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, 1996 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 1100
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. [ X ]
At August 31, 1996, 1,908,612 common shares (the registrant's only
class of voting stock) were outstanding. The aggregate market value of
the 733,847 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 approximately $1,513,559.
<PAGE>
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. . . . . . . . . . . . . . . . . . . . . .4
Royalty Interests Under Producing Properties . . . . . . . . . .5
Permit Obligations . . . . . . . . . . . . . . . . . . . . . . .5
Drilling Activities. . . . . . . . . . . . . . . . . . . . . . .8
Oil and Gas Production, Prices and Costs . . . . . . . . . . . .8
Customers. . . . . . . . . . . . . . . . . . . . . . . . . . . .8
Office Facilities and Administrative Services. . . . . . . . . .8
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . . . .8
Item 4. Submission of Matters to a Vote of Security Holders. . . . .8
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. . . . . . . . . . . . . . . . . . . . . . . . 9
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. . . . . . . . . . . . . . . . . . . . . 12
Item 8. Financial Statements and Supplementary Data. . . . . . . . 14
Financial Statements . . . . . . . . . . . . . . . . . . . . . 14
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.. . . . . . . . . . . . . . . . . . . 14
PART III. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Item 10. Directors and Executive Officers. . . . . . . . . . . . . 15
Item 11. Executive Compensation. . . . . . . . . . . . . . . . . . 15
Item 12. Security Ownership of Certain Beneficial Owners and
Management . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Item 13. Certain Relationships and Related Transactions. . . . . . 15
PART IV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..15
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
SIGNATURES 18
<PAGE>
PART I
Item 1. Business.
General Description of Business
Kestrel Energy, Inc. 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 plans to continue its international
exploration program during fiscal 1997.
The Company presently owns oil and gas interests in the states of
California, Colorado, Kansas, Louisiana, New Mexico, Oklahoma, South
Dakota, Texas, and Wyoming.
The Company has also acquired farm-in interests in Production
Prospecting License (PPL) 106 in Papua New Guinea and Exploration Permit
(EP) 325, EP 367, WA-254-P, and ATP 560P in Australia. The Company,
through its affiliation with Victoria International Petroleum N.L., has
earned farm-in interests ranging from 2.14% to 10.29% in various wells on
the prospects listed above. The Company earns the farm-in interest by
contributing to the costs of drilling a well on the prospect. To date, the
Company has earned a 5% working interest in PPL 106 in Papua New Guinea, a
10.29% working interest in EP 367, a 2.14% to 3.0% working interest in WA-
254-P in Western Australia, and a 5% interest in EP 325, Western Australia
and a 5% interest in Authority To Prospect (ATP) 560P in Queensland,
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.
Recent Activities
The Company acquired a 5% working interest in ATP 560P in Queensland
during the fourth quarter of fiscal 1996. The McIver #1 well was drilled
on that prospect in April of 1996 but was abandoned as a dry hole at an
approximate cost of $25,000 to the Company. Future drilling opportunities
in the associated exploration permit are being evaluated by the Company.
The Company also participated in the drilling of the Helicon #1
well in the WA-254-P Prospect, Western Australia in July, 1996. The well
was abandoned as a dry hole at a cost of $26,000 to the Company. The
Company continues to evaluate the permit for future drilling opportunities
by participating in additional seismic acquisition.
The Company participated in the successful completion of an
offset well, the Gallion #5, N.E. Krebs prospect, Pittsburg County
Oklahoma, in August 1996. The Company anticipates costs of approximately
$15,000 to complete the well. The Gallion #5 is a gas well, and increased
the Company's proved gas reserves by approximately 159,000 mcf.
Operations and Policies
The Company does not limit its consideration of acquisition
opportunities to any geographical area. 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; anticipated
prices of oil and gas; 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 parent, Victoria
International Petroleum N.L. These joint ventures will allow the Company
access to more acquisition candidates and enable the Company to share the
evaluation and other costs among the joint ventures.
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 three 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. 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 intends to actively review, select and negotiate for the
purchase of producing oil and gas properties, subject to the Company's
ability to obtain reasonable and adequate financing for such properties.
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 on the Company's working
interest in the international permits, provided to the Company by its
affiliate which produce net revenues for the Company.
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, 1996.
<TABLE>
<CAPTION>
Total Total
----- -----
Developed Acreage Undeveloped Acreage
<S> <C> <C> <C> <C>
State Gross Net Gross Net
- ----- ----- ----- ----- -----
California 290 44 - 0 - - 0 -
Colorado - 0 - - 0 - 722 342
Kansas 480 62 - 0 - - 0 -
Louisiana 6,202 1,623 - 0 - - 0 -
New Mexico 2,520 1,456 - 0 - - 0 -
Oklahoma 3,332 415 - 0 - - 0 -
South Dakota 160 20 - 0 - - 0 -
Texas 1,140 74 - 0 - - 0 -
Wyoming 36,143 2,991 5,370 1,755
------- ----- ----- -----
TOTAL 50,267 6,685 6,092 2,097
Canada 640 19 - 0 - - 0 -
Papua New Guinea - 0 - - 0 - 864,500 43,225
Australia - 0 - - 0 - 721,856 35,743
(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 33,499 acres.
</TABLE>
Royalty Interests Under Producing Properties
At June 30, 1996, the Company held overriding royalty interests
ranging from 0.013% to 9.26% in 116 producing oil and gas wells located on
30,245 gross developed acres in the United States.
Permit Obligations
PPL 106, Papua New Guinea
In November, 1994 the Company earned a 5% working interest in PPL 106 by
the drilling of the Menga #1. Concurrent with the earning of 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 5% Working Interest
- ------- ---- -------------------
<S> <C> <C>
Years 3&4
(ending January 31, 1998) Regional and detail
geological mapping
or geophysical survey $ 45,000
Year 5
(ending January 31, 1999) One well $ 225,000
---------
Total $ 270,000
</TABLE>
The drilling of the Menga #1 well in November 1994 satisfied the well
obligation for the permit year ending January 31, 1996. That well was
abandoned as a dry hole after a cost to the Company of $284,000.
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 Papua New Guinea government 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%.
<TABLE>
<CAPTION>
EP 325, Australia
Kestrel Share of
Anticipated Expenditures
Current: Work 5% Working Interest
- ------- ---- -------------------
<S> <C> <C>
Year 4
(ending January 20, 1997) One well $ 80,000
Year 5
(ending January 20, 1998) Data review $ 5,000
-----------
Total $ 85,000
</TABLE>
In November 1995, the Company earned a 5% working interest in EP 325 by
drilling the Spider #1. The well was abandoned as a dry hole at a cost of
$85,000.
Subject to EP 325 Joint Venture approval, the White Opal #1 exploration
well is planned for drilling in November 1996. It is the present intention
of the Company to reduce its cost exposure to the well by farmout which
will result in a reduced interest to the Company subject to the terms of
any farmout negotiated.
EP 367, Australia
In October, 1994 the Company earned a 10.29% working interest in EP 367 by
the drilling of the Jasper #1. Concurrent with the earning of 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 Future
Expenditures
Current: Work 10.29% Working Interest
- ------- ---- -----------------------
<S> <C> <C>
Year 5
(ending May 28, 1997) One well $ 100,000
------------
Total $ 100,000
</TABLE>
The Beadon Seismic Survey shot in May 1996, at an estimated cost to the
Company of $7,000, satisfied the work obligation for the permit Year 4
ended May 1996.
Exploration Permits (EP) for petroleum are granted by the State of Western
Australia over exploration areas in state-controlled in-shore waters and
on-shore 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
work 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, but must relinquish 50% of the existing permit's
acreage.
WA-254-P, Australia
The Company entered into a farmout agreement along with the other
participants in the WA-254-P permit which resulted in the permit being
split into four areas. As a result of the farmout agreement the Company
earned a 1.14% carried working interest in the Helicon #1 well and reduced
it's original 5% working interest and now has a 2.14% working interest in
Parts 1, 3, and 4, and a 3.00% working interest in Part 2.
<TABLE>
<CAPTION>
Kestrel Share of
Anticipated Future
Expenditures
Current: Work 3% Working Interest
- ------- ---- -------------------
<S> <C> <C>
Year 3
(ending January 30, 1997*) One well, seismic $ 25,000
Year 4
(ending January 30, 1998) Data review $ 10,000
Year 5
(ending January 30, 1999) 60 miles seismic $ 10,000
Year 6
(ending January 30, 2000) One well $ 187,500
------------
Total $ 232,500
</TABLE>
The drilling of the Bellerophon #1 well satisfied the well obligation for
the permit year ending January 30, 1996.
*Helicon #1 was drilled in July 1996. The well was abandoned as a dry hole
at a cost of approximately $25,000. Remaining costs for Permit Year 1997
listed above are in addition to costs already expended on Helicon #1.
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, with the
work program specified on a year by year minimum work commitment basis.
The first three years work program is mandatory. After completion of the
first three years work program, permitees can withdraw from the permit at
any time by completing the current year's work program and giving notice
of withdrawal 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 but must relinquish 50%
of the existing permit's acreage.
ATP 560P, Australia
The Company earned a 5% interest in the McIver Block of ATP 560P by
participating in the drilling of the McIver #1 in April 1996. The well was
abandoned as a dry hole at a cost of $24,000. The Company's remaining
obligations for the McIver Block over the next two years are data review
costs.
<TABLE>
<CAPTION
Kestrel Share of
Anticipated Future
Expenditures
Current: Work 3% Working Interest
- ------- ---- -------------------
<S> <C> <C>
Year 3
(ending December 1, 1996) Data review $ 2,000
Year 4
(ending December 1, 1997) Data review $ 2,000
----------
Total $ 4,000
</TABLE>
Authorities to Prospect (ATP) are granted by the State of Queensland over
exploration areas onshore for a term of four years. ATP holders may
withdraw without penalty from an ATP once the current year's work program
is satisfied, and prior to commencement of the next years program.
Drilling Activities
The Company participated in the drilling of four wells since June 30,
1995. Three of the wells drilled were dry holes. The unsuccessful wells
were the Spider #1, located in EP 325 in Western Australia, the McIver -
1, located in ATP 560P in Queensland and the Helicon - 1 drilled in July
1996 on the WA - 254-P prospect, Western Australia. The Company completed
the Gallion #5, Pittsburg County, Oklahoma in August 1996. The well was an
offset well on the N.E. Krebs prospect, a producing lease held by the
Company.
Oil and Gas Production, Prices and Costs
As of June 30, 1996, the Company had a royalty and/or working
interest in 94 gross (7.08 net) wells that produce oil only, 19 gross
(2.54 net) wells that produce gas only, and 178 (11.4 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 9 to the financial statements
included in Item 8 of this Report. The reserve estimates for the reporting
year were prepared by Jeffrey W. Rhodes, an independent petroleum engineer
and a consultant to the Company. The Company did not file any oil and gas
reserve estimates with any federal authority or agency during its fiscal
year ended June 30, 1996.
For the year ended June 30, 1996, the Company's average operating
cost (including taxes and marketing) per barrel of oil equivalent (BOE)
(converting gas to oil at 6:1) was $6.94. The average operating cost per
BOE on an equivalent basis for fiscal years 1995 and 1994 was $6.22 and
$4.67, respectively. The average sales price per barrel of oil sold was
$18.65 for 1996, $16.64 for fiscal 1995, and $14.25 for fiscal 1994. The
average sales price per Mcf of gas sold was $1.60 in 1996, $1.35 for 1995,
and $1.79 for fiscal 1994.
Customers
During fiscal year 1996 the Company had two major customers, Eighty-
Eight Oil Co., and Saba Energy. Sales to these customers accounted for
26% and 15%, respectively, of oil and gas sales in 1996. 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 and Administrative Services
The Company's executive offices are currently located at 999 18th
Street, Suite 1100, Denver, Colorado 80202. The Company's current lease
obligation expires November 30, 1997.
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
Small Cap Market under the symbol "KEST." At June 30, 1996 the Company
had 1,908,612 shares outstanding. At June 30, 1996, 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,
mark-down or commission and may not necessarily represent actual
transactions.
<TABLE>
<CAPTION>
Bid Ask
--- ---
<S> <C> <C> <C> <C>
Fiscal Year June 30, 1995 High Low High Low
First Quarter $3.50 $2.50 $4.50 $3.00
Second Quarter 3.50 1.75 4.25 3.00
Third Quarter 1.75 .75 3.00 2.00
Fourth Quarter 1.75 1.00 2.25 1.75
</TABLE>
<TABLE>
<CAPTION>
Fiscal Year June 30, 1996 Sales Price
-----------
<S> <C> <C>
High Low
---- ---
First Quarter $4.88 $1.13
Second Quarter 5.13 2.88
Third Quarter 3.75 1.63
Fourth Quarter 5.13 2.38
</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,
1996 1995 1994
<S> <C> <C> <C>
Oil and Gas
Sales $1,198,795 $1,334,667 $ 706,337
Total Revenue 1,268,456 1,1397,775 730,413
Net Income (Loss) (160,231) (1,119,113) 928
Income (Loss) Per
Common Share (.08) (.64) *
At June 30,
Total Assets $4,115,211 4,287,984 4,044,086
Long-Term Debt - - 600,000
Stockholders'
Equity 3,964,708 4,072,225 3,226,022
</TABLE>
<TABLE>
<CAPTION>
Years ended June 30,
1993 1992
<S> <C> <C>
Oil and Gas
Sales $ 985,428 $ 337,335
Total Revenue 1,025,375 350,654
Net Income (Loss) 349,956 (77,400)
Income (Loss) Per
Common Share .75 (.30)
At June 30,
Total Assets $2,606,818 2,376,276
Long-Term Debt 1,058,000 1,000,000
Stockholders'
Equity 1,488,931 1,138,975
* Less than .01 per share
</TABLE>
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Liquidity and Capital Resources
Working Capital and Cash Flows: The Company's primary source of
liquidity is cash flow from operations and existing cash on hand. Net
working capital at June 30, 1996, was $1,009,113 compared to working
capital of $1,035,859 on June 30, 1995 and working capital of $442,397 at
June 30, 1994. The decrease in working capital of $26,746 during the
current year ended June 30, 1996 was a result of lower operating cash
flows. The increase in working capital of $593,462 from June 30, 1994 to
1995 resulted from a series of private placements of the Company's common
stock, less amounts expended on drilling activities.
Net cash used by operating activities totaled $28,380 for fiscal year
1996 as compared to cash used by operating activities of $272,492 for
fiscal year 1995, a decrease of $244,112. Factors contributing to the
reduction in operating cash flows used were higher oil and gas prices,
lower production expenses, and a reduction in dry hole costs. In 1994,
cash provided by operating activities was $266,547. The decrease in
operating cash flows from 1994 to 1995 was a result of lower oil and gas
revenue, higher administrative costs associated with the acquisition of
Victoria Exploration, Inc. and higher dry hole costs.
Net cash used by investing activities was $500,076 in 1996 as
compared to $781,457 used in 1995 and $189,528 in 1994. During the fiscal
year ended June 30, 1996, $212,595 was used to purchase producing and
non-producing leasehold interests and fixed assets. The expenditures
included the purchase of a 20% working interest in the Boos Unit, Campbell
County, Wyoming, and additional investment in various Australian
prospects, including WA-254-P and EP 325, and PPL 106 in Papua, New
Guinea. During the fiscal year ended June 30, 1995, $527,382 was used for
capital expenditures. The expenditures included a waterflood project on
the Pierce field, lease acquisition costs on the Menga #1 and the Jasper
#1, and the drilling of developmental wells on the Walker Creek Field. A
total of $226,003 was used in 1994 for capital expenditures and was
associated with the drilling of the Edna Dupplechain well, and the
purchase of, the McEntire Property. Proceeds from assets sales were
$60,879, consisting of sales of used well equipment, and the sale of the
Company's interests in the Sam Acola lease in Texas and the Royal Federal
35-7 on the North Adon leasehold in Wyoming. Proceeds from asset sales
were $42,399 in 1995, consisting of the sale of a compressor. No property
sales were made during 1994. The Company purchased short term
investments with its excess cash during 1996 in the amount of $348,360 as
compared to purchases of $296,474 in 1995. No investments were purchased
in 1994.
Cash provided by financing activities was $52,714 in 1996 as compared
to $1,365,336 in 1995. Approximately $41,625 of the cash provided was
attributable to the payment to the Company of the short-term gain realized
by an affiliate on the sale of shares of the Company's stock held less
than six months. Additional proceeds from the issuance of common stock in
the amount of $11,089 were received by the Company pursuant to the
exercise of stock options under the Company's Nonqualified Stock Option
Plan. In 1995, the Company strengthened its cash position by the sale of
551,200 shares of its common stock at $2.50 per share in a private
placement. No cash was used or provided by financing activities in 1994.
The Company acquired a 70% interest in the Rocky Butte Field in
Campbell County, Wyoming as part of the purchase from Victoria
Exploration, Inc. in June 1992. At that time, Victoria Petroleum N.L.
guaranteed that the property would produce a minimum of $600,000 in
positive cash flow. In December 1994, the Company entered into an
agreement with Victoria International Petroleum N.L. to transfer its
interest in the non-producing Rocky Butte Prospect in exchange for the
long term debt owed to Victoria International Petroleum N.L. in the amount
of $600,000. As a result of this transaction, the Company expensed its
cost in the prospect in the amount of $479,119 and increased stockholders
equity by the amount of the debt extinguished.
The Company has capital commitments of approximately $207,000 for the
fiscal year ending June 30, 1997, as described more fully under Permit
Obligations on Pages 5-7. These commitments can 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 it's interest in a permit.
Stockholders Equity: Stockholder equity decreased 3% to $3,964,708
in 1996 from $4,072,225 a year ago. The decrease is attributable to the
net loss incurred by the Company for the year. Stockholder equity
increased 26% to $4,072,225 during fiscal year 1995 from $3,226,022 in
1994. The increase was a result of the private placement of common stock
during the year. Stockholder equity increased 117% during fiscal year
1994 to $3,226,022 from $1,488,931 in 1993. The primary factor leading to
this increase was the assets acquired in the acquisition of Victoria
Exploration, Inc.
Debt Obligations: The Company had no long term debt at June 30, 1996
or June 30, 1995. In fiscal year 1995, the Company transferred a non-
producing property in exchange for the $600,000 debt as described above.
The Company's long term debt at June 30, 1994 was $600,000, a decrease of
$458,550 from year end 1993 debt of $1,058,550. The decrease was
accomplished by converting a portion of the June 30, 1992 debt owed to
Victoria Exploration, Inc. into 207,263 shares of the Company's common
stock.
Reserves and Future Cash Flows: The Company's proved oil reserves
increased by approximately 41,000 Bbls, or 10% from 439,000 Bbls. in 1995
to 480,000 Bbls. in 1996. The Company's proved gas reserves increased 575
Mmcf from 4,325 Mmcf in 1995 to 4,900 Mmcf in 1996, a 13% increase. The
increases are a function of production during the year and revisions due
to higher oil and gas prices. During the year, the Company purchased
approximately 159,000 mcf of gas production.
The Company's undiscounted net future cash flows have been estimated
by Jeffrey W. Rhodes, an independent petroleum engineer providing
consulting services to the Company, to be approximately $9,300,000 as of
June 30, 1996. This compares to $6,990,000 in 1995 and $8,743,000 in 1994.
The increase is a result of higher oil and gas prices at June 30, 1996 and
a revision of previous quantity estimates. The decrease in 1995 was
primarily due to lower gas prices, lower sales of oil and gas produced,
and the revision of previous quantity estimates.
Gas Balancing: The Company at June 30, 1996, was underproduced
approximately 31,000 Mcf. The Company was underproduced by 16,000 Mcf of
gas at June 30, 1995. These amounts are included 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, 1996,
the Company estimated that, for United States federal income tax purposes,
it had consolidated net operating loss carryforwards of approximately
$5,590,000. The utilization of approximately $2,700,000 of these
carryforwards are limited to an estimated $80,000 annually. The balance
of the loss carryforwards, $2,130,000 are limited to the extent of future
taxable income to be generated by the Company's subsidiary, Victoria
Exploration, Inc., and $760,000 is available to offset future taxable
income of the Company. If not utilized, the net operating loss
carryforwards will expire during the period from 1997 through 2010.
Accounting Policies: 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 is 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
indentifiable intangibles to be held and used for impairment whenever
events or changes in circumstances indicate that the carrying amount for
an asset may not be recoverable. An entity shall estimate the future cash
flows expected to result from the use of the asset and its eventual
disposition. Future cash flows are future cash inflows expected to be
generated by an asset 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 has not adopted SFAS No. 121 as of June
30, 1996; however, the Company estimates that if it were to adopt SFAS No.
121 as of that date, it would be required to record a provision of
approximately $220,000 for the impairment of certain of its oil and gas
properties.
Statement of Financial Accounting Standards No. 123, "Accounting for
Stock Based Compensation" (SFAS No. 123), was issued by the Financial
Accounting Standards Board in October 1995. SFAS No. 123 establishes
financial accounting and reporting standards for stock-based employee
compensation plans as well as transactions in which an entity issues its
equity instruments to acquire goods or services from non-employees. The
Company will include the disclosures required by SFAS No. 123 in the notes
to future financial statements.
Results of Operations
Fiscal 1996 vs Fiscal 1995
Net Earnings: The Company reported a loss of $160,231 in fiscal 1996
compared to a loss of $1,119,133 in 1995, a decrease of $958,902. The
reduction in net loss was a result of lower dry hole costs, lower lease
operating expenses, and lower depletion expense incurred during the year.
Revenue: Total revenue decreased in fiscal 1996 by $129,319, or 9% to
$1,268,456 versus $1,397,775 in 1995. The decrease in revenues was
associated with lower sales volumes of both oil and gas during the year.
Revenue from oil and gas sales was $1,198,795 in 1996, a decrease of
$135,872, or 10%, from $1,334,667 recorded in 1995. Sales volumes
decreased for both oil and gas during the year to 41,000 Bbls. of oil and
273 Mmcf of gas from 54,000 Bbls. of oil and 303 Mmcf of gas in 1995.
Average prices per barrel of oil increased 12% to $18.65 from $16.64 a
year ago. Average prices received per Mcf of gas increased 19% to $1.60
versus $1.35 in 1995.
Lease Operating Expenses: Production expenses decreased $53,513 or 8%
to $598,487 from $652,000 a year ago. The decrease in production expense
was a result of lower workover costs and production taxes. Lease operating
costs incurred on a BOE (barrel of oil equivalent) basis increased 12% to
$6.94 from $6.22 a year ago.
Dry Holes, Abandoned and Impaired Properties: Dry hole costs
decreased by $435,210 to $135,448 for fiscal 1996 from $570,658 in 1995.
The Company drilled three dry holes during the year, all on leaseholds in
Australia. Abandonment costs were $18,482, a decrease of $466,920, or 96%
from year ago levels. The Company abandoned the N.E. Dry Gulch Prospect,
and plugged and abandoned the McIlhenny gas well in Louisiana. Impairment
expense of $48,817 has been recorded for fiscal 1996.
General and Administrative Expense: General and administrative
expenses increased $13,903, or 3%, to $437,394 versus $423,491 in 1995.
Interest Expense: There was no interest expense in 1996 versus
$22,058 a year ago. The decrease in interest expense was attributable to
the transfer during 1995 of the Rocky Butte property to Victoria
International Petroleum N.L. in exchange for a note payable to them in the
amount of $600,000.
Fiscal 1995 vs. Fiscal 1994
Net Earnings: The Company reported a loss of $1,119,133 in fiscal
1995 as compared to earnings of $928 in 1994, a decrease of $1,120,061.
Decreased revenue resulted from lower oil prices and gas prices, higher
depletion expenses, the non cash write-off of $479,119 on the exchange of
the Rocky Butte property, and approximately $570,000 in dry hole costs
contributed to the decrease in earnings.
Revenue: Total revenue increased in fiscal year 1995 by $667,362,
or 91%, to $1,397,775 from $730,413 in fiscal 1994. The primary factor
contributing to the increase was the acquisition of additional Victoria
Exploration, Inc. properties in June, 1994.
Revenue from oil and gas sales was $1,334,667 in 1995, an increase of
$628,330, or 89%, from the $706,337 received in 1994. Production volumes
increased during 1995 for both oil and gas to 54,000 Bbls. for oil and
303,000 Mcf for gas. Average prices received per barrel of oil increased
to $16.64 from $14.25 in 1994. Average prices received per Mcf of gas
decreased to $1.35 from $1.79 in 1994. The acquisition of the Victoria
Exploration, Inc.'s properties in June 1994 accounted for the increase in
revenues and production volumes, offset in part by lower gas prices in
1995.
In fiscal 1995 the Company produced approximately 54,000 barrels of
oil and 303 Mmcf of gas, which is an increase of 28,000 Bbls and 116 Mmcf
from 1994, or 107% and 62% respectively. These increases are the result
of the acquisition of Victoria Exploration, Inc. in June 1994.
Interest income increased 340% to $44,361 from $10,067 a year ago.
The increase is attributable to the proceeds received from the sales of
common stock during the year and their investment in interest bearing
investments. Gain on sale of assets was $10,176 in 1995.
Lease Operating Expenses: Production expenses were $652,000 as
compared to $253,368 in 1994, an increase of $398,632, or 157%. The
increase in production expense is attributable to the acquisition of
Victoria Exploration, Inc. in June 1994, and an overall increase in
operating costs to produce as reflected in the increase in operating costs
on a BOE (barrel of oil equivalent) basis from $4.67 in 1994 to $6.22 in
1995. Production expenses were $253,368 in fiscal 1994 as compared to
$294,566 in 1993, a decrease of $41,198, or 14.0%.
Dry Holes and Abandoned Properties: Dry hole costs were $570,658
for the year ended June 30, 1995. The Company drilled four dry holes
during the year, two in Western Australia, one in Papua New Guinea, and
one in Campbell County, Wyoming. Dry hole costs were $13,700 in 1994. In
1995 the Company also had abandonment costs of $485,402, relating to the
non-cash write-off of the Rocky Butte Prospect and the Mchlhenny B-1 in
Louisiana. No properties were abandoned in 1994.
General and Administrative Expense: General and administrative
costs increased $223,655, or 112% in 1995 to $423,491 from $199,836 in
1994. The reasons for the increase are higher costs associated with the
Company's activity level and absorption of all of Victoria Exploration,
Inc.'s general and administrative expenses.
Interest Expense: Interest expense in 1995 declined to $22,058
versus $51,232 in 1994. Interest expense declined due to the transfer of
the Rocky Butte property to Victoria International Petroleum N.L. in
exchange for $600,000 in debt.
Item 8. Financial Statements and Supplementary Data.
See pages F-1 through F-16 for this information.
<PAGE>
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Kestrel Energy, Inc.:
We have audited the accompanying consolidated balance sheets of Kestrel
Energy, Inc. (a subsidiary of Victoria International Petroleum N.L.) and
subsidiary as of June 30, 1996 and 1995, 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, 1996. 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 subsidiary as of June 30, 1996 and 1995, and the
results of their operations and their cash flows for each of the years in
the three-year period ended June 30, 1996, in conformity with generally
accepted accounting principles.
KPMG Peat Marwick LLP
Denver, Colorado
September 13, 1996
<PAGE>
KESTREL ENERGY, INC.
AND SUBSIDIARY
(A Subsidiary of Victoria International Petroleum N.L.)
Consolidated Balance Sheets
June 30, 1996 and 1995
- ------------------------------------------------------------------
<TABLE>
<CAPTION>
Assets 1996 1995
---- ----
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 300,399 776,141
Short-term investments 644,834 296,474
Accounts receivable 164,805 51,224
Related party receivable 25,560 25,560
Other current assets 24,018 2,219
--------- ---------
Total current assets 1,159,616 1,251,618
--------- ---------
Property and equipment, at cost:
Oil and gas properties, successful
efforts method of accounting
(notes 2, 3, and 8):
Unproved 309,931 234,833
Proved 4,084,044 4,070,059
Furniture and equipment 58,554 54,331
--------- ---------
4,452,529 4,359,223
Accumulated depreciation and
depletion (1,496,934) (1,322,857)
--------- ---------
Net property and equipment 2,955,595 3,036,366
$ 4,115,211 4,287,984
========= =========
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable:
Trade $ 78,680 106,747
Related party 32,742 2,756
Accrued liabilities 39,081 106,256
--------- ---------
Total current liabilities 150,503 215,759
--------- ---------
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;
1,908,612 and 1,901,818 shares
issued at June 30, 1996 and 1995,
respectively 8,374,654 8,321,940
Accumulated deficit (4,409,946) (4,249,715)
--------- ---------
Total stockholders' equity 3,964,708 4,072,225
--------- ---------
Commitments (note 7)
$ 4,115,211 4,287,984
========= =========
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
KESTREL ENERGY, INC.
AND SUBSIDIARY
(A Subsidiary of Victoria International Petroleum N.L.)
Consolidated Statements of Operations
Years Ended June 30, 1996, 1995, and 1994
- ----------------------------------------------------------------
<TABLE>
<CAPTION>
1996 1995 1994
<S> <C> <C> <C>
Revenue:
Oil and gas sales $ 1,198,795 1,334,667 706,337
Gain on sale of property
and equipment 14,289 10,176 -
Interest income 44,147 44,361
10,067
Other, net 11,225 8,571 14,009
-------- -------- --------
Total revenue 1,268,456 1,397,775 730,413
-------- -------- --------
Costs and expenses:
Lease operating expenses 598,487 652,000 253,368
Dry holes, abandoned and
impaired properties 202,747 1,056,060 13,712
Depreciation and depletion 190,059 363,299 211,337
General and administrative 437,394 423,491 199,836
Interest expense - 22,058 51,232
-------- -------- --------
Total costs and expenses 1,428,687 2,516,908 729,485
-------- -------- --------
Net income (loss) $ (160,231) (1,119,133) 928
======== ======== ========
Income (loss) per share $ (.08) (.64) *
======== ======== ========
Weighted average number of common
shares outstanding 1,908,612 1,738,732 578,054
======== ======== ========
* Less than .01 per share.
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
KESTREL ENERGY, INC.
AND SUBSIDIARY
(A Subsidiary of Victoria International Petroleum N.L.)
Consolidated Statements of Stockholders' Equity
Years Ended June 30, 1996, 1995, and 1994
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
Total
Common stock Accumulated stockholder's
------------------
Shares Amount deficit equity
------ ------ ----------- ---------
<S> <C> <C> <C> <C>
Balance, June 30, 1993 433,217 $ 4,620,441 (3,131,510) 1,488,931
Common shares issued to
Victoria Exploration,
Inc. (Victoria) in
exchange for a
reduction in note
payable (note 3) 207,263 466,343 -- 466,343
Common shares issued to
acquire Victoria
Exploration, Inc.
(note 2) 709,108 1,269,820 -- 1,269,820
Net income -- -- 928 928
--------- --------- --------- ---------
Balance, June 30,
1994 1,349,588 6,356,604 (3,130,582) 3,226,022
Common shares issued,
net of offering
costs (note 4) 551,200 1,365,336 -- 1,365,336
Adjustment for
previously
issued and unrecorded
shares (note 4) 20 -- -- --
Exchange of non-producing
property for debt
owed to Victoria
International Petroleum
N.L. (VIP) (note 2) - 600,000 -- 600,000
Net loss -- -- (1,119,133) (1,119,133)
------ -------- ---------- ----------
Balance, June 30,
1995 1,900,808 8,321,940 (4,249,715) 4,072,225
Exercise of stock
options 6,750 11,089 -- 11,089
Proceeds from sale of
stock by VIP
(note 6) -- 41,625 -- 41,625
Adjustment for
previously issued
and unrecorded
shares (note 4) 44 -- -- --
Net loss -- -- ( 160,231) ( 160,231)
---------- -------- --------- ---------
Balance, June 30,
1996 1,907,602 $8,374,654 (4,409,946) 3,964,708
========= ========== ========= =========
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
KESTREL ENERGY, INC.
AND SUBSIDIARY
(A Subsidiary of Victoria International Petroleum N.L.)
Consolidated Statements of Cash Flows
Years Ended June 30, 1996, 1995, and 1994
- -------------------------------------------------------------------------
<TABLE>
<CAPTION>
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
Cash flows from operating
activities: Net income (loss) $(160,231) (1,119,133) 928
Adjustments to reconcile net
income (loss) to net cash
provided (used) by operating
activities:
Depreciation and depletion 190,059 363,299 211,337
Abandoned and impaired
properties 56,717 479,119 --
Gain on sale of property and
equipment (14,289) (10,176) --
Changes in operating assets
and liabilities, net of
acquisition:
(Increase) decrease in
accounts receivable (13,581) 40,608 20,280
Increase in related party
receivables -- (25,560) --
(Increase) decrease in
other current assets (21,799) 1,656 922
Increase (decrease) in
accounts payable -- trade (28,067) (40,816) 13,715
Increase (decrease) in
accounts payable --
related party 29,986 (15,191) --
Increase (decrease) in
accrued liabilities (67,175) 53,702 19,365
-------- -------- --------
Net cash provided (used)
by operating activities (28,380) (272,492) 266,547
-------- -------- --------
Cash flows from investing activities:
Capital expenditures (212,595) (527,382) (226,003)
Purchase of short-term investments,
net (348,360) (296,474) --
Cash acquired in acquisition of
Victoria Exploration, Inc.,
net of costs incurred of $46,700 -- -- 36,475
Proceeds from sale of property and
equipment 60,879 42,399 --
-------- -------- --------
Net cash used by
investing activities (500,076) (781,457) (189,528)
------- ------- -------
Cash flows from financing activities:
Proceeds from issuance of common
stock, net of offering costs -- 1,365,336 --
Proceeds from exercise of stock
options 11,089 -- --
Proceeds from sale of stock by
Victoria 41,625 -- --
-------- -------- -------
Net cash provided by
financing activities 52,714 1,365,336 --
-------- -------- --------
Net increase (decrease)
in cash and cash
equivalents (475,742) 311,387 77,019
Cash and cash equivalents at
beginning of year 776,141 464,754 387,735
Cash and cash equivalents at end
of year $ 300,399 776,141 464,754
======== ======== ========
Selected cash payments and noncash
activities were as follows:
Cash paid for interest $ -- 22,058 49,757
Noncash investing and financing
activities:
Transfer of oil and gas
property to VIP
in exchange for note
payable to VIP -- 600,000 --
Common stock issued to Victoria
for reduction in note
payable -- -- 466,343
Acquisition of Victoria:
Receivables -- -- 93,462
Oil and gas properties -- -- 1,414,710
Furniture and equipment -- -- 13,456
Liabilities assumed -- -- (133,440)
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
KESTREL ENERGY, INC.
AND SUBSIDIARY
(A Subsidiary of Victoria International Petroleum N.L.)
Notes to Consolidated Financial Statements
June 30, 1996, 1995, and 1994
- --------------------------------------------------------------------------
Summary of Significant Accounting Policies
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, Colorado, Kansas, Louisiana, New Mexico, Oklahoma,
South Dakota, Texas, and Wyoming. The Company also has an interest
in five international exploration permits, one in New Guinea and
four in Australia.
Victoria International Petroleum N. L. (VIP) owns 61.3% of the
common shares of the Company.
Principles of Consolidation
The consolidated financial statements include the accounts of the
Company and its subsidiary, Victoria Exploration, Inc. (Victoria).
All significant intercompany accounts and transactions have been
eliminated in consolidation.
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.
Cash Equivalents
Cash equivalents consist of money market funds. For purposes of
the statements of cash flows, the Company considers all highly
liquid investments with original maturities of three months or less
to be cash equivalents.
Short-Term Investments
Short-term investments at June 30, 1996 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.
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.
The Company currently assesses impairment of proved oil and gas
properties on an aggregate basis using undiscounted estimated
future net revenue and constant prices and costs. 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 is 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) 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 has not
adopted SFAS No. 121 as of June 30, 1996; however, if it were to
adopt SFAS No. 121 as of that date, it would be required to record
a provision of approximately $220,000 for the impairment of certain
of its oil and gas properties. The provision for impairment will
be recorded in the quarter ended September 30, 1996.
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, 1996 and 1995, the Company is in an under-produced
position of approximately 33,000 MCFs and 16,000 MCFs,
respectively. Accordingly, these amounts have been included in the
reserve quantities as set forth in note 9.
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.
Income (Loss) per Share
Income (loss) per share is computed by dividing net income or loss
by the weighted average number of shares of common stock and common
stock equivalents outstanding during the year. Outstanding stock
options are excluded from the computation if the effect is
antidilutive.
(2) Acquisitions
Effective January 1, 1992, the Company acquired various operating
and royalty interests in producing and non-producing oil and gas
properties in Wyoming, Louisiana and Oklahoma from Victoria for
$1,644,058. The acquisition was originally financed by a
$1,600,000 note payable to Victoria, of which $600,000 was
subsequently converted to common stock of the Company in 1992.
The Company obtained a guarantee from VIP that an unproved
waterflood prospect acquired in the aforementioned property
acquisition would generate $600,000 in positive cash flow to the
Company or, that in the opinion of an independent petroleum
engineering firm, to be obtained in 1997, it could reasonably be
expected to generate this amount. In the event that the property
failed to meet either of these criteria, VIP was obligated to
contribute additional properties or cash to meet any shortfall.
In December 1994, the Company determined that it would not be able
to develop the property, and entered into an agreement with VIP to
transfer its interest in the property in exchange for a note
payable to VIP in the amount of $600,000 (see note 3). As a result
of the transaction, the Company expensed its cost in the prospect
in the amount of $479,119 and increased stockholders' equity by the
amount of the debt extinguished.
On June 10, 1994, the Company exchanged 709,108 previously unissued
common shares of the Company, and certain stock options, for all of
the outstanding common and preferred shares of Victoria, a wholly-
owned subsidiary of VIP. The transaction was accounted for at
historical cost as an exchange between companies under common
control. The stock options issued were in consideration for
certain undeveloped properties owned by Victoria, which the Company
agreed to develop. The options vest if the undeveloped properties
are successfully developed by June 30, 1997.
Prior to the transaction, Victoria transferred all of its holdings
in the Company, 380,913 shares (59%), to VIP. VIP currently owns
61.3% of the common shares of the Company (52.5% diluted for
currently vested options).
(3) Notes Payable to Related Party
In conjunction with the property acquisition from Victoria (see
note 2), the Company issued a $1,000,000 note payable to Victoria
on January 1, 1992 with interest at the prime rate. In December
1992, the terms of a $58,550 unsecured short-term note to Victoria
were conformed to the terms of the $1,000,000 note payable and the
notes were combined. Effective January 1, 1994, $466,343 of
indebtedness to Victoria (including $7,793 of accrued interest) was
canceled in exchange for 207,263 shares of the Company's common
stock.
Effective April 1, 1994, Victoria transferred the remaining
$600,000 note receivable from the Company to its parent, VIP (see
note 2). Effective December 24, 1994, the $600,000 note was
exchanged for non-producing property (see note 2). Related party
interest expense was approximately $22,058 and $40,800 for the
years ended June 30, 1995 and 1994, respectively.
(4) Stockholders' Equity
On March 2, 1994, the Company's shareholders approved an increase
in the authorized shares of common stock from 2 million to 20
million shares and authorized the issuance of up to 1 million
shares of a new class 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.
During 1995, the Company sold 551,200 shares of the common stock at
a price of $2.50 per share in a private placement. Total proceeds,
net of brokers commissions, were $1,365,336.
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, 1996, there were no options
outstanding under the Incentive Plan.
The Company has reserved 750,000 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 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 1996, 1995, 1994 and 1993, the Board of Directors
granted options to purchase shares of common stock to key
personnel, directors and a consultant, pursuant to the Nonqualified
Plan. The exercise prices of the options range from $1.3125 to
$4.63 per share. The options granted are exercisable upon
issuance.
Options granted and outstanding under the Nonqualified Plan as of
June 30, 1996 are as follows:
<TABLE>
<CAPTION>
Exercise Options Options
Year of grant price granted Outstanding
------------ ----- ------- -----------
<S> <C> <C> <C>
1993 $ 1.31 55,750 53,000
1994 2.87 - 4.63 131,000 129,500
1995 1.875 - 4.00 128,500 124,500
1996 2.375 - 3.875 265,000 265,000
======== ========
580,250 572,000
</TABLE>
During fiscal 1996, 6,750 stock options were exercised at prices
ranging from $1.31 to $1.875 per share, and 1,500 stock options
granted at $4.63 expired.
During the years ended June 30, 1995 and 1996, certificates for
previously issued shares of the Company's common stock,
representing 20 and 44 shares, respectively, were presented for
transfer. Prior to presentment, such shares had not been recorded
as issued by the Company.
(5) Income Taxes
At June 30, 1996 and 1995, the Company's significant deferred tax
assets and liabilities are as follows:
<TABLE>
<CAPTION>
1996 1995
---- ----
<S> <C> <C>
Deferred tax assets:
Net operating loss carryforwards $ 2,180,000 2,199,000
Depletion carryforwards 67,000 24,000
Investment tax credit carryforwards 47,000 47,000
Oil and gas properties,
principally due to differences
in depreciation and depletion 5,000 --
-------- --------
Gross deferred tax assets 2,299,000 2,270,000
Valuation allowance (2,299,000) (2,254,000)
-------- --------
Net deferred tax assets - 16,000
Deferred tax liabilities - oil and gas
properties, principally due to
differences in depreciation and
depletion - (16,000)
Net deferred tax liability $ - -
</TABLE>
The valuation allowance for deferred tax assets as of June 30, 1995
was $2,254,000. The net change in the valuation allowance for the
year ended June 30, 1996 was an increase of $45,000.
At June 30, 1996, the Company had net operating loss carryforwards
of approximately $5,590,000. The utilization of approximately
$2,700,000 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, $2,130,000 is limited to the extent of future
taxable income generated by Victoria, and $760,000 is available to
offset future taxable income of the Company. If not utilized, the
tax net operating losses will expire during the period from 1997
through 2009.
(6) Related Party Transactions
In addition to the transactions with related parties described in
notes 2 and 3, the Company entered into an administrative services
agreement with Victoria, effective July 1, 1992. The agreement
called for Victoria to provide office space, support staff, and
office supplies to the Company for a fee of $2,500 per month. The
Company continued to be responsible for professional fees such as
engineering, accounting and legal fees. Fees paid to Victoria
prior to its acquisition by the Company were $30,000 in 1994. The
agreement was canceled on June 30, 1994.
The Company also, 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 five international
permits, one in New Guinea, and four in Australia. The Company has
agreed to pay VIP a 5% royalty on the Company's interest in the
international permits for any permits which produce net revenues
for the Company.
In 1996, the Company received payment of $41,625 from its parent,
attributed to the gain realized by VIP on the sale of shares of the
Company's stock held less than six months.
(7) 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 $31,179 and $28,960 for the years
ended June 30, 1996 and 1995, respectively.
Future minimum rental commitments under noncancelable operating
leases as of June 30, 1996 are as follows:
<TABLE>
<CAPTION>
Fiscal Year
-----------
<S> <C>
1997 $ 30,664
1998 12,777
--------
$ 43,441
========
</TABLE>
The Company currently has an interest in one prospect in Papua New
Guinea and four in Australia. Under the terms of the exploration
permits, the Company is obligated to spend 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 permit obligations expected to be incurred over
the next 5 years are as follows:
<TABLE>
<CAPTION> Permit Year
-----------
<S> <C>
1997 $ 207,000
1998 62,000
1999 235,000
2000 187,500
2001 -
--------
$ 691,500
========
</TABLE>
(8) 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
---------------------
- ---
1996 1995
---- ----
<S> <C> <C>
Proved $ 4,084,044 4,070,059
Unproved 309,931 234,833
-------- --------
4,393,975 4,304,892
Accumulated depreciation
and depletion (1,458,192) (1,292,568)
-------- --------
$ 2,935,783 3,012,324
======== ========
</TABLE>
Costs incurred in oil and gas producing activities for the three
years ended June 30, 1996 were approximately as follows:
<TABLE>
<CAPTION>
1996 1995
1994
---- ---- ---
- -
<S> <C> <C> <C>
Unproved property
acquisition costs $ 123,000 338,000 46,000
Proved property acquisition
costs 37,000 - 1,398,000
Development costs 52,000 333,000 194,000
Exploration costs 146,000 577,000 13,000
</TABLE>
The unproved property acquisition costs and proved property
acquisition costs above include amounts relating to the acquisition
of Victoria in 1994.
During fiscal 1996, the Company had two major customers. Sales to
these customers accounted for approximately 26% and 15% of 1996 oil
and gas sales. During fiscal 1995, the Company had two major
customers. Sales to these customers accounted for approximately
35% and 15% of 1995 oil and gas sales. During fiscal 1994, the
Company had four major customers. Sales to these customers
accounted for approximately 25%, 13%, 13% and 12% of 1994 oil and
gas sales.
(9) Information Regarding Proved Oil and Gas Reserves (Unaudited)
The information presented below regarding the Company's oil and gas
reserves was prepared by an independent petroleum engineering
consultant. 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 reserves of oil and gas for the
years ended June 30, 1996, 1995, and 1994 are as follows:
<TABLE>
<CAPTION>
1996 1995 1994
Oil Gas Oil Gas Oil Gas
(BBLS) (MCF) (BBLS) (MCF) (BBLS) (MCF)
------- --------- ------- --------- ------- --------
<S> <C> <C> <C> <C> <C> <C>
Beginning of year 439,000 4,325,000 471,000 4,768,000 177,000 2,180,000
Purchases of oil
and gas reserves
in place 8,000 - - - - 237,000 2,697,000
Revisions of
previous quantity
estimates 77,000 689,000 22,000 (140,000)(17,000) (135,000)
Extensions,
discoveries
and improved
recovery - 159,000 - - 100,000 213,000
Sales of reserves
in place (1,000) - - - - -
Production (43,000) (273,000)(54,000) (303,000)(26,000) (187,000)
------- --------- ------- --------- ------- ---------
End of year 480,000 4,900,000 439,000 4,325,000 471,000 4,768,000
======= ========= ======= ========= ======= =========
Proved developed
reserves -
beginning of
year 327,000 2,436,000 324,000 2,817,000 176,000 1,771,000
======= ========= ======= ========= ======= =========
Proved developed
reserves - end of
year 400,000 2,717,000 327,000 2,436,000 324,000 2,817,000
======= ========= ======= ========= ======= =========
</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>
1996 1995 1994
<S> <C> <C> <C>
Future cash inflows $ 16,470,000 13,113,000 16,076,000
Future costs:
Production (6,227,000) (5,310,000) (6,177,000)
Development (893,000) (813,000) (892,000)
Income taxes (50,000) - (264,000)
------------ ---------- ----------
Future net cash flows 9,300,000 6,990,000 8,743,000
10% discount factor (3,279,000) (2,871,000) (3,188,000)
------------ ---------- ----------
Standardized measure of discounted
future net cash flows $ 6,021,000 4,119,000 5,555,000
============ ========== ==========
</TABLE>
The principal sources of changes in the standardized measure of discounted
future net cash flows during the years ended June 30, 1996, 1995, and 1994
are as follows:
<TABLE>
<CAPTION>
1996 1995 1994
<S> <C> <C> <C>
Beginning of year $ 4,119,000 5,555,000 2,822,000
Sales of oil and gas produced
during the period, net of
production costs (600,000) (683,000) (439,000)
Net change in prices and production
costs 748,000 (1,027,000) (761,000)
Changes in estimated future
development costs (36,000) (105,000) (21,000)
Purchase of reserves in place 22,000 - 2,818,000
Extensions, discoveries and improved
recovery 112,000 - 808,000
Revisions of previous quantity
estimates and other 1,295,000 (9,000) (122,000)
Net change in income taxes (50,000) (168,000) 168,000
Sales of reserves in place (1,000) - -
Accretion of discount 412,000 556,000 282,000
----------- --------- ---------
End of year $ 6,021,000 4,119,000 5,555,000
=========== ========= =========
</TABLE>
Information Regarding Proved Oil and Gas Reserves (Unaudited)
(continued)
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 1996 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 1996 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 1996 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 1996 annual meeting of
shareholders.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) Exhibits
Exhibit No. Description
---------- -----------
3 Articles of Incorporation and Bylaws. 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.
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 Instruments Defining the Rights of Security
Holders. The form of common stock share
certificate filed as Exhibits 5.1 to the
Registrant's Form S-2 Registration Statement under
the Securities Act of 1933, as amended,
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.
10.1 Purchase and Sale Agreement between the Company and
Victoria Exploration, Inc. dated June 1, 1992, and
filed as Exhibit B with the Form 8-K filed on June
15, 1992 and incorporated herein by reference.
10.2 Consent to Corporate Action dated June 1, 1992 of
Victoria Exploration, Inc. and filed as Exhibit C
with the Form 8-K filed on June 15, 1992 and
incorporated herein by reference.
10.3 Mortgage, Security Agreement, Assignment of
Proceeds, and Financing Statement between the
Company and Victoria Exploration, Inc. dated June
1, 1992, and filed as Exhibit D with the Form 8-K
filed on June 15, 1992 and incorporated herein by
reference.
10.4 Administrative Services Agreement dated September
15, 1992 between Victoria Exploration, Inc. and the
Company filed as Exhibit 10.12 with the Annual
Report on Form 10-K for the fiscal year ended June
30, 1992 and incorporated herein by reference.
10.5 Agreement for Exchange of Stock dated May 3, 1994
filed as Exhibit 2.01 with the Form 8-K filed on
July 8, 1994 and incorporated herein by reference.
10.6 $600,000 Promissory Note dated September 23, 1994
payable to Victoria International Petroleum N.L.,
as amended, filed as Exhibit 10.10 with the Annual
Report on Form 10-K for the fiscal year ended June
30, 1994 and incorporated herein by reference.
10.7 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.
10.8 1993 Nonqualified Stock Option Plan as amended
March 14, 1995 and December 12, 1995 and filed as
Exhibit 4.3 with the Company's Registration
Statement on Form S-8 (SEC No. 33-63171) and
Incorporated herein by reference.
21 Subsidiaries of the Registrant filed as Exhibit 22
with the Annual Report on Form 10-K for the fiscal
year ended June 30, 1994 and incorporated herein by
reference.
23 Consent of KPMG Peat Marwick 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
All schedules are omitted as the required information
is inapplicable or presented in the financial statements or
related notes.
(c) Reports on Form 8-K.
No reports on Form 8-K were filed with the Commission during the
quarter ended June 30, 1996.
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 27, 1996 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 27, 1996 By: /s/ Timothy L. Hoops
Timothy L. Hoops, President,
Chief Executive Officer,
and Director
Date: September 27, 1996 By:/s/ Robert J. Pett
Robert J. Pett, Chairman of
the Board
Date: September 27, 1996 By:/s/ Mark A. Boatright
Mark A. Boatright, Vice
President, Finance, Chief
Financial Officer, and
Director
Date: September 27, 1996 By:/s/ Kenneth W. Nickerson
Kenneth W. Nickerson,
Director
Date: September 27, 1996 By:/s/ John T. Kopcheff
John T. Kopcheff, Vice
President - International,
and Director
EXHIBIT INDEX
-------------
<TABLE>
<CAPTION>
EXHIBIT METHOD OF FILING
- ------- ----------------
<S> <C> <C>
23 Consent of KPMG Peat
Marwick LLP Filed herewith electronically
27 Financial Data Schedule Filed herewith electronically
</TABLE>
INDEPENDENT AUDITORS' CONSENT
THE BOARD OF DIRECTORS
KESTREL ENERGY, INC.:
We consent to the incorporation by reference in the registration statement
(No. 33-63171) on Form S-8 and registration statement (No. 33-89716) on
Form S-3 of Kestrel Energy, Inc. our report dated September 13, 1996,
relating to the consolidated balance sheets of Kestrel Energy, Inc. and
subsidiaries as of June 30, 1996 and 1995, 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, 1996, which report
appears in the June 30, 1996 Annual Report on Form 10-K of Kestrel Energy,
Inc.
/s/KPMG Peat Marwick LLP
KPMG Peat Marwick LLP
Denver, Colorado
September 23, 1996
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> JUN-30-1996
<PERIOD-END> JUN-30-1996
<CASH> 300
<SECURITIES> 645
<RECEIVABLES> 191
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1,160
<PP&E> 4,452
<DEPRECIATION> 1,497
<TOTAL-ASSETS> 4,115
<CURRENT-LIABILITIES> 150
<BONDS> 0
0
0
<COMMON> 8,375
<OTHER-SE> (4,410)
<TOTAL-LIABILITY-AND-EQUITY> 4,115
<SALES> 0
<TOTAL-REVENUES> 1,268
<CGS> 0
<TOTAL-COSTS> 1,428
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> (160)
<INCOME-TAX> 0
<INCOME-CONTINUING> (160)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (160)
<EPS-PRIMARY> (.08)
<EPS-DILUTED> (.08)
</TABLE>
