UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[ X ] Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended June 30, 1999 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, 1999 6,336,000 common shares (the registrant's only class of
voting stock) were outstanding. The aggregate market value of the
5,066,869 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 $7,600,304.
TABLE OF CONTENTS
PART I ............................................................. 3
ITEM 1. BUSINESS ................................................. 3
GENERAL DESCRIPTION OF BUSINESS .................................. 3
RECENT ACTIVITIES ................................................ 3
OPERATIONS AND POLICIES .......................................... 3
ITEM 2. PROPERTIES ............................................... 4
OIL AND GAS INTERESTS ............................................ 5
ROYALTY INTERESTS UNDER PRODUCING PROPERTIES ..................... 4
PERMIT OBLIGATIONS ............................................... 6
DRILLING ACTIVITIES .............................................. 8
FARMOUT AGREEMENTS ............................................... 9
OIL AND GAS PRODUCTION, PRICES AND COSTS ......................... 9
CUSTOMERS ........................................................ 4
OFFICE FACILITIES AND ADMINISTRATIVE SERVICES .................... 4
ITEM 3. LEGAL PROCEEDINGS ......................................... 4
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ....... 4
PART II ............................................................. 10
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS .......................... 4
OUTSTANDING SHARES OF COMMON STOCK ............................... 4
STOCK PRICE ...................................................... 4
DIVIDEND POLICY .................................................. 4
ITEM 6. SELECTED FINANCIAL DATA ................................... 4
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS ....................... 4
LIQUIDITY AND CAPITAL RESOURCES.................................... 4
RESULTS OF OPERATIONS.............................................. 4
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. 4
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ............... 4
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE .................... 4
PART III ............................................................ 16
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ........ 4
ITEM 11. EXECUTIVE COMPENSATION .................................... 4
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT ............................................ 4
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ............ 4
PART IV ............................................................. 16
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K ....................................... 4
SIGNATURES .......................................................... 18
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 at this time 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 has pursued an
aggressive exploration program over the last few years, which it plans to
continue during fiscal 2000.
The Company presently owns oil and gas interests in the states of
California, Louisiana, New Mexico, Oklahoma, South Dakota, Texas, and
Wyoming.
The Company has also owns interests in Petroleum Prospecting License PPL
213 (formerly PPL 106) and PPL 202 in Papua New Guinea and Exploration
Permit EP 325, EP 359, WA-254-P, and WA-261-P in Australia. To date, the
Company has: (i) a 2.04% working interest in PPL 213 in Papua New Guinea;
(ii) a 5% working interest in PPL 202 in Papua New Guinea; (iii) a 3.75%
working interest in EP 359; (iv) a 2.5% working interest in WA-254-P in
Western Australia; (v) a 2.5% working interest in WA-261-P in Western
Australia; and (vi) a 2% interest in EP 325 in Western Australia,
respectively. The Company believes that the international permits
diversify its drilling program. The Company's obligations relating to the
international permits are more fully described in Item 2, Properties,
under Permit Obligations.
The Company, through its wholly owned subsidiary, Kestrel Energy
California, Inc., has a 50% working interest in certain petroleum leases
in California's San Joaquin Basin. The area of interest totals
approximately 6,500 acres net to Kestrel, seismic data covering 16,000
miles, well data from 3,800 wells as well as technical interpretations of
that information from Ampolex (USA), Inc.
RECENT ACTIVITIES
- -----------------
The Company participated in drilling one well during the fourth quarter of
fiscal 1999. The Tumuli #1 was drilled on PPL 213 (formerly PPL 106) in
May, 1999 and was abandoned as a dry hole at an approximate cost to the
Company of $133,277. The Company also initiated the drilling of the UPRC
27-3 test well on August 13, 1999. This 45 day well has a planned total
depth of approximately 15,800 ft. The well is being drilled to test three
formations which include the Dakota, Muddy and Frontier on the Greens
Canyon Prospect, Wyoming.
OPERATIONS AND POLICIES
- -----------------------
The Company currently is focusing its exploration, acquisition and
development opportunities in Wyoming, the San Joaquin Basin in California,
and the Western Shelf of Australia. 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 for 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 is
attempting to alleviate some of these problems by forming acquisition
joint ventures with other companies, including its affiliate, Victoria
International 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. One example is the
Company's joint venture with Black Coral, LLC in connection with the
development of the Company's recently acquired San Joaquin properties,
whereby Black Coral provides ongoing geological and geophysical consulting
regarding prospects and potential wells in the San Joaquin Basin.
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 strongly encourages the
operators of the Company's oil and gas wells to do periodic environmental
assessments of potential liabilities. No significant liabilities of this
kind are known to the Company at this time. To date, the existence of
environmental laws has not materially hindered nor adversely affected the
Company's business.
The Company has five full-time employees, including the Company's
President, Timothy L. Hoops. The Company also hires outside professional
consultants to handle certain additional aspects of the Company's
business. With the addition of Black Coral, LLC, the burden on the
Company from such outside contractors has substantially increased along
with the Company's comparably increased exploration activity, largely in
the San Joaquin Basin. 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.
The Company's focus is now exploration of new oil and gas reserves with
the emphasis on opportunities generated by the Company on acreage
currently held. The Company anticipates that significant efforts will be
made to develop the Wyoming Green River Basin area over the next two
years. The Company will also continue to explore for oil and gas by
participating in prospects generated by outside parties. Such prospects
are often subject to a premium, or promote, to the generating party. The
Company is willing to pay these promotes as an alternative to internally
generating all of its prospects with Company personnel or consultants. A
willingness to consider transactions brought to the Company by third
parties affords the Company a wider range of opportunities than could be
generated in-house. The Company has agreed to pay to its affiliate,
Victoria International Petroleum N.L., a 5% royalty with respect to the
Company's working interest in the international permits, acquired by the
Company from its affiliate which produce net revenues for the Company.
The Company has agreed to pay Black Coral, LLC an overriding royalty based
on the net revenue interest received by the Company relating to
commercial production of oil or gas on properties developed in the San
Joaquin Basin. The overriding royalty could range from 1% to 5%.
ITEM 2. PROPERTIES.
OIL AND GAS INTERESTS
- ---------------------
The following table sets forth information concerning the Company's
leasehold interests in developed and undeveloped oil and gas acreage at
June 30, 1999.
<TABLE>
<CAPTION>
Total Total
Developed Acreage(1)(2) Undeveloped Acreage(1)(2)
State Gross Net Gross Net
----- ----- --- ----- ---
<S> <C> <C> <C> <C>
California 290 44 12,956 6,479
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 4,356 1,753 14,658 14,403
----- ----- ------ ------
TOTAL 9,826 2,707 27,614 20,882
Canada 640 19 -0- -0-
Papua New Guinea -0- -0- 1,700,595 59,520(3)
Australia -0- -0- 2,037,133 58,870
</TABLE>
(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.
(3) IF THE PAPUA NEW GUINEA GOVERNMENT ELECTS TO BACK IN FOR 22.5%, THEN
NET ACREAGE WOULD BE REDUCED TO 46,128 ACRES.
ROYALTY INTERESTS UNDER PRODUCING PROPERTIES
- --------------------------------------------
At June 30, 1999 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.
PERMIT OBLIGATIONS
- ------------------
Irrespective of the Company's current exploration plans for a given
prospect, many of the international permits in which the Company has an
interest require certain actions to be taken by the Company or co-holders
of the permits for the Company to retain or continue to earn its interest
in the permit.
PPL 213, Papua New Guinea
- -------------------------
In February, 1999 the Company acquired by application, a 2.04% working
interest in PPL 213 by the PNG Government. Concurrent with the working
interest are the following permit obligations. The Company can withdraw
from the permit at the end of any permit year without penalty.
<TABLE>
<CAPTION>
Kestrel Share of
Anticipated Expenditures
Current: Work 2.0% Working Interest
- ------- ---- ---------------------
<S> <C> <C>
Year 1 (ending One well $ 25,000
February 10, 2000) ------
Total $ 25,000
</TABLE>
The royalty to Papua New Guinea from petroleum production is 1.25% with a
50% income tax being applied to gross revenues less royalty, depreciation
and expenses. An Additional Profits Tax (APT) of 50% is levied on net
cash flow after a return on investment of 27% is achieved.
The state has a right to participate in any Petroleum Development License
(PDL) which is granted at up to a 22.5% interest level on a carried basis
(shared proportionally between license holders). The carried previous
exploration and development costs are recovered by taking the state
entity's share of production until made up with interest at the US AAA
Corporate rate plus 5%.
PPL 202, Papua New Guinea
- -------------------------
In March 1998, the Company acquired by application a 5% interest in PPL
202 with the following permit obligations. The Company can withdraw from
the permit at the end of the second permit year without penalty.
<TABLE>
<CAPTION>
Kestrel Share of
Anticipated Expenditures
Current: Work 5% Working Interest
- ------- ---- -------------------
<S> <C> <C>
Years 1 & 2 (ending Data review
March 2, 2000) and seismic
reprocessing $ 13,000
Years 3 & 4 (ending Aeromagnetic
March 2, 2002) survey and
50 kms seismic $ 85,000
Years 5 & 6 (ending One well and
March 2, 2004) data review $ 400,000
-------
Total $ 498,000
</TABLE>
The state has a right to participate in any PDL which is granted at up to
a 22.5% interest level on a carried basis (shared proportionally between
license holders). The carried previous exploration and development costs
are recovered by taking the state entity's share of production until made
up with interest at the US AAA Corporate rate plus 5%.
Exploration Permits (EP) for petroleum are granted by the State of Western
Australia over exploration areas in state controlled inshore waters and
onshore for a period of five years in exchange for a five year work
program on a year by year basis.
Permitees may withdraw without penalty from a permit once the current
year's work program is satisfied and prior to entry into the next year's
program.
At the end of the five-year term, permitees may relinquish the permit or
apply for renewal of the permit with a further five-year work program
acceptable to the state and 50% relinquishment of the existing permits
acreage.
EP 325, Western Australia
- -------------------------
<TABLE>
<CAPTION>
Kestrel Share of
Anticipated Expenditures
Current: Work 2% Working Interest
- ------- ---- -------------------
<S> <C> <C>
Year 5 (ended Data review
January 20, 1998) and one well $ 3,000
(continues in force -----
until renewal approved)
Total $ 3,000
</TABLE>
EP 359, Western Australia
- -------------------------
<TABLE>
<CAPTION>
Kestrel Share of
Anticipated Expenditures
Current: Work 3.75% Working Interest
- ------- ---- ----------------------
<S> <C> <C>
Year 1 to April 6, 2000 Data review $ 20,000
------
Total $ 20,000
</TABLE>
WA-254-P, Western Australia
- ---------------------------
<TABLE>
<CAPTION>
Kestrel Share of
Anticipated Future
Expenditures
Current: Work 2.5% Working Interest
- ------- ---- ---------------------
<S> <C> <C>
Year 6 (ending One well $ 187,500
January 30, 2000) -------
Total $ 187,000
</TABLE>
The permit WA-254-P is an offshore federal permit granted by the
commonwealth of Australia under the Petroleum Submerged Lands Act.
Permits are granted for a period of 6 years on the basis of a six-year
work program, the work program specified on a year by year minimum work
commitment basis. The first three-year's work program is mandatory.
After completion of the first three-year's work program, permitees can
withdraw from the permit at any time once the current year's work program
is satisfied and prior to entry into the next year's program.
At the end of the six-year term, permitees may relinquish the permit or
apply for a renewal of the permit with a further six-year work program
acceptable to the federal commonwealth authority and 50% relinquishment of
the existing permits acreage.
WA-261-P, Western Australia
- ---------------------------
<TABLE>
<CAPTION>
Kestrel Share of
Anticipated Future
Expenditures
Current: Work 2.5% Working Interest
- ------- ---- ---------------------
<S> <C> <C>
Year 4 (ending 100 km 3D
January 2, 2000) Seismic $ 20,000
Year 5 (ending One well $ 40,000
January 2, 2001)
Year 6 (ending Data review
January 2, 2002) $ 5,000
-----
Total $ 65,000
</TABLE>
The permit WA-261-P is an offshore federal permit granted by the
commonwealth of Australia under the Petroleum Submerged Lands Act.
Permits are granted for a period of 6 years on the basis of a six-year
work program, the work program specified on a year by year minimum work
commitment basis. The first three-year's work program is mandatory.
After completion of the first three-year's work program, permitees can
withdraw from the permit at any time once the current year's work program
is satisfied and prior to entry into the next year's program.
At the end of the six-year term, permitees may relinquish the permit or
apply for a renewal of the permit with a further six-year work program
acceptable to the federal commonwealth authority and 50% relinquishment of
the existing permits acreage.
Drilling Activities
- -------------------
The Company participated in drilling seven wells since June 30, 1998. Two
of the wells were abandoned as dry holes. The unsuccessful wells were the
Tumuli #1 on the PPL 213 (formerly PPL 106) Prospect in Papua New Guinea
in May, 1999 and the Melanie #1 on EP 325, Australia in July 1998. The
Company successfully completed the Dines Unit #2, Dines Prospect in
Wyoming in January, 1999, and the CBMA 23-15 well, Hilight Prospect,
Campbell County, Wyoming in March, 1999. Both of these wells are
currently in production. The Company also drilled three wells that were
not completed at June 30, 1999, due to additional work or development
requirements. The three wells include the Poitevent Federal #1, Greens
Canyon Prospect, Wyoming in December 1998, the Lake Bouef Developmental
Well, Lake Bouef Prospect, Louisiana in February 1999, and the Sage #1, WA
254-P, Western Australia, in May 1999. The Company also initiated the
UPRC 27-3 test well on the Greens Canyon Prospect, Wyoming, on August 3,
1999. The test well is expected to be completed in early October to an
anticipated total depth of 15,800 ft.
Kestrel and its subsidiaries owned interests in net exploratory and net
development wells for the years ended June 30, 1999, 1998 and 1997 as set
forth below. This information does not include wells drilled under
farmout agreements.
<TABLE>
<CAPTION>
United States Australia
--------------------------- ---------------------------
6/30/99 6/30/98 6/30/97 6/30/99 6/30/98 6/30/97
<S> <C> <C> <C> <C> <C> <C>
Net Exploratory
Wells: (1)
Dry (2) - 2.50 - 0.06 0.02
Productive (3) - - - 0.03 - -
---- ---- ---- ---- ---- ----
- 2.50 - 0.09 0.02 -
==== ==== ==== ==== ==== ====
Net Development
Wells: (1)
Dry (2) - - - - - -
Productive (3)0.25 0.88 0.34 - - -
---- ---- ---- ---- ---- ----
0.25 0.88 0.34 - - -
==== ==== ==== ==== ==== ====
</TABLE>
(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, 1999, two exploratory wells were drilled
under farmout agreements. Both wells were dry holes.
OIL AND GAS PRODUCTION, PRICES AND COSTS
- ----------------------------------------
As of June 30, 1999, the Company had a royalty and/or working interest in
83 gross (12.77 net) wells that produce oil only, 25 gross (3.45 net)
wells that produce gas only, and 242 (8.91 net) wells that produce both
oil and gas. All wells that produced gas were connected to pipelines.
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 7 to the financial statements included in
Item 8 of this Report. The reserve estimates for the reporting year were
prepared by Sproule Associates, 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, 1999.
For the year ended June 30, 1999, the Company's average operating cost
(including taxes and marketing) per barrel of oil equivalent (BOE)
(converting gas to oil at 6:1) was $5.46. The average operating cost per
BOE on an equivalent basis for fiscal years 1998 and 1997 was $5.75 and
$7.13, respectively. The average sales price per barrel of oil sold was
$10.01 for 1999, $14.63 for 1998, and $21.86 for 1997. The average sales
price per mcf of gas sold was $1.26 for 1999, $1.78 for 1998, and $2.22
for 1997.
CUSTOMERS
- ---------
During fiscal year 1999, the Company had three major customers, Oxley
Petroleum, Inc., Amoco, Inc. and KN Energy, Inc. Sales to these customers
accounted for 25%, 12% and 10% respectively, of oil and gas sales in 1999.
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 currently located at 999 18th Street,
Suite 2490, Denver, Colorado 80202 which is comprised of approximately
3,953 square feet, at an annual rate of $60,855. The Company's current
lease obligation expires February 28, 2003.
ITEM 3. LEGAL PROCEEDINGS.
The Company is not a party to, nor is any of its property subject to, any
material pending legal proceedings. The Company knows of no material
legal proceedings contemplated or threatened against it.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
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, 1999 the Company had
4,456,000 shares outstanding. At June 30, 1999, 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.
<TABLE>
<CAPTION>
FISCAL YEAR JUNE 30, 1998 SALES PRICE
-----------
HIGH LOW
---- ---
<S> <C> <C>
First Quarter $4.13 $1.94
Second Quarter 2.63 .94
Third Quarter 1.69 1.00
Fourth Quarter 1.56 .72
</TABLE>
<TABLE>
<CAPTION>
FISCAL YEAR JUNE 30, 1999 SALES PRICE
-----------
HIGH LOW
---- ---
<S> <C> <C>
First Quarter $1.06 $.38
Second Quarter 1.50 .46
Third Quarter 2.75 .50
Fourth Quarter 2.00 .88
</TABLE>
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.
ITEM 6. SELECTED FINANCIAL DATA.
The summary of selected financial data for the Company for its last five
fiscal years is as follows:
<TABLE>
<CAPTION>
Years ended June 30,
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Oil and
Gas Sales $632,030 $895,017 $1,278,502 $1,198,795 $1,334,667
Total Revenue 772,795 1,204,261 1,420,056 1,268,456 1,397,775
Net (Loss) (1,441,424) (2,018,692) (1,312,365) (160,231) (1,119,133)
(Loss) per
Share (.32) (.46) (.56) (.08) (.64)
At June 30,
Total Assets 4,059,234 5,560,022 7,638,626 4,115,211 4,287,984
Long-term Debt - - - - -
Stockholders'
Equity 3,966,297 5,398,346 7,432,443 3,964,708 4,072,225
</TABLE>
* Less than .01 per share
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 at June 30,
1999, was $560,207 compared to working capital of $3,137,982 on June 30,
1998 and working capital of $5,026,785 on June 30, 1997. The decrease in
working capital of $2,577,775 for the current year was a result of an
operating cash flow deficiency and property acquisitions. The decrease in
working capital of $1,888,803 from June 30, 1997 to 1998 was a result of
operating cash flow deficiencies and capital expenditures.
Net cash used by operating activities totaled $752,395 for fiscal year
1999 as compared to $1,654,630 for fiscal 1998, a decrease in cash used of
$902,235. The decrease is primarily due to lower dry hole and exploration
costs, notwithstanding sharply lower oil and gas revenues. Net cash used
by operating activities totaled $1,654,630 for fiscal year 1998 as
compared to cash provided by operating activities of $35,143 for fiscal
1997, a decrease of $1,689,773. The decrease from 1997 to 1998 was a
result of lower oil and gas revenues coupled with substantially higher dry
hole and exploration costs resulting from the Company's emphasis on
exploration during 1998.
Net cash provided by investing activities was $775,181 in 1999 compared to
$518,091 provided in 1998. During the fiscal year ended June 30, 1999,
$1,556,650 was used to acquire proved and unproved oil and gas property
interests and equipment. Proved property investments included $1,296,000
to acquire and develop the Poitevent #1 and Poitevent Prospect in Wyoming,
$72,000 to acquire leasehold interests and workover an existing well on
the Lake Bouef Prospect in Louisiana, $24,000 to complete the CBMA 23-15
well on the Hilight Prospect in Wyoming, $25,000 to acquire additional
lease acreage and well equipment on the Dines Unit #2 in Wyoming, and
$2,650 to acquire well equipment on various leases. Unproved acquisitions
included $108,000 to develop and drill the Sage #1, WA 254-P Prospect in
Australia and $20,000 for the continued development of the Kaye Unit in
Wyoming. The Company also spent $9,000 on computers, software and
furniture during the current fiscal year. For the fiscal year ended June
30, 1999, the Company sold short-term investments of $2,330,831 as
compared to sales of investments of $1,078,256 in 1998. The reduction in
short-term investments reflects the Company's need for additional working
capital and acquisition of proved and unproved property. Proceeds from
the sale of assets amounted to $1,000 for fiscal 1999 as compared to
$14,891 in 1998. The Company received $1,000 for it's interest in the
Edna Dupplechain well in Louisiana. Net cash provided by investing
activities was $518,091 in 1998 as compared to $3,522,504 used in 1997.
During the fiscal year ended June 30, 1998, $575,056 was used to purchase
producing and non-producing leasehold interests and fixed assets. Non-
producing leasehold purchases included $184,000 to acquire various
leasehold interests in the San Joaquin Basin, approximately $26,000 to
acquire additional interests in the Pierce Unit in Campbell County,
Wyoming and $18,000 to commence development of the Kaye Unit in Converse
and Niobrara Counties, Wyoming. Approximately $288,000 was used to
acquire well equipment on various wells, complete the Cab Hughes #5 and
Gallion #6 in Oklahoma and to complete the Scribner 11-10 and the CBM 24-
15 in Wyoming. The Company also spent $59,000 to acquire computers,
accounting software and furniture for use in its expanded operations in
fiscal 1998. For the fiscal year ended June 30, 1998, the Company sold
short-term investments of $1,078,256 versus purchases of short-term
investments of $2,764,253 in 1997. The change in short-term investments
reflects the Company's deployment of its excess cash to facilitate the
exploration program. Proceeds from the sale of property amounted to
$14,891 for fiscal 1998 as compared to proceeds of $77,946 in 1997.
There were no cash flows provided or used from financing activities during
fiscal 1999 as compared to cash used of $15,405 in 1998. Cash used by
financing activities in 1998 was $15,405 as compared to cash provided of
$4,711,100 in 1997. The 1998 use of cash from financing activities
reflects $6,250 received by the Company relating to stock option exercises
by officers of the Company in August, 1997 and $21,655 worth of stock
purchased from an officer to complete the stock option exercise and to
satisfy withholding taxes payable as a result of a stock option exercise.
The Company has capital commitments of approximately $268,500 for the
fiscal year ending June 30, 2000, as described more fully under Permit
Obligations on Pages 6-8. These commitments may increase if operators of
various permits and prospects propose additional exploration or
development projects. Commitments can also be less if the Company elects
to withdraw or reduce its interest in a permit. The Company, through its
wholly owned subsidiary, Kestrel Energy California, Inc., entered into a
contract with Black Coral, LLC, in 1997, in which Black Coral will provide
ongoing geological and geophysical consulting with regard to an Area of
Mutual interest located in the San Joaquin Basin in California. The
contract term was for a period of one year ending September 30, 1998. The
parties have verbally agreed to continue that agreement on a month to
month basis until they formalize a written agreement. The Company's share
of Black Coral, LLC consulting costs for the fiscal year ending June 30,
1999 is anticipated to be approximately $120,000.
STOCKHOLDERS' EQUITY: Stockholders' equity decreased $1,432,049 or
27% to $3,966,297 at June 30, 1999 as compared to $5,398,346 a year ago.
The decrease is attributable to the net loss incurred by the Company for
the year, less 25,000 shares of stock, valued at $9,375, issued to Green
River Resources, Inc. to acquire a 100% working interest in the Dines and
Poitevent Prospects in September, 1998.
DEBT OBLIGATIONS: The Company had no long-term debt at June 30,
1999, 1998 and 1997.
RESERVES AND FUTURE CASH FLOWS: For the fiscal year ended June 30,
1999, the Company's proved oil reserves increased approximately 66,000
bbls. to 288,000 bbls., or 30%, from 222,000 in 1998. The Company's
proved gas reserves increased 2,851 Mmcf from 3,483 Mmcf in 1998 to 6,334
Mmcf in 1999, a 82% increase. The increase in proved reserves is
attributable to revisions of previous quantity estimates, production, and
higher oil and gas prices for the fiscal year ended June 30, 1999.
The Company's undiscounted net future cash flows have been estimated by
Sproule Associates Inc., an independent petroleum engineering firm, to be
approximately $8,862,000 as of June 30, 1999. This compares to $4,697,000
in 1998 and $8,281,000 in 1997. The increase in the current year is a
result of revisions of previous quantity estimates reflecting
significantly higher oil and gas prices.
GAS BALANCING: The Company at June 30, 1999 was underproduced by
approximately 6,200 mcf. At June 30, 1998, the Company was underproduced
approximately 13,000 mcf. The Company was underproduced by 31,000 mcf of
gas at June 30, 1997. 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, 1999,
the Company estimated that, for United States federal income tax purposes,
it had consolidated net operating loss carryforwards of approximately
$8,056,000. The utilization of approximately $932,000 of these
carryforwards are limited to an estimated $80,000 annually. Of the
balance of the loss carryforwards, $1,866,000 are limited to the extent of
future taxable income generated by the Company's subsidiary, Victoria
Exploration, Inc., and $5,258,000 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 2000 through 2014.
YEAR 2000 COMPLIANCE: The Company has conducted a review of its
computer systems to identify software that could be affected by the "Year
2000" issue which results from computer programs being written using two
digits rather than four to define the applicable year. Any computer
programs that have time-sensitive software may recognize a date using "00"
as the year 1900 rather than the year 2000, possibly resulting in a major
system failure or miscalculations. Since 1997, the Company has updated
all of its computer hardware and software to be Year 2000 compliant.
Although the Company believes it has identified the internal Year 2000
issues which might impact its operations, no assurance can be given that
all such issues have been identified or will be corrected. Additionally,
no assurances can be given that the Company's vendors, banks or other
third parties will not experience Year 2000 issues, which may have a
significant impact on the Company's operations. The Company has worked
with its most significant vendors and consultants to ensure that they do
not encounter Year 2000 problems that affect their work for the Company.
RESULTS OF OPERATIONS
- ---------------------
Fiscal 1999 vs. Fiscal 1998
- ---------------------------
NET EARNINGS: The Company reported a loss of $1,441,424 in fiscal
1999 compared to a loss of $2,018,692 in 1998, a decrease of $577,268.
The decrease in loss is attributable to lower dryhole and exploration
expenses despite lower overall revenues as a result of lower oil and gas
prices.
REVENUE: Total revenues decreased in fiscal 1999 by $431,466, or
36%, to $772,795 versus $1,204,261 in 1998. The decrease in overall
revenues was a result of lower oil and gas revenues due to lower oil and
gas prices, and significantly lower interest income due to the reduction
in the Company's short-term investments.
Revenue from oil and gas sales decreased $262,987, or 29%, to $632,030
from $895,017 a year ago. The decrease in revenues was a result of lower
oil and gas prices as well as lower sales volumes for oil. Average prices
per barrel of oil decreased 32% to $10.01 from $14.63 a year ago. Average
prices received per mcf of gas decreased 29% to $1.26 versus $1.78 a year
ago. Sales volumes for oil decreased 12% to 24,319 from 27,559 a year
ago. Sales volumes for gas increased 12% to 308 mmcf from 276 mmcf a year
ago.
LEASE OPERATING EXPENSES: Lease operating expenses decreased
$14,418, or 3% to $412,628 from $427,046 a year ago. The decrease in
lease operating expense is attributable to lower production taxes
resulting from the decline in oil and gas revenues and lower operating
costs on various properties despite higher workover costs incurred on the
Dines Unit #2. Lease operating costs on a BOE (barrel of oil equivalent)
decreased 5% to $5.46 from $5.75 a year ago.
EXPLORATION EXPENSES: Exploration expenses decreased $165,197, or
26%, to $460,336 from $625,533 in 1998. The decrease in exploration
expense reflects the slower pace of the Company's aggressive exploration
program during fiscal 1999 due to low oil and gas prices throughout most
of the year. 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 $388,612 in fiscal 1999 as compared to
$1,211,084 a year ago, a decrease of $822,472 or 68%. Dry hole costs were
$144,515 in fiscal 1999 versus $681,046 a year ago. The Company
participated in drilling two wells that were abandoned as dry holes, the
Tumuli #1, PPL 213 prospect, Papau, New Guinea in May of 1999 at an
approximate cost of $133,000 and the Melanie #1 on EP 325, Australia in
July, 1998 at no cost to the Company by virtue of a carried interest.
Additional dry hole costs of $11,515 were booked in fiscal 1999 for dry
holes drilled as of June 30, 1998. The decrease in dry hole costs
reflected the Company's decision not to drill exploratory wells due to the
lower oil and gas prices throughout fiscal 1999. Abandonment costs
decreased $437,171, or 96% to $17,857 from a year ago. The Company
abandoned two leases in the San Joaquin Basin which accounted for fiscal
1999 expense. Impairment expense increased 151,230 or 202% to $226,240
from $75,010 a year ago. The increase is attributable to higher
impairment expense under SFAS 121, which amounted to $176,990. The
remaining impairment expense of $49,250 related to various international
permits.
GENERAL AND ADMINISTRATIVE EXPENSE: General and administrative
expenses increased $12,511, or 2%, to $778,229 as compared to $765,718 a
year ago. The increase in general and administrative expenses is not
attributable to any particular expense category.
Fiscal 1998 vs. Fiscal 1997
- ---------------------------
NET EARNINGS: The Company reported a loss of $2,018,692 in fiscal
1998 compared to a loss of $1,312,365 in 1997, an increase of $706,327 or
54%. The increase in loss is attributable to lower oil and gas revenues
and to higher dry hole and exploration expenses.
REVENUE: Total revenues decreased in fiscal 1998 by $215,795, or
15%, to $1,204,261 versus $1,420,056 in 1997. The decrease in overall
revenues was a result of lower oil and gas revenues, despite higher
interest income and overhead recovery from the Company's San Joaquin Joint
Venture partner.
Revenue from oil and gas sales decreased $383,485, or 30%, to $895,017 in
1998 from $1,278,502 in 1997. The decrease in revenues was a result of
lower oil and gas prices as well as lower sales volumes for oil. Average
prices per barrel of oil decreased 33% to $14.63 in 1998 from $21.86 in
1997. Average prices received per mcf of gas decreased 20% to $1.78 in
1998 versus $2.22 in 1997. Sales volumes for oil decreased 15% to 28,000
in 1998 from 33,000 in 1997. Sales volumes for gas increased 10% to 276
mmcf in 1998 from 251 mmcf in 1997.
LEASE OPERATING EXPENSES: Lease operating expenses decreased
$106,074, or 20% to $427,046 in 1998 from $533,120 in 1997. The decrease
in lease operating expense is attributable to lower production taxes
resulting from the decline in oil and gas revenues and lower operating
costs on the Pierce and Kuehne Ranch Units. Lease operating costs on a
BOE (barrel of oil equivalent) decreased 19% to $5.75 in 1998 from $7.13
in 1997.
EXPLORATION EXPENSES: Exploration expenses increased $432,622, or
224%, to $625,533 in 1998 from $192,911 in 1997. The increase in
exploration expense reflected the Company's emphasis in fiscal 1998 on
exploration of new oil and gas reserves. The increase was a result of
higher geological and geophysical costs as well as higher delay rentals
paid on exploration acreage.
DRY HOLES, ABANDONED AND IMPAIRED PROPERTIES: Dry hole costs were
$681,046 for fiscal 1998. The Company participated in drilling eight
wells that were abandoned as dry holes in fiscal 1998. In the San Joaquin
Basin of California, the Company incurred dry hole costs on the Daisy 31-
26 of $64,200, the Greer #1 and Greer Sidetrack of $352,638, the Dewey #1
of $92,800 and the Sylvester #1 of $112,688. Internationally, the Company
participated in three wells which were abandoned as dry holes. In July
1997, the Company drilled the Heather Downs #1 and in August 1997 the
Company participated in the Longhorn #1, both in Western Australia. Both
wells were dry holes at no cost to the Company by virtue of a carried
interest in the drilling. The Company also participated in the Janus #1
in Western Australia in January, 1998. The well was abandoned as a dry
hole at a cost to the Company of approximately $58,600. There were no dry
hole costs for fiscal 1997. Abandonment costs increased $353,099, or
346%, to $455,028 in 1998 from $101,929 in 1997. The increase was a
result of the Company's decision to abandon some leaseholds in the San
Joaquin Basin, which are no longer a part of the Company's exploration
strategy. Impairment expense decreased $822,242, to $75,010 in 1998 from
$897,252 in 1997. The decrease was attributable to lower impairment
expense under SFAS No. 121, which amounted to $25,500 in fiscal 1998
versus $841,262 in 1997. The remaining impairment expense of $49,500
related to various international permits.
GENERAL AND ADMINISTRATIVE EXPENSE: General and administrative
expenses increased $159,938, or 26%, to $768,216 in 1998 as compared to
$608,278 in 1997. The increase in general and administrative expenses is
due to expanded land, engineering, and accounting departments to
facilitate the higher exploration activity level of the Company during
fiscal 1998, as well as higher public relations costs.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The Company does not invest in or hold market risk sensitive or
interest rate sensitive instruments. The only currency exchange rate risk
borne by the Company is minimal, stemming from the Company's obligations
to fund its international drilling in Australian dollars.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
See pages F-1 through F-17 for this information.
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, 1999 and 1998, and the
related consolidated statements of operations, stockholders' equity and
cash flows for each of the years in the three-year period ended June 30,
1999. 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 generally accepted auditing
standards. 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, 1999 and 1998, and
the results of their operations and their cash flows for each of the years
in the three-year period ended June 30, 1999, in conformity with generally
accepted accounting principles.
KPMG LLP
Denver, Colorado
September 10, 1999
KESTREL ENERGY, INC.
AND SUBSIDIARIES
Consolidated Balance Sheets
June 30, 1999 and 1998
<TABLE>
<CAPTION>
ASSETS 1999 1998
------------ -----------
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 394,980 372,194
Short-term investments --- 2,330,831
Accounts receivable 110,880 166,568
Related party receivable 60,006 393,175
Other current assets 87,278 36,890
-------- ----------
Total current assets 653,144 3,299,658
-------- ----------
Property and equipment, at cost:
Oil and gas properties,
successful efforts method of
accounting (note 6):
Unproved 761,101 688,779
Proved 5,465,748 4,219,282
Furniture and equipment 139,516 130,468
--------- -----------
6,366,365 5,038,529
Accumulated depreciation and
depletion (2,960,275) (2,778,165)
---------- -----------
Net property and equipment 3,406,090 2,260,364
---------- -----------
$4,059,234 5,560,022
========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade $ 47,752 139,989
Related party 20,172 ---
Accrued liabilities 25,013 21,687
-------- -----------
Total current liabilities 92,937 161,676
-------- -----------
Stockholders' equity (note 2):
Preferred stock, $1 par value
1,000,000 shares authorized;
none issued --- ----
Common stock, no par value
20,000,000 shares authorized;
4,456,000 and 4,431,000
shares issued at June 30, 1999
and 1998, respectively 13,148,724 13,139,349
Accumulated deficit (9,182,427) (7,741,003)
---------- -----------
Total stockholders' equity 3,966,297 5,398,346
---------- -----------
Commitments (note 5)
$4,059,234 5,560,022
========== =========
</TABLE>
See accompanying notes to consolidated financial statements.
KESTREL ENERGY, INC.
AND SUBSIDIARIES
Consolidated Statements of Operations
Years ended June 30, 1999, 1998 and 1997
<TABLE>
<CAPTION>
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
Revenue:
Oil and gas sales $ 632,030 895,017 1,278,502
Gain(loss)on sale of
property and equipment (788) 14,832 43,993
Interest income 76,490 202,496 67,986
Other,net 65,063 91,916 29,575
--------- --------- ---------
Total revenue 772,795 1,204,261 1,420,056
--------- --------- ---------
Costs and expenses:
Lease operating expenses 412,628 427,046 533,120
Dry holes, abandoned and
impaired properties 388,612 1,211,084 999,181
Exploration expenses 460,336 625,533 192,911
Depreciation and depletion 174,414 191,074 398,931
General and administrative 778,229 765,718 608,278
Interest expense --- 2,498 ---
--------- --------- ---------
Total costs
and expenses 2,214,219 3,222,953 2,732,421
--------- --------- ---------
Net loss $(1,441,424) (2,018,692) (1,312,365)
========= ========= =========
Loss per share $ (0.32) (0.46) (0.56)
========= ========= =========
Weighted average number
of common shares
outstanding 4,451,833 4,429,626 2,325,041
========= ========= =========
</TABLE>
See accompanying notes to consolidated financial statements.
KESTREL ENERGY, INC.
AND SUBSIDIARIES
Consolidated Statements of Stockholders' Equity
Years ended June 30, 1999, 1998 and 1997
<TABLE>
<CAPTION>
COMMON STOCK TOTAL
----------------- ACCUMULATED STOCKHOLDERS'
SHARES AMOUNT DEFICIT EQUITY
------ ------ ----------- -------------
<S> <C> <C> <C> <C>
Balance,
June 30, 1996 1,907,602 8,374,654 (4,409,946) 3,964,708
Common shares
issued, net of
offering costs
(note 2) 2,502,000 4,711,100 --- 4,711,100
Common shares
issued for
services (note 2) 5,000 12,500 --- 12,500
Options issued
for services
(note 2) --- 56,500 --- 56,500
Adjustment for
previously issued
and unrecorded
shares (note 2) 22 --- --- ---
Net loss --- --- (1,312,365) (1,312,365)
---------- ---------- ---------- ----------
Balance
June 30, 1997 4,414,624 $13,154,754 (5,722,311) 7,432,443
Exercise of
stock options
(note 2) 32,884 44,472 --- 44,472
Common shares
surrendered by
officer (note 2) (16,518) (59,877) --- (59,877)
Adjustment for
previously issued
and unrecorded
shares (note 2) 10 --- --- ---
Net loss --- --- (2,018,692) (2,018,692)
---------- ---------- ---------- ----------
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
========== ========== ========== ==========
</TABLE>
See accompanying notes to consolidated financial statements.
KESTREL ENERGY, INC.
AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years ended June 30, 1999, 1998 and 1997
<TABLE>
<CAPTION>
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Cash flows from
operating activities:
Net loss $(1,441,424) (2,018,692) (1,312,365)
Adjustments to reconcile net
loss to net cash provided
(used) by operating activities:
Depreciation and depletion 174,414 191,074 398,931
Abandoned and impaired
properties 244,097 529,217 953,250
Loss (gain) on sale of
property and equipment 788 (14,832) (43,993)
Noncash compensation expense
for common stock and options
issued for services --- --- 69,000
Changes in operating
assets and liabilities:
(Increase) decrease in
accounts receivable 55,688 (4,460) 2,697
(Increase) decrease in
related party receivables 333,169 (264,186) (103,429)
(Increase) decrease in
other current assets (50,388) (28,244) 15,372
Increase (decrease) in
accounts payable - trade (92,237) (25,052) 86,361
Increase (decrease) in
accounts payable -
related party 20,172 (23,972) (8,770)
Increase (decrease) in
accrued liabilities 3,326 4,517 (21,911)
---------- ---------- ----------
Net cash provided
(used) by operating
activities (752,395) (1,654,630) 35,143
---------- ---------- ----------
Cash flows from investing activities:
Capital expenditures (1,556,650) (575,056) (836,197)
Sale (purchase) of short-term
investments, net 2,330,831 1,078,256 (2,764,253)
Proceeds from sales of
property and equipment 1,000 14,891 77,946
---------- ---------- ----------
Net cash provided
(used) by investing
activities 775,181 518,091 (3,522,504)
---------- ---------- ----------
Cash flows from financing activities:
Proceeds from issuance of common
stock, net of offering costs --- --- 4,711,100
Proceeds from exercise of
stock options --- 6,250 ---
Common stock purchased for
withholding tax --- (21,655) ---
---------- ---------- ----------
Net cash provided
(used) by financing
activities --- (15,405) 4,711,100
---------- ---------- ----------
Net increase (decrease)
in cash and cash
equivalents 22,786 (1,151,944) 1,223,739
Cash and cash equivalents,
beginning of year 372,194 1,524,138 300,399
---------- ---------- ----------
Cash and cash equivalents,
end of year $ 394,980 372,194 1,524,138
========== ========== ==========
</TABLE>
See accompanying notes to consolidated financial statements.
KESTREL ENERGY, INC.
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 1999 and 1998
(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
California, Kansas, Louisiana, New Mexico, Oklahoma, South Dakota,
Texas, and Wyoming. The Company also has an interest in seven
international exploration permits, two in Papua New Guinea and
four in Australia.
Victoria International Petroleum N. L. (VIP) owns 26.2% of the
common shares of the Company at June 30, 1999.
(B)PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the
Company and its subsidiaries, Victoria Exploration, Inc.
(Victoria) and Kestrel Energy California, Inc. All significant
intercompany accounts and transactions have been eliminated in
consolidation.
(C)ESTIMATES
The preparation of financial statements in conformity with
generally accepted accounting principles 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)SHORT-TERM INVESTMENTS
Short-term investments at June 30, 1998 consist primarily of U.S.
Treasury securities with maturities of less than one year which
are classified as available for sale. Short-term investments are
recorded at cost, which approximates market value.
(F)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 exploration and
development costs is computed on the units-of-production method by
individual fields as the related proved reserves are produced. A
reserve is provided for estimated future costs of site
restoration, dismantlement, and abandonment activities, net of
residual salvage value, as a component of depletion.
Furniture and equipment are depreciated using the straight-line
method over estimated lives ranging from three to five years.
Management periodically evaluates capitalized costs of unproved
properties and provides for impairment, if necessary, through a
charge to operations.
In March 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 121 (SFAS No.
121), ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED ASSETS AND FOR
LONG-LIVED ASSETS TO BE DISPOSED OF. This Statement was effective
for financial statements for fiscal years beginning after December
15, 1995. Under SFAS No. 121 an entity shall review long-lived
assets and certain identifiable intangibles to be held and used
for impairment whenever events or changes in circumstances
indicate that the carrying amount of an asset may not be
recoverable. If the changes in circumstances are present or if
other events in circumstances indicate that the carrying amount of
an asset that an entity expects to hold and use may not be
recoverable, the entity shall estimate the future cash flows
expected to result from the use of the asset and its eventual
disposition. Future cash flows are the future cash inflows
expected to be generated by an asset (grouped at the lowest level
for which there are identifiable cash flows which is on a field by
field basis) less the future cash outflows expected to be
necessary to obtain those inflows. If the sum of expected future
cash flows (undiscounted and without interest charges) is less
than the carrying amount of the asset, the entity shall recognize
an impairment loss in accordance with SFAS No. 121. Otherwise, an
impairment loss shall not be recognized. The Company adopted SFAS
No. 121 effective July 1, 1996 and recorded a provision for
impairment of its proved oil and gas properties of approximately
$177,000 and $25,000 for the years ended June 30, 1999 and 1998.
Prior to July 1, 1996, the Company assessed the impairment of
proved oil and gas properties on an aggregate basis using
undiscovered estimated future net revenue and constant prices and
costs.
(G)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, 1999 and 1998, the Company is in an under-produced
position of approximately 6,234 MCFs and 13,000 MCFs,
respectively. Accordingly, these amounts have been included in
the reserve quantities as set forth in note 7.
(H)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.
(I)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 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.
(J)LOSS PER SHARE
Loss per share is based on the weighted average number of common
shares outstanding during the period. Outstanding stock options
are excluded from the computation as their effect was
antidilutive.
(2) 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 July 1997, the Company's president exercised options to
purchase 27,884 shares of the Company's common stock. Payment for
the shares of common stock purchased upon exercise of the option
was made in shares of the Company's common stock previously owned
by the Company's president, valued at the market price on the date
of exercise. The Company recorded the 10,544 shares of the
Company's common stock reacquired at cost, which shares were
subsequently retired. In exchange for the withholding taxes due
as a result of the gain on sale recognized by the Company's
president, 5,974 shares of the Company's common stock value at
$21,655 were acquired at cost, which shares were subsequently
retired.
In May 1997, the Company sold 2,502,000 shares of common stock at
a price of $2.00 per share in a private placement. Total
proceeds, net of brokers commissions, were $4,711,100.
Also in May 1997, the Company issued 5,000 shares of common stock
valued at $2.50 per share to a company for services. The fair
value of the common stock of $12,500 was charged to expense in
fiscal 1997.
During the year ended June 30, 1998, certificates for previously
issued shares of the Company's common stock, representing 20
shares were presented for transfer. Prior to presentment, such
shares had not been recorded as issued by the Company.
In September 1998 the Company acquired oil and gas properties by
issuing 25,000 shares of common stock valued at $9,375.
(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
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 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 1999, 1998 and 1997, the Board of Directors granted
options to purchase shares of common stock to key employees and
directors pursuant to the Plan and the Nonqualified Plan. The
exercise prices of the options range from $.50 to $3.88 per share.
The options granted are exercisable upon issuance.
During fiscal 1999, the Board of Directors reduced the number 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.
The Company applies APB Opinion 25 and related interpretations in
accounting for its plans. Accordingly, no compensation cost has
been recognized for stock options granted to key employees and
directors. 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
loss and loss per share would have been increased to the pro forma
amounts indicated below:
<TABLE>
<CAPTION>
Years ended June 30,
----------------------------------
1999 1998 1997
--------- -------- --------
<S> <C> <C> <C>
Net loss:
As reported $(1,441,424)(2,018,692) (1,312,365)
Pro forma (1,605,422)(2,038,934) (1,400,899)
Loss per share:
As reported (0.32) (0.46) (0.56)
Pro forma (0.36) (0.46) (0.60)
</TABLE>
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 1999, 1998 and
1997, respectively: no dividend yield for all years; expected
volatility of 137%, 93% and 98%; weighted average risk-free
interest rates of 5.06% in fiscal 1999, 6.1% in fiscal 1998 and
6.5% in fiscal 1997 for the Incentive Plan options and 6.7% in
fiscal 1997 for the Nonqualified Plan options; and expected lives
of seven years for all years.
During fiscal 1997, the Company granted options to purchase 35,500
shares of common stock at prices ranging from $1.47 to $3.69 per
share to consultants for services. The fair value of the options
granted of $56,500 was charged to expense in fiscal 1997.
A summary of the status of the Company's two fixed stock options
plans as of June 30, 1999 and 1998, and changes during the years
then ended is presented below:
<TABLE>
<CAPTION>
1999
------------------------------
Weighted
average
exercise
Fixed options Shares price
------------- ------ --------
<S> <C> <C>
Outstanding at
beginning of
year 625,616 $ 2.55
Granted 510,642 1.64
Exercised -- --
Cancelled (439,000) 2.94
Expired (5,500) 2.20
-------- --------
Outstanding at end
of year 691,758 1.69
========
Options exercisable
at year end 691,758
Weighted average
fair value of
options granted
during the year $ 0.87
</TABLE>
<TABLE>
<CAPTION>
1998
------------------------------
Weighted
average
exercise
Fixed options Shares price
------------- ------ --------
<S> <C> <C>
Outstanding at
beginning of
year 648,500 $ 2.49
Granted 10,000 2.28
Exercised (32,884) 1.35
Cancelled -- --
Expired -- --
-------- --------
Outstanding at end
of year 625,616 2.55
========
Options exercisable
at year end 625,616
Weighted average
fair value of
options granted
during the year $ 2.01
</TABLE>
<TABLE>
<CAPTION>
1997
------------------------------
Weighted
average
exercise
Fixed options Shares price
------------- ------ --------
<S> <C> <C>
Outstanding at
beginning of
year 570,000 $ 2.54
Granted 81,500 2.11
Exercised -- --
Cancelled -- --
Expired (3,000) 2.47
-------- --------
Outstanding at end
of year 648,500 2.49
========
Options exercisable
at year end 648,500
Weighted average
fair value of
options granted
during the year $ 1.78
</TABLE>
The following table summarizes information about fixed stock
options outstanding at June 30, 1999 (all of which are
exercisable):
<TABLE>
<CAPTION>
Weighted
average
remaining Weighted
Range of exercise Number contractual average
price outstanding life (in years) exercise price
----------------- ---------- -------------- --------------
<S> <C> <C> <C>
$0.50 - 1.03125 180,000 9.6 $0.86
1.25 - 1.3125 31,500 4.2 1.30
1.875 - 2.00 422,160 6.4 1.97
2.25 - 3.00 58,098 8.4 2.39
-------
691,758 7.3 1.69
=======
</TABLE>
(3) INCOME TAXES
At June 30, 1999 and 1998, the Company's significant deferred tax
assets are as follows:
<TABLE>
<CAPTION>
1999 1998
----------- ----------
<S> <C> <C>
Deferred tax assets:
Net operating loss
carryforwards $3,142,000 2,850,000
Depletion carryforwards 175,000 151,000
Oil and gas properties,
principally due to
differences in depreciation
and depletion and impairment 99,000 --
---------- ----------
3,416,000 3,001,000
Deferred liabilities:
Oil and gas properties,
principally due to
differences in depreciation
and depletion and impairment (63,000) (40,000)
Other -- (24,000)
---------- ----------
(63,000) (64,000)
---------- ----------
Valuation allowance (3,353,000) (2,937,000)
---------- ----------
Net deferred tax assets $ -- $ --
========== ==========
</TABLE>
The valuation allowance for deferred tax assets as of June 30, 1999
was $3,353,000. The net change in the valuation allowance for the
year ended June 30, 1999 was an increase of $416,000.
At June 30, 1999, the Company had net operating loss carryforwards of
approximately $8,056,000. The utilization of approximately $932,000
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,
$1,866,000 is limited to the extent of future taxable income generated
by Victoria, and $5,258,000 is available to offset future taxable
income of the Company. If not utilized, the tax net operating losses
will expire during the period from 2000 through 2014.
(4) RELATED PARTY TRANSACTIONS
The Company, through its affiliation with VIP, has the opportunity to
participate in various international permits throughout the world.
The Company earns a right to participate by sharing in the costs of
data review, seismic, and drilling. To date, the Company has agreed
to farm-in on eight international permits, two in Papua New Guinea,
and four in Australia. The Company has agreed to pay VIP a 5% royalty
with respect to the Company's interest in the international permits
for any permits which produce net revenues for the Company.
(5) 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 $60,336, $38,793 and $33,958 for the
years ended June 30, 1999, 1998 and 1997, respectively.
Future minimum rental commitments under noncancelable operating leases
as of June 30, 1999 are as follows:
Fiscal year
2000 $ 58,636
2001 62,590
2002 65,886
2003 44,807
--------
$231,919
========
The Company currently has a 2% to 5% interest in two
prospects in Papua New Guinea and four in Australia.
Under the terms of the exploration permits, the Company is
obligated to share in spending specified amounts in each
annual period in order to retain its interest in the
permit. The Company can generally withdraw from the
permit at the end of any annual period without penalty and
forfeit its interest in the permit. Estimated costs to
maintain permits expected to be incurred over the next 5
years are as follows:
Permit Year
1999 $ --
2000 268,500
2001 82,500
2002 47,500
2003 200,000
Thereafter 200,000
--------
$798,500
========
(6) DISCLOSURES ABOUT CAPITALIZED COSTS, COSTS INCURRED, AND MAJOR
CUSTOMERS
Capitalized costs related to oil and gas producing activities are as
follows:
<TABLE>
<CAPTION>
June 30,
--------------------------
1999 1998
------------ ----------
<S> <C> <C>
Unproved:
Domestic $ 593,511 577,504
Foreign 167,590 111,275
Proved 5,465,748 4,219,282
----------- ----------
6,226,849 4,908,061
Accumulated depletion
and impairment (2,885,851) (2,732,345)
----------- ----------
$ 3,340,998 2,175,716
=========== ==========
</TABLE>
Costs incurred in oil and gas producing activities for the years ended
June 30, 1999 and 1998 were approximately as follows:
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- -------
<S> <C> <C> <C>
Unproved property
acquisition costs $ 127,557 228,000 714,000
Proved property
acquisition costs 2,752 -- --
Development costs 71,819 289,000 88,000
Exploration costs 1,345,487 -- --
</TABLE>
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 1998, the Company had three
major customers. Sales to these customers accounted for approximately
19%, 16% and 10% of fiscal 1998 oil and gas sales. During fiscal
1997, the Company had two major customers. Sales to these customers
accounted for approximately 22% and 18% of fiscal 1997 oil and gas
sales.
(7) 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.
Estimated net quantities of proved developed and undeveloped reserves
of oil and gas for the years ended June 30, 1999, 1998 and 1997 are as
follows:
<TABLE>
<CAPTION>
1999
------------------------------
Oil Gas
(BBLS) (MCF)
-------- ----------
<S> <C> <C>
Beginning of year 222,000 3,483,000
Revisions of previous
quantity estimates 89,000 482,000
Extensions, discoveries
and improved recovery 2,000 2,677,000
Sales of reserves in
place (1,000) --
Production (24,000) (308,000)
-------- ---------
End of year 288,000 6,334,000
======== =========
Proved developed reserves
- end of year 213,000 3,469,000
======== =========
</TABLE>
<TABLE>
<CAPTION>
1998
------------------------------
Oil Gas
(BBLS) (MCF)
-------- ----------
<S> <C> <C>
Beginning of year 267,000 4,617,000
Revisions of previous
quantity estimates (17,000) (1,092,000)
Extensions, discoveries
and improved recovery -- 234,000
Sales of reserves in
place -- --
Production (28,000) (276,000)
-------- ---------
End of year 222,000 3,483,000
======== =========
Proved developed reserves
- end of year 166,000 2,903,000
======== =========
</TABLE>
<TABLE>
<CAPTION>
1997
------------------------------
Oil Gas
(BBLS) (MCF)
-------- ----------
<S> <C> <C>
Beginning of year 480,000 4,900,000
Revisions of previous
quantity estimates (182,000) (59,000)
Extensions, discoveries
and improved recovery 10,000 24,000
Sales of reserves in
place (8,000) --
Production (33,000) (248,000)
-------- ---------
End of year 267,000 4,617,000
======== =========
Proved developed reserves
- end of year 211,000 2,735,000
======== =========
</TABLE>
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.
<TABLE>
<CAPTION>
1999 1998 1997
----------- --------- ----------
<S> <C> <C> <C>
Future cash inflows $16,549,000 8,593,000 13,230,000
Future costs:
Production (6,597,000) (3,392,000) (4,326,000)
Development (1,090,000) (504,000) (623,000)
----------- ---------- ----------
Future net cash flows 8,862,000 4,697,000 8,281,000
10% discount factor (4,583,000) (1,820,000) (3,074,000)
----------- ---------- ----------
Standardized measure
of discounted future
net cash flows $4,279,000 2,877,000 5,207,000
========== ========== ==========
</TABLE>
The principal sources of changes in the standardized measure of
discounted future net cash flows during the years ended June 30, 1999,
1998 and 1997, are as follows:
<TABLE>
<CAPTION>
1999 1998 1997
----------- --------- ---------
<S> <C> <C> <C>
Beginning of year $2,877,000 5,207,000 5,445,000
Sales of oil and gas
produced during the
period, net of
production costs (219,000) (468,000) (745,000)
Net change in prices
and production costs 216,000 (1,325,000) 650,000
Changes in estimated
future development
costs (80,000) 103,000 169,000
Extensions, discoveries
and improved recovery 1,656,000 96,000 50,000
Revisions of previous
quantity estimates and
other (414,000) (1,257,000) (934,000)
Net change in income
taxes -- -- 50,000
Sales of reserves in place -- -- (23,000)
Purchase of reserves in
place (45,000) -- --
Accretion of discount 288,000 521,000 545,000
----------- ---------- ---------
End of year $ 4,279,000 2,877,000 5,207,000
=========== ========== =========
</TABLE>
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.
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 1999 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 1999 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 1999 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 1999 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 (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 That portion entitled "Selling Restriction" of
the Registrant's Private Placement memorandum dated
April 2, 1997 filed as Exhibit 4.4 to the Registrant's
Form S-3 Registration Statement (No. 333-27769) 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
February 24, 1999 and filed as Exhibit 10.1 with the
Company's Registration Statement on Form S-8 (SEC No.
333-74101) and Incorporated herein by reference.
21 Subsidiaries of the Registrant filed as Exhibit
21 with the Annual Report on Form 10-K for the year
ended June 30, 1997 and incorporated herein by
reference.
23 Consent of KPMG LLP
27 Financial Data Schedule
(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
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: September 29, 1999 By: /s/ Timothy L. Hoops
---------------------------------
Timothy L. Hoops, President
and Chief Executive 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: September 29, 1999 By: /s/ Timothy L. Hoops
---------------------------------
Timothy L. Hoops, President,
Chief Executive Officer,
and Director
Date: September 29, 1999 By: /s/ Robert J. Pett
---------------------------------
Robert J. Pett, Chairman of
the Board
Date: September 29, 1999 By: /s/ Mark A. Boatright
---------------------------------
Mark A. Boatright,
Vice President, Finance,
Chief Financial Officer,
and Director
Date: September 29, 1999 By: /s/ Kenneth W. Nickerson
---------------------------------
Kenneth W. Nickerson, Director
Date: September 29, 1999 By: /s/ John T. Kopcheff
---------------------------------
John T. Kopcheff, Vice President
International, and Director
Date: September 29, 1999 By: /s/ Mark A. E. Syropoulo
---------------------------------
Mark A. E. Syropoulo, Director
EXHIBIT 23
INDEPENDENT AUDITORS' CONSENT
The Board of Directors
Kestrel Energy, Inc.:
We consent to the incorporation by reference in the registration
statements (No. 33-63171, 333-45587, 333-51875 and 333-74101) on Form S-8
and the registration statements (Nos. 33-89716, 333-27769 and 333-87473)
on Form S-3 of Kestrel Energy, Inc. our report dated September 10, 1999,
relating to the consolidated balance sheets of Kestrel Energy, Inc. and
subsidiaries as of June 30, 1999 and 1998, and the related consolidated
statements of operations, stockholders' equity and cash flows for each of
the years in the three-year period ended June 30, 1999, which report
appears in the June 30, 1999 Annual Report on Form 10-K of Kestrel Energy,
Inc.
KPMG LLP
Denver, Colorado
September 29, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> JUN-30-1999
<PERIOD-END> JUN-30-1999
<CASH> 395
<SECURITIES> 0
<RECEIVABLES> 171
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 653
<PP&E> 6,366
<DEPRECIATION> 2,960
<TOTAL-ASSETS> 4,059
<CURRENT-LIABILITIES> 93
<BONDS> 0
0
0
<COMMON> 13,149
<OTHER-SE> (9,183)
<TOTAL-LIABILITY-AND-EQUITY> 4,059
<SALES> 632
<TOTAL-REVENUES> 773
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 2,214
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> (1,441)
<INCOME-TAX> 0
<INCOME-CONTINUING> (1,441)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (1,441)
<EPS-BASIC> (.32)
<EPS-DILUTED> (.32)
</TABLE>
