that increased recovery will be achieved.
Proved undeveloped reserves. Proved undeveloped oil and gas reserves
are reserves that are expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major expenditure is required
for recompletion. Reserves on undrilled acreage is limited to those drilling
units offsetting productive units that are reasonably certain of production when
drilled. Proved reserves for other undrilled units is claimed only where it can
be demonstrated with certainty that there is continuity of production from the
existing productive formation. Under no circumstances are estimates for proved
undeveloped reserves attributable to any acreage for which an application of
fluid injection or other improved recovery technique is contemplated, unless
such techniques have been proved effective by actual tests in the area and in
the same reservoir.
As used in this Form 10-K:
"Mcf" means thousand cubic feet, "MMcf" means million cubic feet,
"Bcf" means billion cubic feet, "Tcf" means trillion cubic feet, "Bbl" means
barrel, "MBbls" means thousand barrels, "MMBbls" means million barrels, "BOE"
means equivalent barrels of oil, "MBOE" means thousand equivalent barrels of oil
and "MMBOE" means million equivalent barrels of oil.
Unless otherwise indicated in this Form 10-K, gas volumes are stated
at the legal pressure base of the state or area in which the reserves are
located and at 60/o/ Fahrenheit. Equivalent barrels of oil are determined using
the ratio of 5.5 Mcf of gas to 1 Bbl of oil.
The term "gross" refers to the total acres or wells in which the
Company has a working interest, and "net" refers to gross acres or wells
multiplied by the percentage working interest owned by the Company. "Net
production" means production that is owned by the Company less royalties and
production due others.
Cautionary Information About Forward-Looking Statements
This document contains forward-looking statements within the meaning
of Section 27A of the Securities Act and Section 21E of the Exchange Act. All
statements, other than statements of historical facts, included in or
incorporated by reference into this Form 10-K which address activities, events
or developments which the Company expects, believes or anticipates will or may
occur in the future are forward-looking statements. The words "believes,"
"intends," "expects," "anticipates," "projects," "estimates," "predicts" and
similar expressions are also intended to identify forward-looking statements.
These forward-looking statements include, among others, statements concerning:
... the benefits expected to result from GREKA's 1999 acquisition of Saba
Petroleum Company ("Saba") discussed below, including
... synergies in the form of increased revenues,
... decreased expenses and avoided expenses and expenditures that are expected
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to be realized as a result of the Saba acquisition, and
... the complementary nature of GREKA's horizontal drilling technology and
certain oil reserves acquired with the acquisition of Saba, and other
statements of:
... expectations,
... anticipations,
... beliefs,
... estimations,
... projections, and
other similar matters that are not historical facts, including such matters as:
... future capital,
... development and exploration expenditures (including the timing, amount and
nature thereof),
... drilling and reworking of wells, reserve estimates (including estimates of
future net revenues associated with such reserves and the present value of
such future net revenues),
... future production of oil and gas,
... repayment of debt,
... business strategies,
... oil, gas and asphalt prices and demand,
... exploitation and exploration prospects,
... expansion and other development trends of the oil and gas industry, and
... expansion and growth of business operations.
These statements are based on certain assumptions and analyses made by
the management of GREKA in light of its experience and its perception of
historical trends, current conditions and expected future developments as well
as other factors it believes are appropriate in the circumstances.
GREKA cautions the reader that these forward-looking statements are
subject to risks and uncertainties, including those associated with:
... our ability to refinance our debt on favorable terms,
... our ability to successfully restructure our operations,
... the financial environment,
... general economic, market and business conditions,
... the regulatory environment,
... business opportunities that may be presented to and pursued by GREKA,
... changes in laws or regulations
... exploitation and exploration successes,
... availability to obtain additional financing on favorable conditions,
... trend projections, and
... other factors, many of which are beyond GREKA's control that could cause
actual events or results to differ materially from those expressed or
implied by the statements. Such risks and uncertainties include those risks
4
and uncertainties identified in the Description of the Business and
Management's Discussion and Analysis sections of this document and risk
factors discussed from time to time in the Company's filings with the
Securities and Exchange Commission.
Significant factors that could prevent GREKA from achieving its stated
goals include:
... the inability of GREKA to obtain financing for capital expenditures and
acquisitions,
... declines in the market prices for oil, gas and asphalt, and
... adverse changes in the regulatory environment affecting GREKA.
The cautionary statements contained or referred to in this document
should be considered in connection with any subsequent written or oral
forward-looking statements that may be issued by GREKA or persons acting on its
or their behalf.
GREKA undertakes no obligation to release publicly any revisions to
any forward-looking statements to reflect events or circumstances after the date
hereof or to reflect the occurrence of unanticipated events.
PART I
Item 1. Description of Business
Overview of GREKA Energy Corporation
GREKA Energy Corporation, a Colorado corporation ("GREKA" or the
"Company") is a vertically-integrated energy company with primary areas of
activities in California and long-term in China. The Company is committed to
creating shareholder value by principally focusing on exploiting the high cash
margin created from the relatively stable natural hedge by its crude production
and the asphalt market in Central California. GREKA's operations are primarily
conducted through our wholly owned subsidiaries established as business segments
to allow for concentrated operations by region and/or markets. (Refer to
financial statements NOTE 1 - Description of Business)
As of December 31, 2001, the Company had estimated net proved reserves
of approximately 13,576 MBOE with a PV-10 value before tax of $56.6 million.
During 2001, the estimated net proved reserves have been lowered by 2,086 MBOE.
During 2001, the throughput at the Company's asphalt refinery averaged
approximately 2,370 BBL per day with the Company's present goal of reaching
efficient plant capacity of 7,500 BBL per day by year-end 2003. Of this
throughput, the Company's subsidiaries supplied an average of approximately 46%,
or 1,090 BBL per day, from their production in California, and we plan to focus
on increasing our feedstock during 2002. Also in 2001, we reported exploration
success at the Potash Field, Plaquemines Parish, Louisiana with our drilling of
the HD No. 1 well with initial production at over 6 MMCF per day and current
production at 510 BOEPD (or 60 BOPD and 2.7 MMCFD) per day.
Our principal offices are located at 630 Fifth Avenue, Suite 1501, New
York, New York 10111 and our telephone number is (212) 218-4680.
Business Strategy
In March 2002, we announced a restructuring of our business to focus
on the integration of our Central California operations, which assets include
our asphalt refinery and interests in heavy oil fields. GREKA's proactive and
aggressive restructuring plan is designed to provide increased profitability and
cash flow stability.
We have established a strategy that capitalizes on our asset base to
enhance shareholder value as follows:
Integrated Operations
Operations of GREKA are planned to focus on the integration of our
subsidiaries' Santa Maria (California) assets, including an asphalt refinery and
interests in heavy oil fields. The hedged operations are targeted to capitalize
on the stable asphalt market in California by providing a balance of equity and
third
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party feedstock (heavy oil) into the refinery. The integration of the
refinery (100% owned) with the interests in the heavy oil producing fields (100%
working interest) has successfully provided a stable ongoing hedge to GREKA on
each equity barrel since June 1999. GREKA's strategy in these integrated assets
is to proceed with acquisitions that enhance the long-term feedstock supply to
the refinery and to cost-efficiently boost production rates from the potential
drilling locations identified in the Santa Maria Valley area of central
California. We anticipate that the profitability from these integrated
operations will not be affected by volatile oil prices. It is also anticipated
that, by using our equity barrels to supply the refinery, working capital
requirements should be lower and cash flow should be enhanced. The continued
stability of the price of asphalt, coupled with reduced costs for processing and
lifting, should create substantial value for GREKA's shareholders.
In March 2002, we announced as part of GREKA's unique business
strategy in its integrated assets that we had closed into escrow our acquisition
of Vintage Petroleum, Inc.'s oil and gas producing properties and facilities in
the Santa Maria Valley of Central California. Subject to customary terms and
conditions, a final closing out of escrow effective December 1, 2001 is
scheduled to occur by May 31, 2002. During this escrow period, Vintage will
continue to operate the properties while the crude will be delivered to GREKA's
asphalt refinery, ramping up from approximately 800 BBL per day to approximately
2,000 BBL per day as of April 1st. This acquisition will increase the current
equity throughput of approximately 1,200 BBL per day to approximately 3,200 BBL
per day into the refinery.
Divestiture of E&P Assets
In March 2002, we announced GREKA's determination that our traditional
exploitation and production assets are inconsistent with our restructured
business strategy going forward. During second quarter 2002, we plan to sell
GREKA's interests in these assets primarily including the Potash Field,
Plaquemines Parish, Louisiana; Manila Village, Jefferson Parish, Louisiana;
Richfield East Dome Unit, Orange County, California; and PRC 91, Orange County,
California. The Company is further pursuing the sale of our exploration
interests in Indonesia and a limestone reserve in Indiana.
Exploitation, Exploration & Production
We plan to focus on our existing concessions in strategic locations,
such as China, where GREKA believes there is a significant, long-term demand for
energy and a niche advantage for the Company. GREKA plans to continuously pursue
new, emerging opportunities in the energy business to identify and evaluate
niche markets for our proprietary drilling technology. Two specific niche
targets are coal bed methane projects and gas storage. These opportunities
should provide significant upside from the use of short radius horizontal
laterals.
Business Development of GREKA
GREKA Energy Corporation was formed in 1988 as a Colorado corporation
under the name of Kiwi III, Ltd. On May 13, 1996, GREKA, then known as Petro
Union, Inc., filed a voluntary petition for relief pursuant to Chapter 11 of the
United States Bankruptcy Code. Current GREKA management acquired Petro Union,
Inc. and simultaneously procured on August 28, 1997, an order confirming Petro
Union's First Amended Plan of Reorganization from the Bankruptcy Court for the
Southern District of Indiana. The bankruptcy court approved the final accounting
and closed the bankruptcy proceedings on March 26, 1998.
During 1998, our management focused substantially all of its efforts
on corporate restructuring, recapitalization and acquisition efforts and an
investment in a horizontal drilling pilot program in the Cat Canyon field in
California that all were part of implementing its strategic niche growth plan.
During the latter part of 1998 and early 1999, management was primarily focused
on the acquisition of Saba, which had substantial reserves suited to
exploitation by GREKA's horizontal drilling technology, and considerable
expenses were incurred in connection with the Saba transactions in the first
quarter of 1999.
On March 22, 1999, the Company, then known as Horizontal Ventures,
Inc., changed its name to GREKA Energy Corporation. Effective March 24, 1999,
GREKA acquired Saba Petroleum Company as a wholly owned subsidiary.
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Immediately subsequent to the completion of the Saba acquisition,
management commenced its strategy to reverse the decline in value of the Saba
assets which included securing bank financing of up to $47.0 million, reducing
Saba debt by $27.2 million, assuming full operation of our asphalt refinery
which significantly increased operating cash flows, selling our non-core assets
in Colombia while maintaining our repurchase option, acquiring all of the shares
we did not already own of Beaver Lake Resources Corporation ("Beaver Lake"), and
signing a production sharing contract with the China United Coalbed Methane
Corporation Ltd. to jointly exploit coalbed methane (CBM) resources in China.
During December 1999, GREKA commenced trading on the Nasdaq National Market
System.
During 2000, management exercised GREKA's option to repurchase our
Colombian assets, closed the financing with a new bank, Canadian Imperial Bank
of Commerce ("CIBC"), of up to $47.5 million with a portion of the proceeds used
to reduce current debt resulting in the complete elimination of Saba's defaulted
bank debt, completed the sale of all our non-core assets in Canada, settled with
Capco Resources, Ltd. and its related parties whereby GREKA cancelled 840,000
shares of its common stock for $5.2 million and gained voting control over the
remaining 514,500 shares owned by Capco, declared a payment of a 5% stock
dividend to our shareholders of record at close of market on December 31, 2000,
and completed a spot secondary public offering of 542,785 (including
over-allotment option) at a price of $13.10 per share.
Year 2001 Highlights
Highlights announced during 2001 include the following:
. In February 2001, GREKA increased up to $46 million its credit
facility with GMAC Commercial Credit LLC ("GMAC").
. In March 2001, GREKA secured financing of up to $75 million with
a new bank, closing on a revolving credit line of $16 million
with an initial advance of $13.2 million.
. In July 2001, GREKA announced a repurchase program to buy back up
to 10% of its outstanding common stock.
. In August 2001, GREKA concluded the Colombian transaction
resulting in its receipt of cash and assets with an aggregate
value estimated by the Company of up to $14 million.
. In October 2001, GREKA announced exploration success at the
Potash Field with the drilling of its HD No. 1 well with initial
production at over 6 MMCF per day.
. GREKA concluded all material legal matters. In October 2001,
after an August 2001 court order awarding RGC International
Investors $13.25 million on its claim, GREKA settled by paying
RGC $11.5 million.
Acquisition Activities
California E&P Assets
In September 2001, for a value of approximately $8 million, all
interests of Omimex Resources, Inc. in the Richfield East Dome Unit, Orange
County, California, were transferred to GREKA increasing our working interest to
99% and net revenue interest to 77% for this operated property. The value of the
acquired interest was determined by the Company's engineers based on an
acquisition price of $3.96 per BOE on total proved reserves.
California Integrated Assets
In June 2001, we had executed an agreement to acquire all of Vintage
Petroleum, Inc.'s oil and gas producing properties and facilities in the Santa
Maria Valley of Central California for $17.75 million in cash at closing,
subject to customary terms and conditions including consents and adjustments.
The contracted properties consist of five fields and approximately 110 producing
wells, encompassing over 5,000 acres of mineral interests and over 800 acres of
real estate. In March 2002, we announced as part of GREKA's unique business
strategy in
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its integrated assets that we had closed into escrow our acquisition of these
producing properties. Subject to customary terms and conditions, a final closing
out of escrow effective December 1, 2001 is scheduled to occur by May 31, 2002.
During this escrow period, Vintage has operated and will continue to operate the
properties while the crude has been and will continue to be delivered to GREKA's
asphalt refinery, that has ramped up to approximately 2,000 BBL per day as of
April 1st. This acquisition will increase the current equity throughput of
approximately 1,200 BBL per day to approximately 3,200 BBL per day into the
refinery.
Divestiture Activities
Non-Core E&P Assets
In December 2001, the Company sold its interests in the San Simon
Field, Lea County, New Mexico and other mid-continent properties for a contract
price of $2.2 million.
Non-Core Colombian Assets
For approximately $10 million, the Company sold its Colombian assets
in 1999 subject to a look- back provision and valuation threshold which, by the
Company's calculation, had been met. In March 2000, we exercised our option to
re-purchase the Colombian assets in exchange for payment of $12.0 million,
reassignment of certain California assets acquired from the buyer, and
adjustments for related capital expenditures. The buyer refused to close
resulting in a legal dispute. In lieu of pursuing the re-purchase of this
non-core asset, the Company chose to settle these matters with the buyer which
resulted in an additional $14 million fiscal benefit to the Company that
included $6 million cash and the California assets discussed above valued at
approximately $8 million. This settlement provided us with $24 million total
value from the final disposition of our interests in Colombia.
Financing & Debt Restructuring Activities
Bank Financing
In February 2001, the credit facility secured by GREKA's subsidiaries'
interests in certain California oil and gas properties and real estate was
increased for a third time by GMAC. The transaction provides additional
financing of up to $46 million by increasing the principal amount of the term
loan from $25 million to $36 million, and $10 million for working capital.
Modifications to the terms of the credit agreement include the extension of the
credit facility to a term up to November 30, 2005.
In March 2001, GREKA's subsidiary as borrower and the Company acting
as guarantor entered into a credit and guarantee agreement with the Bank of
Texas, N.A. ("Bank of Texas"). The agreement provides that GREKA's subsidiary
may borrow up to $75 million. GREKA closed a revolving credit line of $16
million with an initial advance of $13.2 million against the line secured by
GREKA's subsidiary's interest in certain North American oil and gas properties.
A portion of the proceeds were paid to reduce the current debt of GREKA, which
payment resulted in the complete elimination of all obligations owed to CIBC.
In October 2001, our subsidiary entered into an amendment to the
credit and guarantee agreement with the Bank of Texas providing an additional
advance of $7.5 million against the revolving credit line secured by our
subsidiaries' interests in additional North American oil and gas properties and
real estate. The proceeds were paid to reduce the current debt of GREKA. (see
Item 3-"Legal Proceedings")
Debentures
On February 1, 2001, GREKA paid its 15% convertible senior
subordinated debentures in the principal amount of $1 million, and the security
of GREKA's subsidiary's interest in limestone deposits was released. There were
no conversions by debenture holders into GREKA common stock at the conversion
price of $20.00 per share.
In November 2001, GREKA issued 15% subordinated convertible debentures
in the aggregate amount of $1.3 million due May 31, 2002. The debentures are
convertible to Company common stock at the option of the debenture holders at
any
8
time prior to payment by the Company. Upon the receipt of a duly executed notice
of election to convert the GREKA debenture, the Company will convert the
debenture to GREKA common stock based upon a per share conversion price equal to
the lower of (i) five U.S. dollars ($5.00) or (ii) two U.S. dollars ($2.00)
below the lowest closing price of Greka's common stock for the month of November
2001.
During 2001, GREKA converted $0.28 million of its 9% senior
subordinated convertible debentures into 23,307 shares of GREKA common stock and
paid $0.07 million of debentures that had been redeemed, with a resulting
debenture balance of $2.40 million at December 31, 2001.
GREKA's Horizontal Drilling Technology
Horizontal drilling has become widely accepted as a standard option
for exploiting oil & gas resources. The principle advantage of horizontal
drilling is that it results in a substantially greater surface area for
drainage, and thus extraction of the oil from the reservoir. In industry terms
this is referred to as communicating zones of permeability. The unique method of
reentering a well and horizontal drilling patented by BP Amoco and licensed to
GREKA allows for turning while drilling, which can cause a vertical well to be
horizontal in as little as 25 feet. Thus this technology provides considerable
flexibility to the geologists and engineers in designing their well plans around
geological formation and reservoir constraints to achieve maximum performance.
Furthermore, this technique facilitates multi-laterals off an existing well
bore, which avoids costly drilling of new wells, and has considerable advantages
in shallow reservoirs where the traditional horizontal tools cannot be utilized
due to their larger radius requirements and related economics.
Marketing
Marketing of Asphalt Refinery Production
Our asphalt refinery in Santa Maria, California produces light
naphtha, kerosene distillate, gas oils and numerous cut-back, paving and
emulsion asphalt products. Historically, we have focused marketing efforts on
the asphalt products which are sold to various users, primarily in the Central
and Northern California areas. Distillates are readily marketed to wholesale
purchasers. Three customers accounted for more than ten percent of the Company's
sales of North American refinery production for each of the three years in the
period ended December 31, 2001, namely FAMM, Lawson and Granite which accounted
for approximately 22%, 14% and 12%, respectively, of such sales.
GREKA regards the refinery as a valuable adjunct to its production of
crude oil in the Santa Maria Valley and surrounding areas. Generally, the crude
oil produced in these areas is of low gravity and makes an excellent asphalt.
Prices for asphalt exceed market prices for crude and costs of operating the
refinery. GREKA believes that as road building and repairs increase in
California and surrounding western states, the market for asphalt will expand
significantly.
We market two principal products from our refinery: liquid asphalt and
light-end products (gas oil, naphtha and distillates). Liquid asphalt, which
accounted for approximately 65% of total refinery production in 2001, is
marketed primarily in California. While liquid asphalt is principally used
for road paving and manufacturing roofing products, all of the liquid asphalt
sold by GREKA's subsidiary is used for pavement applications. Paving grade
liquid asphalt is sold by GREKA's subsidiary to hot mix asphalt producers,
material supply companies, contractors and government agencies.
These customers further treat the liquid asphalt which is used for
road paving. In addition to conventional paving grade asphalt, our subsidiary
also produces modified and cutback asphalt products. Modified asphalt is a blend
of recycled plastics, rubber and polymer materials with liquid asphalt, which
produces a more durable product that can withstand greater changes in
temperature. Cutback asphalt is a blend of liquid asphalt and lighter petroleum
products and is used primarily to repair asphalt road surfaces. Additionally,
some of the paving grade and modified asphalts we produce are sold as base
stocks for emulsified asphalt products that are primarily used for pavement
maintenance.
Because the chemical footprint unique to the heavy crude oil
indigenous to the Santa Maria Valley readily blends, we are particularly well
positioned to supply the asphalt specifications in accordance with the standards
established by the National Highway and Transportation Administrations Strategic
Highway Research
9
Program (SHRP) or set by the American Association of State Highway and
Transportation Officials.
Demand for liquid paving asphalt products is primarily affected by
federal, state and local highway spending, as well as the general state of the
California economy, which drives commercial construction. Another factor is
weather, as asphalt paving projects are usually shut down in cold, wet weather
conditions. All of these demand factors are beyond our control. Government
highway spending provides a source of demand which has been relatively
unaffected by normal business cycles but is dependent on appropriations.
Growth in the California economy generally means well for the Company,
as increased business activity results in increased construction activity,
including new road construction and repair efforts on existing roads in both the
public and private sectors. A slowing economy could negatively impact both sales
and pricing of products.
As our asphalt refinery and principal markets are located in
California, the following discussion focuses on government highway funds
available in California.
Federal Funding
Federal funding of highway projects is accomplished through the
Federal Aid Highway Program. The Federal Aid Highway Program is a
federally-assisted, state-administered program that distributes federal funds to
the states to construct and improve urban and rural highway systems. The program
is administered by the Federal Highway Administration (FHWA), an agency of the
Department of Transportation. Nearly all federal highway funds are derived from
gasoline user taxes assessed at the pump.
In June 1998, the $217 billion federal highway bill, officially known
as the Transportation Equity Act for the 21st Century or TEA-21 was enacted. The
bill is estimated to increase transportation-related expenditures by $850
million a year in California alone over a six fiscal year period beginning
October 1, 1997. This will equate to a 51% increase over previous funding
levels. The average California apportionment over the six year period ending in
October 2003 is estimated to be $2.50 billion per year or a total of $15
billion. However, while management of GREKA's subsidiary believes it has
benefited from and should benefit in the future from such funding increases
there can be no guarantee that it will in fact do so in the future.
State and Local Funding
In addition to federal funding for highway projects, states
individually fund transportation improvements with the proceeds of a variety of
gasoline and other taxes. In California, the California Department of
Transportation (CALTRANS) administers state expenditures for highway projects.
According to the Department of Finance for the State of California, funding
available from the State Highway Account is estimated to average $1.13 billion
per year over the next 10 years excluding the Seismic Retrofit Bond Fund. This
compares to an average of $0.36 billion over the previous ten years.
Marketing of our Oil and Gas Production
The prices obtained for oil and gas are dependent on numerous factors
beyond our control, including domestic and foreign production rates of oil and
gas, market demand and the effect of governmental regulations and incentives.
Substantially all of our North American crude oil production is sold at the
wellhead at posted prices under short term contracts, as is customary in the
industry. Other than production from the Company's Integrated Operations
Division which is transported to our refinery, three customers accounted for
more than ten percent of the Company's sales of North American oil and gas
production during 2001, namely Tosco, Adams Resources and Plains Marketing,
L.P. which accounted for 34%, 34% and 21% respectively, of such sales.
The market for heavy crude oil produced by GREKA from its Central
Coast Fields in California differs substantially from the remaining domestic
crude oil market, due principally to GREKA's sale to the market of asphalt,
naphtha and distillates rather than hydrocarbons. GREKA's Santa Maria refinery
uses essentially all of its Central Coast Fields' crude oil, in addition to
third party crude oil,
10
to produce asphalt, among other products. Ownership and operation of the
refinery gives us a steady and stable market for its local crude oil which is
not enjoyed by other producers.
Competition
Competition in the oil and gas business is intense, particularly with
respect to the acquisition of producing properties, proved undeveloped acreage
and leases. Major and independent oil and gas companies actively bid for
desirable oil and gas properties and for the equipment and labor required for
their operation and development. We believe that the locations of our leasehold
acreage, our exploration, drilling and production capabilities and the
experience of our management and that of our industry partners generally enable
us to compete effectively. Many of our competitors, however, have financial
resources and exploration, development and acquisition budgets that are
substantially greater than ours, and these may adversely affect GREKA's ability
to compete, particularly in regions outside of GREKA's principal producing
areas. Because of this competition, GREKA cannot assure that it will be
successful in finding and acquiring producing properties and development and
exploration prospects.
Our management believes we have an advantage over our competition in
the regional asphalt market within Central California because of our vertical
integration and self-sufficiency in our Integrated Operations Division,
resulting in margins higher than other refiners in the same market.
Our management believes we have a further advantage over our
competition due to our acquired license from BP Amoco of the Short Radius
Horizontal Drilling technology, our level of field expertise in applying the
proprietary technology and our ability to apply these drilling techniques at a
fraction of the cost compared to conventional drilling techniques utilized by
our competition. Although BP Amoco has provided licenses to others, GREKA feels
that its strategy to apply the proprietary technology to its own oil and gas
properties and to penetrate new niche markets utilizing the proprietary
technology is within an entirely different market segment than any of the other
licensees who are concentrating on providing contract drilling services to
non-owned properties within their respective geographical area. We have not felt
any competitive pressure relative to our acquisition strategy focused on the
unique application of our niche, short-radius horizontal drilling technology.
Governmental Regulation
The following discussion of regulation of the oil and gas industry is
necessarily brief and is not intended to constitute a complete discussion of the
various statutes, rules, regulations or governmental orders to which operations
of GREKA and its subsidiaries may be subject.
Federal Regulation of First Sales and Transportation of Natural Gas
The sale and transportation of natural gas production from properties
owned by our subsidiaries may be subject to regulation under various federal and
state laws including, but not limited to, the Natural Gas Act and the Natural
Gas Policy Act, both of which are administered by the Federal Regulatory
Commission. The provisions of these acts and regulations are complex. Under
these acts, producers and marketers have been required to obtain certificates
from FERC to make sales, as well as obtaining abandonment approval from FERC to
discontinue sales. Additionally, first sales have been subject to maximum lawful
price regulation. However, the NGPA provided for phased-in deregulation of most
new gas production and, as a result of the enactment on July 26, 1989 of the
Natural Gas Wellhead Decontrol Act of 1989, the remaining regulations imposed by
the NGA and the NGPA with respect to "first sales" were terminated by no later
than January 1, 1993. FERC jurisdiction over transportation and sales other than
"first sales" has not been affected.
Because of current market conditions, many producers, including GREKA,
are receiving contract prices substantially below most remaining maximum lawful
prices under the NGPA. Our management believes that most of the gas to be
produced from GREKA's properties is already price-deregulated. The price at
which such gas may be sold will continue to be affected by a number of factors,
including the price of alternate fuels such as oil. At present, two factors
affecting prices are gas-to-gas competition among various gas marketers and
storage of natural gas. Moreover, the actual prices realized under GREKA's
current gas sales contracts also may be
11
affected by the nature of the decontrolled price provisions included therein and
whether any indefinite price escalation clauses in such contracts have been
triggered by federal decontrol.
The economic impact on GREKA and gas producers generally of price
decontrol is uncertain, but it currently appears to be resulting in higher gas
prices. Currently, there is a shortage of deliverable gas in most areas of the
United States and, accordingly, it remains possible that gas prices may remain
at relatively high levels. This is in sharp contrast to even recent pricing
which has been depressed for some time since deregulation. Producers such as
GREKA or resellers may be required to reduce prices in the future in order to
assure continued sales. It is also possible that gas production from certain
properties may be shut-in altogether for lack of an available market.
Commencing in the mid-1980's, FERC promulgated several orders designed
to correct market distortions and to make gas markets more competitive by
removing the transportation barriers to market access. These orders have had a
profound influence upon natural gas markets in the United States and have, among
other things, fostered the development of a large spot market for gas. The
following is a brief description of the most significant of those orders and is
not intended to constitute a complete description of those orders or their
impact.
On April 8, 1992, FERC issued Order 636, which is intended to
restructure both the sales and transportation services provided by interstate
natural gas pipelines. The purpose of Order 636 is to improve the competitive
structure of the pipeline industry and maximize consumer benefits from the
competitive wellhead gas market. The major function of Order 636 is to assure
that the services non-pipeline companies can obtain from pipelines is comparable
to the services pipeline companies offer to their gas sales customers. One of
the key features of the Order is the "unbundling" of services that pipelines
offer their customers. This means that pipelines must offer transportation and
other services separately from the sale of gas. The Order is complex and faces
potential challenges in court. GREKA is not able to predict the effect the Order
might have on its business.
FERC regulates the rates and services of "natural-gas companies",
which the NGA defines as persons engaged in the transportation of gas in
interstate commerce for resale. As previously discussed, the regulation of
producers under the NGA is being gradually phased out. Interstate pipelines,
however, continue to be regulated by FERC under the NGA. Various state
commissions also regulate the rates and services of pipelines whose operations
are purely intrastate in nature, although generally sales to and transportation
on behalf of other pipelines or industrial end-users are not subject to material
state regulation.
There are many legislative proposals pending in Congress and in the
legislatures of various states that, if enacted, might significantly affect the
petroleum industry. It is impossible to predict what proposals will be enacted
and what effect, if any, such proposals would have on GREKA and its
subsidiaries.
State and Local Regulation of Drilling and Production
State regulatory authorities have established rules and regulations
requiring permits for drilling, drilling bonds and reports concerning
operations. The states in which GREKA'S subsidiaries operate also have statutes
and regulations governing a number of environmental and conservation matters,
including the unitization and pooling of oil and gas properties and
establishment of maximum rates of production from oil and gas wells. A few
states also pro-rate production to the market demand for oil and gas.
Environmental Regulations
Our operations are subject to numerous laws and regulations governing
the discharge of materials into the environment or otherwise relating to
environmental protection. These laws and regulations may require the acquisition
of a permit before drilling commences, prohibit drilling activities on certain
lands lying within wilderness and other protected areas and impose substantial
liabilities for pollution resulting from drilling operations. Such laws and
regulations may also restrict air or other pollution resulting from GREKA's
operations. Moreover, many commentators believe that the state and federal
environmental laws and regulations will become more stringent in the future. For
instance, proposed legislation amending the federal Resource Conservation and
Recovery Act would reclassify oil and gas production wastes as "hazardous
waste". If such legislation were to pass,
12
it could have a significant impact on the operating costs of GREKA, as well as
the oil and gas industry in general. State initiatives to further regulate the
disposal of oil and gas wastes are also pending in certain states, including
states in which our subsidiaries have operations, and these various initiatives
could have a similar impact on GREKA.
Operational Hazards and Insurance
GREKA's subsidiaries' operations are subject to the usual hazards
incident to the drilling and production of oil and gas, such as blowouts,
cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires,
pollution, releases of toxic gas and other environmental hazards and risks.
These hazards can cause personal injury and loss of life, severe damage to and
destruction of property and equipment, pollution or environmental damage and
suspension of operations.
GREKA and its subsidiaries have up to $11 million of general liability
insurance. GREKA's insurance does not cover every potential risk associated with
the drilling, production and processing of oil and gas. In particular, coverage
is not obtainable for certain types of environmental hazards. The occurrence of
a significant adverse event, the risks of which are not fully covered by
insurance, could have a material adverse effect on GREKA's financial condition
and results of operations. Moreover, no assurance can be given that GREKA will
be able to maintain adequate insurance in the future at rates it considers
reasonable.
Employees
As of April 30, 2002, GREKA and its subsidiaries had 121 full-time
employees. None of GREKA's employees is subject to a collective bargaining
agreement. GREKA considers its relations with its employees to be satisfactory.
Shareholders Rights Plan
We have a shareholder rights plan in order to preserve the long-term
value of the Company for GREKA's shareholders. Under the shareholder rights
plan, one right will be distributed for each outstanding share of GREKA common
stock. Each right will entitle the holder to buy one share of GREKA common stock
for an initial exercise price of $57.14 per share. The rights will initially
trade with common shares and will not be exercisable unless certain takeover
events occur. The plan generally provides that if a person or group acquires or
announces a tender offer for the acquisition of 9.9% (amended from 12% by
approval of GREKA's Board of Directors in May 2001) or more of GREKA common
stock without approval of the Board of Directors, the rights will become
exercisable and the holders of the rights, other than the acquiring person or
group, will be entitled to purchase shares of GREKA common stock (or under
certain circumstances stock of the acquiring entity) for 50% of its current
market price. The rights may be redeemed by GREKA for a redemption price of $.01
per right.
Retirement Plan
The Company sponsors a defined contribution retirement savings plan
(401(k) Plan) to assist all eligible U.S. employees in providing for retirement
or other future financial needs. We currently provide matching contributions
equal to 50% of each employee's contribution, subject to a maximum of 8% of
their eligible contribution.
Net Profit Sharing Plan
The Company has a net profit sharing plan ("NPSP") for employees that
fulfill certain qualification requirements. The NPSP provides for an equal
disbursement normally of 10% of the Company's pretax income, excluding
extraordinary gains. Such disbursement is planned to follow the filing of the
annual audited financial statements of the Company. However, the NPSP could be
suspended, increased or otherwise amended at the discretion of our Board of
Directors for any specific year.
Item 2. Description of Property
The following description of the GREKA properties at December 31, 2001
includes all discussions of prior operations of all of GREKA's properties and
those of its wholly owned subsidiaries.
13
GREKA's Properties as of December 31, 2001
GREKA owned interests in approximately 523 wells at December 31, 2001.
The majority of these wells are concentrated along the central coast
of California and in Louisiana. In 2001, California (heavy oil) and Louisiana
(gas) were the primary and focused areas of exploitation and development
activities. At December 31, 2001, GREKA also operated wells and had exploitation
and development activities in other regions of California and in several states
outside of California and Louisiana, principally New Mexico and Texas. GREKA's
evaluation of international exploration and exploitation projects are in
Indonesia and China. The Company continuously evaluates the profitability of its
oil, gas and related activities and, as part of its strategic business plan,
intends to divest unprofitable leases or areas of operations that are not
consistent with its business strategy.
Exploitation and Development Activities
The following is a brief discussion of significant developments in the
Company's recent exploitation and development activities through its wholly
owned subsidiaries:
United States
California (Integrated)
Approximately 34.8% of GREKA's proved reserves at December 31, 2001
(4.7 MMBOE) were located in four onshore fields in California's central coast
region. Daily production from the Central Coast Fields averaged 1,361 BOE for
the year ended December 31, 2001, representing 43.3% of GREKA's total
production. GREKA operates all of its wells in the Central Coast Fields.
California (E&P)
GREKA also holds interests in other California areas, which
represented 30.8% (4.2 MMBOE) of GREKA's proved reserves at December 31, 2001.
GREKA's share of daily production from these other interests averaged 684 BOE
(1,016 BOE gross) for the year ended December 31, 2001, representing 21.8% of
GREKA's total production.
Louisiana
Approximately 31.3% of GREKA's proved reserves at December 31, 2000
(4.2 MMBOE) were located in two fields in Louisiana. GREKA's share of daily
production from the Louisiana fields averaged 852 BOE (1,032 BOE gross) for the
year ended December 31, 2001, representing 27.1% of the Company's total
production.
Other States
In addition to our California and Louisiana properties, GREKA owns
producing properties in a number of other states, but primarily New Mexico and
Texas, which collectively represented 3.1% of GREKA's proved reserves at
December 31, 2001 (0.4 MMBOE). GREKA's share of daily production from these
properties averaged 136 BOE (264 BOE gross) for the year ended December 31,
2001, representing 7.8% of GREKA's total production.
GREKA seeks to acquire domestic and international producing properties
where it can significantly increase reserves through development or exploitation
activities and control costs by serving as operator. GREKA believes that its
substantial experience and established relationships in the oil and gas industry
enable it to identify, evaluate and acquire high potential properties on
favorable terms. As the market for acquisitions has become more competitive in
recent years, GREKA has taken the initiative in creating acquisition
opportunities, particularly with respect to adjacent properties, by directly
soliciting fee owners, as well as working and royalty interest holders, who have
not placed their properties on the market.
GREKA's 2002 discretionary capital expenditure budget for properties
is dependent upon the price for which its products are sold and upon the ability
of GREKA to obtain external financing. Subject to these variables and based on
the current asset base, we expect our cash flow and credit facilities to fund
14
approximately $30 million in 2002 for capital expenditure, which includes the
acquisition of Vintage properties for $18 million. The budget is primarily
allocated to the development of the Integrated Operations Division.
Exploration Activities
GREKA further plans to expand its existing reserve base by developing
high potential exploration prospects in known productive regions. GREKA believes
these activities complement its traditional development and exploitation
activities. In pursuing these exploration opportunities, GREKA may use advanced
technologies, including 3-D seismic and satellite imaging. In addition, GREKA
may seek to limit its direct financial exposure in exploration projects by
entering into strategic partnerships that shift the drilling related financial
risks to partners while providing the Company with an upside upon a successful
event. At December 31, 2001, GREKA had exploration plays in three primary areas:
California, Indonesia and China.
The following is a brief discussion of significant developments in the
Company's recent exploration activities through its wholly owned subsidiaries:
California
Coalinga Nose Exploration Prospect, Fresno County, California. GREKA
has leases and contractual rights covering approximately 9,000 acres of land in
the region of the prolific Coalinga oil field in the San Joaquin Valley of
California. GREKA participated in a 16 square mile 3-D seismic survey covering
this area and has interpreted the survey. Nineteen anomalies have been
identified in the prospect area, covering five potentially productive zones,
ranging in depth from 6,500 to 12,000 feet. GREKA has an 89% working interest
below and a 9% working interest above the Gatchell formation in the Leda
Prospect, Pleasant Valley, and Cotton Gin Prospects. In April 2001, we entered
into a farmout agreement of our 89% interest in the deep rights under the east
half of our acreage block in which we retained a 22.25% back-in interest after
payout. The farmee drilled the initial well to 11,200' with completion in
September 2001. However, this initial well could not be tested, as the integrity
of the well bore could not be sustained. The farmee, who abandoned the well in
March 2002, did not earn any right to participate in the prospect.
Foreign Operations
Indonesia
West Java Exploration Prospect, Jakarta, Indonesia. GREKA is a party
to a production sharing contract, along with Pertamina, the Indonesian
state-owned oil company, covering 1.275 million unexplored acres on the Island
of Java near a number of producing oil and gas fields. The 30-year contract
provides that oil and gas in commercial quantities must be discovered prior to
September 2003. A portion of the block has been distinctly identified as the
Jonggol area consisting of 500,000 acres. The Jonggol area has two prospects and
eleven leads. In March 2002, the Company, which has a 75% interest in the block,
entered into an agreement to sell its exploration interests in Indonesia. The
sale requires the customary consent by Pertamina, the Indonesian state-owned oil
company, that has been requested and is currently pending.
China
Fengcheng Coalbed Methane Exploration Prospect, Jiangxi, China. GREKA
is a party to a production sharing contract with the China United Coalbed
Methane Corporation Ltd., which contract has been approved by the Chinese
Ministry of Foreign Trade and Economic Cooperation, to jointly exploit coalbed
methane resources in Fengcheng, East China's Jiangxi Province. The contract
block in which GREKA has a 49% working interest covers a total area of 380,534
acres. The 30-year contract provides that GREKA as operator will drill at least
ten coalbed methane wells over a three year term. Two production test wells have
been drilled and were both successful. The Company intends to drill 5 wells in
2002 to prove reserves this year and to thereafter formulate detailed
development plans.
Oil and Gas Producing Properties
At December 31, 2001, we owned and operated domestic producing
properties in 8 states, with our U.S. proved reserves located primarily in two
core areas:
15
California and Louisiana which represent approximately 65.6% and 31.3%,
respectively, of our proved reserves (BOE).
The following table summarizes GREKA's estimated proved oil and gas
reserves by geographic area as of December 31, 2001. The following table
includes both proved developed (producing and non-producing) and proved
undeveloped reserves. Approximately 37.9% of the total reserves reflected in the
following table are proved undeveloped. There can be no assurance that the
timing of drilling, reworking and other operations, volumes, prices and costs
employed by Netherland Sewell & Associates, independent petroleum engineers will
prove accurate. Since December 31, 2001, oil and gas prices have generally
increased. At such date, the price of WTI crude oil as quoted on the New York
Mercantile Exchange was $19.84 per Bbl and the comparable price for April 30,
2002 was $27.29. Quotations for the comparable periods for natural gas were
$2.57 per Mcf and $3.80 per Mcf, respectively. The proved developed and proved
undeveloped oil and gas reserve figures are estimates based on reserve reports
prepared by GREKA's independent petroleum engineers Netherland Sewell &
Associates. The estimation of reserves requires substantial judgment on the part
of the petroleum engineers, resulting in imprecise determinations, particularly
with respect to new discoveries. Estimates of reserves and of future net
revenues prepared by different petroleum engineers may vary substantially,
depending, in part, on the assumptions made, and may be subject to material
adjustment. Estimates of proved undeveloped reserves comprise a substantial
portion of GREKA's reserves and, by definition, had not been developed at the
time of the engineering estimate. The accuracy of any reserve estimate depends
on the quality of available data as well as engineering and geological
interpretation and judgment. Results of drilling, testing and production or
price changes subsequent to the date of the estimate may result in changes to
such estimates. The estimates of future net revenues in this report reflect oil
and gas prices and production costs as of the date of estimation, without
escalation, except where changes in prices were fixed under existing contracts.
There can be no assurance that such prices will be realized or that the
estimated production volumes will be produced during the periods specified in
such reports. The estimated reserves and future net revenues may be subject to
material downward or upward revision based upon production history, results of
future development, prevailing oil and gas prices and other factors. A material
decrease in estimated reserves or future net revenues could have a material
adverse effect on GREKA and its operations.
December 31, 2001
Proved Reserves, net
Gross Oil Gas PV-10 Value
Property Wells (MBbls) (MMcf) MBOE Dollar Value %
-------- ----- ------- ------ ------ ------------ -----------
(In thousands)
California:
Integrated Ops ........... 340 4,374 1,912 4,722 $11,182 19.7%
E&P ...................... 136 3,896 1,586 4,184 $13,565 24.0%
Total
California ............... 476 8,270 3,498 8,906 $24,747 43.7%
Louisiana ................... 30 1,704 13,982 4,246 $30,269 53.5%
Other United
States ................... 17 78 1,902 424 $ 1,602 2.8%
Total United
States ................... 523 10,052 19,382 13,576 $56,618 100.0%
The following is a brief discussion of our oil and gas operations in
our major fields:
California
Central Coast Fields. GREKA's subsidiary operates four fields in the
Central Coast area of California. These fields provide equity crude oil for
GREKA's wholly owned asphalt refinery. The fields are Cat Canyon, Casmalia, Gato
Ridge and Santa Maria Valley which collectively have an average working interest
of 100% in 107 active wells producing 1,361 BOEPD (gross). These fields
represent 34.8% of GREKA's total proved reserves. In March 2002, we announced a
restructuring of our business to focus on the integration of our Central
California operations, which assets include our asphalt refinery and these
interests in heavy oil fields.
We have established a horizontal drilling program by re-entering
existing idle wellbores and drilling short radius laterals utilizing proprietary
technology patented from BP Amoco. The reduced cost for re-entries ($125,000 per
well) should
16
contribute to a higher economic success rate and additional economic reserves.
Earlier drilling has delineated the S1b Sisquac Sand in the Cat Canyon Field and
S2 Sisquac Sand in the Gato Ridge Field as those formations with the highest
opportunities for success. In 2001, no wells were drilled. Management plans to
drill up to 6 horizontal re-entries during 2002 primarily to exploit these two
reservoirs plus explore the Monterey Zone.
Richfield East Dome Unit. The Richfield East Dome Unit is a mature
waterflood in Orange County, California, operated by GREKA's subsidiary and
producing 684 BOPD. The field has proved net reserves of 2.4 MMBO valued at
PV-10 $6.2 million or 17.7% of the Company's total reserve value. In September
2001, we increased our working interest in this field to 99% and net revenue
interest to 77%. (see Item 1-"Description of Business, Acquisition Activities,
California E&P Assets") Waterflood operations were initiated in 1974 by Texaco.
Field facilities are in sufficiently satisfactory condition to service the
waterflood operation through the remaining life of the field. During second
quarter 2002, we plan to sell GREKA's interests in this asset.
North Belridge Field. The North Belridge Field is located in Kern
County, California. GREKA's subsidiary is the operator and owns 100% working
interest in 42 wells on three leases covering 270 contiguous acres. The wells
produce from two formations-- light oil from the Diatomite zone and heavy oil
from the Tulare formation. Current production is about 278 BOEPD, net proved
reserves are 1.5 MMBOE valued at PV-10 $6.2 million.
Louisiana
Potash Dome Field. The Potash Dome Field is located in Plaquemines
Parish south of New Orleans, Louisiana, overlying a salt dome. The wells on the
west side of the field are land based while the wells on the east side produce
from single well structures located in shallow inland water. GREKA's subsidiary
operates the 3000 acre field and has 100% working interest in 21 wells. Proved
net reserves in the field are 1.6 MMBO and 14 BCFG valued at PV-10 $30.1
million. There exists substantial drilling opportunities in the field with net
proved undeveloped reserves of 0.6 MMBO and 8.2 BCFG in seven drilling locations
as determined by Netherland, Sewell & Associates, Inc., GREKA's independent
petroleum engineers. During 2001, as the first of a four-phased program in the
2001 business plan, we successfully executed our initial five-well recompletion
program, namely: Orleans Levee Board ("OLB") #77, #94, B-10, #90, #77, and SL508
#25. During the second phase of our program, also in 2001 we drilled to a total
depth of 10,604' and dually completed in the 11-B gas sand and the 9-A oil sand
our first well, Haspel & Davis No. 1, in the 9-A zone. Initial production from
this well was at over 6 MMCF per day and current production is at 510 BOEPD (or
60 BOPD and 2.7 MMCFD). The well, which was directionally drilled beneath a
large salt overhand in inland waters utilizing The Parker Drilling Co. rig #8B
1000 HP barge, was set to TD with 7 5/8" of production casing. This success
proved the technical interpretation by GREKA of the potential reservoirs in this
field. With our completion of the HD No. 1 well, the field has a total of 96
wells drilled to depths varying from 600' to 14,000' with 21 wells remaining.
Additionally, GREKA believes there is substantial opportunity to add gas
reserves in a deeper zone called the Tex "W" which is owned 50% by GREKA's
subsidiary and 50% by Exxon-Mobil. During second quarter 2002, we plan to sell
GREKA's interests in this asset.
Manila Village Field. The Manila Village Field is located in Jefferson
Parish, south Louisiana. There are net proved reserves of 0.1 MBO in this field
as of December 31, 2001. In April 2002, we sold our interest in this field.
Other United States
Southwest Tatum Field. The Southwest Tatum Field operated by GREKA's
subsidiary is located in Lea County, New Mexico. This field was discovered in
1996 through the use of 3-D seismic. There are four different productive
horizons in the field, Devonian, Canyon, Cisco, and Wolfcamp. There are net
proved developed reserves of 0.1 MBO and 0.1 MMCFG in the field as of December
31, 2001.
San Simon Field. The San Simon Field is located in Lea County, New
Mexico. In 2001, GREKA's subsidiary operated one oil well and three gas wells.
The oil well is the only producer in the field completed in the Wolfcamp
formation. This property was sold as of December 31, 2001.
17
Oil and Gas Reserves
Our proved reserves and the estimated present value of future revenues
from proved developed and undeveloped oil and gas properties in this document
have been estimated by our independent petroleum engineers. In 1999, 2000 and
2001, Netherland, Sewell & Associates, Inc. prepared reports on GREKA's reserves
in the United States. The estimates of these independent petroleum engineers
were based upon review of production histories and other geological, economic,
ownership and engineering data provided by GREKA. In accordance with the SEC's
guidelines, GREKA's estimates of future net revenues from GREKA's proved
reserves and the present value thereof are made using oil and gas sales prices
in effect as of the dates of such estimates and are held constant throughout the
life of the properties, except where such guidelines permit alternate treatment,
including, in the case of gas contracts, the use of fixed and determinable
contractual price escalation. Future gross revenues at December 31, 2001 reflect
weighted average prices of $14.53 per BOE compared to $26.93 per BOE and $17.90
per BOE as of December 31, 2000 and 1999, respectively.
The following tables present total estimated proved developed
producing, proved developed non-producing and proved undeveloped reserve volumes
as of December 31, 1999, 2000 and 2001 and the estimated present value of future
net revenues ("PV-10") (based on current prices and costs at the respective
year's end, using a discount factor of 10 percent per annum). As used herein,
the term "proved undeveloped reserves" are those which can be expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage is limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves for other
undrilled units are claimed only where it can be demonstrated with certainty
that there is continuity of production from the existing productive formation.
We do not include estimates for proved undeveloped reserves attributable to any
acreage for which an application of fluid injection or other improved recovery
technique is contemplated, unless such techniques have been proved effective by
actual tests in the area and in the same reservoir. There can be no assurance
that these estimates are accurate predictions of reserves or of future net
revenues from oil and gas reserves or their present value. The prices received
for oil and gas have generally increased since the preparation of the 2001 year
end engineering estimates.
Estimated Proved Oil and Gas Reserves
At December 31,
---------------------------
1999(1) 2000(1) 2001(1)
------- ------- -------
Net oil reserves (MBbl)
Proved developed producing .............. 6,469 7,059 4,310
Proved developed non-producing .......... 825 1,309 2,664
Proved undeveloped ...................... 3,237 3,644 3,078
------ ------ ------
Total proved oil reserves (MBbl) ....... 10,531 12,012 10,052
====== ====== ======
Net natural gas reserves (MMcf)
Proved developed producing .............. 3,364 5,184 2,206
Proved developed non-producing .......... 5,398 4,758 5,822
Proved undeveloped ...................... 8,836 10,133 11,354
------ ------ ------
Total proved natural gas
reserves (MMcf) ..................... 17,598 20,075 19,382
====== ====== ======
Total proved reserves (MBOE) ............... 13,732 15,662 13,576
- ----------
(1) Does not include reserve volumes attributable to the Company's interest in
assets subsequently divested.
Estimates of proved reserves may vary from year to year reflecting
changes in the price of oil and gas and results of drilling activities during
the
18
intervening period. Reserves previously classified as proved undeveloped may be
completely removed from the proved reserves classification in a subsequent year
as a consequence of negative results from additional drilling or product price
declines which make such undeveloped reserves non-economic to develop.
Conversely, successful development and/or increases in product prices may result
in additions to proved undeveloped reserves.
Estimated Present Value of
Future Net Revenue
(In thousands)
At December 31,
----------------------------
1999(1) 2000(1) 2001(1)
------- -------- -------
PV-10 Value
Proved developed producing .......... $39,689 $ 67,080 $15,180
Proved developed non-producing ...... 8,977 37,160 21,164
Proved undeveloped .................. 18,487 59,637 20,274
------- -------- -------
Total ............................ $67,153 $163,877 $56,618
======= ======== =======
- ----------
(1) Does not include reserve volumes attributable to the Company's interest in
assets subsequently divested.
As used herein, the terms "proved oil and gas reserves," "proved
developed oil and gas reserves," and "proved undeveloped reserves" have the
meanings defined by the SEC as set forth in the Table of Contents to this
document. Reservoir engineering is a subjective process of estimating the sizes
of underground accumulations of oil and gas that cannot be measured in an exact
way. The accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Reserve reports of other engineers might differ from the reports contained
herein. Results of drilling, testing and production subsequent to the date of
the estimate may justify revision of such estimate. Future prices received for
the sale of oil and gas may be different from those used in preparing these
reports. The amounts and timing of future operating and development costs may
also differ from those used. Accordingly, reserve estimates are often different
from the quantities of oil and gas that are ultimately recovered.
The following table summarizes sales volume, sales price and
production cost information for GREKA's net oil and gas production for each of
the years in the three-year period ended December 31, 2001.
Year Ended December 31,
---------------------------
1999(1) 2000(1) 2001(1)
------- ------- -------
Production Data:
Oil (MBbls) .................... 505 770 827
Gas (MMcf) ..................... 862 1,807 1,848
Total (MBOE) ................. 685 1,099 1,163
Average Sales
Price Data
(Per Unit):
BOE ............................ $13.85 $22.14 $19.51
Selected Data
per BOE:
Production costs(2) ............ $ 7.57 $ 6.49 $ 7.87
General and
administrative ............... $ 3.35 $ 5.79 $ 3.22
Depletion,
19
depreciation and
amortization ................. $ 2.72 $ 2.90 $ 4.34
- ----------
(1) Does not include reserve volumes attributable to the Company's interest in
assets subsequently divested.
(2) Production costs include production taxes.
Drilling Activity
With respect to GREKA's participation in the drilling of exploratory
and development wells for each of the three years in the three year period ended
December 31, 2001, there has been no drilling activity except as set forth in
the following table:
Year Ended December 31,
-----------------------------------------------------------
1999 2000 2001
----------------- ----------------- -------------------
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
-------- ------ -------- ------ -------- ------
United States:
Development Wells
Oil -- -- 5 5 1 1
Gas -- -- -- -- 1 1
Dry (3) -- -- 1 1 -- --
- ----------
(1) A gross well is a well 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.
(2) A net well is deemed to exist when the sum of fractional ownership working
interest in gross wells equals one. The number of net wells is the sum of
fractional working interests owned in gross wells expressed as whole
numbers and fractions thereof.
(3) A dry hole is an exploratory or development well that is not a producing
well.
Productive Oil and Gas Wells
The following table sets forth information at December 31, 2001,
relating to the number of productive oil and gas wells (producing wells and
wells capable of production, including wells that are shut in) in which GREKA
through its subsidiaries owned a working interest:
Oil Gas Total
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
United States 498 450 25 9 523 459
===== === ===== === ===== ===
Oil and Gas Acreage
The following table sets forth certain information at December 31,
2001 relating to oil and gas acreage in which GREKA through its subsidiaries
owned a working interest:
Developed(1) Undeveloped
--------------- --------------
Gross Net Gross Net
20
United States 21,070 16,180 11,201 8,025
====== ====== ====== =====
(1) Developed acreage is acreage assigned to productive wells.
Title to Properties
Many of GREKA's subsidiaries' oil and gas properties are held in the
form of mineral leases, licenses, reservations, concession agreements and
similar agreements. In general, these agreements do not convey a fee simple
title to GREKA, but rather, depending upon the jurisdiction in which the
pertinent property is situated, create lesser interests, varying from a profit a
prendre to a determinable interest in the minerals. In some jurisdictions,
notably non-U.S. jurisdictions, GREKA's subsidiaries' interest is only a
contractual relationship and bestows no interest in the oil or gas in place. As
is customary in the oil and gas industry, a preliminary investigation of title
is made at the time of acquisition of undeveloped properties. Title
investigations are generally completed, however, before commencement of drilling
operations or the acquisition of producing properties. GREKA believes that its
methods of investigating title to, and acquisition of, its oil and gas
properties are consistent with practices customary in the industry and that it
has generally satisfactory title to the leases covering its proved reserves.
Because most of GREKA's oil and gas leases require continuous production beyond
the primary term, it is always possible that a cessation of producing or
operating activities could result in the loss of a lease. Assignments of
interest to and/or from GREKA'S subsidiaries may not be publicly recorded.
From time to time, substantially all of GREKA's properties, including
its stock in its subsidiaries, are hypothecated to secure GREKA's current and
future indebtedness. GREKA's subsidiaries' working interest in properties may be
subject to lienholders by non-payment. In the event of GREKA's non-payment or
untimely payment of its obligations, GREKA expects liens to be filed against its
assets and to be subject to lawsuits. Oil and gas leases in which GREKA'S
subsidiaries have an interest may be deficient, require ratifications and be
subject to action by GREKA subsidiaries.
Average Sales Price and Production Cost
The following table sets forth information concerning average per unit
sales price and production cost for GREKA's oil and gas production for the
periods indicated:
Year Ended December 31,
------------------------
1999 2000 2001
------ ------ ------
Average sales price per BOE:
Integrated Ops .................... $10.82 $18.63 $16.82
E&P Americas ...................... 17.14 25.27 21.77
Combined .......................... 13.86 22.14 19.51
Average production cost per BOE:
Integrated Ops .................... $ 8.74 $ 3.99 $ 6.51
E&P Americas ...................... 5.80 6.88 8.00
Combined .......................... 7.47 5.51 7.87
Asphalt Refinery
GREKA owns an asphalt refinery in Santa Barbara County, California
through a wholly owned subsidiary. The refinery is a fully self-contained plant
with steam generation, mechanical shops, control rooms, office, laboratory,
emulsion plant and related facilities, and is staffed with a total of 21
operating, maintenance, laboratory and administrative personnel.
Real Estate Activities
GREKA'S subsidiaries from time to time purchased real estate in
conjunction with their acquisition of oil and gas and refining properties in
21
California and plan to continue this practice. At December 31, 2001, the Company
owned through its subsidiaries approximately 2,500 acres in Santa Barbara
County, California and approximately 6 acres in Orange County, California. GREKA
has used a portion of its real estate holdings for agricultural purposes. GREKA
plans to retain some of these real estate holdings for asset appreciation which
may include developmental activities at a future date.
Limestone Properties
GREKA owns a non-core, 355 acre limestone property located in Monroe
County, Indiana. The limestone deposits are made up of Salem limestone, which
produces a high industrial grade calcium oxide or calcium carbonate used in
scrubbing machinery that cleans the gaseous emissions from coal burning
generators. The Company is pursuing the sale of GREKA's interests in this asset.
In 1999, GREKA sold its interest in the limestone property in exchange
for a $5.7 million non-recourse promissory note, secured by the limestone
property. The buyer defaulted on the note, and the parties litigated their
claims for which the court in May 2001 ordered in favor of GREKA and the
property was reconveyed to GREKA.
Offices
GREKA leases approximately 1,000 square feet of office space at 630
Fifth Avenue, Suite 1501, New York, New York, for its executive offices through
September 30, 2004. GREKA's offices are located in Santa Maria, California;
Houston, Texas; and Beijing, China. In March 2002, GREKA announced that, due to
the divestiture of related assets, it closed its international offices in
Jakarta, Indonesia and Bogota, Colombia and will be downsizing its E&P Americas
unit in Houston to a satellite office.
Item 3. Legal Proceedings
Bank of Texas, N.A. v. Greka AM, Inc. and GREKA Energy Corporation
(Case No. 02-00771, 160th Judicial District Court of Dallas County, Texas,
January 2002). Bank of Texas alleged a default on the loan to GREKA's subsidiary
and brought an action seeking repayment of the loan plus unspecified exemplary
damages and attorney fees. GREKA filed counter-claims seeking contract and
unspecified exemplary damages and attorneys' fees. The parties have entered into
a forbearance agreement through June 30, 2002 by which time the parties' claims
shall be settled or GREKA shall proceed to vigorously defend all claims asserted
by Bank of Texas and seek counter-relief.
Liens and legal actions in connection therewith alleging nonpayment or
untimely payment for services or goods provided to GREKA's properties in an
aggregate amount of approximately $5.2 million have been filed against our
subsidiary's working interests. We plan to settle these claims concurrent with
if not before the planned sale of our assets and debt restructuring in the
second quarter.
From time to time, the Company and its subsidiaries are a named party
in legal proceedings arising in the ordinary course of business. While the
outcome of such proceedings cannot be predicted with certainty, management does
not expect these matters to have a material adverse effect on the Company's
financial condition or results of operations.
Item 4. Submission of Matters to a Vote of Security Holders
At the Annual Meeting of Shareholders held on December 7, 2001, the
following individual was elected to the Board of Directors to serve for a 3-year
term ending 2004 as a Class A director:
Votes For Votes Withheld
--------- --------------
Randeep S. Grewal 3,546,272 148,890
22
PART II
Item 5. Market for Common Equity and Related Stockholder Matters
Our common stock is listed for trading on the Nasdaq National Market
under the symbol "GRKA". Prior to March 25, 1999, the trading symbol was "HVNV".
Except for a period from August to December of 1997, GREKA's common stock has
been quoted on NASDAQ since February 19, 1993. The following table sets forth,
for the periods indicated, the high and low closing bid quotations per share of
GREKA common stock as reported on the Nasdaq National Market. Our common stock
quotations represent inter-dealer quotations, without retail markup, markdown or
commissions, and may not represent actual transactions. There can be no
assurance that a public market for GREKA's common stock will be sustained in the
future.
Bid
---
Quarter Ended Low High
March 31, 1999 4.875 10.500
June 30, 1999 6.375 9.125
September 30, 1999 7.000 13.500
December 31, 1999 7.500 12.000
March 31, 2000 8.563 9.500
June 30, 2000 8.625 8.813
September 30, 2000 14.375 15.688
December 31, 2000 12.750 13.438
March 31, 2001 12.250 14.813
June 30, 2001 10.000 14.375
September 30, 2001 7.500 11.600
December 31, 2001 6.950 9.150
March 31, 2002 6.010 8.630
On April 30, 2002 there were approximately 885 registered holders of
GREKA's common stock. Based on a broker count, GREKA believes at least an
additional 3,692 persons are shareholders with street name positions.
Holders of GREKA common stock are entitled to receive such dividends
as may be declared by the GREKA board of directors. GREKA has not yet paid any
cash dividends, and the board of directors of GREKA presently intends to pursue
a policy of retaining earnings for use in GREKA's operations and to finance
expansion of its business. In January 2001, GREKA issued a 5% stock dividend to
its shareholders of record at close of market on December 31, 2000 increasing
the total number of shares outstanding by 215,394. The declaration and payment
of dividends in the future, of which there can be no assurance, will be
determined by our board of directors in light of conditions then existing,
including our earnings, financial condition, capital requirements and other
factors.
In July 2001, the Company announced a repurchase program to buy back
up to 10% of its outstanding common stock, which repurchase is subject to market
conditions and will occur through open market purchases or privately negotiated
transactions at prices and on terms acceptable to management. At December 31,
2001, GREKA repurchased 25,000 shares of its common stock and canceled such
shares so that they became authorized but unissued shares of common stock.
Item 6. Selected Financial Data.
The following table sets forth selected consolidated financial data
for the Company as of the dates and for the periods indicated. The financial
data for each of the five years ended December 31, 2001, were derived from the
Consolidated Financial Statements of the Company. The following data should be
read in conjunction with "Management's Discussion and Analysis of Financial
Condition and Results of Operations," which includes a discussion of factors
materially affecting the comparability of the information presented, and in
conjunction with the Company's financial statements included elsewhere in this
report.
Years Ended December 31,
----------------------------------------------------
2001 2000 1999 1998 1997
-------- -------- -------- ------- -------
23
(In thousands, except per share data)
Income Statement Data:
Revenues ....................................... $ 40,755 $ 49,067 $ 29,138 $ 146 $ 212
Production and Product Costs ................... $ 24,782 $ 25,200 $ 17,821 $ 121 $ 248
General and administrative ..................... $ 7,974 $ 6,699 $ 3,205 $ 1,542 $ 756
Depletion, depreciation &
amortization ................................. $ 5,579 $ 3,592 $ 3,024 $ 333 $ 24
Other operating expenses ....................... $ 300 $ 2,377 $ -- $ -- $ --
Interest Expense ............................... $ 4,157 $ 4,535 $ 1,860 $ 32 $ 25
Other Expenses Net ............................. $ (5,540) $ (992) $ (1,696) $ (526) $ (34)
Minority Interest .............................. $ -- $ -- $ 21 $ -- $ --
Income tax (expense) benefit ................... $ (37) $ (362) $ (46) $ -- $ --
Equity in Earnings.............................. $ -- $ -- $ 569 $ 586 $ --
Cumulative effect of change in accounting ...... $ -- $ 853 $ -- $ -- $ --
Net (loss) income ............................. $ (7,614) $ 4,457 $ 3,367 $(5,548) $ (851)
(Loss) income per common share:
Basic net (loss) income per share .............. $ (1.67) $ 1.00 $ 0.80 $ (3.25) $ (1.37)
Cash dividend per share ........................ $ -- $ -- $ -- $ -- $ --
Basic weighted average common
shares outstanding ........................... 4,555 4,476 4,203 1,702 621
Diluted weighted average common
shares outstanding ........................... 4,651 4,763 4,801 1,702 621
Balance Sheet Data (end of period):
Working Capital ................................ $(50,355)* $ (2,664) $(14,176) $(1,828) $ 3,133
Net property and equipment ..................... $ 89,465 $ 77,182 $ 70,287 $ 4,426 $ 6,795
Total assets ................................... $100,049 $ 98,813 $ 84,214 $20,807 $10,803
Long-term obligations .......................... $ 13,445 $ 28,207 $ 15,696 $ 53 $ 77
Total stockholders' equity ..................... $ 33,165 $ 40,211 $ 33,378 $18,505 $ 9,095
* Includes reclassification of long-term debt to current due to a technical
default.
Item 7. Management's Discussion and Analysis of Financial Conditions and Results
of Operation
Overview
In view of significant material changes to GREKA during 1998, the
acquisition of Saba in March 1999, and assumption of full operations related to
the asphalt refinery, management believes that the financial condition and
results of operations of GREKA reported for periods prior to 1999 are not
indicative of the future financial condition and results of operations of GREKA.
As a consequence of GREKA's subsidiary's assumption of full operations at its
refinery in May 1999, the Company has been reporting 100% of the revenue and net
income resulting from operations in contrast to recognition prior to May 1999 of
only 50% of the net profit resulting from the same operations. Saba's 1998
financial statements are not consolidated with GREKA's 1998 financial statements
since the acquisition had not been consummated by December 31, 1998.
During the latter part of 1998 and early 1999, management of GREKA was
primarily focused on the acquisition of Saba and considerable expenses were
incurred in connection with the Saba transactions in the fourth quarter of 1998
and the first quarter of 1999. Due to the significance to GREKA of the Saba
acquisition, GREKA's management and staff devoted a substantial amount of time
and effort to the acquisition.
In view of the significant differences between GREKA's corporate
structure before the March 1999 acquisition of Saba, comparisons of GREKA's
results of operations for 1998 and 1997 are considered by management to be
neither relevant nor representative of GREKA Energy's long-term potential.
Results of Operations
Comparison of Years Ended December 31, 2001 and 2000
Revenue decreased by 17% or $8,311,858 from $49,067,140 for 2000 to
$40,755,282 for 2001. The decrease was mostly due to both lower volume sales of
8%
24
from 1,080,604 barrels in 2000 to 998,640 barrels in 2001, and 15% lower
average sales prices of refined products form $29.26 in 2000 to $24.87 in 2001
at our integrated operations.
Production and product costs decreased by 2% or $417,681 from
$25,199,620 in 2000 to $24,781,939 in 2001. The overall decrease was net of an
increase of 9% in the average per barrel cost from $11.20 in 2000 to $12.22 in
2001, or a total of $2,068,498 offset by a decrease of 10% in volume from
2,249,495 barrels in 2000 to 2,027,945 barrels in 2001 or a total decrease of
$2,486,179. The decrease in volume of barrels of throughput at the integrated
operations contributed to the overall increase in the average per barrel cost
for the year.
General and Administrative expenses increased by 19% or $1,274,908
from $6,699,275 for 2000 to $7,974,183 due to increase in audit, legal,
consulting and insurance costs coupled with costs associated with increase of
personnel and related fringe benefits.
Operating Income decreased 81% or $9,078,639 from $11,198,901 in 2000
to $2,120,262 as a direct result of a decrease in revenues of $8,311,858 or 92%
(explained above) coupled with increase in general and administrative expenses
and depreciation, depletion and amortization expenses.
Depreciation, depletion and amortization increased 55% or $1,986,657
primarily as a result of increase in the per barrel rate of depletion from $3.43
in 2000 to $4.80 in 2001. The increase in the depletion rate was a result of an
increase of 40% in the asset base relating to oil and gas properties coupled
with a decrease of 13% in the overall reserves from 15,662 MBOE in 2000 to
13,576 MBOE in 2001.
Interest Expense decreased 8% from $4,535,174 in 2000 to $4,157,110
for 2001 mostly due to a decrease in the interest rates applied to average
outstanding loan balances.
Other Expense net increased by 75%, or $4,170,693, from $5,526,613 in
2000 to ($9,697,306) in 2001, mostly due to expenses and non-recurring charges
associated with settlement of litigation post acquisition adjustments.
Net income decreased by 271%, or $12,070,758, from $4,457,214 for 2000
to ($7,613,544) for 2001. The variance is mostly due to a 69% decrease in
revenue of $8,311,858 and a 31% net increase of expenses, or $3,758,900
consisting mainly of nonrecurring charges resulting from settlement of material
litigation and post acquisition adjustments.
Capital expenditures increased 26% or $3,568,957 from $13,602,000 in
2000 to $17,170,957 in 2001. Capital expenditures were utilized primarily for
drilling activities in E&P Americas.
Comparison of Years Ended December 31, 2000 and 1999
Revenue increased from $26,137,810 for 1999 to $49,067,140 for 2000.
This increase resulted primarily from a 160% increase in BOE production and an
increase in the selling price of the Company's products from an average of
$13.95 per BOE in 1999 to $22.14 in 2000. While management expects a continued
increase in production it cannot project future pricing changes.
Production and Product costs increased from $17,820,620 for 1999 to
$25,199,620 for 2000 primarily as a result of a full twelve months of post
merger operations of the asphalt facility and oil and gas operations.
General and administrative expenses increased from $3,205,276 for 1999
to $6,699,275 for 2000 primarily as a result of a full twelve months of post
merger activity and increased staffing during the period.
Operating income more than doubled from $5,088,131 in 1999 to
$11,198,901 primarily as a result of the increased sales volume and improved
pricing for product sold.
Depreciation, depletion and amortization increased from $3,023,783 for
1999 to $3,592,242 for 2000 primarily as a result of a full twelve months of
post merger depreciation, depletion and amortization expenses and larger asset
base.
25
The Company sold its Canadian subsidiary during the year, resulting in
a loss of $991,439. The Company's accounting method for inventory was changed
from the first in, first out (FIFO) method to the average cost method effective
January 1, 2000. The average cost method is preferable because the primary
inventoriable cost at the refinery is crude oil for which the price can
fluctuate significantly. The weighted average method balances the impact of
short term fluctuations in crude oil pricing on the Company's refinery inventory
levels. The Company recorded the effect of this change of $853,110 as a
cumulative effect of a change in accounting principle as of January 1, 2000.
Interest expense increased from $1,859,688 for 1999 to $4,535,174 for
2000 primarily as a result of increased debt levels.
Net income increased from $3,367,000 for 1999 to $4,457,000 for 2000.
This increase was substantially, negatively impacted by the non recurring,
non-cash charges for the change in accounting practices and the loss on the sale
of our Beaver lake subsidiary both discussed above. Net was also impacted by a
larger provision for income taxes and a charge for the employee profit sharing
plan.
Capital expenditures increased from $2,092,000 in 1999 to $13,602,000
in 2000. Capital expenditures were utilized primarily for drilling activity in
the E&P Americas gas drilling program and re-working our Integrated Operations
heavy oil wells. Capital expenditures are expected to rise to $30 million during
2001.
Cash Flows
Cash provided by operating activities decreased 54% or $6,356,735 from
an inflow of $11,674,581 for 2000 to $5,317,847 for 2001. Net income for the
period adjusted for non-cash charges provided $47,669 of cash inflow.
The Company's net cash flows from investment activities increased from
a net outflow of $13,601,519 for 2000 to a net outflow of $16,030,140 for 2001.
The increase was due to an unanticipated increase in expenditures associated
with the drilling of the Haspel and Davis #1 well at Potash, coupled with
expenditures associated with the 3-year cycle for the major turnaround
maintenance program at the asphalt refinery.
The Company's net cash flow provided by financing activities increased
slightly or 3% from $6,096,318 in 2000 to $6,296,697 in 2001. Cash was provided
during 2001 from proceeds of the Company's financing facilities with the Bank of
Texas and GMAC.
Liquidity and Capital Resources
The following discussion of our liquidity and capital resources is on
a consolidated basis, noting the uses and contributions of our consolidated
entity. The Company's growth is focused on acquisitions that are strategic and
in accordance with its business plan. It is intended that such acquisitions will
be achieved concurrent with the closing of adequate financing. Historically,
GREKA has relied on cash flow from operations to finance operational capitalized
expenditures. In 2001, GREKA had expended $17,170,957 for its capitalized
expenditures. For 2002, GREKA has budgeted $30 million for its discretionary
capitalized expenditures, which includes the acquisition of Vintage properties
for $18 million, to be funded by its cash flow and credit facilities. Factors
affecting actual expenditures and investments include availability of capital
and suitable investment opportunities, market volatility and economic trends.
The anticipated sources of funds for such growth opportunity are cash flow from
operations and external financings.
Further, GREKA intends to achieve the following:
. In addition to eliminating the trade and bank debt estimated at $25M
related to our traditional exploration and production assets that are
planned to be sold, we have embarked on a complete restructuring of
our remaining long-term and maturing debt of $20m. The debt
restructuring scheduled during the second quarter is intended to
payoff all remaining non-trade debt including debentures of $6M, fund
the acquisition of the escrowed Vintage Petroleum, Inc. properties of
$18.5M, provide availability for targeted acquisitions within the
Integrated Operations' business plan, continued development of our
interests in China, and working capital.
. Continue to execute an aggressive rework program to return to
production existing wells on all properties that have shut-in wells.
. Utilize the in-house proprietary and cost effective horizontal
drilling technology to enhance production in the Santa Maria Valley
area, increasing the equity oil and gas production as well as new gas
treatment facilities.
26
. Continue to acquire assets to enhance the benefit of integrated
operations that collectively provide for low cost operating expenses
and high cash flow.
. Drill five new wells in China in a pilot program to confirm
anticipated production levels of Coalbed Methane (CBM), and upon
successful completion, develop and implement the appropriate plan to
exploit the additional acreage.
GREKA's management also believes that the disposition of non-core
assets brings opportunities for cost savings, and other synergies, resulting in
improved cash flow potential for the long-term growth of GREKA and of
shareholder value. Further, these dispositions give GREKA a stronger
consolidated asset base upon which it can rely in securing future financings,
both equity and debt. However, there is no assurance that any specific level of
cost savings or other synergies will be achieved or that such cost savings or
other synergies will be achieved within the time periods contemplated, or that
GREKA will be able to secure future financings.
For an analysis of certain contractual and commercial obligations in 2002 and
thereafter, see "Disclosures about Contractual Obligations and Commercial
Obligations and Certain Investments", shown below. The following table reflects
the contractual cash obligations and other commercial commitments in the
respective periods in which they are due.
Total
Amounts Less than
Contractual Obligations Committed 1 Year 1-2 Years 3-4 Years Thereafter
- ----------------------- --------- ------ --------- --------- ----------
(Thousands of Dollars)
Debt $ 43,132 33,644 6,043 3,445 --
Operating Leases 353 175 178 -- --
--------------------------------------------------------------------
Total Contractual Cash Obligations $ 43,485 $ 33,819 $ 6,221 $ 3,445 $ --
====================================================================
Our continuation as a going concern is dependent upon our ability to
successfully establish the necessary financing arrangements and implement our
strategies consistent with our restructuring plans announced in the first
quarter of 2002. However, although no assurances can be given, we remain
confident that we will be able to continue operating as a going concern.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
At December 31, 2001, the Company's operations were exposed to market
risks primarily as a result of changes in commodity prices and interest rates.
The Company does not use derivative financial instruments for speculative or
trading purposes.
Interest Rate Risk - The Company is exposed to the impact of interest
rate changes. The Company has approximately $4.3 million outstanding under its
Revolving credit agreements and $32 million under its term loan facility which
exposes the Company to the risk of earnings or cash flow loss due to changes in
market interest rates. The interest rates are based on current market rates
(Prime rate or Federal Funds Rate) plus a range of 100 to 300 basis points.
Commodity price risk - The Company is subject to the market risk
associated with changes in commodity prices of the underlying crude oil and
refined products; such changes in values are generally offset by changes in the
sale prices of the Company's refined products.
Credit Risk - Financial instruments which potentially subject the
Company to credit risk consist principally of trade receivables. Concentration
of credit risk with respect to trade receivables is mitigated by the stability,
longevity and financial soundness of the Company's customers. Although 83% of
the Company's sales are made to six customers, these customers are not a credit
risk since most of their sales are to funded city, state or federal government
projects.
Inflation
GREKA does not believe that inflation will have a material impact on
GREKA's future operations.
Critical Accounting Policies and Use of Estimates
Use of Estimates. The preparation of the consolidated financial
statements in conformity with generally accepted accounting principles requires
our management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the dates of the financial statements and the reported amounts of
revenues and expenses during the reporting periods. Our most significant
financial estimates are based on remaining proved natural gas and oil reserves.
Full Cost Accounting - The Company uses the full cost method to
account for our natural gas and oil properties. Under full cost accounting, all
costs incurred in the acquisition, exploration and development of natural gas
and oil reserves are capitalized into a "full cost pool". Capitalized costs
include costs of all unproved properties, internal costs directly related to our
natural gas and oil activities and capitalized interest. The Company amortizes
these costs using a unit-of-production method. Greka computes the provision for
depreciation, depletion and amortization quarterly by multiplying production for
the quarter by a depletion rate. The depletion rate is determined by dividing
our total unamortized cost base by net equivalent proved reserves at the
beginning of the quarter. Unevaluated properties and related costs are excluded
from our amortization base until a determination is made as to the existence of
proved reserves. The amortization base includes estimates for future development
costs as well as future abandonment and dismantlement costs. Estimates of proved
reserves are key components of our depletion rate for natural gas and oil
properties and our full costs ceiling test limitation. See Note 17 Supplemental
Oil and Gas Information. Because there are numerous uncertainties inherent in
the estimation process, actual results could differ from the estimates.
Inventories - The Company values its inventory on the weighted average
cost method. The weighted average cost method is considered the preferable
because the primary inventorable cost at the refinery is crude oil for which the
price can fluctuate significantly. The weighted average method balances the
impact of short term fluctuations in crude oil pricing on the Company's refinery
inventory levels.
27
New Accounting Pronouncements
The SFAS has recently issued SFAS No. 141, "Business Combinations," SFAS No.
142, "Goodwill and Other Intangible Assets, "SFAS No. 143, "Accounting for Asset
Retirement Obligations" and SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets."
SFAS No. 141, "Business Combinations," requires the use of the purchase method
of accounting for all business combinations initiated after June 30, 2001. SFAS
No. 142, "Goodwill and Other Intangible Assets", addresses accounting for the
acquisition of intangible assets and accounting for goodwill and other
intangible assets after they have been initially recognized in the financial
statements. We do not currently have goodwill or other similar intangible
assets' therefore, the adoption of the new standard on January 1, 2002, has not
had a material effect on our financial statements.
SFAS No. 143, "Accounting for Asset Retirement Obligations, "addresses
accounting and reporting for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs. SFAS No.
143 will be effective for us January 1, 2003 and early adoption is encouraged.
SFAS No. 143 requires that the fair value of a liability for an asset's
retirement obligation be recorded in the period in which it is incurred and the
corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its then present value each
period, and the capitalized cost is depreciated over the useful life of the
related asset. If the liabilty is settled for an amount other than the recorded
amount, a gain or loss is recognized. Currently, we include estimated future
costs of abandonment and dismantlement in our full cost amortization base and
amortize these costs as a component of our depletion expense. We are evaluating
the impact the new standards will have on our financial statements.
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets,"
is effective for us January 1, 2002, and addresses accounting and reporting for
the impairment or disposal of long-lived assets. SFAS 144 supersedes SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for the Long-Lived
Assets to Be Disposed Of" and ABP Opinion No. 30, "Reporting the Results of
Operations-Reporting the Effects of Disposal of Segment of a Business." SFAS No.
144 retains the fundamental provisions of SFAS NO. 121 and expands 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. We are evaluating the impact the new standard will have on our
financial statements.
Item 8. Financial Statements.
Please see accompanying Index to Financial Statements commencing on
page F-1.
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure
In May 2001, the Company engaged Hein + Associates LLP to replace
Arthur Andersen LLP as its independent public accountants to audit its
consolidated financial statements for the year ending December 31, 2001. Refer
to the Company's Form 8-K filed on May 21, 2001.
In December 2001, the Company appointed Deloitte & Touche LLP to
replace Hein + Associates LLP as its independent public accountants to audit its
consolidated financial statements for the year ending December 31, 2001. Refer
to the Company's Form 8-K filed on January 3, 2002.
28
PART III
Item 10. Directors, Executive Officers, Promoters and Control Persons;
Compliance With Section 16(a) of the Exchange Act
The directors and executive officers of GREKA are as follows:
Name
Since Age Positions
- ----- --- ---------
Randeep S. Grewal 37 Chairman of the Board, Chief Executive
September 1997(1) Officer and President, Class A Director
Dr. Jan F. Holtrop 66 Class B Director
September 1997(2)
George G. Andrews 76 Class B Director
July 1998(2)
Dai Vaughan 62 Class C Director
March 1999(3)
Kenton D. Miller 49 Class C Director
October 2000(3)
Richard "Sam" R. Lembcke 65 Vice President-Upstream Operations
December 2001
Max A. Elghandour 51 Chief Financial Officer
August 2001
Brent E. Stromberg 57 Vice President-Downstream Operations
December 2001
Susan M. Whalen 40 Vice President-Corporate Affairs,
August 2001 Secretary
(1) term as Director expires 2004
(2) term as Director expires 2003
(3) term as Director expires 2002
Randeep S. Grewal. Since September 1997, Mr. Grewal has served as our
Chairman of the Board, Chief Executive Officer and President. From April 1997 to
September 1997, Mr. Grewal served as Chairman and Chief Executive Officer for
Horizontal Ventures, Inc., an oil and gas horizontal drilling technology company
that became a subsidiary of our predecessor in September 1997. From 1993 to
1996, Mr. Grewal was the Corporate Vice President for the Rada Group with
principal responsibilities for its global expansion and related operations. He
has also been involved in various joint ventures, acquisitions, mergers and
reorganizations since 1986 in the United States, Europe and the Far East within
diversified businesses. Mr. Grewal has a Bachelor of Science degree in
Mechanical Engineering from Northrop University.
Dr. Jan Fokke Holtrop. Dr. Holtrop has been a Class B Director of
GREKA since September 1997. Since 1989 he has been a senior Production
Technology professor at Delft University of Technology within the Faculty of
Petroleum Engineering and Mining in The Netherlands. Prior to Delft University,
he served in various positions within the Shell Oil Company where he started his
career in 1962. This includes mining engineering, reservoir engineering and
petroleum engineering field work in at least 14 different countries, as well as
deep sea drilling, coal production and coal exploration operations, well
technology research, and well design, drilling and production operations. Dr.
Holtrop has almost 40 years of experience within the oil and gas exploration,
drilling and production industry with a global hands-on background. Dr. Holtrop
has a Ph.D. and a MSC in Mining Engineering from Delft University of Technology.
George G. Andrews. Mr. Andrews became a Class B Director of GREKA in
July 1998. He has been a consultant and private investor since his retirement
from the oil and gas industry in 1987. From 1982 until 1987 he was employed as
Corporate Vice President of Intercontinental Energy Corporation of Englewood,
Colorado and
29
directed the company's land acquisition, lease and management operations.
Between June 1981 and November 1982, Mr. Andrews was Vice President of Shelter
Hydrocarbons, Inc. of Denver, Colorado where he directed all land management and
operation procedures. From 1979 to June of 1981, Mr. Andrews was Senior Landman
for the National Cooperative Refinery Association in Denver, Colorado. Mr.
Andrews obtained his B.S. degree in 1947 from the University of Tulsa.
Kenton D. Miller. In October 2000, Mr. Miller became a Class C
Director of GREKA. Since 1991, Mr. Miller has maintained a private consulting
practice specializing in management advisory services for a diverse group of
petroleum related companies. His consulting services are oriented to improving
financial performance for clients utilizing the combination of financial
accounting with operations principles and providing assistance with strategic
acquisitions or divestitures. Mr. Miller has 30 years of oil and gas experience
in reservoir engineering, field operations and management, primarily with Ladd
Petroleum Company, BP Amoco and Cities Service Oil Company. His management
experience includes the successful drilling of the first commercial horizontal
well in Oklahoma and the lead engineering of the early Beaufort Sea exploratory
wells drilled. Mr. Miller has been a Registered Professional Petroleum Engineer
since 1984 and a Certified Public Accountant since 1994. He has a Bachelor of
Science in Petroleum Engineering from the University of Tulsa.
Dai Vaughan. Mr. Vaughan has been a Class C Director of GREKA since
March 1999. He has been an independent management consultant since 1994 with
concentrated experience in business plan development, implementation, and
business turn-arounds. From 1985 until 1994, he was with Continental Airlines,
most recently as Manager of Aircraft Acquisition. Mr. Vaughan has served in
numerous positions in his 44 year career in the airline industry with Pan
American Airlines, Eastern Airlines and finally Continental Airlines, including
Systems Engineering, Aircraft Maintenance and Aircraft Acquisition. Mr. Vaughan
received a HNC degree (B.S. equivalent) in Electrical Engineering.
Richard "Sam" R. Lembcke. Mr. Lembcke joined us in February 2000 as
Vice President of the E&P Americas division and in December 2001 was appointed
Vice President-Upstream Operations. Mr. Lembcke possesses vast experience in the
oil and gas industry that spans over 40 years. Throughout his tenure in the
industry, he has held a series of positions with increasing responsibility,
including President from 1996 to 2000 of Gulf Tech, a Louisiana focused oil and
gas company, President and General Manager of Ultramar Oil & Gas Limited in
Houston, Texas from 1989 to 1992, and as Vice President - Manager of Operations
from 1983 to 1989. From 1978 to 1983, Mr. Lembcke served as Executive Vice
President and Director for Marion Drilling Services Company. From 1960 to 1978,
he served in several positions for Union Oil Company of California. Further, he
has served as past President of the American Petroleum Institute and Society of
Petroleum Engineers. Mr. Lembcke received a Bachelor of Science degree in
Petroleum Engineering from the University of Oklahoma.
Max E. Elghandour. Mr. Elghandour joined us in May 2001 as Chief
Financial Officer. He has over 20 years of financial and operational experience
in the oil, gas, and chemical industries. Prior to joining us, Mr. Elghandour
spent 16 years as a member of the senior financial team at Elf Aquitaine, now
Totalfinaelf, in progressive functional and engaging capacities in the United
States, France and the Middle East. He has a Bachelor of Science in Accounting
from Saint Francis College and is a Certified Public Accountant. He is a member
of the American Institute of Certified Public Accountants and the New York State
Society of Certified Public Accountants.
Brent E. Stromberg. Mr. Stromberg joined us in May 1999 as General
Manager - Refinery Operations and in March 2000 was appointed Vice President--
Integrated Operations in Santa Maria, California. In December 2001, he was
appointed Vice President-Downstream Operations. Mr. Stromberg's experience of 19
years in the management of crude oil operations includes 18 years with Petro
Source Corporation/Crown Asphalt in Salt Lake City. From 1981 to 1999, he served
in several management positions, including Santa Maria Project Manager,
Transportation Manager, and Motor Gasoline Blending and Marketing Manager. Mr.
Stromberg received a Bachelor of Arts in Business Management and a Masters in
Business Administration Degree from the University of Utah.
Susan M. Whalen. Ms. Whalen served as General Counsel for Saba
Petroleum Company from 1997 until 1999, when Saba was acquired by GREKA.
Following the
30
acquisition she served as our Vice President of Legal & Corporate Affairs and as
Corporate Secretary. In October 2000 she was appointed Corporate Liaison to our
Integrated Operations division and in August 2001 she was appointed our Vice
President of Corporate Affairs. Prior to joining Saba in 1997, Ms. Whalen was
involved in various niche-market product developments within the retail industry
for 10 years. Ms. Whalen received her J.D. degree from Western State University
- - College of Law.
During 2001, the Board of Directors met seventeen times. No director
attended less than 75% of the meetings.
There are no family relationships among the directors. There are no
arrangements or understandings between any director and any other person
pursuant to which that director was elected.
During the past five years, there have been no petitions under the
Bankruptcy Act or any state insolvency law filed by or against, nor have there
been any receivers, fiscal agents, or similar officers appointed by any court
for the business or property of any of GREKA's directors or executive officers,
or any partnership in which any such person was a general partner within two
years before the time of such filing, or any corporation or business association
of which any such director or executive officer was an executive officer within
two years before the time of such filing. During the past five years, no
incumbent director or executive officer of GREKA has been convicted of any
criminal proceeding (excluding traffic violations and other minor offenses) and
no such person is the subject of a criminal prosecution which is presently
pending.
Committees
GREKA's Audit Committee, whose charter was adopted in June 2000, is
made up of Messrs. Miller, Andrews and Vaughan, and its Compensation Committee
is made up of Messrs. Grewal, Vaughan and Andrews. The Board of Directors
selects director nominees and will consider suggestions by shareholders for
names of possible future nominees delivered in writing to the Secretary of GREKA
on or before November 30th in any year. The Audit Committee met six times during
2001, and the Compensation Committee met once during 2001.
Section 16(a) Beneficial Ownership Reporting Compliance
Based solely on a review of reports filed with GREKA, all directors,
executive officers and beneficial owners of more than five percent of GREKA
common stock timely filed all reports regarding transactions in GREKA's
securities required to be filed during the last fiscal year by Section 16(a) of
the Securities Exchange Act of 1934, except Form 3's for Mr. Elghandour, Ms.
Whalen, and Mssrs. Lembcke and Stromberg.
Item 11. Executive Compensation
The following summary compensation table sets forth in summary form
the compensation received during each of GREKA's last three completed fiscal
years by the executive officers of GREKA, except no disclosure is required for
those earning gross compensation less than $100,000.
31
Executive Compensation
Summary Compensation Table
Annual Compensation Long Term Compensation
----------------------- ---------------------------
Restricted Securities
Name and principal stock awards underlying All other
position Year Salary($) Bonus($)(1) ($) options/SARS compensation
- ------------------ ---- --------- ----------- ------------ ------------ ------------
Randeep S. Grewal, 2001 $353,777 $8,844 -- -- $12,000(2)
Chairman and Chief 2000 $290,269 -- -- 410,000 $12,000(2)
Executive Officer 1999 $248,400 -- -- -- $12,000(2)
Richard R. Lembcke, 2001 $114,471 $8,844 -- -- --
VP-Upstream Operations
Max A. Elghandour, 2001 $103,385 -- -- 45,000 --
Chief Financial Officer
Brent E. Stromberg, 2001 $ 97,386 $8,844 -- -- --
VP-Downstream Operations
Susan M. Whalen, 2001 $ 93,445 $8,844 -- -- --
VP-Corporate Affairs
(1) The bonus paid to the executive officers of GREKA in 2001 was their
participation in the Company's NPSP. The executive officers of GREKA were not
paid any bonuses during 1999 or 2000.
(2) Auto expense allowance.
No other form of compensation was paid during 1999, 2000 or 2001. No
other executive officer or director of GREKA received total compensation in
excess of $100,000 during the last three fiscal years.
Option/SAR Grants in Last Fiscal Year(1)
(Individual Grants)
Number of Percent of total
Securities options/SARS Grant
Underlying granted to Exercise or Date
Options/SARS employees in base price Expiration Present
Name granted(#) fiscal year ($/Sh) date Value
- ---- ------------ ---------------- ----------- ---------- --------
Max A. Elghandour 45,000 40% $11.32 4/25/11 $390,600(2)
(1) At December 31, 2001, GREKA had granted 1.4 million options to acquire
shares of common stock of GREKA, of which 93,000 were granted in 2001 at
exercise prices of $12.50 (68,000 options) and $11.32 (45,000 options) to
employees, directors and consultants of the Company. A total of 24,000
options have terminated through attrition and 39,000 options have been
exercised, leaving the total option grants outstanding as of December 31,
2001 at 1,088,000 options.
(2) The Black-Scholes pricing model was used with a volatility of .65 and a
risk-free interest rate of 5%.
Aggregated Option/SAR Exercises
in Last Fiscal Year and
FY-End Option/SAR Values
Value of
Number of unexercised
Shares unexercised in-the-money
acquired options/SARS options/SARS
on Value at FY-end(#) at FY-end($)
exercise realized exercisable/ exercisable/
Name (#) ($) unexercisable unexercisable
- ---- -------- -------- -------------- -------------
Susan M. Whalen 5,000 $24,075 35,000/10,000 $875/$250
32
Employment Contracts and Termination Agreements
On September 9, 1997, GREKA entered into a five-year employment
agreement with Randeep S. Grewal. This agreement was amended on October 14,
1998, and on November 3, 1999 the Board of Directors adopted an amended and
restated employment agreement for Mr. Grewal (the "Restated Agreement"). Under
the terms of the Restated Agreement, Mr. Grewal's annual salary is $287,500
subject to an annual increase effective on the anniversary date. Mr. Grewal
participates in GREKA's benefit plans and is entitled to bonuses and incentive
compensation as determined by the board of directors of GREKA. The Restated
Agreement also allows Mr. Grewal to receive an assignment of a 2% overriding
royalty of all oil and gas properties of GREKA and to receive fringe benefits
which include an automobile allowance of $1,000 per month. Under the original
agreement, 31,500 shares of GREKA common stock were issued to Mr. Grewal.
The term of the Restated Agreement is through the fifth anniversary of
December 31, 1999; however, it automatically rolls over so that it is a minimum
of three years unless sixty days prior to any anniversary date the Company
notifies Mr. Grewal that the change of control period shall not be extended. A
change of control termination clause was added which is intended to deter
hostile changes of control by providing a substantial termination payment should
Mr. Grewal terminate his employment or be terminated as a result of a change of
control. The Restated Agreement is terminable for cause or by the death or
disability of Mr. Grewal. In addition, the Restated Agreement may be terminated
by Mr. Grewal in the event of any diminution by GREKA in Mr. Grewal's position,
authority, duties or responsibilities. Upon termination of the Restated
Agreement by GREKA for any reason other than for cause, death or disability, or
upon termination of the Restated Agreement by Mr. Grewal in the event of any
diminution by GREKA in Mr. Grewal's position, authority, duties or
responsibilities, GREKA is obligated to pay within 30 days after the date of
termination: (a) Mr. Grewal's base salary through the date of the severance
period, (b) Mr. Grewal's base salary for the balance of the term of the
agreement if the date of termination is within the first five years of the
employment agreement (base salary is the salary rate in effect at the date of
termination), (c) the annual bonus paid to Mr. Grewal for the last full fiscal
year during the employment period, and (d) all amounts of deferred compensation,
if any.
Director Compensation
Each director who is not an employee of GREKA is reimbursed for
expenses incurred in attending meetings of the board of directors and related
committees. At December 31, 2001, GREKA had four outside directors. No
compensation was paid to any outside director during fiscal 2001, except $11,900
to Mr. Vaughan and $11,950 to Mr. Miller for specifically identified matters,
and none is planned for the immediate future.
During 2001, options to acquire 28,000 shares of common stock of GREKA
at an exercise price of $12.50 per share were granted to Mr. Miller as a GREKA
director for his services as a member of the Board of Directors. The options,
which are exercisable at January 31, 2001 (6,000 options) and January 31, 2002
(22,000 options), were granted in accordance with GREKA's Stock Option Plan and
expire on January 29, 2011.
GREKA has no knowledge of any arrangement or understanding in
existence between any executive officer named above and any other person
pursuant to which any such executive officer was or is to be elected to such
office or offices. All officers of GREKA serve at the pleasure of the board of
directors. No family relationship exists among the directors or executive
officers of GREKA. There is no person who is not a designated officer who is
expected to make any significant contribution to the business of GREKA. Any
officer or agent elected or appointed by the board of directors may be removed
by the board whenever in its judgment the best interests of GREKA will be served
thereby without prejudice, however, to any contractual rights of the person so
removed.
Future Transactions
All transactions between GREKA and an officer, director, principal
stockholder or affiliate of GREKA will be approved by a majority of the
uninterested directors, only if they have determined that the transaction is
fair to GREKA and its shareholders and that the terms of such transaction are no
less favorable to GREKA than could be obtained from unaffiliated parties.
33
Item 12. Security Ownership of Certain Beneficial Owners and Management
Security Ownership of Certain Beneficial Owners and Management
The following table presents as of April 30, 2002 the common stock
ownership of each person known by GREKA to be the beneficial owner of five
percent or more of GREKA's common stock, all directors and officers
individually, and all directors and officers of GREKA as a group. Except as
noted, each person has sole voting and investment power with respect to the
shares shown. GREKA is not aware of any contractual arrangements or pledges of
GREKA's securities which may at a subsequent date result in a change of control
of GREKA. As of April 30, 2002, there were 4,698,368 shares of GREKA common
stock issued and outstanding.
Amount of Beneficial
Ownership
Name and Address
of Beneficial Owner Common Stock(1) Percent of Class
- ------------------- --------------- ----------------
Strong Capital Management, Inc. 422,940 9.00%
Richard S. Strong
100 Heritage Reserve
Menomonee Falls, WI 53051
Randeep S. Grewal 782,500(2) 15.00%
Chairman of the Board, Chief Executive Officer,
and President
10815 Briar Forest Drive
Houston, TX 77042
Dr. Jan F. Holtrop 85,499(3) 1.80%
Director
Van Alkemadelaan
2596 AS The Hague
The Netherlands
George G. Andrews 95,250(4) 1.99%
Director
7899 West Frost Drive
Littleton, CO 80123
Dai Vaughan 70,000(5) 1.47%
Director
2536 Waterstone Way
Marietta, GA 30062
Kenton D. Miller 41,000(6) *
Director
212 E. 25th Street
Tulsa, OK 47114
Richard R. Lembcke 51,575(7) 1.09%
VP Upstream Operations
3000 Wilcrest Drive, Suite 220
Houston, TX 77042
Max A. Elghandour 15,000(8) *
Chief Financial Officer
630 Fifth Avenue, Suite 1501
New York, NY 10111
Brent E. Stromberg 51,900(9) 1.09%
VP Downstream Operations
2801B Santa Maria Way
Santa Maria, CA 93455
Susan M. Whalen 35,000(10) *
VP Corporate Affairs
2801B Santa Maria Way
Santa Maria, CA 93455
All directors and officers as a group (9 persons) 1,227,724(11) 21.85%
* Less than 1%
(1) Rule 13d-3 under the Securities Exchange Act of 1934 involving the
determination of beneficial owners of securities, includes as beneficial owners
of securities any person who directly or indirectly, through any contract,
arrangement, understanding, relationship or otherwise has, or shares, voting
power and/or investment power with respect to such securities, and any person
who has the
34
right to acquire beneficial ownership of such security within sixty days,
including through the exercise of any option, warrant or conversion of a
security.
(2) Includes options presently exercisable to acquire 520,000 shares of GREKA
common stock, and 262,500 shares of GREKA common stock held individually by Mr.
Grewal.
(3) Includes options presently exercisable to acquire 50,000 shares of GREKA
common stock.
(4) Includes options presently exercisable to acquire 90,000 shares of GREKA
common stock.
(5) Consists of options presently exercisable to acquire 70,000 shares of GREKA
common stock.
(6) Consists of options presently exercisable to acquire 41,000 shares of GREKA
common stock.
(7) Includes options presently exercisable to acquire 50,000 shares of GREKA
common stock.
(8) Includes options presently exercisable to acquire 15,000 shares of GREKA
common stock.
(9) Includes options presently exercisable to acquire 50,000 shares of GREKA
common stock.
(10) Consists of options presently exercisable to acquire 35,000 shares of GREKA
common stock.
(11) Includes options presently exercisable to acquire 921,000 shares of GREKA
common stock held by directors and executive officers of GREKA.
Item 13. Certain Relationships and Related Transactions
During the last three fiscal years, there have been no material
transactions between GREKA and any officer, director, nominee for election as
director, or any shareholder owning greater than five percent (5%) of GREKA's
outstanding shares, nor any member of the above referenced individuals'
immediate family, except for Mr. Grewal's restated employment agreement (See
Item 11 - "Executive Compensation"), the loan from International Publishing
Holdings ("IPH"), the Settlement Agreement and Release entered into with Capco
dated August 17, 2000, and as set forth below.
GREKA has an agreement with Grupo de Creacion, Ltd. ("GDC"), a
Gibraltar corporation and a shareholder of the Company, for any European
financing. Under the agreement, GDC assisted GREKA in arranging a private
convertible debenture offering during 1999 resulting in proceeds of
approximately $1,000,000. As compensation, GDC received a negotiated commission
of 10% of the financing less expenses.
The Company had a note receivable at December 31, 2001 from Randeep S.
Grewal, the Company's Chairman of the Board and Chief Executive Officer of
$500,000 which was all due and payable on April 30, 2002. This note has been
repaid in full.
It is GREKA's policy that any future material transactions between it
and members of its management or their affiliates shall be on terms no less
favorable than those available from unaffiliated third parties.
35
Part IV
Item 14. Exhibits and Reports on Form 8-K.
(a) Exhibits. The following exhibits are furnished as part of this report:
Exhibit No. Exhibit Description
3.1 Restated Articles of Incorporation of Horizontal Ventures
(filed as Exhibit 3A to Horizontal Ventures' Quarterly Report
on Form 10-QSB for the quarter ended June 30, 1998 (File No.
0-20760) and incorporated herein by reference)
3.2 Articles of Amendment to Articles of Incorporation effective
March 22, 1999 (filed as Exhibit 3.1 to the Company's Current
Report on Form 8-K dated March 15, 1999 and incorporated
herein by reference)
3.3 ByLaws of Horizontal Ventures (incorporated by reference to
Exhibit No. 3 to the Horizontal Ventures' Registration
Statement (#33-24265-LA)
3.4 Amendment to Article II of the Bylaws of GREKA (filed as
Exhibit 3.1 to the GREKA Report on Form 10-Q for the Quarter
ended September 30, 1999 and incorporated by reference herein)
10.1 Amendment to Promissory Notes dated January 20, 2000 between
Greka and International Publishing Holding, Inc. (filed as
Exhibit 10.13 to GREKA'S amended Report on Form 10-K filed on
April 14, 2000 for the fiscal year ended December 31, 1999,
and incorporated by reference herein)
10.2 Preferred Stock Transfer Agreement dated October 7, 1998
between Horizontal Ventures and RGC (filed as Exhibit 10.1 to
Horizontal Ventures' Quarterly Report on Form 10-QSB for the
quarter ended September 30, 1998 and incorporated herein by
reference).
10.3 Option Agreement dated July 22, 1998 between Horizontal
Ventures and IPH (filed as Exhibit 10.3 to Horizontal
Ventures' Quarterly Report on Form 10-QSB for the quarter
ended September 30, 1998 and incorporated herein by
reference).
10.4 Promissory Note dated October 6, 1998 payable by Horizontal
Ventures to IPH (filed as Exhibit 10.4 to Horizontal Ventures'
Quarterly on Form 10-QSB for the quarter ended September 30,
1998 incorporated herein by reference).
10.5 Pledge Agreement dated October 6, 1998 between Horizontal
Ventures and IPH (filed as Exhibit 10.5 to Horizontal
Ventures' Quarterly Report on Form 10-QSB for the quarter
ended September 30, 1998 and incorporated herein by
reference).
10.6 Promissory Note dated November 4, 1998 payable by Horizontal
Ventures to IPH (filed as Exhibit 10.6 to Horizontal Ventures'
Quarterly Report on Form 10-QSB for the quarter ended
September 30, 1998 and incorporated herein by reference).
10.7 Pledge Agreement dated November 4, 1998 between Horizontal
Ventures and IPH (filed as Exhibit 10.7 to Horizontal
Ventures' Quarterly Report on Form 10-QSB for the quarter
ended September 30, 1998 and incorporated herein by
reference).
10.8 Amendment to $1,500,000 Promissory Note (filed as Exhibit
10.86 to the Amendment No. 2 to the Company's Registration
Statement filed Form S-4 dated February 19, 1999 and
36
incorporated herein by reference)
10.9 Exchange Agreement between GREKA and RGC International
Investors (filed as Exhibit 10.87 to the GREKA Energy Report
on Form 10-K/A for the fiscal year ended December 31, 1998 and
incorporated herein by reference).
10.10 Secured Convertible Promissory Note (filed as Exhibit 10.88 to
the GREKA Energy Report on Form 10-K/A for the fiscal year
ended December 31, 1998 and incorporated herein by reference).
10.11 Asset Purchase Agreement dated March 17, 1999 among Sabacol,
Inc. and the Omimex Group (filed as Exhibit 10.89 to the GREKA
Annual Report on Form 10-KSB for the fiscal year ended
December 31, 1998 and incorporated by reference herein).
10.12 Arrangement Agreement dated June 16, 1999 among GREKA Energy
Corporation and Beaver Lake Resources Corporation (filed as
Exhibit 10.1 to the GREKA Report on Form 10-Q for the quarter
ended June 30, 1999 and incorporated by reference herein)
10.13 Closing Agreement dated June 30, 1999 among Sabacol, Inc. and
Omimex Resources, Inc. et al. (filed as Exhibit 4.2 to the
GREKA Report on Form 8-K filed July 14, 1999 and incorporated
by reference herein)
10.14 Amended and Restated Executive Employment Agreement dated
November 3, 1999 among Randeep S. Grewal and GREKA (filed as
Exhibit 10.2 to the GREKA Report on Form 10-Q for the quarter
ended September 30, 1999 and incorporated by reference herein)
10.15 Rights Agreement dated November 3, 1999 (filed as Exhibit 10.4
to the GREKA Report on Form 10-Q for the quarter ended
September 30, 1999 and incorporated by reference herein)
10.16 First Amended and Restated Loan and Security Agreement dated
November 30, 1999 by and among GMAC Commercial Credit LLC,
Greka Integrated, Inc., Saba Realty, Inc. and Santa Maria
Refining Company (filed as Exhibit 10.1 to the GREKA Report on
Form 8-K filed February 18, 2000 and incorporated by reference
herein)
10.17 Letter Agreement dated December 13, 1999 by and among GMAC
Commercial Credit LLC, Greka Integrated, Inc., Saba Realty,
Inc. and Santa Maria Refining Company (filed as Exhibit 10.2
to the GREKA Report on Form 8-K filed February 18, 2000 and
incorporated by reference herein)
10.18 Settlement Agreement and Release by and among GREKA and
Randeep S. Grewal and Capco Resources, Ltd., Capco Energy,
Inc., and Ilyas Chaudhary dated August 17, 2000 (filed as
Exhibit 10.8 to the Post Effective Amendment No. 1 to the
registration statement on Form S-2, file no. 333-45352, and
incorporated by reference herein)
10.19 First Amendment To First Amended And Restated Loan And
Security Agreement dated February 22, 2001 by and among GMAC
Commercial Credit LLC, Greka Integrated, Inc., Saba Realty,
Inc. and Santa Maria Refining Company (filed as Exhibit 10.30
to the GREKA Annual Report on Form 10-K for the fiscal year
ended December 31, 2000 and incorporated by reference herein)
10.20 Loan Agreement dated as of March 1, 2001 among Greka AM, Inc.
as borrower, the Company as guarantor, and the Bank of Texas,
National Association (filed as Exhibit 10.31 to the GREKA
Annual Report on Form 10-K for the fiscal year ended December
31, 2000 and incorporated by reference herein)
21.1 Subsidiaries of GREKA*
37
23.1 Consent of Arthur Andersen LLP**
23.2 Consent of Netherland, Sewell & Associates, Inc.*
* Filed herewith.
** To be filed by amendment.
(b) Reports on Form 8-K. During the fourth quarter of 2001, GREKA filed the
following reports on Form 8-K:
(1) Current Reports on Form 8-K and 8-K/A dated December 26, 2001 which
reported events under Item 4, Changes in Registrant's Certifying
Accountant.
38
GREKA ENERGY CORPORATION
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
Page
Consolidated Financial Statements of GREKA Energy Corporation
Report of Independent Public Accountants............................. F-2
Consolidated Balance Sheets as of December 31, 2001 and 2000......... F-3
Consolidated Statements of Operations for each of the
three years in the period ended December 31, 2001 ................. F-4
Consolidated Statements of Stockholders' Equity for each
of the three years in the period ended December 31, 2001 .......... F-5
Consolidated Statements of Cash Flows for each of the three
years in the period ended December 31, 2001 ....................... F-6
Notes to Consolidated Financial Statements........................... F-7
Schedule II - Valuation and Qualifying Accounts
for the three years ended December 31, 2001........................ F-19
All other financial statement schedules have been omitted since they are either
not required, are not applicable or the required information is included in the
consolidated financial statements or the notes thereto.
F-1
INDEPENDENT AUDITORS' REPORT
- ----------------------------
To the Stockholders of
Greka Energy Corporation:
We have audited the accompanying consolidated balance sheet of Greka Energy
Corporation and subsidiaries (the "Company") as of December 31, 2001 and the
related consolidated statements of operations, stockholders' equity, and cash
flows for the year then ended. These financial statements are the responsibility
of the Company's management. Our responsibility is to express an opinion on
these financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of the Company as of December 31,
2001, and the results of its operations and its cash flows for the year then
ended in conformity with accounting principles generally accepted in the United
States of America.
Our audit was conducted for the purpose of forming an opinion on the basic
financial statements taken as a whole. Schedule II - Valuation and Qualifying
Accounts is presented for the purpose of additional analysis and is not a
required part of the basic financial statements. This schedule is the
responsibility of the Company's management. Such information has been subjected
to the auditing procedures applied in our audits of the basic financial
statements and, in our opinion, is fairly stated in all material respects when
considered in relation to the basic financial statements taken as a whole.
/s/ Deloitte & Touche LLP
May 13, 2002
New York, New York
F-2
GREKA ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31,
ASSETS
Current Assets 2001 2000
------------ -----------
Cash and cash equivalents ................................ $ 422,103 $ 4,837,699
Accounts receivable trade, net of allowance for
doubtful accounts of $436,258 (2001)
and $827,144 (2000) .................................... 3,618,368 5,951,051
Inventories .............................................. 1,796,520 3,814,992
Other current assets ..................................... 1,552,090 5,160,062
------------ -----------
Total Current Assets ............................ $ 7,389,081 19,763,804
------------ -----------
Property and Equipment
Investment in limestone property ......................... 3,675,973 3,675,973
Oil and gas properties ................................... 46,928,312 31,318,933
Undeveloped oil and gas properties ....................... 7,347,113 7,519,236
Land ..................................................... 17,247,744 17,247,744
Plant and equipment ...................................... 29,823,908 27,398,506
------------ -----------
105,023,050 87,160,392
Less accumulated depreciation, depletion and
amortization ........................................... (15,557,669) (9,978,770)
------------ -----------
Property and Equipment, net ...................................... 89,465,381 77,181,622
Other Assets ..................................................... 3,194,985 1,867,859
------------ -----------
Total Assets ..................................................... $100,049,447 $98,813,285
============ ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities 2001 2000
------------ -----------
Accounts payable and accrued expenses .................... $ 23,751,354 $13,742,245
Current maturities of long-term debt and notes payable ... 33,993,043 8,580,110
Short term borrowing ..................................... -- 105,000
------------ -----------
Total Current Liabilities ....................... 57,744,397 22,427,355
Long term debt, net of current portion ........................... 9,139,395 28,206,771
Other Liabilities ................................................ -- 7,967,941
Commitments and Contingent Liabilities
Stockholders' Equity
Common Stock, no par value, 50,000,000 shares
authorized, 4,694,953 (2001) and 4,523,273 (2000)
shares issued and outstanding .......................... 43,112,523 42,544,542
Accumulated comprehensive income ......................... -- --
Accumulated deficit ...................................... (9,946,868) (2,333,324)
------------ -----------
Total Stockholders' Equity ............................... 33,165,655 40,211,218
------------ -----------
$100,049,447 $98,813,285
============ ===========
The accompanying notes are an integral part of these financial statements
F-3
GREKA ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations
For The Years in the Period Ended December 31,
2001 2000 1999
----------- ----------- -----------
Revenues ....................................................... $40,755,282 $49,067,140 $29,137,810
----------- ----------- -----------
Costs and Expenses
Production and Product Costs ........................... 24,781,938 25,199,620 17,820,620
General and Administration ............................. 8,274,183 7,194,521 3,205,276
Depreciation, depletion and amortization ............... 5,578,899 3,592,242 3,023,783
Other expenses ......................................... -- 1,881,856 --
----------- ----------- -----------
Total Costs and expenses ....................................... 38,635,020 37,868,239 24,049,679
----------- ----------- -----------
Operating Income ............................................... 2,120,262 11,198,901 5,088,131
Other income (expense)
Equity in loss of Saba ................................. -- -- (568,751)
Interest expense ....................................... (4,157,110) (4,535,174) (1,859,688)
Loss on sale of Canadian properties .................... (991,439) --
Other, net ............................................. (5,540,196) -- 732,723
----------- ----------- -----------
Other expense, net ............................ (9,697,306) (5,526,613) (1,695,716)
Minority Interest in loss of consolidated
subsidiary ............................................. -- -- 20,617
----------- ----------- -----------
(Loss) Income Before Income Taxes and cumulative
effect of change in accounting method .................. (7,577,044) 5,672,288 3,413,032
Provision for Income Tax ....................................... (36,500) 361,964 46,000
(Loss) Income before cumulative effect of change in
accounting method ...................................... (7,613,544) 5,310,324 3,367,032
Cumulative effect of change in accounting ...................... -- 853,110 --
----------- ----------- -----------
Net (loss) income .............................................. $(7,613,544) $ 4,457,214 $ 3,367,032
----------- ----------- -----------
Other Comprehensive (loss) ..................................... -- -- (19,243)
----------- ----------- -----------
Comprehensive (loss) income .................................... $(7,613,544) $ 4,457,214 $ 3,347,789
=========== =========== ===========
Net (loss) Income per Common Share - Basic
Before cumulative effect of a change in accounting method..... $ (1.67) $ 1.17 $ 0.80
=========== =========== ===========
Cumulative effect of a change in accounting method ............. -- $ .17 --
Net (loss) Income .............................................. $ (1.67) $ 1.00 $ .80
=========== =========== ===========
Basic Shares ................................................... 4,555,255 4,475,985 4,203,015
Net (loss) Income per Common Shares Diluted
Before cumulative effect of a change in accounting method .... $ (1.67) $ (1.17) $ .75
Cumulative effect of a change in accounting method ............. -- $ .18 --
Net (loss) Income .............................................. $ (1.67) $ .99 $ .75
=========== =========== ===========
Diluted Shares ................................................. 4,650,790 4,762,979 4,801,338
=========== =========== ===========
The accompanying notes are an integral part of these financial statements.
F-4
GREKA ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Statements of Stockholders' Equity
For Each of the Three Years in the Period Ended December 31,
Common Stock Accumulated
Shares Amount (Deficit) Total
---------- ----------- ----------- -----------
Balance as of December 31, 1998 3,056,537 $25,735,019 $(7,230,509) $18,504,510
Issuance of stock for acquisition
of Saba 1,295,425 9,869,904 -- 9,869,904
Issuance of stock for acquisition of
Beaver Lake minority interest 70,977 506,978 -- 506,978
Other issuance, net 133,998 1,149,142 -- 1,149,142
Net income -- -- 3,367,032 3,367,032
Other Comprehensive Loss -- -- (19,243) (19,243)
---------- ----------- ----------- -----------
Balance as of December 31, 1999 4,556,937 37,261,043 (3,882,720) 33,378,323
Issuance of stock for secondary offering 543,375 6,350,377 -- 6,350,377
Issuance of stock for options and warrants 219,427 1,292,420 -- 1,292,420
Issuance of stock for conversion of
debentures 43,534 470,000 -- 470,000
Repurchase of common stock (840,000) (5,737,116) -- (5,737,116)
Stock dividend -- 2,907,818 (2,907,818) --
Net Income -- -- 4,457,214 4,457,214
---------- ----------- ----------- -----------
Balance as of December 31, 2000 4,523,273 $42,544,542 $(2,333,324) $40,211,218
---------- ----------- ----------- -----------
Issuance of stock for options and warrants 25,000 208,125 -- 208,125
Issuance of stock for conversion of
debentures 37,101 395,743 -- 395,743
Issuance of Stock for Assets 20,000 202,000 -- 202,000
Repurchase of common stock (25,000) (237,887) -- (237,887)
Reconciliation with Transfer Agent(a) 114,579 -- -- --
Net Income -- -- (7,613,544) (7,613,544)
---------- ----------- ----------- -----------
Balance as of December 31, 2001 4,694,953 $43,112,523 $(9,946,868) $33,165,655
========== =========== =========== ===========
(a) Relates to finalization of SABA acquisition and other stock related
transactions reported by the Transfer Agent.
The accompanying notes are an integral part of these financial statements.
F-5
GREKA ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows
For Each of the Three Years in the Period Ended December 31,
2001 2000 1999
------------ ------------ ------------
Cash Flow from operating activities
Net (loss) Income ............................... $ (7,613,544) $ 4,457,214 $ 3,367,032
Adjustments to reconcile net income
(loss) to net cash provided by (used in)
operating activities
Depreciation, depletion, and
amortization ................................. 5,578,899 3,592,242 3,023,788
Net loss on settlements of litigation ........... 2,166,613 -- --
Equity in net loss of Saba ...................... -- -- 553,483
Compensation expense attributable to
the issuance of Common Stock .................... -- -- 150,000
Loss on sale of Canadian properties ................ -- 991,439 --
Other non-cash expense ............................. -- 90,000 --
Change in accounting policy ........................ -- 853,110 --
(Increase) decrease in accounts
receivable ...................................... 1,708,996 (1,453,805) (1,101,994)
(Increase) decrease in other current assets ........ 853,145 1,750,336 (5,126,741)
(Increase) decrease in inventory.................... 2,018,472 (528,612) (66,310)
(Increase) decrease in other assets ................ 1,343,416 3,076,133 --
Increase (decrease) in accounts
payable and accrued expenses .................... 968,140 4,998,790 (1,179,791)
Minority Interest in (loss) of
Consolidated subsidiary ......................... -- -- (20,617)
------------ ------------ ------------
Net cash provided by (used in)
operating activities ............................ 5,317,847 11,668,581 (401,152)
------------ ------------ ------------
Cash flow from investing activities:
Purchases of property and equipment ............. (17,170,957) (13,601,519) (2,091,735)
Proceeds from sale of property and
equipment .................................... 890,817 571,000 915,000
Loan to related party .............................. 750,000 -- --
Repayment from party ............................... (500,000) -- --
Acquisition of Saba common and
preferred shares ................................ -- -- --
Cash acquired in Saba acquisition ............... -- -- 444,764
Other .............................................. -- -- (56,380)
------------ ------------ ------------
Net Cash (used in) investing activities ............ (16,030,140) (13,030,519) (788,351)
Cash flows from financing activities:
Repayments of Notes Payable ..................... (16,124,689) (9,085,831) (28,098,901)
Proceeds of loans from affiliates ............... -- -- 25,317,293
Proceeds of Loan ................................ 27,348,007 13,026,468 --
Net increase(decrease) in Revolver Loan ............ (3,647,875) -- 4,443,216
Payment of financing costs ......................... (1,294,535) -- (625,000)
Proceeds from sale of stock, net of
expenses ........................................ -- 6,350,377 --
Repurchase of Common Stock ......................... 237,887 (5,737,116) --
Increase from restricted cash ...................... -- 1,000,000 --
Exercise of options ................................ 320,676 542,420 --
Bond redemption .................................... (67,000) -- --
------------ ------------ ------------
Net cash provided by financing activities .......... 6,296,697 6,096,318 1,036,608
------------ ------------ ------------
Net increase (decrease) in cash and
cash equivalents ................................ (4,415,596) 4,740,380 (152,893)
Cash and cash equivalents:
Beginning of period ............................. 4,837,699 97,319 250,212
------------ ------------ ------------
End of period ...................................... $ 422,103 $ 4,837,699 $ 97,319
============ ============ ============
Cash paid for:
Interest ........................................ $ 3,402,206 $ 3,830,243 $ 1,688,424
Income taxes .................................... $ -- $ 197,938 $ 149,288
Non-cash financing and investing activities:
Stock issued for services ....................... $ -- $ -- $ (180,000)
Stock issued upon conversion of
convertible debentures ....................... 283,666 470,000 --
The accompanying notes are an integral part of these financial statements.
F-6
GREKA Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2001
NOTE 1 - DESCRIPTION OF BUSINESS
GREKA Energy Corporation, a Colorado corporation ("GREKA" or the "Company") is a
vertically-integrated energy company with primary areas of activities in
California and long-term in China. The Company is principally focused on
exploiting the high cash margin created from the relatively stable natural hedge
by its crude production and the asphalt market in Central California.
Business Segments
During 2001 and 2000, the Company operated in three industry segments:
Integrated Operations (California refinery and E&P), E&P Americas, and E&P
International. The Integrated Operations include an asphalt refinery and
interests in heavy oil fields. The refinery produces liquid asphalt, gasoil,
naphtha and distillates. The exploration and production segments, focuses on
developing and exploiting hydrocarbon reserves domestically and internationally.
The accounting policies of the segments are the same as those described in NOTE
2 - Summary of Significant Accounting Policies. Information about the Company's
operations by segment as of and for the years ended December 31, 2001, 2000 and
1999 is as follows (in thousands):
Integrated E&P E&P Corp. &
Operations Americas Int'l Other* Total
---------- -------- ------- -------- --------
2001
Total Oil and Gas
Revenue $ 8,587 $15,090 $ -- $ (8,541) $ 15,136
Refinery Revenue 25,620 -- -- -- 25,620
------- ------- ----- -------- --------
Total Revenue 34,207 15,090 -- (8,541) 40,756
------- ------- ----- -------- --------
Expenses:
Production Costs 3,324 5,219 -- (3,324) 5,219
Refinery Costs 24,780 -- -- (5,217) 19,563
General and Administrative 1,883 2,240 -- 3,851 7,974
Depreciation, Depletion and
Amortization Expenses 2,292 3,142 -- 145 5,579
Net Profit Sharing Plan -- -- -- 300 300
------- ------- ----- -------- --------
Operating Profit 1,928 4,489 -- (4,296) 2,120
------- ------- ----- -------- --------
Interest expense (2,366) (1,164) -- (627) (4,157)
Non-Recurring Income (Expense) (438) 1,755 -- (6,857) (5,540)
Income Tax -- -- -- (37) (37)
------- ------- ----- -------- --------
Net Income (Loss) $ (876) $ 5,080 $ -- $(11,817) $ (7,614)
======= ======= ===== ======== ========
Capital Expenditures $ 4,188 $12,156 $ -- $ 826 $ 17,170
Assets at year-end $56,739 $32,693 $ -- $ 10,617 $100,049
*Excludes intercompany elimination
2000
Total Oil and Gas
Revenue $10,230 $14,851 $ 423 $(9,916) $15,588
Refinery Revenue 33,480 -- -- -- 33,480
------- ------- ------ ------- -------
Total Revenue 43,710 14,851 422 (9,916) 49,068
------- ------- ------ ------- -------
Expenses:
Production Costs 2,065 3,993 84 (2,065) 4,077
Refinery Costs 28,985 -- -- (7,862) 21,123
General and Administrative 1,896 1,922 104 2,777 6,699
Depreciatioin, Depletion and
Amortization Expenses 1,814 1,556 77 145 3,592
Net profit sharing plan -- -- -- 495 495
Other expenses 1,882 -- -- -- 1,882
------- ------- ------ ------- -------
Operating Profit 7,068 7,380 157 (3,405) 11,199
------- ------- ------ ------- -------
Interest expense (2,646) (320) (27) (1,542) (4,535)
Loss on sale of Canadian
properties -- -- (991) -- (991)
Income tax expense -- -- -- (362) (362)
Cumulative effect of
accounting change (853) -- -- -- (853)
------- ------- ------ ------- -------
Net Income (loss) $ 3,569 $ 7,060 $ (861) $(5,309) $ 4,457
======= ======= ====== ======= =======
Capital Expenditures $ 5,828 $ 6,112 $1,662 $ -- $13,602
Assets at Year End $61,497 $31,925 $4,642 $ 749 $98,813
1999
Total Oil and Gas
Revenue $ 3,710 $ 5,425 $2,868 $(3,799) $ 8,183
Refinery Revenue 20,924 -- -- -- 20,924
------- ------- ------ ------- -------
Total Revenue 24,645 5,425 2,868 (3,799) 29,138
------- ------- ------ ------- -------
Expenses:
Production Costs 2,229 2,939 1,577 (3,799) 7,244
Refinery Costs 14,375 -- -- -- 10,576
Gross Profit 7,543 2,487 1,290 -- 11,318
Other Expenses 1,426 245 576 958 3,205
Depreciation, Depletion and
Amortization Expenses 1,543 1,064 506 -- 3,024
Interest and other
(expense) income 31 (31) 747 (2,380) (1,695)
------- ------- ------ ------- -------
Net Income (Loss) $ 4,630 $ 1,147 $ 955 $(3,365) $ 3,367
======= ======= ====== ======= =======
Capital Expenditures $ 2,092 $ -- $ -- $ -- $ 2,092
Assets at year-end $58,267 $16,886 $8,456 $ 244 $84,213
F-7
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of presentation - The consolidated financial statements include the
accounts of the Company and wholly owned subsidiaries.
All significant intercompany accounts and transactions have been eliminated in
the accompanying consolidated financial statements.
The preparation of financial statements in conformity with accounting principles
generally accepted in the United States requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amount of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Effective December 31, 2000, the Company declared a 5% stock dividend for
issuance of .05 shares of common stock for each share of common stock issued and
outstanding to holders of the Company's common stock as of December 31, 2000.
The fair market value of the dividend has been reflected as a charge to retained
earnings in the accompanying financial statements. The accompanying financial
statements have been adjusted to reflect the additional shares issued in
connection with this stock dividend as if such shares had been outstanding for
all periods presented.
Certain reclassifications have been made to prior year financial statements to
conform to the current year presentation.
Cash and cash equivalents - The Company considers all highly liquid investments
purchased with an original maturity of three months or less to be cash
equivalents.
Fair value of financial instruments - The carrying amounts of cash and cash
equivalents, accounts receivable, accounts payable and accrued expenses, other
current liabilities and notes payable, approximate fair value because of the
short maturity of these items. These fair value estimates are subjective in
nature and involve uncertainties and matters of significant judgment, and,
therefore, cannot be determined with precision. Changes in assumptions could
significantly affect these estimates.
Accounts receivable - The Company provides an allowance for uncollectible
receivables when it is determined that collection is doubtful. Substantially all
of the Company's subsidiaries 2001 and 2000 trade receivables are from sales of
asphalt and related products and oil and gas billings, including those to joint
interest property owners.
Inventories - Inventories are stated at the lower of cost or market. The
Company's accounting method for inventory was changed from the first in, first
out (FIFO) method to the average cost method effective January 1, 2000. The
average cost method is preferable because the primary inventoriable cost at the
refinery is crude oil for which the price can fluctuate significantly. The
weighted average method balances the impact of short term fluctuations in crude
oil pricing on the Company's refinery inventory levels. The Company recorded the
effect of this change of $853,110 as a cumulative effect of a change in
accounting principle as of January 1, 2000.
Concentrations of credit risk - Substantially all of the Company's subsidiaries'
accounts receivable are from companies engaged in the asphalt/paving and oil and
gas businesses, and concentrated in the Western and Southern United States.
Generally, the Company's subsidiaries do not require collateral for its accounts
receivables. Three customers accounted for more than ten percent of the
Company's sales of North American refinery production during the three years in
the period ended December 31, 2001, namely FAMM, Lawson and Granite accounted
for approximately 22%, 14% and 12%, respectively, of such sales.
Properties and equipment - Properties and equipment are stated at cost. The
Company follows the "full-cost" method of accounting for oil and gas property
and equipment costs. Under this method, all productive and nonproductive costs
incurred in the acquisition, exploration, and development of oil and gas
reserves are capitalized. Such costs include lease acquisitions, geological and
geophysical services, drilling, completion, equipment, and certain general and
administrative costs directly associated with acquisition, exploration, and
development activities. General and administrative costs related to production
and general overhead are expensed as incurred. No gains or losses are recognized
upon the sale or disposition of oil and gas properties, except in transactions
that involve a
F-8
significant amount of reserves in a cost center. The proceeds from the sale of
oil and gas properties are generally treated as a reduction of oil and gas
property costs. Fees from associated oil and gas exploration and development
partnerships, if any, will be credited to oil and gas property costs to the
extent they do not represent reimbursement of general and administrative
expenses currently charged to expense.
Such costs can be directly identified with acquisition, exploration and
development activities and do not include any costs related to production,
general corporate overhead, or similar activities.
Future development, site restoration, and dismantlement and abandonment costs,
net of salvage values, are estimated on a property-by-property basis based on
current economic conditions and are amortized to expense as the Company's
subsidiaries' capitalized oil and gas property costs are amortized. The
Company's subsidiaries' properties are all onshore, and the Company expects that
the salvage value of the tangible equipment will substantially offset any site
restoration and dismantlement and abandonment costs.
The provision for depreciation, depletion, and amortization of oil and gas
properties is computed on the unit-of-production method. Under this method, the
Company computes the provision by multiplying the total unamortized costs of oil
and gas properties including future development, site restoration, and
dismantlement and abandonment costs, but excluding costs of unproved properties
by an overall rate determined by dividing the physical units of oil and gas
produced during the period by the total estimated units of proved oil and gas
reserves. This calculation is done on a country by country basis for those
countries with oil and gas production. The cost of unevaluated properties
(approximately $7.3 and $7.5 million at December 31, 2001 and 2000) not being
amortized, to the extent there is such a cost, is assessed quarterly to
determine whether the value has been impaired below the capitalized cost. Any
impairment assessed is added to the cost of proved properties being amortized.
The costs associated with unevaluated properties relate to projects which were
undergoing exploration or development activities or in which the Company intends
to commence such activities in the future. The Company will begin to amortize
these costs when proved reserves are established or impairment is determined.
Management believes no such impairment exists at December 31, 2001.
At the end of each quarterly reporting period, the unamortized cost of oil and
gas properties, net of related deferred income taxes, is limited to the sum of
the estimated future net revenues from proved properties using current prices,
discounted at 10%, and the lower of cost or fair value of unproved properties,
adjusted for related income tax effects ("Ceiling Limitation").
The calculation of the Ceiling Limitation and provision for depreciation,
depletion, and amortization is based on estimates of proved reserves. There are
numerous uncertainties inherent in estimating quantities of proven reserves and
in projecting the future rates of production, timing, and plan of development.
The accuracy of any reserves estimate is a function of the quality of available
data and of engineering and geological interpretation and judgment. Results of
drilling, testing, and production subsequent to the date of the estimate may
justify revision of such estimate. Accordingly, reserve estimates are often
different from the quantities of oil and gas that are ultimately recovered.
Depreciation for all other property and equipment is provided over estimated
useful lives using the straight line method of depreciation for financial
reporting purposes and the accelerated cost recovery method for income tax
purposes. Renewals and betterments are capitalized when incurred. Costs of
maintenance and repairs that do not improve or extend asset lives are charged to
expense.
Environmental expenditures - If and when remediation of a property is probable
and the related costs can be reasonably estimated, the environmentally related
remediation costs will be expensed and recorded as liabilities. If recoveries of
environmental costs from third parties are probable, a receivable will be
recorded.
Revenue recognition - Revenue from oil, gas and asphalt production is recognized
in the period in which the product is sold. The related costs and expenses are
recognized when incurred. Revenues from drilling operations are recognized in
the accounting period, which corresponds with the performance of the service to
the customer.
F-9
Federal and State income taxes - The Company follows SFAS No. 109, "Accounting
for Income Taxes", which accounts for income taxes using the liability method.
Under SFAS No. 109, deferred tax liabilities and assets are determined based on
differences between the financial statement and tax bases of assets and
liabilities using enacted tax rates expected to be in effect for the year in
which the differences are expected to reverse. The net change in deferred tax
assets and liabilities is reflected in the statement of operations. The primary
differences between financial reporting and tax reporting relate to the
availability of net operating loss carryforwards, and the use of accelerated
methods of depreciation for income tax purposes.
Earnings per share - Basic earnings/(loss) per share has been computed using the
weighted average number of common shares outstanding during the respective
periods. Diluted earnings per share is computed by considering the effect of
outstanding options, warrants and other convertible securities. However,diluted
earnings per share is the same as basic earnings per share in instances where a
loss has been incurred. The impact of a 5% stock dividend, which was effective
on December 31, 2000, has been reflected in earnings per share for all periods
presented.
New Accounting Pronouncements
The FASB has recently issued SFAS No. 141, "Business Combinations," SFAS No.
142, "Goodwill and Other Intangible Assets." SFAS No. 143, "Accounting for
Asset Retirement Obligations" and SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets."
SFAS No. 141, "Business Combinations," requires the use of the purchase method
of accounting for all business combinations initiated after June 30, 2001. SFAS
No. 142, "Goodwill and Other Intangible Assets", addresses accounting for the
acquisition of intangible assets and accounting for goodwill and other
intangible assets after they have been initially recognized in the financial
statements. We do not currently have goodwill or other similar intangible
assets' therefore, the adoption of the new standard on January 1, 2002, has not
had a material effect on our financial statements.
SFAS No. 143, "Accounting for Asset Retirement Obligations," addresses
accounting and reporting for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs. SFAS No.
143 will be effective for us January 1, 2003 and early adoption is encouraged.
SFAS No. 143 requires that the fair value of a liability for an asset's
retirement obligation be recorded in the period in which it is incurred and the
corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its then present value each
period, and the capitalized cost is depreciated over the useful life of the
related asset. If the liability is settled for an amount other than the
recorded amount, a gain or loss is recognized. Currently, we include estimated
future costs of abandonment and dismantlement in our full cost amortization base
and amortize these costs as a component of our depletion expense. We are
evaluating the impact the new standards will have on our financial statements.
SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets,"
is effective for us January 1, 2002, and addresses accounting and reporting for
the impairment or disposal of long-lived assets. SFAS 144 supersedes SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of" and ABP Opinion No. 30, "Reporting the Results of
Operations-Reporting the Effects of Disposal of Segment of a Business." SFAS No.
144 retains the fundamental provisions of SFAS No. 121 and expands 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. We are evaluating the impact the new standard will have on our
financial statements.
NOTE 3 - MERGER WITH SABA PETROLEUM COMPANY
In March 1999, the Company, through a wholly owned subsidiary, merged with Saba
in a transaction accounted for as a purchase with a cost of approximately $9.9
million based upon the issuance of 1,233,738 shares of GREKA stock. GREKA's
total acquisition cost of $25.8 million has been allocated to the fair value of
each of Saba's assets and liabilities, as of March 24, 1999 (as updated) in the
following table. (dollars in thousands)
03/24/99
--------
Refinery $ 25,400
Oil and Gas Properties 29,935
Land 16,600
Other Assets 7,027
Liabilities and minority interest (53,207)
--------
Total investment $ 25,755
========
The following are the unaudited pro forma revenue, net income and income per
share of the Company giving effect to the acquisition of Saba, as if such
acquisition had occurred at the beginning of 1999. The unaudited pro forma
financial data does not purport to be indicative of the financial position or
results of operations that would actually have occurred if the acquisition had
occurred as presented or that may be obtained in the future.
Year Ended
December 31, 1999
-----------------
Dollars in thousands,
except share amounts
Revenue ........................... $32,779
Net Income ........................ 1,459
Income per common share ........... 0.34
NOTE 4 - PROPERTY AND EQUIPMENT
A summary of the Company's subsidiaries' property and equipment as of December
31, 2001 and 2000 is as follows:
2001 2000
----------- -----------
Investment in limestone properties ........................ 3,675,973 3,675,973
Oil and gas properties .................................... 46,928,312 31,318,933
Undeveloped oil and gas properties ........................ 7,347,113 7,519,236
Land and buildings ........................................ 17,247,744 17,247,744
Plant and equipment ....................................... 29,823,908 27,398,506
----------- -----------
Total cost ................................................ 105,023,050 87,160,392
Accumulated depreciation, and Amortization depletion ...... (15,557,669) (9,978,770)
----------- -----------
F-10
$89,465,381 $77,181,622
=========== ===========
Depreciation, depletion and amortization charged against income was $5,578,899
in 2001, $3,592,242 in 2000, and $3,023,783 in 1999.
Useful lives are as follows:
Refinery .............................................. 40 years
Buildings ............................................. 20 to 40 years
Transportation equipment .............................. 5 to 6 years
Office and computer equipment ......................... 3 to 10 years
NOTE 5 - EARNINGS PER SHARE
Diluted earnings per share for 2001, 2000 and 1999 was calculated as follows:
2001 2000 1999
----------- ---------- ---------
Net (Loss) Income .................................. $(7,613,544) $4,457,214 $3,367,032
Income impact of assumed conversion of convertible
debt ........................................... -- 256,770 241,313
----------- ---------- ----------
Net (loss) income of assumed conversion ............ $(7,613,544) $4,713,984 $3,608,345
=========== ========== ==========
Weighted Average Common Shares Outstanding ......... 4,555,255 4,475,985 4,203,015
Effect of Dilutive Securities -
Employee stock options and warrants/(a)/ ........ -- 58,754 177,735
Convertible Debt ................................ -- 228,240 420,588
----------- ---------- ----------
Weighted Average Shares plus impact
of assumed conversion ........................... 4,555,255 4,762,979 4,801,338
=========== ========== ==========
Basic Earnings per Share......................... $ (1.67) $ 1.00 $ 0.80
Diluted Earnings per share....................... $ (1.67) $ 0.99 $ 0.75
(a) During 2001, employee stock option and warrants totaled 95,535. These
securities are not included in 2001 Earnings per Share calculation since the
effect is antidilutive.
NOTE 6 - INVENTORIES
Inventory includes material, labor and manufacturing overhead costs. Due to the
continuous manufacturing process, there is no significant work in process at any
time. Inventory consists of the following as of December 31,:
2001 2000
---------- ----------
Raw Material ........................ $ 632,651 $ 368,054
Finished goods....................... 1,163,869 3,446,938
---------- ----------
Total ............................ $1,796,520 $3,814,992
NOTE 7 - COMMITMENTS AND CONTINGENCIES
The Company and its subsidiaries lease office space, automobiles, computers, and
other equipment under various operating leases. The Company and its subsidiaries
have options to renew these leases. Aggregate commitments under these leases at
December 31, 2001 were as follows:
Year Ending December 31: Amount
- ------------------------ -------
2002 175,032
2003 177,616
2004 824
2005 and thereafter -0-
-----------
Total $353,472
===========
Rent expense included in the accompanying statements of operations was $266,666,
$274,341, and $370,133 in 2001, 2000, and 1999, respectively.
In October 1994, the Company licensed certain directional drilling technology
from BP Amoco, a major oil corporation. The license currently requires minimum
annual
F-11
payments of $15,000 per year or $1,639 per well drilled under the license,
whichever is greater, and the amounts are adjusted periodically for inflation.
The Company incurred license fees approximating $15,000, $15,000, and
$30,000 for the years ended December 31, 2001, 2000, and 1999, respectively.
Semi-annual settlements are required under the license, and BP Amoco has the
right to terminate the license for non-payment.
In 1995, the Company agreed to acquire an oil and gas interest in California on
which a number of out of production oil wells had been drilled by the seller.
The acquisition agreement required that the Company assume the obligation to
abandon any wells that it did not return to production, irrespective of whether
certain consents of third parties necessary to transfer the property to the
Company were obtained. A third party whose consent was required to transfer the
property did not consent to the transfer. The third party is holding the seller
responsible for all remediation. The Company believes it has no financial
obligation to remediate this property because it was never the owner of the
property, never produced any oil or gas from the property, was not associated
with the site and the seller did not give its predecessor any consideration to
enter into the contract for the property. Since May 2000, the Company commenced
remediation on the subject property as directed by the regulatory agency.
Notwithstanding its compliance in proceeding with any required remediation on
seller's account, the Company is committed to hold the seller accountable for
the required obligations of the subject property. Through December 31, 2001, the
Company has remediated 31 of 72 wells and related facilities on the property for
a cost of $1.5 million. This amount is recorded as a long-term receivable, as
the Company believes it is probable that such amount will be recoverable from
the seller. The Company has had informal discussions with the seller, which to
date have not produced positive results. Therefore, the Company intends to
pursue formal litigation for recovery. Based on future developments with this
litigation, it is reasonably possible that the Company's estimate of recovery
and ultimate liability could change in the near term and such change could be
material.
GREKA's subsidiary owns an asphalt refinery in Santa Maria, California, with
which environmental remediation obligations are associated. The party who sold
the asphalt refinery to the Company's subsidiary performs all environmental
obligations that arose during and as a result of its operations of the refinery
prior to the acquisition. There could be additional environmental issues which
may require material remediation efforts in the future.
GREKA's subsidiaries, as is customary in the industry, are required to plug and
abandon wells and remediate facility sites on their properties after production
operations are completed. The cost of such operation will be significant and
will occur, from time to time, as properties are abandoned.
There can be no assurance that material costs for remediation or other
environmental compliance will not be incurred in the future. The occurrence of
such environmental compliance costs could be materially adverse to the Company.
No assurance can be given that the costs of closure of any of the Company's
subsidiaries' other oil and gas properties would not have a material adverse
effect on the Company.
NOTE 8 - FEDERAL AND STATE INCOME TAXES
The components of income (loss) before income taxes for the years ended December
31, 2001, 2000, and 1999 are as follows:
2001 2000 1999
----------- ---------- ----------
United States ................ $(7,577,044) $5,542,481 $2,725,143
International ................ -- 129,807 687,889
----------- ---------- ----------
$(7,577,044) $5,672,288 $3,413,032
Components of provision for income tax expense for the years ended December 31,
2001 and 2000 are as follows.
2001 2000 1999
------- -------- --------
Current
F-12
Federal ............... $ -- $ 93,787 $ 40,000
State ................. 36,500 268,177 46,000
------- -------- --------
$36,500 $361,964 86,000
Deferred
Federal ............... -- -- (40,000)
State ................. -- -- --
------- -------- --------
-- -- (40,000)
------- -------- --------
$36,500 $361,964 $ 46,000
======= ======== ========
In 2001, the effective tax rate differs from the amount that would result from
the application of the statutory rate due primarily to the utilization of net
operating loss carryforwards. The Company generated a net operating loss in the
current year and established a full valuation allowance. The Company is only
providing for state franchise/capital tax expense which is not dependent on
income.
Net deferred income tax assets, which are significantly comprised of net
operating loss carryforwards, the temporary difference resulting from the use of
different depreciation methods for property and equipment for book and tax
purposes and tax credit carryforwards have been fully reserved for through a
valuation allowance.
A significant net operating loss carryforward has been incurred in prior years,
primarily by Petro Union, Horizontal Ventures and Saba. The net operating loss
expires, if unused, as follows:
Expires in Amount
- ---------- -----------
2008 $ 3,582,000
2009 452,000
2010 64,000
2011 1,067,000
2018 569,000
2019 6,229,000
-----------
Total $14,628,000
===========
The Company's review of its available net operating loss carry-forwards is
ongoing. Upon completion of this review, additional net operating loss carry
forwards may be identified. In accordance with Internal Revenue Service
regulations, the use of the above net operating loss carryforwards related to
acquired companies is subject to an annual limitation.
NOTE 9 - NOTES PAYABLE AND LONG-TERM DEBT:
Notes payable and long-term debt consist of the following at December 31, 2001
and 2000:
2001 2000
----------- -----------
9% senior subordinated
Debentures Due 2005 Net of
discount(a) ......................... $ 2,527,088 $ 2,683,933
Loan agreement -(b)..................... 18,055,000 8,700,000
Capital lease obligations(c) ........... -- 233,437
Term loan with a bank(d) .............. 325,972 340,354
Notes payable(e) ....................... 2,390,000 2,390,000
15% convertible senior subordinated
Debentures due 2001(f) .............. 1,300,000 1,000,000
Term and Revolving Loan Agreement
GMAC Financial Corporation(g) ....... 18,256,811 20,904,446
Other notes and loans .................. 277,567 639,711
----------- -----------
$43,132,438 $36,891,881
Less current portion ................... 33,993,043 8,685,110
----------- -----------
Net Long-term debt ..................... $ 9,139,395 $28,206,771
=========== ===========
Annual Principal Requirements (in 000's)
2002 $ 34,687
2003 5,000
2004 3,445
---------
Total $ 43,132
=========
(a) In June 2000, GREKA exchanged $3.3 million of Saba 9% senior subordinated
convertible debentures for GREKA debentures. The GREKA
F-13
debentures are convertible to Company common stock at the option of the
holders of the debentures at any time prior to the due date of the
debenture (December 31, 2005), unless previously redeemed. Upon the receipt
of a duly executed notice of election to convert the GREKA debenture, the
Company will convert the debenture to GREKA common stock based upon a per
share conversion price equal to 95% of the average closing bid price of its
common stock for 30 consecutive trading days ending one day prior to the
receipt of the notice of election to convert except that the conversion
price shall in no case be less than $8.50 per share nor greater than $12.50
per share. GREKA also has the right to redeem the GREKA debenture by
providing 30 days written notice of its intent to redeem during which time
the debenture holder may convert his or her debenture. During 2000, $0.5
million debentures were converted into 43,534 shares of GREKA common stock
and $0.1 million debentures were redeemed, with a resulting debenture
balance of $2.7 million as of December 31, 2000.
(b) In June 2000, one of GREKA's subsidiary entered into a credit and guarantee
agreement with Canadian Imperial Bank of Commerce ("CIBC") and CIBC World
Markets Corp. The agreement provided that this subsidiary may borrow up
to $47.5 million bearing interest at prime plus 1.25 percent. A portion of
the proceeds were paid to reduce the current debt of GREKA, which payment
resulted in the complete elimination of all Bank One debt ($3.0 million)
incurred by GREKA in its acquisition of Saba. The facility, which is
secured by GREKA's subsidiary's interest in certain North American oil and
gas properties, specifically provided the financing required to close
GREKA's option to re-purchase the Colombian assets. In December 2000, the
facility was amended to extend the maturity date from December 1, 2000 to
February 28, 2001 and fix the maximum available amount of the facility
pending repayment.
In March 2001, GREKA's subsidiary entered into a credit and guarantee
agreement with the Bank of Texas, N.A. ("Bank of Texas"). The agreement
provides that GREKA's subsidiary may borrow up to $75 million bearing
interest at prime rate less 1/2 percent. GREKA closed a revolving credit
line of $16 million with an initial advance of $13.2 million against the
line secured by GREKA's subsidiary's interest in certain North American oil
and gas properties. A portion of the proceeds were used to reduce the
current debt of GREKA, which payment resulted in the complete elimination
of all obligations owed to CIBC.
(c) A subsidiary of the Company leases certain equipment under agreements that
are classified as capital leases. Lease terms vary from three to five
years. The effective interest rate on the total amount of capitalized
leases at December 31, 2001 and 2000 was 14.1% and 8.21%, respectively.
(d) The term loan with a bank ($325,972) is due to the seller of a fee interest
in property in which one of the Company's subsidiaries owns mineral
interests. The term loan bears interest at the rate of prime plus 1% (10.5%
and 10.25% at December 31, 2001 and 2000, respectively), is scheduled for
repayment in monthly installments to a maturity date of August 2002 and is
collateralized by the fee interest acquired by the subsidiary.
(e) Effective January 1, 2000, two prior loans from GREKA's then affiliate,
International Publishing Holdings ("IPH"), which matured December 31, 1999
in the aggregate amount of $2 million were consolidated into one loan with
a maturity date of June 30, 2000, bearing interest at the rate of 9% per
annum from January 1, 2000 payable quarterly, with monthly installment
payments of $100,000. The Company paid $180,000 in consideration of the
loan extension. The terms of the extension provided that if the entire
unpaid principal and/or accrued interest was not paid at maturity, the
amount of principal owed and rate of interest shall increase by $390,000
and 6%, respectively. At December 31, 2000 and 2001 the Company owed IPH
$2,569,250 and $2,479,625 of principal and accrued interest. The loan,
was repaid in full during the second quarter 2002.
(f) On February 1, 2001, GREKA paid its 15% convertible senior subordinated
debentures in the principal amount of $1 million that were issued in
February 1999, and the security of one of GREKA's subsidiaries interest in
limestone deposits was released. There were no conversions by debenture
holders into GREKA common stock at the conversion price of $20.00 per
share.
F-14
(g) In November 1999, the Company entered into a loan and security agreement
with GMAC Commercial Credit LLC ("GMAC"). That agreement amends the loan
and security agreement the parties entered into in April 1999. The November
1999 agreement increased from $11 million to $35 million the amount which
GREKA's subsidiaries may borrow from GMAC upon the satisfaction of the
terms and conditions of the agreement. The financing consists of a term
loan of $25 million and a revolving credit facility of $10 million. The
financing is secured by GREKA's subsidiaries' interests in certain
California oil and gas properties and real estate. The term loan had an
outstanding balance of $17,500,000 and the revolving credit facility
$3,404,446 at December 31, 2000. Amounts outstanding under the credit
facility bear interest at the rate of prime plus 1% (9.25% at December 31,
1999). Amortization of the term loan began in April 2000.
In February 2001, the credit facility with GMAC was increased for a third
time. The transaction provides additional financing of up to $46 million by
increasing the principal amount of the term loan from $25 million to $36
million, and $10 million for working capital. Modifications to the terms of
the credit agreement include the extension of the credit facility to a term
through November 30, 2005.
The balance in the working capital portion of the Loan was $3,956,571 and
the term had a balance of $14,300,000 at December 31, 2001. The term loan
requires a principal deduction of $5,000,000 in 2002.
NOTE 10 - OTHER LIABILITIES
Other liabilities of $7,967,941 at December 31, 2000, primarily represent the
Company's estimated remaining exposure to litigation acquired in the Saba
acquisition. At December 31, 2001, there were no amounts accrued for litigation.
NOTE 11 - LITIGATION
Bank of Texas, N.A. v. Greka AM, Inc. and GREKA Energy Corporation (Case No.
02-00771, 160th Judicial District Court of Dallas County, Texas, January 2002).
Bank of Texas alleged a default on the loan to GREKA's subsidiary and brought an
action seeking repayment of the loan plus unspecified exemplary damages and
attorney fees. GREKA filed counter-claims seeking contract and unspecified
exemplary damages and attorneys fees. The parties have entered into a
forbearance agreement through June 30, 2002 by which time the parties' claims
shall be settled or GREKA shall proceed to vigorously defend all claims asserted
by Bank of Texas and seek counter-relief.
Liens and legal actions in connection therewith alleging nonpayment or untimely
payment for services or goods provided to GREKA's properties in an aggregate
amount of approximately $5.2 million have been filed against our subsidiary's
working interests. We plan to settle these claims concurrent with if not before
the planned sale of our assets and debt restructuring in the second quarter of
2002.
From time to time, the Company and its subsidiaries are a named party in legal
proceedings arising in the ordinary course of business. While the outcome of
such proceedings cannot be predicted with certainty, management does not expect
these matters to have a material adverse effect on the Company's financial
condition or results of operations.
NOTE 12 - SETTLEMENT AGREEMENT WITH CAPCO RESOURCES, LTD.
In October 2000, the Company closed its settlement agreement with Capco
Resources, Ltd. ("CAPCO") Under the terms of the agreement the Company bought
back 80,769 shares in the third quarter of 2000, and in October, bought back
759,231 additional shares of the Company's common stock for cash consideration
of $5.2 million and the forgiveness of a note receivable. These shares have been
canceled. At December 31, 2001, CAPCO owns 514,500 shares of GREKA's common
stock. However, CAPCO does not have any voting rights associated with such
shares. The Company retains the voting right through December 31, 2002.
NOTE 13 - RELATED PARTY TRANSACTIONS
GREKA has an agreement with Grupo de Creacion, Ltd. ("GDC"), a Gibraltar
corporation and a shareholder of the Company, for any European financing. Under
the
F-15
agreement, GDC assisted GREKA in arranging a private convertible debenture
offering during 1999 resulting in proceeds of approximately $1,000,000. As
compensation, GDC received a negotiated commission of 10% of the financing less
expenses.
The Company had a note receivable at December 31, 2000 from an officer of the
Company of $750,000 relating to an exercise of stock options on December 26,
2000. This note was repaid on January 9, 2001.
The Company had a note receivable at December 31, 2001 from Randeep S. Grewal,
the Company's Chairman of the Board and Chief Executive Officer of $500,000
which was all due and payable on April 30, 2002. This note was repaid in full in
April, 2002.
NOTE 14 - STOCK OPTIONS AND WARRANTS
At December 31, 2000, GREKA had granted 1.4 million options to acquire shares of
common stock of GREKA, of which 1,025,000 were granted in 2000 at an exercise
price of $8.625 to employees and directors of the Company. A total of 164,000
options have terminated through attrition and 178,000 options were exercised
during 2000, leaving the total option grants outstanding as of December 31, 2000
at 1,058,000 options. Management has determined not to adjust the exercise price
or the number of employee options granted or available for grant not
withstanding the 5% stock dividend issued during January 2001.
At December 31, 2001, GREKA had granted 1.4 million options to acquire shares of
common stock of GREKA, of which 93,000 were granted in 2001 at exercise prices
of $12.50 (68,000 options) and $11.32 (45,000 options) to employees and
directors of the Company. A total of 24,000 options have terminated through
attrition and 39,000 options have been exercised, leaving the total option
grants outstanding as of December 31, 2001 at 1,088,000 options.
A summary of the outstanding options follows:
2001 2000 1999
---------- -------- --------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
--------- ---------- --------- -------- ------- --------
Options outstanding,
January 1 ................ 1,058,000 $ 8.54 375,000 $ 6.93 400,000 $7.03
Options granted ............. 93,000 11.929 1,025,000 8.625 14,000 7.75
Options exercised ........... 39,000 8.91 178,000 5.17 -- --
Options terminated .......... 24,000 11.850 164,000 8.625 39,000 8.25
--------- ---------- --------- ------ ------- -----
Options outstanding,
December 31 .............. 1,088,000 $ 9.33 1,058,000 $ 8.54 375,000 $6.93
Exercisable at
year end ................. 1,037,000 9.23 222,000 $ 8.26 371,000 6.92
A summary is as follows of the Class B warrants to purchase common stock granted
by the Company on February 26, 1999:
Number of
Warrants Effective Expiration Number of Warrants
Granted Option Price Date Date Exercised in 2000
- --------- ------------ ---------------- ----------------- ------------------
105,000 $9.52 February 1, 1999 December 31, 2001 32,025
As permitted under SFAS 123, the Company has elected to continue to account for
stock-based compensation under the provisions of APB Opinion No. 25. Had
compensation cost been determined consistent with SFAS No. 123, the Company's
net income and earnings per share would have been reduced to the following pro
forma amounts:
December 31
-------------------------------------
2001 2000 1999
----------- ---------- ----------
Net (Loss) Income as reported $(7,613,544) $4,457,214 $3,367,032
Pro Forma
Net (Loss) Income (7,577,044) 4,314,824 2,654,911
F-16
Basic EPS as reported $ (1.67) $ 1.00 $ 0.80
Pro Forma basic EPS $ (1.63) $ .96 $ 0.63
The fair value of each option granted in 2001, 2000, and 1999 is estimated on
the date of grant using the Black-Scholes option pricing model with the
following assumptions: (a) risk free interest rates ranging from 5% to 6.4% (b)
expected volatility of 59.2% to 64.2%(c) average time to exercise of 7 years and
(d) expected dividend yield of zero.
NOTE 15 - ACQUISITIONS
In September 2001, for a value of approximately $8 million, all interests of
Omimex Resources, Inc. in the Richfield East Dome Unit, Orange County,
California, were transferred to GREKA increasing our working interest to 99% and
net revenue interest to 77% for this operated property. The value of the
acquired interest was determined by the Company's engineers based on an
acquisition price of $3.96 per BOE on total proved reserves. However, the value
of the increased interest in the Richfield East Dome Unit was reduced by $6.2
million based on an annual re-evaluation of the Company's reserves at December
31, 2001 at prevailing prices.
In June 2001, we had executed an agreement to acquire all of Vintage Petroleum,
Inc.'s oil and gas producing properties and facilities in the Santa Maria Valley
of Central California for $17.75 million in cash at closing, subject to
customary terms and conditions including consents and adjustments. The
contracted properties consist of five fields and approximately 110 producing
wells, encompassing over 5,000 acres of mineral interests and over 800 acres of
real estate. In March 2002, we announced as part of GREKA's unique business
strategy in its integrated assets that we had closed into escrow our acquisition
of these producing properties. Subject to customary terms and conditions, a
final closing out of escrow effective December 1, 2001 is scheduled to occur by
May 31, 2002. During this escrow period, Vintage has operated and will continue
to operate the properties while the crude has been and will continue to be
delivered to GREKA's asphalt refinery, that has ramped up to approximately 2,000
BBL per day as of April 1st. This acquisition will increase the current equity
throughput of 1,200 BBL per day to 3,200 BBL per day into the refinery.
NOTE 16 - DIVESTITURES
In December 2001, the Company sold its interests in the San Simon Field, Lea
County, New Mexico and other mid-continent properties for a contract price of
$2.2 million.
For approximately $10 million, the Company sold its Colombian assets in 1999
subject to a look- back provision and valuation threshold which, by the
Company's calculation, had been met. In March 2000, we exercised our option to
re-purchase the Colombian assets in exchange for payment of $12.0 million,
reassignment of certain California assets acquired from the buyer, and
adjustments for related capital expenditures. The buyer refused to close
resulting in a legal dispute. In lieu of pursuing the re-purchase of this
non-core asset, the Company chose to settle these matters with the buyer which
resulted in an additional $14 million fiscal benefit to the Company that
included $6 million cash and the California assets discussed above valued at
approximately $8 million. This settlement provided us with $24 million total
value from the final disposition of our interests in Colombia.
NOTE 17 - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Presented below is a summary of the changes in estimated domestic reserves of
the Company for the years ended December 31:
Proved developed and undeveloped reserves 2001 2000 1999
----------------------- ----------------------- -----------------------
Oil (Bbl) Gas (Mcf) Oil (Bbl) Gas (Mcf) Oil (Bbl) Gas (Mcf)
---------- ---------- ---------- ---------- ---------- ----------
Balance beginning of the year ........... 12,012,060 20,074,566 10,531,706 17,598,296 250,221 --
Production .............................. (837,664) (1,773,827) (770,007) (1,806,764) (504,961) (861,261)
Discoveries, extensions, etc. ...........
Acquisitions of reserves in place ....... -- -- -- -- 10,786,446 18,459,557
Sale of reserves in place ............... (450,292) (1,133,088) -- -- --
Revisions of previous estimates ......... (672,212) 2,213,872 2,250,361 4,283,034 -- --
---------- ---------- ---------- ---------- ---------- ----------
Balance end of the year ................. 10,051,892 19,381,523 12,012,060 20,074,566 10,531,706 17,598,296
Balance proved developed producing....... 4,310,391 2,206,108 7,059,487 5,183,649 6,469,416 3,364,401
F-17
Capitalized cost 2001 2000 1999
------------ ----------- -----------
Proven oil and gas properties (domestic) $ 46,928,312 $ 31,318,933 $ 26,909,388
Proven oil and gas properties (international) -- -- 574,769
Unproven oil and gas properties (domestic) 3,036,065 4,656,659 2,441,300
Unproven oil and gas properties (international) 4,311,048 2,862,577 302,373
------------ ------------ ------------
54,275,425 38,838,169 54,275,425
Less accumulated depletion (15,257,669) (9,970,686) (4,801,051)
------------ ------------ ------------
Net investment in oil and gas properties $ 39,017,756 $ 28,867,483 $ 25,426,779
============ ============ ============
Results of Operations 2001 2000 1999
------------ ----------- -----------
Oil and gas sales - Third party $ 14,151,828 $ 14,673,501 $ 4,384,081
Oil and gas sales - Affiliates 8,541,481 9,927,023 3,799,008
------------ ------------ ------------
Total oil and gas sales 22,693,309 24,600,524 8,183,089
Production cost 8,976,720 6,057,571 7,244,316
Depreciation, depletion and amortization 5,050,189 3,024,801 2,379,539
------------ ------------ ------------
Net income from Operations $ 8,666,400 $ 15,518,152 $ (1,440,766)
============ ============ ============
- -
SFAS No. 69, "Disclosures About Oil and Gas Producing Activities," prescribes
guidelines for computing a standardized measure of future net cash flows and
changes therein relating to estimated proved reserves. The Company has followed
these guidelines which are briefly discussed below.
-
Future cash inflows and future production and development costs are determined
by applying benchmark prices and costs, including transportation and basis =
differential, in effect at year-end to the year-end estimated quantities of oil
and gas to be produced in the future. Estimated future income taxes are computed
using current statutory income tax rates, including consideration for estimated
future statutory depletion and alternative fuels tax credits. The resulting
future net cash flows are reduced to present value amounts by applying a 10%
annual discount factor.
The assumptions used to compute the standardized measure are those prescribed by
the FASB and, as such, do not necessarily reflect the Company's expectations of
actual revenues to be derived from those reserves, nor their present worth. The
limitations inherent in the reserve quantity estimation process, as discussed
previously, are equally applicable to the standardized measure computations
since these estimates are the basis for the valuation process.
The following summary sets forth the Company's future net cash flows relating to
proved oil and gas reserves based on the standardized measure prescribed in SAFS
No. 69.
Discounted future net cash flows 2001 2000 1999
------------ ------------- -------------
Future cash flows $197,238,400 $ 421,837,100 $ 245,779,700
Future cost:
Development cost (26,749,700) (28,604,800) (24,109,700)
Production cost (85,275,400) (116,726,900) (107,662,800)
Future net cash flow before income
taxes 85,213,300 276,505,400 114,007,200
Future income taxes (18,966,265) 92,590,000 35,475,470
Future net cash flows 66,247,035 183,915,400 78,531,730
10% annual discount for future cash flows 28,595,600 74,914,260 32,276,541
Standardized measure of discounted
future cash flows, end of year(a) $ 37,651,435 $ 109,001,140 $ 46,255,189
(a) The primary difference between the standardized measure of discounted
future cash flows, end of year and the amounts per the specialist report is
solely due to corporate income taxes.
The principle sources of change in the standardized measure of discounted future
net cash flows for the years ended December 31, 2001 are as follows:
Changes in Standardized Future Cash Flows 2001 2000 1999
------------- ------------ -------------
Beginning of year $ 109,001,140 $ 46,255,189 $ 188,286
Sales of Oil and Gas, net of
production cost (14,634,393) (19,431,000) (5,205,000)
Net changes in prices and
production cost (135,620,827) 116,861,306 (106,869,100)
Changes in development cost (5,186,100) (4,495,100) (23,669,700)
Revision of previous quantity
Estimates 30,102,209 67,613,989 219,587,322
Accreciation of discount 10,900,114 4,364,766 18,800
Net change in taxes 73,623,735 (56,874,370) (35,563,340)
Net changes in production rates,
timing and other 29,669,975 (45,293,640) (2,232,079)
Standardized measure of discounted
future cash flows $ 37,651,435 $109,001,140 $ 46,255,189
NOTE 18 - CONDENSED QUARTERLY FINANCIAL DATA (UNAUDITED)
First Second Third Fourth
Quarter Quarter Quarter Quarter
2001 ----------- ----------- ----------- ------------
Sales $ 6,989,830 $11,622,892 $13,311,897 $ 8,830,663
Operating Income (loss) 1,953,687 1,932,017 1,403,027 (3,424,781)
Net Income (loss) 1,018,138 1,813,162 2,713,743 (13,122,081)
F-18
Diluted earning per
common share:
Net Income (loss) $ 0.22 $ 0.36 $ 0.57 $ (2.78)
2000
Sales $ 9,680,426 $13,699,489 $12,119,901 $ 13,567,324
Operating Income (loss) 995,941 3,741,661 3,177,516 3,283,783
Net Income (loss)(1)(2)(3) (1,121,797) 2,813,691 772,018 1,993,302
Diluted earning per
common share:
Net Income (loss)(1)(2)(3) $ (0.26) $ 0.64 $ 0.07 $ 0.47
(1) The first quarter net loss and per share data has been restated (from
previously reported results) to reflect the cumulative effect of the
change in accounting for inventory of $853,110 as of January 1, 2000.
(2) The third quarter net loss and per share data include the impact of the
loss on the sale of the Company's Canadian subsidiary of $991,439.
(3) The operating income (loss), net income (loss) and earnings (loss) per
share data for the first three quarters have been restated from
previously reported amounts to reflect certain fourth quarter adjustments
attributable to the first three quarters of 2000.
NOTE 19 - SUBSEQUENT EVENTS
In January 2002, the matter of Bank of Texas, N.A. v. Greka AM, Inc. and GREKA
Energy Corporation (Case No. 02-00771, 160th Judicial District Court of Dallas
County, Texas) commenced and the parties entered into a forbearance agreement.
(see Note 11 - Litigation)
In April 2002, we closed a $5.1 million bridge facility to provide short-term
liquidity during the implementation of GREKA's restructuring.
In April 2002, we paid in full the loan obligation in the principal amount of
$2,390,000 million to IPH, thereby releasing collateral of all issued and
outstanding shares of capital stock of a GREKA subsidiary.
In April 2002, we sold our interest in the Manila Village Field located in
Jefferson Parish, south Louisiana.
Greka Energy Corporation and subsidiaries
Schedule II - Valuation and qualifying accounts(b)
For Each of the Three Years Ended December 31, 2001
Balance at Charged to Charged to Balance
Beginning of costs and other at End of
Year Period expenses accounts Deductions Period
---- ------------ ---------- ---------- ---------- ----------
2001 $ 827,144 $ -- $ 390,886(c) $ -- $ 436,258
2000 $1,343,852 $153,457 $ 363,251 $ -- $ 827,144
1999 $ 74,000 $ -- $1,269,852(a) $ -- $1,343,852
(a) Amount represents the reserve for doubtful accounts of Saba Petroleum
Company, which was acquired on March 24, 1999.
(b) Schedule presented below represents information related to the allowance for
doubtful accounts.
(c) Write-off of individual accounts receivables.
F-19
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the
registrant has caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
GREKA ENERGY CORPORATION
Dated: May 15, 2002 By: /s/ Randeep S. Grewal
----------------------------------------
Randeep S. Grewal, Chairman of the Board
and Chief Executive Officer
In accordance with the Exchange Act, this report has been signed below
by the following persons on behalf of the registrant and in the capacities and
on the dates indicated.
Signature Title Date
/s/ Randeep S. Grewal
- ------------------------
Randeep S. Grewal Chairman of the Board of May 15, 2002
Directors and Chief
Executive Officer
(Principal Executive
Officer)
/s/ Max A. Elghandour
- ------------------------
Max A. Elghandour Chief Financial Officer May 15, 2002
and Principal Accounting
Officer)
/s/ Dr. Jan F. Holtrop
- ------------------------
Dr. Jan F. Holtrop Director May 15, 2002
/s/ George C. Andrews
- ------------------------
George C. Andrews Director May 15, 2002
/s/ Dai Vaughan
- ------------------------
Dai Vaughan Director May 15, 2002
/s/ Kenton D. Miller
- ------------------------
Kenton D. Miller Director May 15, 2002
F-20