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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, 2002
[ ] 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 2002 were $28,910,845.
The aggregate market value of 4,656,727 shares of common stock held by
non-affiliates of the issuer, based on the closing bid price of the common stock
on March 17, 2003 of $3.90 as reported on the Nasdaq National Market System and
based on a total of 4,951,451 shares being outstanding on that date, was
$19,310,659.
(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]
Check whether the issuer is an accelerated filer (as defined in Rule 126-2 of
the Act). Yes [ ] No [X]
Table of Contents
PART I ............................................................... 5
Item 1. Description of Business........................................ 5
Item 2. Description of Property........................................ 16
Item 3. Legal Proceedings.............................................. 23
Item 4. Submission of Matters to a Vote of Security Holders............ 23
PART II. ............................................................... 24
Item 5. Market for Common Equity and Related Stockholder Matters....... 24
Item 6. Selected Financial Data........................................ 25
Item 7. Management's Discussion and Analysis of Financial
Conditions and Results of Operations........................... 27
Item 7A. Quantitative and Qualitative Disclosures About Market Risk..... 31
Item 8. Financial Statements and Schedule.............................. 34
Item 9. Changes in and Disagreements With Accountants on
Accounting and Financial Disclosures........................... 34
PART III. ............................................................... 35
Item 10. Directors, Executive Officers, Promoters and Control Persons;
Compliance With Section 16(a) of the Exchange Act.............. 35
Item 11. Executive Compensation......................................... 38
Item 12. Security Ownership of Certain Beneficial Owners
and Management................................................. 40
Item 13. Certain Relationships and Related Transactions................. 42
Item 14. Controls and Procedures........................................ 42
Part IV. ............................................................... 43
Item 15. Exhibits and Reports on Form 8-K............................... 43
2
Definitions
The terms below are used in this document and have specific Securities and
Exchange Commission ("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 supplementing 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
6.0 Mcf of gas to 1 Bbl of oil, for the year ended December 31, 2002 and 5.5 Mcf
of gas to 1 Bbl of oil for the years ended December 31, 2001 and 2000.
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.
3
Cautionary Information About Forward-Looking Statements
This document contains forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933 (the "Securities Act") and Section 21E
of the Securities Exchange Act of 1934 (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
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
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.
4
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 an independent integrated energy company. Our oil and gas production,
exploration and development activities are concentrated in our properties in
California where we also own and operate an asphalt refinery. We supply our
asphalt refinery with equity oil, which is the crude oil we produce from our
surrounding heavy crude oil reserves, and we also utilize crude oil purchased
from third party producers. We believe that our vertically integrated operations
reduce our exposure to material volatile swings in crude oil prices.
Historically we have also engaged in oil and gas exploration, development and
production from our properties in Louisiana, Texas and New Mexico which
operations have substantially been sold as part of our strategic, internal
reorganization. In addition, we have interests in coalbed methane properties and
production sharing contracts in China.
We conduct our operations through two divisions:
o Integrated Operations
o International Operations
Integrated Operations. Our wholly owned and operated consolidated
assets in central California include substantial oil in place, over 1,200
wells, extensive pipeline and production facilities, and an infrastructure
including 3 work-over rigs, approximately 17,700 mineral acres,
approximately 3,300 acres of real estate, a 1-acre island connected to land
by a 2,700' causeway containing the gas and oil pipelines and facilitating
vehicular access, and an asphalt refinery.
We own and operate an asphalt refinery located in Santa Maria,
California. Crude oil that we produce from our surrounding heavy crude oil
reserves supplies feedstock to the refinery. We supplement our equity oil
production with third party feedstock to achieve efficiencies through lower
refinery operating costs of finished product per unit. Our asphalt refinery
produces 65% asphalt and 30% gas oil, with the remainder produced as
naphtha. We sell our asphalt to hot mix asphalt producers, material supply
companies and government agencies for use in road surfacing applications,
and we sell the gas oil and naphtha to end users and refineries. The
relatively stable price of asphalt and the low cost of our oil compared to
third party feedstock reduce our exposure to volatile swings in crude oil
prices and position us to effectively compete in the asphalt market.
5
During 2002, approximately 2,609 Bbls per day of our oil produced
locally were used as feedstock, accounting for approximately 91% of the
asphalt refinery throughput. Our properties also produce natural gas which
is used to fuel the field production and the refinery, in part. We operate
all of the wells associated with our Integrated Operations division.
International Operations. Other than the Fengcheng Block in which we
have a 49% operating working interest, we have a 60% operating working
interest in five coalbed methane ("CBM") exploration and development
projects within the Provinces of Jiangxi, Shanxi and Anhui, China.
As of December 31, 2002, the Company had estimated net proved reserves of
approximately 28,542 MBOE with a PV-10 value (10 year present value) before tax
of $177.6 million. During 2002, the estimated net proved reserves increased over
last year by 14,966 MBOE.
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
We intend to implement a two-pronged strategy:
Capitalize on Our California Market Position. Our asphalt refinery, prior
to 1992 was owned and operated for approximately fifty years by Conoco and ran
between 9,000 to 11,000 Bbls per day of throughput. We expect that our refinery
can attain its rated capacity of 10,000 Bbls per day of throughput. As of
December 31, 2002, we utilized approximately 30% of this rated capacity. Our
strategy in these vertically integrated assets is to enhance the long-term
equity barrel feedstock supply to the refinery and to cost-efficiently boost
production from the drilling locations identified in California. Our total
average throughput currently at the asphalt refinery is approximately 3,000 Bbls
per day, a 24% increase over 2001 levels. Approximately 90% of current
throughput is now equity barrels. In our integrated business on a recurring
basis, we are designed to be a relatively fixed cost operation with an
established infrastructure in place. Equity production and throughput at the
refinery increases ought to be realized without significant infrastructural
costs to us. In this division, we are focused on organic production growth by
returning to production the large inventory of shut-in wells acquired in recent
acquisitions.
Major oil companies, such as Union Oil Company, Shell and Texaco, began
drilling in the Santa Maria, California basin in the early 1900's and built a
consolidated infrastructure of pipelines and facilities. Thousands of wells were
drilled discovering several productive oil and gas zones between 2,500 ft. and
8,500 ft. The shallower Sisquoc zone with heavier 6-12 gravity oil was passed
over in favor of the deeper Monterey zone which was generally at a depth below
5,000 ft. and the lightest oil zone carrying the highest margins. Thus, the
majors primarily concentrated on the Monterey zone and largely ignored the
others. It is this enormous proven reserve base that provides a specific road
map for the Company to build a substantial production base. Our objectives are
to exploit through increased production both the gas reservoirs for fuel
self-sufficiency and the oil for asphalt production.
Pursue High Potential International Prospects on a Longer-Term Basis. GREKA
is party to and operator under five, 30-year production sharing contracts
("PSCs") with China United Coalbed Methane Corporation Ltd. ("CUCBM") for CBM
exploitation in China within two development and three exploration blocks. The
combined total contract area within the Jiangxi, Shanxi and Anhui Provinces is
approximately 6,600 square kilometers (1.7 million acres) with average coalbed
thickness of 16.5 feet and potential reserves of 34.5 Tcf, as estimated by
CUCBM. GREKA has a 60% working interest in all PSCs other than the Fengcheng
Block in which it has a 49% working interest. The remaining working interest is
owned by CUCBM.
6
Empowered by the State Council, CUCBM, a wholly state-owned company, is the
only company responsible for exploration, development, production and sales of
CBM in China. The signing of the four contracts brings the total number of CBM
PSCs signed by CUCBM with foreign companies to 18, five of which are with GREKA.
The total area covered by the 18 PSCs is over 31,000 sq km containing CBM
resources of approximately 3.4 trillion m3 (120 Tcf) of which GREKA's PSCs are
estimated at 30%, as estimated by CUCBM.
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.
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 increased operating cash flows, selling non-core assets in Colombia (the
"Columbian assets") while maintaining a repurchase option, acquiring all of the
shares we did not already own of Beaver Lake Resources Corporation, and signing
a production sharing contract with CUCBM to jointly exploit 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 the
Colombian assets, closed the financing with a new bank, Canadian Imperial Bank
of Commerce, 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 shares (including
over-allotment option) at a price of $13.10 per share.
During 2001, GREKA increased up to $46 million its credit facility with
GMAC Commercial Credit LLC ("GMAC") and secured financing of up to $75 million
with a new bank, Bank of Texas, N.A., closing on a revolving credit line of $16
million with an initial advance of $13.2 million. Later that year, the Company
announced a repurchase program to buy back up to 10% of its outstanding common
stock. Also in 2001, GREKA concluded the Colombian transaction resulting in its
receipt of cash and assets with an aggregate value of $14 million, and,
operationally, 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. By
the end of the year, GREKA concluded all material legal matters, including
payment of $11.5 million to RGC International Investors for settlement in full
of a court order awarding RGC $13.25 million.
7
Year 2002 Highlights
o In March 2002, the Company announced that it intended to substantially
restructure its operations by disposing of its exploration and
production assets which had been operated through its E&P Americas
subsidiary and to focus on its Integrated Operations around its
asphalt refinery located in Santa Maria, California. At the end of May
2002, we closed the sale of the most substantial portion of the E&P
Americas' assets, the Potash Field located in South Louisiana for $20
million, the proceeds of which were used to pay debt, which included
$12.5 million to the Bank of Texas, N.A. The sale of the Potash Field
essentially completed the divestiture of the Company's E&P Americas'
assets. In June 2002, we concluded a refinancing of our debt by
closing a $30 million secured credit facility through Guggenheim
Investment Management, LLC. The proceeds of this credit facility were
used to payoff the $14.3 million GMAC term loan, $12 million to
purchase of the Vintage Petroleum, Inc. ("Vintage") properties in the
Santa Maria Valley and the balance toward working capital and closing
expenses. Also in June 2002, to complete the purchase of the Santa
Maria Valley properties, we executed a promissory note for the
remaining $6 million purchase price owed to Vintage to be paid within
twelve months. In July 2002, we closed as planned our Houston office
following the E&P asset divestitures.
o As a result of the completed restructuring, substantially all of our
oil, gas and refining assets and operations are located within a 20
mile radius in the Santa Maria Valley of California. As part of our
restructuring strategy, we focused on boosting production of our heavy
crude to increase the feedstock of our equity oil for use in our Santa
Maria Refinery. The closing of the Vintage acquisition increased
equity oil production.
o In September 2002, we sold real estate for a contract price of $2.325
million, and we paid $1.1 million toward the $5.1 million bridge
facility that closed in the second quarter of 2002. The payment was
made from the sale proceeds of certain real estate owned by the
Company. Also as of September 2002, we satisfied in full our 15%
subordinated convertible debentures by converting $1.26 million in
principal plus accrued interest into 251,348 shares of GREKA common
stock and paying $0.26 million in principal plus accrued interest that
had been redeemed.
o In October 2002, the $4 million balance of the $5.1 million bridge
facility was transferred to International Publishing Holding, Inc.
("IPH"), and IPH cancelled the irrevocable standby letter of credit in
the amount of $4 million that was arranged in favor of the initial
creditor.
o Also in October 2002, we acquired Rincon Island Limited Partnership
("Rincon"), and its general partner, Windsor Energy US Corporation
("Windsor"), that owns and operates oil and gas producing properties
and facilities located within the Rincon Island Field in central
California. The properties cover approximately 1,700 mineral acres,
including a 1-acre island connected to land by a 2,700' causeway
containing the gas and oil pipelines and facilitating vehicular
access. In October 2002, of the 56 wells on the property, 12 were
producing at approximately 300 BOPD and 80 MCFD. Substantial value of
the field lies in the large, proved undeveloped portion and in the
partially exploited secondary recovery reserves of non-flooded zones
where production historically peaked at approximately 2,500 BOPD and
1.5 MMCFD. Additionally, there are 21 slots available on the island
providing the foundation for the development of the substantial
reserves.
8
o Further in October 2002, we restructured some of our debt and
increased working capital by institutionally placing $12.5 million of
secured debt, which accretes up to $14.5 million until maturity. Of
the $12.5 million proceeds, we paid off our outstanding debt to
Vintage and all but approximately $832,000 of our convertible
debentures, acquired $5.35 million worth of operational bonds related
to the acquisition of Rincon and Windsor, and applied the balance
toward working capital and closing costs.
o Lastly in October 2002, we entered into an amendment to our 30-year
production sharing contract with the CUCBM to extend for an additional
two years through December 2004 the term in which core testing is to
be conducted and the pilot program is to be developed in our Fengcheng
Coalbed Methane Exploration Prospect in Jiangxi, China.
Acquisition Activities;
California Integrated Assets
In June 2002, we closed, as scheduled, the acquisition of all of Vintage's
oil and gas producing properties and facilities in the Santa Maria Valley of
central California for $18 million. These properties, operated by the Company,
consist of five fields and approximately 110 producing wells, encompassing
approximately 8,000 acres of mineral interest and over 800 acres of real estate.
In October 2002, we acquired Rincon, and its general partner, Windsor, that
owns and operates oil and gas producing properties and facilities located within
the Rincon Island Field in central California. The properties cover
approximately 1,700 mineral acres, including a 1-acre island connected to land
by a 2,700' causeway containing the gas and oil pipelines and facilitating
vehicular access. At closing, of the 56 wells on the property, 12 were producing
at approximately 300 BOPD and 80 MCFD.
Divestiture Activities;
Non-Core Assets
In April 2002, we sold, as planned, our interest in the Manila Village
Field located in Jefferson Parish, south Louisiana for approximately $55,000.
In May 2002, we closed, as planned, the sale of our interest in the Potash
Field, Plaquemines Parish, Louisiana for a contract price of approximately $20
million.
In June 2002, we closed, as planned, the sale of our 75% exploration
interest in the Jatiluhur Block, West Java for a $4 million future production
payment upon discovery of reserves producible in commercial quantities and a
retained 5% overriding royalty interest in the Block. Pertamina, the Indonesian
state-owned oil company, consented to the sale.
In September 2002, we sold real estate for a contract price of
approximately $2.3 million.
In January 2003, we closed, as planned, the sale of our 355-acre limestone
reserve located in Monroe County, Indiana for a contract price of $0.5 million.
Financing & Debt Restructuring Activities
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 $2.4 million to IPH, thereby releasing collateral of all issued and
outstanding shares of capital stock of a GREKA subsidiary.
In May 2002, Bank of Texas, N.A. was paid $12.5 million from the proceeds
of the closed sale of our interest in the Potash Field.
9
In June 2002, we institutionally placed $30 million of a secured credit
facility to conclude the Company's debt restructuring and to close the
acquisition of the Santa Maria Valley oil and gas assets. Of these proceeds, we
paid $14.3 million to GMAC to retire its term loan and $12 million to Vintage.
Also in June 2002, we executed a promissory note for the remaining $6 million
purchase price owed to Vintage to be paid within twelve months.
In September 2002, we paid $1.1 million toward the $5.1 million bridge
facility that closed in the second quarter 2002. The payment was made from the
sale proceeds of certain real estate owned by the Company.
In October 2002, the $4 million balance of the $5.1 million bridge facility
was transferred to IPH, and IPH cancelled the irrevocable standby letter of
credit in the amount of $4 million that was arranged in favor of the initial
creditor.
Also in October 2002, we restructured some of our debt and increased
working capital by institutionally placing $12.5 million of secured debt, which
accretes up to $14.5 million until maturity. Of the $12.5 million proceeds, we
paid off our outstanding debt to Vintage and all but approximately $832,000 of
our convertible debentures, acquired $5.35 million worth of operational bonds
related to the acquisition of Rincon and Windsor, and applied the balance toward
working capital and closing costs.
In March 2003, our placed $20 million with an institutional investor
through a 2-year, secured credit facility. From these proceeds, the Company paid
$4.7 million to Bank of Texas and $4.1 million to IPH to retire their respective
loans, and the balance, in addition to closing costs and working capital, will
fund a portion of the Company's $15 million capital expenditure program for
2003. Of the $20 million, $13.5 million bears interest at a variable rate of
Libor + 6.25% or 8.25%, whichever is greater, while the balance $6.5 million
bears interest at a fixed rate of 9.25%. The Company paid a 4.25% closing fee,
and the placement resulted in an increase of approximately $10 million of the
Company's total debt.
Debentures
As of September 2002, we satisfied, in full, its 15% subordinated
convertible debentures by converting $1.26 million in principal plus accrued
interest into 251,348 shares of GREKA common stock and paying $0.26 million in
principal plus accrued interest that had been redeemed.
During 2002, GREKA converted $0.04 million in principal of its 9% senior
subordinated convertible debentures into 4,118 shares of GREKA common stock and
paid $1.74 million in principal of debentures that had been redeemed, with a
resulting debenture balance of $0.83 million in principal at December 31, 2002.
GREKA's Horizontal Drilling Technology
Horizontal drilling has become widely accepted as a standard option for
exploiting oil & gas resources. The principal 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
re-entering 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.
10
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. Four
customers exceeded individually more than 10 percent of the Company's sales of
North American refinery production during 2002, namely FAMM, Lawson, Union and
Granite which accounted for approximately 18%, 20%, 20% and 18%, respectively,
of such sales. The receivable balance as of December 31, 2002 from the same
customers amounted to $97,757, $848,237, $217,252 and $265,808, respectively.
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 60% of total refinery production in 2002, 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 can
also produce 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 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 is generally good 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.
11
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 one of GREKA's subsidiaries 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. A
portion 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 exceeded individually more than 10
percent of the Company's sales of North American oil and gas production during
2002, namely Tosco, Adams Resources and Plains Marketing, L.P. which accounted
for 51%, 12% and 15%, respectively, of such sales. Sales to Adams Resources and
Plains Marketing, L.P. were from properties subsequently sold.
The market for heavy crude oil produced by GREKA from properties in central
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 California crude oil, in addition to third party
crude oil, 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
12
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.
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 ("NGA") and the Natural
Gas Policy Act ("NGPA"), both of which are administered by the Federal Energy
Regulatory Commission ("FERC"). 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 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.
13
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, 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.
14
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.
GREKA and its subsidiaries have up to $11 million of general liability
insurance. Additionally, GREKA and its subsidiaries have up to $10 million of
environmental coverage through June 2007 covering the central California
properties acquired in June 2002. The policy protects us against third party
claims resulting from unknown pre-existing or new pollution conditions that
cause on or offsite bodily injury, property damage or clean up. The policy also
covers costs that exceed the projected costs for remediation of the known
conditions on the properties. In addition to insurance coverage, bonds in the
approximate principal amount of $6.8 million have been issued securing the
operational performance of GREKA's subsidiaries in California.
Employees
As of March 17, 2003, GREKA and its subsidiaries had 126 full-time
employees. None of GREKA's employees are subject to a collective bargaining
agreement. GREKA considers its relations with its employees to be satisfactory.
Shareholder 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% 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 the Board of
Directors for any specific year.
15
Item 2. Description of Property
The following description of the GREKA properties at December 31, 2002
includes all discussions of prior operations of all of GREKA's properties and
those of its wholly owned subsidiaries.
GREKA's Properties as of December 31, 2002
GREKA owned interests in approximately 1,200 wells at December 31, 2002.
The majority of these wells are concentrated in central California. At
December 31, 2002, California (heavy oil) was the primary and focused area of
GREKA's exploitation and development activities. GREKA's evaluation of
international exploration and exploitation project is in 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
California in the Company's recent exploitation and development activities
through its wholly owned subsidiaries:
Approximately 99% of GREKA's proved reserves at December 31, 2002 (28.2
MMBOE) were located in four regions in California. Daily production from these
regions averaged 3,300 BOE (gross) for the year ended December 31, 2002,
representing 99% of GREKA's total production. GREKA operates all of its wells in
these California regions. The remaining 1% of GREKA's proved reserves at
December 31, 2002 is allocated to domestic producing properties in which GREKA
has an interest located in four states other than California.
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 2003 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
approximately $15 million in 2003 for capital expenditure. (See Item 1 -
"Description of Business, Financing & Debt Restructuring Activities") The
Company's 2003 capex program is designed to facilitate organic production
increases from the integrated operations. Capex projects identified for 2003,
namely workovers, redrills, recompletions, side-tracks, and various facility
enhancements, are scheduled throughout the year.
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, 2002, GREKA had exploration plays in two primary areas:
California and China.
16
The following is a brief discussion of significant developments in the
Company's recent exploration activities through its wholly owned subsidiaries:
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. Since December 31, 2002,
GREKA re-evaluated the potential productive zones within the field and
identified the most prospective areas. The Company intends to reduce its acreage
in the field to these identified areas.
Coalbed Methane Exploration Prospect, Jiangxi, Shanxi and Anhui Provinces,
China. In January 2003, GREKA's wholly-owned subsidiaries signed at the Great
Hall of the People in China four Production Sharing Contracts PSCs with CUCBM
for the exploitation of CBM resources in the Shanxi and Anhui Provinces.
Considering the previously signed PSC for the Fengcheng Block in the Jiangxi
Province, GREKA is now party to and operator under five, 30-year PSCs for CBM
exploitation in China within two development and three exploration blocks. The
combined total contract area is approximately 6,600 square kilometers (1.7
million acres) with average coalbed thickness of 16.5 feet and potential
reserves of 34.5 Tcf, as estimated by CUCBM. Greka has a 60% working interest in
all PSC's other than the Fengcheng Block in which it has a 49% working interest.
The remaining working interest is owned by CUCBM.
Oil and Gas Producing Properties
The following table summarizes GREKA's estimated proved oil and gas
reserves as of December 31, 2002. The following table includes both proved
developed (producing and non-producing) and proved undeveloped reserves.
Approximately 51% 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 and/or Ryder-Scott Company Petroleum Consultants,
independent petroleum engineers, will prove accurate. Since December 31, 2002,
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 $29.39 per Bbl and
the comparable price for March 17, 2003 was $34.93. Quotations for the
comparable periods for natural gas were $4.84 per Mcf and $5.51 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 and Ryder-Scott Company
Petroleum Consultants. 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.
17
December 31, 2002
Proved Reserves, net
Gross Oil Gas PV-10 Value
Wells (MBbls) (MMcf) MBOE (000's)
----- ------- ------ ------ ------------
322 26,571 11,822 28,542 $177,584
The following is a brief discussion of our oil and gas operations in our
major fields located in California at December 31, 2002:
Central Coast Fields. One of GREKA's subsidiaries operates seven 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, Santa Maria Valley, Zaca, Clark Avenue and Los Flores which collectively
have an average working interest of 100% in 179 active wells producing 2,364
BOEPD (gross). These fields represent 38% of GREKA's total proved reserves.
North Belridge Field. The North Belridge Field is located in Kern County,
California. One of GREKA's subsidiaries 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. Production is about 300 BOEPD, and this field
represents 8% of GREKA's total proved reserves.
Rincon Field. One of GREKA's subsidiaries operates the Rincon Field which
is located in the Central Coast of California and covers approximately 1,700
mineral acres, including a 1-acre island connected to land by a 2,700' causeway
containing the gas and oil pipelines and facilitating vehicular access. GREKA
has a 100% working interest in 16 active wells producing approximately 371
BOEPD. This field represents 40% of the Company's total reserve value.
Richfield East Dome Unit. The Richfield East Dome Unit is a mature
waterflood (one method of secondary recovery in which water is injected into an
oil reservoir for the purpose of washing the oil out of the reservoir rock into
the bore of a producing well) in Orange County, California, operated by one of
GREKA's subsidiaries and producing approximately 615 BOPD from 94 active wells.
The field in which GREKA's working interest is 99%, represents 12% of the
Company's total reserve value. 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.
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 2000, 2001 and 2002,
Netherland, Sewell & Associates, Inc. prepared reports on GREKA's reserves in
the United States (except in the Rincon Field, California), and in 2002
Ryder-Scott Company Petroleum Consultants prepared reports on GREKA's reserves
in the Rincon Field, California. 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 year end 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, 2002 reflect weighted
average prices of $23.07 per BOE compared to $14.53 per BOE and $26.93 per BOE
as of December 31, 2001 and 2000, respectively.
18
The following tables present total estimated proved developed producing,
proved developed non-producing and proved undeveloped reserve volumes as of
December 31, 2000, 2001 and 2002 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 2002 year end
engineering estimates.
Estimated Proved Oil and Gas Reserves
At December 31,
---------------------------
2000(1) 2001(1) 2002
------- ------- -------
Net oil reserves (MBbl)
Proved developed producing .............. 7,059 4,310 11,672
Proved developed non-producing .......... 1,309 2,664 1,839
Proved undeveloped ...................... 3,644 3,078 13,060
------ ------ ------
Total proved oil reserves (MBbl) ....... 12,012 10,052 26,571
====== ====== ======
Net natural gas reserves (MMcf)
Proved developed producing .............. 5,184 2,206 1,929
Proved developed non-producing .......... 4,758 5,822 453
Proved undeveloped ...................... 10,133 11,354 9,440
------ ------ ------
Total proved natural gas
reserves (MMcf) ..................... 20,075 19,382 11,822
====== ====== ======
Total proved reserves (MBOE) ............... 15,662 13,576 28,542
====== ====== ======
- ----------
(1) Does 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
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.
19
Estimated Present Value of
Future Net Revenue
(In thousands)
At December 31,
------------------------------
2000(1) 2001(1) 2002
-------- -------- --------
PV-10 Value
Proved developed producing .......... $ 67,080 $15,180 $60,022
Proved developed non-producing ...... 37,160 21,164 13,615
Proved undeveloped .................. 59,637 20,274 103,947
-------- -------- --------
Total ............................ $163,877 $56,618 $177,584
======== ======== ========
- ----------
(1) Does include value 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, 2002.
Year Ended December 31,
--------------------------
2000(1) 2001(1) 2002
------- ------- ------
Production Data:
Oil (MBbls) .................... 770 827 1,021
Gas (MMcf) ..................... 1,807 1,848 371
Total (MBOE) ................. 1,099 1,163 1,083
Average Sales
Price Data
(Per Unit):
BOE ............................ $22.14 $19.51 $21.89
Selected Data
per BOE:
Production costs(2) ............ $ 5.51 $ 7.87 $ 4.90
General and
administrative ............... $ 5.79 $ 3.22 $ 3.43
Depletion,
depreciation and
amortization ................. $ 2.90 $ 4.34 $ 3.12
- ----------
(1) Does include sales volumes attributable to the Company's interest in assets
subsequently divested.
(2) Production costs include production taxes.
20
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, 2002, there has been no drilling activity except as set forth in
the following table:
Year Ended December 31,
---------------------------------------------------------
2000 2001 2002
----------------- ----------------- -----------------
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, 2002, 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 in the United States:
Oil Gas Total
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- -----
2002 280 272 42 39 322 311
2001 498 450 25 9 523 459
2000 625 487 80 41 705 528
Oil and Gas Acreage
The following table sets forth certain information at December 31, 2002
relating to oil and gas acreage in the United States in which GREKA through its
subsidiaries owned a working interest:
Developed(1) Undeveloped
--------------- --------------
Gross Net Gross Net
----- --- ----- ---
2002 13,693 10,515 11,201 8,025
2001 21,070 16,180 11,201 8,025
2000 21,070 16,180 11,201 8,025
- ----------
(1) Developed acreage is acreage assigned to productive wells.
21
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 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,
------------------------
2000 2001 2002
------ ------ ------
Average sales price per BOE $22.14 $19.51 $21.89
Average production cost per BOE $ 5.51 $ 7.87 $ 4.90
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 17 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 California and
plan to continue this practice. At December 31, 2002, the Company owned through
its subsidiaries approximately 3,300 acres in Santa Barbara County, California.
GREKA has used a portion of its real estate holdings for leased agricultural
purposes. GREKA plans to retain some of these real estate holdings for asset
appreciation which may include developmental activities at a future date.
22
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 other offices are located in Santa Maria,
California; and Beijing, China. In July 2002, due to the planned divestiture of
related assets, GREKA closed its Houston, Texas 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). In March 2003, the parties entered into a Settlement Agreement and Full
Release resolving all outstanding issues. The settlement agreement provided full
release of the Company upon repayment of the outstanding balance, which occurred
in March 2003.
People of State of California, et al. v. Greka SMV, Inc. (Case No. 1114292,
Superior Court of State of California, County of Santa Barbara, Santa Maria
Division, December 2002). Plaintiffs brought an action against GREKA's
subsidiary seeking damages of approximately $1 million for alleged statutory
violations relating to a fire caused by a third party, that, ignoring GREKA's
instructions, entered GREKA's operations which were being conducted in
accordance with common industry practice. GREKA has submitted this matter as an
insurance claim, and plans to vigorously defend all claims asserted. The
litigation is in its preliminary, pre-discovery stage.
Union Oil Company of California, dba Unocal v. GREKA, et al. (Case No.
1125964, Superior Court of State of California, County of Santa Barbara, Santa
Maria Division, December 2002). Plaintiff brought an action against GREKA and
its subsidiaries seeking damages of approximately $6.25 million for alleged
breach of contract claiming that, as successor-in-interest to Saba under the
terms of the contract, the Company failed to abandon a certain number of wells
or provide an acceptable abandonment plan, and failed to have in place
instruments securing the abandonment. GREKA plans to vigorously defend all
claims asserted. The litigation is in its preliminary, pre-discovery stage.
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 5, 2002, the
following individuals were elected to the Board of Directors to serve for a
3-year term ending 2005 as Class C directors:
Votes For Votes Withheld
--------- --------------
Dai Vaughan 3,805,812 320,312
Kenton D. Miller 3,809,717 316,407
23
PART II
Item 5. Market for Common Equity and Related Stockholder Matters
Our common stock is listed for trading on the Nasdaq National Market
("NASDAQ") 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, 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
June 30, 2002 4.580 7.330
September 30, 2002 4.750 6.290
December 31, 2002 3.760 6.120
On March 17, 2003 there were approximately 888 registered holders of
GREKA's common stock. Based on a broker count, GREKA believes at least an
additional 3,700 persons are shareholders with street name positions.
Holders of GREKA common stock are entitled to receive such dividends as may
be declared by GREKA's 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. 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 April 2002, the Company granted to IPH the right and option to purchase
up to 400,000 shares of common stock of the Company at an exercise price of
$6.00 per share for the first 200,000 shares and at an exercise price of $6.50
per share for the remaining 200,000 shares. The options were granted in
consideration of IPH arranging for an irrevocable standby letter of credit
having a term expiring on September 29, 2003 and in the amount of $4 million in
favor of the Company's creditor that loaned $5.1 million to the Company as a
bridge facility. Such options shall be exercisable during a period of five days
from the date that IPH receives written notice from the Company that the letter
of credit has been surrendered in connection with the loan repayment, expired,
or tendered to the bank in connection with a draw thereunder. These options are
exempt from registration pursuant to Section 4(2) of the Securities Act.
In October 2002 and in consideration of the transfer to IPH of the $4
million balance of the $5.1 million bridge facility, we amended and restated our
grant to IPH of its right and option to purchase up to 400,000 shares of common
stock of the Company at an exercise price of $6.00 per share for the first
200,000 shares and $6.50 per share for the remaining 200,000 shares. Such
options shall be exercisable beginning on the earlier of March 31, 2003 or
changes in capitalization of the Company and ending on the later of September
30, 2003 or fifteen days after the full repayment of the loan. These options are
exempt from registration pursuant to Section 4(2) of the Securities Act.
24
In June 2002 and in consideration of the $30 million of secured debt
institutionally placed, the Company granted to the note holders and the
collateral agent warrants to purchase up to an aggregate 150,000 shares of
common stock of the Company at an exercise price of $0.01 per share and expiring
in ten years.
In October 2002 and in consideration of the $12.5 million of secured debt
institutionally placed, which accretes up to $14.5 million until maturity, the
Company granted to the collateral agent warrants to purchase up to an aggregate
of 80,000 shares of common stock of the Company at an exercise price of $0.01
per share and expiring in ten years.
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, 2002, 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.
25
Years Ended December 31,
-----------------------------------------------------------
2002 2001 2000 1999 1998
-------- -------- -------- -------- -------
(In thousands, except per share data)
Statement of Operations:
Revenues ....................................... $ 28,911(1) $ 40,755 $ 49,067(2) $ 29,138(3) $ 146
Production and product costs ................... $ 16,258(1) $ 24,782 $ 25,200(2) $ 17,821(3) $ 121
Sales, general and administration expenses ..... $ 9,183 $ 8,274 $ 7,195 $ 3,205 $ 1,542
Depletion, depreciation &
amortization ................................. $ 3,245 $ 5,579 $ 3,592 $ 3,024 $ 333
Impairment of Long-lived Assets............ .... $ 5,961 $ -- $ 1,882 $ -- $ 3,171
Gain on sale of properties $ 3,960 $ -- $ -- $ -- $ --
Interest Expense, net .......................... $ 9,424 $ 4,157 $ 4,535 $ 1,860 $ (51)
Other Income (Expenses), net ................... $ 1,151 $ (5,540)(4) $ - $ 733 $ 9
Minority Interest .............................. $ -- $ -- $ -- $ 21 $ --
(Benefit) Provision for Income taxes ........... $ (33) $ (37) $ 362 $ 46 $ --
Equity in Loss of Saba.......................... $ -- $ -- $ -- $ 569 $ 586
Cumulative effect of change in accounting
principle $ -- $ -- $ 853 $ -- $ --
Net (loss) income ............................. $(10,083) $ (7,614) $ 4,457 $ 3,367 $(5,548)
(Loss) income per common share:
Basic net (loss) income per share .............. $ (2.11) $ (1.67) $ 1.00 $ 0.80 $ (3.25)
Diluted net (loss) income per share . . . . . . $ (2.11) $ (1.67) $ .99 $ .75 $ (3.25)
Cash dividend per share ........................ $ -- $ -- $ -- $ -- $ --
Basic weighted average common
shares outstanding ........................... 4,768 4,555 4,476 4,203 1,703
Diluted weighted average common
shares outstanding ........................... 4,768 4,555 4,763 4,801 1,703
Balance Sheet Data (end of period):
Working Capital (deficit).......... ............ $(14,929) $(50,355)(5) $ (2,664) $(14,176) $(1,828)
Net property and equipment ..................... $ 78,869 $ 89,465 $ 77,182 $ 70,287 $ 4,426
Total assets ................................... $ 97,589 $100,049 $ 98,813 $ 84,214 $20,807
Long-term obligations .......................... $ 47,665 $ 9,139 $ 28,207 $ 15,696 $ 53
Total stockholders' equity ..................... $ 26,051 $ 33,166 $ 40,211 $ 33,378 $18,505
(1) Revenues and production and products costs are affected by the sale of
certain exploration and production assets in 2002.
(2) Revenues and production and products costs are affected by the full
consolidation of the subsidiary engaged in the refinery operations
effective May 1999.
(3) Revenues and production and products costs are affected by the acquisition
of SABA in early 1999.
(4) Other expense reflects costs incurred in connection with settlement of
litigation.
(5) Includes reclassification of long-term debt to current due to a technical
default.
26
Item 7. Management's Discussion and Analysis of Financial Conditions and Results
of Operations
Overview
GREKA is an independent integrated energy company. Our oil and gas
production, exploration and development activities are concentrated in our
properties in California where we also own and operate an asphalt refinery. We
supply our asphalt refinery with equity oil, which is the crude oil we produce
from our surrounding heavy crude oil reserves, and we also utilize crude oil
purchased from third party producers. We believe that our vertically integrated
operations reduce our exposure to material volatile swings in crude oil prices.
Historically we have also engaged in oil and gas exploration, development and
production from our properties in Louisiana, Texas and New Mexico which
operation has substantially been sold as part of our strategic, internal
reorganization. In addition, we have interests in coalbed methane properties and
production sharing contracts in China.
Results of Operations
Comparison of Years Ended December 31, 2002 and 2001
Revenue decreased from $40,755,282 for 2001 to $28,910,845 for 2002. This
29% decrease is the net effect of a decrease in revenue from our upstream
activities by 59% from $14,151,828 in 2001 to $5,846,409 in 2002 resulting from
the effects of the Company's restructuring plan and sale of its interests in the
Potash Field, Manila Village and other oil and gas properties, in addition to a
decrease of 10% in revenue from our downstream activities (asphalt sales) from
$25,255,580 in 2001 to $22,751,809 in 2002. The decrease is the total effect of
a 6% volume decrease from 998,640 Bbls in 2001 to 939,301 Bbls in 2002 or
$1,500,683. Coupled with a 4% price decrease in the weighted average selling
price per barrel of asphalt products from $25.29 in 2001 to $24.22 in 2002 or
$1,003,088, this was also compounded by a decrease in other income from the farm
operation and other sources by $1,035,248, from $1,347,874 in 2001 to $312,626
in 2002.
Production and product costs decreased from $24,781,938 for 2001 to $16,258,337
for 2002. This 34% decrease consists of a 57% decrease in production costs from
upstream activities from $5,219,044 in 2001 to $2,254,536 in 2002 due to the
effect of the Company's restructuring plan, coupled with a 28% decrease in
production costs from downstream activities from $19,562,894 in 2001 to
$14,003,800 in 2002. The decrease of $5,559,094 is the aggregate effect of 6%
decrease in volume or a reduction of production costs of $1,162,421 coupled with
a 24% decrease in cost per barrel from $19.59 to $14.91, or a further reduction
of $4,396,673. The decrease in the cost per barrel is due to a 24% increase of
the average daily throughput from 2,369 Bbls in 2001 to 2,944 Bbls in 2002
coupled with a material decrease in the percentage of daily average throughput
from third party crude (feedstock) from 47% or 1,277 Bbls in 2001 to 8% or 250
Bbls in 2002. The decrease in purchases of third party crude is due to the
acquisition of properties, which increased contribution to feedstock from equity
crude by approximately 1,500 Bbls per day from approximately 1,000 to 2,500 Bbls
per day.
Sales, general and administration expenses increased by 11% from $8,274,183
for 2001 to $9,182,828 for 2002. The increase is primarily due to incremental
freight cost associated with shipment of distillates to customers, audit fees
and acquisition-related expenses.
Depreciation, depletion and amortization decreased significantly from
$5,578,899 for 2001 to $3,244,847 for 2002. This decrease of 42% is the result
of lower depletion rate for 2002 of $3.12 per barrel compared to $4.48 per
barrel for 2001 coupled with a 23% decrease in volume of production from a
weighted daily average of 3,179 BOE in 2001 to 2,441 BOE for 2002. The lower
depletion rate resulted from 110% increase in the reserves from 13,576 MBOE for
2001 to 28,542 MBOE for 2002. This, however, was mitigated by a 52% increase in
the related total oil and gas properties asset base from $60.7 million for 2001
to $91.8 million for 2002.
27
The Company reported an operating loss of $1,776,608 for 2002 compared to
an operating income of $ 2,120,262 for 2001. This 184% decrease is due to: i)
impairment of long-lived assets covering Indonesia and the limestone properties
for an amount of $5,961,187, which was partly offset by a gain on the sale of
real estates in California in the amount of $3,959,746 and, ii) a decrease in
operating income of $1,895,429 primarily deriving from a decrease in oil and gas
revenues due the sale of certain oil and gas properties in 2002.
Interest expense increased from $4,157,110 for 2001 to $9,423,521 for 2002
as a result of an increase in the interest bearing loans outstanding from a
weighted average of approximately $40 million in 2001 to $51 million in 2002
coupled with an increase in the weighted average interest rate from 10% to 18%.
Other income and expenses for 2002 of $1,150,729 is primarily the net write
off of capitalized financing costs of approximately $1.4 million relating to the
payoff of the GMAC and bridge loans offset by write off of stale liabilities and
non-recurring charges of approximately $1 million in addition to non-operating
income realized from the sale of emission credits of $0.6 million.
Net loss increased from $7,613,544 for 2001 to $10,082,509 for 2002 due to
impairments of long-lived assets coupled with an increase in the cost of capital
in addition to charges relating to issued warrants and options associated with
financing activities in 2002 (see Item 5 - "Market for Common Equity and Related
Stockholder Matters"). This, however, was somewhat mitigated by gains realized
from sale of various real estate, discussed above.
Capital expenditures increased 18% or $3,126,698 from $17,170,957 for 2001
to $20,297,655 for 2002. Capital expenditures were utilized primarily for the
acquisition of oil and gas properties, as well as for drilling activities in oil
and gas producing properties in California.
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% from 1,080,604 barrels in 2000 to 998,640 barrels in 2001, and 15% lower
average sales prices of refined products from $29.26 in 2000 to $24.87 in 2001
at our integrated operations.
Production and product costs decreased by 2% or $417,682 from $25,199,620
in 2000 to $24,781,938 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.
Sales, general and administration expenses increased by 15% or $1,079,662
from $7,194,521 for 2000 to $8,274,183 in 2001 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 administration expenses
and depreciation, depletion and amortization expenses.
Depreciation, depletion and amortization increased 55% or $1,986,657
primarily as a result of an 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.
28
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 a net income of
$4,457,214 for 2000 to a net loss of $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 in
expenses, or $3,758,900 consisting mainly of non-recurring charges resulting
from settlement of material litigation and post-acquisition adjustments.
Capital expenditures increased 26% or $3,569,438 from $13,601,519 in 2000
to $17,170,957 in 2001. Capital expenditures were utilized primarily for
drilling activities in E&P Americas.
Cash Flows
Cash provided by or used in operations decreased from an inflow of
$5,317,847 for 2001 to an outflow of $14,582,896 for 2002. Net loss for the
period ended December 31, 2002 contributed to $10,082,509 of cash outflow.
The Company's net cash flows provided from investing activities increased
from net outflows of $16,030,140 for 2001 to a net inflow of $4,294,959 for
2002. The change is the net of cash inflows from the sale of our interests in
the Potash Field, Yorba Linda and other real estate properties offset by the
acquisition cost of the Vintage properties and current year capital
expenditures.
The Company's net cash provided by financing activities increased by 79% or
$4,940,517 from $6,296,697 for 2001 compared to net cash provided by financing
activities of $11,227,214 for 2002. The increase of $4,940,517 is primarily a
result of the Company's net proceeds from notes payable issued.
Liquidity and Capital Resources
The working capital deficit at December 31, 2002 of $14,928,691 decreased
by $35,426,625 from a working capital deficit of $50,355,316 at December 31,
2001. Current assets increased by $453,039 from $7,389,081 at December 31, 2001
to $7,842,120 at December 31, 2002 which includes an increase of $939,277 in
cash and cash equivalents from $422,103 at December 31, 2001 to $1,361,380 at
December 31, 2002. The increase in the cash balance, as well as current assets
is due primarily to the effect of the sale of non-core assets that had been
earmarked for divestiture in accordance with the Company's restructuring plan
announced in March 2002, Other changes include an increase in receivables and a
decrease in inventories from $3,618,368 and $1,796,520 respectively at December
31, 2001 to $3,760,613 and $1,363,506, respectively, at December 31, 2002. Other
changes included a decrease in other current assets of $655,469 from $1,552,090
at December 31, 2001 to $896,621 at December 31, 2002 mostly as a result of
payment of notes receivables from both a third party and a related party.
Current liabilities decreased $34,973,586 from $57,744,397 at December 31, 2001
to $22,770,811 at December 31, 2002 as a result of payment of loans to the Bank
of Texas ($12,400,000) and to GMAC ($5,000,000 current portion) in addition to a
decrease in accounts payable and accrued expenses of $10,653,457 from
$23,751,354 at December 31 2001 to $13,097,897 at December 31, 2002 as a result
of management's concerted effort to reduce aged outstanding liabilities.
Although the Company decreased its working capital deficit by $35,426,625 from
December 2001, the Company did continue to experience certain liquidity issues.
However, as discussed in Item 1 - "Financing & Debt Restructuring Activities",
the Company placed $20 million with an institutional investor through a 2-year
secured credit facility.
29
In March 2003, the Company amended, with certain retrospective effects, the
terms of its loan agreement, and it borrowed additional $20 million through its
collateral agent by issuing 2-years promissory notes. From these proceeds, the
Company paid $4.7 million to Bank of Texas and $4.1 million to IPH to retire
their respective loans, and the balance, in addition to closing costs and
working capital, will fund a portion of the Company's $15 million capital
expenditure program for 2003. Of the $20 million, $13.5 million bears interest
at a variable rate of Libor + 6.25% or 8.25%, whichever is greater, while the
balance $6.5 million bears interest at a fixed rate of 9.25%. The Company paid a
4.25% closing fee, and the placement resulted in increase by approximately $10
million to the Company's total debt. See Note 9,(d)to the consolidated financial
statements.
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 organic production increases that are
strategic and in accordance with our business plan. Historically, GREKA has
relied on cash flow from operations to finance operational capitalized
expenditures. In 2002, GREKA had expended $20,297,655 for its capitalized
expenditures. For 2003, GREKA has budgeted $15 million for its discretionary
capitalized expenditures. 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:
. We have embarked on a complete restructuring of all our long-term and
maturing debt. The debt restructuring scheduled during the second
quarter is intended to payoff all remaining aged trade debt, provide
availability for continued development within the Integrated
Operations' business plan, continued development of our interests in
China, and working capital.
. Utilize cash on hand to implement an aggressive drilling program in
the second and third quarters of 2003.
. 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.
. Continue to acquire assets to enhance the benefit of integrated
operations that collectively provide for low cost operating expenses
and high cash flow.
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.
30
Total
Amounts Less than
Contractual Obligations Committed 1 Year 1-2 Years 3-4 Years Thereafter
- ----------------------- --------- ------ --------- --------- ----------
(Thousands of Dollars)
Debt $ 57,930 $ 9,673 $ 48,257 -- $ --
Operating Leases 355 216 137 2 --
-------------------------------------------------------------
Total Contractual Cash Obligations $ 58,285 $ 9,889 $ 48,394 $ 2 $ --
=============================================================
In March 2003, the Company borrowed an additional $20 million, by issuing 2-year
promissory notes. Out of the total proceeds of $ 20 million, $8.8 million was
used to repay the current portion of long-term debt (Bank of Texas and IPH),
with the remaining balance to be used to fund a portion of the Company's 2003
capital expenditures and for working capital requirements.
The Company's continuation as a going concern is dependent upon its ability to
successfully establish the necessary financing arrangements and implement our
strategies consistent with its restructuring plans and successful 2003 capital
expenditure program.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
To some extent, at December 31, 2002, 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 $3.3 million outstanding under its
Revolving credit agreement. Changes in the interest rate on such debt are deemed
not be material to the financial position of the Company. In addition, the
Company issued $25 million in senior notes and $5 million in senior subordinated
notes with an initial interest of 15% and 21% per year, respectively. The
interest rates payable are adjusted downward based on the Company achieving
certain financial targets and could result in a minimum interest of 11% and 17%
for the senior and subordinated notes, respectively. The Company did not achieve
these targets as of December 31, 2002.
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.
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 four customers
accounted for more than 10% each of the Company's sales, these customers are not
currently considered 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.
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Critical Accounting Policies and Use of Estimates
Use of Estimates. The preparation of the consolidated financial statements
in conformity with accounting principles generally accepted in the United States
of America 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 estimates involves the assessment of the amount of proved natural
gas and oil reserves and the estimate of future development and plug and
abandonment costs. Actual results could differ from those estimates.
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. 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 cost ceiling test limitation. See Note 13 to the
consolidated financial statements, "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 method
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.
Recent Accounting Pronouncements
A summary of the recent accounting pronouncements, issued by the Financial
Accounting Standards Board ("FASB"),that may affect the Company are presented
below.
The Statement of Financial Accounting Standards ("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 consolidated
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 became effective on 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
32
amount, a gain or loss is recognized. Currently, the Company includes estimated
future costs of abandonment and dismantlement in its full cost amortization base
and amortizes these costs as a component of its depletion expense. The Company
is continuing to revise its calculation of the impact the new standard will have
on the consolidated financial statements and the Company does not believe there
will be a material impact to the consolidated financial statements.
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets,"
became effective on January 1, 2002, and addresses accounting and reporting for
the impairment or disposal of long-lived assets. SFAS No. 144 supercedes SFAS
No. 121, "Accounting for the Impairment of Long-Lived Assets and for the
Long-Lived Assets to Be Disposed Of" and Accounting Principles Board ("ABP")
Opinion No. 30, "Reporting the Results of Operations-Reporting the Effects of
Disposal of Segment of a Business and Extraordinary, Unusual and Infrequently
Occurring Events and Transactions." 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. The standard had no impact
on the consolidated financial statements for the year ended December 31, 2002.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No.
4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections."
SFAS No. 145 rescinds the provisions of SFAS No. 4 that require companies to
classify certain gains and losses from debt extinguishments as extraordinar