Back to GetFilings.com
U.S. Securities and Exchange Commission
Washington, D.C. 20549
Form 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 For the fiscal year ended December 31, 2001
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 For the transition period from to
----------- ------------
Commission File No.: 0-20760
GREKA Energy Corporation
----------------------------------------------
(Name of issuer in its charter)
Colorado 84-1091986
------------------------------ ----------------------
(State or other jurisdiction (I.R.S. Employer
incorporation or organization) Identification Number)
630 Fifth Avenue, Suite 1501 New York, NY 10111
- ----------------------------------------- ----------
(Address of principal executive offices) (Zip Code)
Issuer's telephone number: (212) 218-4680
Securities registered under Section 12(b) of the Exchange Act:
None
Securities registered under Section 12(g) of the Exchange Act:
No Par Value Common Stock.
Check whether the issuer (1) filed all reports required to be filed by Section
13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter
period that the registrant was required to file such reports) and (2) has been
subject to such filing requirements for the past 90 days. Yes [X] No [ ]
Check if there is no disclosure of delinquent filers in response to Item 405 of
Regulation S-B contained in this form, and no disclosure will be contained, to
the best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
The issuer's revenues for 2001 were $40,755,282.
The aggregate market value of 4,391,644 shares of common stock held by
non-affiliates of the issuer, based on the closing bid price of the common stock
on April 30, 2002 of $6.11 as reported on the Nasdaq National Market System and
based on a total of 4,698,368 shares being outstanding on that date, was
$26,832,945.
(ISSUERS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PAST FIVE YEARS)
Check whether the issuer has filed all documents and reports required to be
filed by Section 12, 13 or 15(d) of the Exchange Act after the distribution of
securities under a plan confirmed by a court. Yes [X] No [ ]
Transitional Small Business Disclosure Format (check one).
Yes [ ] No [X]
Table of Contents
PART I ............................................................... 5
Item 1. Description of Business........................................ 5
Item 2. Description of Property........................................ 13
Item 3. Legal Proceedings.............................................. 22
Item 4. Submission of Matters to a Vote of Security Holders............ 22
PART II. ............................................................... 23
Item 5. Market for Common Equity and Related Stockholder Matters....... 23
Item 6. Selected Financial Data........................................ 23
Item 7. Management's Discussion and Analysis of Financial
Conditions and Results of Operation............................ 24
Item 7A. Quantitative and Qualitative Disclosures About Market Risk..... 27
Item 8. Financial Statements........................................... 28
Item 9. Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure............................ 28
PART III. ............................................................... 29
Item 10. Directors, Executive Officers, Promoters and Control Persons;
Compliance With Section 16(a) of the Exchange Act.............. 29
Item 11. Executive Compensation......................................... 31
Item 12. Security Ownership of Certain Beneficial Owners
and Management................................................. 34
Item 13. Certain Relationships and Related Transactions................. 35
Part IV. ............................................................... 36
Item 14. Exhibits and Reports on Form 8-K............................... 36
Definitions
The terms below are used in this document and have specific SEC
definitions as follows:
Proved oil and gas reserves. Proved oil and gas reserves are the
estimated quantities of crude oil and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate is made. Prices
include consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions.
Proved developed oil and gas reserves. Proved developed oil and gas
reserves are reserves that can be expected to be recovered through existing
wells with existing equipment and operating methods. Additional oil and gas
expected to be obtained through the application of fluid injection or other
improved recovery techniques for implementing the natural forces and mechanisms
of primary recovery is included as "proved developed reserves" only after
testing by a pilot project or after the operation of an installed program has
confirmed through production response that increased recovery will be achieved.
Proved undeveloped reserves. Proved undeveloped oil and gas reserves
are reserves that are expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major expenditure is required
for recompletion. Reserves on undrilled acreage is limited to those drilling
units offsetting productive units that are reasonably certain of production when
drilled. Proved reserves for other undrilled units is claimed only where it can
be demonstrated with certainty that there is continuity of production from the
existing productive formation. Under no circumstances are estimates for proved
undeveloped reserves attributable to any acreage for which an application of
fluid injection or other improved recovery technique is contemplated, unless
such techniques have been proved effective by actual tests in the area and in
the same reservoir.
As used in this Form 10-K:
"Mcf" means thousand cubic feet, "MMcf" means million cubic feet,
"Bcf" means billion cubic feet, "Tcf" means trillion cubic feet, "Bbl" means
barrel, "MBbls" means thousand barrels, "MMBbls" means million barrels, "BOE"
means equivalent barrels of oil, "MBOE" means thousand equivalent barrels of oil
and "MMBOE" means million equivalent barrels of oil.
Unless otherwise indicated in this Form 10-K, gas volumes are stated
at the legal pressure base of the state or area in which the reserves are
located and at 60/o/ Fahrenheit. Equivalent barrels of oil are determined using
the ratio of 5.5 Mcf of gas to 1 Bbl of oil.
The term "gross" refers to the total acres or wells in which the
Company has a working interest, and "net" refers to gross acres or wells
multiplied by the percentage working interest owned by the Company. "Net
production" means production that is owned by the Company less royalties and
production due others.
Cautionary Information About Forward-Looking Statements
This document contains forward-looking statements within the meaning
of Section 27A of the Securities Act and Section 21E of the Exchange Act. All
statements, other than statements of historical facts, included in or
incorporated by reference into this Form 10-K which address activities, events
or developments which the Company expects, believes or anticipates will or may
occur in the future are forward-looking statements. The words "believes,"
"intends," "expects," "anticipates," "projects," "estimates," "predicts" and
similar expressions are also intended to identify forward-looking statements.
These forward-looking statements include, among others, statements concerning:
... the benefits expected to result from GREKA's 1999 acquisition of Saba
Petroleum Company ("Saba") discussed below, including
... synergies in the form of increased revenues,
... decreased expenses and avoided expenses and expenditures that are expected
3
to be realized as a result of the Saba acquisition, and
... the complementary nature of GREKA's horizontal drilling technology and
certain oil reserves acquired with the acquisition of Saba, and other
statements of:
... expectations,
... anticipations,
... beliefs,
... estimations,
... projections, and
other similar matters that are not historical facts, including such matters as:
... future capital,
... development and exploration expenditures (including the timing, amount and
nature thereof),
... drilling and reworking of wells, reserve estimates (including estimates of
future net revenues associated with such reserves and the present value of
such future net revenues),
... future production of oil and gas,
... repayment of debt,
... business strategies,
... oil, gas and asphalt prices and demand,
... exploitation and exploration prospects,
... expansion and other development trends of the oil and gas industry, and
... expansion and growth of business operations.
These statements are based on certain assumptions and analyses made by
the management of GREKA in light of its experience and its perception of
historical trends, current conditions and expected future developments as well
as other factors it believes are appropriate in the circumstances.
GREKA cautions the reader that these forward-looking statements are
subject to risks and uncertainties, including those associated with:
... our ability to refinance our debt on favorable terms,
... our ability to successfully restructure our operations,
... the financial environment,
... general economic, market and business conditions,
... the regulatory environment,
... business opportunities that may be presented to and pursued by GREKA,
... changes in laws or regulations
... exploitation and exploration successes,
... availability to obtain additional financing on favorable conditions,
... trend projections, and
... other factors, many of which are beyond GREKA's control that could cause
actual events or results to differ materially from those expressed or
implied by the statements. Such risks and uncertainties include those risks
4
and uncertainties identified in the Description of the Business and
Management's Discussion and Analysis sections of this document and risk
factors discussed from time to time in the Company's filings with the
Securities and Exchange Commission.
Significant factors that could prevent GREKA from achieving its stated
goals include:
... the inability of GREKA to obtain financing for capital expenditures and
acquisitions,
... declines in the market prices for oil, gas and asphalt, and
... adverse changes in the regulatory environment affecting GREKA.
The cautionary statements contained or referred to in this document
should be considered in connection with any subsequent written or oral
forward-looking statements that may be issued by GREKA or persons acting on its
or their behalf.
GREKA undertakes no obligation to release publicly any revisions to
any forward-looking statements to reflect events or circumstances after the date
hereof or to reflect the occurrence of unanticipated events.
PART I
Item 1. Description of Business
Overview of GREKA Energy Corporation
GREKA Energy Corporation, a Colorado corporation ("GREKA" or the
"Company") is a vertically-integrated energy company with primary areas of
activities in California and long-term in China. The Company is committed to
creating shareholder value by principally focusing on exploiting the high cash
margin created from the relatively stable natural hedge by its crude production
and the asphalt market in Central California. GREKA's operations are primarily
conducted through our wholly owned subsidiaries established as business segments
to allow for concentrated operations by region and/or markets. (Refer to
financial statements NOTE 1 - Description of Business)
As of December 31, 2001, the Company had estimated net proved reserves
of approximately 13,576 MBOE with a PV-10 value before tax of $56.6 million.
During 2001, the estimated net proved reserves have been lowered by 2,086 MBOE.
During 2001, the throughput at the Company's asphalt refinery averaged
approximately 2,370 BBL per day with the Company's present goal of reaching
efficient plant capacity of 7,500 BBL per day by year-end 2003. Of this
throughput, the Company's subsidiaries supplied an average of approximately 46%,
or 1,090 BBL per day, from their production in California, and we plan to focus
on increasing our feedstock during 2002. Also in 2001, we reported exploration
success at the Potash Field, Plaquemines Parish, Louisiana with our drilling of
the HD No. 1 well with initial production at over 6 MMCF per day and current
production at 510 BOEPD (or 60 BOPD and 2.7 MMCFD) per day.
Our principal offices are located at 630 Fifth Avenue, Suite 1501, New
York, New York 10111 and our telephone number is (212) 218-4680.
Business Strategy
In March 2002, we announced a restructuring of our business to focus
on the integration of our Central California operations, which assets include
our asphalt refinery and interests in heavy oil fields. GREKA's proactive and
aggressive restructuring plan is designed to provide increased profitability and
cash flow stability.
We have established a strategy that capitalizes on our asset base to
enhance shareholder value as follows:
Integrated Operations
Operations of GREKA are planned to focus on the integration of our
subsidiaries' Santa Maria (California) assets, including an asphalt refinery and
interests in heavy oil fields. The hedged operations are targeted to capitalize
on the stable asphalt market in California by providing a balance of equity and
third
5
party feedstock (heavy oil) into the refinery. The integration of the
refinery (100% owned) with the interests in the heavy oil producing fields (100%
working interest) has successfully provided a stable ongoing hedge to GREKA on
each equity barrel since June 1999. GREKA's strategy in these integrated assets
is to proceed with acquisitions that enhance the long-term feedstock supply to
the refinery and to cost-efficiently boost production rates from the potential
drilling locations identified in the Santa Maria Valley area of central
California. We anticipate that the profitability from these integrated
operations will not be affected by volatile oil prices. It is also anticipated
that, by using our equity barrels to supply the refinery, working capital
requirements should be lower and cash flow should be enhanced. The continued
stability of the price of asphalt, coupled with reduced costs for processing and
lifting, should create substantial value for GREKA's shareholders.
In March 2002, we announced as part of GREKA's unique business
strategy in its integrated assets that we had closed into escrow our acquisition
of Vintage Petroleum, Inc.'s oil and gas producing properties and facilities in
the Santa Maria Valley of Central California. Subject to customary terms and
conditions, a final closing out of escrow effective December 1, 2001 is
scheduled to occur by May 31, 2002. During this escrow period, Vintage will
continue to operate the properties while the crude will be delivered to GREKA's
asphalt refinery, ramping up from approximately 800 BBL per day to approximately
2,000 BBL per day as of April 1st. This acquisition will increase the current
equity throughput of approximately 1,200 BBL per day to approximately 3,200 BBL
per day into the refinery.
Divestiture of E&P Assets
In March 2002, we announced GREKA's determination that our traditional
exploitation and production assets are inconsistent with our restructured
business strategy going forward. During second quarter 2002, we plan to sell
GREKA's interests in these assets primarily including the Potash Field,
Plaquemines Parish, Louisiana; Manila Village, Jefferson Parish, Louisiana;
Richfield East Dome Unit, Orange County, California; and PRC 91, Orange County,
California. The Company is further pursuing the sale of our exploration
interests in Indonesia and a limestone reserve in Indiana.
Exploitation, Exploration & Production
We plan to focus on our existing concessions in strategic locations,
such as China, where GREKA believes there is a significant, long-term demand for
energy and a niche advantage for the Company. GREKA plans to continuously pursue
new, emerging opportunities in the energy business to identify and evaluate
niche markets for our proprietary drilling technology. Two specific niche
targets are coal bed methane projects and gas storage. These opportunities
should provide significant upside from the use of short radius horizontal
laterals.
Business Development of GREKA
GREKA Energy Corporation was formed in 1988 as a Colorado corporation
under the name of Kiwi III, Ltd. On May 13, 1996, GREKA, then known as Petro
Union, Inc., filed a voluntary petition for relief pursuant to Chapter 11 of the
United States Bankruptcy Code. Current GREKA management acquired Petro Union,
Inc. and simultaneously procured on August 28, 1997, an order confirming Petro
Union's First Amended Plan of Reorganization from the Bankruptcy Court for the
Southern District of Indiana. The bankruptcy court approved the final accounting
and closed the bankruptcy proceedings on March 26, 1998.
During 1998, our management focused substantially all of its efforts
on corporate restructuring, recapitalization and acquisition efforts and an
investment in a horizontal drilling pilot program in the Cat Canyon field in
California that all were part of implementing its strategic niche growth plan.
During the latter part of 1998 and early 1999, management was primarily focused
on the acquisition of Saba, which had substantial reserves suited to
exploitation by GREKA's horizontal drilling technology, and considerable
expenses were incurred in connection with the Saba transactions in the first
quarter of 1999.
On March 22, 1999, the Company, then known as Horizontal Ventures,
Inc., changed its name to GREKA Energy Corporation. Effective March 24, 1999,
GREKA acquired Saba Petroleum Company as a wholly owned subsidiary.
6
Immediately subsequent to the completion of the Saba acquisition,
management commenced its strategy to reverse the decline in value of the Saba
assets which included securing bank financing of up to $47.0 million, reducing
Saba debt by $27.2 million, assuming full operation of our asphalt refinery
which significantly increased operating cash flows, selling our non-core assets
in Colombia while maintaining our repurchase option, acquiring all of the shares
we did not already own of Beaver Lake Resources Corporation ("Beaver Lake"), and
signing a production sharing contract with the China United Coalbed Methane
Corporation Ltd. to jointly exploit coalbed methane (CBM) resources in China.
During December 1999, GREKA commenced trading on the Nasdaq National Market
System.
During 2000, management exercised GREKA's option to repurchase our
Colombian assets, closed the financing with a new bank, Canadian Imperial Bank
of Commerce ("CIBC"), of up to $47.5 million with a portion of the proceeds used
to reduce current debt resulting in the complete elimination of Saba's defaulted
bank debt, completed the sale of all our non-core assets in Canada, settled with
Capco Resources, Ltd. and its related parties whereby GREKA cancelled 840,000
shares of its common stock for $5.2 million and gained voting control over the
remaining 514,500 shares owned by Capco, declared a payment of a 5% stock
dividend to our shareholders of record at close of market on December 31, 2000,
and completed a spot secondary public offering of 542,785 (including
over-allotment option) at a price of $13.10 per share.
Year 2001 Highlights
Highlights announced during 2001 include the following:
. In February 2001, GREKA increased up to $46 million its credit
facility with GMAC Commercial Credit LLC ("GMAC").
. In March 2001, GREKA secured financing of up to $75 million with
a new bank, closing on a revolving credit line of $16 million
with an initial advance of $13.2 million.
. In July 2001, GREKA announced a repurchase program to buy back up
to 10% of its outstanding common stock.
. In August 2001, GREKA concluded the Colombian transaction
resulting in its receipt of cash and assets with an aggregate
value estimated by the Company of up to $14 million.
. In October 2001, GREKA announced exploration success at the
Potash Field with the drilling of its HD No. 1 well with initial
production at over 6 MMCF per day.
. GREKA concluded all material legal matters. In October 2001,
after an August 2001 court order awarding RGC International
Investors $13.25 million on its claim, GREKA settled by paying
RGC $11.5 million.
Acquisition Activities
California E&P Assets
In September 2001, for a value of approximately $8 million, all
interests of Omimex Resources, Inc. in the Richfield East Dome Unit, Orange
County, California, were transferred to GREKA increasing our working interest to
99% and net revenue interest to 77% for this operated property. The value of the
acquired interest was determined by the Company's engineers based on an
acquisition price of $3.96 per BOE on total proved reserves.
California Integrated Assets
In June 2001, we had executed an agreement to acquire all of Vintage
Petroleum, Inc.'s oil and gas producing properties and facilities in the Santa
Maria Valley of Central California for $17.75 million in cash at closing,
subject to customary terms and conditions including consents and adjustments.
The contracted properties consist of five fields and approximately 110 producing
wells, encompassing over 5,000 acres of mineral interests and over 800 acres of
real estate. In March 2002, we announced as part of GREKA's unique business
strategy in
7
its integrated assets that we had closed into escrow our acquisition of these
producing properties. Subject to customary terms and conditions, a final closing
out of escrow effective December 1, 2001 is scheduled to occur by May 31, 2002.
During this escrow period, Vintage has operated and will continue to operate the
properties while the crude has been and will continue to be delivered to GREKA's
asphalt refinery, that has ramped up to approximately 2,000 BBL per day as of
April 1st. This acquisition will increase the current equity throughput of
approximately 1,200 BBL per day to approximately 3,200 BBL per day into the
refinery.
Divestiture Activities
Non-Core E&P Assets
In December 2001, the Company sold its interests in the San Simon
Field, Lea County, New Mexico and other mid-continent properties for a contract
price of $2.2 million.
Non-Core Colombian Assets
For approximately $10 million, the Company sold its Colombian assets
in 1999 subject to a look- back provision and valuation threshold which, by the
Company's calculation, had been met. In March 2000, we exercised our option to
re-purchase the Colombian assets in exchange for payment of $12.0 million,
reassignment of certain California assets acquired from the buyer, and
adjustments for related capital expenditures. The buyer refused to close
resulting in a legal dispute. In lieu of pursuing the re-purchase of this
non-core asset, the Company chose to settle these matters with the buyer which
resulted in an additional $14 million fiscal benefit to the Company that
included $6 million cash and the California assets discussed above valued at
approximately $8 million. This settlement provided us with $24 million total
value from the final disposition of our interests in Colombia.
Financing & Debt Restructuring Activities
Bank Financing
In February 2001, the credit facility secured by GREKA's subsidiaries'
interests in certain California oil and gas properties and real estate was
increased for a third time by GMAC. The transaction provides additional
financing of up to $46 million by increasing the principal amount of the term
loan from $25 million to $36 million, and $10 million for working capital.
Modifications to the terms of the credit agreement include the extension of the
credit facility to a term up to November 30, 2005.
In March 2001, GREKA's subsidiary as borrower and the Company acting
as guarantor entered into a credit and guarantee agreement with the Bank of
Texas, N.A. ("Bank of Texas"). The agreement provides that GREKA's subsidiary
may borrow up to $75 million. GREKA closed a revolving credit line of $16
million with an initial advance of $13.2 million against the line secured by
GREKA's subsidiary's interest in certain North American oil and gas properties.
A portion of the proceeds were paid to reduce the current debt of GREKA, which
payment resulted in the complete elimination of all obligations owed to CIBC.
In October 2001, our subsidiary entered into an amendment to the
credit and guarantee agreement with the Bank of Texas providing an additional
advance of $7.5 million against the revolving credit line secured by our
subsidiaries' interests in additional North American oil and gas properties and
real estate. The proceeds were paid to reduce the current debt of GREKA. (see
Item 3-"Legal Proceedings")
Debentures
On February 1, 2001, GREKA paid its 15% convertible senior
subordinated debentures in the principal amount of $1 million, and the security
of GREKA's subsidiary's interest in limestone deposits was released. There were
no conversions by debenture holders into GREKA common stock at the conversion
price of $20.00 per share.
In November 2001, GREKA issued 15% subordinated convertible debentures
in the aggregate amount of $1.3 million due May 31, 2002. The debentures are
convertible to Company common stock at the option of the debenture holders at
any
8
time prior to payment by the Company. Upon the receipt of a duly executed notice
of election to convert the GREKA debenture, the Company will convert the
debenture to GREKA common stock based upon a per share conversion price equal to
the lower of (i) five U.S. dollars ($5.00) or (ii) two U.S. dollars ($2.00)
below the lowest closing price of Greka's common stock for the month of November
2001.
During 2001, GREKA converted $0.28 million of its 9% senior
subordinated convertible debentures into 23,307 shares of GREKA common stock and
paid $0.07 million of debentures that had been redeemed, with a resulting
debenture balance of $2.40 million at December 31, 2001.
GREKA's Horizontal Drilling Technology
Horizontal drilling has become widely accepted as a standard option
for exploiting oil & gas resources. The principle advantage of horizontal
drilling is that it results in a substantially greater surface area for
drainage, and thus extraction of the oil from the reservoir. In industry terms
this is referred to as communicating zones of permeability. The unique method of
reentering a well and horizontal drilling patented by BP Amoco and licensed to
GREKA allows for turning while drilling, which can cause a vertical well to be
horizontal in as little as 25 feet. Thus this technology provides considerable
flexibility to the geologists and engineers in designing their well plans around
geological formation and reservoir constraints to achieve maximum performance.
Furthermore, this technique facilitates multi-laterals off an existing well
bore, which avoids costly drilling of new wells, and has considerable advantages
in shallow reservoirs where the traditional horizontal tools cannot be utilized
due to their larger radius requirements and related economics.
Marketing
Marketing of Asphalt Refinery Production
Our asphalt refinery in Santa Maria, California produces light
naphtha, kerosene distillate, gas oils and numerous cut-back, paving and
emulsion asphalt products. Historically, we have focused marketing efforts on
the asphalt products which are sold to various users, primarily in the Central
and Northern California areas. Distillates are readily marketed to wholesale
purchasers. Three customers accounted for more than ten percent of the Company's
sales of North American refinery production for each of the three years in the
period ended December 31, 2001, namely FAMM, Lawson and Granite which accounted
for approximately 22%, 14% and 12%, respectively, of such sales.
GREKA regards the refinery as a valuable adjunct to its production of
crude oil in the Santa Maria Valley and surrounding areas. Generally, the crude
oil produced in these areas is of low gravity and makes an excellent asphalt.
Prices for asphalt exceed market prices for crude and costs of operating the
refinery. GREKA believes that as road building and repairs increase in
California and surrounding western states, the market for asphalt will expand
significantly.
We market two principal products from our refinery: liquid asphalt and
light-end products (gas oil, naphtha and distillates). Liquid asphalt, which
accounted for approximately 65% of total refinery production in 2001, is
marketed primarily in California. While liquid asphalt is principally used
for road paving and manufacturing roofing products, all of the liquid asphalt
sold by GREKA's subsidiary is used for pavement applications. Paving grade
liquid asphalt is sold by GREKA's subsidiary to hot mix asphalt producers,
material supply companies, contractors and government agencies.
These customers further treat the liquid asphalt which is used for
road paving. In addition to conventional paving grade asphalt, our subsidiary
also produces modified and cutback asphalt products. Modified asphalt is a blend
of recycled plastics, rubber and polymer materials with liquid asphalt, which
produces a more durable product that can withstand greater changes in
temperature. Cutback asphalt is a blend of liquid asphalt and lighter petroleum
products and is used primarily to repair asphalt road surfaces. Additionally,
some of the paving grade and modified asphalts we produce are sold as base
stocks for emulsified asphalt products that are primarily used for pavement
maintenance.
Because the chemical footprint unique to the heavy crude oil
indigenous to the Santa Maria Valley readily blends, we are particularly well
positioned to supply the asphalt specifications in accordance with the standards
established by the National Highway and Transportation Administrations Strategic
Highway Research
9
Program (SHRP) or set by the American Association of State Highway and
Transportation Officials.
Demand for liquid paving asphalt products is primarily affected by
federal, state and local highway spending, as well as the general state of the
California economy, which drives commercial construction. Another factor is
weather, as asphalt paving projects are usually shut down in cold, wet weather
conditions. All of these demand factors are beyond our control. Government
highway spending provides a source of demand which has been relatively
unaffected by normal business cycles but is dependent on appropriations.
Growth in the California economy generally means well for the Company,
as increased business activity results in increased construction activity,
including new road construction and repair efforts on existing roads in both the
public and private sectors. A slowing economy could negatively impact both sales
and pricing of products.
As our asphalt refinery and principal markets are located in
California, the following discussion focuses on government highway funds
available in California.
Federal Funding
Federal funding of highway projects is accomplished through the
Federal Aid Highway Program. The Federal Aid Highway Program is a
federally-assisted, state-administered program that distributes federal funds to
the states to construct and improve urban and rural highway systems. The program
is administered by the Federal Highway Administration (FHWA), an agency of the
Department of Transportation. Nearly all federal highway funds are derived from
gasoline user taxes assessed at the pump.
In June 1998, the $217 billion federal highway bill, officially known
as the Transportation Equity Act for the 21st Century or TEA-21 was enacted. The
bill is estimated to increase transportation-related expenditures by $850
million a year in California alone over a six fiscal year period beginning
October 1, 1997. This will equate to a 51% increase over previous funding
levels. The average California apportionment over the six year period ending in
October 2003 is estimated to be $2.50 billion per year or a total of $15
billion. However, while management of GREKA's subsidiary believes it has
benefited from and should benefit in the future from such funding increases
there can be no guarantee that it will in fact do so in the future.
State and Local Funding
In addition to federal funding for highway projects, states
individually fund transportation improvements with the proceeds of a variety of
gasoline and other taxes. In California, the California Department of
Transportation (CALTRANS) administers state expenditures for highway projects.
According to the Department of Finance for the State of California, funding
available from the State Highway Account is estimated to average $1.13 billion
per year over the next 10 years excluding the Seismic Retrofit Bond Fund. This
compares to an average of $0.36 billion over the previous ten years.
Marketing of our Oil and Gas Production
The prices obtained for oil and gas are dependent on numerous factors
beyond our control, including domestic and foreign production rates of oil and
gas, market demand and the effect of governmental regulations and incentives.
Substantially all of our North American crude oil production is sold at the
wellhead at posted prices under short term contracts, as is customary in the
industry. Other than production from the Company's Integrated Operations
Division which is transported to our refinery, three customers accounted for
more than ten percent of the Company's sales of North American oil and gas
production during 2001, namely Tosco, Adams Resources and Plains Marketing,
L.P. which accounted for 34%, 34% and 21% respectively, of such sales.
The market for heavy crude oil produced by GREKA from its Central
Coast Fields in California differs substantially from the remaining domestic
crude oil market, due principally to GREKA's sale to the market of asphalt,
naphtha and distillates rather than hydrocarbons. GREKA's Santa Maria refinery
uses essentially all of its Central Coast Fields' crude oil, in addition to
third party crude oil,
10
to produce asphalt, among other products. Ownership and operation of the
refinery gives us a steady and stable market for its local crude oil which is
not enjoyed by other producers.
Competition
Competition in the oil and gas business is intense, particularly with
respect to the acquisition of producing properties, proved undeveloped acreage
and leases. Major and independent oil and gas companies actively bid for
desirable oil and gas properties and for the equipment and labor required for
their operation and development. We believe that the locations of our leasehold
acreage, our exploration, drilling and production capabilities and the
experience of our management and that of our industry partners generally enable
us to compete effectively. Many of our competitors, however, have financial
resources and exploration, development and acquisition budgets that are
substantially greater than ours, and these may adversely affect GREKA's ability
to compete, particularly in regions outside of GREKA's principal producing
areas. Because of this competition, GREKA cannot assure that it will be
successful in finding and acquiring producing properties and development and
exploration prospects.
Our management believes we have an advantage over our competition in
the regional asphalt market within Central California because of our vertical
integration and self-sufficiency in our Integrated Operations Division,
resulting in margins higher than other refiners in the same market.
Our management believes we have a further advantage over our
competition due to our acquired license from BP Amoco of the Short Radius
Horizontal Drilling technology, our level of field expertise in applying the
proprietary technology and our ability to apply these drilling techniques at a
fraction of the cost compared to conventional drilling techniques utilized by
our competition. Although BP Amoco has provided licenses to others, GREKA feels
that its strategy to apply the proprietary technology to its own oil and gas
properties and to penetrate new niche markets utilizing the proprietary
technology is within an entirely different market segment than any of the other
licensees who are concentrating on providing contract drilling services to
non-owned properties within their respective geographical area. We have not felt
any competitive pressure relative to our acquisition strategy focused on the
unique application of our niche, short-radius horizontal drilling technology.
Governmental Regulation
The following discussion of regulation of the oil and gas industry is
necessarily brief and is not intended to constitute a complete discussion of the
various statutes, rules, regulations or governmental orders to which operations
of GREKA and its subsidiaries may be subject.
Federal Regulation of First Sales and Transportation of Natural Gas
The sale and transportation of natural gas production from properties
owned by our subsidiaries may be subject to regulation under various federal and
state laws including, but not limited to, the Natural Gas Act and the Natural
Gas Policy Act, both of which are administered by the Federal Regulatory
Commission. The provisions of these acts and regulations are complex. Under
these acts, producers and marketers have been required to obtain certificates
from FERC to make sales, as well as obtaining abandonment approval from FERC to
discontinue sales. Additionally, first sales have been subject to maximum lawful
price regulation. However, the NGPA provided for phased-in deregulation of most
new gas production and, as a result of the enactment on July 26, 1989 of the
Natural Gas Wellhead Decontrol Act of 1989, the remaining regulations imposed by
the NGA and the NGPA with respect to "first sales" were terminated by no later
than January 1, 1993. FERC jurisdiction over transportation and sales other than
"first sales" has not been affected.
Because of current market conditions, many producers, including GREKA,
are receiving contract prices substantially below most remaining maximum lawful
prices under the NGPA. Our management believes that most of the gas to be
produced from GREKA's properties is already price-deregulated. The price at
which such gas may be sold will continue to be affected by a number of factors,
including the price of alternate fuels such as oil. At present, two factors
affecting prices are gas-to-gas competition among various gas marketers and
storage of natural gas. Moreover, the actual prices realized under GREKA's
current gas sales contracts also may be
11
affected by the nature of the decontrolled price provisions included therein and
whether any indefinite price escalation clauses in such contracts have been
triggered by federal decontrol.
The economic impact on GREKA and gas producers generally of price
decontrol is uncertain, but it currently appears to be resulting in higher gas
prices. Currently, there is a shortage of deliverable gas in most areas of the
United States and, accordingly, it remains possible that gas prices may remain
at relatively high levels. This is in sharp contrast to even recent pricing
which has been depressed for some time since deregulation. Producers such as
GREKA or resellers may be required to reduce prices in the future in order to
assure continued sales. It is also possible that gas production from certain
properties may be shut-in altogether for lack of an available market.
Commencing in the mid-1980's, FERC promulgated several orders designed
to correct market distortions and to make gas markets more competitive by
removing the transportation barriers to market access. These orders have had a
profound influence upon natural gas markets in the United States and have, among
other things, fostered the development of a large spot market for gas. The
following is a brief description of the most significant of those orders and is
not intended to constitute a complete description of those orders or their
impact.
On April 8, 1992, FERC issued Order 636, which is intended to
restructure both the sales and transportation services provided by interstate
natural gas pipelines. The purpose of Order 636 is to improve the competitive
structure of the pipeline industry and maximize consumer benefits from the
competitive wellhead gas market. The major function of Order 636 is to assure
that the services non-pipeline companies can obtain from pipelines is comparable
to the services pipeline companies offer to their gas sales customers. One of
the key features of the Order is the "unbundling" of services that pipelines
offer their customers. This means that pipelines must offer transportation and
other services separately from the sale of gas. The Order is complex and faces
potential challenges in court. GREKA is not able to predict the effect the Order
might have on its business.
FERC regulates the rates and services of "natural-gas companies",
which the NGA defines as persons engaged in the transportation of gas in
interstate commerce for resale. As previously discussed, the regulation of
producers under the NGA is being gradually phased out. Interstate pipelines,
however, continue to be regulated by FERC under the NGA. Various state
commissions also regulate the rates and services of pipelines whose operations
are purely intrastate in nature, although generally sales to and transportation
on behalf of other pipelines or industrial end-users are not subject to material
state regulation.
There are many legislative proposals pending in Congress and in the
legislatures of various states that, if enacted, might significantly affect the
petroleum industry. It is impossible to predict what proposals will be enacted
and what effect, if any, such proposals would have on GREKA and its
subsidiaries.
State and Local Regulation of Drilling and Production
State regulatory authorities have established rules and regulations
requiring permits for drilling, drilling bonds and reports concerning
operations. The states in which GREKA'S subsidiaries operate also have statutes
and regulations governing a number of environmental and conservation matters,
including the unitization and pooling of oil and gas properties and
establishment of maximum rates of production from oil and gas wells. A few
states also pro-rate production to the market demand for oil and gas.
Environmental Regulations
Our operations are subject to numerous laws and regulations governing
the discharge of materials into the environment or otherwise relating to
environmental protection. These laws and regulations may require the acquisition
of a permit before drilling commences, prohibit drilling activities on certain
lands lying within wilderness and other protected areas and impose substantial
liabilities for pollution resulting from drilling operations. Such laws and
regulations may also restrict air or other pollution resulting from GREKA's
operations. Moreover, many commentators believe that the state and federal
environmental laws and regulations will become more stringent in the future. For
instance, proposed legislation amending the federal Resource Conservation and
Recovery Act would reclassify oil and gas production wastes as "hazardous
waste". If such legislation were to pass,
12
it could have a significant impact on the operating costs of GREKA, as well as
the oil and gas industry in general. State initiatives to further regulate the
disposal of oil and gas wastes are also pending in certain states, including
states in which our subsidiaries have operations, and these various initiatives
could have a similar impact on GREKA.
Operational Hazards and Insurance
GREKA's subsidiaries' operations are subject to the usual hazards
incident to the drilling and production of oil and gas, such as blowouts,
cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires,
pollution, releases of toxic gas and other environmental hazards and risks.
These hazards can cause personal injury and loss of life, severe damage to and
destruction of property and equipment, pollution or environmental damage and
suspension of operations.
GREKA and its subsidiaries have up to $11 million of general liability
insurance. GREKA's insurance does not cover every potential risk associated with
the drilling, production and processing of oil and gas. In particular, coverage
is not obtainable for certain types of environmental hazards. The occurrence of
a significant adverse event, the risks of which are not fully covered by
insurance, could have a material adverse effect on GREKA's financial condition
and results of operations. Moreover, no assurance can be given that GREKA will
be able to maintain adequate insurance in the future at rates it considers
reasonable.
Employees
As of April 30, 2002, GREKA and its subsidiaries had 121 full-time
employees. None of GREKA's employees is subject to a collective bargaining
agreement. GREKA considers its relations with its employees to be satisfactory.
Shareholders Rights Plan
We have a shareholder rights plan in order to preserve the long-term
value of the Company for GREKA's shareholders. Under the shareholder rights
plan, one right will be distributed for each outstanding share of GREKA common
stock. Each right will entitle the holder to buy one share of GREKA common stock
for an initial exercise price of $57.14 per share. The rights will initially
trade with common shares and will not be exercisable unless certain takeover
events occur. The plan generally provides that if a person or group acquires or
announces a tender offer for the acquisition of 9.9% (amended from 12% by
approval of GREKA's Board of Directors in May 2001) or more of GREKA common
stock without approval of the Board of Directors, the rights will become
exercisable and the holders of the rights, other than the acquiring person or
group, will be entitled to purchase shares of GREKA common stock (or under
certain circumstances stock of the acquiring entity) for 50% of its current
market price. The rights may be redeemed by GREKA for a redemption price of $.01
per right.
Retirement Plan
The Company sponsors a defined contribution retirement savings plan
(401(k) Plan) to assist all eligible U.S. employees in providing for retirement
or other future financial needs. We currently provide matching contributions
equal to 50% of each employee's contribution, subject to a maximum of 8% of
their eligible contribution.
Net Profit Sharing Plan
The Company has a net profit sharing plan ("NPSP") for employees that
fulfill certain qualification requirements. The NPSP provides for an equal
disbursement normally of 10% of the Company's pretax income, excluding
extraordinary gains. Such disbursement is planned to follow the filing of the
annual audited financial statements of the Company. However, the NPSP could be
suspended, increased or otherwise amended at the discretion of our Board of
Directors for any specific year.
Item 2. Description of Property
The following description of the GREKA properties at December 31, 2001
includes all discussions of prior operations of all of GREKA's properties and
those of its wholly owned subsidiaries.
13
GREKA's Properties as of December 31, 2001
GREKA owned interests in approximately 523 wells at December 31, 2001.
The majority of these wells are concentrated along the central coast
of California and in Louisiana. In 2001, California (heavy oil) and Louisiana
(gas) were the primary and focused areas of exploitation and development
activities. At December 31, 2001, GREKA also operated wells and had exploitation
and development activities in other regions of California and in several states
outside of California and Louisiana, principally New Mexico and Texas. GREKA's
evaluation of international exploration and exploitation projects are in
Indonesia and China. The Company continuously evaluates the profitability of its
oil, gas and related activities and, as part of its strategic business plan,
intends to divest unprofitable leases or areas of operations that are not
consistent with its business strategy.
Exploitation and Development Activities
The following is a brief discussion of significant developments in the
Company's recent exploitation and development activities through its wholly
owned subsidiaries:
United States
California (Integrated)
Approximately 34.8% of GREKA's proved reserves at December 31, 2001
(4.7 MMBOE) were located in four onshore fields in California's central coast
region. Daily production from the Central Coast Fields averaged 1,361 BOE for
the year ended December 31, 2001, representing 43.3% of GREKA's total
production. GREKA operates all of its wells in the Central Coast Fields.
California (E&P)
GREKA also holds interests in other California areas, which
represented 30.8% (4.2 MMBOE) of GREKA's proved reserves at December 31, 2001.
GREKA's share of daily production from these other interests averaged 684 BOE
(1,016 BOE gross) for the year ended December 31, 2001, representing 21.8% of
GREKA's total production.
Louisiana
Approximately 31.3% of GREKA's proved reserves at December 31, 2000
(4.2 MMBOE) were located in two fields in Louisiana. GREKA's share of daily
production from the Louisiana fields averaged 852 BOE (1,032 BOE gross) for the
year ended December 31, 2001, representing 27.1% of the Company's total
production.
Other States
In addition to our California and Louisiana properties, GREKA owns
producing properties in a number of other states, but primarily New Mexico and
Texas, which collectively represented 3.1% of GREKA's proved reserves at
December 31, 2001 (0.4 MMBOE). GREKA's share of daily production from these
properties averaged 136 BOE (264 BOE gross) for the year ended December 31,
2001, representing 7.8% of GREKA's total production.
GREKA seeks to acquire domestic and international producing properties
where it can significantly increase reserves through development or exploitation
activities and control costs by serving as operator. GREKA believes that its
substantial experience and established relationships in the oil and gas industry
enable it to identify, evaluate and acquire high potential properties on
favorable terms. As the market for acquisitions has become more competitive in
recent years, GREKA has taken the initiative in creating acquisition
opportunities, particularly with respect to adjacent properties, by directly
soliciting fee owners, as well as working and royalty interest holders, who have
not placed their properties on the market.
GREKA's 2002 discretionary capital expenditure budget for properties
is dependent upon the price for which its products are sold and upon the ability
of GREKA to obtain external financing. Subject to these variables and based on
the current asset base, we expect our cash flow and credit facilities to fund
14
approximately $30 million in 2002 for capital expenditure, which includes the
acquisition of Vintage properties for $18 million. The budget is primarily
allocated to the development of the Integrated Operations Division.
Exploration Activities
GREKA further plans to expand its existing reserve base by developing
high potential exploration prospects in known productive regions. GREKA believes
these activities complement its traditional development and exploitation
activities. In pursuing these exploration opportunities, GREKA may use advanced
technologies, including 3-D seismic and satellite imaging. In addition, GREKA
may seek to limit its direct financial exposure in exploration projects by
entering into strategic partnerships that shift the drilling related financial
risks to partners while providing the Company with an upside upon a successful
event. At December 31, 2001, GREKA had exploration plays in three primary areas:
California, Indonesia and China.
The following is a brief discussion of significant developments in the
Company's recent exploration activities through its wholly owned subsidiaries:
California
Coalinga Nose Exploration Prospect, Fresno County, California. GREKA
has leases and contractual rights covering approximately 9,000 acres of land in
the region of the prolific Coalinga oil field in the San Joaquin Valley of
California. GREKA participated in a 16 square mile 3-D seismic survey covering
this area and has interpreted the survey. Nineteen anomalies have been
identified in the prospect area, covering five potentially productive zones,
ranging in depth from 6,500 to 12,000 feet. GREKA has an 89% working interest
below and a 9% working interest above the Gatchell formation in the Leda
Prospect, Pleasant Valley, and Cotton Gin Prospects. In April 2001, we entered
into a farmout agreement of our 89% interest in the deep rights under the east
half of our acreage block in which we retained a 22.25% back-in interest after
payout. The farmee drilled the initial well to 11,200' with completion in
September 2001. However, this initial well could not be tested, as the integrity
of the well bore could not be sustained. The farmee, who abandoned the well in
March 2002, did not earn any right to participate in the prospect.
Foreign Operations
Indonesia
West Java Exploration Prospect, Jakarta, Indonesia. GREKA is a party
to a production sharing contract, along with Pertamina, the Indonesian
state-owned oil company, covering 1.275 million unexplored acres on the Island
of Java near a number of producing oil and gas fields. The 30-year contract
provides that oil and gas in commercial quantities must be discovered prior to
September 2003. A portion of the block has been distinctly identified as the
Jonggol area consisting of 500,000 acres. The Jonggol area has two prospects and
eleven leads. In March 2002, the Company, which has a 75% interest in the block,
entered into an agreement to sell its exploration interests in Indonesia. The
sale requires the customary consent by Pertamina, the Indonesian state-owned oil
company, that has been requested and is currently pending.
China
Fengcheng Coalbed Methane Exploration Prospect, Jiangxi, China. GREKA
is a party to a production sharing contract with the China United Coalbed
Methane Corporation Ltd., which contract has been approved by the Chinese
Ministry of Foreign Trade and Economic Cooperation, to jointly exploit coalbed
methane resources in Fengcheng, East China's Jiangxi Province. The contract
block in which GREKA has a 49% working interest covers a total area of 380,534
acres. The 30-year contract provides that GREKA as operator will drill at least
ten coalbed methane wells over a three year term. Two production test wells have
been drilled and were both successful. The Company intends to drill 5 wells in
2002 to prove reserves this year and to thereafter formulate detailed
development plans.
Oil and Gas Producing Properties
At December 31, 2001, we owned and operated domestic producing
properties in 8 states, with our U.S. proved reserves located primarily in two
core areas:
15
California and Louisiana which represent approximately 65.6% and 31.3%,
respectively, of our proved reserves (BOE).
The following table summarizes GREKA's estimated proved oil and gas
reserves by geographic area as of December 31, 2001. The following table
includes both proved developed (producing and non-producing) and proved
undeveloped reserves. Approximately 37.9% of the total reserves reflected in the
following table are proved undeveloped. There can be no assurance that the
timing of drilling, reworking and other operations, volumes, prices and costs
employed by Netherland Sewell & Associates, independent petroleum engineers will
prove accurate. Since December 31, 2001, oil and gas prices have generally
increased. At such date, the price of WTI crude oil as quoted on the New York
Mercantile Exchange was $19.84 per Bbl and the comparable price for April 30,
2002 was $27.29. Quotations for the comparable periods for natural gas were
$2.57 per Mcf and $3.80 per Mcf, respectively. The proved developed and proved
undeveloped oil and gas reserve figures are estimates based on reserve reports
prepared by GREKA's independent petroleum engineers Netherland Sewell &
Associates. The estimation of reserves requires substantial judgment on the part
of the petroleum engineers, resulting in imprecise determinations, particularly
with respect to new discoveries. Estimates of reserves and of future net
revenues prepared by different petroleum engineers may vary substantially,
depending, in part, on the assumptions made, and may be subject to material
adjustment. Estimates of proved undeveloped reserves comprise a substantial
portion of GREKA's reserves and, by definition, had not been developed at the
time of the engineering estimate. The accuracy of any reserve estimate depends
on the quality of available data as well as engineering and geological
interpretation and judgment. Results of drilling, testing and production or
price changes subsequent to the date of the estimate may result in changes to
such estimates. The estimates of future net revenues in this report reflect oil
and gas prices and production costs as of the date of estimation, without
escalation, except where changes in prices were fixed under existing contracts.
There can be no assurance that such prices will be realized or that the
estimated production volumes will be produced during the periods specified in
such reports. The estimated reserves and future net revenues may be subject to
material downward or upward revision based upon production history, results of
future development, prevailing oil and gas prices and other factors. A material
decrease in estimated reserves or future net revenues could have a material
adverse effect on GREKA and its operations.
December 31, 2001
Proved Reserves, net
Gross Oil Gas PV-10 Value
Property Wells (MBbls) (MMcf) MBOE Dollar Value %
-------- ----- ------- ------ ------ ------------ -----------
(In thousands)
California:
Integrated Ops ........... 340 4,374 1,912 4,722 $11,182 19.7%
E&P ...................... 136 3,896 1,586 4,184 $13,565 24.0%
Total
California ............... 476 8,270 3,498 8,906 $24,747 43.7%
Louisiana ................... 30 1,704 13,982 4,246 $30,269 53.5%
Other United
States ................... 17 78 1,902 424 $ 1,602 2.8%
Total United
States ................... 523 10,052 19,382 13,576 $56,618 100.0%
The following is a brief discussion of our oil and gas operations in
our major fields:
California
Central Coast Fields. GREKA's subsidiary operates four fields in the
Central Coast area of California. These fields provide equity crude oil for
GREKA's wholly owned asphalt refinery. The fields are Cat Canyon, Casmalia, Gato
Ridge and Santa Maria Valley which collectively have an average working interest
of 100% in 107 active wells producing 1,361 BOEPD (gross). These fields
represent 34.8% of GREKA's total proved reserves. In March 2002, we announced a
restructuring of our business to focus on the integration of our Central
California operations, which assets include our asphalt refinery and these
interests in heavy oil fields.
We have established a horizontal drilling program by re-entering
existing idle wellbores and drilling short radius laterals utilizing proprietary
technology patented from BP Amoco. The reduced cost for re-entries ($125,000 per
well) should
16
contribute to a higher economic success rate and additional economic reserves.
Earlier drilling has delineated the S1b Sisquac Sand in the Cat Canyon Field and
S2 Sisquac Sand in the Gato Ridge Field as those formations with the highest
opportunities for success. In 2001, no wells were drilled. Management plans to
drill up to 6 horizontal re-entries during 2002 primarily to exploit these two
reservoirs plus explore the Monterey Zone.
Richfield East Dome Unit. The Richfield East Dome Unit is a mature
waterflood in Orange County, California, operated by GREKA's subsidiary and
producing 684 BOPD. The field has proved net reserves of 2.4 MMBO valued at
PV-10 $6.2 million or 17.7% of the Company's total reserve value. In September
2001, we increased our working interest in this field to 99% and net revenue
interest to 77%. (see Item 1-"Description of Business, Acquisition Activities,
California E&P Assets") Waterflood operations were initiated in 1974 by Texaco.
Field facilities are in sufficiently satisfactory condition to service the
waterflood operation through the remaining life of the field. During second
quarter 2002, we plan to sell GREKA's interests in this asset.
North Belridge Field. The North Belridge Field is located in Kern
County, California. GREKA's subsidiary is the operator and owns 100% working
interest in 42 wells on three leases covering 270 contiguous acres. The wells
produce from two formations-- light oil from the Diatomite zone and heavy oil
from the Tulare formation. Current production is about 278 BOEPD, net proved
reserves are 1.5 MMBOE valued at PV-10 $6.2 million.
Louisiana
Potash Dome Field. The Potash Dome Field is located in Plaquemines
Parish south of New Orleans, Louisiana, overlying a salt dome. The wells on the
west side of the field are land based while the wells on the east side produce
from single well structures located in shallow inland water. GREKA's subsidiary
operates the 3000 acre field and has 100% working interest in 21 wells. Proved
net reserves in the field are 1.6 MMBO and 14 BCFG valued at PV-10 $30.1
million. There exists substantial drilling opportunities in the field with net
proved undeveloped reserves of 0.6 MMBO and 8.2 BCFG in seven drilling locations
as determined by Netherland, Sewell & Associates, Inc., GREKA's independent
petroleum engineers. During 2001, as the first of a four-phased program in the
2001 business plan, we successfully executed our initial five-well recompletion
program, namely: Orleans Levee Board ("OLB") #77, #94, B-10, #90, #77, and SL508
#25. During the second phase of our program, also in 2001 we drilled to a total
depth of 10,604' and dually completed in the 11-B gas sand and the 9-A oil sand
our first well, Haspel & Davis No. 1, in the 9-A zone. Initial production from
this well was at over 6 MMCF per day and current production is at 510 BOEPD (or
60 BOPD and 2.7 MMCFD). The well, which was directionally drilled beneath a
large salt overhand in inland waters utilizing The Parker Drilling Co. rig #8B
1000 HP barge, was set to TD with 7 5/8" of production casing. This success
proved the technical interpretation by GREKA of the potential reservoirs in this
field. With our completion of the HD No. 1 well, the field has a total of 96
wells drilled to depths varying from 600' to 14,000' with 21 wells remaining.
Additionally, GREKA believes there is substantial opportunity to add gas
reserves in a deeper zone called the Tex "W" which is owned 50% by GREKA's
subsidiary and 50% by Exxon-Mobil. During second quarter 2002, we plan to sell
GREKA's interests in this asset.
Manila Village Field. The Manila Village Field is located in Jefferson
Parish, south Louisiana. There are net proved reserves of 0.1 MBO in this field
as of December 31, 2001. In April 2002, we sold our interest in this field.
Other United States
Southwest Tatum Field. The Southwest Tatum Field operated by GREKA's
subsidiary is located in Lea County, New Mexico. This field was discovered in
1996 through the use of 3-D seismic. There are four different productive
horizons in the field, Devonian, Canyon, Cisco, and Wolfcamp. There are net
proved developed reserves of 0.1 MBO and 0.1 MMCFG in the field as of December
31, 2001.
San Simon Field. The San Simon Field is located in Lea County, New
Mexico. In 2001, GREKA's subsidiary operated one oil well and three gas wells.
The oil well is the only producer in the field completed in the Wolfcamp
formation. This property was sold as of December 31, 2001.
17
Oil and Gas Reserves
Our proved reserves and the estimated present value of future revenues
from proved developed and undeveloped oil and gas properties in this document
have been estimated by our independent petroleum engineers. In 1999, 2000 and
2001, Netherland, Sewell & Associates, Inc. prepared reports on GREKA's reserves
in the United States. The estimates of these independent petroleum engineers
were based upon review of production histories and other geological, economic,
ownership and engineering data provided by GREKA. In accordance with the SEC's
guidelines, GREKA's estimates of future net revenues from GREKA's proved
reserves and the present value thereof are made using oil and gas sales prices
in effect as of the dates of such estimates and are held constant throughout the
life of the properties, except where such guidelines permit alternate treatment,
including, in the case of gas contracts, the use of fixed and determinable
contractual price escalation. Future gross revenues at December 31, 2001 reflect
weighted average prices of $14.53 per BOE compared to $26.93 per BOE and $17.90
per BOE as of December 31, 2000 and 1999, respectively.
The following tables present total estimated proved developed
producing, proved developed non-producing and proved undeveloped reserve volumes
as of December 31, 1999, 2000 and 2001 and the estimated present value of future
net revenues ("PV-10") (based on current prices and costs at the respective
year's end, using a discount factor of 10 percent per annum). As used herein,
the term "proved undeveloped reserves" are those which can be expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage is limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves for other
undrilled units are claimed only where it can be demonstrated with certainty
that there is continuity of production from the existing productive formation.
We do not include estimates for proved undeveloped reserves attributable to any
acreage for which an application of fluid injection or other improved recovery
technique is contemplated, unless such techniques have been proved effective by
actual tests in the area and in the same reservoir. There can be no assurance
that these estimates are accurate predictions of reserves or of future net
revenues from oil and gas reserves or their present value. The prices received
for oil and gas have generally increased since the preparation of the 2001 year
end engineering estimates.
Estimated Proved Oil and Gas Reserves
At December 31,
---------------------------
1999(1) 2000(1) 2001(1)
------- ------- -------
Net oil reserves (MBbl)
Proved developed producing .............. 6,469 7,059 4,310
Proved developed non-producing .......... 825 1,309 2,664
Proved undeveloped ...................... 3,237 3,644 3,078
------ ------ ------
Total proved oil reserves (MBbl) ....... 10,531 12,012 10,052
====== ====== ======
Net natural gas reserves (MMcf)
Proved developed producing .............. 3,364 5,184 2,206
Proved developed non-producing .......... 5,398 4,758 5,822
Proved undeveloped ...................... 8,836 10,133 11,354
------ ------ ------
Total proved natural gas
reserves (MMcf) ..................... 17,598 20,075 19,382
====== ====== ======
Total proved reserves (MBOE) ............... 13,732 15,662 13,576
- ----------
(1) Does not include reserve volumes attributable to the Company's interest in
assets subsequently divested.
Estimates of proved reserves may vary from year to year reflecting
changes in the price of oil and gas and results of drilling activities during
the
18
intervening period. Reserves previously classified as proved undeveloped may be
completely removed from the proved reserves classification in a subsequent year
as a consequence of negative results from additional drilling or product price
declines which make such undeveloped reserves non-economic to develop.
Conversely, successful development and/or increases in product prices may result
in additions to proved undeveloped reserves.
Estimated Present Value of
Future Net Revenue
(In thousands)
At December 31,
----------------------------
1999(1) 2000(1) 2001(1)
------- -------- -------
PV-10 Value
Proved developed producing .......... $39,689 $ 67,080 $15,180
Proved developed non-producing ...... 8,977 37,160 21,164
Proved undeveloped .................. 18,487 59,637 20,274
------- -------- -------
Total ............................ $67,153 $163,877 $56,618
======= ======== =======
- ----------
(1) Does not include reserve volumes attributable to the Company's interest in
assets subsequently divested.
As used herein, the terms "proved oil and gas reserves," "proved
developed oil and gas reserves," and "proved undeveloped reserves" have the
meanings defined by the SEC as set forth in the Table of Contents to this
document. Reservoir engineering is a subjective process of estimating the sizes
of underground accumulations of oil and gas that cannot be measured in an exact
way. The accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Reserve reports of other engineers might differ from the reports contained
herein. Results of drilling, testing and production subsequent to the date of
the estimate may justify revision of such estimate. Future prices received for
the sale of oil and gas may be different from those used in preparing these
reports. The amounts and timing of future operating and development costs may
also differ from those used. Accordingly, reserve estimates are often different
from the quantities of oil and gas that are ultimately recovered.
The following table summarizes sales volume, sales price and
production cost information for GREKA's net oil and gas production for each of
the years in the three-year period ended December 31, 2001.
Year Ended December 31,
---------------------------
1999(1) 2000(1) 2001(1)
------- ------- -------
Production Data:
Oil (MBbls) .................... 505 770 827
Gas (MMcf) ..................... 862 1,807 1,848
Total (MBOE) ................. 685 1,099 1,163
Average Sales
Price Data
(Per Unit):
BOE ............................ $13.85 $22.14 $19.51
Selected Data
per BOE:
Production costs(2) ............ $ 7.57 $ 6.49 $ 7.87
General and
administrative ............... $ 3.35 $ 5.79 $ 3.22
Depletion,
19
depreciation and
amortization ................. $ 2.72 $ 2.90 $ 4.34
- ----------
(1) Does not include reserve volumes attributable to the Company's interest in
assets subsequently divested.
(2) Production costs include production taxes.
Drilling Activity
With respect to GREKA's participation in the drilling of exploratory
and development wells for each of the three years in the three year period ended
December 31, 2001, there has been no drilling activity except as set forth in
the following table:
Year Ended December 31,
-----------------------------------------------------------
1999 2000 2001
----------------- ----------------- -------------------
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
-------- ------ -------- ------ -------- ------
United States:
Development Wells
Oil -- -- 5 5 1 1
Gas -- -- -- -- 1 1
Dry (3) -- -- 1 1 -- --
- ----------
(1) A gross well is a well in which a working interest is owned. The number of
gross wells is the total number of wells in which a working interest is
owned.
(2) A net well is deemed to exist when the sum of fractional ownership working
interest in gross wells equals one. The number of net wells is the sum of
fractional working interests owned in gross wells expressed as whole
numbers and fractions thereof.
(3) A dry hole is an exploratory or development well that is not a producing
well.
Productive Oil and Gas Wells
The following table sets forth information at December 31, 2001,
relating to the number of productive oil and gas wells (producing wells and
wells capable of production, including wells that are shut in) in which GREKA
through its subsidiaries owned a working interest:
Oil Gas Total
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
United States 498 450 25 9 523 459
===== === ===== === ===== ===
Oil and Gas Acreage
The following table sets forth certain information at December 31,
2001 relating to oil and gas acreage in which GREKA through its subsidiaries
owned a working interest:
Developed(1) Undeveloped
--------------- --------------
Gross Net Gross Net
20
United States 21,070 16,180 11,201 8,025
====== ====== ====== =====
(1) Developed acreage is acreage assigned to productive wells.
Title to Properties
Many of GREKA's subsidiaries' oil and gas properties are held in the
form of mineral leases, licenses, reservations, concession agreements and
similar agreements. In general, these agreements do not convey a fee simple
title to GREKA, but rather, depending upon the jurisdiction in which the
pertinent property is situated, create lesser interests, varying from a profit a
prendre to a determinable interest in the minerals. In some jurisdictions,
notably non-U.S. jurisdictions, GREKA's subsidiaries' interest is only a
contractual relationship and bestows no interest in the oil or gas in place. As
is customary in the oil and gas industry, a preliminary investigation of title
is made at the time of acquisition of undeveloped properties. Title
investigations are generally completed, however, before commencement of drilling
operations or the acquisition of producing properties. GREKA believes that its
methods of investigating title to, and acquisition of, its oil and gas
properties are consistent with practices customary in the industry and that it
has generally satisfactory title to the leases covering its proved reserves.
Because most of GREKA's oil and gas leases require continuous production beyond
the primary term, it is always possible that a cessation of producing or
operating activities could result in the loss of a lease. Assignments of
interest to and/or from GREKA'S subsidiaries may not be publicly recorded.
From time to time, substantially all of GREKA's properties, including
its stock in its subsidiaries, are hypothecated to secure GREKA's current and
future indebtedness. GREKA's subsidiaries' working interest in properties may be
subject to lienholders by non-payment. In the event of GREKA's non-payment or
untimely payment of its obligations, GREKA expects liens to be filed against its
assets and to be subject to lawsuits. Oil and gas leases in which GREKA'S
subsidiaries have an interest may be deficient, require ratifications and be
subject to action by GREKA subsidiaries.
Average Sales Price and Production Cost
The following table sets forth information concerning average per unit
sales price and production cost for GREKA's oil and gas production for the
periods indicated:
Year Ended December 31,
------------------------
1999 2000 2001
------ ------ ------
Average sales price per BOE:
Integrated Ops .................... $10.82 $18.63 $16.82
E&P Americas ...................... 17.14 25.27 21.77
Combined .......................... 13.86 22.14 19.51
Average production cost per BOE:
Integrated Ops .................... $ 8.74 $ 3.99 $ 6.51
E&P Americas ...................... 5.80 6.88 8.00
Combined .......................... 7.47 5.51 7.87
Asphalt Refinery
GREKA owns an asphalt refinery in Santa Barbara County, California
through a wholly owned subsidiary. The refinery is a fully self-contained plant
with steam generation, mechanical shops, control rooms, office, laboratory,
emulsion plant and related facilities, and is staffed with a total of 21
operating, maintenance, laboratory and administrative personnel.
Real Estate Activities
GREKA'S subsidiaries from time to time purchased real estate in
conjunction with their acquisition of oil and gas and refining properties in
21
California and plan to continue this practice. At December 31, 2001, the Company
owned through its subsidiaries approximately 2,500 acres in Santa Barbara
County, California and approximately 6 acres in Orange County, California. GREKA
has used a portion of its real estate holdings for agricultural purposes. GREKA
plans to retain some of these real estate holdings for asset appreciation which
may include developmental activities at a future date.
Limestone Properties
GREKA owns a non-core, 355 acre limestone property located in Monroe
County, Indiana. The limestone deposits are made up of Salem limestone, which
produces a high industrial grade calcium oxide or calcium carbonate used in
scrubbing machinery that cleans the gaseous emissions from coal burning
generators. The Company is pursuing the sale of GREKA's interests in this asset.
In 1999, GREKA sold its interest in the limestone property in exchange
for a $5.7 million non-recourse promissory note, secured by the limestone
property. The buyer defaulted on the note, and the parties litigated their
claims for which the court in May 2001 ordered in favor of GREKA and the
property was reconveyed to GREKA.
Offices
GREKA leases approximately 1,000 square feet of office space at 630
Fifth Avenue, Suite 1501, New York, New York, for its executive offices through
September 30, 2004. GREKA's offices are located in Santa Maria, California;
Houston, Texas; and Beijing, China. In March 2002, GREKA announced that, due to
the divestiture of related assets, it closed its international offices in
Jakarta, Indonesia and Bogota, Colombia and will be downsizing its E&P Americas
unit in Houston to a satellite office.
Item 3. Legal Proceedings
Bank of Texas, N.A. v. Greka AM, Inc. and GREKA Energy Corporation
(Case No. 02-00771, 160th Judicial District Court of Dallas County, Texas,
January 2002). Bank of Texas alleged a default on the loan to GREKA's subsidiary
and brought an action seeking repayment of the loan plus unspecified exemplary
damages and attorney fees. GREKA filed counter-claims seeking contract and
unspecified exemplary damages and attorneys' fees. The parties have entered into
a forbearance agreement through June 30, 2002 by which time the parties' claims
shall be settled or GREKA shall proceed to vigorously defend all claims asserted
by Bank of Texas and seek counter-relief.
Liens and legal actions in connection therewith alleging nonpayment or
untimely payment for services or goods provided to GREKA's properties in an
aggregate amount of approximately $5.2 million have been filed against our
subsidiary's working interests. We plan to settle these claims concurrent with
if not before the planned sale of our assets and debt restructuring in the
second quarter.
From time to time, the Company and its subsidiaries are a named party
in legal proceedings arising in the ordinary course of business. While the
outcome of such proceedings cannot be predicted with certainty, management does
not expect these matters to have a material adverse effect on the Company's
financial condition or results of operations.
Item 4. Submission of Matters to a Vote of Security Holders
At the Annual Meeting of Shareholders held on December 7, 2001, the
following individual was elected to the Board of Directors to serve for a 3-year
term ending 2004 as a Class A director:
Votes For Votes Withheld
--------- --------------
Randeep S. Grewal 3,546,272 148,890
22
PART II
Item 5. Market for Common Equity and Related Stockholder Matters
Our common stock is listed for trading on the Nasdaq National Market
under the symbol "GRKA". Prior to March 25, 1999, the trading symbol was "HVNV".
Except for a period from August to December of 1997, GREKA's common stock has
been quoted on NASDAQ since February 19, 1993. The following table sets forth,
for the periods indicated, the high and low closing bid quotations per share of
GREKA common stock as reported on the Nasdaq National Market. Our common stock
quotations represent inter-dealer quotations, without retail markup, markdown or
commissions, and may not represent actual transactions. There can be no
assurance that a public market for GREKA's common stock will be sustained in the
future.
Bid
---
Quarter Ended Low High
March 31, 1999 4.875 10.500
June 30, 1999 6.375 9.125
September 30, 1999 7.000 13.500
December 31, 1999 7.500 12.000
March 31, 2000 8.563 9.500
June 30, 2000 8.625 8.813
September 30, 2000 14.375 15.688
December 31, 2000 12.750 13.438
March 31, 2001 12.250 14.813
June 30, 2001 10.000 14.375
September 30, 2001 7.500 11.600
December 31, 2001 6.950 9.150
March 31, 2002 6.010 8.630
On April 30, 2002 there were approximately 885 registered holders of
GREKA's common stock. Based on a broker count, GREKA believes at least an
additional 3,692 persons are shareholders with street name positions.
Holders of GREKA common stock are entitled to receive such dividends
as may be declared by the GREKA board of directors. GREKA has not yet paid any
cash dividends, and the board of directors of GREKA presently intends to pursue
a policy of retaining earnings for use in GREKA's operations and to finance
expansion of its business. In January 2001, GREKA issued a 5% stock dividend to
its shareholders of record at close of market on December 31, 2000 increasing
the total number of shares outstanding by 215,394. The declaration and payment
of dividends in the future, of which there can be no assurance, will be
determined by our board of directors in light of conditions then existing,
including our earnings, financial condition, capital requirements and other
factors.
In July 2001, the Company announced a repurchase program to buy back
up to 10% of its outstanding common stock, which repurchase is subject to market
conditions and will occur through open market purchases or privately negotiated
transactions at prices and on terms acceptable to management. At December 31,
2001, GREKA repurchased 25,000 shares of its common stock and canceled such
shares so that they became authorized but unissued shares of common stock.
Item 6. Selected Financial Data.
The following table sets forth selected consolidated financial data
for the Company as of the dates and for the periods indicated. The financial
data for each of the five years ended December 31, 2001, were derived from the
Consolidated Financial Statements of the Company. The following data should be
read in conjunction with "Management's Discussion and Analysis of Financial
Condition and Results of Operations," which includes a discussion of factors
materially affecting the comparability of the information presented, and in
conjunction with the Company's financial statements included elsewhere in this
report.
Years Ended December 31,
----------------------------------------------------
2001 2000 1999 1998 1997
-------- -------- -------- ------- -------
23
(In thousands, except per share data)
Income Statement Data:
Revenues ....................................... $ 40,755 $ 49,067 $ 29,138 $ 146 $ 212
Production and Product Costs ................... $ 24,782 $ 25,200 $ 17,821 $ 121 $ 248
General and administrative ..................... $ 7,974 $ 6,699 $ 3,205 $ 1,542 $ 756
Depletion, depreciation &
amortization ................................. $ 5,579 $ 3,592 $ 3,024 $ 333 $ 24
Other operating expenses ....................... $ 300 $ 2,377 $ -- $ -- $ --
Interest Expense ............................... $ 4,157 $ 4,535 $ 1,860 $ 32 $ 25
Other Expenses Net ............................. $ (5,540) $ (992) $ (1,696) $ (526) $ (34)
Minority Interest .............................. $ -- $ -- $ 21 $ -- $ --
Income tax (expense) benefit ................... $ (37) $ (362) $ (46) $ -- $ --
Equity in Earnings.............................. $ -- $ -- $ 569 $ 586 $ --
Cumulative effect of change in accounting ...... $ -- $ 853 $ -- $ -- $ --
Net (loss) income ............................. $ (7,614) $ 4,457 $ 3,367 $(5,548) $ (851)
(Loss) income per common share:
Basic net (loss) income per share .............. $ (1.67) $ 1.00 $ 0.80 $ (3.25) $ (1.37)
Cash dividend per share ........................ $ -- $ -- $ -- $ -- $ --
Basic weighted average common
shares outstanding ........................... 4,555 4,476 4,203 1,702 621
Diluted weighted average common
shares outstanding ........................... 4,651 4,763 4,801 1,702 621
Balance Sheet Data (end of period):
Working Capital ................................ $(50,355)* $ (2,664) $(14,176) $(1,828) $ 3,133
Net property and equipment ..................... $ 89,465 $ 77,182 $ 70,287 $ 4,426 $ 6,795
Total assets ................................... $100,049 $ 98,813 $ 84,214 $20,807 $10,803
Long-term obligations .......................... $ 13,445 $ 28,207 $ 15,696 $ 53 $ 77
Total stockholders' equity ..................... $ 33,165 $ 40,211 $ 33,378 $18,505 $ 9,095
* Includes reclassification of long-term debt to current due to a technical
default.
Item 7. Management's Discussion and Analysis of Financial Conditions and Results
of Operation
Overview
In view of significant material changes to GREKA during 1998, the
acquisition of Saba in March 1999, and assumption of full operations related to
the asphalt refinery, management believes that the financial condition and
results of operations of GREKA reported for periods prior to 1999 are not
indicative of the future financial condition and results of operations of GREKA.
As a consequence of GREKA's subsidiary's assumption of full operations at its
refinery in May 1999, the Company has been reporting 100% of the revenue and net
income resulting from operations in contrast to recognition prior to May 1999 of
only 50% of the net profit resulting from the same operations. Saba's 1998
financial statements are not consolidated with GREKA's 1998 financial statements
since the acquisition had not been consummated by December 31, 1998.
During the latter part of 1998 and early 1999, management of GREKA was
primarily focused on the acquisition of Saba and considerable expenses were
incurred in connection with the Saba transactions in the fourth quarter of 1998
and the first quarter of 1999. Due to the significance to GREKA of the Saba
acquisition, GREKA's management and staff devoted a substantial amount of time
and effort to the acquisition.
In view of the significant differences between GREKA's corporate
structure before the March 1999 acquisition of Saba, comparisons of GREKA's
results of operations for 1998 and 1997 are considered by management to be
neither relevant nor representative of GREKA Energy's long-term potential.
Results of Operations
Comparison of Years Ended December 31, 2001 and 2000
Revenue decreased by 17% or $8,311,858 from $49,067,140 for 2000 to
$40,755,282 for 2001. The decrease was mostly due to both lower volume sales of
8%
24
from 1,080,604 barrels in 2000 to 998,640 barrels in 2001, and 15% lower
average sales prices of refined products form $29.26 in 2000 to $24.87 in 2001
at our integrated operations.
Production and product costs decreased by 2% or $417,681 from
$25,199,620 in 2000 to $24,781,939 in 2001. The overall decrease was net of an
increase of 9% in the average per barrel cost from $11.20 in 2000 to $12.22 in
2001, or a total of $2,068,498 offset by a decrease of 10% in volume from
2,249,495 barrels in 2000 to 2,027,945 barrels in 2001 or a total decrease of
$2,486,179. The decrease in volume of barrels of throughput at the integrated
operations contributed to the overall increase in the average per barrel cost
for the year.
General and Administrative expenses increased by 19% or $1,274,908
from $6,699,275 for 2000 to $7,974,183 due to increase in audit, legal,
consulting and insurance costs coupled with costs associated with increase of
personnel and related fringe benefits.
Operating Income decreased 81% or $9,078,639 from $11,198,901 in 2000
to $2,120,262 as a direct result of a decrease in revenues of $8,311,858 or 92%
(explained above) coupled with increase in general and administrative expenses
and depreciation, depletion and amortization expenses.
Depreciation, depletion and amortization increased 55% or $1,986,657
primarily as a result of increase in the per barrel rate of depletion from $3.43
in 2000 to $4.80 in 2001. The increase in the depletion rate was a result of an
increase of 40% in the asset base relating to oil and gas properties coupled
with a decrease of 13% in the overall reserves from 15,662 MBOE in 2000 to
13,576 MBOE in 2001.
Interest Expense decreased 8% from $4,535,174 in 2000 to $4,157,110
for 2001 mostly due to a decrease in the interest rates applied to average
outstanding loan balances.
Other Expense net increased by 75%, or $4,170,693, from $5,526,613 in
2000 to ($9,697,306) in 2001, mostly due to expenses and non-recurring charges
associated with settlement of litigation post acquisition adjustments.
Net income decreased by 271%, or $12,070,758, from $4,457,214 for 2000
to ($7,613,544) for 2001. The variance is mostly due to a 69% decrease in
revenue of $8,311,858 and a 31% net increase of expenses, or $3,758,900
consisting mainly of nonrecurring charges resulting from settlement of material
litigation and post acquisition adjustments.
Capital expenditures increased 26% or $3,568,957 from $13,602,000 in
2000 to $17,170,957 in 2001. Capital expenditures were utilized primarily for
drilling activities in E&P Americas.
Comparison of Years Ended December 31, 2000 and 1999
Revenue increased from $26,137,810 for 1999 to $49,067,140 for 2000.
This increase resulted primarily from a 160% increase in BOE production and an
increase in the selling price of the Company's products from an average of
$13.95 per BOE in 1999 to $22.14 in 2000. While management expects a continued
increase in production it cannot project future pricing changes.
Production and Product costs increased from $17,820,620 for 1999 to
$25,199,620 for 2000 primarily as a result of a full twelve months of post
merger operations of the asphalt facility and oil and gas operations.
General and administrative expenses increased from $3,205,276 for 1999
to $6,699,275 for 2000 primarily as a result of a full twelve months of post
merger activity and increased staffing during the period.
Operating income more than doubled from $5,088,131 in 1999 to
$11,198,901 primarily as a result of the increased sales volume and improved
pricing for product sold.
Depreciation, depletion and amortization increased from $3,023,783 for
1999 to $3,592,242 for 2000 primarily as a result of a full twelve months of
post merger depreciation, depletion and amortization expenses and larger asset
base.
25
The Company sold its Canadian subsidiary during the year, resulting in
a loss of $991,439. The Company's accounting method for inventory was changed
from the first in, first out (FIFO) method to the average cost method effective
January 1, 2000. The average cost method is preferable because the primary
inventoriable cost at the refinery is crude oil for which the price can
fluctuate significantly. The weighted average method balances the impact of
short term fluctuations in crude oil pricing on the Company's refinery inventory
levels. The Company recorded the effect of this change of $853,110 as a
cumulative effect of a change in accounting principle as of January 1, 2000.
Interest expense increased from $1,859,688 for 1999 to $4,535,174 for
2000 primarily as a result of increased debt levels.
Net income increased from $3,367,000 for 1999 to $4,457,000 for 2000.
This increase was substantially, negatively impacted by the non recurring,
non-cash charges for the change in accounting practices and the loss on the sale
of our Beaver lake subsidiary both discussed above. Net was also impacted by a
larger provision for income taxes and a charge for the employee profit sharing
plan.
Capital expenditures increased from $2,092,000 in 1999 to $13,602,000
in 2000. Capital expenditures were utilized primarily for drilling activity in
the E&P Americas gas drilling program and re-working our Integrated Operations
heavy oil wells. Capital expenditures are expected to rise to $30 million during
2001.
Cash Flows
Cash provided by operating activities decreased 54% or $6,356,735 from
an inflow of $11,674,581 for 2000 to $5,317,847 for 2001. Net income for the
period adjusted for non-cash charges provided $47,669 of cash inflow.
The Company's net cash flows from investment activities increased from
a net outflow of $13,601,519 for 2000 to a net outflow of $16,030,140 for 2001.
The increase was due to an unanticipated increase in expenditures associated
with the drilling of the Haspel and Davis #1 well at Potash, coupled with
expenditures associated with the 3-year cycle for the major turnaround
maintenance program at the asphalt refinery.
The Company's net cash flow provided by financing activities increased
slightly or 3% from $6,096,318 in 2000 to $6,296,697 in 2001. Cash was provided
during 2001 from proceeds of the Company's financing facilities with the Bank of
Texas and GMAC.
Liquidity and Capital Resources
The following discussion of our liquidity and capital resources is on
a consolidated basis, noting the uses and contributions of our consolidated
entity. The Company's growth is focused on acquisitions that are strategic and
in accordance with its business plan. It is intended that such acquisitions will
be achieved concurrent with the closing of adequate financing. Historically,
GREKA has relied on cash flow from operations to finance operational capitalized
expenditures. In 2001, GREKA had expended $17,170,957 for its capitalized
expenditures. For 2002, GREKA has budgeted $30 million for its discretionary
capitalized expenditures, which includes the acquisition of Vintage properties
for $18 million, to be funded by its cash flow and credit facilities. Factors
affecting actual expenditures and investments include availability of capital
and suitable investment opportunities, market volatility and economic trends.
The anticipated sources of funds for such growth opportunity are cash flow from
operations and external financings.
Further, GREKA intends to achieve the following:
. In addition to eliminating the trade and bank debt estimated at $25M
related to our traditional exploration and production assets that are
planned to be sold, we have embarked on a complete restructuring of
our remaining long-term and maturing debt of $20m. The debt
restructuring scheduled during the second quarter is intended to
payoff all remaining non-trade debt including debentures of $6M, fund
the acquisition of the escrowed Vintage Petroleum, Inc. properties of
$18.5M, provide availability for targeted acquisitions within the
Integrated Operations' business plan, continued development of our
interests in China, and working capital.
. Continue to execute an aggressive rework program to return to
production existing wells on all properties that have shut-in wells.
. Utilize the in-house proprietary and cost effective horizontal
drilling technology to enhance production in the Santa Maria Valley
area, increasing the equity oil and gas production as well as new gas
treatment facilities.
26
. Continue to acquire assets to enhance the benefit of integrated
operations that collectively provide for low cost operating expenses
and high cash flow.
. Drill five new wells in China in a pilot program to confirm
anticipated production levels of Coalbed Methane (CBM), and upon
successful completion, develop and implement the appropriate plan to
exploit the additional acreage.
GREKA's management also believes that the disposition of non-core
assets brings opportunities for cost savings, and other synergies, resulting in
improved cash flow potential for the long-term growth of GREKA and of
shareholder value. Further, these dispositions give GREKA a stronger
consolidated asset base upon which it can rely in securing future financings,
both equity and debt. However, there is no assurance that any specific level of
cost savings or other synergies will be achieved or that such cost savings or
other synergies will be achieved within the time periods contemplated, or that
GREKA will be able to secure future financings.
For an analysis of certain contractual and commercial obligations in 2002 and
thereafter, see "Disclosures about Contractual Obligations and Commercial
Obligations and Certain Investments", shown below. The following table reflects
the contractual cash obligations and other commercial commitments in the
respective periods in which they are due.
Total
Amounts Less than
Contractual Obligations Committed 1 Year 1-2 Years 3-4 Years Thereafter
- ----------------------- --------- ------ --------- --------- ----------
(Thousands of Dollars)
Debt $ 43,132 33,644 6,043 3,445 --
Operating Leases 353 175 178 -- --
--------------------------------------------------------------------
Total Contractual Cash Obligations $ 43,485 $ 33,819 $ 6,221 $ 3,445 $ --
====================================================================
Our continuation as a going concern is dependent upon our ability to
successfully establish the necessary financing arrangements and implement our
strategies consistent with our restructuring plans announced in the first
quarter of 2002. However, although no assurances can be given, we remain
confident that we will be able to continue operating as a going concern.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
At December 31, 2001, the Company's operations were exposed to market
risks primarily as a result of changes in commodity prices and interest rates.
The Company does not use derivative financial instruments for speculative or
trading purposes.
Interest Rate Risk - The Company is exposed to the impact of interest
rate changes. The Company has approximately $4.3 million outstanding under its
Revolving credit agreements and $32 million under its term loan facility which
exposes the Company to the risk of earnings or cash flow loss due to changes in
market interest rates. The interest rates are based on current market rates
(Prime rate or Federal Funds Rate) plus a range of 100 to 300 basis points.
Commodity price risk - The Company is subject to the market risk
associated with changes in commodity prices of the underlying crude oil and
refined products; such changes in values are generally offset by changes in the
sale prices of the Company's refined products.
Credit Risk - Financial instruments which potentially subject the
Company to credit risk consist principally of trade receivables. Concentration
of credit risk with respect to trade receivables is mitigated by the stability,
longevity and financial soundness of the Company's customers. Although 83% of
the Company's sales are made to six customers, these customers are not a credit
risk since most of their sales are to funded city, state or federal government
projects.
Inflation
GREKA does not believe that inflation will have a material impact on
GREKA's future operations.
Critical Accounting Policies and Use of Estimates
Use of Estimates. The preparation of the consolidated financial
statements in conformity with generally accepted accounting principles requires
our management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the dates of the financial statements and the reported amounts of
revenues and expenses during the reporting periods. Our most significant
financial estimates are based on remaining proved natural gas and oil reserves.
Full Cost Accounting - The Company uses the full cost method to
account for our natural gas and oil properties. Under full cost accounting, all
costs incurred in the acquisition, exploration and development of natural gas
and oil reserves are capitalized into a "full cost pool". Capitalized costs
include costs of all unproved properties, internal costs directly related to our
natural gas and oil activities and capitalized interest. The Company amortizes
these costs using a unit-of-production method. Greka computes the provision for
depreciation, depletion and amortization quarterly by multiplying production for
the quarter by a depletion rate. The depletion rate is determined by dividing
our total unamortized cost base by net equivalent proved reserves at the
beginning of the quarter. Unevaluated properties and related costs are excluded
from our amortization base until a determination is made as to the existence of
proved reserves. The amortization base includes estimates for future development
costs as well as future abandonment and dismantlement costs. Estimates of proved
reserves are key components of our depletion rate for natural gas and oil
properties and our full costs ceiling test limitation. See Note 17 Supplemental
Oil and Gas Information. Because there are numerous uncertainties inherent in
the estimation process, actual results could differ from the estimates.
Inventories - The Company values its inventory on the weighted average
cost method. The weighted average cost method is considered the preferable
because the primary inventorable cost at the refinery is crude oil for which the
price can fluctuate significantly. The weighted average method balances the
impact of short term fluctuations in crude oil pricing on the Company's refinery
inventory levels.
27
New Accounting Pronouncements
The SFAS has recently issued SFAS No. 141, "Business Combinations," SFAS No.
142, "Goodwill and Other Intangible Assets, "SFAS No. 143, "Accounting for Asset
Retirement Obligations" and SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets."
SFAS No. 141, "Business Combinations," requires the use of the purchase method
of accounting for all business combinations initiated after June 30, 2001. SFAS
No. 142, "Goodwill and Other Intangible Assets", addresses accounting for the
acquisition of intangible assets and accounting for goodwill and other
intangible assets after they have been initially recognized in the financial
statements. We do not currently have goodwill or other similar intangible
assets' therefore, the adoption of the new standard on January 1, 2002, has not
had a material effect on our financial statements.
SFAS No. 143, "Accounting for Asset Retirement Obligations, "addresses
accounting and reporting for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs. SFAS No.
143 will be effective for us January 1, 2003 and early adoption is encouraged.
SFAS No. 143 requires that the fair value of a liability for an asset's
retirement obligation be recorded in the period in which it is incurred and the
corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its then present value each
period, and the capitalized cost is depreciated over the useful life of the
related asset. If the liabilty is settled for an amount other than the recorded
amount, a gain or loss is recognized. Currently, we include estimated future
costs of abandonment and dismantlement in our full cost amortization base and
amortize these costs as a component of our depletion expense. We are evaluating
the impact the new standards will have on our financial statements.
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets,"
is effective for us January 1, 2002, and addresses accounting and reporting for
the impairment or disposal of long-lived assets. SFAS 144 supersedes SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for the Long-Lived
Assets to Be Disposed Of" and ABP Opinion No. 30, "Reporting the Results of
Operations-Reporting the Effects of Disposal of Segment of a Business." SFAS No.
144 retains the fundamental provisions of SFAS NO. 121 and expands the reporting
of discontinued operations to include all components of an entity with
operations that can be distinguished from the rest of the entity and that will
be eliminated from the ongoing operations of the entity in a disposal
transaction. We are evaluating the impact the new standard will have on our
financial statements.
Item 8. Financial Statements.
Please see accompanying Index to Financial Statements commencing on
page F-1.
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure
In May 2001, the Company engaged Hein + Associates LLP to replace
Arthur Andersen LLP as its independent public accountants to audit its
consolidated financial statements for the year ending December 31, 2001. Refer
to the Company's Form 8-K filed on May 21, 2001.
In December 2001, the Company appointed Deloitte & Touche LLP to
replace Hein + Associates LLP as its independent public accountants to audit its
consolidated financial statements for the year ending December 31, 2001. Refer
to the Company's Form 8-K filed on January 3, 2002.
28
PART III
Item 10. Directors, Executive Officers, Promoters and Control Persons;
Compliance With Section 16(a) of the Exchange Act
The directors and executive officers of GREKA are as follows:
Name
Since Age Positions
- ----- --- ---------
Randeep S. Grewal 37 Chairman of the Board, Chief Executive
September 1997(1) Officer and President, Class A Director
Dr. Jan F. Holtrop 66 Class B Director
September 1997(2)
George G. Andrews 76 Class B Director
July 1998(2)
Dai Vaughan 62 Class C Director
March 1999(3)
Kenton D. Miller 49 Class C Director
October 2000(3)
Richard "Sam" R. Lembcke 65 Vice President-Upstream Operations
December 2001
Max A. Elghandour 51 Chief Financial Officer
August 2001
Brent E. Stromberg 57 Vice President-Downstream Operations
December 2001
Susan M. Whalen 40 Vice President-Corporate Affairs,
August 2001 Secretary
(1) term as Director expires 2004
(2) term as Director expires 2003
(3) term as Director expires 2002
Randeep S. Grewal. Since September 1997, Mr. Grewal has served as our
Chairman of the Board, Chief Executive Officer and President. From April 1997 to
September 1997, Mr. Grewal served as Chairman and Chief Executive Officer for
Horizontal Ventures, Inc., an oil and gas horizontal drilling technology company
that became a subsidiary of our predecessor in September 1997. From 1993 to
1996, Mr. Grewal was the Corporate Vice President for the Rada Group with
principal responsibilities for its global expansion and related operations. He
has also been involved in various joint ventures, acquisitions, mergers and
reorganizations since 1986 in the United States, Europe and the Far East within
diversified businesses. Mr. Grewal has a Bachelor of Science degree in
Mechanical Engineering from Northrop University.
Dr. Jan Fokke Holtrop. Dr. Holtrop has been a Class B Director of
GREKA since September 1997. Since 1989 he has been a senior Production
Technology professor at Delft University of Technology within the Faculty of
Petroleum Engineering and Mining in The Netherlands. Prior to Delft University,
he served in various positions within the Shell Oil Company where he started his
career in 1962. This includes mining engineering, reservoir engineering and
petroleum engineering field work in at least 14 different countries, as well as
deep sea drilling, coal production and coal exploration operations, well
technology research, and well design, drilling and production operations. Dr.
Holtrop has almost 40 years of experience within the oil and gas exploration,
drilling and production industry with a global hands-on background. Dr. Holtrop
has a Ph.D. and a MSC in Mining Engineering from Delft University of Technology.
George G. Andrews. Mr. Andrews became a Class B Director of GREKA in
July 1998. He has been a consultant and private investor since his retirement
from the oil and gas industry in 1987. From 1982 until 1987 he was employed as
Corporate Vice President of Intercontinental Energy Corporation of Englewood,
Colorado and
29
directed the company's land acquisition, lease and management operations.
Between June 1981 and November 1982, Mr. Andrews was Vice President of Shelter
Hydrocarbons, Inc. of Denver, Colorado where he directed all land management and
operation procedures. From 1979 to June of 1981, Mr. Andrews was Senior Landman
for the National Cooperative Refinery Association in Denver, Colorado. Mr.
Andrews obtained his B.S. degree in 1947 from the University of Tulsa.
Kenton D. Miller. In October 2000, Mr. Miller became a Class C
Director of GREKA. Since 1991, Mr. Miller has maintained a private consulting
practice specializing in management advisory services for a diverse group of
petroleum related companies. His consulting services are oriented to improving
financial performance for clients utilizing the combination of financial
accounting with operations principles and providing assistance with strategic
acquisitions or divestitures. Mr. Miller has 30 years of oil and gas experience
in reservoir engineering, field operations and management, primarily with Ladd
Petroleum Company, B