UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
(Amendment No. 1)
(Mark One)
[ X ] Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended June 30, 2001 or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
Commission File No: 0-9261
KESTREL ENERGY, INC.
--------------------
(Exact name of registrant as specified in its charter)
State of Incorporation: Colorado I.R.S. Employer Identification No.
84-0772451
999 - 18th Street, Suite 2490
Denver, Colorado 80202
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (303) 295-0344
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
TITLE OF EACH CLASS
COMMON STOCK, NO PAR VALUE
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
|X| YES | | NO
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of 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. [ ]
At August 31, 2001, 7,700,200 common shares (the registrant's only class of
voting stock) were outstanding. The aggregate market value of the 4,674,569
common shares of the registrant held by nonaffiliates on that date (based upon
the mean of the closing bid and asked price on the NASDAQ system) was
$5,399,127.
1
TABLE OF CONTENTS
PART I.................................................................3
ITEM 1. BUSINESS......................................................3
General Description of Business......................................3
Recent Activities....................................................3
Operations and Policies..............................................3
Risk Factors.........................................................4
Forward-Looking Statements...........................................6
ITEM 2. PROPERTIES....................................................6
Oil and Gas Interests................................................6
Royalty Interests Under Producing Properties.........................7
Drilling Activities..................................................7
Farmout Agreements...................................................8
Oil and Gas Production, Prices and Costs.............................8
Customers............................................................8
Office Facilities....................................................8
ITEM 3. LEGAL PROCEEDINGS.............................................8
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS...........9
PART II................................................................9
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS....................................................9
Outstanding Shares of Common Stock...................................9
Stock Price..........................................................9
Dividend Policy.....................................................10
ITEM 6. SELECTED FINANCIAL DATA......................................10
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.............................................10
Liquidity and Capital Resources.....................................10
Results of Operations...............................................13
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK...15
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA..................15
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE............................................15
PART III..............................................................16
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..........16
ITEM 11. EXECUTIVE COMPENSATION......................................16
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT..........................................................16
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS..............16
PART IV...............................................................16
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS
ON FORM 8-K.........................................................16
SIGNATURES............................................................18
2
PART I
ITEM 1. BUSINESS.
GENERAL DESCRIPTION OF BUSINESS
Kestrel Energy, Inc. (the "Company") was incorporated under the laws of the
State of Colorado on November 1, 1978. The Company's principal business is the
acquisition, either alone or with others, of interests in proved developed
producing oil and gas leases, and exploratory and developmental drilling.
The Company presently owns oil and gas interests in the states of Louisiana, New
Mexico, Oklahoma, South Dakota, Texas, and Wyoming.
RECENT ACTIVITIES
In September 2001, the Company announced the appointment of Barry D. Lasker as
President, Chief Executive Officer and Director. Mr. Lasker brings to the
Company 20 years of experience in the oil and gas industry. Timothy L. Hoops,
former President and Chief Executive Officer, will remain on the Board of
Directors and will provide consulting services to the Company on a contract
basis.
On June 22, 2001, ( the effective date), the Company filed Articles of Merger of
Victoria Exploration, Inc. into Kestrel Energy, Inc. pursuant to Section
7-111-104 of the Colorado Revised Statutes. In accordance with the Articles of
Merger, on the effective date, Victoria Exploration, Inc. ceased to exist and
Kestrel Energy, Inc. became the surviving corporation. Up until June 22, 2001,
the consolidated financial statements include the accounts of the Company and
its wholly-owned subsidiary, Victoria Exploration, Inc. All significant inter
company accounts and transactions have been eliminated in consolidation.
In May 2001, the Company restructured its line of credit agreement with Wells
Fargo Bank West. Under the prior terms the Company had a borrowing base of
$2,000,000 with interest paid monthly. The new agreement lowered the borrowing
base to $1,400,000 and required the Company to reduce the principal balance on
the line of credit to $1,400,000 by October 31, 2001 with interest on the
outstanding balance paid monthly. As of October 15, 2001, the principal balance
is $1,455,000.
OPERATIONS AND POLICIES
The Company currently is focusing its exploration, acquisition and development
opportunities in Wyoming, specifically on the Greens Canyon Field. However, the
acquisition, development, production and sale of oil and gas acreage are subject
to many factors outside the Company's control. These factors include worldwide
and domestic economic conditions; proximity to pipelines; existing oil and gas
sales contracts on properties being evaluated; the supply and price of oil and
gas as well as other energy forms; the regulation of prices, production,
transportation and marketing by federal and state governmental authorities; and
the availability of, and interest rates charged on, borrowed funds.
Historically, in attempting to acquire, explore and drill wells on oil and gas
leases, the Company has often been at a competitive disadvantage since it had to
compete with many companies and individuals with greater capital and financial
resources and larger technical staffs. The Company has in the past sought to
mitigate some of these problems by forming acquisition joint ventures with other
companies, including its affiliate, Victoria Petroleum N.L. These joint ventures
allow the Company access to more acquisition candidates and enable the Company
to share the evaluation and other costs among the venture partners.
The Company's operations are subject to various provisions of federal, state and
local laws regarding environmental matters. The impact of these environmental
laws on the Company may necessitate significant capital outlays, which may
materially affect the earnings potential of the Company's oil and gas business
in particular, and could cause material changes in the industry in general. The
Company
3
strongly encourages the operators of the Company's oil and gas wells to
do periodic environmental assessments of potential liabilities. To date,
environmental laws have not materially hindered nor adversely affected the
Company's business. Please see Item 3, Legal Proceedings, however, for a
discussion of potential environmental litigation involving the Company.
The Company has four full-time employees, including the Company's President,
Barry D. Lasker. The Company also hires outside professional consultants to
handle certain additional aspects of the Company's business. Management believes
this type of contracting for professional services is the most economical and
practical means for the Company to obtain such services at this time.
RISK FACTORS
WE MUST CONTINUE TO EXPAND OUR OPERATIONS
Our long term success is ultimately dependent on our ability to expand our
revenue base through the acquisition of producing properties and, to a much
greater extent, by successful results in our exploration efforts. We will need
to continue to raise capital to make additional acquisitions and to make further
investments in our current portfolio of exploration properties. We have made
significant investments in exploration properties in the Western Green River
Basin in Wyoming. There is no assurance that any of these acquisitions or other
acquisitions will be as successful as originally projected. In fact, while we
have already had some measure of success with these acquisitions, we have also
had some disappointments. All of our exploration projects are subject to failure
and the loss of our investment.
PRICES OF OIL AND NATURAL GAS FLUCTUATE WIDELY BASED ON MARKET CONDITIONS AND
ANY DECLINE WILL ADVERSELY AFFECT OUR FINANCIAL CONDITION
Our revenues, operating results, cash flow and future rate of growth are very
dependent upon prevailing prices for oil and gas. Historically, oil and gas
prices and markets have been volatile and not predictable, and they are likely
to continue to be volatile in the future. Prices for oil and gas are subject to
wide fluctuations in response to relatively minor changes in the supply of and
demand for oil and gas, market uncertainty and a variety of additional factors
that are beyond our control, including:
o the strength of the United States and global economy;
o political conditions in the Middle East and elsewhere;
o the supply and price of foreign oil and gas;
o the level of consumer product demand;
o the price and availability of alternative fuels;
o the effect of federal and state regulation of production and transportation;
and
o the proximity of our natural gas to pipelines and their capacity.
WE MUST REPLACE THE RESERVES WE PRODUCE
A substantial portion of our oil and gas properties contain proved undeveloped
reserves. Successful development and production of those reserves cannot be
assured. Additional drilling will be necessary in future years both to maintain
production levels and to define the extent and recoverability of existing
reserves. There is no assurance that our present oil and gas wells will continue
to produce at current or anticipated rates of production, that development
drilling will be successful, that production of oil and gas will commence when
expected, that there will be favorable markets for oil and gas which may be
produced in the future or that production rates achieved in early periods can be
maintained.
THERE ARE MANY RISKS IN DRILLING OIL AND GAS WELLS
The cost of drilling, completing and operating wells is often uncertain.
Moreover, drilling may be curtailed, delayed or canceled as a result of many
factors, including title problems, weather conditions, shortages of or delays in
delivery of equipment, as well as the financial instability of well operators,
major working interest owners and well servicing companies. Our gas wells may be
shut-in for lack of a market until a gas pipeline or gathering system with
available capacity is extended into our area. Our oil wells may have
4
production curtailed until production facilities and delivery arrangements are
acquired or developed for them.
WE FACE INTENSE COMPETITION
The oil and natural gas industry is highly competitive. We compete with others
for property acquisitions and for opportunities to explore or to develop and
produce oil and natural gas. We have previously formed acquisition joint
ventures with several other companies, including Victoria Petroleum N.L. and
other affiliates, which have allowed us more access to acquisition candidates
and to share the evaluation costs with them. We face strong competition from
many companies and individuals with greater capital, financial resources and
larger technical staffs. We also face strong competition in procuring services
from a limited pool of laborers, drilling service contractors and equipment
vendors.
THE AMOUNT OF INSURANCE WE CARRY MAY NOT BE SUFFICIENT TO PROTECT US
We, our partners, co-venturers and well operators maintain general liability
insurance but it may not cover all future claims. If a large claim is
successfully asserted against us, we might not be covered by insurance, or it
might be covered but cause us to pay much higher insurance premiums or a large
deductible or co-payment. Furthermore, regardless of the outcome, litigation
involving our operations or even insurance companies disputing coverage could
divert management's attentions and energies away from operations. The nature of
the oil and gas business involves a variety of operating hazards such as fires,
explosions, cratering, blow-outs, adverse weather conditions, pollution and
environmental risks, encountering formations with abnormal pressures, and, in
horizontal wellbores, the increased risk of mechanical failure and collapsed
holes, the occurrence of any of which could result in substantial losses to us.
OUR SUCCESS MAY BE DEPENDENT ON OUR ABILITY TO RETAIN BARRY LASKER, JOHN
KOPCHEFF, BOB PETT AND IRA PASTERNACK AS KEY PERSONNEL
We believe that the oil and gas exploration and development and related
management experience of our key personnel is important to our success. The
active participation in the Company of our new president, Barry Lasker, John T.
Kopcheff, vice president of International, Robert J. Pett, our chairman, and Ira
Pasternack, vice president of Exploration, is a necessity for our continued
operations. We do not have any employment contracts with these individuals and
we do not carry key person life insurance on their lives. We compete with bigger
and better financed oil and gas exploration companies for these individuals. Our
future success may depend on whether we can attract, retain and motivate highly
qualified personnel. We cannot assure you that we will be able to do so.
OUR RESERVES ARE UNCERTAIN
Estimating our proved reserves involves many uncertainties, including factors
beyond our control. Our annual report on Form 10-K for fiscal year 2001 contains
estimates of our oil and natural gas reserves and the future cash flow to be
realized from those reserves for fiscal years 2001, 2000 and 1999, as prepared
by independent petroleum engineers. There are uncertainties inherent in
estimating quantities of proved oil and natural gas reserves since petroleum
engineering is not an exact science. Estimates of commercially recoverable oil
and gas reserves and of the future net cash flows from them are based upon a
number of variable factors and assumptions including:
o historical production from the properties compared with production from
other producing properties;
o the effects of regulation by governmental agencies;
o future oil and gas prices; and
5
o future operating costs, severance and excise taxes, abandonment costs,
development costs and workover and remedial costs.
GOVERNMENTAL REGULATION, ENVIRONMENTAL RISKS AND TAXES COULD ADVERSELY AFFECT
OUR OIL AND GAS OPERATIONS IN THE UNITED STATES
Our oil and natural gas operations in the United States are subject to
regulation by federal and state government, including environmental laws. To
date, we have not had to expend significant resources in order to satisfy
environmental laws and regulations presently in effect. However, compliance
costs under any new laws and regulations that might be enacted could adversely
affect our business and increase the costs of planning, designing, drilling,
installing, operating and abandoning our oil and gas wells and other facilities.
Additional matters that are, or have been from time to time, subject to
governmental regulation include land tenure, royalties, production rates,
spacing, completion procedures, water injections, utilization, the maximum price
at which products could be sold, energy taxes and the discharge of materials
into the environment.
FORWARD-LOOKING STATEMENTS
This prospectus contains forward-looking statements. We use words such as
"anticipate", "believe", "expect", "future", "may", "will", "should", "plan",
"intend", and similar expressions to identify forward-looking statements. These
statements are based on our beliefs and the assurances we made using information
currently available to us. Because these statements reflect our current views
concerning future events, these statements involve risks, uncertainties and
assumptions. Our actual results could differ materially from the results
discussed in the forward-looking statements. Some, but not all, of the factors
that may cause these differences include those discussed in the risk factors in
this prospectus. You should not place undue reliance on these forward-looking
statements. You should also remember that these statements are made only as of
the date of this prospectus and future events may cause them to be less likely
to prove to be true.
ITEM 2. PROPERTIES.
OIL AND GAS INTERESTS
The following table describes the Company's leasehold interests in developed and
undeveloped oil and gas acreage at June 30, 2001:
Total Total
----- -----
Developed Acreage (1)(2) Undeveloped Acreage (1)(2)
State Gross Net Gross Net
------ ----- --- ----- ---
Louisiana 591 248 -0- -0-
New Mexico 549 227 -0- -0-
Oklahoma 2,887 353 -0- -0-
South Dakota 160 20 -0- -0-
Texas 993 62 -0- -0-
Wyoming 2,636 1,852 36,214 36,214
----- ----- ------ ------
TOTAL 7,816 2,762 36,214 36,214
Canada 640 19 -0- -0-
(1) Gross acres are the total acreage involved in a single lease or group of
leases. Net acres represent the number of acres attributable to an owner's
proportionate working interest in a lease (e.g., a 50% working interest in a
lease covering 320 acres is equivalent to 160 net acres).
(2) The acreage figures are stated on the basis of applicable state oil and gas
spacing regulations.
6
ROYALTY INTERESTS UNDER PRODUCING PROPERTIES
At June 30, 2001, the Company held overriding royalty interests ranging from
0.013% to 9.26% in 124 producing oil and gas wells located on 6,019 gross
developed acres in the United States. The royalty interests from these wells
produce approximately 1.9 barrels of oil equivalent per day, have a PV(10) value
of approximately $69,500 and are included within the Company's Proved Developed
Producing reserves category. At June 30, 2000, the Company held overriding
royalty interests ranging from 0.013% to 9.26% in 116 producing oil and gas
wells located on 6,019 gross developed acres in the United States. At June 30,
1999, the Company also held overriding royalty interest ranging from 0.013% to
9.26% in 116 producing oil and gas wells located on 6,019 gross developed acres
in the United States. These figures are included within the Company's Proved
Developed Producing reserves category for fiscal 2001, 2000 and 1999. The
royalty interests are considered to be immaterial to the Company.
DRILLING ACTIVITIES
The Company participated in drilling eight wells since June 30, 2000. All eight
wells were development wells including the Turner 1-23 and 3-14 wells on the
Amber leasehold in Grady County, Oklahoma and six coal bed methane wells in
Campbell County, Wyoming.
Kestrel Energy, Inc. owned interests in net exploratory and net development
wells for the years ended June 30, 2001, 2000 and 1999 as set forth below. This
information does not include wells drilled under farmout agreements.
United States Australia
---------------------------- ---------------------------
6/30/01 6/30/00 6/30/99 6/30/01 6/30/00 6/30/99
Net Exploratory Wells: (1)
Dry (2) - - - - - 0.06
Productive (3) - 2.0 - - - 0.03
------- ------- ------- ------- ------- -------
- 2.0 - - - 0.09
======= ======= ======= ======= ======= =======
Net Development Wells: (1)
Dry (2) - - - - - -
Productive (3) 1.76 0.84 0.25 - - -
------ ------- ------- ------- ------- -------
1.76 0.84 0.25 - - -
====== ======= ======= ======= ======= =======
(1) A net well is deemed to exist when the sum of fractional ownership working
interests in gross wells equals one. The number of net wells is the sum of
the fractional working interests owned in gross wells expressed as whole
numbers and fractions thereof.
(2) A dry well (hole) is a well found to be incapable of producing either oil
or natural gas in sufficient quantities to justify completion as an oil or
natural gas well.
(3) Productive wells are producing wells and wells capable of production,
including wells that are shut-in.
FARMOUT AGREEMENTS
Under a farmout agreement, outside parties undertake exploration activities
using prospects owned by Kestrel. This enables the Company to participate in the
exploration prospects without incurring additional capital costs, although with
a substantially reduced ownership interest in each prospect.
During the year ended June 30, 2001, no wells were drilled under farmout
agreements.
OIL AND GAS PRODUCTION, PRICES AND COSTS
As of June 30, 2001, the Company had a royalty and/or working interest in 74
gross (10.06 net) wells that produce oil only, 51 gross (11.21 net) wells that
produce gas only, and 229 (6.62 net) wells that produce both oil and gas. All
wells that produced gas are connected to pipelines.
7
For information concerning the Company's oil and gas production, estimated oil
and gas reserves, and estimated future cash inflows relating to proved oil and
gas reserves, see Note 8 to the consolidated financial statements included in
Item 8 of this Report. The reserve estimates for the reporting year were
prepared by Sproule Associates Inc., an independent petroleum engineering firm.
The Company did not file any oil and gas reserve estimates with any federal
authority or agency during its fiscal year ended June 30, 2001.
For the year ended June 30, 2001, the Company's average operating cost
(including taxes and marketing) per barrel of oil equivalent (BOE) (converting
gas to oil at 6:1) was $11.96. The average operating cost per BOE on an
equivalent basis for fiscal years 2000 and 1999 was $7.98 and $5.46,
respectively. The average sales price per barrel of oil sold was $28.18 for
2001, $24.78 for 2000, and $10.01 for 1999. The average sales price per mcf of
gas sold was $4.75 for 2001, $2.59 for 2000, and $1.26 for 1999.
CUSTOMERS
During fiscal year 2001, the Company had two major customers: Kaiser Francis Oil
Company and Duke Energy. Sales to these customers accounted for 26% and 15%,
respectfully, of oil and gas sales in 2001. The Company does not believe that it
is dependent on a single customer. The Company has the option at most properties
to change purchasers if conditions so warrant.
OFFICE FACILITIES
The Company's executive offices are located at 999 18th Street, Suite 2490,
Denver, Colorado 80202, which is comprised of approximately 3,953 square feet,
at an annual rate of $73,900. The Company's current lease obligation expires
February 28, 2003.
ITEM 3. LEGAL PROCEEDINGS.
In the ordinary course of conducting its business, the Company becomes involved
in litigation, administrative proceedings and governmental investigations,
including environmental matters.
In May of 2000, the Company received a notice letter from the U.S. Environmental
Protection Agency (EPA) stating that the Company is a potentially responsible
party under the federal Comprehensive Environmental Response, Compensation and
Liability Act of 1980 ("CERCLA") for the Casmalia Waste Disposal Site in Santa
Barbara County, California. If the Company is ultimately determined to be a
responsible party, it may be obligated to conduct remedial investigations,
feasibility studies, remediation and/or removal of alleged releases of hazardous
substances or to reimburse the EPA for such activities.
The Company does not believe that it has any liability under CERCLA for wastes
disposed at Casmalia and believes that the EPA's notice was issued in error. The
Company has responded to the EPA, explaining that the Company did not arrange to
dispose of any waste at Casmalia. The Company's involvement with Casmalia is
limited to the purchase of assets from another entity, which disposed of waste
at Casmalia. The Company intends to defend allegations of its responsibility, if
any, and will also rely upon an indemnification given by the previous owner of
the properties at Casmalia, which previous owner has confirmed that the
indemnification would apply to any such allegations.
The Company is unable to estimate the dollar amount of exposure to loss in
connection with the above-referenced matter; however, the ultimate site-wide
clean up costs, which could be borne by the persons or entities found to be
responsible parties, have been estimated by the EPA at approximately $271.9
million.
It is the opinion of Company's management that the outcome of these proceedings,
individually or in the aggregate, will not have a material adverse effect on the
Company's financial position, results of operations, or cash flows.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
8
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
OUTSTANDING SHARES OF COMMON STOCK
The Company's common stock trades over-the-counter on the NASDAQ SmallCap Market
under the symbol "KEST." At June 30, 2001, the Company had 7,700,200 shares
outstanding. At June 30, 2001, the Company had approximately 1,300 shareholders
of record, although the Company believes that there are more beneficial owners
of its stock, the number of which is unknown.
STOCK PRICE
These quotations reflect inter-dealer prices, without retail mark-up, markdown
or commission and may not necessarily represent actual transactions.
Fiscal Year June 30, 2000 Sales Price
-----------
High Low
---- ---
First Quarter $3.25 $1.06
Second Quarter 3.25 2.00
Third Quarter 3.50 2.50
Fourth Quarter 3.62 1.75
Fiscal Year June 30, 2001 Sales Price
-----------
High Low
---- ---
First Quarter $3.43 $1.38
Second Quarter 2.41 1.56
Third Quarter 2.00 1.06
Fourth Quarter 1.89 .75
DIVIDEND POLICY
While there are no covenants or other aspects of any finance agreements or
bylaws that restrict the declaration or payment of cash dividends, the Company
has not paid any dividends on its common stock and does not expect to do so in
the foreseeable future.
9
ITEM 6. SELECTED FINANCIAL DATA.
The summary of selected financial data for the Company for its last five fiscal
years is as follows:
Years ended June 30,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
Oil and Gas Sales $ 2,195,189 $ 1,061,638 $ 632,030 $ 895,017 $ 1,278,502
Total Revenue 2,328,958 2,993,459 772,795 1,204,261 1,420,056
Net Earnings (Loss) (104,371) 943,977 (1,441,424) (2,018,692) (1,312,365)
Basic Earnings (Loss) per
Share (.01) .14 (.32) (.46) (.56)
Diluted Earnings (Loss)
Per Share (.01) .13 (.32) (.46) (.56)
At June 30,
Total Assets 12,911,302 12,270,459 4,059,234 5,560,022 7,638,626
Stockholders' Equity 10,756,633 10,806,435 3,966,297 5,398,346 7,432,443
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.
LIQUIDITY AND CAPITAL RESOURCES
Working Capital and Cash Flows: Net working capital deficit at June 30,
2001, was $1,750,853 compared to a working capital deficit of $748,831 at June
30, 2000 and positive working capital of $560,207 at June 30, 1999. The decrease
in working capital of $1,002,021 resulted from short term borrowings on the
Company's line of credit which allowed the Company to re-complete the Greens
Canyon 27-3 well and to fund the drilling of eight development wells in
Oklahoma. The Company restructured the line of credit with Wells Fargo Bank in
May 2001 and anticipates renewing that line by October 31, 2001.
The decrease in working capital was $1,309,038 for the year 2000, largely the
result of capital expenditures made by the Company to develop the Greens Canyon
Field and the related pipeline. The Company funded its working capital deficit
at June 30, 2000 by drawing on the line of credit at Wells Fargo Bank, and
utilizing additional revenues from oil and gas sales resulting from higher oil
and gas prices.
Net cash used by operating activities was $994,010 for fiscal 2001 as compared
to cash provided of $646,114 in fiscal 2000, a decrease of $1,640,124. The
decrease in operating cash flows is primarily attributable to the reduction of
accounts payable from fiscal 2000 levels.
Net cash provided by operating activities totaled $646,114 for fiscal 2000 as
compared to cash used by operating activities of $752,395 for fiscal 1999, a
change of $1,398,509. The change was primarily a result of the increase in oil
and gas revenues and in trade accounts payable, which increased as a result of
the Company's drilling and completing two Greens Canyon gas wells and a pipeline
to transport gas to market.
Net cash used by investing activities was $1,270,999 in fiscal 2001 as compared
to $6,432,902 in fiscal 2000. For the year ended June 30, 2001, $1,384,692 was
used to acquire and develop proved and unproved oil and gas interests, finish
the gas pipeline and purchase equipment. Proved property expenditures included
the re-completion of the Greens Canyon 27-3 at an approximate cost of $538,000,
the balance of the completion of the Poitevent #1 and Greens Canyon 29-2 wells
for $139,000, the drilling and completion of the Turner 1-23 and 3-14 wells in
Wyoming at a cost of $579,000, the $50,000 drilling
10
and completion of six coal bed methane wells in Wyoming and the acquisition of
additional acreage and analysis of seismic studies on various properties for
$24,000. The Company also finished its gas pipeline for $36,000 and purchased
office equipment and computers for $5,000. Unproved property acquisitions
included $14,000 to acquire various lease acreage on the Brown Ranch Prospect in
Wyoming. The Company received $22,597 from the sale of shallow rights on the
Oxbow Prospect in Wyoming and sale of a submersible pump on the Pierce Unit. The
Company also wrote off its investment in a joint venture in Farpura, recording a
loss to the Company of $9,878. The Company also received $91,096 from the sale
of 3,000,000 Victoria Petroleum, NL shares during the fiscal year ended June 30,
2001. The shares were acquired in May 2000 as part of the merger agreement
between the Company and Victoria Petroleum, NL. The sale resulted in a gain of
$3,440. The unrealized gain or loss on the Company's investment in Victoria
Petroleum, NL shares is recorded as Other Accumulated Comprehensive Income on
the Company's balance sheet as of June 30, 2001.
Net cash used by investing activities was $6,432,902 in fiscal 2000 as compared
to $775,181 provided in fiscal 1999. During the fiscal year ended June 30, 2000,
$6,728,902 was used to acquire, explore and develop proved and unproved oil and
gas property interests, construct a gas pipeline on the Greens Canyon Field, and
purchase equipment. Proved property investments included $2,937,600 to drill and
complete the Greens Canyon 27-3 well, $2,199,400 to drill and complete the
Greens Canyon 29-2 well, $100,000 to finalize completion of the Poitevent #1
well, and $470,000 to acquire additional acreage and conduct a seismic study on
the Greens Canyon Field. Approximately $25,000 was expended to continue
development in various coalbed methane wells on the Wagensen Field in Wyoming.
Additionally, the Company constructed a 17 mile gas pipeline on the Greens
Canyon Field at a cost to the Company of approximately $772,000. Unproved
property acquisitions included $202,000 to acquire lease acreage on the Fire
Hole Canyon Prospect in Wyoming and $6,500 for the continued development of the
Kaye Unit in Wyoming. The Company also spent approximately $16,400 on computers
and related software. Proceeds from the sales of property and equipment were
$296,000 for fiscal 2000 as compared to $1,000 in the previous year. The Company
received $35,000 for its entire working interest in the Sally Persons Unit in
Wyoming, and $261,000 for the Company's entire working interests in 16 wells
located on the Porcupine leasehold in Wyoming. There were no sales of short-term
investments during fiscal 2000 as compared to sales of $2,330,831 in fiscal
1999.
Net cash provided by financing activities was $1,882,000 for fiscal 2001 versus
$5,893,842 a year ago. The cash provided during fiscal 2001 came from the
Company's line of credit with Wells Fargo Bank. Under the terms of the
agreement, the Company has a revolving line of credit with a borrowing base of
$1,400,000. The Company restructured the line of credit with Wells Fargo Bank in
May 2001, which requires the Company to make scheduled principal payments to
reduce the amount outstanding to $1,400,000 by the October 31, 2001 due date.
The funds were used to existing accounts payable and capital expenditures.
Net cash provided by financing activities was $5,893,842 for fiscal 2000. The
Company completed three private offerings (described below) which provided cash
to the Company of $5,878,842 net of offering expenses. In August 1999 the
Company completed a private offering of 1,880,000 shares of its common stock at
$1.25 per share. Net proceeds to the Company were $2,299,038 after offering and
related expenses of $50,962. In December 1999 the Company completed a private
offering of 950,000 shares of its common stock at $2.70 per share. Net proceeds
to the Company were $2,532,176 after offering and related expenses of $32,824.
In April 2000 the Company completed a private offering of 374,000 shares of its
common stock at $3.00 per share. Net proceeds to the Company were $1,047,628
after offering and related expenses of $74,372. The shares sold in the offerings
were sold to offshore purchasers in accordance with SEC Regulation S but the
Company has since registered the shares with the SEC on Form S-3 for resale in
the United States. The Company also received $15,000 from the exercise of
non-qualified stock options by Company employees.
Stockholders' Equity: Stockholders' equity decreased $49,802 to
$10,756,633 from $10,806,435 a year ago. The decrease is a result of the net
loss for the year offset by common shares issued to third parties of $24,800,
director compensation from stock options of $3,338, and unrealized gain on
securities of $26,431.
Debt Obligations: The Company had no long-term debt at June 30, 2001,
2000 and 1999.
11
Reserves and Future Cash Flows: For the fiscal year ended June 30, 2001,
the Company's proved oil reserves decreased approximately 32,000 bbls. to
356,000 bbls., or 8%, from 388,000 in 2000. The Company's proved gas reserves
decreased 11,133 Mmcf to 13,384 Mmcf, or 45%, from 24,517 Mmcf in 2001. The
decrease in proved reserves is primarily attributable to a reduction in the
go-forward working interest in the Company's greens canyon project from 100% to
30%. Accordingly, a significant reduction in gas reserve of 10.34 bcf was
recorded. Additionally, the poor performance of the Greens Canyon field during
the year resulted in a further reduction of 1.88 bcf of proved gas reserves,
which was offset, in part, by an increase in reserves of 1.1 bcf principally
from 2 additional wells at the Amber Northeast field in Grady County, Oklahoma.
The Company's undiscounted net future cash flows have been estimated by Sproule
Associates Inc., an independent petroleum engineering firm, to be approximately
$27,647,000 as of June 30, 2001. This compares to $70,983,000 in 2000 and
$8,862,000 in 1999. The decrease in the current year is the result of revisions
of previous quantity estimates, new discoveries and extensions and lower oil and
gas prices.
Gas Balancing: The Company at June 30, 2001 was under-produced by
approximately 22,245 Mcf. The Company at June 30, 2000 was underproduced by
approximately 5,828 Mcf. At June 30, 1999, the Company was underproduced
approximately 6,234 Mcf. These amounts are reflected in the reserves and
estimated net future cash flows.
Natural Gas Sales Contracts: The Company's gas production is generally
sold under short term contracts with pricing set on current spot markets with
adjustments for marketing and transportation costs. All contracts are cancelable
within 30-90 days notice by the Company. The Company has no contracts that are
based on a fixed natural gas price.
Net Operating Loss and Tax Credit Carryforwards: At June 30, 2001, the
Company estimated that, for United States federal income tax purposes, it had
consolidated net operating loss carryforwards of approximately $9,171,000. The
utilization of approximately $496,000 of these carryforwards are limited to an
estimated $80,000 annually. Of the balance of the loss carryforwards, $1,497,000
is limited to the extent of future taxable income generated by the Company's
subsidiary, Victoria Exploration, Inc., and $7,178,000 is available to offset
any future taxable income of the Company. If not utilized, the net operating
loss carryforwards will expire during the period from 2002 through 2021.
RESULTS OF OPERATIONS
FISCAL 2001 VS. FISCAL 2000
Net Earnings: The Company reported a net loss of $104,371 in fiscal 2001
compared to net earnings of $943,977 in 2000, which was a decrease of
$1,048,348. The net loss in fiscal 2001 is attributable to higher abandonment
and impaired expenses, higher depreciation and depletion expenses and higher
interest expense despite significantly higher oil and gas revenues.
Revenue: Total revenues decreased in fiscal 2001 by $664,501, or 22%, to
$2,328,958 versus $2,993,459 in 2000. The decrease in revenues was a result of
substantially lower gain on sale of assets which declined $1,799,859. Excluding
a $1,594,929 gain on one-time sale of assets to an affiliate for shares of the
affiliate's stock in fiscal 2000, year over year revenues were up $930,428. This
increase in revenues was a result of significantly higher oil and gas revenues
as discussed below.
Revenue from oil and gas sales increased $1,134,181, or 107%, to $2,195,819 from
$1,061,638 a year ago. The increase in revenues was a result of higher oil and
gas prices despite lower sales volumes for oil. Average prices per barrel of oil
increased 14% to $28.18 from $24.78 a year ago. Average prices received per Mcf
of gas increased 83% to $4.75 from $2.59 a year ago. Sales volumes for oil
decreased 6% to 18,688 from 19,939 a year ago. Sales volumes for gas increased
61% to 350 Mmcf from 218 Mmcf a year ago. The increase in gas volumes can be
attributed to the completion of the Turner 1-23 and 3-14 wells and the coal bed
methane wells.
The Company recorded gain on sale of property and equipment of $16,159. The
Company sold the shallow rights on the Oxbow Prospect for $7,972 and sold a
submersible pump on the Pierce Unit for $14,625 and wrote off its cost of $9,878
in an international joint venture which dissolved in fiscal 2001. The Company
also sold 3,000,000 shares of common stock of Victoria Petroleum, NL in the
fourth quarter
12
of fiscal 2001. The common stock was acquired as part of the merger with
Victoria Petroleum, NL in May of 2000. The Company received $91,096 in proceeds
from the sale and recorded a gain of $3,440.
Other income rose $46,213 to $111,141 from $64,928 a year ago. The increase is
attributable to overhead charges to a related party for the use of the Company's
office space and personnel.
Lease Operating Expenses: Lease operating expenses increased $471,447, or
105%, to $920,692 from $449,245 a year ago. The caption "Lease Operating
Expenses" includes not only the direct costs of operating a well, but workover
costs and production taxes. Direct lease expense increased 100% to $575,296 from
$287,956 a year ago. Workover costs increased 180% to $151,390 from $53,993 last
year. Production taxes increased 81% to $194,006 from $107,296 a year ago. The
increase in direct lease expenses is attributable to the addition of eight new
wells, initial expenses on the Greens Canyon wells and higher lease expenses on
the Pierce and Grady Units in Wyoming. The increase in workover expenses is
attributable to the workover conducted on the Pierce Unit in Wyoming and the
Burditt #1 well in Texas. The increase in production taxes was a result of
higher oil and gas revenues and higher gas volumes. Lease operating costs on a
BOE (barrel of oil equivalent) increased 50% to $11.96 from $7.98 a year ago.
Exploration Expenses: Exploration expenses decreased $289,444, or 74%, to
$101,131 from $390,575 in 2000. The decrease in exploration expense reflected
the slower pace of the Company's exploration program during fiscal 2001 as the
Company's emphasis has been on the development of the Greens Canyon Field. The
decrease was a result of lower geological and geophysical costs as well as lower
delay rentals paid on exploration acreage.
Dry Holes, Abandoned and Impaired Properties: Dry holes, abandoned and
impaired property costs were $101,459 in fiscal 2001 as compared to $25,125 a
year ago, an increase of $76,334, or 304%. No dry hole costs were recorded for
fiscal 2001 or 2000. Abandonment costs increased 100% to $29,000 for fiscal
2001. The Company abandoned the Pinon Ridge Prospect in Colorado. Impairment
expenses increased $47,334 or 188% to $72,459 from $25,125 a year ago. The
impairment was a result of the anaylsis of the Company's properties as required
by SFAS 121.
General and Administrative Expense: General and administrative expenses
decreased $187,499, or 17%, to $898,430 as compared to $1,086,551 a year ago.
The decrease in general and administrative expenses is attributable to lower
company personnel costs as well as lower legal and accounting expenses. The
Company continues to review ways to reduce overhead expenses as a result of the
current oil and gas pricing structure.
Interest Expense: Interest expense totaled $126,907 for the fiscal year
ended June 30, 2001. The interest is attributable to the line of credit the
Company has with Wells Fargo Bank.
RESULTS OF OPERATIONS
FISCAL 2000 VS. FISCAL 1999
Net Earnings: The Company reported net earnings of $943,977 in fiscal
2000 compared to a loss of $1,441,424 in 1999, which was a decrease of
$2,385,401. The net earnings in fiscal 2000 was attributable to a gain on sale
of property and equipment and significantly higher oil and gas revenues as a
result of higher oil and gas prices.
Revenue: Total revenues increased in fiscal 2000 by $2,220,664, or 287%,
to $2,993,459 versus $772,795 in 1999. The increase in overall revenues was a
result of higher oil and gas revenues due to higher oil and gas prices, and
higher gain on sale of property and equipment as described more fully below.
Revenue from oil and gas sales increased $429,608, or 68%, to $1,061,638 from
$632,030 in 1999. The increase in revenues was a result of higher oil and gas
prices despite lower sales volumes for oil and gas. Average prices per barrel of
oil increased 148% to $24.78 from $10.01 in 1999. Average prices received per
Mcf of gas increased 106% to $2.59 from $1.26 a year ago. Sales volumes for oil
decreased 18% to 19,939 from 24,319 in 1999. Sales volumes for gas decreased 29%
to 218 Mmcf from 308 Mmcf in 1999.
13
The Company recorded gains on sale of equipment and property of $1,816,018 in
2000 versus a loss of $788 in 1999. On May 5, 2000, the Company sold six
international permits with a net book value of approximately $143,179 for
petroleum drilling in Western Australia and New Guinea to Victoria Petroleum
USA, Inc. (VP/USA), a Colorado corporation and wholly owned subsidiary of VP, in
exchange for 8,250,000 shares of VP Common Stock. The stock was valued at
$0.0292/share and resulted in a gain on the sale of $97,721. Also, on May 5,
2000, KEC, VP, and VP/USA entered into an Agreement and Plan of Merger (Merger
Agreement). Pursuant to the Merger Agreement, on May 12, 2000, the Company, as
sole shareholder of KEC, acquired 66,750,000 shares of VP common stock and
VP/USA acquired all of the issued and outstanding share of KEC through a merger
of KEC with and into VP/USA, with KEC as the surviving corporation. The stock
was valued at $0.292/share and resulted in a gain on sale of $1,497,208. The
Company sold its entire interest in the Sally Persons Unit, located in Wyoming,
for $35,000, which resulted in a gain on sale of $27,836. Additionally, the
Company sold its entire working interests in 16 wells located in the Porcupine
Field, Wyoming for $261,000 which resulted in a gain on sale of $193,254.
Lease Operating Expenses: Lease operating expenses increased $36,617, or
9%, to $449,245 from $412,628 in 1999. The increase in lease operating expense
is attributable to higher production taxes resulting from the increase in oil
and gas revenues despite lower operating costs on various properties. Lease
operating costs on a BOE (barrel of oil equivalent) increased 46% to $7.98 from
$5.46 in 1999 as a result of lower sales volumes of oil and gas.
Exploration Expenses: Exploration expenses decreased $69,761, or 15%, to
$390,575 from $460,336 in 1999. The decrease in exploration expense reflected
the slower pace of the Company's exploration program during fiscal 2000 as the
Company's emphasis has been on the development of the Greens Canyon Field. The
decrease was a result of lower geological and geophysical costs as well as lower
delay rentals paid on exploration acreage.
Dry Holes, Abandoned and Impaired Properties: Dry holes, abandoned and
impaired property costs were $25,125 in fiscal 2000 as compared to $388,612 in
1999, a decrease of $363,487, or 94%. No dry hole costs were recorded in fiscal
2000 versus $144,515 in 1999. The decrease in dry hole costs reflected the
Company's successful drilling efforts on the Greens Canyon Field during fiscal
2000. Abandonment costs decreased $17,857, or 100% from fiscal 1999. Impairment
expense decreased $201,115, or 89%, to $25,125 from $226,240 in 1999. The
Company recorded impairment expense of $25,125 related to various international
permits prior to their sale.
General and Administrative Expense: General and administrative expenses
increased $308,322, or 40%, to $1,086,551 as compared to $778,229 in 1999. The
increase in general and administrative expenses is attributable to higher
company personnel costs as well as higher legal and accounting expenses. Company
personnel costs rose as a direct result of the increase in the Company's
development of the Greens Canyon Field. Legal and accounting costs increased as
a result of the Company expensing previously incurred legal and accounting fees
associated with the potential listing of the Company's stock on the Australian
Stock Exchange, the Company's warrant dividend issue in January 2000, and the
merger with VP in May 2000.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Until fiscal 2000, the Company did not invest in or hold market risk sensitive
or interest rate sensitive instruments and the only currency exchange rate risk
borne by the Company stemmed from the Company's obligations to fund its
international drilling in foreign currencies. During the fiscal year ended June
30, 2000, the Company received 75,000,000 shares of VP Common Stock as a result
of the merger and sale of international permits discussed above. (See
Management's Discussion and Analysis-Results of Operations--Fiscal 2000 vs.
Fiscal 1999.) The investment in VP Common Stock is classified as
available-for-sale. Net unrealized gains and losses on the investment are
recorded to other comprehensive income or loss. At June 30, 2001 the unrealized
gain on the investment was $26,431. The Common Stock of VP was trading for $.058
cents per share in Australian dollars as of June 30, 2001. The Company applies
the exchange rate between the U.S. dollar and Australian dollar as quoted in the
Wall Street Journal. On June 30, 2001, the exchange rate in dollar terms was
$.5101 which resulted in a U.S. dollar share price of $.0296 cents per share.
The Company sold 3,000,000 shares of VP Stock in June 2001 which provided
$91,096 in proceeds to the Company and a corresponding gain on sale of $3,440
was recorded.
14
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
See pages F-1 through F-18 for this information.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE.
None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information required herein is incorporated by reference from the
Company's definitive proxy statement for the 2001 annual meeting of
shareholders.
ITEM 11. EXECUTIVE COMPENSATION.
The information required herein is incorporated by reference from the
Company's definitive proxy statement for the 2001 annual meeting of
shareholders.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information required herein is incorporated by reference from the
Company's definitive proxy statement for the 2001 annual meeting of
shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information required herein is incorporated by reference from the
Company's definitive proxy statement for the 2001 annual meeting of
shareholders.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) Exhibits
Exhibit No. Description
----------- -----------
3.1 Amended and Restated Articles of Incorporation, as
filed with the Secretary of State of Colorado on
March 16, 1995, filed as Exhibit (3)1 to the Annual
Report on Form 10-K/A for the fiscal year ended
June 30, 1994 and incorporated herein by reference.
3.2 Amended and Restated Bylaws, as adopted by the Board
of Directors on January 16, 1995, filed as
Exhibit (3)2 to the Annual Report on Form 10-K/A for
the fiscal year ended June 30, 1994 and incorporated
herein by reference.
4.1 The form of common stock share certificate filed as
Exhibits 5.1 to the Registrant's Form S-2 Registration
Statement (No. 2-65317) and Article II of the
Registrant's Articles of Incorporation filed as
Exhibit 4.1 thereto, as amended on March 4, 1994 and
filed with the Annual Report on Form 10-K for the
fiscal year ended June 30, 1994 are incorporated
herein by reference.
4.2 Warrant Agreement dated January 18, 2000 with American
Securities Transfer & Trust, Inc. filed as Exhibit 4.1
to the Registrant's Form 8-A Registration Statement
filed January 20, 2000 and incorporated herein by
reference.
15
4.3 Form of Warrant Certificate filed as Exhibit 4.2 to
the Registrant's Form 8-A Registration Statement filed
January 20, 2000 and incorporated herein by reference.
10.1 Amended and Restated Incentive Stock Option Plan as
amended March 14, 1995 and filed as Exhibit 10.7 with
the Annual Report on Form 10-K for the fiscal year
ended June 30, 1995 and incorporated herein by
reference.
10.2 Kestrel Energy, Inc. Stock Option Plan as amended
December 19, 2000 and January 3, 2001 and filed as
Exhibit 4 to the Registrant's Form S-8 Registration
Statement (No. 333-68086) and incorporated herein by
reference.
10.3 Line of Credit with Norwest Bank, Colorado National
Association dated February 21, 2000 as Exhibit 10.1 to
the Registrant's Form 10-Q for the period ended
March 31, 2000 and incorporated herein by reference.
10.4 Articles of Merger for Kestrel Energy California, Inc.
and Victoria Petroleum USA, Inc. filed as Exhibit 10.2
to the Registrant's Form 10-Q for the period ended
March 31, 2000 and incorporated herein by reference.
10.5 Letter Amendment to Wells Fargo Bank West, N.A.
Agreement dated September 27, 2000 filed as Exhibit 10
to the Registrant's Form 10-Q for the period ended
September 30, 2000 and incorporated herein by
reference.
10.6* Articles of Merger for Victoria Exploration, Inc.
23.1* Consent of KPMG LLP
23.2 Consent of Sproule Associates Inc.
99.1 Certification of President and Principal Financial
Officer
* Previously filed
(b) Financial Statements.
Independent Auditors' Report F-1
Consolidated Balance Sheets F-2
Consolidated Statements of Operations F-3
Consolidated Statements of Stockholders' Equity F-4
Consolidated Statements of Cash Flows F-5
Notes to Consolidated Financial Statements F-6
(c) Reports on Form 8-K.
None
16
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
KESTREL ENERGY, INC.
(Registrant)
Date: January 28, 2003
By: /s/ BARRY D. LASKER
-------------------------------
Barry D. Lasker, President,
Chief Executive Officer,
Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.
Date: January 28, 2003 By: /s/ BARRY D. LASKER
-------------------------------
Barry D. Lasker, President,
Chief Executive Officer,
Chief Financial Officer
Date: January 28, 2003 By: /s/ ROBERT J. PETT
-------------------------------
Robert J. Pett, Chairman of
the Board
Date: January 28, 2003 By: /s/ KENNETH W. NICKERSON
-------------------------------
Kenneth W. Nickerson, Director
Date: January 28, 2003 By: /s/ JOHN T. KOPCHEFF
-------------------------------
John T. Kopcheff, Director
Date: January 28, 2003 By: /s/ MARK A. E. SYROPOULO
-------------------------------
Mark A. E. Syropoulo, Director
Date: January 28, 2003 By: /s/ TIMOTHY L. HOOPS
-------------------------------
Timothy L. Hoops, Director
Date: ________________ By:
-------------------------------
Neil T. MacLachlan, Director
17
CERTIFICATION
I, Barry D. Lasker, certify that:
1. I have reviewed this Annual Report on Form 10-K/A of Kestrel Energy,
Inc.;
2. Based on my knowledge, this Annual Report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this Annual
Report; and
3. Based on my knowledge, the financial statements, and other financial
information included in this Annual Report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods represented by this Annual Report.
Date: January 28, 2003
/s/ BARRY D. LASKER
------------------------
Barry D. Lasker
President, Chief Executive Officer and
Principal Financial Officer
18
KESTREL ENERGY, INC.
AND SUBSIDIARIES
Consolidated Financial Statements
June 30, 2001 and 2000
(With Independent Auditors' Report Thereon)
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Kestrel Energy, Inc.:
We have audited the accompanying consolidated balance sheets of Kestrel Energy,
Inc. and subsidiaries as of June 30, 2001 and 2000, and the related consolidated
statements of operations and comprehensive income, stockholders' equity and cash
flows for each of the years in the three-year period ended June 30, 2001. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Kestrel Energy, Inc.
and subsidiaries as of June 30, 2001 and 2000, and the results of their
operations and their cash flows for each of the years in the three-year period
ended June 30, 2001, in conformity with accounting principles generally accepted
in the United States of America.
Denver, Colorado
September 14, 2001
F-1
KESTREL ENERGY, INC.
AND SUBSIDIARIES
Consolidated Balance Sheets
June 30, 2001 and 2000
ASSETS 2001 2000
----- -----
Current assets:
Cash and cash equivalents $ 119,025 $ 502,034
Accounts receivable 278,834 181,075
Related party receivable -- 524
Other current assets 5,957 31,560
-------------- --------------
Total current assets 403,816 715,193
-------------- --------------
Property and equipment, at cost:
Oil and gas properties, successful
efforts method of accounting (note 8):
Unproved 217,941 353,027
Proved 12,398,775 10,933,518
Pipeline and facilities 807,851 772,164
Furniture and equipment 143,724 138,970
-------------- --------------
13,568,291 12,197,679
Accumulated depreciation and depletion (3,190,983) (2,833,816)
-------------- --------------
Net property and equipment 10,377,308 9,363,863
-------------- --------------
Investment in related party (note 2) 2,130,178 2,191,403
-------------- --------------
$ 12,911,302 $ 12,270,459
============== ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade $ 121,464 1,419,429
Related party 26,397 9,399
Accrued liabilities 124,808 35,196
Line of credit, bank (note 3) 1,882,000 -
-------------- --------------
Total current liabilities 2,154,669 1,464,024
-------------- --------------
Stockholders' equity (note 4):
Preferred stock, $1 par value. 1,000,000 shares
authorized; none issued - -
Common stock, no par value. 20,000,000 shares
authorized; 7,700,200 and 7,680,000 shares
issued and outstanding at
June 30, 2001 and 2000, respectively 19,073,023 19,044,885
Accumulated other comprehensive income 26,431 -
Accumulated deficit (8,342,821) (8,238,450)
-------------- --------------
Total stockholders' equity 10,756,633 10,806,435
-------------- --------------
Commitments (notes 3 and 6)
$ 12,911,302 $ 12,270,459
============== ==============
See accompanying notes to consolidated financial statements.
F-2
KESTREL ENERGY, INC.
AND SUBSIDIARIES
Consolidated Statements of Operations and Comprehensive Income
Years ended June 30, 2001, 2000 and 1999
2001 2000 1999
----- ----- -----
Revenue:
Oil and gas sales $ 2,195,819 1,061,638 632,030
Gain (loss) on sale of
property and equipment 12,719 1,816,018 (788)
Gain on sale of
available-for-sale securities 3,440 -- --
Interest income 5,839 50,875 76,490
Other, net 111,141 64,928 65,063
----------- ----------- -----------
Total revenue 2,328,958 2,993,459 772,795
----------- ----------- -----------
Costs and expenses:
Lease operating expenses 920,692 449,245 412,628
Dry holes, abandoned and
impaired properties 101,459 25,125 388,612
Exploration expenses 101,131 390,575 460,336
Depreciation and depletion 284,710 97,986 174,414
General and administrative 898,430 1,086,551 778,229
Interest expense 126,907 -- --
------------ ----------- -----------
Total costs and expenses 2,433,329 2,049,482 2,214,219
------------ ----------- -----------
Net earnings (loss) (104,371) 943,977 (1,441,424)
Other comprehensive income (loss)-
unrealized gain (loss) from
available-for-sale securities 26,431 -- -
------------ ----------- -----------
Comprehensive income
(loss) $ (77,940) 943,977 (1,441,424)
============ =========== ===========
Basic earnings (loss) per share $ (.01) 0.14 (0.32)
============ =========== ===========
Diluted earnings (loss) per share $ (0.01) 0.13 (0.32)
============ =========== ===========
Weighted average number of
common shares outstanding 7,684,110 6,787,104 4,451,833
============ =========== ===========
See accompanying notes to consolidated financial statements.
F-3
KESTREL ENERGY, INC.
AND SUBSIDIARIES
Consolidated Statements of Stockholders' Equity
Years ended June 30, 2001, 2000 and 1999
Accumulated
Common stock other Total
----------------------------- Accumulated comprehensive stockholders'
Shares Amount deficit income equity
------------ ------------- ------------ ---------------- -------------
Balance June 30, 1998 4,431,000 $ 13,139,349 (7,741,003) -- 5,398,346
Shares issued for property 25,000 9,375 - -- 9,375
Net loss -- -- (1,441,424) -- (1,441,424)
------------ ------------ ------------ ------------ ------------
Balance June 30, 1999 4,456,000 13,148,724 (9,182,427) -- 3,966,297
Common shares issued, net of offering
costs of $158,158 (note 4) 3,204,000 5,878,842 -- -- 5,878,842
Exercise of stock options (note 4) 20,000 15,000 -- -- 15,000
Stock options issued as compensation -- 2,319 -- -- 2,319
Net earnings -- -- 943,977 -- 943,977
------------ ------------ ------------ ------------ ------------
Balance June 30, 2000 7,680,000 19,044,885 (8,238,450) -- 10,806,435
Adjustment for previously issued
and unrecorded shares (note 4) 200 -- -- -- --
Common shares issued (note 4) 20,000 24,800 -- -- 24,800
Stock options issued as compensation -- 3,338 -- -- 3,338
Unrealized gain on securities
classified as available for sale -- -- -- 26,431 26,431
Net loss -- -- (104,371) -- (104,371)
------------ ------------ ----------- ------------ ------------
Balance June 30, 2001 7,700,200 $ 19,073,023 (8,342,821) 26,431 10,756,633
============ ============ =========== ============ ============
See accompanying notes to consolidated financial statements.
F-4
KESTREL ENERGY, INC.
AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years ended June 30, 2001, 2000 and 1999
2001 2000 1999
-------- -------- --------
Cash flows from operating activities:
Net earnings (loss) $ (104,371) 943,977 (1,441,424)
Adjustments to reconcile net income (loss)
to net cash provided (used)
by operating activities:
Depreciation and depletion 284,710 97,986 174,414
Abandoned and impaired properties 101,459 -- 244,097
Gain on sale of available-for-sale
securities (3,440) -- --
Loss (gain) on sale of property
and equipment (12,719) (1,816,018) 788
Noncash compensation expense for
stock options issued 3,338 2,319 --
Changes in operating assets and
liabilities, net of dispositions:
(Increase) decrease in accounts
receivable (97,759) (70,195) 55,688
(Increase) decrease in related
party receivables 524 59,482 333,169
(Increase) decrease in other
current assets 25,603 55,476 (50,388)
Increase (decrease) in accounts
payable - trade (1,297,965) 1,378,036 (92,237)
Increase (decrease) in accounts
payable - related party 16,998 (10,773) 20,172
Increase (decrease) in accrued
liabilities 89,612 5,824 3,326
------------ ------------ ------------
Net cash provided (used) by
operating activities (994,010) 646,114 (752,395)
------------ ------------ ------------
Cash flows from investing activities:
Capital expenditures (1,384,692) (6,728,902) (1,556,650)
Proceeds from sale of securities 91,096 -- 2,330,831
Proceeds from sales of property
and equipment 22,597 296,000 1,000
------------ ------------ ------------
Net cash provided (used) by
investing activities (1,270,999) (6,432,902) 775,181
------------ ------------ ------------
Cash flows from financing activities:
Net proceeds from line of credit 1,882,000 -- --
Proceeds from issuance of common stock,
net of offering costs -- 5,878,842 --
Proceeds from exercise of stock options -- 15,000 --
------------ ------------ -----------
Net cash provided by financing
activities 1,882,000 5,893,842 --
------------ ------------ ------------
Net increase (decrease) in
cash and cash equivalents (383,009) 107,054 22,786
Cash and cash equivalents, beginning of year 502,034 394,980 372,194
------------ ----------- ------------
Cash and cash equivalents, end of year $ 119,025 502,034 394,980
============ =========== ============
Supplemental cash flow information -- cash
paid for interest $ 113,084 -- --
============ =========== ============
Supplemental disclosure of noncash
investing activities:
Common stock issued for property
and equipment $ 24,800 -- --
============ =========== ============
Unrealized holding gain on
available-for-sale securities $ 26,431 -- --
============ =========== ============
See accompanying notes to consolidated financial statements.
F-5
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) ORGANIZATION
Kestrel Energy, Inc. (the Company) was incorporated under the laws of
the State of Colorado on November 1, 1978. The Company's principal
business is the acquisition, either alone or with others, of interests
in proved developed producing oil and gas leases, and exploratory and
development drilling.
The Company presently owns oil and gas interests in the states of
Louisiana, New Mexico, Oklahoma, South Dakota, Texas and Wyoming.
Victoria Petroleum N. L. (VP) owns 18% of the common shares of the
Company and the Company owns 15% of VP at June 30, 2000.
(b) PRINCIPLES OF CONSOLIDATION
Up until June 22, 2001, the consolidated financial statements included
the accounts of the Company and its wholly owned subsidiary, Victoria
Exploration, Inc. (Victoria). All significant intercompany accounts and
transactions have been eliminated in consolidation.
On June 22, 2001 (the Effective Date), the Company filed Articles of
Merger of Victoria Exploration, Inc. into Kestrel Energy, Inc. pursuant
to Section 7-111-104 of the Colorado Revised Statutes. In accordance
with the agreement, on the Effective Date, Victoria ceased to exist and
Kestrel Energy, Inc. became the surviving corporation.
(c) ESTIMATES
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets
and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
(d) CASH EQUIVALENTS
Cash equivalents consist of money market funds. For purposes of the
consolidated statements of cash flows, the Company considers all highly
liquid investments with original maturities of three months or less to
be cash equivalents.
(e) PROPERTY AND EQUIPMENT
The Company follows the successful efforts method of accounting for its
oil and gas activities. Accordingly, costs associated with the
acquisition, drilling and equipping of successful exploratory wells are
capitalized. Geological and geophysical costs, delay and surface
rentals and drilling costs of unsuccessful exploratory wells are
charged to expense as incurred. Costs of drilling development wells,
both successful and unsuccessful, are capitalized. Upon the sale or
retirement of oil and gas properties, the cost thereof and the
accumulated depreciation or depletion are removed from the accounts and
any gain or loss is credited or charged to operations.
Depreciation and depletion of capitalized oil and gas properties is
computed on the units-of-production method by individual fields as the
related proved reserves are produced. A reserve
F-6
is provided for estimated future costs of site restoration,
dismantlement, and abandonment activities, net of residual salvage
value, as a component of depletion.
Pipeline and facilities are stated at original cost. Depreciation of
pipeline and facilities is provided on a straight-line basis over the
estimated useful life of the pipeline of twenty years.
Furniture and equipment are depreciated using the straight-line method
over estimated lives ranging from three to seven years.
Management periodically evaluates capitalized costs of unproved
properties and provides for impairment, if necessary, through a charge
to operations.
Proved oil and gas properties are assessed for impairment on a
field-by-field basis. If the net capitalized costs of proved properties
exceeds the estimated undiscounted future net cash flows from the
property, a provision for impairment is recorded to reduce the carrying
value of the property to its estimated fair value. The Company recorded
a provision for impairment of its proved oil and gas properties of
approximately $101,000 and $25,000 for the years ended June 30, 2001
and 2000, respectively.
(f) GAS BALANCING
The Company uses the sales method of accounting for gas balancing of
gas production. Under this method, all proceeds from production
credited to the Company are recorded as revenue until such time as the
Company has produced its share of related reserves. Thereafter,
additional amounts received are recorded as a liability.
As of June 30, 2001 and 2000, the Company is in an under-produced
position of approximately 22,245 MCFs and 5,828 MCFs, respectively.
Accordingly, these amounts have been included in the reserve quantities
as set forth in note 8.
(g) INCOME TAXES
The Company accounts for income taxes under the provisions of Statement
of Financial Accounting Standards No. 109 (SFAS No. 109), Accounting
for Income Taxes. Under the asset and liability method of SFAS No. 109,
deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their
respective tax bases and operating loss and tax credit carryforwards.
Deferred tax assets and liabilities are measured using enacted income
tax rates expected to apply to taxable income in the years in which
those differences are expected to be recovered or settled. Under SFAS
No. 109, the effect on deferred tax assets and liabilities of a change
in income tax rates is recognized in the results of operations in the
period that includes the enactment date.
(h) STOCK-BASED COMPENSATION
In October 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 123, Accounting for
Stock-Based Compensation (SFAS 123), effective for fiscal years
beginning after December 15, 1995. This statement defines a fair value
method of accounting for employee stock options and encourages entities
to adopt that method of accounting for its stock compensation plans.
SFAS 123 allows an entity to continue to measure compensation costs for
these plans using the intrinsic value based method of accounting as
prescribed in Accounting Pronouncement Bulletin Opinion No. 25,
Accounting for Stock Issued to Employees (APB 25). The Company has
elected to continue to account for
F-7
its employee stock compensation plans as prescribed under APB 25. The
pro forma disclosures of net loss and loss per share required by SFAS
123 are included in note 2.
(i) EARNINGS (LOSS) PER SHARE
Basic earnings (loss) per share is based on the weighted average number
of common shares outstanding during the period.
Diluted earnings (loss) per share is computed by adjusting the weighted
average number of common shares outstanding for the dilutive effect, if
any, of stock options and warrants.
The following sets forth the calculation of basic and diluted earnings
(loss) per common share for the years ended June 30:
2001 (1) 2000 (2) 1999 (3)
---------- ---------- -----------
Net earnings (loss) $ (104,371) 943,977 (1,441,424)
========== ========== ===========
Weighted average common shares
outstanding during the period 7,684,110 6,787,104 4,451,833
Add dilutive effects of -
employee options -- 408,174 --
---------- ---------- -----------
Weighted average common shares
outstanding during the period
including the effects of
dilutive securities 7,684,110 7,195,278 4,451,833
========== ========== ==========
Basic earnings (loss) per common
share $ (0.01) 0.14 (0.32)
========== ========== ===========
Diluted earnings (loss) per
common share $ (0.01) 0.13 (0.32)
========== ========== ===========
F-8
(1) At June 30, 2001, all outstanding options were excluded from the
computation of diluted loss per share for the year ended June 30,
2001. The effect of the assumed exercises of these options was
antidilutive.
(2) At June 30, 2000, options to purchase 40,000 shares of common stock
at prices ranging from $8.38 to $25.00 per share were outstanding,
but were not included in the computation of diluted earnings per
share for the year ended June 30, 2000. The exercise prices of
these options were greater than the average market price of the
common shares.
(3) At June 30, 1999, all outstanding options were excluded from the
computation of diluted loss per share for the year ended June 30,
1999. The effect of the assumed exercises of these options was
antidilutive.
(j) RECENTLY ISSUED ACCOUNTING STANDARDS AND PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board issued SFAS No.
141, Business Combinations, and SFAS No. 142, Goodwill and Other
Intangible Assets and approved for issuance SFAS No. 143, Accounting
for Asset Retirement Allocations. SFAS No. 141 requires that the
purchase method of accounting be used for all business combinations
initiated or completed after June 30, 2001. SFAS No. 141 also
specifies criteria that intangible assets acquired in a purchase
method business combination must be recognized and reported apart from
goodwill. The adoption of SFAS No. 141 as of July 1, 2001 will have no
impact on Kestrel's 2001 financial statements.
SFAS No. 142 requires that goodwill no longer be amortized, but instead
tested for impairment at least annually in accordance with the
provisions of SFAS No. 142. Any goodwill and any intangible asset
determined to have an indefinite useful life that are acquired in a
purchase business combination completed after June 30, 2001 will not be
amortized, but will be evaluated for impairment in accordance with the
appropriate existing accounting literature. Goodwill and intangible
assets acquired in business combinations completed before July 1, 2001
will continue to be amortized prior to the adoption of SFAS No. 142.
The adoption of SFAS No. 142 will have no impact on Kestrel's 2001
financial statements.
SFAS No. 143 requires entities to record the fair value of a liability
for an asset retirement obligation in the period in which it is
incurred and a corresponding increase in the carrying amount of the
related long-lived asset and is effective for fiscal years beginning
after June 15, 2002. The Company is currently assessing the impact SFAS
No. 143 will have on its financial condition and results of operations.
(k) RECLASSIFICATION
Certain amounts in the 2000 financial statements have been reclassified
to conform to the 2001 financial statement presentation.
F-9
(2) INVESTMENT IN RELATED PARTY
On May 5, 2000, the Company sold six international permits with a net book
value of $143,179 for petroleum drilling in Western Australia and New
Guinea to Victoria Petroleum USA, Inc. (VP/USA), a Colorado corporation and
wholly owned subsidiary of VP, in exchange for 8,250,000 shares of VP
Common Stock. The stock was valued at $0.029 per share and resulted in a
gain on the sale of $97,721. The investment is recorded at cost.
Also, on May 5, 2000, KEC, VP and VP/USA entered into an Agreement and Plan
of Merger (Merger Agreement). Pursuant to the Merger Agreement, on May 12,
2000, the Company, as sole shareholder of KEC, acquired 66,750,000 shares
of VP common stock and VP/USA acquired all of the issued and outstanding
shares of KEC through a merger of KEC into VP/USA, with KEC as the
surviving corporation. The stock was valued at $0.029 per share and
resulted in a gain on the sale of $1,497,208, based upon sales of other
assets totaling $242, accounts payable totaling $2,000, and property and
equipment with a net book value of $454,899. The investment is recorded at
cost.
As a result of the above transactions, the Company owns 15% of VP at
June 30, 2001.
(3) LINE OF CREDIT
On February 21, 2000, the Company entered into a $2,000,000 Line of Credit
agreement with Wells Fargo Bank, formerly Norwest Banks Colorado, N.A.,
which provided the Company with an initial borrowing base of $600,000,
based on reserves with interest at Wells Fargo's prime rate plus 2.5%. On
September 27, 2000, the Company and Wells Fargo amended the Line of Credit
Agreement to provide the Company with a borrowing base of $2,000,000 and
reduced the interest rate to 1.5% over the Wells Fargo prime rate. On May
31, 2001, Wells Fargo reduced the borrowing base to $1,400,000. As a result
of the reduction to the borrowing base, the Company is required to make
scheduled principal payments to reduce the amount outstanding to $1,400,000
by October 31, 2001, the maturity date of the line of credit. The line of
credit is secured by Deeds of Trust on various oil and gas producing
properties held by the Company. As of June 30, 2001, $1,882,000 was
outstanding on the line of credit.
(4) STOCKHOLDERS' EQUITY
(a) PREFERRED STOCK
The Company is authorized to issue up to 1 million shares of $1 par
value preferred stock, the rights and preferences of which are to be
determined by the Board of Directors at or prior to the time of
issuance.
(b) COMMON STOCK
In September 1998, the Company acquired oil and gas properties by
issuing 25,000 shares of common stock valued at $9,375.
In August 1999, the Company completed a private offering of 1,880,000
shares of its common stock at $1.25 per share. Net proceeds to the
Company were $2,299,038 after offering and related expenses of $50,962.
In December 1999, the Company completed a private offering of 950,000
shares of its common stock at $2.70 per share. Net proceeds to the
Company were $2,532,176 after offering and related expenses of $32,824.
F-10
On January 18, 2000, the Board of Directors of the Company declared a
dividend distribution of 10 Warrants for every 100 shares of
outstanding common stock of the Company held of record by the
shareholders at the close of business on February 4, 2000 (record
date). The Warrant Certificates were only issued in increments of 10
Warrants based upon a rounding of individual shareholders' record
holdings. No Warrants were issued to shareholders holding less than 100
shares as of the Record Date.
Each Warrant entitled the registered holder to purchase from the
Company one share of Common Stock at a price of $3.125 per share,
subject to adjustment. The Warrants were to expire on February 4, 2001.
On January 24, 2001 the Board of Directors reduced the exercise price
to $2.50 and extended the exercise period to September 4, 2002.
In April 2000, the Company completed a private offering of 374,000
shares of its common stock at $3.00 per share. Net proceeds to the
Company were $1,047,628 after offering and related expenses of $74,372.
In April 2001, the Company paid $6,000 and issued 20,000 shares of its
common stock at $1.24 per share to an unrelated third party in exchange
for geophysical data.
During 2001, certificates for previously issued shares of the Company's
common stock, representing 200 shares were presented for transfer.
Prior to presentment, such shares had not been recorded as issued by
the Company.
(c) STOCK OPTION PLANS
The Company has reserved 36,000 shares of its no par common stock for
key employees of the Company under its 1993 Amended Restated Stock
Incentive Plan (the Incentive Plan). Under the terms of the Incentive
Plan, no stock options are exercisable more than ten years after the
date of grant (five years after date of grant for 10% shareholders). As
of June 30, 1998, all 36,000 options had been granted under the
Incentive Plan.
The Company has reserved 75,000 shares of its no par common stock for
employees, officers, directors, consultants and advisors of the Company
under its 1993 Nonqualified Stock Option Plan (the Nonqualified Plan).
Under the terms of the Nonqualified Plan, no stock options are
exercisable more than ten years after the date of grant (five years
after date of grant for 10% shareholders).
During fiscal 1998, the Company merged the Incentive Plan and the
Nonqualified Plan into the Stock Option Plan (the Plan). The Company
has reserved 1,200,000 shares of its no par common stock for employees,
officers, directors, consultants and advisors of the Company under the
Plan. Under the terms of the Plan, no stock options are exercisable
more than ten years after the date of grant (five years after date of
grant for 10% shareholders).
During fiscal 2001, 2000 and 1999, the Board of Directors granted
options to purchase shares of common stock to key employees and
directors pursuant to the Plan. The exercise prices of the options
range from $.50 to $3.00 per share. The options granted are exercisable
upon issuance.
On December 1, 1998, the Board of Directors reduced the number of
options outstanding and repriced certain options. The exercise prices
of the repriced options range from $1.875 to $2.00 per share. The
options are immediately exercisable.
F-11
The Company applies APB Opinion 25 and related interpretations in
accounting for its plan. Accordingly, no compensation cost has been
recognized for stock options granted at or above market value at the
date of the grant to key employees and directors. Compensation expense
of $3,338 and $2,319 has been recorded during fiscal 2001 and 2000,
respectively, for options granted below the market value, based on the
difference between the option price and the quoted market price at the
date of grant. Had compensation cost for the Company's two stock-based
compensation plans been determined based on the fair value at the grant
dates for awards under those plans consistent with the method
prescribed in FASB Statement 123, the Company's net earnings (loss) and
earnings (loss) per share would have been increased to the pro forma
amounts indicated below:
Years Ended June 30,
------------------------------------------
2001 2000 1999
------------ ------------ ------------
Net earnings (loss):
As reported $(104,371) 943,977 (1,441,424)
Pro forma (346,240) 305,625 (1,605,422)
Earnings (loss) per share:
As reported (0.01) 0.14 (0.32)
Pro forma (0.05) 0.05 (0.36)
The fair value of each option grant is estimated on the date of grant
using the Black-Scholes option-pricing model with the following
assumptions used for grants in fiscal 2001, 2000 and 1999,
respectively: no dividend yield for all years; expected volatility of
146%, 129% and 137%; weighted average risk-free interest rates of 5.36%
in fiscal 2001, 5.86% in fiscal 2000 and 5.06% in fiscal 1999; and
expected lives of seven years for all years.
F-12
A summary of the status of the Company's fixed stock options plan as of
June 30, 2001, 2000 and 1999, and changes during the years then ended
is presented below:
2001 2000 1999
--------------------------- ---------------------------- ----------------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Fixed Options Shares Price Shares Price Shares Price
---------------------- ----------- ----------- ----------- ------------ ------------ -----------
Outstanding at
beginning of
year 1,133,964 $ 1.60 691,758 $ 1.69 625,616 $ 2.55
Granted 135,000 1.85 472,206 1.43 510,642 1.64
Exercised -- -- (20,000) .75 -- --
Cancelled -- -- -- -- (439,000) 2.94
Expired (120,000) 2.14 (10,000) 1.03 (5,500) 2.20
----------- ----------- ----------- ------------ ------------ -----------
Outstanding at end
of year 1,148,964 $ 1.58 1,133,964 $ 1.60 691,758 $ 1.69
=========== =========== ============
Options exercisable
at year end 1,123,964 1,133,964 691,758
Weighted average
fair value of
options granted
during the year $ 1.79 $ 1.35 $ 0.87
The following table summarizes information about fixed stock options
outstanding at June 30, 2001 (of which 1,123,964 are exercisable):
Weighted
average
remaining Weighted
Range of exercise Number contractual average
price outstanding life (in years) exercise price
-------------------- ------------- ----------------- ----------------
$ 0.50 - 1.10 165,000 7.8 $ 0.89
1.25 - 1.38 483,706 7.7 1.37
1.88 - 2.08 470,258 4.4 1.97
2.25 - 3.00 30,000 3.5 2.76
-------------
$ 0.50 - 3.00 1,148,964 6.3 $ 1.58
=============
F-13
(5) INCOME TAXES
At June 30, 2001 and 2000, the Company's significant deferred tax assets
and liabilities are as follows:
2001 2000
----------- -----------
Deferred tax assets:
Net operating loss carryforwards $ 3,383,000 3,055,000
Depletion carryforwards 225,000 188,000
Oil and gas properties, principally
due to differences in depreciation,
depletion and impairment 30,000 10,000
----------- -----------
3,638,000 3,253,000
Deferred liabilities:
Oil and gas properties, principally due
due to differences in depreciation,
depletion and impairment (564,000) (493,000)
Investment in related parties -- (584,000)
----------- -----------
(564,000) (1,077,000)
----------- -----------
Valuation allowance (3,074,000) (2,176,000)
----------- -----------
Net deferred tax assets $ -- --
=========== ===========
The valuation allowance for deferred tax assets as of June 30, 2001 was
$3,074,000. The net change in the valuation allowance for the year ended
June 30, 2001 was an increase of $898,000.
At June 30, 2001, the Company had net operating loss carryforwards of
approximately $9,171,000. The utilization of approximately $496,000 of
these loss carryforwards is limited to an estimated $80,000 per year as a
result of a change of ownership which occurred June 30, 1994. Of the
balance of the net operating loss carryforwards, $1,497,000 is limited to
the extent of future taxable income generated by Victoria, and $7,178,000
is available to offset future taxable income of the Company. If not
utilized, the tax net operating losses will expire during the period from
2002 through 2021.
Income tax expense is different from amounts computed by applying the
statutory federal income tax rate due primarily to the change in valuation
allowance for net deferred tax assets and the expiration of tax
carryforwards.
(6) LEASE COMMITMENTS
The Company has noncancelable operating leases, primarily for rent of
office facilities that expire over the next five years. Rental expense for
operating leases was $73,903, $63,683 and $60,336 for the years ended June
30, 2001, 2000 and 1999, respectively.
F-14
Future minimum rental commitments under noncancelable operating leases as
of June 30, 2001 are as follows:
Fiscal year:
2002 $ 67,655
2003 46,736
2004 1,929
-----------
$ 116,320
===========
(7) CONTINGENCIES
In the ordinary course of conducting its business, the Company becomes
involved in litigation, administrative proceedings and governmental
investigations, including environmental matters.
In May 2000, the Company received a notice letter from the U.S.
Environmental Protection Agency (EPA) stating that the Company is a
potentially responsible party under the federal Comprehensive Environmental
Response, Compensation and Liability Act of 1980 (CERCLA) at the Casmalia
Waste Disposal Site in Santa Barbara County, California. If the Company is
ultimately determined to be a responsible party, it may be obligated to
conduct remedial investigations, feasibility studies, remediation and/or
removal of alleged releases of hazardous substances or to reimburse the EPA
for such activities.
The Company does not believe that it has any liability under CERCLA for
wastes disposed at Casmalia and believes that the EPA's notice was issued
in error. The Company has responded to the EPA, explaining that the Company
did not arrange to dispose of any waste at Casmalia. The Company's
involvement with Casmalia is limited to the purchase of assets from another
entity, which disposed of waste at Casmalia. The Company intends to defend
allegations of its responsibility, if any, and will also reply upon an
indemnification given by the previous owner of the properties at Casmalia,
which previous owner has confirmed that the indemnification would apply to
any such allegations.
The Company is unable to estimate the dollar amount of exposure to loss in
connection with the above-referenced matter; however, it has been estimated
that the ultimate site-wide clean up costs will be approximately $271.9
million.
It is the opinion of Company's management that the outcome of these
proceedings, individually or in the aggregate, will not have a material
adverse effect on the Company's financial position, results of operations
or cash flows.
F-15
(8) DISCLOSURES ABOUT CAPITALIZED COSTS, COSTS INCURRED AND MAJOR CUSTOMERS
Capitalized costs related to oil and gas-producing activities are as
follows:
June 30,
-------------------------
2001 2000
----------- -----------
Unproved - Domestic $ 217,941 353,027
Proved 12,398,775 10,933,518
----------- -----------
12,616,716 11,286,545
Accumulated depletion and impairment (3,039,413) (2,747,285)
----------- -----------
$ 9,577,303 8,539,260
=========== ===========
Costs incurred in oil and gas producing activities for the years ended
June 30, 2001, 2000 and 1999 were approximately as follows:
2001 2000 1999
----------- ----------- -----------
Unproved property acquisition costs $ 13,557 208,827 127,557
Proved property acquisition costs 38,594 500 2,752
Development costs 523,668 100,300 71,819
Exploration costs 654,035 5,631,600 1,345,487
During fiscal 2001, the Company had two major customers. Sales to these
customers accounted for approximately 26% and 15% of fiscal 2001 oil and
gas sales. During fiscal 2000, the Company had two major customers. Sales
to these customers accounted for approximately 13% each of fiscal 2000 oil
and gas sales. During fiscal 1999, the Company had three major customers.
Sales to these customers accounted for approximately 25%, 12% and 10% of
fiscal 1999 oil and gas sales.
During fiscal 2001, the Company spent approximately $514,000 converting
proved undeveloped reserves at Amber field (2 wells) and Wagensen
Waterflood field (4 wells) into proved producing reserves. During fiscal
2000, the Company spent approximately $100,000 converting proved
undeveloped reserves at Poitevent Federal into proved producing reserves.
During fiscal 1999, the Company did not spend any money converting proved
undeveloped reserves into proved producing reserves.
(9) INFORMATION REGARDING PROVED OIL AND GAS RESERVES (UNAUDITED)
The information presented below regarding the Company's oil and gas
reserves were prepared by independent petroleum engineering consultants.
All reserves are located within the continental United States.
Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas 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.
Proved developed oil and gas reserves are those expected to be recovered
through existing wells with existing equipment and operating methods. The
determination of oil and gas reserves is highly complex and interpretive.
The estimates are subject to continuing changes as additional information
becomes available.
F-16
Estimated net quantities of proved developed and undeveloped reserves of
oil and gas for the years ended June 30, 2001, 2000 and 1999 are as
follows:
2001 2000 1999
-------------------------- --------------------------- ------------------------
Oil Gas Oil Gas Oil Gas
(BBLS) (MCF) (BBLS) (MCF) (BBLS) (MCF)
---------- ------------- ----------- ------------- ---------- -----------
Beginning of year 388,000 24,517,000 288,000 6,334,000 222,000 3,483,000
Revisions of previous
quantity estimates (13,000) (12,739,000) 136,000 684,000 89,000 482,000
Extensions, discoveries
and improved recovery -- 1,956,000 -- 18,053,000 2,000 2,677,000
Sales of reserves in place -- -- (16,000) (336,000) (1,000) --
Production (19,000) (350,000) (20,000) (218,000) (24,000) (308,000)
---------- ------------- ----------- ------------- ---------- -----------
End of year 356,000 13,384,000 388,000 24,517,000 288,000 6,334,000
========== ============= =========== ============= ========== ===========
Proved developed
reseves-end of year 283,000 6,189,000 315,000 8,630,000 213,000 3,469,000
========== ============= =========== ============= ========== ===========
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
Future net cash flows presented below are computed using year-end prices
and costs. Future corporate overhead expenses and interest expense have not
been included.
2001 2000 1999
--------------- --------------- ---------------
Future cash inflows $ 46,149,000 107,497,000 16,549,000
Future costs:
Production (13,843,000) (26,027,000) (6,597,000)
Development (4,659,000) (10,487,000) (1,090,000)
--------------- --------------- ---------------
Future net cash flows 27,647,000 70,983,000 8,862,000
10% discount factor (13,822,000) (34,980,000) (4,583,000)
--------------- --------------- ---------------
Standardized measure of discounted
future net cash flows $ 13,825,000 36,003,000 4,279,000
=============== =============== ===============
To achieve the 2002 future cash inflows, the capital expenditure of
approximately $2.4 mm in fiscal 2002, $1.7 mm in fiscal 2003 and $1.7 mm in
fiscal 2004 will be required to develop existing proved undeveloped
reserves.
The principal sources of changes in the standardized measure of discounted
future net cash flows during the years ended June 30, 2001, 2000 and 1999,
are as follows:
2001 2000 1999
--------------- -------------- --------------
Beginning of year $ 36,003,000 4,279,000 2,877,000
Sales of oil and gas produced during the period,
net of production costs (1,275,000) (612,000) (219,000)
Net change in prices and production costs (16,108,000) 5,988,000 216,000
Changes in estimated future development costs 3,319,000 (248,000) (80,000)
Extensions, discoveries and improved recovery 1,852,000 22,850,000 1,656,000
F-17
2001 2000 1999
--------------- -------------- --------------
Revisions of previous quantity estimates and
other (13,566,000) 3,510,000 (414,000)
Sales of reserves in place -- (192,000) --
Purchase of reserves in place -- -- (45,000)
Accretion of discount 3,600,000 428,000 288,000
--------------- -------------- --------------
End of year $ 13,825,000 36,003,000 4,279,000
=============== ============== ==============
The standardized measure of discounted future net cash flows relating to
proved oil and gas reserves and the changes in standardized measure of
discounted future net cash flows relating to proved oil and gas reserves
were prepared in accordance with the provisions of Statement of Financial
Accounting Standards No. 69. Future cash inflows were computed by applying
current prices at year-end to estimated future production. Future
production and development costs are computed by estimating the
expenditures to be incurred in developing and producing the proved oil and
gas reserves at year-end, based on year-end costs and assuming continuation
of existing economic conditions. Future income tax expenses are calculated
by applying appropriate year-end tax rates to future pretax net cash flows
relating to proved oil and gas reserves, less the tax basis of properties
involved and tax credits and loss carryforwards relating to oil and gas
producing activities. Future net cash flows are discounted at a rate of 10%
annually to derive the standardized measure of discounted future net cash
flows. This calculation procedure does not necessarily result in an
estimate of the fair market value or the present value of the Company's oil
and gas properties.
The complete definition of proved oil and gas reserves appears at
Regulation S-X 4-10(a)(2), 17 CFR 210.4-10(a)(2). The complete definition
of proved developed oil and gas reserves appears at Regulation S-X
4-10(a)(3), 17 CFR 210.4-10(a)(3). The complete definition of proved
undeveloped reserves appears at Regulation S-X 4-10(a)(4), 17 CFR
210.4-10(a)(4). These regulations are available on the SCC's website,
www.scc.gov/divisions/corpfin/forms/regsx.htm#gas.
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F-18