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 2001.
The Company presently owns oil and gas interests in the states of Louisiana, New Mexico, Oklahoma, South Dakota, Texas, and Wyoming.
Recent Activities - -----------------
On May 5, 2000, the Company sold six international permits for petroleum drilling in Western Australia and New Guinea to Victoria Petroleum USA, Inc. ("VP/USA"), a Colorado corporation and wholly owned subsidiary of Victoria Petroleum N.L. ("VP"), an Australian corporation and an affiliate of the Company, in exchange for 8,250,000 shares of VP Common Stock. On May 5, 2000, the Company, Kestrel Energy California, Inc. ("KEC"), a wholly owned subsidiary of the Company, VP, and VP/USA entered into an Agreement and Plan of Merger (the "Merger Agreement"). Pursuant to the Merger Agreement, on May 12, 2000, the Company, as sole shareholder of KEC, acquired 66,750,000 shares of VP common stock and VP/USA acquired all of the issued and outstanding shares of KEC through a merger of KEC with and into VP/USA, with KEC as the surviving corporation.
In April 2000 the Company completed a private offering of 374,000 shares of its common stock at $3.00 per share. Net proceeds to the Company were $1,047,628 after offering and related expenses of $74,372. The private placement of shares provided the Company with resources to complete the Greens Canyon 29-2 well on the Greens Canyon Field.
During the fourth quarter of fiscal 2000, the Company completed the Greens Canyon 29-2 well for production and finished the construction of the Greens Canyon pipeline. As a result of the pipeline, the Company was able to transport gas produced from the Greens Canyon wells to market for sale in May and June.
Operations and Policies - -----------------------
The Company currently is focusing its exploration, acquisition and development opportunities in Wyoming, specifically on the Greens Canyon Field. However, the acquisition, development, production and sale of oil and gas acreage are subject to many factors outside the Company's control. These factors include worldwide and domestic economic conditions; proximity to pipelines; existing oil and gas sales contracts on properties being evaluated; the supply and price of oil and gas as well as other energy forms; the regulation of prices. production, transportation and marketing by federal and state governmental authorities; and the availability of, and interest rates charged on, borrowed funds.
Historically, in attempting to acquire, explore and drill 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 has in the past sought to alleviate some of these problems by forming acquisition joint ventures with other companies, including its affiliate, Victoria Petroleum N.L. These joint ventures allow the Company access to more acquisition candidates and enable the Company to share the evaluation and other costs among the venture partners.
The Company's operations are subject to various provisions of federal, state and local laws regarding environmental matters. The impact of these environmental laws on the Company may necessitate significant capital outlays, which may materially affect the earnings potential of the Company's oil and gas business in particular, and could cause material changes in the industry in general. The Company strongly encourages the operators of the Company's oil and gas wells to do periodic environmental assessments of potential liabilities. To date, the existence of environmental laws has not materially hindered nor adversely affected the Company's business. Please see Item 3, Legal Proceedings for a discussion of potential environmental litigation involving the Company.
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. 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 current focus is the exploration of new oil and gas properties 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 Greens Canyon Field 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.
Risk Factors - ------------
We must continue to expand our operations - -----------------------------------------
Our long term success is ultimately dependent on our ability to expand our revenue base through the acquisition of producing properties and, to a much greater extent, by successful results in our exploration efforts. We have recently made significant investments in exploration properties in the Western Green River Basin in Wyoming. There is no assurance that these acquisitions or other acquisitions will be as successful as projected. All of our exploration projects are subject to failure and the loss of our investment.
Prices of oil and natural gas fluctuate widely based on market conditions and any decline will adversely affect our financial condition - -------------------------------------------------------------------------
Our revenues, operating results, cash flow and future rate of growth are very dependent upon prevailing prices for oil and gas. Historically, oil and gas prices and markets have been volatile and not predictable, and they are likely to continue to be volatile in the future. Prices for oil and gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond our control, including:
o political conditions in the Middle East; o the supply and price of foreign oil and gas; o the level of consumer product demand; o the price and availability of alternative fuels; o the effect of federal and state regulation of production and transportation; and o the proximity of our natural gas to pipelines and their capacity.
We must replace the reserves we produce - ---------------------------------------
A substantial portion of our oil and gas properties contain proved undeveloped reserves and probable reserves. Successful development and production of those reserves cannot be assured. Additional drilling will be necessary in future years both to maintain production levels and to define the extent and recoverability of existing reserves. There is no assurance that our present oil and gas wells will continue to produce at current or anticipated rates of production, that development drilling will be successful, that production of oil and gas will commence when expected, that there will be favorable markets for oil and gas which may be produced in the future or that production rates achieved in early periods can be maintained.
There are many risks in drilling oil and gas wells - --------------------------------------------------
The cost of drilling, completing and operating wells is often uncertain. Moreover, drilling may be curtailed, delayed or canceled as a result of many factors, including title problems, weather conditions, shortages of or delays in delivery of equipment, as well as the financial instability of well operators, major working interest owners and well servicing companies. Our gas wells may be shut-in for lack of a market until a gas pipeline or gathering system with available capacity is extended into our area. Our oil wells may have production curtailed until production facilities and delivery arrangements are acquired or developed for them.
We face intense competition - ---------------------------
The oil and natural gas industry is highly competitive. We compete with others for property acquisitions and for opportunities to explore or to develop and produce oil and natural gas. We have previously formed acquisition joint ventures with several other companies, including Victoria Petroleum N.L. and other affiliates, which have allowed us more access to acquisition candidates and to share the evaluation costs with them. We face strong competition from many companies and individuals with greater capital, financial resources and larger technical staffs. We also face strong competition in procuring services from a limited pool of laborers, drilling service contractors and equipment vendors.
The amount of insurance we carry may not be sufficient to protect us - --------------------------------------------------------------------
We, our partners, co-venturers and well operators maintain general liability insurance but it may not cover all future claims. If a large claim is successfully asserted against us, we might not be covered by insurance, or it might be covered but cause us to pay much higher insurance premiums or a large deductible or co-payment. Furthermore, regardless of the outcome, litigation involving our operations or even insurance companies disputing coverage could divert management's attentions and energies away from operations. The nature of the oil and gas business involves a variety of operating hazards such as fires, explosions, cratering, blow-outs, adverse weather conditions, pollution and environmental risks, encountering formations with abnormal pressures, and, in horizontal wellbores, the increased risk of mechanical failure and collapsed holes, the occurrence of any of which could result in substantial losses to us.
Our success may be dependent on our ability to retain Tim Hoops, John Kopcheff, Bob Pett and Ira Pasternack as key personnel - -------------------------------------------------------------------------
We believe that the oil and gas exploration and development and related management experience of our key personnel is important to our success. The active participation in Kestrel of Timothy L. Hoops, our president, John T. Kopcheff, vice president of International, Robert J. Pett, our chairman, and Ira Pasternack, vice president of Exploration, is a necessity for our continued operations. We do not have any employment contracts with these individuals and we do not have key person life insurance on their lives. We compete with bigger and better financed oil and gas exploration companies for these individuals. Our future success may depend on whether we can attract, retain and motivate highly qualified personnel. We can't assure you that we will be able to do so.
Our reserves are uncertain - --------------------------
Estimating our proved reserves involves many uncertainties, including factors beyond our control. Our annual report on Form 10-K for fiscal year 2000 contains estimates of our oil and natural gas reserves and the future cash flow to be realized from those reserves for fiscal years 2000, 1999 and 1998, as prepared by independent petroleum engineers. There are uncertainties inherent in estimating quantities of proved oil and natural gas reserves since petroleum engineering is not an exact science. Estimates of commercially recoverable oil and gas reserves and of the future net cash flows from them are based upon a number of variable factors and assumptions including:
o historical production from the properties compared with production from other producing properties; o the effects of regulation by governmental agencies; o future oil and gas prices; and o future operating costs, severance and excise taxes, abandonment costs, development costs and workover and remedial costs.
Governmental regulation, environmental risks and taxes could adversely affect our oil and gas operations in the United States - -------------------------------------------------------------------------
Our oil and natural gas operations in the United States are subject to regulation by federal and state government, including environmental laws. To date, we have not had to expend significant resources in order to satisfy environmental laws and regulations presently in effect. However, compliance costs under any new laws and regulations that might be enacted could adversely affect our business and increase the costs of planning, designing, drilling, installing, operating and abandoning our oil and gas wells and other facilities. Additional matters that are, or have been from time to time, subject to governmental regulation include land tenure, royalties, production rates, spacing, completion procedures, water injections, utilization, the maximum price at which products could be sold, energy taxes and the discharge of materials into the environment.
Forward-Looking Statements - --------------------------
This report contains forward-looking statements. We use words such as "anticipate", "believe", "expect", "future", "may", "will", "should", "plan", "intend", and similar expressions to identify forward-looking statements. These statements are based on our beliefs and the assurances we made using information currently available to us. Because these statements reflect our current views concerning future events, these statements involve risks, uncertainties and assumptions. Our actual results could differ materially from the results discussed in the forward- looking statements. Some, but not all, of the factors that may cause these differences include those discussed in the risk factors in this report. You should not place undue reliance on these forward-looking statements. You should also remember that these statements are made only as of the date of this report and future events may cause them to be less likely to prove to be true.
ITEM 2.
ITEM 2. PROPERTIES. - --------------------
Oil and Gas Interests - ---------------------
The following table describes the Company's leasehold interests in developed and undeveloped oil and gas acreage at June 30, 2000:
(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.
Royalty Interests Under Producing Properties - --------------------------------------------
At June 30, 2000, the Company held overriding royalty interests ranging from 0.013% to 9.26% in 116 producing oil and gas wells located on 6,019 gross developed acres in the United States.
Drilling Activities - -------------------
The Company has participated in drilling thirteen wells since June 30, 1999. These included two exploratory wells and eleven development wells. All of these wells are productive. The two exploratory wells were the Greens Canyon 27-3 and the Greens Canyon 29-2. The Greens Canyon 27-3 is productive from the 2nd Frontier Sandstone, while the Greens Canyon 29-2 is productive from the Muddy Sandstone. The eleven development wells were coalbed methane wells drilled on the Wagensen property.
Kestrel and its subsidiaries owned interests in net exploratory and net development wells for the years ended June 30, 2000, 1999 and 1998 as set forth below. This information does not include wells drilled under farmout agreements.
(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, 2000, no wells were drilled under farmout agreements.
Oil and Gas Production, Prices and Costs - ----------------------------------------
As of June 30, 2000, the Company had a royalty and/or working interest in 74 gross (10.06 net) wells that produce oil only, 43 gross (9.45 net) wells that produce gas only, and 229 (6.62 net) wells that produce both oil and gas. All wells that produced gas are connected to pipelines.
For information concerning the Company's oil and gas production, estimated oil and gas reserves, and estimated future cash inflows relating to proved oil and gas reserves, see Note 8 to the 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, 2000. For the year ended June 30, 2000, the Company's average operating cost (including taxes and marketing) per barrel of oil equivalent (BOE) (converting gas to oil at 6:1) was $7.98. The average operating cost per BOE on an equivalent basis for fiscal years 1999 and 1998 was $5.46 and $5.75, respectively. The average sales price per barrel of oil sold was $24.78 for 2000, $10.01 for 1999, and $14.63 for 1998. The average sales price per mcf of gas sold was $2.59 for 2000, $1.26 for 1999, and $1.78 for 1998. Customers - ---------
During fiscal year 2000, the Company had two major customers; Oxley Petroleum, Inc. and Amoco, Inc. Sales to these customers accounted for 13% each oil and gas sales in 2000. 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.
ITEM 3. LEGAL PROCEEDINGS. - ---------------------------
In the ordinary course of conducting its business, the Company becomes involved in litigation, administrative proceedings and governmental investigations, including environmental matters.
The Company has received a notice letter from the U.S. Environmental Protection Agency (EPA) that the Company is a potentially responsible party under the federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) at the Casmalia Waste Disposal Site in Santa Barbara County, California. The Company may be obligated to conduct remedial investigations, feasibility studies, remediation and/or removal of alleged releases of hazardous substances or to reimburse the EPA for such activities.
The Company does not believe that it has any liability under CERCLA for wastes disposed at Casmalia and believes that the EPA's notice was issued in error. The Company has responded to the EPA, explaining that the Company did not arrange to dispose of any waste at Casmalia. The Company's involvement with Casmalia is limited to the purchase of assets from another entity, which disposed of waste at Casmalia. The Company intends to tender the defense that an indemnification given from the previous owner of the properties at Casmalia applies, and the previous owner has confirmed that the indemnification would apply.
The Company is unable to estimate the dollar amount of exposure to loss in connection with the above-referenced matter; however, it has been estimated that the ultimate site-wide clean up costs will be approximately $271.9 million.
It is the opinion of Company's management that the outcome of these proceedings, individually or in the aggregate, will not have a material adverse effect on the Company's financial position, results of operations, or cash flows.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. - -------------------------------------------------------------
None.
PART II -------
ITEM 5.
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, 2000 the Company had 7,680,000 shares outstanding. At June 30, 2000, 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.
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.
ITEM 6. SELECTED FINANCIAL DATA. - ---------------------------------
The summary of selected financial data for the Company for its last five fiscal years is as follows:
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. - -------------------------------------------------------------------------
Liquidity and Capital Resources - -------------------------------
Working Capital and Cash Flows: Net working capital deficit at June 30, 2000, was $748,831 compared to positive working capital of $560,207 at June 30, 1999 and positive working capital of $3,137,982 at June 30, 1998. The decrease in working capital of $1,309,038 for the current year was a result of capital expenditures made by the Company to develop the Greens Canyon Field and the related pipeline. The Company plans to fund the working capital deficit at June 30, 2000 by drawing on its line of credit of $600,000 at Wells Fargo Bank, formerly Norwest Banks Colorado, N.A., utilizing additional revenues from oil and gas sales resulting from higher oil and gas prices, and obtaining funds from other sources as necessary. The decrease in working capital of $2,577,775 from June 30, 1998 to 1999 was a result of operating cash flow deficiencies and capital expenditures.
Net cash provided by operating activities totaled $646,114 for fiscal 2000 as compared to cash used by operating activities of $752,395 for fiscal 1999, an increase of $1,398,509. The increase is primarily a result of the increase in oil and gas revenues and in trade accounts payable, which increased as a result of the Company's drilling and completing two Greens Canyon gas wells and a pipeline to transport gas to market. Net cash used by 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 was primarily due to lower dry hole and exploration costs, notwithstanding sharply lower oil and gas revenues.
Net cash used by investing activities was $6,432,902 in fiscal 2000 as compared to $775,181 provided in fiscal 1999. During the fiscal year ended June 30, 2000, $6,728,902 was used to acquire, explore and develop proved and unproved oil and gas property interests, construct a gas pipeline on the Greens Canyon Field, and purchase equipment. Proved property investments included $2,937,600 to drill and complete the Greens Canyon 27-3 well, $2,199,400 to drill and complete the Greens Canyon 29-2 well, $100,000 to finalize completion of the Poitevent #1 well, and $470,000 to acquire additional acreage and conduct a seismic study on the Greens Canyon Field. Approximately $25,000 was expended to continue development in various coalbed methane wells on the Wagensen Field in Wyoming. Additionally, the Company constructed a 17 mile gas pipeline on the Greens Canyon Field at a cost to the Company of approximately $772,000. Unproved property acquisitions included $202,000 to acquire lease acreage on the Fire Hole Canyon Prospect in Wyoming and $6,500 for the continued development of the Kaye Unit in Wyoming. The Company also spent approximately $16,400 on computers and related software. Proceeds from the sales of property and equipment were $296,000 for fiscal 2000 as compared to $1,000 in the previous year. The Company received $35,000 for its entire working interest in the Sally Persons Unit in Wyoming, and $261,000 for the Company's entire working interests in 16 wells located on the Porcupine leasehold in Wyoming. There were no sales of short-term investments during fiscal 2000 as compared to sales of $2,330,831 a year ago. 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 Greens Canyon Field in Wyoming, $72,000 to acquire leasehold interests and workover an existing well on the Lake Bouef Field in Louisiana, $24,000 to complete the CBMA 23-15 well on the Hilight Field 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 fiscal year ended June 30, 1999. During fiscal year 1999, the Company also 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, exploration and development of proved and unproved property. Proceeds from the sale of assets amounted to $1,000 for fiscal 2000 as compared to $14,891 in 1998. The Company received $1,000 from the sale of its interest in the Edna Dupplechain well in Louisiana.
Net cash provided by financing activities was $5,893,842 for fiscal 2000. The Company completed three private offerings (described below) which provided cash to the Company of $5,878,842 net of offering expenses. In August 1999 the Company completed a private offering of 1,880,000 shares of its common stock at $1.25 per share. Net proceeds to the Company were $2,299,038 after offering and related expenses of $50,962. In December 1999 the Company completed a private offering of 950,000 shares of its common stock at $2.70 per share. Net proceeds to the Company were $2,532,176 after offering and related expenses of $32,824. In April 2000 the Company completed a private offering of 374,000 shares of its common stock at $3.00 per share. Net proceeds to the Company were $1,047,628 after offering and related expenses of $74,372. The shares sold in the offerings were sold to offshore purchasers in accordance with SEC Regulation S but the Company has since registered the shares with the SEC on Form S-3 for resale in the United States. The Company also received $15,000 from the exercise of non-qualified stock options by Company employees. There were no cash flows provided or used from financing activities during fiscal 1999 as compared to cash used of $15,405 in 1998.
Stockholders' Equity: Stockholders' equity increased $6,840,138, or 172%, to $10,806,435 at June 30, 2000 as compared to $3,966,297 at June 30, 1999. The increase is attributable to the three private stock offerings completed by the Company, the proceeds from stock option exercises as discussed above, and the net income reported by the Company.
Debt Obligations: The Company had no long-term debt at June 30, 2000, 1999 and 1998.
Reserves and Future Cash Flows: For the fiscal year ended June 30, 2000, the Company's proved oil reserves increased approximately 100,000 bbls. to 388,000 bbls., or 35%, from 288,000 in 1999. The Company's proved gas reserves increased 18,183 Mmcf to 24,517 Mmcf, or 287%, from 6,334 Mmcf in 1999. The increase in proved reserves is attributable to revisions of previous quantity estimates, production, new discoveries and extensions, and higher oil and gas prices for the fiscal year ended June 30, 2000.
The Company's undiscounted net future cash flows have been estimated by Sproule Associates Inc., an independent petroleum engineering firm, to be approximately $70,983,000 as of June 30, 2000. This compares to $8,862,000 in 1999 and $4,697,000 in 1998. The increase in the current year is the result of revisions of previous quantity estimates, new discoveries and extensions and higher oil and gas prices.
Gas Balancing: The Company at June 30, 2000 was underproduced by approximately 5,828 mcf. At June 30, 1999, the Company was underproduced approximately 6,234 mcf. The Company was under produced by 13,000 mcf of gas at June 30, 1998. 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, 2000, the Company estimated that, for United States federal income tax purposes, it had consolidated net operating loss carryforwards of approximately $7,833,000. The utilization of approximately $496,000 of these carryforwards are limited to an estimated $80,000 annually. Of the balance of the loss carryforwards, $1,885,000 is limited to the extent of future taxable income generated by the Company's subsidiary, Victoria Exploration, Inc., and $5,452,000 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 2001 through 2015.
Results of Operations - ---------------------
Fiscal 2000 vs. Fiscal 1999 - ---------------------------
Net Earnings: The Company reported net earnings of $943,977 in fiscal 2000 compared to a loss of $1,441,424 in 1999, which was a decrease of $2,385,401. The net earnings in fiscal 2000 is attributable to a gain on sale of property and equipment and significantly higher oil and gas revenues as a result of higher oil and gas prices.
Revenue: Total revenues increased in fiscal 2000 by $2,220,664, or 287%, to $2,993,459 versus $772,795 in 1999. The increase in overall revenues was a result of higher oil and gas revenues due to higher oil and gas prices, and higher gain on sale of property and equipment as described more fully below.
Revenue from oil and gas sales increased $429,608, or 68%, to $1,061,638 from $632,030 a year ago. The increase in revenues was a result of higher oil and gas prices despite lower sales volumes for oil and gas. Average prices per barrel of oil increased 148% to $24.78 from $10.01 a year ago. Average prices received per mcf of gas increased 106% to $2.59 from $1.26 a year ago. Sales volumes for oil decreased 18% to 19,939 from 24,319 a year ago. Sales volumes for gas decreased 29% to 218 mmcf from 308 mmcf a year ago.
The Company recorded gains on sale of equipment and property of $1,816,018 in 1999 versus a loss of $788 a year ago. On May 5, 2000, the Company sold six international permits with a net book value of approximately $143,179 for petroleum drilling in Western Australia and New Guinea to Victoria Petroleum USA, Inc. (VP/USA), a Colorado corporation and wholly owned subsidiary of VP, in exchange for 8,250,000 shares of VP Common Stock. The stock was valued at $0.0292/share and resulted in a gain on the sale of $97,721. Also, on May 5, 2000, KEC, VP, and VP/USA entered into an Agreement and Plan of Merger (Merger Agreement). Pursuant to the Merger Agreement, on May 12, 2000, the Company, as sole shareholder of KEC, acquired 66,750,000 shares of VP common stock and VP/USA acquired all of the issued and outstanding shares of KEC through a merger of KEC with and into VP/USA, with KEC as the surviving corporation. The stock was valued at $0.292/share and resulted in a gain on sale of $1,497,208. The Company sold its entire interest in the Sally Persons Unit, located in Wyoming, for $35,000, which resulted in a gain on sale of $27,836. Additionally, the Company sold its entire working interests in 16 wells located in the Porcupine Field, Wyoming for $261,000 which resulted in a gain on sale of $193,254.
Lease Operating Expenses: Lease operating expenses increased $36,617, or 9%, to $449,245 from $412,628 a year ago. The increase in lease operating expense is attributable to higher production taxes resulting from the increase in oil and gas revenues despite lower operating costs on various properties. Lease operating costs on a BOE (barrel of oil equivalent) increased 46% to $7.98 from $5.46 a year ago as a result of lower sales volumes of oil and gas.
Exploration Expenses: Exploration expenses decreased $69,761, or 15%, to $390,575 from $460,336 in 1999. The decrease in exploration expense reflected the slower pace of the Company's exploration program during fiscal 2000 as the Company's emphasis has been on the development of the Greens Canyon Field. The decrease was a result of lower geological and geophysical costs as well as lower delay rentals paid on exploration acreage.
Dry Holes, Abandoned and Impaired Properties: Dry holes, abandoned and impaired property costs were $25,125 in fiscal 2000 as compared to $388,612 a year ago, a decrease of $363,487, or 94%. No dry hole costs were recorded in fiscal 2000 versus $144,515 a year ago. The decrease in dry hole costs reflected the Company's successful drilling efforts on the Greens Canyon Field during the year. Abandonment costs decreased $17,857, or 100% from a year ago. Impairment expense decreased $201,115, or 89%, to $25,125 from $226,240 a year ago. The Company recorded impairment expense of $25,125 related to various international permits prior to their sale.
General and Administrative Expense: General and administrative expenses increased $308,322, or 40%, to $1,086,551 as compared to $778,229 a year ago. The increase in general and administrative expenses is attributable to higher company personnel costs as well as higher legal and accounting expenses. Company personnel costs rose as a direct result of the increase in the Company's development of the Greens Canyon Field. Legal and accounting costs increased as a result of the Company expensing previously incurred legal and accounting fees associated with the potential listing of the Company's stock on the Australian Stock Exchange, the Company's warrant dividend issue in January 2000, and the merger with VP in May 2000.
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 was 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 in 1998 from $895,017 in 1998. 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 in 1999 from $14.63 in 1998. Average prices received per mcf of gas decreased 29% to $1.26 in 1999 versus $1.78 in 1998. Sales volumes for oil decreased 12% to 24,319 in 1999 from 27,559 in 1998. Sales volumes for gas increased 12% to 308 mmcf in 1999 from 276 mmcf in 1998.
Lease Operating Expenses: Lease operating expenses decreased $14,418, or 3%, to $412,628 in 1999 from $427,046 in 1998. The decrease in lease operating expense was 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 in 1999 from $5.75 in 1998.
Exploration Expenses: Exploration expenses decreased $165,197, or 26%, to $460,336 in 1999 from $625,533 in 1998. The decrease in exploration expense reflected the slower pace of the Company's aggressive exploration program during fiscal 1999 due to lower 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 in 1998, a decrease of $822,472 or 68%. Dry hole costs were $144,515 in fiscal 1999 versus $681,046 in 1998. 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 in 1999 from 1998 levels. 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 in 1999 from $75,010 in 1998. The increase was 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 in 1999 as compared to $765,718 in 1998. The increase in general and administrative expenses was not attributable to any particular expense category.
Recent Accounting Pronouncements: In March 2000, the Financial Accounting Standard Board ("FASB") issued FASB Interpretation No. 44 "Accounting for Certain Transactions involving Stock Compensation - and interpretation of APB Opinion No. 25 ("FIN 44"). This opinion provides guidance on the accounting for certain stock option transactions and subsequent amendments to stock option transactions. FIN 44 is effective July 1, 2000, but certain conclusions cover specific events that occur after either December 15, 1998 or January 12, 2000. To the extent that FIN 44 covers events occurring during the period from December 15, 1998 and January 12, 2000, but before July 1, 2000, the effects of applying this Interpretation are to be recognized on a prospective basis. The Company does not expect the impact on its financial position or results of operations to be material.
In December 1999, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin No. 101, "Revenue Recognition (SAB 101), which provides guidance on the recognition, presentation and disclosure of revenue in financial statements filed with the SEC. Subsequently, the SEC released SAB 101B, which delayed the implementation date of SAB 101 for registrants with fiscal years beginning between December 16, 1999 and March 15, 2000. The Company does not expect the impact on its financial position or results of operations to be material.
In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, 137, and 138, Accounting for Derivative Instruments and Hedging Activities (Statement No. 133), effective beginning with the first quarter of fiscal years beginning after June 30, 2000. Statement No. 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. The Company does not expect the impact on its financial position or results of operations to be material.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. - ---------------------------------------------------------------------
Until fiscal 2000, the Company did not invest in or hold market risk sensitive or interest rate sensitive instruments and the only currency exchange rate risk borne by the Company stemmed from the Company's obligations to fund its international drilling in Australian dollars. During the current fiscal year ended June 30, 2000, the Company received 75,000,000 shares of VP Common Stock as a result of the merger and sale of international permits discussed previously. The VP Common Stock is recorded at cost on the Company's balance sheet under the heading "Investment in related party". The VP shares are traded publicly on the Australian stock exchange and the price for which the Company could sell its shares could be higher or lower than the Company's cost.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. - -----------------------------------------------------
See pages through for this information.
KESTREL ENERGY, INC. AND SUBSIDIARIES --------------------
Consolidated Financial Statements
June 30, 2000 and 1999
(With Independent Auditors' Report Thereon)
INDEPENDENT AUDITORS' REPORT ----------------------------
The Board of Directors and Stockholders Kestrel Energy, Inc.:
We have audited the accompanying consolidated balance sheets of Kestrel Energy, Inc. and subsidiaries as of June 30, 2000 and 1999, 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, 2000. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Kestrel Energy, Inc. and subsidiaries as of June 30, 2000 and 1999, and the results of their operations and their cash flows for each of the years in the three-year period ended June 30, 2000, in conformity with accounting principles generally accepted in the United States of America.
KPMG LLP --------
Denver, Colorado September 5, 2000
KESTREL ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
June 30, 2000 and 1999
See accompanying notes to consolidated financial statements.
KESTREL ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
Years ended June 30, 2000, 1999 and 1998
See accompanying notes to consolidated financial statements.
KESTREL ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Stockholders' Equity
Years ended June 30, 2000, 1999 and 1998
See accompanying notes to consolidated financial statements.
KESTREL ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years ended June 30, 2000, 1999 and 1998
See accompanying notes to consolidated financial statements.
KESTREL ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2000 and 1999
(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.
Victoria Petroleum N.L. (VP) owns 18% of the common shares of the Company and the Company owns 15% of VP at June 30, 2000.
(b) Principles Of Consolidation ---------------------------
The consolidated financial statements include the accounts of the Company and its subsidiaries, Victoria Exploration, Inc. (Victoria) and Kestrel Energy California, Inc. (KEC). 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) 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.
Pipeline facilities and equipment are stated at original cost. Depreciation of pipeline facilities is provided on a straight- line basis over the estimated useful life of the pipeline of fifteen years.
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.
Proved oil and gas properties are assessed for impairment on a field-by-field basis. If the net capitalized costs of proved properties exceeds the estimated undiscounted future net cash flows from the property, a provision for impairment is recorded to reduce the carrying value of the property to its estimated fair value. The Company recorded a provision for impairment of its proved oil and gas properties of approximately $25,000 and $177,000 for the years ended June 30, 2000 and 1999, respectively.
(f) Gas Balancing -------------
The Company uses the sales method of accounting for gas balancing of gas production. Under this method, all proceeds from production credited to the Company are recorded as revenue until such time as the Company has produced its share of related reserves. Thereafter, additional amounts received are recorded as a liability.
As of June 30, 2000 and 1999, the Company is in an under- produced position of approximately 5,828 MCFs and 6,234 MCFs, respectively. Accordingly, these amounts have been included in the reserve quantities as set forth in note 8.
(g) Income Taxes ------------
The Company accounts for income taxes under the provisions of Statement of Financial Accounting Standards No. 109 (SFAS No. 109), Accounting for Income Taxes. Under the asset and liability method of SFAS No. 109, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted income tax rates expected to apply to taxable income in the years in which those differences are expected to be recovered or settled. Under SFAS No. 109, the effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date.
(h) Stock-Based Compensation ------------------------
In October 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (SFAS 123), effective for fiscal years beginning after December 15, 1995. This statement defines a fair value method of accounting for employee stock options and encourages entities to adopt that method of accounting for its stock compensation plans. SFAS 123 allows an entity to continue to measure compensation costs for these plans using the intrinsic value based method of accounting as prescribed in Accounting Pronouncement Bulletin Opinion No. 25, Accounting for Stock Issued to Employees (APB 25). The Company has elected to continue to account for its employee stock compensation plans as prescribed under APB 25. The pro forma disclosures of net loss and loss per share required by SFAS 123 are included in note 2.
(i) Earnings (Loss) Per Share -------------------------
Basic earnings (loss) per share is based on the weighted average number of common shares outstanding during the period.
Diluted earnings (loss) per share is computed by adjusting the weighted average number of common shares outstanding for the dilutive effect, if any, of stock options and warrants.
The dilutive effect of outstanding stock options and warrants as of June 30, 2000 totaling 408,174 were adjusted to the weighted average number of common shares outstanding to obtain 7,195,278 weighted average common shares outstanding during the year ended June 30, 2000 including the effect of dilutive securities. Stock options totaling 40,000 for the year ended June 30, 2000 were excluded from the computation as their effect was antidilutive. All outstanding stock options for the year ended June 30, 1999 and 1998 were excluded from the computation as their effect was antidilutive.
(2) INVESTMENT IN RELATED PARTY ---------------------------
On May 5, 2000, the Company sold six international permits with a net book value of $143,179 for petroleum drilling in Western Australia and New Guinea to Victoria Petroleum USA, Inc. (VP/USA), a Colorado corporation and wholly owned subsidiary of VP, in exchange for 8,250,000 shares of VP Common Stock. The stock was valued at $0.0292187 per share and resulted in a gain on the sale of $97,721. The investment is recorded at cost.
Also, on May 5, 2000, KEC, VP and VP/USA entered into an Agreement and Plan of Merger (Merger Agreement). Pursuant to the Merger Agreement, on May 12, 2000, the Company, as sole shareholder of KEC, acquired 66,750,000 shares of VP common stock and VP/USA acquired all of the issued and outstanding shares of KEC through a merger of KEC into VP/USA, with KEC as the surviving corporation. The stock was valued at $0.0292187 per share and resulted in a gain on the sale of $1,497,208, based upon sales of other assets totaling $242, accounts payable totaling $2,000, and property and equipment with a net book value of $454,899. The investment is recorded at cost.
As a result of the above transactions, the Company owns 15% of VP at June 30, 2000.
(3) LINE OF CREDIT --------------
On February 21, 2000, the Company entered into a $2,000,000 Line of Credit agreement with Wells Fargo Bank West, N.A., formerly Norwest Bank Colorado, N.A., which provides the Company a current borrowing base of $600,000, based on reserves with interest at Norwest's prime rate plus 2.5%. The note is due October 31, 2001, and is secured by Deeds of Trust on various oil and gas producing properties held by the Company. No amounts were outstanding as of June 30, 2000.
(4) STOCKHOLDERS' EQUITY --------------------
(a) Preferred Stock ---------------
The Company is authorized to issue up to 1 million shares of $1 par value preferred stock, the rights and preferences of which are to be determined by the Board of Directors at or prior to the time of issuance.
(b) Common Stock ------------
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.
In August 1999, the Company completed a private offering of 1,880,000 shares of its common stock at $1.25 per share. Net proceeds to the Company were $2,299,038 after offering and related expenses of $50,962.
In December 1999, the Company completed a private offering of 950,000 shares of its common stock at $2.70 per share. Net proceeds to the Company were $2,532,176 after offering and related expenses of $32,824.
On January 18, 2000, the Board of Directors of the Company declared a dividend distribution of 10 Warrants for every 100 shares of outstanding common stock of the Company held of record by the shareholders at the close of business on February 4, 2000 (record date). The Warrant Certificates were only issued in increments of 10 Warrants based upon a rounding of individual shareholders' record holdings. No Warrants were issued to shareholders holding less than 100 shares as of the Record Date.
Each Warrant entitles the registered holder to purchase from the Company one share of Common Stock at a price of $3.125 per share, subject to adjustment. The Warrants will expire on February 4, 2001, unless redeemed earlier by the Company.
In April 2000, the Company completed a private offering of 374,000 shares of its common stock at $3.00 per share. Net proceeds to the Company were $1,047,628 after offering and related expenses of $74,372.
(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 2000, 1999 and 1998, the Board of Directors granted options to purchase shares of common stock to key employees and directors pursuant to the Plan. The exercise prices of the options range from $.50 to $3.88 per share. The options granted are exercisable upon issuance.
On December 1, 1998, the Board of Directors reduced the number of options outstanding and repriced certain options. The exercise prices of the repriced options range from $1.875 to $2.00 per share. The options are immediately exercisable.
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 at or above market value at the date of the grant to key employees and directors. Compensation expense of $2,319 has been recorded during fiscal 2000 for options granted below the market value, based on the difference between the option price and the quoted market price at the date of grant. Had compensation cost for the Company's two stock-based compensation plans been determined based on the fair value at the grant dates for awards under those plans consistent with the method prescribed in FASB Statement 123, the Company's net earnings (loss) and earnings (loss) per share would have been increased to the pro forma amounts indicated below:
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 2000, 1999 and 1998, respectively: no dividend yield for all years; expected volatility of 129%, 137% and 93%; weighted average risk-free interest rates of 5.86% in fiscal 2000, 5.06% in fiscal 1999 and 6.1% in fiscal 1998 for the Incentive Plan options; and expected lives of seven years for all years.
A summary of the status of the Company's fixed stock options plan as of June 30, 2000, 1999 and 1998, and changes during the years then ended is presented below:
The following table summarizes information about fixed stock options outstanding at June 30, 2000 (all of which are exercisable):
(5) INCOME TAXES ------------
At June 30, 2000 and 1999, the Company's significant deferred tax assets are as follows:
The valuation allowance for deferred tax assets as of June 30, 2000 was $2,176,000. The net change in the valuation allowance for the year ended June 30, 2000 was a decrease of $1,177,000.
At June 30, 2000, the Company had net operating loss carryforwards of approximately $7,833,000. The utilization of approximately $496,000 of these loss carryforwards is limited to an estimated $80,000 per year as a result of a change of ownership which occurred June 30, 1994. Of the balance of the net operating loss carryforwards, $1,885,000 is limited to the extent of future taxable income generated by Victoria, and $5,452,000 is available to offset future taxable income of the Company. If not utilized, the tax net operating losses will expire during the period from 2001 through 2015.
Income tax expense is different from amounts computed by applying the statutory federal income tax rate due primarily to the change in valuation allowance for net deferred tax assets and the expiration of tax carryforwards.
(6) LEASE COMMITMENTS -----------------
The Company has noncancelable operating leases, primarily for rent of office facilities that expire over the next five years. Rental expense for operating leases was $63,683, $60,336 and $38,793 for the years ended June 30, 2000, 1999 and 1998, respectively.
Future minimum rental commitments under noncancelable operating leases as of June 30, 2000 are as follows:
(7) CONTINGENCIES -------------
In the ordinary course of conducting its business, the Company becomes involved in litigation, administrative proceedings and governmental investigations, including environmental matters.
The Company has received a notice letter from the U.S. Environmental Protection Agency (EPA) that the Company is a potentially responsible party under the federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) at the Casmalia Waste Disposal Site in Santa Barbara County, California. The Company may be obligated to conduct remedial investigations, feasibility studies, remediation and/or removal of alleged releases of hazardous substances or to reimburse the EPA for such activities.
The Company does not believe that it has any liability under CERCLA for wastes disposed at Casmalia and believes that the EPA's notice was issued in error. The Company has responded to the EPA, explaining that the Company did not arrange to dispose of any waste at Casmalia. The Company's involvement with Casmalia is limited to the purchase of assets from another entity which disposed of waste at Casmalia. The Company intends to tender the defense that an indemnification given from the previous owner of the properties at Casmalia applies, and the previous owner has confirmed that the indemnification would apply.
The Company is unable to estimate the dollar amount of exposure to loss in connection with the above-referenced matter; however, it has been estimated that the ultimate site-wide clean up costs will be approximately $271.9 million.
It is the opinion of Company's management that the outcome of these proceedings, individually or in the aggregate, will not have a material adverse effect on the Company's financial position, results of operations or cash flows.
(8) DISCLOSURES ABOUT CAPITALIZED COSTS, COSTS INCURRED AND MAJOR CUSTOMERS --------------------------------------------------------------
Capitalized costs related to oil and gas producing activities are as follows:
Costs incurred in oil and gas producing activities for the years ended June 30, 2000, 1999 and 1998 were approximately as follows:
During fiscal 2000, the Company had two major customers. Sales to these customers accounted for approximately 13% each of fiscal 2000 oil and gas sales. During fiscal 1999, the Company had three major customers. Sales to these customers accounted for approximately 25%, 12% and 10% of fiscal 1999 oil and gas sales. During fiscal 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.
(9) INFORMATION REGARDING PROVED OIL AND GAS RESERVES (UNAUDITED) -------------------------------------------------------------
The information presented below regarding the Company's oil and gas reserves were prepared by independent petroleum engineering consultants. All reserves are located within the continental United States.
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. The determination of oil and gas reserves is highly complex and interpretive. The estimates are subject to continuing changes as additional information becomes available.
Estimated net quantities of proved developed and undeveloped reserves of oil and gas for the years ended June 30, 2000, 1999 and 1998 are as follows:
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.
The principal sources of changes in the standardized measure of discounted future net cash flows during the years ended June 30, 2000, 1999 and 1998, are as follows:
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.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. - -------------------------------------------------------------------------
None
PART III --------
ITEM 10.
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 2000 annual meeting of shareholders.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION. - ---------------------------------
The information required herein is incorporated by reference from the Company's definitive proxy statement for the 2000 annual meeting of shareholders.
ITEM 12.
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 2000 annual meeting of shareholders.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. - ---------------------------------------------------------
The information required herein is incorporated by reference from the Company's definitive proxy statement for the 2000 annual meeting of shareholders.
PART IV -------
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K. - -------------------------------------------------------------------------
(a) Exhibits
Exhibit No. Description ----------- ----------- 3.1 Amended and Restated Articles of Incorporation, as filed with the Secretary of State of Colorado on March 16, 1995, filed as Exhibit (3)1 to the Annual Report on Form 10-K/A for the fiscal year ended June 30, 1994 and incorporated herein by reference.
3.2 Amended and Restated Bylaws, as adopted by the Board of Directors on January 16, 1995, filed as Exhibit (3)2 to the Annual Report on Form 10-K/A for the fiscal year ended June 30, 1994 and incorporated herein by reference.
4.1 The form of common stock share certificate filed as Exhibits 5.1 to the Registrant's Form S-2 Registration Statement (No. 2-65317) and Article II of the Registrant's Articles of Incorporation filed as Exhibit 4.1 thereto, as amended on March 4, 1994 and filed with the Annual Report on Form 10-K for the fiscal year ended June 30, 1994 are incorporated herein by reference.
4.2 Warrant Agreement dated January 18, 2000 with American Securities Transfer & Trust, Inc. filed as Exhibit 4.1 to the Registrant's Form 8-A Registration Statement filed January 20, 2000 and incorporated herein by reference.
4.3 Form of Warrant Certificate filed as Exhibit 4.2 to the Registrant's Form 8-A Registration Statement filed January 20, 2000 and incorporated herein by reference.
10.1 Amended and Restated Incentive Stock Option Plan as amended March 14, 1995 and filed as Exhibit 10.7 with the Annual Report on Form 10-K for the fiscal year ended June 30, 1995 and incorporated herein by reference.
10.2 Kestrel Energy, Inc. Stock Option Plan as amended January 5, 2000 and filed as Exhibit 4 to the Registrant's Form S-8 Registration Statement (No. 333-38776) and incorporated herein by reference.
10.3 Line of Credit with Norwest Bank, Colorado National Association dated February 21, 2000 as Exhibit 10.1 to the Registrant's Form 10-Q for the period ended March 31, 2000 and incorporated herein by reference.
10.4 Articles of Merger for Kestrel Energy California, Inc. and Victoria Petroleum USA, Inc. filed as Exhibit 10.2 to the Registrant's Form 10-Q for the period ended March 31, 2000 and incorporated herein by reference.
21 Subsidiary of the Registrant
23.1 Consent of KPMG LLP
27 Financial Data Schedule
(b) Financial Statements. Independent Auditors' Report Consolidated Balance Sheets Consolidated Statements of Operations Consolidated Statements of Stockholders' Equity Consolidated Statements of Cash Flows Notes to Consolidated Financial Statements
(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 28, 2000 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 28, 2000 By: /s/ Timothy L. Hoops --------------------------- Timothy L. Hoops, President, Chief Executive Officer, and Director
Date: September 28, 2000 By: /s/ Robert J. Pett --------------------------- Robert J. Pett, Chairman of the Board
Date: September 28, 2000 By: /s/ Mark A. Boatright --------------------------- Mark A. Boatright, Vice President, Finance, Chief Financial Officer, and Director
Date: September 28, 2000 By: /s/ Kenneth W. Nickerson --------------------------- Kenneth W. Nickerson, Director
Date: September 28, 2000 By: /s/ John T. Kopcheff --------------------------- John T. Kopcheff, Vice President International, and Director
Date: September 28, 2000 By: /s/ Mark A. E. Syropoulo --------------------------- Mark A. E. Syropoulo, Director
EXHIBIT INDEX
No. Description - --- -----------
21 Subsidiary of the Registrant
23.1 Consent of KPMG LLP
27 Financial Data Schedule
All of the foregoing exhibits are filed electronically herewith.