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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED JUNE 30, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM _____________ TO _____________
COMMISSION FILE NUMBER 0-21179
QUEEN SAND RESOURCES, INC.
QUEEN SAND RESOURCES, INC.
QUEEN SAND OPERATING CO.
CORRIDA RESOURCES, INC.
(EXACT NAME OF REGISTRANTS AS SPECIFIED IN THEIR CHARTER)
DELAWARE 75-2615565
NEVADA 75-2564071
NEVADA 75-2593510
NEVADA 75-2691594
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NOS.)
13760 NOEL RD., SUITE 1030
DALLAS, TEXAS 75240-7336
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
(REGISTRANTS' TELEPHONE NUMBER, INCLUDING AREA CODE) (972) 233-9906
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
COMMON STOCK, PAR VALUE $0.0015 PER SHARE
(TITLE OF CLASS)
----------
INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS
REQUIRED TO BE FILED BY SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE
REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH
FILING REQUIREMENTS FOR THE PAST 90 DAYS.
YES [X] NO [ ]
INDICATE BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO
ITEM 405 OF REGULATION S-K IS NOT CONTAINED HEREIN, AND WILL NOT BE CONTAINED,
TO THE BEST OF REGISTRANTS' KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION
STATEMENTS INCORPORATED BY REFERENCE IN PART III OF THIS FORM 10-K OR ANY
AMENDMENT OF THIS FORM 10-K. [ ]
STATE THE AGGREGATE MARKET VALUE OF THE VOTING AND NON-VOTING COMMON
EQUITY HELD BY NON-AFFILIATES (ALL DIRECTORS, OFFICERS AND 5% OR MORE
SHAREHOLDERS ARE PRESUMED TO BE AFFILIATES) OF THE REGISTRANT ON AUGUST 17,
2000, WAS $4,362,394 BASED ON THE CLOSING PRICE PER SHARE OF THE COMMON STOCK ON
SUCH DATE.
THE NUMBER OF SHARES OF COMMON STOCK, PAR VALUE $0.0015 PER SHARE, OF
REGISTRANT OUTSTANDING ON AUGUST 17, 2000 WAS 80,688,538.
DOCUMENTS INCORPORATED BY REFERENCE
PORTIONS OF THE REGISTRANT'S PROXY STATEMENT FOR THE 2000 ANNUAL
MEETING OF STOCKHOLDERS, EXPECTED TO BE FILED ON OR PRIOR TO OCTOBER 28, 2000,
ARE INCORPORATED BY REFERENCE INTO PART III.
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TABLE OF CONTENTS
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PAGE
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<S> <C> <C> <C>
PART I.................................................................................................1
Item 1. Business..........................................................................2
Item 2. Description of Properties........................................................27
Item 3. Legal Proceedings................................................................27
Item 4. Submission of Matters to a Vote of Security Holders..............................27
PART II...............................................................................................28
Item 5. Market for the Common Stock and Related Stockholder Matters......................28
Item 6. Selected Financial Data..........................................................29
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations............................................................30
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.......................42
Item 8. Financial Statements and Supplementary Data......................................43
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.........................................................43
PART III..............................................................................................44
Item 10. Directors and Executive Officers of the Registrant...............................44
Item 11. Executive Compensation...........................................................44
Item 12. Security Ownership of Certain Beneficial Owners and Management...................44
Item 13. Certain Relationships and Related Transactions...................................44
PART IV...............................................................................................48
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.................48
SIGNATURE PAGE........................................................................................52
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS...........................................................F-1
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QUEEN SAND RESOURCES, INC.
PART I
A WARNING ABOUT FORWARD-LOOKING STATEMENTS
We have made forward-looking statements in this Form 10-K that are
subject to risks and uncertainties. These forward-looking statements include
information about possible or assumed future results of our operations. Also,
when we use any of the words "believes," "expects," "intends," "anticipates" or
similar expressions, we are making forward-looking statements. Examples of types
of forward-looking statements include statements on:
o our oil and natural gas reserves;
o future acquisitions;
o future drilling and operations;
o future capital expenditures;
o future production of oil and natural gas; and
o future net cash flow.
You should understand that the following important factors, in addition
to those discussed elsewhere in this report on Form 10-K, could affect our
future financial results and performance and cause our results or performance to
differ materially from those expressed in our forward-looking statements:
o the timing and extent of changes in prices for oil and natural gas;
o the need to acquire, develop and replace reserves;
o our ability to obtain financing to fund our business strategy;
o environmental risks;
o drilling and operating risks;
o risks related to exploitation and development projects;
o competition;
o government regulation; and
o our ability to meet our stated business goals.
We claim the protection of the safe harbor for forward-looking statements
contained in the Private Securities Litigation Reform Act of 1995 for these
statements.
You should consider these risks when you purchase our common stock and the
risks discussed in "Business -- Risk Factors".
SUBSIDIARY REGISTRANTS
Due to requirements of the Securities and Exchange Commission, certain
subsidiaries of the parent company are also shown as co-registrants on this Form
10-K. Unless otherwise stated, the information provided in the Form 10-K
describes the business, assets, financial condition and financial results of the
parent company and the consolidated subsidiaries as if they were one entity. As
used herein, references to "Queen Sand Resources, Inc." are to Queen Sand
Resources, Inc., a Delaware corporation, and its consolidated subsidiaries.
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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
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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
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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.
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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.
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TOTAL PERCENT
GROSS TOTAL PERCENT OF OF
OIL & NATURAL PROVED TOTAL SEC TOTAL
NATURAL OIL GAS RESERVES PROVED PV-10 SEC
GAS WELLS (MBBLS) (MMCF) (BCFE)(1) RESERVES ($000S) PV-10(1)
--------- -------- -------- --------- ---------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
East Texas
Gilmer Field 41 564 51,081 54.5 38% $ 78,438 36%
South Texas
J.C. Martin Field 84 -- 16,331 16.3 11% 36,305 17%
Lopeno and Volpe Fields 25 60 7,663 8.0 6% 12,856 6%
Other South Texas 128 236 2,585 4.0 3% 6,799 3%
-------- -------- -------- ----- -------- -------- --------
Total South Texas 237 296 26,579 28.3 20% 55,960 26%
Kentucky (Appalachian Basin)
Nasgas Field 32 -- 36,665 36.6 25% 31,721 15%
-------- -------- -------- ----- -------- -------- --------
Appalachian Basin total 32 -- 36,665 36.6 25% 31,721 15%
Permian Basin
Caprock (Queen) Field 29 181 -- 1.1 1% 872 0%
Other Permian Basin 11 324 234 2.2 1% 4,764 2%
-------- -------- -------- ----- -------- -------- --------
Total Permian Basin 40 505 234 3.3 2% 5,636 2%
Mid-continent Total (25 fields) 207 318 16,256 18.2 12% 36,645 17%
Other (Gulf Coast) 27 327 1,865 3.8 3% 8,972 4%
-------- -------- -------- ----- -------- -------- --------
Grand Total 584 2,010 132,680 144.7 100% $217,372 100%
</TABLE>
(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.
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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
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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.
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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.
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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
9
<PAGE> 12
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:
<TABLE>
<CAPTION>
JUNE 30,
--------------------------------------
1998 1999 2000
------- ------- -------
<S> <C> <C> <C>
Natural gas (per Mcf) $ 2.40 $ 2.32 $ 4.45
Oil (per Bbl) $ 12.80 $ 19.28 $ 31.42
</TABLE>
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
10
<PAGE> 13
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)
<TABLE>
<CAPTION>
JUNE 30,
--------------------------------------
1998 1999 2000
-------- -------- --------
<S> <C> <C> <C>
NATURAL GAS RESERVES (MMCF):
Proved Developed Reserves 120,998 94,614 86,348
Proved Undeveloped Reserves 55,097 42,947 46,332
-------- -------- --------
Total Proved Reserves of natural gas 176,095 137,561 132,680
OIL RESERVES (MBBL):
Proved Developed Reserves 5,298 2,138 1,868
Proved Undeveloped Reserves 2,651 2,486 142
-------- -------- --------
Total Proved Reserves of oil 7,949 4,624 2,010
TOTAL PROVED RESERVES (MMCFE) 223,788 165,299 144,740
</TABLE>
11
<PAGE> 14
SEC PV-10 OF PROVED RESERVES(1)
<TABLE>
<CAPTION>
JUNE 30,
-------------------------------------
1998 1999 2000
--------- --------- ---------
<S> <C> <C> <C>
SEC PV-10 ($,000)(2):
Proved Developed Reserves $ 131,200 $ 99,650 $ 163,982
Proved Undeveloped Reserves 33,920 31,076 53,390
--------- --------- ---------
Total SEC PV-10 $ 165,120 $ 130,726 $ 217,372
</TABLE>
(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.
<TABLE>
<CAPTION>
GROSS NET
---------------- -------------------
OIL GAS TOTAL OIL GAS TOTAL
--- --- ----- --- ---- -----
<S> <C> <C> <C> <C> <C> <C>
Texas 160 159 319 41.9 33.6 75.5
New Mexico 29 -- 29 28.5 -- 28.5
Louisiana 1 -- 1 1.0 -- 1.0
Oklahoma -- 148 148 0.0 19.0 19.0
Kentucky -- 32 32 -- 22.4 22.4
Other(1) 1 54 55 0.4 10.8 11.2
--- --- --- ---- ---- -----
Total 191 393 584 71.8 85.8 157.6
</TABLE>
(1) Represents wells located in Kansas, Alabama and Wyoming.
12
<PAGE> 15
PRODUCTION ECONOMICS
The following table sets forth certain operating information for the
periods presented.
<TABLE>
<CAPTION>
1998 1999 2000
------- ------- -------
<S> <C> <C> <C>
OPERATING DATA
PRODUCTION VOLUMES:
Natural gas (MMcf) 3,368 12,962 10,618
Oil (MBbl) 325 500 224
Total (Mmcfe) 5,318 15,960 11,960
AVERAGE SALES PRICE:
Natural gas (per Mcf) $ 2.27 $ 2.13 $ 2.59
Oil (per Bbl) 15.52 12.37 22.76
SELECTED EXPENSES (PER MCFE):
Production taxes $ 0.12 $ 0.09 $ 0.12
Lease operating expense 1.07 0.49 0.47
General and administrative 0.43 0.22 0.25
Depreciation, depletion and amortization(1) 0.91 0.74 0.71
</TABLE>
(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.
<TABLE>
<CAPTION>
1998 1999 2000
------------- -------------- -------------
GROSS NET GROSS NET GROSS NET
----- --- ----- ---- ----- ---
EXPLORATORY:
<S> <C> <C> <C> <C> <C> <C>
Oil 1 0.0 -- 0.0 1 0.2
Natural gas 1 0.3 -- 0.0 -- 0.0
Dry 1 0.7 1 1.0 1 0.5
-- --- -- ---- -- ---
Total 3 1.0 1 1.0 2 0.7
DEVELOPMENT:
Oil 5 2.1 1 0.2 1 0.8
Natural gas 10 2.6 26 9.9 13 2.2
Dry 1 0.4 1 0.7 1 0.2
-- --- -- ---- -- ---
Total 16 5.1 28 10.8 15 3.2
TOTAL:
Oil 6 2.1 1 0.2 2 1.0
Natural gas 11 2.9 26 9.9 13 2.2
Dry 2 1.1 2 1.7 2 0.7
-- --- -- ---- -- ---
Total 19 6.1 29 11.8 17 3.9
</TABLE>
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.
13
<PAGE> 16
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.
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
------------------- -------------------
GROSS NET GROSS NET
------- ------- ------- -------
<S> <C> <C> <C> <C>
Texas 47,200 13,800 6,500 1,300
New Mexico 14,300 14,100 -- --
Louisiana 300 300 6,100 3,300
Oklahoma 37,400 5,300 -- --
Kentucky 600 400 43,900 30,700
Other(1) 20,500 5,200 -- --
------- ------- ------- -------
Total 120,300 39,100 56,500 35,300
</TABLE>
(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
14
<PAGE> 17
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.
15
<PAGE> 18
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.
16
<PAGE> 19
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.
17
<PAGE> 20
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.
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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.
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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.
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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;
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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.
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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.
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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.
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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
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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.
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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. 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. 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.
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<PAGE> 30
PART II
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.
<TABLE>
<CAPTION>
HIGH LOW
------ ------
<S> <C> <C>
FISCAL YEAR ENDED JUNE 30, 1999
First Quarter $8.000 $6.500
Second Quarter 7.000 3.375
Third Quarter 4.125 1.125
Fourth Quarter 1.469 0.937
FISCAL YEAR ENDED JUNE 30, 2000
First Quarter $0.938 $0.281
Second Quarter 0.594 0.281
Third Quarter 0.530 0.281
Fourth Quarter 0.406 0.094
</TABLE>
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).
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<PAGE> 31
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. 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. Management's
Discussion and Analysis of Financial Condition and Results and Operations," our
Consolidated Financial Statements and the notes thereto.
29
<PAGE> 32
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
-----------------------------------------------------------------------------
2000 1999 1998 1997 1996
($,000) ($,000) ($,000) ($,000) ($,000)
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
OPERATIONS DATA:
Oil and natural gas sales(1) 32,584 33,783 12,665 4,381 2,079
Oil and natural gas production expenses(1) 7,097 9,127 6,333 2,507 1,175
--------- --------- --------- --------- ---------
Net oil and natural gas revenues 25,487 24,656 6,332 1,874 904
General and administrative expenses 3,026 3,534 2,259 1,452 1,113
--------- --------- --------- --------- ---------
EBITDA 22,461 21,122 4,073 422 209
Hedge contract termination costs 3,328 -- -- -- --
Interest and financing costs(2) 16,945 17,003 3,957 878 421
Depletion, depreciation, and 10,259 13,354 4,809 982 630
amortization(3)
Ceiling test write-down -- 35,033 28,166 -- --
Interest and other income (143) (326) (105) (300) (71)
Extraordinary item 1,130 3,549 -- 171 --
--------- --------- --------- --------- ---------
Net loss (9,058) (47,491) (32,754) (1,309) (1,189)
========= ========= ========= ========= =========
Net loss per common share $ (0.21) $ (1.51) $ (1.44) $ (0.05) $ (0.05)
CASH FLOWS DATA:
Net cash provided by (used in) in
operating activities (834) 9,504 1,041 263 (620)
Net cash used in investing activities (3,874) (1,611) (154,342) (4,305) (5,502)
Net cash provided by financing activities 7,222 444 154,021 3,752 6,622
Net increase (decrease) in cash 2,514 8,337 720 (290) 500
BALANCE SHEET DATA (AT END OF PERIOD):
Total current assets 18,524 14,019 6,411 1,066 1,533
Property and equipment, net 92,525 97,198 142,467 16,187 9,662
Deferred assets 8,144 7,993 4,797 -- 88
Total assets 119,193 119,210 153,675 17,253 11,283
Total current liabilities 10,535 11,142 6,836 3,670 1,450
Long-term obligations, net of current 143,500 133,852 153,619 7,152 6,670
portion
Total stockholders' equity (deficit) (34,842) (25,784) (6,780) 6,431 3,163
</TABLE>
(1) Oil and natural gas sales and production expenses related to net profits
interests have been presented as if such net profits interests were working
interests.
(2) Interest charges payable on outstanding debt obligations.
(3) Depreciation, depletion and amortization includes amortized deferred
charges related to debt obligations of $1.6 million for the year ended June
30, 2000, and $1.3 million for the year ended June 30, 1999, and $98,000,
$120,000 and $22,000 of amortized deferred charges related to our natural
gas price hedging program for the years ended June 30, 2000, 1999 and 1998,
respectively.
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.
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<PAGE> 33
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 $0.6 million
in the fiscal year ended June 30, 2000. We expense costs associated with
production and general corporate activities in the period incurred. We
capitalize interest costs related to unproved properties and properties under
development. Sales of oil and natural gas properties are accounted for as
adjustments of capitalized costs, with no gain or loss recognized, unless these
adjustments would significantly alter the relationship between capitalized costs
and proved reserves of oil and natural gas.
The following table sets forth certain operating information for the
periods presented. We acquired certain significant producing oil and natural gas
producing properties during certain of the periods presented which affects the
comparability of the data for the periods presented.
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
--------------------------------------------------------
2000 1999 1998
-------------- -------------- --------------
PRODUCTION DATA:
<S> <C> <C> <C>
Natural gas (Mcf) ............................................... 10,618,000 12,962,000 3,368,000
Oil (Bbls) ...................................................... 224,000 500,000 325,000
Mcfe ............................................................ 11,960,000 15,960,000 5,318,000
AVERAGE SALES PRICE:
Natural gas ($/Mcf) ............................................. $ 2.59 $ 2.13 $ 2.27
Oil ($/Bbl) ..................................................... $ 22.76 $ 12.37 $ 15.52
Mcfe ($Mcfe) .................................................... $ 2.72 $ 2.12 $ 2.39
AVERAGE COST ($/MCFE) DATA:
Production and operating costs .................................. $ 0.47 $ 0.49 $ 1.07
Production and severance taxes .................................. $ 0.12 $ 0.09 $ 0.12
General and administrative costs ................................ $ 0.25 $ 0.22 $ 0.43
Interest expense (excluding amortization of deferred
debt issuance costs) ........................................... $ 1.42 $ 1.06 $ 0.75
Depletion, depreciation, and amortization (excluding writedown
of oil and natural gas properties) ............................. $ 0.71 $ 0.74 $ 0.91
</TABLE>
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
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<PAGE> 34
$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
32
<PAGE> 35
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.
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<PAGE> 36
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.
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<PAGE> 37
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.
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<PAGE> 38
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;
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<PAGE> 39
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%.
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<PAGE> 40
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.
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<PAGE> 41
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.
<TABLE>
<CAPTION>
JUNE 30,
----------------------------------
2000 1999 1998
------ ------ ------
<S> <C> <C> <C>
NATURAL GAS (PER MCF):
Price received at wellhead $ 2.69 $ 2.00 $ 2.24
Effect of hedge contracts (0.10) 0.13 0.03
------ ------ ------
Effective price received, including hedge contracts 2.59 2.13 2.27
Average NYMEX Henry Hub 2.78 2.01 2.46
Average basis differential including hedge contracts (0.19) 0.12 (0.19)
Average basis differential excluding hedge contracts (0.09) (0.01) (0.22)
OIL (PER BARREL):
Average price received at wellhead per barrel 24.86 12.37 15.07
Average effect of hedge contract (2.10) 0.00 0.45
------ ------ ------
Average price received, including hedge contracts 22.76 12.37 15.52
Average NYMEX Sweet Light Oil 25.90 14.45 17.62
Average basis differential including hedge contracts (3.14) (2.08) (2.10)
Average basis differential excluding hedge contracts (1.04) (2.08) (2.55)
</TABLE>
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
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<PAGE> 42
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.
<TABLE>
<CAPTION>
Volume Floor Ceiling
Period Beginning Period Ending (MMBtu) Price Price
---------------- --------------- ------- ----- -------
<S> <C> <C> <C> <C>
September 1, 1997 August 31, 1998 600,000 $1.90 $2.66
</TABLE>
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.
<TABLE>
<CAPTION>
Volume Floor Ceiling
Period Beginning Period Ending (Barrels) Price Price
---------------- --------------- --------- ------ -------
<S> <C> <C> <C> <C>
September 1, 1997 August 31, 1998 120,000 $18.00 $20.40
</TABLE>
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.
<TABLE>
<CAPTION>
Volume Floor Ceiling
Period Beginning Period Ending (MMBtu) Price Price
---------------- ----------------- --------- ----- -------
<S> <C> <C> <C> <C>
January 1, 1999 October 31, 1999 3,608,000 $2.00 $2.70
</TABLE>
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:
<TABLE>
<CAPTION>
Volume
Period Beginning Period Ending (MMBtu)
---------------- ----------------- ---------
<S> <C> <C>
November 1, 1999 December 31, 1999 722,000
January 1, 2000 December 31, 2000 3,520,000
January 1, 2001 December 31, 2001 2,970,000
January 1, 2002 December 31, 2002 2,550,000
January 1, 2003 December 31, 2003 2,250,000
</TABLE>
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<PAGE> 43
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:
<TABLE>
<CAPTION>
Volume
Period Beginning Period Ending (MMBtu)
---------------- ------------- ---------
<S> <C> <C>
January 1, 1999 December 31, 1999 1,080,000
January 1, 2000 December 31, 2000 880,000
January 1, 2001 December 31, 2001 740,000
January 1, 2002 December 31, 2002 640,000
January 1, 2003 December 31, 2003 560,000
</TABLE>
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:
<TABLE>
<CAPTION>
Volume
Period Beginning Period Ending (MMBtu)
---------------- ------------- ---------
<S> <C> <C>
January 1, 1999 December 31, 1999 2,710,000
January 1, 2000 December 31, 2000 2,200,000
January 1, 2001 December 31, 2001 1,850,000
January 1, 2002 December 31, 2002 1,600,000
January 1, 2003 December 31, 2003 1,400,000
</TABLE>
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:
<TABLE>
<CAPTION>
Volume
Period Beginning Period Ending (Barrels) Price per Barrel
---------------- ------------- --------- ----------------
<S> <C> <C> <C>
March 1, 1999 August 31, 1999 60,000 $13.50
April 1, 1999 September 30, 1999 30,000 $14.35
April 1, 1999 September 30, 1999 30,000 $14.82
</TABLE>
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.
<TABLE>
<CAPTION>
Volume Floor Price Ceiling Price
Period Beginning Period Ending (Barrels) per Barrel per Barrel
---------------- ------------- --------- ----------- -------------
<S> <C> <C> <C> <C>
December 1, 1999 March 31, 2000 40,000 $22.90 $25.77
April 1, 2000 June 30, 2000 15,000 $23.00 $28.16
July 1, 2000 December 31, 2000 30,000 $22.00 $28.63
</TABLE>
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.
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<PAGE> 44
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.
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<PAGE> 45
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. 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. 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.
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<PAGE> 46
PART III
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. 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. 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. 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.
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<PAGE> 47
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.
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<PAGE> 48
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.
46
<PAGE> 49
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.
47
<PAGE> 50
PART IV
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.
48
<PAGE> 51
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.
49
<PAGE> 52
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.
50
<PAGE> 53
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.
51
<PAGE> 54
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.
<TABLE>
<CAPTION>
SIGNATURE TITLE
--------- -----
<S> <C> <C>
/s/ EDWARD J. MUNDEN CHAIRMAN OF THE BOARD, PRESIDENT, AUGUST 25, 2000
---------------------------- CHIEF EXECUTIVE OFFICER AND
EDWARD J. MUNDEN DIRECTOR (PRINCIPAL EXECUTIVE OFFICER)
/s/ BRUCE I. BENN EXECUTIVE VICE PRESIDENT, DIRECTOR AUGUST 25, 2000
----------------------------
BRUCE I. BENN
/s/ RONALD I. BENN CHIEF FINANCIAL OFFICER (PRINCIPAL AUGUST 25, 2000
---------------------------- FINANCIAL OFFICER AND ACCOUNTING OFFICER)
RONALD I. BENN
/s/ ROBERT P. LINDSAY CHIEF OPERATING OFFICER, EXECUTIVE AUGUST 25, 2000
---------------------------- VICE PRESIDENT AND DIRECTOR
ROBERT P. LINDSAY
</TABLE>
52
<PAGE> 55
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Report of Ernst & Young LLP, Independent Auditors........................................................... F-2
Consolidated Financial Statements
Consolidated Balance Sheets as of June 30, 2000 and 1999.................................................... F-3
Consolidated Statements of Operations for the
Years ended June 30, 2000, 1999, and 1998.............................................................. F-4
Consolidated Statements of Stockholders' Equity (Net Capital
Deficiency) for the Years ended June 30, 2000, 1999, and 1998.......................................... F-5
Consolidated Statements of Cash Flows for the
Years ended June 30, 2000, 1999, and 1998.............................................................. F-7
Notes to Consolidated Financial Statements.................................................................. F-8
</TABLE>
F-1
<PAGE> 56
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
F-2
<PAGE> 57
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
JUNE 30,
--------------------------------
2000 1999
-------------- --------------
<S> <C> <C>
ASSETS
Current assets:
Cash $ 11,881,000 $ 9,367,000
Accounts receivable 6,530,000 4,499,000
Note receivable from employee -- 79,000
Other 113,000 74,000
-------------- --------------
Total current assets 18,524,000 14,019,000
-------------- --------------
Property and equipment, at cost:
Oil and gas properties, based on full cost accounting method 182,280,000 178,421,000
Other equipment 405,000 392,000
-------------- --------------
182,685,000 178,813,000
Less accumulated depreciation and amortization (90,160,000) (81,615,000)
-------------- --------------
Net property and equipment 92,525,000 97,198,000
Other assets 8,144,000 7,993,000
-------------- --------------
$ 119,193,000 $ 119,210,000
============== ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 355,000 $ 1,419,000
Accrued liabilities 9,596,000 9,681,000
Current portion of long-term obligations 584,000 42,000
-------------- --------------
Total current liabilities 10,535,000 11,142,000
Long-term obligations, net of current portion 143,500,000 133,852,000
Commitments and contingencies
Stockholders' equity (net capital deficiency):
Preferred stock, $.01 par value:
Authorized shares -- 50,000,000 at June 30, 2000 and 1999
Issued and outstanding shares -- 9,602,173 and 9,604,698 at June 30,
2000 and 1999, respectively 96,000 96,000
Aggregate liquidation preference -- $7,446,225 and $10,051,950 at June 30,
2000 and 1999, respectively
Common stock, $.0015 par value:
Authorized shares -- 100,000,000 at June 30, 2000 and 1999
Issued and outstanding shares -- 80,688,538 and 33,442,210
at June 30, 2000 and 1999, respectively 135,000 65,000
Additional paid-in capital 65,112,000 64,912,000
Accumulated deficit (92,934,000) (83,606,000)
Treasury stock, at cost (7,251,000) (7,251,000)
-------------- --------------
Total stockholders' equity (net capital deficiency) (34,842,000) (25,784,000)
-------------- --------------
Total liabilities and stockholders' equity $ 119,193,000 $ 119,210,000
============== ==============
</TABLE>
See accompanying notes.
F-3
<PAGE> 58
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
--------------------------------------------
2000 1999 1998
------------ ------------ ------------
<S> <C> <C> <C>
Revenues:
Oil and gas sales $ 3,967,000 $ 4,591,000 $ 6,446,000
Net profits and royalty interests 22,990,000 23,140,000 4,432,000
Interest and other 143,000 326,000 105,000
------------ ------------ ------------
27,100,000 28,057,000 10,983,000
Expenses:
Production expenses 1,372,000 3,196,000 4,547,000
Depreciation and amortization 8,741,000 11,885,000 4,809,000
Hedge contract termination costs 3,328,000 -- --
Write-down of oil and gas properties -- 35,033,000 28,166,000
General and administrative 3,026,000 3,533,000 2,259,000
Interest and financing costs 18,561,000 18,352,000 3,956,000
------------ ------------ ------------
35,028,000 71,999,000 43,737,000
------------ ------------ ------------
Loss before extraordinary item (7,928,000) (43,942,000) (32,754,000)
Extraordinary loss 1,130,000 3,549,000 --
------------ ------------ ------------
Net loss $ (9,058,000) $(47,491,000) $(32,754,000)
============ ============ ============
Loss before extraordinary item per common share $ (0.18) $ (1.40) $ (1.44)
============ ============ ============
Net loss per common share $ (0.21) $ (1.51) $ (1.44)
============ ============ ============
Weighted average common shares outstanding 43,465,423 31,434,465 22,719,177
============ ============ ============
</TABLE>
See accompanying notes.
F-4
<PAGE> 59
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(NET CAPITAL DEFICIENCY)
YEARS ENDED JUNE 30, 2000, 1999, AND 1998
<TABLE>
<CAPTION>
PREFERRED STOCK COMMON STOCK ADDITIONAL
---------------------------- --------------------------- PAID-IN
SHARES AMOUNT SHARES AMOUNT CAPITAL TREASURY
------------ ------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
Balance at June 30, 1997 9,600,000 $ 96,000 20,825,552 $ 46,000 $ 14,474,000 $ (5,000,000)
Issuance of common
stock for services -- -- 150,000 -- 300,000 --
Issuance of common
stock for oil and
gas properties -- -- 1,337,500 2,000 4,810,000 --
Issuance of common
stock for cash -- -- 2,010,715 3,000 4,883,000 --
Issuance of
convertible
preferred stock and
warrants to purchase
common stock for 10,400 -- -- -- 9,544,000 --
cash
Net loss -- -- -- -- -- --
------------ ------------ ------------ ------------ ------------ ------------
Balance at June 30, 1998 9,610,400 96,000 24,323,767 51,000 34,011,000 (5,000,000)
Issuance of common
stock for oil and
gas properties -- -- 8,740 -- 65,000 --
Issuance of common
stock for cash -- -- 3,845,241 6,000 23,668,000 --
Issuance of common
stock upon exercise
of warrants -- -- 2,474,236 4,000 6,996,000 --
Issuance of common
stock pursuant to
repricing rights -- -- 1,384,016 2,000 (2,000) --
Issuance of common
stock on conversion
of convertible
preferred stock (3,550) -- 1,328,639 2,000 (2,000) --
Issuance of common
stock as stock
dividend -- -- 77,571 -- 176,000 --
Repurchase of
convertible
preferred stock (2,152) -- -- -- -- (2,251,000)
Net loss -- -- -- -- -- --
------------ ------------ ------------ ------------ ------------ ------------
Balance at June 30, 1999 9,604,698 96,000 33,442,210 65,000 64,912,000 (7,251,000)
</TABLE>
<TABLE>
<CAPTION>
TOTAL
ACCUMULATED STOCKHOLDERS'
DEFICIT EQUITY
------------ ------------
<S> <C> <C>
Balance at June 30, 1997 $ (3,185,000) $ 6,431,000
Issuance of common
stock for services -- 300,000
Issuance of common
stock for oil and
gas properties -- 4,812,000
Issuance of common
stock for cash -- 4,886,000
Issuance of
convertible
preferred stock and
warrants to purchase
common stock for -- 9,544,000
cash
Net loss (32,754,000) (32,754,000)
------------ ------------
Balance at June 30, 1998 (35,939,000) (6,781,000)
Issuance of common
stock for oil and
gas properties -- 65,000
Issuance of common
stock for cash -- 23,674,000
Issuance of common
stock upon exercise
of warrants -- 7,000,000
Issuance of common
stock pursuant to
repricing rights -- --
Issuance of common
stock on conversion
of convertible
preferred stock -- --
Issuance of common
stock as stock
dividend (176,000) --
Repurchase of
convertible
preferred stock -- (2,251,000)
Net loss (47,491,000) (47,491,000)
------------ ------------
Balance at June 30, 1999 (83,606,000) (25,784,000)
</TABLE>
F-5
<PAGE> 60
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(NET CAPITAL DEFICIENCY) (CONTINUED)
YEARS ENDED JUNE 30, 2000, 1999, AND 1998
<TABLE>
<CAPTION>
PREFERRED STOCK COMMON STOCK ADDITIONAL
---------------------------- --------------------------- PAID-IN ACCUMULATED
SHARES AMOUNT SHARES AMOUNT CAPITAL TREASURY DEFICIT
------------ ------------ ------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Issuance of common
stock pursuant to
repricing rights -- $ -- 38,113,785 $ 56,000 $ (56,000) $ -- $ --
Issuance of common
stock on conversion
of convertible
preferred stock (2,525) -- 8,217,831 12,000 (12,000) -- --
Issuance of common
stock as stock
dividend -- -- 914,712 2,000 268,000 -- (270,000)
Net loss -- -- -- -- -- -- (9,058,000)
------------ ------------ ------------ ------------ ------------ ------------ ------------
Balance at June 30, 2000 9,602,173 $ 96,000 80,688,538 $ 135,000 $ 65,112,000 $ (7,251,000) $(92,934,000)
============ ============ ============ ============ ============ ============ ============
</TABLE>
<TABLE>
<CAPTION>
TOTAL
STOCKHOLDERS'
EQUITY
------------
<S> <C>
Issuance of common
stock pursuant to
repricing rights $ --
Issuance of common
stock on conversion
of convertible
preferred stock --
Issuance of common
stock as stock
dividend --
Net loss (9,058,000)
------------
Balance at June 30, 2000 $(34,842,000)
============
</TABLE>
See accompanying notes.
F-6
<PAGE> 61
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
--------------------------------------------------
2000 1999 1998
-------------- -------------- --------------
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net loss $ (9,058,000) $ (47,491,000) $ (32,754,000)
Adjustments to reconcile net loss to net cash provided by (used in)
operating activities:
Extraordinary loss 1,130,000 3,549,000 --
Depreciation and amortization 10,288,000 13,354,000 4,809,000
Write-down of oil and gas properties -- 35,033,000 28,166,000
Unrealized foreign currency translation gains (54,000) (19,000) (18,000)
Issuance of common stock for services -- -- 300,000
Changes in operating assets and liabilities:
Accounts receivable (1,952,000) 747,000 (4,580,000)
Other assets (39,000) (18,000) (45,000)
Accounts payable and accrued liabilities (1,149,000) 4,349,000 5,163,000
-------------- -------------- --------------
Net cash provided by (used in) operating activities (834,000) 9,504,000 1,041,000
INVESTING ACTIVITIES
Additions to oil and gas properties (7,410,000) (11,474,000) (154,242,000)
Proceeds from sales of oil and gas properties 3,551,000 10,024,000 --
Net additions to other property and equipment (15,000) (161,000) (100,000)
-------------- -------------- --------------
Net cash used in investing activities (3,874,000) (1,611,000) (154,342,000)
FINANCING ACTIVITIES
Proceeds from revolving credit facilities 26,898,000 12,300,000 103,000,000
Proceeds from (repayments on) bridge financing facilities -- (58,860,000) 58,860,000
Debt issuance costs (1,957,000) (4,665,000) (4,898,000)
Termination of LIBOR swap agreement -- (3,549,000) --
Payments on revolving credit facilities (16,398,000) (96,800,000) (15,358,000)
Proceeds from issuance of 12 1/2% Senior Notes -- 125,000,000 121,000
Costs of proposed recapitalization (1,066,000) -- --
Redemption of DEM bonds (213,000) -- --
Payments on notes payable -- (1,325,000) (2,064,000)
Proceeds from sale of convertible preferred stock and warrants to
purchase common stock -- -- 9,544,000
Proceeds from the issuance of common stock -- 30,674,000 4,886,000
Repurchase of common and preferred stock -- (2,251,000) --
Payments on capital lease obligation (42,000) (80,000) (70,000)
-------------- -------------- --------------
Net cash provided by financing activities 7,222,000 444,000 154,021,000
Net increase in cash 2,514,000 8,337,000 720,000
Cash at beginning of year 9,367,000 1,030,000 310,000
-------------- -------------- --------------
Cash at end of year $ 11,881,000 $ 9,367,000 $ 1,030,000
============== ============== ==============
</TABLE>
See accompanying notes.
F-7
<PAGE> 62
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.
F-8
<PAGE> 63
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.
F-9
<PAGE> 64
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).
F-10
<PAGE> 65
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.
F-11
<PAGE> 66
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.
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30
------------------------------------------
2000 1999 1998
------------ ------------ ------------
<S> <C> <C> <C>
Oil and gas sales $ 28,715,000 $ 29,071,000 $ 6,219,000
Production expenses 5,725,000 5,931,000 1,787,000
------------ ------------ ------------
Net profits and royalty interests $ 22,990,000 $ 23,140,000 $ 4,432,000
============ ============ ============
</TABLE>
F-12
<PAGE> 67
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:
<TABLE>
<CAPTION>
JUNE 30
---------------------------
2000 1999
------------ ------------
<S> <C> <C>
12 1/2% Senior Notes, due July 2008 $125,000,000 $125,000,000
12% unsecured DEM bonds, due July 2000 584,000 852,000
Revolving credit agreement 18,500,000 8,000,000
Capital lease obligations -- 42,000
------------ ------------
144,084,000 133,894,000
Less current portion of debt and capitalized lease 584,000 42,000
obligation
------------ ------------
Total long-term obligations $143,500,000 $133,852,000
============ ============
</TABLE>
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
F-13
<PAGE> 68
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.
F-14
<PAGE> 69
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.
<TABLE>
<CAPTION>
VOLUME
PERIOD BEGINNING PERIOD ENDING (MMBTU)
-------------------------------------------- ----------------- ---------
<S> <C> <C>
May 1, 1998................................. December 31, 1998 885,000
January 1, 1999............................. December 31, 1999 1,080,000
January 1, 2000............................. December 31, 2000 880,000
January 1, 2001............................. December 31, 2001 740,000
January 1, 2002............................. December 31, 2002 640,000
January 1, 2003............................. December 31, 2003 560,000
</TABLE>
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.
<TABLE>
<CAPTION>
VOLUME
PERIOD BEGINNING PERIOD ENDING (MMBTU)
--------------------------------------------- ----------------- ---------
<S> <C> <C>
May 1, 1998.................................. December 31, 1998 2,210,000
January 1, 1999.............................. December 31, 1999 2,710,000
January 1, 2000.............................. December 31, 2000 2,200,000
January 1, 2001.............................. December 31, 2001 1,850,000
January 1, 2002.............................. December 31, 2002 1,600,000
January 1, 2003.............................. December 31, 2003 1,400,000
</TABLE>
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.
<TABLE>
<CAPTION>
VOLUME FLOOR CEILING
PERIOD BEGINNING PERIOD ENDING (MMBTU) PRICE PRICE
------------------------------ ----------------- --------- ------ -------
<S> <C> <C> <C> <C>
May 1, 1998................... December 31, 1998 3,540,000 $2.00 $2.70
January 1, 1999............... October 31, 1999 3,608,000 2.00 2.70
</TABLE>
F-15
<PAGE> 70
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.
<TABLE>
<CAPTION>
VOLUME
PERIOD BEGINNING PERIOD ENDING (MMBTU)
-------------------------------------- ----------------- ---------
<S> <C> <C>
November 1, 1999...................... December 31, 1999 722,000
January 1, 2000....................... December 31, 2000 3,520,000
January 1, 2001....................... April 30, 2001 990,000
May 1, 2001........................... December 31, 2001 1,980,000
January 1, 2002....................... April 30, 2002 850,000
May 1, 2002........................... December 31, 2002 1,700,000
January 1, 2003....................... December 31, 2003 2,250,000
</TABLE>
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.
<TABLE>
<CAPTION>
VOLUME FLOOR CEILING
PERIOD BEGINNING PERIOD ENDING (MMBTU) PRICE PRICE
------------------------------ ----------------- ------- ------- ------
<S> <C> <C> <C> <C>
December 1, 1999.............. March 31, 2000 40,000 $22.90 $25.77
April 1, 2000................. June 30, 2000 15,000 $23.00 $28.16
July 1, 2000.................. December 31, 2000 30,000 $22.00 $28.63
</TABLE>
F-16
<PAGE> 71
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
F-17
<PAGE> 72
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
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
F-18
<PAGE> 73
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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.
F-19
<PAGE> 74
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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
F-20
<PAGE> 75
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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.
F-21
<PAGE> 76
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
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.
F-22
<PAGE> 77
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
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:
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30
----------------------------------------------------------------
2000 1999 1998
-------------------- ------------------- -------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at July 1 763,500 $ 6.87 173,000 $ 5.25 -- $ --
Granted -- -- 590,500 7.38 173,000 5.25
Exercised -- -- -- -- -- --
Canceled (34,500) 7.38 -- -- -- --
-------- -------- --------
Outstanding at June 30 729,000 $ 6.84 763,500 $ 6.87 173,000 $ 5.25
======== ======== ========
Exercisable options outstanding at
June 30 496,636 $ 6.67 96,500 $ 5.25 -- $ --
======== ======== ========
</TABLE>
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.
F-23
<PAGE> 78
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:
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
--------------------------------------------------
2000 1999 1998
-------------- -------------- --------------
<S> <C> <C> <C>
Pro forma net loss $ (10,106,000) $ (48,917,000) $ (32,928,000)
Loss per common share $ (0.23) $ (1.56) $ (1.45)
</TABLE>
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.
F-24
<PAGE> 79
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:
<TABLE>
<CAPTION>
2000 1999
------------ ------------
<S> <C> <C>
Deferred income tax assets (liabilities):
Reverse acquisition costs $ 21,000 $ 43,000
Net operating loss carryforwards 19,744,000 10,965,000
Statutory depletion carryforward 126,000 126,000
Oil and gas properties, principally due to differences in
depreciation and amortization 11,109,000 16,902,000
Other (221,000) (146,000)
------------ ------------
30,779,000 27,890,000
Less valuation allowance (30,779,000) (27,890,000)
------------ ------------
Net deferred income tax asset $ -- $ --
============ ============
</TABLE>
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.
F-25
<PAGE> 80
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
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:
<TABLE>
<CAPTION>
2000 1999 1998
------------ ------------ ------------
<S> <C> <C> <C>
Oil and gas sales $ 3,967,000 $ 4,591,000 $ 6,446,000
Net profits and royalty interests revenues 22,990,000 23,140,000 4,432,000
Production expenses (1,372,000) (3,196,000) (4,547,000)
Depreciation and amortization (8,452,000) (11,803,000) (4,736,000)
Write-down of oil and gas properties -- (35,033,000) (28,166,000)
------------ ------------ ------------
Results of operations (excludes corporate
overhead and interest expense) $ 17,133,000 $(22,301,000) $(26,571,000)
============ ============ ============
</TABLE>
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:
<TABLE>
<CAPTION>
2000 1999
-------------- --------------
<S> <C> <C>
Oil and gas properties - proved $ 182,280,000 $ 178,421,000
Accumulated depreciation and amortization (89,921,000) (81,469,000)
-------------- --------------
Net capitalized costs $ 92,359,000 $ 96,952,000
============== ==============
</TABLE>
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:
<TABLE>
<CAPTION>
2000 1999 1998
------------ ------------ ------------
<S> <C> <C> <C>
Property acquisition costs $ -- $ 580,000 $153,196,000
============ ============ ============
Development costs $ 6,198,000 $ 10,340,000 $ 6,031,000
============ ============ ============
</TABLE>
F-26
<PAGE> 81
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.
<TABLE>
<CAPTION>
OIL (Bbls) GAS (Mcf)
------------ ------------
<S> <C> <C>
Proved reserves:
Balance at June 30, 1997 6,709,000 20,973,000
Purchases of minerals in place 4,301,000 158,528,000
Revisions of previous estimates and other (2,736,000) (38,000)
Production (325,000) (3,368,000)
------------ ------------
Balance at June 30, 1998 7,949,000 176,095,000
Sales of minerals in place (2,735,000) (18,243,000)
Revisions of previous estimates and other (90,000) (7,329,000)
Production (500,000) (12,962,000)
------------ ------------
Balance at June 30, 1999 4,624,000 137,561,000
Sales of minerals in place (1,000) (7,752,000)
Revisions of previous estimates and other (2,389,000) 13,489,000
Production (224,000) (10,618,000)
------------ ------------
Balance at June 30, 2000 2,010,000 132,680,000
============ ============
Proved developed reserves:
Balance at June 30, 1997 2,188,000 12,412,000
============ ============
Balance at June 30, 1998 5,298,000 120,998,000
============ ============
Balance at June 30, 1999 2,138,000 94,614,000
============ ============
Balance at June 30, 2000 1,868,000 86,348,000
============ ============
</TABLE>
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.
F-27
<PAGE> 82
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
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:
<TABLE>
<CAPTION>
2000 1999
-------------- --------------
<S> <C> <C>
Future cash inflows $ 653,511,000 $ 415,013,000
Future costs and expenses:
Production expenses (171,740,000) (124,209,000)
Development costs (14,735,000) (18,811,000)
Future income taxes (95,642,000) (33,933,000)
-------------- --------------
Future net cash flows 371,394,000 238,060,000
10% annual discount for estimated timing of cash flows (198,539,000) (123,642,000)
-------------- --------------
Standardized measure of discounted future net cash flows $ 172,855,000 $ 114,418,000
============== ==============
</TABLE>
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:
<TABLE>
<CAPTION>
2000 1999 1998
-------------- -------------- --------------
<S> <C> <C> <C>
Beginning balance $ 114,418,000 $ 142,315,000 $ 30,146,000
Purchases of minerals in place -- -- 139,292,000
Sales of minerals in place (12,953,000) (16,035,000) --
Developed during the period 6,198,000 10,340,000 6,031,000
Net change in prices and costs 126,368,000 2,187,000 (15,593,000)
Revisions of previous estimates 13,225,000 (22,121,000) (13,784,000)
Accretion of discount 11,442,000 14,232,000 3,015,000
Net change in income taxes (61,709,000) 6,452,000 (461,000)
Sales of oil and gas produced, net of
production expenses (24,134,000) (22,952,000) (6,331,000)
-------------- -------------- --------------
Balance at June 30 $ 172,855,000 $ 114,418,000 $ 142,315,000
============== ============== ==============
</TABLE>
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.
F-28
<PAGE> 83
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
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)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
------------------------------------------------------------
SEPTEMBER 30 DECEMBER 31 MARCH 31 JUNE 30
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
YEAR ENDED JUNE 30, 2000
Total revenues $ 5,543,000 $ 6,653,000 $ 6,673,000 $ 8,231,000
Operating income $ 5,385,000 $ 6,533,000 $ 6,101,000 $ 7,709,000
Income (loss) before extraordinary
item $ (2,242,000) $ (4,258,000) $ (1,618,000) $ 190,000
Extraordinary loss $ -- $ (1,130,000) $ -- $ --
Net income (loss) $ (2,242,000) $ (5,388,000) $ (1,618,000) $ 190,000
Income (loss) before extraordinary
item per common share $ (0.07) $ (0.12) $ (0.04) $ 0.00
Net income (loss) per common share $ (0.07) $ (0.15) $ (0.04) $ 0.00
</TABLE>
<TABLE>
<CAPTION>
THREE MONTHS ENDED
------------------------------------------------------------
SEPTEMBER 30 DECEMBER 31 MARCH 31 JUNE 30
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
YEAR ENDED JUNE 30, 1999
Total revenues $ 7,353,000 $ 6,984,000 $ 6,734,000 $ 6,986,000
Write-downs of oil and gas
properties -- $(35,033,000) -- --
Operating income $ 6,188,000 $ 6,295,000 $ 6,015,000 $ 6,363,000
Loss before extraordinary item $ (2,104,000) $(37,678,000) $ (1,977,000) $ (2,183,000)
Extraordinary loss $ (3,549,000) -- -- --
Net loss $ (5,653,000) $(37,678,000) $ (1,977,000) $ (2,183,000)
Loss before extraordinary item per
common share $ (0.07) $ (1.25) $ (0.06) $ (0.07)
Net loss per common share $ (0.19) $ (1.25) $ (0.06) $ (0.07)
</TABLE>
F-29
<PAGE> 84
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C>
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.
</TABLE>
<PAGE> 85
<TABLE>
<S> <C>
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.
</TABLE>
<PAGE> 86
<TABLE>
<S> <C>
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.
</TABLE>
<PAGE> 87
<TABLE>
<S> <C>
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
</TABLE>
----------
* Filed herewith.
