ITEM 1. BUSINESS
GENERAL
We are an independent energy company engaged in the exploration, development, exploitation and acquisition of oil and natural gas properties in on-shore, conventional producing areas of North America. To date, we have grown almost exclusively through acquisitions of properties. As a result of our acquisitions we own a diverse property base in six producing areas or basins. Approximately 58% of our proved reserves are concentrated in south and east Texas. Our assets are primarily long-lived natural gas properties exhibiting low operating costs.
At June 30, 2000 we owned proved reserves of approximately 133 Bcf of natural gas and 2 MMBbls of oil aggregating to approximately 145 Bcfe with an SEC PV-10 value of $217 million and a reserve life index of 12.1 years. Approximately 68% of our proved reserves were classified as proved developed and approximately 92% of our proved reserves were natural gas. Our average net daily production for the month of June 2000 was 30.6 Mmcfe. At June 30, 2000 we had interests in 667 wells, including 83 service wells.
Our properties are diversified over 6 asset areas located principally in the southwestern United States. Our interests in east and south Texas represent approximately 62% of our proved reserves on an SEC PV-10 basis at June 30, 2000. In addition, we own substantial properties in Kentucky, New Mexico and Oklahoma. At June 30, 2000 we had interests in leases covering approximately 177,000 gross, or 74,000 net, acres.
We were incorporated under the laws of Delaware in 1989. The parent company is principally a holding company, holding the stock of its subsidiaries that own our assets and conduct our operations.
RECENT DEVELOPMENTS
On July 17, 2000, we entered into a recapitalization agreement with the holders of our Series A preferred stock, Series C preferred stock and common stock repricing rights which calls for these holders to exchange all of their holdings of our Series A preferred stock, Series C preferred stock and common stock repricing rights together with all warrants and maintenance rights that they may own for an aggregate of 732,500 shares of common stock after giving effect to the 156 to 1 reverse split of our common stock. Our board of directors approved the recapitalization agreement and transactions contemplated thereunder on July 17, 2000. As required by the recapitalization agreement, our board of directors will solicit stockholder approval of the exchange of stock and repricing rights described above that are held by the stockholders who have entered into the recapitalization agreement and the reverse stock split pursuant to proxy materials filed with the SEC.
The closing contemplated under the recapitalization agreement is subject to:
o stockholder approval of the recapitalization and the reverse stock split;
o our delivery of 732,500 shares of post-reverse split shares of common stock to the stockholders who are a party to the recapitalization agreement without any restrictive legend or stop transfer orders, except as otherwise provided in the recapitalization agreement;
o the completion of an equity financing on or before October 31, 2000 generating net proceeds to us of at least $50 million;
o our repurchase of not less than $75 million in principal amount of our 12 1/2% senior notes for approximately $49 million on or before October 31, 2000; and
o the representations and warranties contained in the recapitalization agreement being true as of the date of the agreement and the date of delivery of shares of common stock to the Series A preferred stock, the Series C preferred stock and the repricing rights holders.
We intend to make a tender offer or an exchange offer to effect a repurchase of not less than $75 million original principal amount of our senior notes for approximately $49 million. We have executed a binding participation
agreement with the holders of approximately $94 million of senior notes pursuant to which these holders have agreed to tender their senior notes to us. The participation agreement is conditioned upon the tender or exchange offer closing on or before October 31, 2000 with the participation of not less than $110 million of the senior notes. To finance the repurchase of our senior notes, we intend to complete a public offering or private placement of post-reverse split common stock on or before October 31, 2000. We have filed a registration statement with the Securities and Exchange Commission contemplating the sale of up to 10,000,000 shares of our common stock (11,500,000 shares if the underwriters' over-allotment option is exercised in full) at a post-reverse split price between $7.00 and $9.00 per share. Depending on market conditions we may sell fewer shares than we currently contemplate. We can not assure you that we will successfully complete this equity offering.
For a more complete description of the recapitalization, please see "Proposal Two" and "Proposal Three" in our proxy statement dated August 28, 2000 filed with the SEC relating to our 2000 annual meeting.
BUSINESS STRATEGY
Our goal is to enhance shareholder value by expanding our oil and natural gas reserves, production levels and cash flow, focusing on return on capital. Our strategy to achieve these goals consists of these elements:
o Recapitalizing the company, see "- Recent Developments".
o Pursuing managed asset growth through:
- actively developing and exploiting our existing higher potential oil and natural gas properties, particularly in south and east Texas;
- selective acquisitions of high potential oil and natural gas assets that complement our existing properties, coupled with routine dispositions of non-core and lower potential properties;
- an increased emphasis on exploration activities; and
- targeted merger(s) where the consolidation with other companies will give access to quality reserves within our core areas.
o Maintaining a capital and financial structure with prudent debt to equity ratios that will allow us to use cash generated from operations to fund growth in our production and reserves; and
o Enhancing our board of directors and management team through the addition of new industry senior executives to assist the company in enhancing and expanding our operating capacity and exploration activities.
DEVELOPMENT AND EXPLOITATION OF EXISTING PROPERTIES. We have identified over 423 potential development locations and exploitation opportunities on our properties. We have prioritized these opportunities to concentrate on those higher impact projects that have the potential to replace and grow our reserves while maximizing the long-term return on our capital. Our opportunities include:
o additional exploration of well-defined locations on existing properties such as in the J.C. Martin field in south Texas;
o infill drilling on our producing properties such as in the Gilmer field in east Texas;
o recompletion of existing wells in behind-pipe intervals such as in the Lopeno and Volpe fields in south Texas; and
o developing proved undeveloped reserves by drilling low risk, long lived natural gas wells in the shallow New Albany Shale formation in Kentucky.
PROPERTY ACQUISITIONS AND DIVESTITURES. We will diligently pursue the acquisition of oil and natural gas properties that we believe will provide us with a combination of increased production, reserve growth and exploration potential. Our focus will be on only those properties that can be acquired at prices that will enhance our overall return on capital. Although we are currently weighted towards natural gas reserves, we anticipate that we may return to a more even oil to natural gas ratio. While the acquisition market is currently very competitive, we believe that there are opportunities to acquire high quality oil and natural gas properties with these characteristics in the mid-continent and
southwest regions of the United States, where we have established core areas. In all property acquisitions the company will be seeking to become the operator. We will also continue to routinely evaluate our portfolio of properties and periodically divest non-core or low potential properties.
EXPLORATION. The acquisition market is currently very competitive, especially for transactions that exceed $50 million. These properties are generally sold on a tender bid basis, which has the effect of bidding up the price and maximizing the return to the seller. As a result, we have determined that it is no longer prudent to rely solely on acquisitions for asset growth. Our growth strategy has evolved from being primarily acquisition driven to a more balanced approach with an increased emphasis on exploration opportunities. We believe that this balanced approach will provide for a lower average reserve replacement cost, thereby improving our return on capital. In order to diversify our exposure, we generally acquire larger interests in company-operated, low risk projects and smaller interests in higher risk/high impact exploration properties. Our plan is for much of our exploration effort to be conducted with partners who bring a unique experience, expertise or ownership position in the prospect area of interest and have a successful track record.
MERGER OPPORTUNITIES. If we are able to complete the recapitalization, we expect to be able to attract other small capitalization oil and natural gas companies as merger or consolidation partners as a result of our substantially deleveraged balance sheet and stronger cash flow. We will be in an excellent position to make accretive acquisitions of other companies and, through this process, to use our strong balance sheet and cash flow to effect the recapitalization of suitable merger candidates that otherwise may not have access to capital.
CAPITAL AND FINANCIAL STRUCTURE. Our objective is to use internally generated cash flow to fund our exploration, development and exploitation programs. We believe that we can finance our acquisition opportunities at attractive prices with a combination of equity and debt.
MANAGEMENT TEAM. If we are able to complete the recapitalization, we will have the financial capability to pursue our strategy of increased focus on operating those properties that we own and on exploration as a means to grow our assets. We intend to continue restructuring our management team to add to our engineering, geology and geophysical personnel. We also intend to add seasoned senior oil and gas industry executives with experience in building stockholder value and in the management of exploration and development projects.
PRINCIPAL OIL AND NATURAL GAS PROPERTIES
The following table summarizes certain information with respect to each of our principal areas of operation at June 30, 2000.
(1) The proved reserves and SEC PV-10 were estimated by our internal petroleum engineers.
The following is an overview of our major fields, by area.
EAST TEXAS
GILMER FIELD. The Gilmer field consists of 41 natural gas wells that cover approximately 13,000 gross acres in Upshur County in east Texas. The wells produce from the Cotton Valley Lime formation at a depth of approximately 11,500 feet to 12,000 feet.
Goldston Oil Corporation, or Goldston, has an 80% working interest in, and is the operator of, our wells, which are in the heart of the Gilmer field. We own a 47.5% net profits interest in Goldston's working interest.
The Gilmer field is located on the northwestern flank of the Sabine Uplift. The initial well in the field was drilled in 1986 and the field was delineated over the following ten years, eventually expanding to 21 natural gas units. The reservoirs are characterized by low permeability, depletion drive mechanisms and require stimulation. Well spacing is currently four wells per 640 acre block for most of the units in the field. A field dedicated treating plant and centralized compression system provides the operator control in marketing the natural gas.
At June 30, 2000, the Gilmer field contained 55 Bcfe of proved reserves, which represented approximately 38% of our total proved reserves and 36% of our SEC PV-10. Our average daily net production from the Gilmer field in June 2000 was approximately 7.8 MMcf of natural gas and 91 Bbls, aggregating 8.3 MMcfe.
Two new wells have been drilled in June and July 2000, a third well is being drilled and three additional proved undeveloped locations are scheduled to be drilled this year. We believe these wells will allow the operator to assess the benefits of further down spacing. Depending upon economic conditions, the property's value could be increased by accelerating production through additional down spacing.
SOUTH TEXAS
J.C. MARTIN FIELD. The J.C. Martin field consists of 84 producing natural gas wells that cover approximately 8,300 gross acres in Zapata County, Texas on the Mexican border. The field primarily produces from the Lobo 1, 3 and 6 series of sands in the Wilcox formation at depths of approximately 8,000 feet to 10,000 feet.
Our interests consist of (a) a 13.33% perpetual, non-participating mineral royalty interest covering the Mecom family ranch and (b) an 80% net profits interest in Devon Energy Corporation's, or Devon's, 20% working interest in the ranch. Coastal Oil Corporation, or Coastal, operates all of the wells. The reservoirs are low permeability, producing through pressure depletion and requiring fracture stimulations. A portion of our royalty interest in this property is the subject of litigation involving the predecessor owner. For further description of this litigation, see "Item 3. Legal Proceedings."
At June 30, 2000, the J.C. Martin field contained 16 Bcfe of proved reserves, which represented approximately 11% of our total proved reserves and approximately 17% of our SEC PV-10. Our average daily net production from the J.C. Martin field in June 2000 was 13.4 MMcfe.
Some wells drilled since 1998 in this field tested natural gas from a deeper Cretaceous zone, the Navarro. This zone previously had not produced on the lease but had produced significant volumes to the north. We believe that there may be additional potential on the Mecom Ranch for this zone as only six wells have actually penetrated the Cretaceous zone. We also believe that potential exists for reserves in the Middle Wilcox zones at approximately 5,000 feet to 6,000 feet.
LOPENO AND VOLPE FIELDS. The Lopeno and Volpe fields are located in Zapata County, Texas. These fields consist of 25 wells. All of the wells produce from multiple reservoirs in the Upper Wilcox formation. Cody Energy, LLC ("Cody"), is the operator of the majority of the wells with Dominion Production & Exploration, Inc. operating the remainder.
The Lopeno field covers over 6,000 acres and is an extension of a field originally discovered in 1952. Over 20 sands have produced in the field at depths ranging from 6,500 feet to 12,000 feet. Typical of the numerous Upper Wilcox fields along the Texas Gulf Coast, the Lopeno field is highly faulted and overpressured. The Volpe field is also a Wilcox field located 8 miles north of Lopeno, Texas. A well was drilled directionally along the trapping fault and is producing from the Middle Wilcox formation. Multiple Upper Wilcox zones are classified behind the pipe. Nine proved undeveloped locations have been identified in these fields.
Until June 30, 2000, we owned a 66.66% net profits interest in working interests owned by Choctaw II Oil & Gas Ltd., or Choctaw. Choctaw's working interests vary from 15.7% to 75%. Effective June 30, 2000, we sold our net profits interests in the Lopeno and Volpe fields, and we purchased primarily working interests in these properties as well as some additional interests in the Lopeno and Volpe area. As a result of this sale, our economic interest in the Lopeno-Volpe properties has been reduced by approximately one-half and we have converted substantially all of the remaining economic interest from net profits interests to working interests.
On completion of the June 30, 2000 transactions, the Lopeno and Volpe fields contained an estimated 8
Bcfe of proved reserves, which represented approximately 6% of our total proved reserves and approximately 6% of our SEC PV-10. Our average daily net production from the fields in June 2000 was 1.2 MMcf/d of natural gas.
We believe that the production in these fields can be enhanced through workovers and accelerated drilling for the shallow, behind-the-pipe reserves.
KENTUCKY
NASGAS FIELD. We have a 75% working interest in approximately 44,000 gross acres in Meade, Hardin and Breckinridge Counties, Kentucky. There are currently 32 gross producing natural gas wells located on our leases in Meade County. We drilled 12 wells in this field during our first year of ownership. These wells produce from the New Albany Shale formation at depths of approximately 850 feet. The shale zone has two porosity members and averages 80 feet in thickness. In addition to the natural gas wells, we also own an interest in two salt-water disposal wells and a related natural gas gathering system.
At June 30, 2000, these properties contained 37 Bcfe of net proved reserves, which represents approximately 25% of our total proved reserves and approximately 15% of our SEC PV-10. We acquired these properties because we believe they have significant low risk development potential from relatively shallow formations. Natural gas reserves in the New Albany Shale formation are long-lived reserves, generally lasting over 40 years. Our average daily net production from the Nasgas field in June 2000 was 435 Mcf.
NEW MEXICO
CAPROCK (QUEEN) FIELD. The Caprock (Queen) field was our first acquisition and consists of 29 oil wells, 57 water injection wells, 57 shut-in wells and 76 temporarily abandoned wells on approximately 14,200 gross acres located in Lea and Chaves Counties, New Mexico. The Caprock field produces from the "Artesia Red Sand" or Queen sandstone of Permian age at a depth of approximately 3,000 feet. Discovery and delineation wells were drilled from 1940 through 1949. Development wells were drilled between 1954 and 1956 within the productive limits of the field, which is approximately twenty miles long and three miles wide. Primary production was established on 40-acre spacing. Initial waterflood operations began in 1959 and 1960.
We have a 100% working interest and an 82.6% revenue interest in two operating units, the Drickey Queen Sand Unit and the Westcap Unit, a 98.3% working interest and a 79.3% revenue interest in a third operating unit, the Rock Queen Unit, and a 100% working interest and a 90% revenue interest in the Trigg and Federal V leases. Our working interest partner, Texican, Inc., or Texican, owns 25% of our interest in 640 acres of the Drickey Queen Sand Unit and has an option to participate for 25% of our interest in future development activities in all of our units except for the Rock Queen Unit. These five properties comprise the central 14,200 acres of the approximately 26,000 productive acres that contain nine contiguous development units. We have an option on an additional 5,920 acres within the 26,000 productive acres.
We temporarily shut the field in due to significantly low oil prices in late 1998 and early 1999. The field was returned to production in October 1999.
Phase I of the program toward redeveloping the waterflood pattern has been implemented. This program consisted of drilling four single lateral water injection wells and one dual-lateral producing well. These five wells along with the production facilities and water injection plant constitute Phase I of the redevelopment program. Phase I incorporates 640 acres out of the approximate 20,000 acres we control in the Caprock field. We are the operator of this project.
MID-CONTINENT
We own interests in oil and gas assets located in the Texas panhandle, Oklahoma and Kansas, collectively referred to as the mid-continent assets. The mid-continent assets include 207 wells in 25 fields. These reserves are concentrated in high quality fields with the value evenly distributed over diverse, well-known reservoirs with long production histories supported by stable production declines. These reserves are long-lived assets with a productive life of 40 years and a reserves-to-production ratio of six years. An experienced production company operates each of these properties with focused operations in their respective areas. We own net profits overriding royalty interests in each of these properties.
The net daily production from these properties in June 2000 was 146 BOPD and 5.6 Mmcf, or 6.5 MMcfe. At June 30, 2000, the net proven reserves were estimated to be 18.2 Bcfe, which represented approximately 12% of our total proved reserves and 17% of our SEC PV-10.
EXPLORATION, DEVELOPMENT AND EXPLOITATION ACTIVITIES
Our development drilling program is generated largely through our internal technical evaluation efforts and as a result of our obtaining undeveloped acreage in connection with producing property acquisitions. In addition, there are numerous opportunities for infill drilling on our leases currently producing oil and natural gas. We intend to continue to pursue development drilling opportunities which offer potentially significant returns to us. Our exploitation activities consist of the evaluation of additional reserves through workovers, behind-the-pipe recompletions and secondary recovery operations.
The objective of our overall development and exploitation strategy is to achieve a balance between low risk workover and recompletion activities and moderate risk infill and extensional development wells. This exploitation/development strategy is intended to increase reserves while minimizing the risk of uneconomic projects. We have budgeted through the fiscal year ending June 30, 2001 approximately $3.8 million for exploratory drilling projects.
During the year ended June 30, 2000, we participated in drilling 21 gross, or 6.9 net, wells, of which 15 gross, or 3.2 net, were productive. However, we cannot assure you that this past rate of drilling success will continue in the future. We are currently pursuing development drilling projects on 7 different fields and anticipate continued growth in drilling activities.
At June 30, 2000, we had identified approximately 115 development locations and exploitation projects on our acreage. We expect to spend approximately $12.5 million on development locations and exploitation projects during the fiscal year ending June 30, 2001, depending on the availability of drilling capital.
The following is a brief discussion of our primary areas of development and exploitation activity:
EAST TEXAS
SEGNO FIELD. During April 1999, with an effective date of November 1, 1998, we converted our 80% net profits interest in Prime Energy's working interest to an 80% working interest in the proved developed wells and a 50% working interest in all other proved and unproved locations. We believe this was necessary to encourage Prime Energy to take steps to develop the field more fully.
We intend to continue participating with the operator, Prime Energy, in the development of the Segno field. Recent activity includes recompleting several wells. The operator continues to return wells that are off production back to service and to improve the field's facilities infrastructure. Several significant new prospects have been identified utilizing 2-D seismic data. We are participating in developing options to exploit these prospects. We have recently agreed to farm out the rights to drill a Middle Wilcox test in which we will retain a carried interest and a back in after payout.
SOUTH TEXAS
J.C. MARTIN FIELD. The J.C. Martin field produces from the Lobo Trend. Intense faulting has created many separate reservoirs that are over-pressured and highly faulted with numerous stacked sands. A 3D seismic study over the field has identified multiple new locations and initiated a new round of drilling. Since we acquired our interest in 1998, 23 wells have been drilled, five of which have been drilled in 2000. In addition to the Lobo reservoirs evaluated in the reserve report, we believe upside potential exists in the Navarro and Middle Wilcox zones. We recently recompleted one well in the Middle Wilcox. The deeper Cretaceous formation, the Navarro zone, also produces in this field. We expect 10 additional wells to be drilled before June 30, 2001.
LOPENO/VOLPE FIELDS. We believe significant potential exists in the Lopeno/Volpe fields to increase production. Over twenty sands have produced in the Lopeno field and most wells have multiple behind-the-pipe zones. Accelerated drilling for some of the shallower zones may be justified, improving their present value. Seven proved undeveloped locations have been identified in the Lopeno/Volpe fields that would develop Upper Wilcox sands. We are currently working with the operator to pursue the necessary workovers and additional drilling. We anticipate our share of capital expenditures in the Lopeno/Volpe fields will be approximately $2.4 million through June 2001.
KENTUCKY
NASGAS FIELD. We believe that the Nasgas field presents opportunities for low cost developmental drilling at depths of less than 1,000 feet. We expect that the field will be developed in four phases. The first phase, consisting of 20 wells, was completed in 1996. The second phase, consisting of 12 wells, was completed in 1998. The remaining development drilling is scheduled to commence during our 2001 fiscal year. We expect to develop an additional 75 proven locations at an average cost to us of $64,000 per well.
NEW MEXICO
CAPROCK (QUEEN) FIELD. Exploitation efforts at the Caprock (Queen) field consist primarily of a waterflood redevelopment project. We, with the assistance of independent engineering consultants, have evaluated several alternate development options. We plan to redevelop the Drickey Queen/Westcap Units using a line drive waterflood pattern. A total of five dual lateral horizontal producers and 14 single lateral horizontal injection wells may be drilled. Phase I of the program consists of four horizontal water injection wells and one dual lateral horizontal producer with an associated water injection plant and production facility and was recently implemented. Phase I fully developed one 640 acre section of the Drickey Queen Unit. We have entered into an agreement with Texican regarding Phase I. The agreement requires Texican to fund 50% of the first $2.0 million of the cost of Phase I. In consideration of this, Texican will earn a 25% working interest in Phase I in the Drickey Queen Unit. The Phase I program was implemented in the first calendar quarter of 2000 and our share of the program cost $1.6 million. We have begun injection and production operations in Phase I and do not have definitive results.
MARKETING
Our oil and natural gas production is sold to various purchasers typically in the areas where the oil or natural gas is produced. We do not refine or process any of the oil and natural gas we produce. We are currently able to sell, under contract or in the spot market, all of the oil and the natural gas we are capable of producing at current market prices. Substantially all of our oil and natural gas is sold under short term contracts or contracts providing for periodic adjustments or in the spot market; therefore, our revenue streams are highly sensitive to changes in current market prices. Our market for natural gas is pipeline companies as opposed to end users. For a description of the risks of changes in the prices for oil and natural gas, see "Item 1. Business - Risk Factors - Risks Related to Our Business -- Our profitability is highly dependent on the prices for oil and natural gas, which can be extremely volatile."
In an effort to reduce the effects of the volatility of the price of oil and natural gas on our operations and cash flow, we adopted a policy of hedging oil and natural gas prices whenever market prices are in excess of the prices
anticipated in our operating budget and financial plan through the use of commodity futures, options and swap agreements. We do not engage in speculative trading. For further description of our hedging strategy, see "Item 7. - Management's Discussion and Analysis of Financial Condition and Results of Operations - Changes in prices and hedging activities."
For the year ended June 30, 2000, Goldston Oil Corporation accounted for approximately 28% of our oil and natural gas sales, Coastal Oil and Gas, Inc. accounted for approximately 16% of our oil and natural gas sales, Devon Energy Corporation accounted for approximately 12% of our oil and natural gas sales, and Kaiser Francis Oil Company accounted for approximately 10% of our oil and natural gas sales. We do not believe that the loss of any of these buyers would have a material effect on our business or results of operations as we believe we could readily locate other buyers. However, short term disruptions could occur while we seek alternative buyers or while lines were being connected to other pipelines.
The market for our oil and natural gas depends on factors beyond our control, including the:
o price of imports of oil and natural gas;
o the extent of domestic production and imports of oil and natural gas;
o the proximity and capacity of natural gas pipelines and other transportation facilities;
o weather;
o demand for oil and natural gas;
o the marketing of competitive fuels; and
o the effects of state and federal regulations.
The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.
OIL AND NATURAL GAS RESERVES
The following tables summarize information regarding our estimated proved oil and natural gas reserves as of June 30, 1998, 1999 and 2000. All of these reserves are located in the United States. The estimates relating to our proved oil and natural gas reserves and future net revenues of oil and natural gas reserves at June 30, 1998 and 1999 with respect to the Morgan Properties included in this report on Form 10-K are based upon reports prepared by Ryder Scott Company. The estimates at June 30, 1998 and 1999 other than with respect to the Morgan Properties included in this form are based upon reports prepared by H.J. Gruy and Associates, Inc. The estimates at June 30, 2000 are based on reserve reports prepared by our internal petroleum engineers. In accordance with guidelines of the SEC, the estimates of future net cash flows from proved reserves and their SEC PV-10 are made using oil and natural gas sales prices in effect as of the dates of the estimates and are held constant throughout the life of the properties. Our estimates of proved reserves, future net cash flows and SEC PV-10 were estimated using the following weighted average prices, before deduction of production taxes:
Reserve estimates are imprecise and may be expected to change, as additional information becomes available. Furthermore, estimates of oil and natural gas reserves, of necessity, are projections based on engineering data, and there are uncertainties inherent in the interpretation of these data as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgement. Reserve reports of other engineers might differ from the reports contained herein. Results of drilling, testing, and production
subsequent to the date of the estimate may justify revision of this estimate. Future prices received for the sale of oil and natural gas may be different from those used in preparing these reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, we cannot assure you that the reserves set forth herein will ultimately be produced or can there be assurance that the proved undeveloped reserves will be developed within the periods anticipated. The discounted future net cash inflows should not be construed as representative of the fair market value of the proved oil and natural gas properties, since discounted future net cash inflows are based upon projected cash inflows which do not provide for changes in oil and natural gas prices nor for escalation of expenses and capital costs. The meaningfulness of these estimates is highly dependent upon the accuracy of the assumptions upon which they were based.
All reserves are evaluated at constant temperature and pressure, which can affect the measurement of natural gas reserves. Operating costs, development costs and some production-related and ad valorem taxes were deducted in arriving at the estimated future net cash flows. No provision was made for income taxes, and the estimates were based on operating methods and existing conditions at the prices and operating costs prevailing at the dates indicated above. The estimates of the SEC PV-10 from future net cash flows differ from the Standardized Measure set forth in the notes to our consolidated financial statements, which is calculated after provision for future income taxes. We cannot assure you that these estimates are accurate predictions of future net cash flows from oil and natural gas reserves or their present value.
For additional information concerning our oil and natural gas reserves and estimates of future net revenues attributable thereto, see note 11 of the notes to consolidated financial statements included in this report.
COMPANY RESERVES
The following tables set forth our proved reserves of oil and natural gas and the SEC PV-10 thereof for each year in the three-year period ended June 30, 2000.
PROVED OIL AND NATURAL GAS RESERVES(1)
SEC PV-10 OF PROVED RESERVES(1)
(1) The data shown at June 30, 1998 and June 30, 1999, excluding data with respect to the Morgan Properties at June 30, 1998 and June 30, 1999, is based upon reports prepared by H.J. Gruy and Associates, Inc. The data included with respect to the Morgan Properties at June 30, 1998 and June 30, 1999 is based upon reserve reports prepared by Ryder Scott Company. The data for June 30, 2000 is based upon reserve reports prepared by our internal petroleum engineers.
(2) SEC PV-10 differs from the Standardized Measure set forth in the notes to our consolidated financial statements, which is calculated after a provision for future income taxes.
Except for the effect of changes in oil and natural gas prices no major discovery or other favorable or adverse event is believed to have caused a significant change in these estimates of our reserves since June 30, 2000.
Except for Form EIA 23, "Annual Survey of Domestic Oil and Gas Reserves," filed with the United States Department of Energy, no other estimates of total proven net oil and natural gas reserves have been filed by us with, or included in any report to, any United States authority or agency pertaining to our individual reserves since the beginning of our last fiscal year. Reserves reported on Form EIA 23 are comparable to the reserves reported by us herein.
OPERATIONS DATA
PRODUCTIVE WELLS
The following table sets forth the number of total gross and net productive wells in which we owned an interest as of June 30, 2000.
(1) Represents wells located in Kansas, Alabama and Wyoming.
PRODUCTION ECONOMICS
The following table sets forth certain operating information for the periods presented.
(1) Represents depreciation, depletion and amortization of oil and natural gas properties only.
DRILLING ACTIVITY
The following table sets forth our gross and net working interests in exploratory and development wells (but excluding injection or service wells) drilled during the indicated periods.
Since June 30, 2000 we have successfully drilled 3 gross, 1.9 net, wells, of which 1 gross, 1.0 net, were dry holes, through August 17, 2000. At August 17, 2000 we were in the process of drilling 4 gross, 0.9 net, wells.
DEVELOPED AND UNDEVELOPED ACREAGE
The following table sets forth the approximate gross and net acres in which we owned an interest as of June 30, 2000.
(1) Represents acreage located in Colorado, Kansas, Alabama and Wyoming.
MARKETS AND COMPETITION
The oil and natural gas industry is highly competitive. Our competitors include major oil companies, other independent oil and natural gas concerns and individual producers and operators, many of which have financial resources, staffs and facilities substantially greater than ours. In addition, we encounter substantial competition in acquiring oil and natural gas properties, marketing oil and natural gas and hiring trained personnel. When possible, we try to avoid open competitive bidding for acquisition opportunities. The principal means of competition with respect to the sale of oil and natural gas production are product availability and price. While it is not possible for us to state accurately our position in the oil and natural gas industry, we believe that we represent a minor competitive factor.
The market for our oil and natural gas production depends on factors beyond our control, including domestic and foreign political conditions, the overall level of supply of and demand for oil and natural gas, the price of imports of oil and natural gas, access to natural gas pipelines and other transportation facilities and overall economic conditions. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.
TITLE TO OIL AND NATURAL GAS PROPERTIES
We have acquired interests in producing and non-producing acreage in the form of working interests, royalty interests, overriding royalty interests and net profits interests. Substantially all of our property interests, and the assignors' interests in the working or other interests in the underlying properties, are held pursuant to leases from third parties. The leases grant the lessee the right to explore for and extract oil and natural gas from specified areas. Consideration for these leases usually consists of a lump sum payment, such as a bonus, and a fixed annual charge, such as a delay rental, prior to production unless the lease is paid up and, once production has been established, a royalty based generally upon either the proceeds from the sale of oil and natural gas or the market value of oil and natural gas produced. Once wells are drilled, a lease generally continues so long as production of oil and natural gas continues. In some cases, leases may be acquired in exchange for a commitment to drill or finance the drilling of a specified number of wells to predetermined depths. Some of our non-producing acreage is held under leases from mineral owners or governmental entities which expire at varying dates. We are obligated to pay annual delay rentals to the lessors of some properties in order to prevent the leases from terminating. Title to leasehold properties is subject to royalty, overriding royalty, carried, net profits and other similar interests and contractual arrangements customary in the oil and natural gas industry, and to liens incident to operating agreements, liens relating to amounts owed to the operator, liens for current taxes not yet due and other encumbrances.
As is customary in the industry, we generally acquire oil and natural gas acreage without any warranty of title
except as to claims made by, through or under the transferor. Although we have title examined prior to acquisition of developed acreage in those cases in which the economic significance of the acreage justifies the cost, there can be no assurance that losses will not result from title defects or from defects in the assignment of leasehold rights. In many instances, title opinions may not be obtained if in our judgment it would be uneconomical or impractical to do so.
The underlying properties are typically subject, in one degree or another, to one or more of the following:
o royalties and other burdens and obligations, expressed and implied, under oil and gas leases;
o overriding royalties and other burdens created by the assignor or its predecessors in title;
o a variety of contractual obligations, including, in some cases, development obligations, arising under operating agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles;
o liens that may arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements;
o pooling, unitization and communitization agreements, declarations and orders; and
o easements, restrictions, rights-of-way and other matters that commonly affect property.
To the extent that these burdens and obligations affect the assignor's rights to production and the value of production from the underlying properties, they have been taken into account in calculating our interests and in estimating the size and value of the reserves attributable to our net profits interests and royalty interests.
A substantial portion of our oil and natural gas property interests are in the form of non-operated, net profits interests and royalty interests. The net profits interests were conveyed to us by various assignors from the assignor's net revenue interests in the oil and natural gas properties burdened by the net profits interests and royalty interests (the "underlying properties"). The assignors' net revenue interests are generally leasehold working interests less lease burdens.
Net profits interests. As the owner of net profits interests, we do not have the direct right to drill or operate wells or to cause third parties to propose or drill wells on the underlying properties. If an assignor or any other working interest owner proposes to drill wells on one of the underlying properties, then that assignor must give us notice of the proposal. Under an agreement covering the underlying property, we have the option to pay a specified percentage of the assignor's working interest share of the expenses of the well that is proposed. We would then become entitled to a net profits interest equal to the specified percentage multiplied by the assignor's net revenue interest in that well. However, if an assignor elects not to participate in the drilling of a well, we will not be able to participate in that well. Moreover, if an assignor owns less than a 100% working interest in a proposed well, and the other owners of working interests in that well elect not to participate in the well, the well will not be drilled unless the money to pay the costs allocable to the working interest owners who do not elect to participate in the well is obtained. The financial strength and the competence of the various assignors, and to a lesser extent the financial strength and the competence of other parties owning working interests in the underlying properties, may have an effect on when and whether wells get drilled on the underlying properties, and on whether operations are conducted in a prudent and competent manner.
Royalty interests. The royalty interests are generally in the form of term royalty interests. The duration of these interests is the same as the underlying oil and natural gas lease. Some of the royalty interests are perpetual royalty interests which entitle the owner to a share of production from the underlying properties under both the current oil and natural gas lease and any replacement or successor oil and natural gas lease. In all cases, the royalty interests are non-operating interests, have little or no influence over oil and natural gas development or operation on the lands they burden but have limited cost bearing responsibilities.
Sale and abandonment of underlying properties. An assignor has the right to abandon any well or working interest included in the underlying properties if, in its opinion, the well or property ceases to produce or is not capable of producing oil or natural gas in commercially paying quantities. We may not control the timing of plugging and abandoning wells. The conveyances provide that the assignor's working interest share of the costs of plugging and abandoning uneconomic wells are deducted in calculating our net cash flow from the underlying property.
The assignor can sell the underlying properties, subject to and burdened by the royalty interests, without our consent. Accordingly, the underlying properties could be transferred to a party with a weaker financial profile.
REGULATION
GENERAL FEDERAL AND STATE REGULATION
Our oil and natural gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal and state agencies. Failure to comply with these rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with these laws.
The State of Texas and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and natural gas. Many states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of these wells. Many states restrict production to the market demand for oil and natural gas. Some states have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries.
The Federal Energy Regulatory Commission, or FERC, regulates interstate natural gas transportation rates and service conditions, which affect the revenues received by us for sales of our production. Since the mid-1980s, FERC has issued a series of orders, culminating in Order Nos. 636, 636-A and 636-B, or Order 636, that have significantly altered the marketing and transportation of natural gas. Order 636 mandates a fundamental restructuring of interstate pipeline sales and transportation service, including the unbundling by interstate pipelines of the sale, transportation, storage and other components of the city-gate sales services the pipelines previously performed. One of FERC's purposes in issuing the orders is to increase competition within all phases of the natural gas industry. Order 636 and subsequent FERC orders on rehearing have been appealed and are pending judicial review. Because these orders may be modified as a result of the appeals, it is difficult to predict the ultimate impact of the orders on us. Generally, Order 636 has eliminated or substantially reduced the traditional role of intrastate pipelines as wholesalers of natural gas, and has substantially increased competition and volatility in natural gas markets.
The price we receive from the sale of oil and natural gas liquids is affected by the cost of transporting products to market. Effective January 1, 1995, FERC implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index these rates to inflation, subject to some conditions and limitations. The Railroad Commission of the State of Texas is considering adopting rules to prevent discriminatory transportation practices by intrastate natural gas gatherers and transporters by requiring the disclosure of rate information under varying conditions of service. We are not able to predict with certainty the effects, if any, of these regulations on our operations. However, the regulations may increase transportation costs or reduce wellhead prices for oil and natural gas liquids.
Finally, from time to time regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas.
ENVIRONMENTAL REGULATION
The exploration, development and production of oil and natural gas, including the operation of saltwater injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. Our domestic activities are subject to a variety of environmental laws and regulations, including but not limited to, the Oil Pollution Act of 1990, or OPA, the Clean Water Act, or CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or CAA, and the Safe Drinking Water Act, or SDWA, as well as state regulations promulgated under comparable state statutes. We are also subject to regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials that are found in our oil and natural gas operations. Civil and criminal fines and penalties may be imposed for non-compliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected areas or species, and impose substantial liabilities for cleanup of pollution.
Under the OPA, a release of oil into water or other areas designated by the statute could result in our being held responsible for the costs of remediating the release, OPA specified damages, and natural resource damages. The extent of that liability could be extensive, as set forth in the statute, depending on the nature of the release. A release of oil in harmful quantities or other materials into water or other specified areas could also result in our being held responsible under the CWA for the costs of remediation, and any civil and criminal fines and penalties.
CERCLA and comparable state statutes, also known as "Superfund" laws, can impose joint and several retroactive liability, without regard to fault or the legality of the original conduct, on specified classes of persons for the release of a "hazardous substance" into the environment. In practice, cleanup costs are usually allocated among various responsible parties. Potentially liable parties include site owners or operators, past owners or operators under certain conditions, and entities that arrange for the disposal or treatment of, or transport hazardous substances found at the site. Although CERCLA, as amended, currently exempts petroleum, including but not limited to, oil, natural gas and natural gas liquids from the definition of hazardous substance, our operations may involve the use or handling of other materials that may be classified as hazardous substances under CERCLA. Furthermore, there can be no assurance that the exemption will be preserved in future amendments of CERCLA, if any.
RCRA and comparable state and local requirements impose standards for the management, including treatment, storage, and disposal of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. From time to time, proposals have been made that would reclassify certain oil and natural gas wastes, including wastes generated during pipeline, drilling, and production operations, as "hazardous wastes" under RCRA which would make these solid wastes subject to much more stringent handling, transportation, storage, disposal, and clean-up requirements. This development could have a significant impact on our operating costs. While state laws vary on this issue, state initiatives to further regulate oil and natural gas wastes could have a similar impact.
Oil and natural gas exploration and production, and possibly other activities, have been conducted at some of our properties by previous owners and operators. Materials from these operations remain on some of the properties and in some instances require remediation. In addition, we have agreed to indemnify sellers of producing properties from whom we have acquired reserves against certain liabilities for environmental claims associated with these properties. While we do not believe that costs to be incurred by us for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, there can be no guarantee that these costs will not result in material expenditures.
Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil or other materials occur, and we incur costs for waste handling and environmental compliance. Moreover, we are able to control directly the operations of only those wells for which we act as the operator.
Notwithstanding our lack of control over wells owned by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us.
It is not anticipated that we will be required in the near future to expend amounts that are material in relation to our total capital expenditures program by reason of environmental laws and regulations, but inasmuch as these laws and regulations are frequently changed, we are unable to predict the ultimate cost of compliance. There can be no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See "Risk Factors."
EMPLOYEES
As of August 17, 2000, we had 18 full-time employees consisting of 8 officers and 10 support staff. Four of the employees are in Ottawa, Canada, 13 of the employees are located in the Dallas office, and 1 is on site in Kentucky. In addition, we regularly engage technical consultants and independent contractors to provide specific advice or to perform administrative or technical functions.
RISK FACTORS
You should carefully consider the following risks before making an investment decision. The trading price of our common stock could decline due to any of these risks, and you could lose all or part of your investment. You also should refer to the other information set forth in this report, including our financial statements and the related notes thereto.
RISKS RELATED TO OUR BUSINESS
WE HAVE IN THE PAST EXPERIENCED NET LOSSES AND WE MAY EXPERIENCE NET LOSSES IN THE FUTURE, WHICH COULD MATERIALLY ADVERSELY AFFECT OUR RESULTS OF OPERATIONS.
Since beginning operations in 1994, we have not been profitable on an annual or quarterly basis. We experienced a net loss of approximately $32.8 million for the year ended June 30, 1998, a net loss of approximately $47.5 million for the year ended June 30, 1999 and a net loss of approximately $9.1 million for the year ended June 30, 2000. We may experience net losses in the future as we continue to incur significant operating expenses and to make capital expenditures. Even if we do become profitable, we may not sustain or increase profitability on a quarterly or annual basis in the future. At June 30, 2000, we had an accumulated deficit of approximately $92.9 million.
OUR PROFITABILITY IS HIGHLY DEPENDENT ON THE PRICES FOR OIL AND NATURAL GAS, WHICH CAN BE EXTREMELY VOLATILE.
Our revenues, profitability and future growth substantially depend on prevailing prices for oil and natural gas. Prices for oil and natural gas can be extremely volatile. Among the factors that can cause this volatility are:
o weather conditions;
o the level of consumer product demand;
o domestic and foreign governmental regulations;
o the price and availability of alternative fuels;
o political conditions in oil and natural gas producing regions;
o the domestic and foreign supply of oil and natural gas;
o the availability, proximity and capacity of gathering systems of natural gas;
o the price of foreign imports; and
o overall economic conditions.
Prices for oil and natural gas affect the amount of cash flow available to us for capital expenditures and the repayment of our outstanding debt. Our ability to maintain or increase our borrowing capacity and to obtain additional capital on attractive terms is also substantially dependent upon oil and natural gas prices. In addition, because we currently produce more natural gas than oil, we face more risk with fluctuations in the price of natural gas than oil. We have used hedging contracts to reduce our exposure to price changes.
HEDGING OUR PRODUCTION MAY CAUSE US TO FOREGO FUTURE PROFITS.
To reduce our exposure to changes in the prices of oil and natural gas, we have entered into and may in the future enter into hedging arrangements for a portion of our oil and natural gas production. The hedges that we have entered into generally provide a "floor" or "cap and floor" on the prices paid for our oil and natural gas production over a period of time. Hedging arrangements may expose us to the risk of financial loss in some circumstances, including the following:
o the other party to the hedging contract defaults on its contract obligations; or
o there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.
Reduced revenues resulting from our hedging activities could have an adverse effect on our financial condition and operations. For the year ended June 30, 2000, our revenues were reduced by $1,548,000 as a result of our existing hedge contracts. We may have to make additional payments under these contracts in the future depending on the difference between actual and hedged prices of oil and natural gas. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in the prices for oil and natural gas.
Some of our hedging arrangements contain a "cap" whereby we must pay the counter-party if oil or natural gas prices exceed the price specified in the contract. We are required to maintain letters of credit with our counter-parties, and we may be required to provide additional letters of credit if prices for oil and natural gas futures increase above the "cap" prices. The amount of these letters of credit is a function of the market value of oil and natural gas prices and the volumes of oil and natural gas subject to the contract. As a result, the value of these letters of credit will fluctuate with the market prices of oil and natural gas. These letters of credit are issued pursuant to our credit agreement and as a result utilize some of our borrowing capacity, reducing funds available to be borrowed under our credit agreement.
IF WE ARE NOT ABLE TO REPLACE DEPLETED RESERVES, OUR FUTURE RESULTS OF OPERATIONS WILL BE ADVERSELY AFFECTED.
The rate of production from oil and natural gas properties declines as reserves are depleted. Our proved reserves will decline as reserves are produced unless we acquire additional properties containing proved reserves, conduct successful exploration, development and exploitation activities on new or currently leased properties or identify additional formations with primary or secondary reserve opportunities on our properties. If we are not successful in expanding our reserve base, our future oil and natural gas production, the primary source of our revenues, will be adversely affected. The level of our future oil and natural gas production and our results of operations are therefore highly dependent on the level of our success in finding and acquiring additional reserves. Our ability to find and acquire additional reserves depends on our generating sufficient cash flow from operations and other sources of capital, including borrowings under our credit agreement. We cannot assure you that we will have sufficient cash flow or cash from other sources to expand our reserve base. Our ability to continue acquiring producing properties or companies that own producing properties assumes that major integrated oil companies and independent oil companies will continue to divest many of their oil and natural gas properties. We cannot assure you that these divestitures will continue or that we will be able to acquire producing properties at acceptable prices.
WE MAY HAVE DIFFICULTY FINANCING OUR PLANNED GROWTH AND CAPITAL EXPENDITURES.
We have experienced and expect to continue to experience substantial capital expenditure and working capital needs as a result of our exploration, development, exploitation and acquisition strategy. In the future, we may require financing, in addition to cash generated from our operations and the proposed offering of our common stock, to fund our planned growth and capital expenditures. Over the past two years, we have experienced constraints on our ability to arrange additional capital to fund our business plan.
Although we were able to borrow an additional $9.3 million under our credit agreement as of August 17, 2000, our lenders could reduce our borrowing limit. If additional capital resources are unavailable, we will be unable to grow our business and we may curtail our drilling, development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis.
OUR LEVEL OF DEBT MAY NOT ALLOW US PROPERLY TO PLAN FOR FUTURE OPPORTUNITIES OR TO COMPETE EFFECTIVELY.
As of June 30, 2000, our ratio of total indebtedness to total capitalization was 132% and our consolidated total interest coverage ratio was 1.3 to 1. In addition, we may borrow more money in the future to fund our business strategy. This level of debt could:
o increase our vulnerability to general adverse economic and industry conditions, especially declines in oil and natural gas prices;
o limit our ability to fund future acquisitions, capital expenditures and other general corporate requirements;
o require us to dedicate a material portion of our cash flow from operations to payments on our debt;
o limit our flexibility in planning for or reacting to, changes in our business and industry; and
o limit our ability to, among other things, borrow additional funds, sell assets and pay dividends.
RESTRICTIVE DEBT COVENANTS LIMIT OUR ABILITY TO FINANCE OUR OPERATIONS, FUND OUR CAPITAL NEEDS AND ENGAGE IN OTHER BUSINESS ACTIVITIES THAT MAY BE IN OUR INTEREST.
Our credit agreement and the indenture governing our 12 1/2% senior notes due 2008 contain significant covenants that, among other things, restrict our ability to:
o dispose of assets;
o incur additional indebtedness;
o repay other indebtedness;
o pay dividends;
o enter into specified investments or acquisitions;
o repurchase or redeem capital stock;
o merge or consolidate; or
o engage in specified transactions with subsidiaries and affiliates and our other corporate activities.
Also, our credit agreement requires us to maintain compliance with the financial ratios included in that agreement. Our ability to comply with these ratios may be affected by events beyond our control. A breach of any of these covenants or our inability to comply with the required financial ratios could result in a default under our credit agreement.
We have in the past been in default of some covenants under our previous credit agreement. All of these defaults were waived by the lenders. However, if we default under our current credit agreement, our lender may declare all amounts borrowed under the credit agreement, together with accrued interest, to be due and payable. If we do not repay the indebtedness promptly, our lender could then foreclose against any collateral securing the payment of the indebtedness. Substantially all of our oil and natural gas interests secure our credit agreement.
OUR ABILITY TO GENERATE SUFFICIENT CASH TO SERVICE OUR DEBT AND REPLACE OUR RESERVES DEPENDS ON MANY FACTORS BEYOND OUR CONTROL.
We rely on cash from our operations to pay the principal and interest on our debt. Our ability to generate cash from operations depends on the level of production from our properties, general economic conditions, including the prices paid for oil and natural gas, success in our exploration, development and exploitation activities, and legislative, regulatory, competitive and other factors beyond our control. Our operations may not generate enough cash to pay the principal and interest on our debt.
WE CANNOT ASSURE YOU THAT WE WILL BE SUCCESSFUL IN MANAGING OUR GROWTH.
The success of our future growth will depend on a number of factors, including:
o our ability to timely explore, develop and exploit acquired properties;
o our ability to continue to attract and retain skilled personnel;
o our ability to continue to expand our technical, operational and administrative resources; and
o the results of our drilling program.
Our growth could strain our financial, technical, operational and administrative resources. Our failure to successfully manage our growth could adversely affect our operations and net revenues through increased operating costs and revenues that do not meet our expectations.
WE MAY PURCHASE OIL AND NATURAL GAS PROPERTIES WITH LIABILITIES OR RISKS WE DID NOT KNOW ABOUT OR THAT WE DID NOT CORRECTLY ASSESS, AND, AS A RESULT, WE COULD BE SUBJECT TO LIABILITIES THAT COULD ADVERSELY AFFECT OUR RESULTS OF OPERATIONS.
We evaluate and pursue acquisition opportunities, primarily in the mid-continent and southwest regions of the United States. Before acquiring oil and natural gas properties, we estimate the recoverable reserves, future oil and natural gas prices, operating costs, potential environmental and other liabilities and other factors relating to the properties. We believe our method of review is generally consistent with industry practices. However, our review involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties we buy. We may not become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not generally perform inspections on every well, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. Even if we identify problems, the seller may not be willing or financially able to give contractual protection against these problems, and we may decide to assume environmental and other liabilities in connection with acquired properties. If we acquire properties with risks or liabilities we did not know about or that we did not correctly assess, our financial condition and results of operations could be adversely affected.
THE OIL AND GAS BUSINESS INVOLVES MANY OPERATING RISKS THAT COULD CAUSE SUBSTANTIAL LOSSES.
Drilling activities involve the risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill wells that are productive but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Whether a well is productive and profitable depends on a number of factors, including the following, many of which are beyond our control:
o general economic and industry conditions, including the prices received for oil and natural gas;
o mechanical problems encountered in drilling wells or in production activities;
o problems in title to our properties;
o weather conditions which delay drilling activities or cause producing wells to be shut down;
o compliance with governmental requirements; and
o shortages in or delays in the delivery of equipment and services.
If we do not drill productive and profitable wells in the future, our financial condition and results of operations could be materially and adversely affected due to decreased cash flow and net revenues.
In addition to the substantial risk that we may not drill productive and profitable wells, the following hazards are inherent in oil and natural gas exploration, development, exploitation, production and gathering, including:
o unusual or unexpected geologic formations;
o unanticipated pressures;
o mechanical failures;
o blowouts where oil or natural gas flows uncontrolled at a wellhead;
o cratering or collapse of the formation;
o explosions;
o pollution; and
o environmental accidents such as uncontrollable flows of oil, natural gas or well fluids into the environment, including groundwater contamination.
We could suffer substantial losses from these hazards due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. We carry insurance that we believe is in accordance with customary industry practices for companies of our size. However, we do not fully insure against all risks associated with our business either because this insurance is not available or because we believe the cost is prohibitive. The occurrence of an event that is not covered, or not fully covered by insurance, could have a material adverse effect on our financial condition and results of operations.
OUR EXPLORATION ACTIVITIES INVOLVE A HIGH DEGREE OF RISK AND MAY NOT BE COMMERCIALLY SUCCESSFUL.
Oil and natural gas exploration involves a high degree of risk that hydrocarbons will not be found, that they will not be found in commercial quantities, or that their production will be insufficient to recover drilling, completion and operating costs. The 3-D seismic data and other technologies we may use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or economically producible. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Furthermore, completion of a well does not guarantee that it will be profitable or even that it will result in recovery of drilling, completion and operating costs. Therefore, we may not earn revenues with respect to, or recover costs spent on, our exploration activities.
OUR SECONDARY RECOVERY PROJECTS REQUIRE SIGNIFICANT CAPITAL EXPENDITURES AND MAY NOT BE COMMERCIALLY SUCCESSFUL.
We face the risk that we will spend a significant amount of money on secondary recovery operations, such as waterflooding projects, without any increase in production. Although waterflooding requires significant capital expenditures, the total amount of reserves that can be recovered though waterflooding is uncertain. In addition, there is generally a delay between the initiation of water injection into a formation containing hydrocarbons and any increase in production that may result from the injection. The degree of success, if any, of any secondary recovery program depends on a large number of factors, including the porosity, permeability and heterogeneity of the formation, the technique used and the location of injection wells.
WE CANNOT CONTROL THE DEVELOPMENT OF A SUBSTANTIAL PORTION OF OUR PROPERTIES BECAUSE OUR INTERESTS ARE IN THE FORM OF NON-OPERATED NET PROFITS INTERESTS AND OVERRIDING ROYALTY INTERESTS.
A substantial portion of our oil and natural gas property interests are in the form of non-operated, net profits interests and royalty interests. As the owner of non-operated net profits interests and royalty interests, we do not have the direct right to drill or operate wells or to cause third parties to propose or drill wells on the underlying properties. As a result, the success and timing of our drilling and development activities on those properties operated by others depend upon a number of factors outside of our control, including:
o the timing and amount of capital expenditures;
o the operator's expertise and financial resources;
o the approval of other participants in drilling wells; and
o the selection of suitable technology.
If the operators of these properties do not conduct drilling and development activities on these properties, then our results of operations may be adversely affected.
WE MAY LOSE TITLE TO OUR ROYALTY INTEREST IN THE J.C. MARTIN FIELD AS A RESULT OF LITIGATION OVER TITLE TO THE ROYALTY INTEREST.
A portion of our landowner royalty on the J.C. Martin field, which comprises approximately 10% of our total SEC PV-10 value as of June 30, 2000, is currently subject to a lawsuit that may create uncertainty as to the title to our royalty interest. A favorable order of summary judgment has been rendered in favor of the pension funds managed by the entity that sold us the properties. The order has been appealed. Eight million dollars of the purchase price we paid for the Morgan Properties, which include our royalty interest in the J.C. Martin field, are currently in escrow pending the resolution of this lawsuit. If the summary judgment is overturned and a final judgment is later entered against the entity who sold us this property and that judgment unwinds the original transaction in which the entity acquired its interest in the J.C. Martin field, the escrowed monies would be returned to us and we would be required to convey our royalty interest in the J.C. Martin field to the plaintiff retroactive to the date we acquired the interest.
IF A BANKRUPTCY COURT TREATS ANY OF OUR NET PROFITS INTERESTS AS CONTRACT RIGHTS INSTEAD OF REAL PROPERTY INTERESTS, WE COULD LOSE ALL OF THE VALUE OF THOSE INTERESTS.
We cannot assure you whether a court in the states of Kansas and Oklahoma would treat the net profits interests as contract rights or real property interests. Our net profits interests in these states comprise 14% of our SEC-PV-10 as of June 30, 2000. If any of the assignors become involved in bankruptcy proceedings in these states, we face the risk that our net profits interests might be treated by a bankruptcy court as contract rights instead of real property interests. If the bankruptcy court treats our net profits interests as contract rights, then we would be treated as an unsecured creditor in the bankruptcy, and under the terms of the bankruptcy plan, we could lose all of the value of the net profits interests. If the bankruptcy court treats the net profits interests as real property interests, then our interests should not be materially affected.
ANY NEGATIVE VARIANCE IN OUR ESTIMATES OF PROVED RESERVES AND FUTURE NET REVENUES COULD AFFECT THE CARRYING VALUE OF OUR ASSETS, OUR INCOME AND OUR ABILITY TO BORROW FUNDS.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and the timing of development expenditures, including many factors beyond our control. The reserve data included in this report represent only estimates. In addition, the estimates of future net revenue from proved reserves and their present value are based on assumptions about future production levels, prices and costs that may not prove to be correct over time. In particular, estimates of oil and natural gas reserves, future net revenue from proved reserves and the present value of proved reserves for the oil and natural gas properties described in this report are based on the assumption that future oil and natural gas prices remain the same as oil and natural gas prices at June 30, 2000. The NYMEX prices as of June 30, 2000, used for purposes of our estimates were $32.50 per Bbl of oil and $4.33 per Mcf of natural gas. Any significant variance in actual results from these assumptions could also materially affect the estimated quantity and value of our reserves.
WE MAY BE REQUIRED TO WRITE DOWN THE CARRYING VALUE OF OUR PROVED PROPERTIES UNDER ACCOUNTING RULES AND THESE WRITEDOWNS COULD ADVERSELY AFFECT OUR FINANCIAL CONDITION.
There is a risk that we will be required to write-down the carrying value of our oil and natural gas properties when oil and natural gas prices are low. In addition, write-downs may occur if we have:
o downward adjustments to our estimated proved reserves,
o increases in our estimates of development costs or
o deterioration in our exploration and exploitation results.
We periodically review the carrying value of our oil and natural gas properties under the full cost accounting rules of the Securities and Exchange Commission. Under these rules, the net capitalized costs of oil and natural gas properties may not exceed a ceiling limit that is based on the present value, based on flat prices at a single point in time, of estimated future net revenues from proved reserves, discounted at 10%. If net capitalized costs of oil and natural gas properties exceed the ceiling limit, we must charge the amount of this excess to earnings in the quarter in which the excess occurs. At June 30, 1998, we were required to write down the carrying value of our oil and natural gas properties by $28.2 million. At December 31, 1998, we were required to write down the carrying value of our oil and natural gas properties by an additional $35 million. We may not reverse write-downs even if prices increase in subsequent periods. A write-down does not affect cash flow from operating activities, but it does reduce the book value of our net tangible assets and stockholders' equity.
IF WE ARE UNABLE TO COMPETE EFFECTIVELY AGAINST OTHER OIL AND GAS COMPANIES, WE MAY BE UNABLE TO ACQUIRE NEW PROPERTIES AT ATTRACTIVE PRICES OR TO SUCCESSFULLY DEVELOP OUR PROPERTIES.
We encounter strong competition from other oil and gas companies in acquiring properties and leases for the exploration, exploitation and production of oil and natural gas. Many of our competitors have financial resources, staff and facilities substantially greater than ours. Our competitors may be able to pay more for desirable leases and to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit. As a result, we may not be able to buy properties at affordable prices or to successfully develop our properties. Our ability to explore, develop and exploit oil and natural gas reserves and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.
WE ARE SUBJECT TO GOVERNMENT REGULATION AND LIABILITY, INCLUDING ENVIRONMENTAL LAWS THAT COULD REQUIRE SIGNIFICANT EXPENDITURES AND COULD MATERIALLY DECREASE OUR NET INCOME.
The exploration, development, exploitation, production and sale of oil and natural gas in the U.S. are subject to many federal, state and local laws and regulations, including environmental laws and regulations. Under these laws and regulations, we may be required to make large expenditures that could materially and adversely affect our results of operations. These expenditures could include payments for personal injuries, property damage, oil spills, the discharge of hazardous materials, remediation and clean-up costs and other environmental damages. While we maintain insurance coverage for our operations, we do not believe that full insurance coverage for all potential environmental damages is available at a reasonable cost. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Laws and regulations protecting the environment have become increasingly stringent in recent years and may impose liability on us for environmental damage and disposal of hazardous materials even if we were not negligent or at fault. We may also be liable for the conduct of others or for our own acts even if our acts complied with applicable laws at the time we performed those acts.
RISKS RELATING TO OUR COMMON STOCK
OUR COMMON STOCK WAS DELISTED FROM THE NASDAQ SMALL CAP MARKET AND AS A RESULT THE PRICE OF THE COMMON STOCK MAY BE DEPRESSED AND YOU MAY HAVE DIFFICULTIES RESELLING THE STOCK.
On November 11, 1999, Nasdaq delisted our common stock from trading on the Nasdaq SmallCap Market because of our failure to meet the minimum net tangible asset base, the minimum market capitalization and the minimum trading price thresholds. This has resulted in our common stock being quoted on the OTC Bulletin Board. Many institutional and other investors refuse to invest in stocks that are traded at levels below the Nasdaq SmallCap Market which could make our efforts to raise capital more difficult. In addition, the firms that currently make a market for our common stock could discontinue that role. OTC Bulletin Board stocks are often lightly traded or not traded at all on any given day. Our inability to list our common stock on the Nasdaq Small Cap Market or any other stock exchange will negatively affect the liquidity and marketability of the common stock.
IF THERE IS A CHANGE OF CONTROL OF THE COMPANY, WE WOULD BE IN DEFAULT UNDER OUR CREDIT AGREEMENT AND WE COULD BE REQUIRED TO REPURCHASE OUR SENIOR NOTES.
If there is a change of control of our company as defined in our credit agreement, we would be in default under our credit agreement. In addition, the indenture governing our senior notes contains provisions that, under some circumstances, will cause our senior notes to become due upon the occurrence of a change of control as defined in the indenture. If a change of control occurs, we may not have the financial resources to repay this indebtedness and would be in default under the indenture. These provisions could also make it more difficult for a third party to acquire control of us, even if that change of control might benefit our stockholders.
OUR CERTIFICATE OF INCORPORATION CONTAINS PROVISIONS THAT COULD DISCOURAGE AN ACQUISITION OR CHANGE OF CONTROL OF OUR COMPANY.
Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. Provisions of our certificate of incorporation, such as the provision allowing our board of directors to issue preferred stock with rights more favorable than our common stock, could make it more difficult for a third party to acquire control of us, even if that change of control might benefit our stockholders.
OUR STOCKHOLDERS MAY EXPERIENCE SUBSTANTIAL DILUTION IN THE FUTURE
If the recapitalization proposal (see "Item 1 Business - Recent Developments") is not approved by our stockholders or, if approved is not able to be implemented by us, our stockholders may experience substantial dilution in the future upon the conversion of shares of our Series A and Series C preferred stock and the exercise of dilutive "reset" rights that we granted in connection with some prior issuances of our common stock.
Holders of our Series A preferred stock may convert each of their shares into one share of our common stock. There are 9,600,000 shares of common stock outstanding which are convertible into 9,600,000 shares of common stock.
Holders of our Series C preferred stock may convert their shares into shares of common stock at a conversion price based on the market price of our common stock. Since their issuance in December 1997 through August 17, 2000, 2,152 shares of Series C preferred stock have been repurchased by us and 6,075 shares have been converted into 10,538,754 shares of common stock. As of August 17, 2000, 2,173 shares of Series C preferred stock remain outstanding and would be convertible into 32,811,308 shares of common stock if all these shares were converted on that date at the conversion price of $0.075 per share prevailing as of that date.
Pursuant to two purchase agreements signed in July and November 1998, we issued an aggregate of 3,845,241 shares of common stock. As part of those issuances and in consideration for the original issuance price paid by the investors, we agreed to protect the holders against declines in the price of their common stock by granting them one
repricing right for every share issued. Each repricing right gives the holder a one-time right to require us to issue additional shares without the payment of additional consideration. Generally, subject to certain limitations, the number of additional shares that will be issued when repricing rights are exercised by the holder is determined by multiplying the number of reset rights being exercised times the "repricing rate." The repricing rate is determined by the following formula:
"repricing price" - market price -------------------------------- market price
The repricing price is determined by multiplying the original purchase price of the share -$7.00 per share in the case of the July 1998 transaction and $6.00 per share in the case of the November 1998 transaction- by a premium that rises to 128% over time. The repricing rights expire upon exercise. As long as the market price exceeds the repricing price, we are not required to issue any additional shares.
Since their issuance in 1998 through August 17, 2000, a total of 2,251,322 repricing rights have been exercised for an aggregate of 39,497,894 shares of common stock. As of August 17, 2000, 1,593,918 repricing rights remained outstanding and could have been exercised for 184,000,092 shares of common stock at the exercise price of $0.075 per share prevailing as of that date.
If the holders of Series A and Series C preferred stock had elected to convert all their remaining shares and the holders of the repricing rights elected to exercise all the outstanding repricing rights as of August 17, 2000 at the prices that were then in effect ($0.075 per share), we would have been required to issue an aggregate of 226,411,399 additional shares of common stock raising the total amount of common shares issued and outstanding to 307,099,937 which exceeds the 100,000,000 shares of common stock authorized by our certificate of incorporation. We would need to obtain stockholder approval to raise our authorized share capital before we could issue that number of additional shares of common stock.
In addition, our board of directors may issue shares of common stock and preferred stock in the future which may dilute our stockholders' ownership. We are authorized to issue 100,000,000 shares of common stock (80,688,538 shares were issued and outstanding at August 17, 2000). We are also authorized to issue 50,000,000 shares of preferred stock (9,602,173 shares of preferred stock were issued and outstanding at August 17, 2000).
FUTURE SALES OF OUR COMMON STOCK MAY ADVERSELY AFFECT THE MARKET PRICE
Future sales by stockholders could adversely affect the prevailing market price of our common stock. As of August 17, 2000, we had 80,688,538 shares of common stock outstanding. In addition,
o 9,600,000 shares of common stock are issuable upon conversion of our Series A preferred stock,
o 32,811,308 shares of common stock are issuable upon conversion of our Series C preferred stock (assuming a conversion price of $0.075 per share),
o 1,525,153 shares of common stock are issuable upon exercise of outstanding warrants,
o 763,500 shares of common stock are issuable upon exercise of outstanding stock options, and
o 184,000,092 shares would be issued upon exercise of the repricing rights (assuming a market price of $0.075 per share).
Of the issued and outstanding shares of our common stock, 63,945,919 are freely tradable without restriction or further registration under the Securities Act. The remaining issued and outstanding shares of common stock (16,742,619 shares) are "restricted shares" or shares held by our affiliates.
Some of our stockholders who hold "restricted securities" have previously been granted registration rights entitling them to demand, in certain circumstances, that we register the shares of common stock held by them for sale under the Securities Act. Sales of substantial amounts of common stock in the public market, pursuant to Rule 144 or otherwise, or the availability of such shares for sale, could adversely affect the prevailing market price of the common stock and impair our ability to raise additional capital through the sale of equity securities.
ITEM 2.
ITEM 2. DESCRIPTION OF PROPERTIES
GENERAL
We occupy approximately 8,360 square feet of office space at 13760 Noel Road, Suite 1030, Dallas, Texas, under a lease that expires in October, 2003. We also occupy approximately 2,000 square feet of space in Ottawa, Ontario for offices for certain of our executive officers located there under a lease that expires in August 2003. We lease property for a rig yard in New Mexico.
OTHER
For a description of our oil and natural gas properties, oil and gas reserves, acreage, wells, production and drilling activity, see "Item 1. Business."
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The landowner royalty on the J.C. Martin Field is currently the subject of a lawsuit that has created uncertainty regarding our title to our interest in the J.C. Martin Field. See "Item 1. Business - Risk Factors - Risks Related to Our Business - We may lose title to our royalty interest in the J.C. Martin field as a result of litigation over title to the royalty interest".
No other legal proceedings are pending other than ordinary routine litigation incidental to us, the outcome of which management believes will not have a material adverse effect on our financial condition or results of operations.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the last 3 months of the fiscal year ended June 30, 2000, no matter was submitted by us to a vote of our stockholders through the solicitation of proxies or otherwise.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE COMMON STOCK AND RELATED STOCKHOLDER MATTERS
MARKET INFORMATION
Our preferred stock is not publicly traded. Our common stock is currently quoted on the OTC Bulletin Board under the symbol "QSRI." Our common stock was quoted on the Nasdaq Small Cap Market under the symbol "QSRI" from May 1997 to November 10, 1999. On November 11, 1999, Nasdaq delisted our common stock for failing to meet the minimum net tangible asset base, the minimum market capitalization requirement and for failing to meet the minimum trading price thresholds. See "Item 1. Business - Risk Factors - Risks relating to our common stock - Our common stock was delisted from the Nasdaq Small Cap Market and as a result the price of the common stock may be depressed and you may have difficulties reselling the stock." The following table sets forth the high and low closing bid prices for our common stock as reported on Nasdaq and quoted on the OTC Bulletin Board for the periods indicated.
We have filed an application to designate our common stock on the Nasdaq National Market. However, we cannot assure you that we will be able to designate or list our common stock on the Nasdaq National Market or any other market or exchange, or, if we are able to designate or list our common stock, that we will be able to continue that designation or listing.
TRANSFER AGENT
The Transfer Agent for our common stock is Continental Stock Transfer & Trust Company, 2 Broadway, New York, New York 10004.
HOLDERS
The approximate number of record holders of our common stock as of August 17, 2000 was 1,400, inclusive of those brokerage firms and/or clearing houses holding our common stock for their clientele (with each such brokerage house and/or clearing house being considered as one holder).
CAPITAL STOCK ISSUANCES
During the three months ended June 30, 2000, pursuant to Section 3(a) (9) of the Securities Act of 1933, we issued 22,018,756 shares of common stock for no additional consideration to stockholders who exercised repricing rights included with the private placement of July 8 and November 10, 1998. The repricing rights were issued in connection with the July and November 1998 private placements and permit holders to acquire shares of common stock without the payment of additional consideration if the common stock does not achieve certain price thresholds in excess of the original issuance price of the shares purchased by the holders in July 1998.
Additionally, pursuant to Section 3(a) (9) of the Securities Act of 1933, the holders of Series C preferred stock converted 392 shares of Series C preferred stock into 2,954,808 shares of common stock. In conjunction with those conversions, we issued 364,991 shares of common stock in payment of stock dividends. The value of these stock dividends was $48,201.
DIVIDENDS
We have never declared or paid any dividends on our common stock. We currently intend to retain future earnings, if any, for the operation and development of our business and do not intend to pay any dividends on our common stock in the foreseeable future. Because Queen Sand Resources, Inc. is a holding company, our ability to pay dividends depends on the ability of our subsidiaries to pay cash dividends or make other cash distributions. Our credit agreement prohibits us from paying cash dividends on our common stock and the senior notes indenture restricts our payment of dividends on common stock. The terms of our Series A preferred stock and our Series C preferred stock prohibit cash dividends on our common stock unless all accrued and unpaid dividends on the preferred stock have been paid. Our board of directors has sole discretion over the declaration and payment of future dividends subject to Delaware corporate law. Any future dividends may also be restricted by any loan agreements which we may enter into from time to time and will depend on our profitability, financial condition, cash requirements, future prospects, general business conditions, the terms of our debt agreements and certificate of incorporation and other factors our board of directors believes relevant.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth for the periods indicated certain of our summary historical consolidated financial information. The summary historical consolidated financial information for each of the years in the five years ended June 30, 2000 have been derived from our audited consolidated financial statements. We completed material acquisitions of producing properties in some of the periods presented which affects the comparability of the historical financial and operating data for all periods presented. The summary historical information below should be read in conjunction with "Item 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
We are an independent energy company engaged in the exploration, development, exploitation and acquisition of oil and natural gas properties in on-shore, known producing areas, using conventional recovery techniques.
Our goal is to expand our reserve base, cash flow and net income and to generate an attractive return on capital. Our strategy to achieve these goals consists of these elements:
o develop, exploit and explore our existing oil and natural gas properties;
o identify acquisition opportunities that complement our existing properties; and
o utilize a well balanced financial structure that will allow us to direct the cash generated from operations to fund production and reserve growth without having to be overly reliant on the capital markets.
We use the full cost method of accounting for our investment in oil and natural gas properties. Under this method, we capitalize all acquisition, exploration and development costs incurred for the purpose of finding oil and natural gas reserves, including salaries, benefits and other related general and administrative costs directly attributable to these activities. We capitalized general and administrative costs of $0.7 million in the fiscal year ended June 30, 1998, $0.9 million in the fiscal year ended June 30, 1999 and $0.6 million in the fiscal year ended June 30, 2000. We expense costs associated with production and general corporate activities in the period incurred. We capitalize interest costs related to unproved properties and properties under development. Sales of oil and natural gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless these adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas.
The following table sets forth certain operating information for the periods presented. We acquired certain significant producing oil and natural gas producing properties during certain of the periods presented which affects the comparability of the data for the periods presented.
The following discussion of the results of operations and financial condition should be read in conjunction with our consolidated financial statements and related notes thereto included herein, and reflects the operating results as if the net profits interests were accounted for as working interests. We believe that this presentation will provide you with a more meaningful understanding of the underlying operating results and conditions for the period.
THE YEAR ENDED JUNE 30, 2000 COMPARED TO THE YEAR ENDED JUNE 30, 1999
RESULTS OF OPERATIONS
Revenues. Total revenues during the year ended June 30, 2000 were $32.6 million, a decrease of $1.2 million from the $33.8 million for the year ended June 30, 1999. Our revenues were derived from the sale of 10.6 Bcf of natural gas at an average price per Mcf of $2.59 and 224,000 barrels of oil at an average price per barrel of $22.76. During the year ended June 30, 1999 our revenues were derived from the sale of 13.0 Bcf of natural gas, at an average price per Mcf of $2.13, and 500,000 barrels of oil, at an average price per barrel of $12.37. Overall we produced 12.0 Bcfe at an average price of $2.72 per Mcfe during the year ended June 30, 2000 as compared to 16.0 Bcfe at an average price of
$2.12 per Mcfe during the year ended June 20, 1999. This represents a decrease of 4.0 Bcfe (25%) in production and an increase of $0.60 (28%) in the average price we received.
We produced 224,000 barrels of oil during the year ended June 30, 2000, a decrease of 276,000 barrels (55%) from the 500,000 barrels produced during the comparable period in 1999. The properties that we sold at the end of June 1999 represent 196,000 barrels (71%) of the total decrease of 276,000 barrels. Production from the properties that we owned during both periods decreased by 80,000 barrels. This represents a 26% decline from volumes produced during the year ended June 30, 1999. The decrease in production of oil from the properties owned during the comparative periods is comprised of three components:
o The Segno field has not been meeting production expectations. This under performance represents approximately 37% of the decrease in production from the properties that we owned during both periods. Remedial action is being taken to rehabilitate this field.
o During March 1999, we shut in substantially all of the wells in the Caprock Field in New Mexico in response to low oil prices. As oil prices recovered, we returned to production those wells that produce economically. In addition, we are in the early stages of a redevelopment program in the Caprock Field to enhance production. We have drilled four single lateral injection wells and one dual-lateral producing well. These five wells along with the production facilities and a water injection plant constitute phase one of the redevelopment program. Phase one covers 640 acres out of the approximate 20,000 acres we control in the Caprock Field.
o The final component of the production decline is the result of the natural depletion of our oil reservoirs.
We produced 10.6 Bcf of natural gas during the year ended June 30, 2000, down from the 13.0 Bcf produced during the comparable period in 1999. The properties that we sold at the end of June 1999 represent 1.0 Bcf (43%) of the total decrease of 2.3 Bcf. Production from the properties that we owned during both periods decreased by 1.3 Bcf. This represents an 11% decline from the volumes produced during the year ended June 30, 1999. The decrease in production from the properties owned during the comparative periods is comprised of three components:
o The Gilmer field has experienced production declines in excess of what was expected. The operator of the property has commenced drilling and completion efforts on the first two of a series of proposed infield wells to increase production.
o Our successful development and exploitation program in south Texas resumed in August 1999 and ten new wells have been drilled through the end of June 2000. These wells have high initial production rates and significant initial decline rates, with approximately half of total reserves being produced during the first year.
o The final component of the production decline is the result of the natural depletion of our natural gas reservoirs.
On a thousand cubic feet of gas equivalent ("Bcfe") basis, production for the year ended June 30, 2000 was 12 Bcfe, down 4.0 Bcfe (25%) from the 16.0 Bcfe produced during the comparable period in 1999. The properties that we sold at the end of June 1999 represent 2.2 Bcfe of the total decrease of 4.0 Bcfe. Production from the properties that we owned during both periods decreased by 1.8 Bcfe.
The decrease in revenues resulting from lower production volumes was offset by the significant industry-wide increase in oil and natural gas prices. The average price per barrel of oil sold by us during the year ended June 30, 2000 was $22.76, an increase of $10.39 per barrel (84%) over the $12.37 per barrel during the year ended June 30, 2000. The average price per Mcf of natural gas sold by us was $2.59 during the year ended June 30, 2000, an increase of $0.46 per Mcf (22%) over the $2.13 per Mcf during the comparable period in 1999. Oil prices have remained at these elevated levels subsequent to June 30, 2000. Natural gas prices were volatile throughout the year, and have remained so subsequent to June 30, 2000. On an Mcfe basis, the average price received by us during the year ended June 30, 2000 was $2.72, a $0.60 increase (28%) over the $2.12 we received during the comparable period in 1999.
During the year ended June 30, 2000 we paid $470,000 in cash settlements pursuant to our oil price-hedging program. The effect on the average oil prices we received during the period was a decrease of $2.10 per barrel (8%). During the year ended June 30, 2000 we paid $981,000 in cash settlements and amortized $98,000 of deferred hedging costs regarding our natural gas price-hedging program. The net negative effect on the average natural gas prices we
received during the period was $0.10 (4%). Payments made as a result of our oil price-hedging program during the year ended June 30, 1999 were insignificant. During the comparable period in 1999 we received $1.7 million in cash settlements and amortized $120,000 of deferred hedging costs regarding our natural gas price-hedging program. The net positive effect on the average natural gas prices we received during the period was $0.13 per Mcf (6%).
Costs and Expenses. Operating costs and expenses for the year ended June 30, 2000, exclusive of a $3.3 million hedge contract termination payment and the $1.1 million extraordinary loss from the write-down of deferred charges when we replaced our operating loans, were $37.4 million. Of this total, lease operating expenses and production taxes were $7.1 million, general and administrative expenses were $3.0 million, interest charges were $18.6 million and depletion, depreciation and amortization costs were $8.7 million. Operating costs and expenses for the year ended June 30, 1999, exclusive of a non-cash ceiling test write-down of $35.0 million and an extraordinary charge of $3.5 million, were $43.0 million. Of this total, lease operating expenses and production taxes were $9.1 million, general and administrative expenses were $3.5 million, interest charges were $18.4 million and depletion, depreciation and amortization costs were $11.9 million
Severance and production taxes, which are based on the revenues derived from the sale of oil and natural gas, were $1.43 million during the year ended June 30, 2000, as compared to $1.38 million during the comparable period in 1999, an increase of $55,000, or 4%. While revenues, after adjusting for commodity hedging contract settlements, decreased 3% during the comparable periods, wellhead revenues increased by 6%. Severance taxes are applied only to wellhead revenues. Our commodity hedge results were the primary cause for our severance and production taxes increasing, on a percentage basis, while overall revenues decreased.
On a cost per Mcfe basis, severance taxes were $0.12 per Mcfe for the year ended June 30, 2000 compared to $0.09 per Mcfe for the comparable period ending June 30, 1999, an increase of 39%. Average wellhead prices rose by 41%, from $2.02 per Mcfe during the year ended June 30, 1999 to $2.85 per Mcfe during the year ended June 30, 2000.
Our lease operating expenses fell to $5.7 million for the year ended June 30, 2000, a decrease of $2.1 million, or 27%, from the $7.8 million incurred during the comparable period in 1999. This decrease is primarily the result of reduced costs from comparable properties and the elimination of costs from the properties we sold at the end of June 1999. Lease operating expenses were $0.47 per Mcfe during the year ended June 30, 2000, a decrease of $0.02, or 3%, from the $0.49 per Mcfe incurred during the comparable period in 1999. This improvement is primarily the result of the sale of properties at the end of June 1999, which had higher operating costs per Mcfe than the properties we currently own.
General and administrative expenses were $3.0 million during the year ended June 30, 2000 compared to $3.5 million incurred during the year ended June 30, 1999. This decrease of $508,000 (14%) consists primarily of reduction in personnel costs and professional fees. On a per unit basis, general and administrative expenses for the year ended June 30, 2000 were $0.25 per Mcfe, an increase of $0.03 per Mcfe (14%) from the $0.22 per Mcfe incurred during the year ended June 30, 1999. This per unit increase in general and administrative expenses is a result of our decreased level of oil and natural gas production.
Interest expense for the year ended June 30, 2000 was $18.6 million. This was comprised of $17.0 million paid or payable in cash and $1.6 million of amortized deferred costs incurred at the time that the related debt obligations were incurred. During the year ended June 30, 1999 our interest expense was $18.3 million. This was comprised of $17.0 million paid or payable in cash and $1.3 million of amortized deferred debt issuance costs incurred at the time that the related debt obligations were established. The increase of $0.3 million in amortization of deferred debt issuance costs arose as a result of replacing our old credit agreement with our new credit agreement. We recorded an extraordinary loss of $1.1 million, in connection with the replacement of our old credit agreement, which loss represented the unamortized deferred costs incurred with respect to the old credit agreement.
On a per unit basis, cash interest expense for the year ended June 30, 2000 was $1.42 per Mcfe, as compared to $1.06 per Mcfe during the year ended June 30, 1999. This is the result of the 25% reduction in production we had during the year ended June 30, 2000, as compared to the year ended June 30, 1999.
The decrease in depletion, depreciation and amortization costs of $3.1 million was a result of the 25% decrease in the volume of oil and natural gas produced by us during the year ended June 30, 2000 as compared to the year ended June 30, 1999. On a cost per Mcfe of reserves the depletion, depreciation and amortization costs decreased by $0.03 per Mcfe (3%). This decrease is a function of:
o the $35 million non-cash write-down we recorded at December 31, 1998; and
o the reduced future capital expenditures required to develop the proved reserves.
Extraordinary Loss. In October 1999 we replaced our old credit agreement with our new credit agreement. As a result we wrote off $1.1 million in unamortized deferred debt issuance costs associated with the old credit agreement. In July 1998, we unwound a LIBOR interest rate swap contract at a cost of $3.5 million.
Net Loss. We have incurred losses since inception, including $9.1 million, or $0.21 per common share, for the year ended June 30, 2000 compared to $47.5 million, or $1.51 per common share for the year ended June 30, 1999. The decline in oil and natural gas prices between December 31, 1997 and December 31, 1998 caused us to record non-cash write-downs of oil and natural gas properties of $35 million and $28 million during the years ended June 30, 1999 and 1998 respectively. Future declines in oil and natural gas prices could lead to additional non-cash write-downs of our oil and natural gas properties.
THE YEAR ENDED JUNE 30, 1999 COMPARED TO THE YEAR ENDED JUNE 30, 1998
RESULTS OF OPERATIONS
Revenues. Total revenues during the year ended June 30, 1999 were $33.8 million, an increase of $21.1 million over the $12.7 million for the year ended June 30, 1998. Our revenues were derived from the sale of 13.0 Bcf of natural gas at an average price per Mcf of $2.13 and 500,000 barrels of oil at an average price per barrel of $12.37. During the year ended June 30, 1998 our revenues were derived from the sale of 3.4 Bcf of natural gas, at an average price per Mcf of $2.27, and 325,000 barrels of oil, at an average price per barrel of $15.52.
The two periods are not readily comparable because of our significant growth during the year ended June 30, 1998, primarily resulting from the April 1998 acquisition of the net profits interests. Production from properties owned throughout both periods was 1.0 Bcf of natural gas and 223,000 barrels of oil during the year ended June 30, 1999. This represents an increase of 0.1 Bcf (14%) over the 0.9 Bcf of natural gas, and an decrease of 26,000 barrels (11%) from the 250,000 barrels of oil produced during the year ended June 30, 1998. The increase in natural gas production is a reflection of our successful exploitation and development programs implemented during the year ended June 30, 1999, offset by the natural rate of depletion of the reservoirs associated with these properties. The decrease in oil production is a combination of the decision to temporarily reduce production from certain producing areas with relatively high production costs, due to the low price of oil received during the year combined with the natural rate of depletion of the reservoirs associated with these properties. The production of oil from those properties temporarily shut in during the period of low oil prices was restored after oil prices returned to their current higher levels. Production from properties acquired during 1998 was 11.9 Bcf of natural gas and 276,000 barrels of oil during 1999 as compared to 2.4 Bcf of natural gas and 75,000 barrels of oil during 1998.
Costs and Expenses. Operating costs and expenses for the year ended June 30, 1999, exclusive of a non-cash ceiling test write-down of $35.0 million and an extraordinary charge of $3.5 million, were $43.0 million. Of this total, lease operating expenses and production taxes were $9.1 million, general and administrative expenses were $3.5 million, interest charges were $18.3 million and depletion, depreciation and amortization costs were $11.9 million. Operating costs and expenses for the year ended June 30, 1998, exclusive of a non-cash ceiling test write-down of $28.2 million, were $17.4 million. Of this total, lease operating expenses and production taxes were $6.3 million, general and administrative costs were $2.3 million, interest charges were $4.0 million, and depletion, depreciation and amortization costs were $4.8 million.
The increase in lease operating expenses and production taxes is a result of our increased levels of oil and natural gas production. When lease operating expenses and production taxes are compared on a cost per unit basis, the cost of producing an Mcfe during the year ended June 30, 1999 decreased by $0.62 per Mcfe (52%) to $0.57 from the $1.19 per Mcfe achieved during the year ended June 30, 1998. This decrease in production costs per unit is primarily the result of the acquisition of properties in April 1998 having lower operating costs per unit than our other properties.
General and administrative expenses increased by $1.3 million as a result of our increased size requiring additional employees and other incremental costs; however, on a per unit basis, general and administrative expenses for the year ended June 30, 1999 were $0.22 per Mcfe, a decrease of $0.21 per Mcfe (49%) from the $0.43 per Mcfe incurred during the year ended June 30, 1998. This per unit decline in general and administrative expenses is a result of our increased level of oil and natural gas production.
Interest expense for the year ended June 30, 1999 was $18.3 million. This is comprised of $17.0 million paid or payable in cash and $1.3 million of amortized deferred costs incurred at the time that the related debt obligations were incurred. During the year ended June 30, 1998 total interest expense was $4.0 million, being comprised of $3.9 million paid or payable in cash and $0.1 million of amortized deferred costs incurred at the time that the related debt obligations were incurred. The increase of $14.3 million in interest expense is due to an increase in the average interest bearing debt outstanding. During the year ended June 30, 1999 we had average interest bearing debt outstanding of $139.3 million, as compared to $48.5 million during the year ended June 30, 1998. On a per unit basis, cash interest expense for the year ended June 30, 1999 was $1.06 per Mcfe, as compared to $0.75 per Mcfe during the year ended June 30, 1998.
The increase in depletion, depreciation and amortization costs of $7.1 million is a result of the increased volume of oil and natural gas produced by us and the higher per unit cost of acquisition of the properties acquired during the year ended June 30, 1998. On a cost per Mcfe of reserves the depletion, depreciation and amortization costs decreased by $0.17 per Mcfe (29%), primarily due to the effects of the non-cash writedowns of $35.0 million and $28.2 million recorded at December 31, 1998 and June 30, 1998 respectively, to reflect the impact of lower oil and natural gas prices at those two dates.
Extraordinary Loss. As a result of the placement of the $125 million of 12 1/2% senior notes in July 1998 we unwound an interest rate hedge contract related to existing floating interest rate bridge loans at a cost of $3,549,000. As the debt hedged was retired using the proceeds from the issuance of the senior notes, the costs of terminating the hedge were recognized as an extraordinary loss.
Net Loss. We have incurred losses since inception, including $47.5 million ($1.51 per common share) for the year ended June 30, 1999, compared to $32.8 million ($1.44 per share) for the year ended June 30, 1998. These losses are a reflection of the low oil and natural gas prices experienced during the year ended June 30, 1999 combined with our highly leveraged position.
LIQUIDITY AND CAPITAL RESOURCES
GENERAL
We have proposed a recapitalization plan that, if achieved, will significantly improve our highly leveraged position. See "Item 1. Business - Recent Developments". The key components of the proposed recapitalization plan are:
o a reverse stock split of one common share for every 156 shares of our common stock;
o the exchange or exercise of all preferred stock, all warrants exercisable for shares of common stock and all remaining unexercised common stock repricing rights for 732,500 shares of post reverse-split common stock;
o a common stock public offering or private placement of up to 10,000,000 shares of post-reverse split common stock which would yield net proceeds to us of approximately $74 million; and
o the repurchase of $75 million face value of our 12 1/2% senior notes for approximately $49 million.
The completion of the recapitalization is subject to the satisfaction of numerous conditions, including stockholder approval of the reverse stock split and the exchange of preferred stock and repricing rights for common stock, the tender by holders of at least $110 million principal amount of our senior notes pursuant to a cash tender offer and the successful sale of our common stock. As a result, we cannot assure you that we will be able to complete the recapitalization.
If we are able to complete the recapitalization, including the public offering or private placement of common stock that yields net proceeds to us of $74 million, our company will:
o obtain a discount on the repurchase of at least $75 million of our senior notes, thereby creating more than $25 million of additional equity value for our stockholders;
o reduce our debt by $93.5 million, thereby increasing annual cash flow available to fund growth by $10.9 million and reducing our interest cost per Mcfe by nearly 60%;
o reduce our long-term debt to $50 million, which approximates 23% of our June 30, 2000 SEC PV-10 of $217 million;
o eliminate all outstanding preferred stock;
o eliminate the dilutive effects of current market price conversion and repricing rights held by some of our stockholders;
o improve our liquidity by using a portion of the proceeds from this offering to pay down our senior working capital facility and modifying the indenture governing our senior notes to permit us to increase our senior working capital facility from $35 million to $60 million; and
o be in a position to satisfy the listing requirements of the Nasdaq National Market with a goal of improving the visibility and liquidity of our common stock.
We have filed a Registration Statement with the SEC contemplating the sale of up to 10,000,000 shares of our common stock (11,500,000 shares if the underwriters' over-allotment option is exercised in full) at a post-reverse split price between $7.00 and $9.00 per share. Depending on market conditions we may sell fewer shares than we currently contemplate. We can not assure you that we will successfully complete this equity offering. If we are able to complete the recapitalization, including a public offering or private placement that yields net proceeds to us of $50 million, our company will:
o obtain a discount on the repurchase of at least $75 million of our senior notes, thereby creating more than $25 million of additional equity value for our stockholders;
o reduce our debt by $75 million, thereby increasing annual cash flow available to fund growth by $9.8 million and reducing our interest cost per Mcfe by nearly 60%;
o reduce our long-term debt to $68.5 million, which approximates 32% of our June 30, 2000 SEC PV-10 of $217 million;
o eliminate all outstanding preferred stock;
o eliminate the dilutive effects of current market price conversion and repricing rights held by some of our stockholders;
o improve our liquidity by modifying the indenture governing our senior notes to permit us to increase our senior working capital facility from $35 million to $60 million; and
o be in a position to satisfy the listing requirements of the Nasdaq National Market with a goal of improving the visibility and liquidity of our common stock.
In the event that we are only able to raise $50 million, net of costs, we believe we will be able to fund our operations and planned activities from the funds derived from our operations and our existing credit agreement.
In the event that we are not successful in our attempts to raise equity then:
o we will not repurchase $75 million of our senior notes and not create any additional equity for our stockholders;
o we will not reduce our debt, increase our cash flow available to fund growth or reduce our interest cost per Mcfe;
o our long-term debt would remain at $143.5 million, which approximates 66% of our June 30, 2000 SEC PV-10 of $217 million;
o our preferred stock will remain outstanding;
o the dilutive effects of current market price conversion and repricing rights held by some of our stockholders will remain;
o the indenture governing our senior notes will not be modified to permit us to increase our senior working capital facility beyond $35 million; and
o we will not be in a position to satisfy the listing requirements of the Nasdaq National Market or the Nasdaq Small Cap and therefore not be able to achieve the goal of improving the visibility or liquidity of our common stock.
We believe we will continue to be able to fund our operations as planned for the year ended June 30, 2001. However, we may be required to reduce our capital spending plans in order to remain within the limitations of our credit agreement. As of August 17, 2000, under our credit agreement we:
o were permitted to borrow up to $30 million;
o had $14.5 million outstanding;
o had a further $6.2 million reserved to secure a letter of credit; and
o were permitted to borrow an additional $9.3 million under our credit agreement.
Consistent with our strategy of acquiring and developing reserves, we have an objective of maintaining as much financing flexibility as is practicable. Since we commenced our oil and natural gas operations, we have utilized a variety of sources of capital to fund our acquisitions and development and exploitation programs, and to fund our operations.
Our general financial strategy is to use cash flow from operations, debt financings and the issuance of equity securities to service interest on our indebtedness, to pay ongoing operating expenses, and to contribute toward the further development of our existing proved reserves as well as additional acquisitions. There can be no assurance that cash from operations will be sufficient in the future to cover all such purposes.
We have planned development and exploitation activities for all of our major operating areas. In addition, we are continuing to evaluate oil and natural gas properties for future acquisition. Historically, we have used the proceeds from the sale of our securities in the private equity market and borrowings under our credit facilities to raise cash to fund acquisitions or repay indebtedness incurred for acquisitions, and we have also used our securities as a medium of exchange for other companies assets in connection with acquisitions. However, there can be no assurance that such funds will be available to us to meet our budgeted capital spending. Furthermore, our ability to borrow other than under the credit agreement is subject to restrictions imposed by such credit agreement. If we cannot secure additional funds for our planned development and exploitation activities, then we will be required to delay or reduce substantially both of such activities.
SOURCES OF CAPITAL
On October 22, 1999 we entered into a new credit agreement with Ableco Finance LLC and Foothill Capital Corporation. The credit agreement, in which we provide a first secured lien on all of our assets, allows for borrowings of up to $50 million, subject to borrowing base limitations, from such lenders to fund, among other things, development and exploitation expenditures, acquisitions and general working capital. Our borrowing base is currently $30 million, of which $14.5 million is outstanding as of August 17, 2000. The credit agreement matures on October 22, 2001. There are no scheduled principal repayments. The credit agreement bears interest (11.5% as of August 17, 2000) as follows:
o when the borrowings are less than $25 million, bank prime plus 2%;
o when the borrowings are $25 million or greater, bank prime plus 4.5%;
o on amounts securing letters of credit issued on our behalf, 3%.
In addition, we have a letter of credit outstanding in the amount of $6.2 million, as of August 17, 2000, to an affiliate of Enron to secure a swap exposure.
We have filed a registration statement with the Securities and Exchange Commission contemplating the sale of up to 10,000,000 shares of our common stock (11,500,000 shares if the underwriters' over-allotment option is exercised in full) at a post-reverse split price between $7.00 and $9.00 per share. which would yield net proceeds to us of approximately $74 million Depending on market conditions we may sell fewer shares than we currently contemplate. We can not assure you that we will successfully complete this equity offering.
In the event that we are not successful in raising additional equity we believe that our cash flows and available sources of financing will be sufficient to satisfy the interest payments on our debt at currently prevailing interest rates and oil and natural gas prices. However, our level of debt may adversely affect our ability to:
o obtain additional financing for working capital, capital expenditures and other purposes, should we need to do so; or
o acquire additional oil and natural gas properties and to make acquisitions utilizing new borrowings.
Our natural gas price hedging program currently in place provides a degree of protection against significant decreases in oil and gas prices. Furthermore, 94% of our interest-bearing debt is at fixed rates for extended periods, providing an effective hedge against increases in prevailing interest rates.
We do not have sufficient liquidity or capital to undertake significant potential acquisition prospects. Therefore, we will continue to be dependent on raising substantial amounts of additional capital through any one or a combination of institutional or bank debt financing, equity offerings, debt offerings and internally generated cash flow, or by forming sharing arrangements with industry participants. Although we have been able to obtain such financings and to enter into such sharing arrangements in certain of our projects to date, there can be no assurance that we will continue to be able to do so. Alternatively, we may consider issuing additional securities in exchange for producing properties. There can be no assurance that any such financings or sharing arrangement can be obtained. Therefore, notwithstanding our need for substantial amounts of additional capital, there can be no assurance that it can be obtained.
Further acquisitions and development activities in addition to those for which we are contractually obligated are discretionary and depend to a significant degree on cash availability from outside sources such as bank debt and the sale of securities or properties.
USES OF CAPITAL
During the period since our inception in August 1994 through April 1998 our primary method of replacing our production and increasing our reserves was through acquisitions. Since that time our primary method of replacing production and enhancing our reserves was through the development and exploitation of our oil and natural gas properties. In either case, these activities require significant capital investments. While our earnings before non-cash charges have been positive since 1997, we have not been able to generate sufficient cash from this internal source to fund the replacement of our reserves consumed by production without relying on external sources of capital. We expect to spend $13.7 million on discretionary capital expenditures through June 2001 for exploitation, development and exploration projects, depending on the availability of funds. As of August 17, 2000 we are contractually obligated to fund $2.9 million in capital expenditures through June 2001.
If we are able to complete the recapitalization, including the public offering or private placement of common stock that yields net proceeds to us of $74 million, our company will:
o purchase at least $75 million of our senior notes;
o pay down our senior working capital facility; and
o use any remainder for working capital purposes.
If we are able to complete the recapitalization, including a public offering or private placement that yields net proceeds to us of only $50 million, our company will:
o purchase $75 million of our senior notes;
o will not pay down the amount outstanding under our credit agreement; and
o will not have additional working capital to fund our operations, planned capital expenditures and any acquisitions that we may chose to make.
If we are not able to complete the recapitalization as a result of not completing a successful public offering or private placement that yields net proceeds to us of at least $50 million, then our company will have to rely on funds generated from operations and funds available under our credit agreement, $9.3 million at August 17, 2000,
INFLATION
During the past several years, we have experienced some inflation in oil and natural gas prices with moderate increases in property acquisition and development costs. During the fiscal year ended June 30, 2000, we received higher commodity prices for the natural resources produced from our properties than we did during the year ended June 30, 1999. Our results of operations and cash flow have been, and will continue to be, affected to a certain extent by the volatility in oil and natural gas prices. Should we experience a significant increase in oil and natural gas prices that is sustained over a prolonged period, we could expect that there would also be a corresponding increase in oil and natural gas finding costs, lease acquisition costs, and operating expenses.
CHANGES IN PRICES AND HEDGING ACTIVITIES
Annual average oil and natural gas prices have fluctuated significantly over the last two years. The table below sets out our weighted average price per barrel of oil and the weighted average price per Mcf of natural gas, the impact of our hedging programs and the related NYMEX indices.
We have a commodity price risk management or hedging strategy that is designed to provide protection from low commodity prices while providing some opportunity to enjoy the benefits of higher commodity prices. We have a series of natural gas futures contracts with Bank of Montreal and with an affiliate of Enron. This strategy is designed to provide a degree of protection from negative shifts in natural gas prices as reported on the Henry Hub Nymex Index, on approximately 73% of our expected natural gas production from reserves currently classified as proved developed
producing during the fiscal year ending June 30, 2001. At the same time, we are able to participate completely in upward movements in the Henry Hub Nymex Index to the extent of approximately 76% of our expected natural gas production from reserves currently classified as proved developed producing for the fiscal year ending June 30, 2001.
The operator of a significant natural gas producing property in which we hold a net profits interest had placed a fixed price contract for the period January 1 through early October 1999. The prices for this contract, from a retrospective perspective when compared to Henry Hub prices, were favorable during the three months ended March 31, 1999 but became unfavorable for the following six months. The fixed prices under this contract reduced the average wellhead price we received during the year ended June 30, 2000 by approximately $0.06 per Mcf. This fixed price contract expired during October 1999.
We had a contract with an affiliate of Enron involving the hedging of a portion of our future natural gas production involving floor and ceiling prices as set out in the table below. We shared 50% of the price of NYMEX Henry Hub in excess of the ceiling price. This contract has expired. The volumes presented in this table are divided equally over the months during the period.
We had a contract with an affiliate of Enron involving the hedging of a portion of our future oil production involving floor and ceiling prices as set out in the table below. We shared 50% of the price of NYMEX Henry Hub in excess of the ceiling price. This contract has expired. The volumes presented in this table are divided equally over the months during the period.
Effective May 1, 1998 through October 31, 1999 we had a contract with Bank of Montreal involving the hedging of a portion of our future natural gas production involving floor and ceiling prices as set out in the table below. The volumes presented in this table are divided equally over the months during the period.
Effective November 1, 1999 we unwound the ceiling price limitation on our natural gas price hedging contract with Bank of Montreal at a cost of $3.3 million. The table below sets out the volume of natural gas that remains under contract with the Bank of Montreal at a floor price of $2.00 per MMBtu. The volumes set out in this table are divided equally over the months during the period:
The table below sets out volume of natural gas hedged with a floor price of $1.90 per MMBtu with Enron. The volumes presented in this table are divided equally over the months during the period:
The table below sets out volume of natural gas hedged with a swap at $2.40 per MMBtu with Enron. The volumes presented in this table are divided equally over the months during the period:
The table below sets out volume of oil hedged with a swap with Enron. All of these contracts have expired. The volumes presented in this table are divided equally over the months during the period:
The table below sets out the volume of oil hedged with a contract with Enron involving floor and ceiling prices as set out in the table below. The volumes presented in this table are divided equally over the months during the period.
INTEREST RATE HEDGING
We entered into a forward LIBOR interest rate swap effective for the period June 30, 1998 through June 29, 2009 at a rate of 6.30% on $125.0 million. We entered into this interest rate swap at a time when interest rates were rising. Our objective was to mitigate the risk of our having to pay higher than expected interest rates on what eventually became our 12 1/2% senior notes due 2008. The swap would have also served as an interest hedge on our indebtedness under the credit agreement and certain short term loans used to finance the April 1998 acquisition of our net profit and royalty interests in the event that we failed to complete the private placement of the unsecured notes. Once the private placement of the 12 1/2% senior notes was completed we determined that the interest rate swap no longer had any on-going value to us. On July 9, 1998, we unwound this swap at a cost to us of approximately $3.5 million, using a portion of the proceeds from the senior notes. This cost was expensed as an extraordinary loss during the year ended June 30, 1999.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
HEDGES OF OIL AND NATURAL GAS PRODUCTION
To reduce our exposure to changes in the prices of oil and natural gas, we have entered into and may in the future enter into arrangements to hedge our oil and natural gas production, whereby gains and losses in the fair value of the derivative instruments are generally offset by price changes in the underlying commodity. The hedges that we have entered into generally provide a 'floor' or 'cap and floor' on the prices paid for our oil and natural gas production over a period of time. Hedging arrangements may expose us to the risk of financial loss in some circumstances, including the following:
o our production does not meet the minimum production requirements under the agreement;
o the other party to the hedging contract defaults on its contract obligations; or
o there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.
Due to our risk assessment procedures and internal controls, we believe that the use of such derivative instruments does not expose us to material risk, however, the use of derivative instruments for the hedging activities could affect our results of operations in particular quarterly or annual periods. The use of such instruments limits the downside risk of adverse price movements, but it may also limit our ability to benefit from favorable price movements.
Our hedging strategy is designed to provide protection from low commodity prices while providing some opportunity to enjoy the benefits of higher commodity prices. We have a series of natural gas futures contracts with Bank of Montreal and with an affiliate of Enron. This strategy is designed to provide a degree of protection of negative shifts in natural gas prices as reported on the Henry Hub Nymex Index on approximately 73% of our expected natural gas production from reserves currently classified as proved developed producing during the fiscal year ending June 30, 2001. At the same time, we are able to participate completely in upward movements in the Henry Hub Nymex Index to the extent of approximately 76% of our expected natural gas production for the fiscal year ending June 30, 2001.
In addition to our natural gas hedging agreements, at June 30, 2000, we have a contract on 5,000 barrels of oil per month involving floor and ceiling prices of $22.00 and $28.63 per barrel, respectively, from July 1 through December 31, 2000.
As of June 30, 2000 the fair value of our hedging contracts, measured as the estimated cost we would incur to terminate the arrangements, was $5.3 million. As of June 30, 2000 a 10% increase in oil and natural gas prices would have resulted in an unfavorable change of $2.0 million in the fair value of our hedging contracts and a 10% decrease in oil and natural gas prices would have resulted in a favorable change of $2.1 million in the fair value of our hedging contracts.
INTEREST RATES
At June 30, 2000, our exposure to interest rates relates primarily to borrowings under our credit agreement. As of June 30, 2000, we are not using any derivatives to manage interest rate risk. Interest is payable on borrowings under the credit agreement based on a floating rate. If short-term interest rates average 10% higher during our fiscal year 2001 than they were during 2000, our interest expense would increase by approximately $213,000. This amount was determined by applying the hypothetical interest rate change of 10% to our outstanding borrowings under the credit agreement at June 30, 2000.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
For the Financial Statements required by Item 8, see the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
There are no changes or disagreements required to be reported under this Item 9.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item will be set forth under the captions "Election of Directors," "Section 16(a) Beneficial Ownership Reporting Compliance," and "Executive Officers" of our proxy statement for our 2000 Annual Meeting of Stockholders (the "Proxy Statement") which will be filed with the Commission pursuant to Regulation 14A under the Exchange Act and is incorporated herein by reference. The Proxy Statement is expected to be filed on or prior to October 28, 1999.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is set forth under the caption "Executive Compensation" of our Proxy Statement, which will be filed with the Commission pursuant to Regulation 14A under the Exchange Act and is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is set forth under the caption "Security Ownership of Certain Beneficial Owners and Management" of our Proxy Statement which will be filed with the Commission pursuant to Regulation 14A under the Exchange Act and is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is set forth under the captions "Executive Compensation", " Director Compensation" and "Certain Relationships and Related Party Transactions" of our Proxy Statement which will be filed with the Commission pursuant to Regulation 14A under the Exchange Act and is incorporated herein by reference.
GLOSSARY
The terms defined in this glossary are used throughout this Annual Report on Form 10-K.
average NYMEX price. The average of the NYMEX closing prices for the near month.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to oil or other liquid hydrocarbons.
Bbl/d. Bbl per day.
Bcf. One billion cubic feet of natural gas.
Bcfe. One billion cubic feet of natural gas equivalents, converting one Bbl of oil to six Mcf of natural gas.
behind-the-pipe. Hydrocarbons in a potentially producing horizon penetrated by a well bore the production of which has been postponed pending the production of hydrocarbons from another formation penetrated by the well bore. The hydrocarbons are classified as proved but non-producing reserves.
BOE. Barrels of oil equivalent (converting six Mcf of natural gas to one Bbl of oil).
BOPD. Barrels of oil per day.
development well. A well drilled within the proved boundaries of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
dry well. A development or exploratory 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.
exploratory well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.
gross acres or gross wells. The total number of acres or wells, as the case may be, in which a working interest is owned.
LOE. Lease operating expenses are those expenses directly associated with oil and/or natural gas producing or service wells.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent, converting six Mcf of natural gas to one Bbl of oil.
Mcf. One thousand cubic feet of natural gas.
Mcf/d. Mcf per day.
Mcfe. One thousand cubic feet of natural gas equivalents, converting one Bbl of oil to six Mcf of gas.
MMBbl. One million barrels of oil or other liquid hydrocarbons.
MMBOE. One million barrels of oil equivalent.
MMcfe. One million cubic feet of natural gas equivalents, converting one Bbl of oil to six Mcf of gas.
MMcf. One million cubic feet of natural gas.
net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells.
net profits interest. A share of the gross oil and natural gas production from a property, measured by net profits from the operation of the property that is carved out of the working interest. This is a non-operated interest.
NYMEX. New York Mercantile Exchange.
producing well, production well, or productive well. A well that is producing oil or natural gas or that is capable of production.
proved developed producing or PDP. Proved developed producing reserves are proved developed reserves which are currently capable of producing in commercial quantities.
proved developed reserves. Proved developed reserves are oil and natural gas reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as 'proved developed reserves' only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
proved reserves. Proved reserves are the estimated quantities of 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 undeveloped reserves or PUD. Proved undeveloped reserves are oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery techniques is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
Reserve Life Index. The estimated productive life of a proved reservoir based upon the economic limit of such reservoir producing hydrocarbons in paying quantities assuming certain price and cost parameters. For purposes of this Annual Report on Form 10-K, reserve life is calculated by dividing the proved reserves (on a Mcfe basis) at the end of the period by production volumes for the previous 12 months.
royalty interest. An interest in an oil and natural gas property entitling the owner to a share of oil and natural gas production free of costs of production.
SEC PV-10. The present value of proved reserves is an estimate of the discounted future net cash flows from each of the properties at June 30, 2000, or as otherwise indicated. Net cash flow is defined as net revenues less, after deducting production and ad valorem taxes, future capital costs and operating expenses, but before deducting federal income taxes. As required by rules of the Commission, the future net cash flows have been discounted at an annual rate of 10% to determine their 'present value.' The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. In accordance with Commission rules, estimates have been made using constant oil and natural gas prices and operating costs, at June 30, 2000, or as otherwise indicated.
secondary recovery. A method of oil and natural gas extraction in which energy sources extrinsic to the reservoir are utilized.
service well. A well used for water injection in secondary recovery projects or for the disposal of produced water.
Standardized Measure. Under the Standardized Measure, future cash flows are estimated by applying year-end prices, adjusted for fixed and determinable escalations, to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pretax cash inflows. Future income taxes are computed by applying the statutory tax rate to the excess of pretax cash inflows over the Company's tax basis in the associated properties. Tax credits, net operating loss carryforwards, and permanent differences are also considered in the future tax calculation. Future net cash inflows after income taxes are discounted using a 10% annual discount rate to arrive at the Standardized Measure.
undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
working interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration to, development and operations and all risks in connection therewith.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) (1) FINANCIAL STATEMENTS
See Index to Consolidated Financial Statements following the signature page to this annual report on Form 10-K.
(a) (2) FINANCIAL STATEMENT SCHEDULES
All Schedules are omitted because the information is not required under the related instructions or is inapplicable or because the information is included in the Consolidated Financial Statements or related notes.
(3) EXHIBITS
3.1 Restated Certificate of Incorporation of the Company, filed as Exhibit 4.5 to the Company's Registration Statement on Form S-3 (No. 333-47577) filed with the Securities and Exchange Commission on March 9, 1998, which Exhibit is incorporated herein by reference.
3.2 Certificate of Designation of Series C Convertible Preferred Stock of the Company, filed as an Exhibit to the Company's Current Report on Form 8-K dated December 24, 1997, which Exhibit is incorporated herein by reference.
3.3 Amended and Restated Bylaws of the Company, filed as an Exhibit to the Company's Current Report on Form 8-K dated March 27, 1997, which Exhibit is incorporated herein by reference.
4.1 Stockholders' Agreement dated as of May 6, 1997, among the Company, Bruce I. Benn, Edward J. Munden, Ronald I. Benn, Robert P. Lindsay, EIBOC Investments Ltd. and Joint Energy Development Investments Limited Partnership ("JEDI"), filed as an Exhibit to the Company's Current Report on Form 8-K dated May 6, 1997, which Exhibit is incorporated herein by reference.
4.2 Indenture, dated July 1, 1998, in regard to 12 1/2% Senior Notes due 2008 by and among the Company and certain of its subsidiaries and Harris Trust and Savings Bank, as Trustee, filed as an Exhibit to the Company's Current Report on Form 8-K dated July 8, 1998, which Exhibit is incorporated herein by reference.
4.3 Form of 12% Notes due July 15, 2001, filed as an Exhibit to the Company's Registration Statement on Form 10-SB filed with the Securities and Exchange Commission on August 12, 1996, which Exhibit is incorporated herein by reference.
4.4 Form of Common Stock Purchase Warrant dated December 24, 1997 and issued to certain institutional investors, filed as an Exhibit to the Company's Current Report on Form 8-K dated December 24, 1997, which Exhibit is incorporated herein by reference.
4.5 Form of Common Stock Purchase Warrant issued to certain investors effective July 8, 1998, filed as an Exhibit to the Company's Current Report on Form 8-K dated July 8, 1998, which Exhibit is incorporated herein by reference.
4.6 Registration Rights Agreement among the Company and certain institutional investors named therein, dated December 24, 1997, filed as an Exhibit to the Company's Current Report on Form 8-K dated December 24, 1997, which Exhibit is incorporated herein by reference.
4.7 Registration Rights Agreement by and between the Company and JEDI dated May 6, 1997, filed as an Exhibit to the Company's Current Report on Form 8-K dated May 6, 1997, which Exhibit is incorporated herein by reference.
4.8 Registration Rights Agreement dated as of July 8, 1998 among the Company and the buyers signatory thereto, filed as an Exhibit to the Company's Current Report on Form 8-K dated July 8, 1998, which Exhibit is incorporated herein by reference.
4.9 Registration Rights Agreement dated November 10, 1998 among Queen Sand Resources, Inc. and the buyers signatory thereto, filed as an Exhibit to the Company's Current Report on Form 8-K dated November 24, 1998, which Exhibit is incorporated herein by reference.
4.10 Form of Common Stock Purchase Warrant issued to certain investors as of November 10, 1998, filed as an Exhibit to the Company's Current Report on Form 8-K dated November 24, 1998, which Exhibit is incorporated herein by reference.
4.11 Form of Common Stock Purchase Warrant issued to Northern Tier Asset Management, Inc. issued by the Company on April 9, 1999 and filed as an exhibit to the Company's Registration Statement on form S-3 (No. 333-78001) which Exhibit is incorporated by reference.
4.12 Registration Rights Agreement dated as of April 9, 1999 between the Company and Northern Tier Asset Management, Inc. and filed as an exhibit to the Company's Registration Statement on form S-3 (No. 333-78001) which Exhibit is incorporated by reference.
4.13 Settlement Agreement dated as of July 17, 2000 between the Company and the stockholders named therein, filed as an Exhibit to the Company's Registration Statement on Form S-2 (No. 333-41992), which Exhibit is incorporated herein by reference.
4.14 Participation Agreement dated as of July 17, 2000 between the Company and the holders of its 12 1/2% senior notes therein filed as an Exhibit to the Company's Registration Statement on Form S-2 (No. 333-41992) which Exhibit is incorporated herein by reference.
10.1 Purchase and Sale Agreement between Eli Rebich and Southern Exploration Company, a Texas corporation, and Queen Sand Resources, Inc., a Nevada corporation, dated April 10, 1996, filed as an Exhibit to the Company's Registration Statement on Form 10-SB filed with the Securities and Exchange Commission on August 12, 1996, which Exhibit is incorporated herein by reference.
10.2 Purchase and Sale Agreement dated March 19, 1998 among the Morgan commingled pension funds and Queen Sand Resources, Inc., a Nevada corporation, filed as an Exhibit to the Company's Current Report on Form 8-K dated March 19, 1998, which Exhibit is incorporated herein by reference.
10.3 Securities Purchase Agreement dated as of March 27, 1997 between JEDI and the Company, filed as an Exhibit to the Company's Current Report on Form 8-K dated March 27, 1997, which Exhibit is incorporated herein by reference.
10.4 Securities Purchase Agreement among the Company and certain institutional investors named therein, dated December 22, 1997, filed as an Exhibit to the Company's Current Report on Form 8-K dated December 24, 1997, which Exhibit is incorporated herein by reference.
10.5 Queen Sand Resources 1997 Incentive Equity Plan, filed as an Exhibit to the Company's Registration Statement on Form S-4 filed with the Securities and Exchange Commission on August 13, 1998, which Exhibit is incorporated herein by reference.
10.6 Employment Agreement dated December 15, 1997 between the Company and Robert P. Lindsay, filed as an Exhibit to the Company's Registration Statement on Form S-4 filed with the Securities and Exchange Commission on August 13, 1998 (No. 333-61403) which Exhibit is incorporated herein by reference.
10.7 Employment Agreement dated December 15, 1997 among the Company, Queen Sand Resources (Canada) Inc. and Bruce I. Benn, filed as an Exhibit to the Company's Registration Statement on Form S-4 filed with the Securities and Exchange Commission on August 13, 1998 (No. 333-61403) which Exhibit is incorporated herein by reference.
10.8 Employment Agreement dated December 15, 1997 among the Company, Queen Sand Resources (Canada) Inc. and Ronald Benn, filed as an Exhibit to the Company's Registration Statement on Form S-4 filed with the Securities and Exchange Commission on August 13, 1998 (No. 333-61403) which Exhibit is incorporated herein by reference.
10.9 Employment Agreement dated December 15, 1997 among the Company, Queen Sand Resources (Canada) Inc. and Edward J. Munden, filed as an Exhibit to the Company's Registration Statement on Form S-4 filed with the Securities and Exchange Commission on August 13, 1998 (No. 333-61403) which Exhibit is incorporated herein by reference.
10.10 Directors' Non-Qualified Stock Option Plan filed as Appendix A to the Company's Definitive Proxy Statement on Schedule 14A dated October 23, 1998, which Exhibit is incorporated herein by reference.
10.11 Amended and Restated Securities Purchase Agreement dated as of July 8, 1998 among the Company and the buyers signatory thereto, filed as an Exhibit to the Company's Current Report on Form 8-K dated July 8, 1998, as amended by the Current Report on Form 8-K/A-1 dated July 8, 1998, which Exhibit is incorporated herein by reference.
10.12 Securities Purchase Agreement dated as of November 10, 1998 among the Company and the buyers signatory thereto, filed as an Exhibit to the Company's Current Report on Form 8-K dated November 24, 1998.
10.13 Amended and Restated Credit Agreement among the Company, Queen Sand Resources, Inc., a Nevada corporation, Ableco Finance LLC, as Collateral Agent, and the lenders signatory thereto, effective as of October 22, 1999, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999.
10.14 Second Amended And Restated Guaranty Agreement dated as of October 22, 1999 by Queen Sand Resources, Inc. as Guarantor in favor of Ableco Finance LLC, as Collateral Agent for the lender group and the lenders signatory thereto, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999.
10.15 Second Amended And Restated Guaranty Agreement dated as of October 22, 1999 by Queen Sand Operating Co., as Guarantor, in favor of Ableco Finance LLC, as Collateral Agent for the lender group, and the lenders signatory thereto, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999.
10.16 Second Amended And Restated Guaranty Agreement dated as of October 22, 1999 by Corrida Resources, Inc. as Guarantor, in favor of Ableco Finance LLC, as Collateral Agent for the lender group, and the lenders signatory thereto, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999.
10.17 Security Agreement dated as of October 22, 1999, by and among the Company, Queen Sand Resources, Inc. (Nevada), Queen Sand Operating Co., Corrida Resources, Inc. and Ableco Finance LLC, as collateral agent for the lender group, and the lenders signatory thereto, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999.
10.18 Second Amended and Restated Pledge and Security Agreement dated as of October 22, 1999, by Queen Sand Resources, Inc., a Nevada corporation in favor of Ableco Finance LLC, as Collateral Agent for the lender group, and the lenders signatory thereto, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999.
10.19 Second Amended and Restated Pledge and Security Agreement dated as of October 22, 1999, by Queen Sand Resources, Inc., a Delaware corporation, in favor of Ableco Finance LLC, as Collateral Agent for the lender group, and the lenders signatory thereto, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999.
10.20 Amendment No. 1 to Credit Agreement dated May 2000 among the Company, Queen Sand Resources, Inc., a Nevada corporation, Ableco Finance LLC, as Collateral Agent, and the lenders signatory thereto, filed as an Exhibit to the Company's Registration Statement on Form S-2 (No. 333-41992), which Exhibit is incorporated by reference.
10.21 Amendment No. 2 to Credit Agreement dated June 30, 2000 among the Company, Queen Sand Resources, Inc., a Nevada corporation, Ableco Finance LLC, as Collateral Agent, and the lenders signatory thereto, filed as an Exhibit to the Company's Registration Statement on Form S-2 (No. 333-41992), which Exhibit is incorporated by reference.
21.1 List of the subsidiaries of the registrant filed as an Exhibit to the Company's Registration Statement on Form S-4 filed with the Securities and Exchange Commission on August 13, 1999 (No. 333-61403) which Exhibit is incorporated by reference.
23.1* Consent of Ernst & Young LLP.
23.2* Consent of Ryder Scott Company.
23.3* Consent of H.J. Gruy and Associates, Inc.
27* Financial Data Schedule
- ----------
* Filed herewith.
(4) REPORTS ON FORM 8-K
None.
(b) II Financial Statement Schedule and Auditors' Report on Schedule:
No other financial statement schedules are filed as part of this Form 10-K since the required information is included in the financial statements, including the notes thereto, or circumstances requiring the inclusion of such schedules are not present.
SIGNATURE PAGE
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 ON THE 25TH OF AUGUST, 2000.
QUEEN SAND RESOURCES, INC.
By: /s/ EDWARD J. MUNDEN ---------------------- Name: Edward J. Munden Title: Chief Executive Officer, President and Chairman of the Board
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT IN THE CAPACITIES AND ON THE DATES INDICATED.
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF ERNST & YOUNG LLP, INDEPENDENT AUDITORS
The Board of Directors and Stockholders Queen Sand Resources, Inc.
We have audited the accompanying consolidated balance sheets of Queen Sand Resources, Inc. and subsidiaries as of June 30, 2000 and 1999, and the related consolidated statements of operations, stockholders' equity (net capital deficiency), and cash flows for each of the three years in the 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 audit.
We conducted our audits in accordance with auditing standards generally accepted in the United States. 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 Queen Sand Resources, Inc. and subsidiaries as of June 30, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2000, in conformity with accounting principles generally accepted in the United States.
Dallas, Texas August 18, 2000
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
See accompanying notes.
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
See accompanying notes.
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (NET CAPITAL DEFICIENCY)
YEARS ENDED JUNE 30, 2000, 1999, AND 1998
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (NET CAPITAL DEFICIENCY) (CONTINUED)
YEARS ENDED JUNE 30, 2000, 1999, AND 1998
See accompanying notes.
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes.
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000, 1999, AND 1998
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
GENERAL
Queen Sand Resources, Inc. (QSRI or the Company) was formed on August 9, 1994, under the laws of the State of Delaware. At June 30, 2000, EIBOC Investments Ltd. (EIBOC) held approximately 6,600,000 shares of the Company's common stock, par value $.0015 per share (Common Stock), representing approximately 7% of the Company's outstanding shares of Common Stock on a fully diluted basis. Certain officers of the Company have beneficial interests in EIBOC (see Note 5). Joint Energy Development Investments Limited Partnership (JEDI), an affiliate of Enron Corp. (Enron), holds approximately 13% of the Company's voting capital stock on a fully diluted basis.
The Company is engaged in one industry segment: the acquisition, exploration, development, production, and sale of crude oil and natural gas. The Company's business activities are carried out primarily in Kentucky, Louisiana, New Mexico, Oklahoma, and Texas.
The Company is highly leveraged. At June 30, 2000, the Company's ratio of total indebtedness to total capitalization was 132%. The Company's revenues, profitability, and ability to repay its indebtedness and related interest charges are highly dependent upon prevailing prices for oil and natural gas. As the Company produces more natural gas than oil, it faces more risk related to fluctuations in natural gas prices than oil prices. To reduce the exposure to changes in the prices of oil and natural gas, the Company has entered into certain hedging arrangements (see Note 4). However, a sustained period of depressed oil and natural gas prices could have a material adverse effect on the Company's results of operations and financial condition.
The Company has proposed a recapitalization of the Company, which would include:
(i) A reverse stock split of one common share for every 156 shares of common stock outstanding
(ii) The exchange of all outstanding convertible preferred stock and warrants and repricing rights exercisable for shares of the Company's common stock for 732,500 shares of post reverse split common stock (see Note 5)
(iii) The repurchase of $75 million face value of the Company's 12 1/2% Senior Notes for approximately $49 million with a portion of the net proceeds from a public offering of common stock
There can be no assurance that the Company will be able to successfully complete the proposed recapitalization or the proposed public offering.
PRINCIPLES OF CONSOLIDATION
The accompanying consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
PROPERTY AND EQUIPMENT
The Company follows the full cost method of accounting for its oil and gas activities under which all costs, including general and administrative expenses directly associated with property acquisition, exploration, and development activities, are capitalized. Capitalized general and administrative expenses directly associated with acquisitions, exploration, and development of oil and gas properties were approximately $706,000, $931,000, and $721,000 for the years ended June 30, 2000, 1999, and 1998, respectively. Capitalized costs are amortized by the unit-of-production method using estimates of proved oil and gas reserves prepared by independent engineers. The costs of unproved properties are excluded from amortization until the properties are evaluated. Sales of oil and gas properties are accounted for as adjustments to the capitalized cost center unless such sales significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center, in which case a gain or loss is recognized.
The Company limits the capitalized costs of oil and gas properties, net of accumulated amortization, to the estimated future net revenues from proved oil and gas reserves less estimated future development and production expenditures discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, as adjusted for related estimated future tax effects. If capitalized costs exceed this limit (the full cost ceiling), the excess is charged to depreciation and amortization expense. During the years ended June 30, 1999 and 1998, the Company recorded full cost ceiling write-downs of $35,033,000 and $28,166,000, respectively.
Amortization of the capitalized costs of oil and gas properties and limits to capitalized costs are based on estimates of oil and gas reserves which are inherently imprecise and are subject to change based on factors such as crude oil and natural gas prices, drilling results, and the results of production activities, among others. Accordingly, it is reasonably possible that such estimates could differ materially in the near term from amounts currently estimated.
Depreciation of other property and equipment is provided principally by the straight-line method over the estimated service lives of the related assets. Equipment under capital lease is recorded at the lower of fair value or the present value of future minimum lease payments and are depreciated over the lease term.
Costs incurred to operate, repair, and maintain wells and equipment are charged to expense as incurred.
Certain of the Company's oil and gas activities are conducted jointly with others and, accordingly, the financial statements reflect only the Company's proportionate interest in such activities.
The Company does not expect future costs for site restoration, dismantlement and abandonment, postclosure, and other exit costs which may occur in the sale, disposal, or abandonment of a property to be material.
REVENUE RECOGNITION
The Company uses the sales method of accounting for oil and gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and gas sold to purchasers.
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
ENVIRONMENTAL MATTERS
The Company is subject to extensive federal, state, and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.
INCOME TAXES
Income taxes are accounted for under the asset and liability method, under which 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 tax rates. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred tax assets is adjusted by a valuation allowance, if necessary, to recognize the extent to which, based on available evidence, the future tax benefits more likely than not will be realized.
STATEMENT OF CASH FLOWS
The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
During 1999 and 1998, the Company issued an aggregate of 8,740 and 1,337,500 shares of Common Stock, respectively, valued at $65,000 and $4,812,000, respectively, in connection with the acquisitions of certain interests in oil and gas properties. During 1998, in connection with certain promotional services rendered by an unrelated party, the Company issued 150,000 shares of Common Stock valued at $300,000.
NET LOSS PER COMMON SHARE
Net loss per common share is presented in accordance with Statement of Financial Accounting Standards No. 128, Earnings Per Share, which requires companies to present basic earnings per share calculated based on the weighted average number of common shares outstanding during the period, and, if applicable, diluted earnings per share which is calculated based on the weighted average number of common shares outstanding during the period plus any dilutive common equivalent shares outstanding. As the Company incurred net losses during each of the years ended June 30, 2000, 1999, and 1998, the loss per common share data is based on the weighted average common shares outstanding and excludes the effects of the Company's potentially dilutive securities (see Note 5).
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
STOCK COMPENSATION
The Company has elected to follow Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (APB 25), in accounting for its employee stock options. Under APB 25, if the exercise price of an employee's stock options equals or exceeds the market price of the underlying stock on the date of grant and certain other plan conditions are met, no compensation expense is recognized.
CONCENTRATIONS OF CREDIT RISK
The Company sells crude oil and natural gas to various customers. In addition, the Company participates with other parties in the operation of crude oil and natural gas wells. Substantially all of the Company's accounts receivable are due from either purchasers of crude oil and natural gas or participants in crude oil and natural gas wells for which the Company serves as the operator. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells. The Company's receivables are generally unsecured.
For the year ended June 30, 2000, four oil and gas companies accounted for 28%, 16%, 12%, and 10%, respectively, of the Company's oil and gas sales. For the year ended June 30, 1999, four oil and gas companies accounted for 30%, 12%, 11%, and 9%, respectively, of the Company's oil and gas sales. For the year ended June 30, 1998, two oil and gas companies accounted for 17% and 13%, respectively, of the Company's oil and gas sales. The Company does not believe that the loss of any of these buyers would have a material effect on the Company's business or results of operations as it believes it could readily locate other buyers.
USE OF 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 revenue and expenses during the reporting period. Because of the use of estimates inherent in the financial reporting process, actual results could differ from those estimates.
COMPREHENSIVE INCOME
Comprehensive income is defined as the change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. For the years ended June 30, 2000, 1999, and 1998, there were no differences between the Company's net losses and total comprehensive income.
DERIVATIVES
The Company utilizes certain derivative financial instruments to hedge future oil and gas prices and interest rate risk (see Note 4). Gains and losses arising from the use of the instruments are deferred until realized. Gains and losses from ongoing settlements of hedges of oil and gas prices are reported as oil and gas sales. Gains and losses from ongoing settlements of interest rate hedges are reported in interest expense.
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, which will be adopted by the Company effective July 1, 2000. The Statement will require the Company to recognize all derivatives on the balance sheet at fair value. Derivatives that are not hedges must be adjusted to fair value through income. If the derivative is a hedge, depending on the nature of the hedge, changes in the fair value of derivatives will either be offset against the change in fair value of the hedged assets, liabilities, or firm commitments through earnings or recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of a derivative's change in fair value will be immediately recognized in earnings. Based on the Company's derivative positions at June 30, 2000, the Company estimates that, upon adoption, it will report a gain from the cumulative effect of adoption of approximately $413,000, and a reduction in other comprehensive income of $5,907,000.
2. ACQUISITIONS
On April 20, 1998, the Company acquired certain nonoperated net profits interests and royalty interests (collectively, the Morgan Properties) for net cash consideration of approximately $137.9 million from pension funds managed by J.P. Morgan Investments (the Morgan Property Acquisition). The Morgan Property Acquisition was financed with borrowings under the Company's previous credit agreement and two subordinated bridge credit facilities (see Note 3). The results of operations of the Morgan Properties have been included in the consolidated financial statements from the date of acquisition.
The Company's interest in the Morgan Properties primarily takes the form of nonoperated net profits overriding royalty interests, whereby the Company is entitled to a percentage of the net profits from the operations of the properties. The oil and gas properties burdened by the Morgan Properties are primarily located in East Texas, South Texas, and the mid-continent region of the United States.
Presented below are the oil and gas sales and associated production expenses associated with the Morgan Properties, which are presented in the accompanying consolidated statements of operations for the years ended June 30, 2000 and 1999, respectively, as net profits and royalty interests revenues.
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. CURRENT AND LONG-TERM DEBT
A summary of current and long-term debt follows:
On April 17, 1998, the Company entered into an amended and restated credit agreement with Bank of Montreal and certain affiliates of JEDI. During October 1999, the Company entered into an amended and restated revolving credit agreement (the Credit Agreement) with new lenders, replacing the existing lender group. The Credit Agreement allows the Company to borrow up to $30 million (subject to borrowing base limitations). Borrowings under the Credit Agreement are secured by a first lien on the Company's oil and natural gas properties. Borrowings under the Credit Agreement bear interest at prime plus 2% on borrowings under $25 million and prime plus 4.5%, if borrowings exceed $25 million. Borrowings under the Credit Agreement totaled $18.6 million at June 30, 2000. The interest rate at June 30, 2000, was 11.5%. The loan under the Credit Agreement expires on October 22, 2001. The Company is subject to certain affirmative and negative financial and operating covenants under the Credit Agreement, including maintaining a minimum interest coverage ratio of 1.0X, based on the last twelve-month operating results. At June 30, 2000, the Company was in compliance with these covenants.
Letters of credit up to a maximum of $7.5 million may be issued on behalf of the Company under the Credit Agreement, which bear interest at 3%. Any outstanding letters of credit reduce the Company's ability to borrow under the Credit Agreement. At June 30, 2000, the Company had a letter of credit outstanding in the amount of $6.2 million to an affiliate of Enron to secure a swap exposure (see Note 4).
As of June 30, 1999, $8,000,000 was outstanding under the Company's previous credit agreement. In connection with entering into the Credit Agreement, the Company retired borrowings under its previous credit agreement, terminating the arrangement. As a result, the Company recorded an extraordinary loss of $1,130,000 relating to the unamortized deferred costs of the previous agreement.
On July 8, 1998, the Company completed a private placement of $125,000,000 principal amount of 12 1/2% Senior Notes (the Notes) due July 1, 2008. Interest on the Notes is payable semiannually on January 1 and July 1 of each year, commencing January 1, 1999, at the rate of 12 1/2% per annum. The Notes are senior unsecured obligations of the Company and rank pari passu with any existing and future unsubordinated indebtedness of the Company. The Notes rank senior to all unsecured subordinated indebtedness of the Company. The Notes contain customary
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. CURRENT AND LONG-TERM DEBT (CONTINUED)
covenants that limit the Company's ability to incur additional debt, pay dividends, and sell assets of the Company. Substantially all of the proceeds from the issuance of the Notes were used to retire indebtedness incurred in connection with the acquisition of the Morgan Properties.
Beginning in July 1995, the Company initiated private debt offerings whereby it could issue up to a maximum of 5,000,000 Deutschmark (DEM) denominated 12% notes due on July 15, 2000, of which DEM 1,200,000 and DEM 1,600,000 were outstanding at June 30, 2000 and 1999, respectively. On July 15, 2000, the Company retired all remaining outstanding notes for approximately $584,000.
During the years ended June 30, 2000, 1999, and 1998, the Company made cash payments of interest totaling approximately $16,944,000, $9,105,000, and $3,946,000, respectively.
4. HEDGING ACTIVITIES
The Company uses swaps, floors, and collars to hedge oil and natural gas prices. Swaps are settled monthly based on differences between the prices specified in the instruments and the settlement prices of futures contracts quoted on the New York Mercantile Exchange (NYMEX). Generally, when the applicable settlement price is less than the price specified in the contract, the Company receives a settlement from the counterparty based on the difference multiplied by the volume hedged. Similarly, when the applicable settlement price exceeds the price specified in the contract, the Company pays the counterparty based on the difference. The Company generally receives a settlement from the counterparty for floors when the applicable settlement price is less than the price specified in the contract, which is based on the difference multiplied by the volumes hedged. For collars, generally the Company receives a settlement from the counterparty when the settlement price is below the floor and pays a settlement to the counterparty when the settlement price exceeds the cap. No settlement occurs when the settlement price falls between the floor and cap.
The Company had a collar with an affiliate of JEDI to hedge 50,000 MMBtu of natural gas production and 10,000 barrels of oil production monthly. The agreements, effective September 1, 1997, and terminating August 31, 1998, called for a natural gas and oil ceiling and floor price of $2.66 and $1.90 per MMBtu and $20.40 and $18.00 per barrel, respectively. During the years ended June 30, 1999 and 1998, the Company recognized net hedging gains of approximately $85,000 and $120,000, respectively, relating to these agreements, which are included in oil and gas sales.
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
4. HEDGING ACTIVITIES (CONTINUED)
The Company has implemented a comprehensive hedging strategy for its natural gas production over the next few years. The table below sets out volumes of natural gas hedged with a floor price of $1.90 per MMBtu with Enron, an affiliate of JEDI, which received a fee of $478,000 during the year ended June 30, 1998, for entering into this agreement. The volumes presented in this table are divided equally over the months during the period.
The table below sets out volume of natural gas hedged with a swap at $2.40 per MMBtu with Enron. The volumes presented in this table are divided equally over the months during the period.
Effective May 1, 1998 through October 31, 1999, the Company had a collar with Bank of Montreal involving the hedging of a portion of future natural gas production involving floor and ceiling prices as set out in the table below. The volumes presented in this table are divided equally over the months during the period.
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
4. HEDGING ACTIVITIES (CONTINUED)
Effective November 1, 1999, the Company unwound the ceiling price limitation of this collar at a cost of $3.3 million. The table below sets out the volume of natural gas that remains under contract at a floor price of $2.00 per MMBtu. The volumes presented in this table are divided equally over the months during the period.
During the years ended June 30, 2000, 1999, and 1998, the Company recognized hedging gains (losses) of approximately $(981,000), $1,690,000, and $122,000, respectively, relating to these agreements, which are included in net profits and royalty interests revenues.
During the year ended June 30, 1999, the Company entered into a swap agreement with an affiliate of JEDI to hedge 12,000 barrels of oil production monthly at $17.00 per barrel, for the months of October, November, and December 1998. The Company recognized hedging gains of approximately $147,000 relating to this agreement which are included in net profits and royalty interests revenues.
During the year ended June 30, 1999, the Company entered into a swap agreement with an affiliate of JEDI to hedge 10,000 barrels of oil production monthly at $13.50 per barrel for the six months March through August 1999, and for 5,000 barrels of oil production monthly at $14.35 per barrel, and for 5,000 barrels of oil production monthly at $14.82 per barrel for the six months April through September 1999. During the years ended June 30, 2000 and 1999, the Company recognized hedging losses of approximately $358,000 and $231,000, respectively, relating to this agreement which are included in net profits and royalty interests revenues.
The table below sets out the volume of oil hedged with a collar with Enron involving floor and ceiling prices as set out in the table below. The volumes presented in this table are divided equally over the months during the period.
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
4. HEDGING ACTIVITIES (CONTINUED)
During the year ended June 30, 2000, the Company recognized hedging losses of approximately $112,000 relating to this contract.
The Company entered into a forward LIBOR interest rate swap effective for the period June 30, 1998 through June 29, 2009, at a rate of 6.3% on $125 million, which could be unwound at any time at the option of the Company. On July 9, 1998, as a result of the retirement of the Bridge Facilities and borrowings under the Credit Agreement, the Company terminated the agreement at a cost of $3,549,000. The cost of termination has been reflected as an extraordinary loss in the accompanying consolidated statement of operations for the year ended June 30, 1999.
5. STOCKHOLDERS' EQUITY
GENERAL
The Company's Certificate of Incorporation authorizes issuance of: (i) 50,000,000 shares of preferred stock of the Company, par value $.01 per share (the Preferred Stock), of which 9,600,000 shares have been designated as Series A Preferred Stock, 9,600,000 shares have been designated as Series B Preferred Stock; and (ii) 100,000,000 shares of Common Stock. During the year ended June 30, 1998, 10,400 shares of Preferred Stock were designated and issued as Series C Preferred Stock.
Any authorized but unissued or unreserved Common Stock and undesignated Preferred Stock is available for issuance at any time, on such terms and for such purposes as the Board of Directors may deem advisable in the future without further action by stockholders of the Company, except as may be required by law or the Series A or Series C Certificate of Designation. The Board of Directors of the Company has the authority to fix the rights, powers, designations, and preferences of the undesignated Preferred Stock and to provide for one or more series of undesignated Preferred Stock. The authority will include, but will not be limited to: determination of the number of shares to be included in the series; dividend rates and rights; voting rights, if any; conversion privileges and terms; redemption conditions; redemption values; sinking funds; and rights upon involuntary or voluntary liquidation.
CAPITAL STOCK PURCHASE AGREEMENTS
In March 1997, the Company entered into a Securities Purchase Agreement (the JEDI Purchase Agreement) with JEDI and a Securities Purchase Agreement (the Forseti Purchase Agreement) with Forseti Investments Ltd. (Forseti).
In May 1997, pursuant to the JEDI Purchase Agreement, JEDI acquired 9,600,000 shares of Series A Participating Convertible Preferred Stock, par value $0.01 per share, of the Company (the Series A Preferred Stock), certain warrants to purchase Common Stock, and nondilution rights as in regard to future stock issuances. The aggregate consideration received by the Company consisted of $5,000,000 ($0.521 per share).
In connection with the issuance of the Series A Preferred Stock, the Company granted JEDI certain maintenance rights and certain demand and piggyback registration rights with respect to the shares of Common Stock issuable upon conversion of the Series A Preferred Stock.
Pursuant to the terms of the Series A Preferred Stock, JEDI may designate a number of directors to the Company's Board of Directors, such that the percentage of the number of directors that JEDI may designate approximates the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5. STOCKHOLDERS' EQUITY (CONTINUED)
percentage voting power JEDI has with respect to the Company's Common Stock. In addition, upon certain events of default (as defined in the Series A Certificate of Designation), JEDI will have the right to elect a majority of the directors of the Company and an option to sell the Series A Preferred Stock to the Company.
In May 1997, pursuant to the Forseti Purchase Agreement, the Company repurchased 9,600,000 shares of Common Stock owned by Forseti in exchange for (i) $5,000,000 ($0.521 per share) cash, (ii) the issuance by the Company of Class A Common Stock Purchase Warrants to purchase 1,000,000 shares of Common Stock at an initial exercise price of $2.50 per share (the Class A Warrants) and Class B Common Stock Purchase Warrants to purchase 2,000,000 shares of Common Stock at an initial exercise price of $2.50 per share (the Class B Warrants, and together with the Class A Warrants, the Forseti Warrants), and (iii) certain contingent payments. Forseti had the option of either selling or exercising the Forseti Warrants or receiving the contingent payments. During the year ended June 30, 1998, Forseti elected to sell the warrants to a third party and, thus, lost the rights to receive any contingent payments.
The JEDI Purchase Agreement contains certain positive and negative covenants. The Company was in compliance with all of the applicable covenants at June 30, 2000 and 1999.
Pursuant to the JEDI Purchase Agreement, JEDI, EIBOC, and certain officers of the Company (Management Stockholders) entered into a Stockholders Agreement whereby JEDI, EIBOC, and the Management Stockholders agreed to certain restrictions on the transfer of shares of Common Stock held by EIBOC and the transfer of shares of Common Stock or securities convertible, exercisable, or exchangeable for shares of Common Stock held by JEDI. The Stockholders Agreement will terminate on the earlier of (i) the fifth anniversary of the date of the Stockholders Agreement or (ii) the date on which JEDI and its affiliates beneficially own in the aggregate less than 10% of the voting power of the Company's capital stock.
SERIES A PREFERRED STOCK
The holders of shares of Series A Preferred Stock are generally entitled to vote (on an as-converted basis) as a single class with the holders of the Common Stock, together with all other classes and series of stock of the Company that are entitled to vote as a single class with the Common Stock, on all matters coming before the Company's stockholders.
For so long as at least 960,000 shares of Series A Preferred Stock are outstanding, the following matters require the approval of the holders of shares of Series A Preferred Stock, voting together as a separate class:
(i) The amendment of any provision of the Company's Certificate of Incorporation or the bylaws
(ii) The creation, authorization, or issuance of, or the increase in the authorized amount of, any class or series of shares ranking on a parity with or prior to the Series A Preferred Stock either as to dividends or upon liquidation, dissolution, or winding up
(iii) The merger or consolidation of the Company with or into any other corporation or other entity or the sale of all or substantially all of the Company's assets
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5. STOCKHOLDERS' EQUITY (CONTINUED)
(iv) The reorganization, recapitalization, or restructuring or similar transaction that requires the approval of the stockholders of the Company
The holders of shares of Series A Preferred Stock have the right, acting separately as a class, to elect a number of members to the Company's Board of Directors. The number shall be a number such that the quotient obtained by dividing such number by the maximum authorized number of directors is as close as possible to being equal to the percentage of the outstanding voting power of the Company entitled to vote generally in the election of directors represented by the outstanding shares of Series A Preferred Stock at the relevant time.
A holder of shares of Series A Preferred Stock has the right, at the holder's option, to convert all or a portion of its shares into shares of Common Stock at any time at an initial rate of one share of Series A Preferred Stock for one share of Common Stock.
The Series A Certificate of Designation provides for customary adjustments to the number of shares issuable upon conversion in the event of certain dividends and distributions to holders of Common Stock, certain reclassifications of the Common Stock, stock splits, and combinations and mergers and similar transactions.
The holders of the shares of Series A Preferred Stock are entitled to receive dividends (other than a dividend or distribution paid in shares of, or warrants, rights, or options exercisable for or convertible into or exchangeable for, Common Stock) when and if declared by the Board of Directors on the Common Stock in an amount equal to the amount each such holder would have received if such holder's shares of Series A Preferred Stock had been converted into Common Stock. The holders of Series A Preferred Stock will also have the right to certain dividends upon and during the continuance of an Event of Default.
Upon the liquidation, dissolution, or winding up of the Company, the holders of the shares of Series A Preferred Stock, before any distribution to the holders of Common Stock, are entitled to receive an amount per share equal to $.521 plus all accrued and unpaid dividends thereon (Liquidation Preference). The holders of the shares of Series A Preferred Stock will not be entitled to participate further in the distribution of the assets of the Company.
The Series A Certificate of Designation provides that an Event of Default will be deemed to have occurred if the Company fails to comply with any of its covenants in the JEDI Purchase Agreement, provided that the Company will have a 30-day cure period with respect to the non-compliance with certain covenants.
Upon the occurrence but only during the continuance of an Event of Default, the holders of Series A Preferred Stock are entitled to receive, in addition to other dividends payable to holders of Series A Preferred Stock, when and if declared by the Board of Directors, cumulative preferential cash dividends accruing from the date of the Event of Default in an amount per share per annum equal to 6% of the Liquidation Preference in effect at the time of accrual of such dividends, payable quarterly in arrears on or before the 15th day after the last day of each calendar quarter during which such dividends are payable. Unless full cumulative dividends accrued on shares of Series A Preferred Stock have been or contemporaneously are declared and paid, no dividend may be declared or paid or set aside for payment on the Common Stock or any other junior securities (other than a dividend or distribution paid in shares of, or warrants, rights, or options exercisable for or convertible into or exchangeable for, Common Stock or any other junior securities), nor shall any Common Stock nor any other junior securities be redeemed, purchased, or otherwise acquired for any consideration, nor may any monies be paid to or made available for a sinking fund for the redemption of any shares of any such securities.
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5. STOCKHOLDERS' EQUITY (CONTINUED)
Upon the occurrence and during the continuance of an Event of Default resulting from the failure to comply with certain covenants, the holders of shares of Series A Preferred Stock have the right, acting separately as a class, to elect a number of persons to the Board of Directors of the Company that, along with any members of the Board of Directors who are serving at the time of such action, will constitute a majority of the Board of Directors.
Upon the occurrence of an Event of Default resulting from the failure to comply with certain covenants, each holder of shares of Series A Preferred Stock has the right, by written notice to the Company, to require the Company to repurchase, out of funds legally available therefor, such holder's shares of Series A Preferred Stock for an amount in cash equal to the Liquidation Preference in effect at the time of the Event of Default.
Concurrently with the transfer of any shares of Series A Preferred Stock to any person (other than a direct or indirect affiliate of JEDI or other entity managed by Enron Corp. or any of its affiliates), the shares of Series A Preferred Stock so transferred will automatically convert into a like number of shares of Series B Preferred Stock. At June 30, 2000, 1999, and 1998, 9,600,000 shares of Series A Preferred Stock were outstanding.
SERIES B PREFERRED STOCK
The Series B Certificate of Designation authorizes the issuance of up to 9,600,000 shares of Series B Preferred Stock. The terms of the Series B Preferred Stock are substantially similar to those of the Series A Preferred Stock, except that the holders of Series B Preferred Stock will not (i) have class voting rights except as required under Delaware corporate law, (ii) be entitled to any remedies upon an event of default, or (iii) be entitled to elect any directors of the Company, voting separately as a class. At June 30, 2000, 1999 and 1998, no shares of Series B Preferred Stock were outstanding.
SERIES C PREFERRED STOCK
The holders of shares of Series C Preferred Stock are not entitled to vote with the holders of the Common Stock except as required by law or as set forth below. For so long as any shares of Series C Preferred Stock are outstanding, the following matters will require the approval of the holders of at least two-thirds of the then outstanding shares of Series C Preferred Stock, voting together as a separate class:
(i) Alter or change the rights, preferences, or privileges of the Series C Preferred Stock or any other capital stock of the Company so as to affect adversely the Series C Preferred Stock
(ii) Create any new class or series of capital stock having a preference over or ranking pari passu with the Series C Preferred Stock as to redemption, the payment of dividends or distribution of assets upon a Liquidation Event (as defined in the Series C Certificate of Designation) or any other liquidation, dissolution, or winding up of the Company
(iii) Increase the authorized number of shares of Preferred Stock of the Company
(iv) Re-issue any shares of Series C Preferred Stock which have been converted in accordance with the terms hereof
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5. STOCKHOLDERS' EQUITY (CONTINUED)
(v) Issue any Senior Securities (other than the Company's Series B Preferred Stock pursuant to the terms of the Company's Series A Preferred Stock) or Pari Passu Securities (each, as defined in the Series C Certificate of Designation)
(vi) Declare, pay, or make any provision for any dividend or distribution with respect to the Common Stock or any other capital stock of the Company ranking junior to the Series C Preferred Stock as to dividends or as to the distribution of assets upon liquidation, dissolution, or winding up of the Company
The holders of at least two-thirds of the then outstanding shares of Series C Preferred Stock can agree to allow the Company to alter or change the rights, preferences, or privileges of the shares of Series C Preferred Stock. Holders of the Series C Preferred Stock that did not agree to such alteration or change shall have the right for a period of thirty days following such change to convert their Series C Preferred Stock to Common Stock.
A holder of shares of Series C Preferred Stock has the right, at the holder's option, to convert all or a portion of its shares into shares of Common Stock at any time. The number of shares of Common Stock into which a share of Series C Preferred Stock may be converted will be determined as of the conversion date according to a formula set forth in the Series C Certificate of Designation. Generally, the conversion rate is equal to the aggregate stated value of the shares to be converted divided by a floating conversion price that may not exceed $7.35 per share. On December 24, 2001, all shares of Series C Preferred Stock that are then outstanding shall be automatically converted into shares of Common Stock.
The Series C Certificate of Designation provides for customary adjustments to the number of shares issuable upon conversion in the event of certain dividends and distributions to holders of Common Stock, certain reclassifications of the Common Stock, stock splits, combinations and mergers, and similar transactions and certain changes of control.
The holders of the shares of Series C Preferred Stock are entitled to receive cumulative dividends, when and if declared by the Board of Directors, subject to the prior payment of any accumulated and unpaid dividends to holders of Senior Securities, but before payment of dividends to holders of Junior Securities (as defined in the Series C Certificate of Designation), on each share of Series C Preferred Stock in an amount equal to the stated value of such share multiplied by 5%.
Upon the liquidation, dissolution, or winding up of the Company, the holders of the shares of Series C Preferred Stock, before any distribution to the holders of Junior Securities, and after payments to holders of Senior Securities, will be entitled to receive an amount equal to the stated value of the Series C Preferred Stock (subject to ratable adjustment in the event of reclassification of the Series C Preferred Stock or other similar event) plus any accrued and unpaid dividends thereon.
The Company has the right to redeem all of the outstanding Series C Preferred Stock under certain conditions. Holders of Series C Preferred Stock have the right to tender shares for redemption upon the occurrence of certain events, which are in the control of management. During fiscal year 1999, the Company repurchased 2,152 shares of Series C Preferred Stock at a cost of $2,251,000.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5. STOCKHOLDERS' EQUITY (CONTINUED)
During the years ended June 30, 2000 and 1999, 2,525 shares and 3,550 shares, respectively, of Series C Preferred Stock were converted into 8,217,831 shares and 1,328,639 shares, respectively, of Common Stock. Additionally, 914,712 shares and 77,571 shares of Common Stock, representing accrued but unpaid dividends due to the converting Series C Preferred Stock holders, were issued upon conversion during fiscal years 2000 and 1999, respectively. At June 30, 2000, 1999, and 1998, 2,173 shares, 4,698 shares, and 10,400 shares of Series C Preferred Stock were outstanding.
COMMON STOCK
During July 1998, the Company completed the private placement of an aggregate of 3,428,574 shares of the Company's Common Stock at $7.00 per share (the July Equity Offerings) which included certain repricing rights (the Repricing Rights) to acquire additional shares of Common Stock (Repricing Common Shares) and warrants (the Warrants) to purchase an aggregate of up to 1,085,000 shares of Common Stock (Warrant Common Shares). Additionally, JEDI exercised warrants to acquire an aggregate of 980,935 shares of Common Stock at $3.33 per share and nondilution rights to purchase 693,301 shares of the Company's Common Stock at $2.50 per share and another entity exercised warrants to acquire an aggregate of 800,000 shares of Common Stock at $2.50 per share (collectively, the Warrant Exercises).
During November 1998, the Company completed the private placement of an aggregate of 416,667 shares of the Company's Common Stock at $6.00 per share (the November Equity Offerings and, collectively with the July Equity Offerings, the Equity Offerings) which included certain repricing rights (the Repricing Rights) to acquire additional shares of Common Stock (Repricing Common Shares) and warrants (the Warrants) to purchase an aggregate of up to 206,340 shares of Common Stock (Warrant Common Shares).
The Repricing Rights allow the purchasers of the Common Shares under the Equity Offerings to receive Repricing Common Shares based on the following formula:
(Repricing Price - Market Price) X Common Shares -------------------------------- Market Price
The Repricing Price is a percentage increase in the purchase price paid for the Common Shares (up to 128% over the following eight months). The Repricing Rights can only be exercised one time and the Company can repurchase the Repricing Rights under certain conditions. During the years ended June 30, 2000 and 1999, 38,113,785 shares and 1,384,016 shares, respectively, of Common Stock were issued upon exercise of Repricing Rights.
Each holder of Repricing Common Shares or Repricing Rights has the right to require the Company to repurchase all or a portion of such holder's Repricing Common Shares or Repricing Rights upon the occurrence of a Major Transaction or a Triggering Event, both of which are under the control of management of the Company.
The Warrants are exercisable for three years commencing July 8, 1998 and November 23, 1998, at an exercise price equal to 110% of the Purchase Price. The Warrants provide for customary adjustments to the exercise price and number of shares to be issued in the event of certain dividends and distributions to holders of Common Stock, stock splits, combinations, and mergers. The Warrants also include customary provisions with respect to, among other things, transfer of the Warrants, mutilated or lost warrant certificates, and notices to holder(s) of the Warrants.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5. STOCKHOLDERS' EQUITY (CONTINUED)
WARRANTS
Certain institutional investors hold warrants to purchase an aggregate of 1,525,153 shares of Common Stock at prices ranging from $6.00 to $8.00 per share. The warrants held by the institutional investors expire at various times from December 24, 2000 through November 25, 2001.
STOCK OPTIONS
Employee stock option activity for the years ended June 30, 2000, 1999, and 1998 is as follows:
The weighted average grant date fair value of stock options granted during 1999 and 1998 were $6.23 and $3.22, respectively. The grant date fair values were estimated at the date of grant using the Black-Scholes option pricing model. As of June 30, 2000, the weighted average remaining contractual life of outstanding stock options was 7.3 years.
Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (SFAS 123), requires the disclosure of pro forma net income and earnings per share information computed as if the Company had accounted for its employee stock options under the fair value method set forth in SFAS 123. The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted average assumptions, respectively: a risk-free interest rate of 6.00% and 5.88% during 1999 and 1998, respectively; a dividend yield of 0%; and a volatility factor of 0.792 and 0.51 during 1999 and 1998, respectively. In addition, the fair value of these options was estimated based on an expected weighted average life of 10 years and 7.5 years during 1999 and 1998, respectively.
The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions, including the expected stock price volatility. Because the Company's employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its employee stock options.
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5. STOCKHOLDERS' EQUITY (CONTINUED)
For purposes of pro forma disclosures, the estimated fair value of the options is amortized to expense over the options' vesting period. The Company's pro forma information follows:
6. FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company defines the fair value of a financial instrument as the amount at which the instrument could be exchanged in a current transaction between willing parties. The carrying value of accounts receivable, accounts payable, and accrued liabilities approximates fair value because of the short maturity of those instruments. The estimated fair value of the Company's long-term obligations is estimated based on the current rates offered to the Company for similar maturities. At June 30, 2000 and 1999, the carrying value of long-term obligations exceeded their fair values by approximately $76,875,000 and $41,250,000, respectively. At June 30, 1998, the carrying value of long-term obligations approximates their fair values. At June 30, 2000, the fair value of the Company's hedging contracts, measured as the estimated cost to the Company to terminate the arrangements, was approximately $5,256,000.
7. RELATED PARTY TRANSACTIONS
The Company has entered into various hedging arrangements with affiliates of Enron (see Note 4).
The Company had entered into a revolving credit facility with ECT, an affiliate of Enron. During the year ended June 30, 1998, commitment fees of approximately $200,000 and interest totaling approximately $9,000 was paid to ECT in connection with this facility. This agreement was terminated in October 1999.
Enron, through its affiliates, participated in indebtedness incurred in connection with the acquisition of the Morgan Properties. During the years ended June 30, 2000 and 1999, Enron received interest payments of approximately $88,000 and $365,000, respectively, from the Company relating to such participation.
The Company paid Enron approximately $100,000 during both of the years ended June 30, 2000 and 1999, under the terms of an agreement which allows the Company to consult, among other things, with Enron's engineering staff.
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
8. INCOME TAXES
The Company's effective tax rate differs from the U.S. statutory rate for each of the years ended June 30, 2000, 1999, and 1998, due to losses for which no deferred tax benefit was recognized. The tax effects of the primary temporary differences giving rise to the deferred federal income tax assets and liabilities as determined under Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes, at June 30, 2000 and 1999, follow:
The net changes in the total valuation allowance for the years ended June 30, 2000 and 1999, were increases of $2,889,000 and $15,677,000, respectively. The Company's net operating loss carryforwards begin expiring in 2010.
9. COMMITMENTS AND CONTINGENCIES
The Company is involved in certain disputes and other matters arising in the normal course of business. Although the ultimate resolution of these matters cannot be reasonably estimated at this time, management does not believe that they will have a material adverse effect on the financial condition or results of operations of the Company.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
10. OIL AND GAS PRODUCING ACTIVITIES
The following tables set forth supplementary disclosures for oil and gas producing activities in accordance with Statement of Financial Accounting Standards No. 69.
RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES
The following sets forth certain information with respect to results of operations from oil and gas producing activities for the years ended June 30, 2000, 1999, and 1998:
Depreciation and amortization of oil and gas properties was $0.71, $0.74, and $0.89 per Mcfe produced for the years ended June 30, 2000, 1999, and 1998, respectively.
The following table summarizes capitalized costs relating to oil and gas producing activities and related amounts of accumulated depreciation and amortization at June 30, 2000 and 1999:
COSTS INCURRED
The following sets forth certain information with respect to costs incurred, whether expensed or capitalized, in oil and gas activities for the years ended June 30, 2000, 1999, and 1998:
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
11. SUPPLEMENTARY OIL AND GAS DATA (UNAUDITED)
RESERVE QUANTITY INFORMATION
The following table presents the Company's estimate of its proved oil and gas reserves, all of which are located in the United States. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, the estimates are expected to change as future information becomes available. The estimates at June 30, 1997, 1998, and 1999, have been prepared by independent petroleum reservoir engineers. The estimate at June 30, 2000, has been prepared by the Company's petroleum engineers.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
The Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Standardized Measure) is a disclosure requirement under Statement of Financial Accounting Standards No. 69.
The Standardized Measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the Company's oil and gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
11. SUPPLEMENTARY OIL AND GAS DATA (UNAUDITED) (CONTINUED)
Under the Standardized Measure, future cash flows are estimated by applying year-end prices, adjusted for fixed and determinable escalations, to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pretax cash inflows. Future income taxes are computed by applying the statutory tax rate to the excess of pretax cash inflows over the Company's tax basis in the associated properties. Tax credits, net operating loss carryforwards, and permanent differences are also considered in the future tax calculation. Future net cash inflows after income taxes are discounted using a 10% annual discount rate to arrive at the Standardized Measure.
The Standardized Measure of discounted future net cash flows relating to proved oil and gas reserves as of June 30, 2000 and 1999, are as follows:
The weighted average price of oil and gas at June 30, 2000 and 1999, used in calculating the Standardized Measure were $31.42 and $17.11 per barrel, respectively, and $4.45 and $2.44 per MCF, respectively.
Changes in the Standardized Measure of discounted future net cash flows relating to proved oil and gas reserves for the years ended June 30, 2000, 1999, and 1998, are as follows:
The future cash flows shown above include amounts attributable to proved undeveloped reserves requiring approximately $12,930,000 of future development costs. If these reserves are not developed, the future net cash flows shown above would be significantly reduced.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
11. SUPPLEMENTARY OIL AND GAS DATA (UNAUDITED) (CONTINUED)
Estimates of economically recoverable gas and oil reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree speculative and may vary considerably from actual results. Therefore, actual production, revenues, taxes, development, and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties, and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of gas and oil may differ materially from the amounts estimated.
12. QUARTERLY FINANCIAL RESULTS (UNAUDITED)
EXHIBIT INDEX
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* Filed herewith.