<PAGE> 1
U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
----------------------
FORM 10-QSB
[x] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 1998
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File No. 0-21179
QUEEN SAND RESOURCES, INC.
(Exact Name of Small Business Issuer as specified in its charter)
Delaware 75-2615565
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
3500 Oak Lawn, Suite 380,
L.B. #31, Dallas, Texas, 75219-4398
(Address of Principal Executive offices) (Zip Code)
Issuer's Telephone Number, Including Area Code: (214) 521-9959
Check whether the issuer (1) filed all reports required to be filed by Section
13 or 15(d) of the Securities Exchange Act during the past 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 [_]
24,224,674 shares of the registrant's Common Stock were outstanding as of May
14, 1998
Transitional Small Business Disclosure Format: Yes [_] No [X]
<PAGE> 2
PART I - FINANCIAL INFORMATION
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
Consolidated Condensed Balance Sheets
(unaudited)
<TABLE>
<CAPTION>
March 31, June 30,
1998 1997
------------ ------------
<S> <C> <C>
Assets
Current assets:
Cash $ 1,136,695 $ 309,695
Accounts receivable and other current assets 1,416,366 756,092
------------ ------------
Total current assets 2,553,061 1,065,787
Deposit on oil and natural gas properties 15,000,000 --
Net property and equipment 30,466,047 16,187,209
Other assets 304,388 --
------------ ------------
$ 48,323,496 $ 17,252,996
============ ============
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable and other $ 2,490,970 $ 1,588,668
Current portion of long-term debt 120,138 2,080,897
------------ ------------
Total current liabilities 2,611,108 3,669,565
Long-term obligations, net of current portion 23,309,967 7,151,881
------------ ------------
Total liabilities 25,921,075 10,821,446
------------ ------------
Commitments
Stockholders' equity:
Preferred stock, $.01 par value 96,104 96,000
Common stock, $.0015 par value 49,812 45,635
Additional paid-in capital 32,579,720 14,474,844
Accumulated deficit (5,323,215) (3,184,929)
Treasury stock (5,000,000) (5,000,000)
------------ ------------
Total stockholders' equity 22,402,421 6,431,550
------------ ------------
$ 48,323,496 $ 17,252,996
============ ============
</TABLE>
See accompanying notes.
2
<PAGE> 3
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
Consolidated Condensed Statements of Operations
(unaudited)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
March 31 March 31
-------- --------
1998 1997 1998 1997
---- ---- ---- ----
<S> <C> <C> <C> <C>
Oil & Gas Revenues $1,507,387 $1,338,179 $4,849,281 $3,118,022
Expenses:
Oil and gas production expenses 1,108,734 648,318 3,182,642 1,632,129
Depreciation, depletion and amortization 469,250 290,000 1,340,000 747,000
General & administrative expenses 427,759 362,130 1,645,927 911,148
Interest and financing costs 259,635 230,149 898,791 655,677
Foreign currency exchange gains (64,664) (178,899) (79,793) (200,917)
------------ ------------ ------------ ------------
Net Loss ($693,327) ($13,519) ($2,138,286) ($627,015)
============ ============ ============ ============
Net Loss per Common Share ($0.03) ($0.00) ($0.09) ($0.02)
============ ============ ============ ============
Weighted average number of common
shares outstanding 22,400,009 29,007,546 23,610,660 27,796,918
============ ============ ============ ============
</TABLE>
See accompanying notes.
3
<PAGE> 4
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
Consolidated Condensed Statements of Cash Flows
(unaudited)
<TABLE>
<CAPTION>
Nine Months Ended March 31
--------------------------
1998 1997
---- ----
<S> <C> <C>
Cash flows from operating activities:
Net loss ($2,138,286) ($627,015)
Depreciation, depletion and amortization 1,340,000 747,000
Issuance of common stock for services rendered 300,000 0
Unrealized gains on foreign exchange obligations (51,009) (151,543)
Net changes in operating assets and liabilities (62,360) 101,476
------------ ------------
Net cash provided (used) in operating activities (608,608) 45,231
------------ ------------
Cash flows used in investing activities
Additions to property and equipment (25,788,818) (3,727,469)
Cash flows from financing activities:
Proceeds from long-term obligations 16,291,054 779,134
Payments on short-term notes (2,008,056) (850,000)
Payments on capital lease obligations (52,078) (44,379)
Proceeds from the sale of capital stock 12,996,553 3,485,500
------------ ------------
Net cash provided by financing activities 27,227,473 3,370,255
------------ ------------
Net increase (decrease) in cash 827,000 (287,296)
Cash at beginning of period 309,695 599,621
------------ ------------
Cash at end of period $1,136,695 $312,325
============ ============
</TABLE>
See accompanying notes.
4
<PAGE> 5
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
Notes to Consolidated Condensed Financial Statements
March 31, 1998
(unaudited)
(1) General
The information furnished reflects all adjustments (consisting solely of
normal recurring accruals) which are, in the opinion of management,
necessary to a fair presentation of the consolidated financial position of
Queen Sand Resources, Inc. (the "Company") as of June 30, 1997 and March
31, 1998 and the results of operations for the three and nine month
periods ended March 31, 1998 and 1997 respectively, and the cash flows for
the nine month periods ended March 31, 1998 and 1997. The results of
operations for the three and nine months ended March 31, 1998 are not
necessarily indicative of the operating results for the full fiscal year
ending June 30, 1998. Moreover, these financial statements do not purport
to contain complete disclosure in conformity with generally accepted
accounting principles and should be read in conjunction with the Company's
audited financial statements at, and for the fiscal year ended June 30,
1997.
(2) Common Stock
In 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 128, Earnings per Share. Statement 128
replaced the previously reported primary and fully diluted earnings per
share with basic and diluted earnings per share. Unlike primary earnings
per share, basic earnings per share excludes any dilutive effects of
options, warrants, and convertible securities. Diluted earnings per share
is very similar to the previously reported fully diluted earnings per
share. All earnings per share amounts for all periods presented have been,
where necessary, restated to confirm to the Statement 128 requirements.
During the nine months ended March 31, 1998 the Company issued 350,000 and
200,000 shares of common stock pursuant to Regulation S for $1,067,500 and
$700,000 ($3.05 and $3.50 per share), respectively. The Company issued
500,000 shares of common stock pursuant to Regulation S for $500,000
($2.50 per share) as a result of the exercise of 500,000 `A' Warrants. The
Company also issued 247,608 shares of common stock pursuant to Section
4(2) of the Securities Act of 1933 for $619,020 ($2.50 per share) related
to the exercise of certain anti-dilution rights by Joint Energy
Development Investments Limited Partnership ("JEDI") arising from the
exercise of the 500,000 `A' Warrants. The Company issued 1,000,000 shares
of common stock valued at $3,125,000 ($3.125 per share) as partial
consideration for the acquisition of oil and natural gas producing
properties in New Mexico, Oklahoma and Texas (see Note 4). The Company
issued 337,500 shares of common stock valued at $1,687,500 ($5.00 per
share) as partial consideration for the acquisition of natural gas
producing properties in Kentucky (see Note 4). The Company issued 150,000
restricted shares of common stock in consideration of services rendered,
which it valued at $2.00 per share ($300,000).
5
<PAGE> 6
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
Notes to Consolidated Condensed Financial Statements
March 31, 1998
(unaudited)
(3) Hedging Activities
The Company has entered into agreements with Enron Capital & Trade
Resources Corp. ("Enron"), an affiliate of JEDI, the holder of 9.6 million
shares of the Company's Series A Participating Convertible Preferred
Stock, to hedge 50,000 MMBtu of natural gas production and 10,000 barrels
of oil production monthly. The agreements, which were effective September
1, 1997, and terminate August 31, 1998, call for a gas and oil ceiling and
floor price of $2.66 and $1.90 per MMBtu of natural gas and $20.40 and
$18.00 per barrel of crude oil, respectively. If the average market price
of oil and gas per month, as defined in the agreements, exceeds the
ceiling price, the Company must pay Enron an amount equal to one-half of
the amount of the hedged quantities multiplied by the difference between
the ceiling price and the market price. If the average market price, as
defined, falls below the floor price, Enron will pay the Company an amount
equal to the amount of the hedged quantities multiplied by the difference
in the floor price and the market price. Pursuant to these hedging
agreements, the Company received cumulative net payments from Enron of
$74,000 as a result of crude oil prices below the floor price in the
agreement during the three months ended March 31, 1998.
(4) Acquisitions
On August 1, 1997 (with an effective date of February 1, 1997) the Company
acquired from Collins & Ware, Inc. 77 productive wells (12.35 net
productive wells) located in various counties in New Mexico, Oklahoma and
Texas. In consideration for these properties the Company paid, subject to
standard industry adjustments at closing, approximately $6,000,000 in cash
and issued 1,000,000 restricted shares of its common stock which it
valued, for purposes of this transaction, at $3.125 per share
($3,125,000).
On March 9, 1998 (with an effective date of January 1, 1998) the Company
acquired 21 productive wells (12.6 net productive wells) and 61,421 acres
(36,858 net acres) in Kentucky. In consideration for these properties the
Company paid, subject to standard industry adjustments at closing,
approximately $450,000 in cash and issued 337,500 shares of its common
stock which it valued, for purposes of this transaction, at $5.00 per
share ($1,687,500).
On March 20, 1998 the Company provided a $15 million deposit pursuant to
the pending acquisition of certain oil and natural gas properties. This
acquisition was completed on April 20, 1998 (see Note 5).
(5) Subsequent Events
On April 17, 1998 the Company amended and restated its Senior Credit
Agreement with the Bank of Montreal to provide for a maximum borrowing of
$125 million. The borrowing base is set at $96 million. On April 17, 1998
the Company entered into a Variable Rate Senior Second Secured Note
Purchase Agreement in the amount of $30 million and a Variable Rate Senior
Third Secured Equity Bridge Note Purchase Agreement with three Lenders,
also in the amount of $30 million.
On April 20, 1998 the Company acquired certain non-operated net profits
interests and royalty interests for gross cash consideration of $150
million plus related costs of approximately $4 million (currently
estimated to be approximately $130 million after adjustments for
production and capital expenditures since October 1, 1997, the effective
date of the purchase) from pension funds managed by J.P. Morgan
6
<PAGE> 7
Investments (the "Morgan Property Acquisition"). The oil and natural gas
properties are primarily located in East Texas, South Texas and the
Mid-Continent region of the United States. The Company used $92 million of
the proceeds of the Senior Credit Agreement, $30 million under the
Variable Rate Senior Second Secured Note Purchase Agreement and $30
million under the Variable Rate Senior Third Secured Equity Bridge Note
Purchase Agreement to fund this acquisition.
On April 22, 1998 the Company entered into a commodity price swap contract
with Enron, an affiliate of a Company shareholder, JEDI, for approximately
25% of the Company's expected natural gas production between May 1, 1998
and December 31, 2003,at a price of $2.40 per MMBTU. The Company also
entered into a floor contract with Enron for approximately 10% of the
Company's expected natural gas production between May 1, 1998 and December
31, 2003 at a floor price of $1.90 per BTU. On April 23, 1998 the Company
entered into a non-participating collar contract with the Bank of Montreal
for approximately 40% of its expected natural gas production between May
1, 1998 and December 31, 2003, with a floor price of $2.00 per MMBTU and
ceiling prices ranging from $2.70 to $2.90 per MMBTU.
On May 8, 1998 the Company entered into a ten year LIBOR swap transaction
with the Bank of Montreal at 6.30% on $125 million effective June 30,
1998.
7
<PAGE> 8
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
FORWARD-LOOKING STATEMENTS
All statements in this document concerning the Company other than purely
historical information (collectively "Forward-Looking Statements") reflect the
current expectation of management and are based on the Company's historical
operating trends, estimates of proved reserves and other information currently
available to management. These statements assume, among other things, (i) that
no significant changes will occur in the operating environment for the Company's
oil and gas properties, gas plants and gathering systems, and (ii) that there
will be no material acquisitions or divestitures. The Company cautions that the
Forward-Looking Statements are subject to all the risks and uncertainties
incident to the acquisition, development and marketing of, and exploration for,
oil and gas reserves. These risks include, but are not limited to, commodity
price risk, environmental risk, drilling risk, reserve, operations, and
production risks, regulatory risks and counterparty risk. Many of these risks
are described in the Company's Annual Report on Form 10-KSB for the fiscal year
ended June 30, 1997 filed with the Securities and Exchange Commission in
September 1997. The Company may make material acquisitions or dispositions,
enter into new or terminate existing oil and gas sales or hedging contracts, or
enter into financing transactions. None of these can be predicted with any
certainty and, accordingly, are not taken into consideration in the
Forward-Looking Statements made herein. For all of the foregoing reasons, actual
results may vary materially from the Forward-Looking Statements and there is no
assurance that the assumptions used are necessarily the most likely.
SELECTED FINANCIAL DATA
The following tables set forth selected financial data for the Company. The
financial data was derived from the consolidated financial statements of the
Company and should be read in conjunction with the Consolidated Financial
Statements and related Notes thereto included herein. The consolidated financial
statements for the three and nine month periods ended March 31, 1998 and 1997
reflect all adjustments which, in the opinion of the Company, are necessary for
a fair presentation of the results of operations and the financial position of
the Company. The results of operations for the three and nine months ended March
31, 1998 will not necessarily be indicative of the operating results for the
full fiscal year ending June 30, 1998.
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
March 31 March 31
-------------------------- --------------------------
1998 1997 1998 1997
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Operations Data:
Oil and Natural Gas Sales $1,507,387 $1,338,179 $4,849,281 $3,118,022
Oil and Natural Gas Production Expenses 1,108,734 648,318 3,182,642 1,632,129
----------- ----------- ----------- -----------
Net Oil and Natural Gas Revenues 398,653 689,861 1,666,639 1,485,893
Depreciation, Depletion and Amortization 469,250 290,000 1,340,000 747,000
General and Administrative Expenses 427,759 362,130 1,645,927 911,148
Interest and Financing Expense 259,635 230,149 898,791 655,677
Interest and Other Income (64,664) (178,899) (79,793) (200,917)
----------- ----------- ----------- -----------
Net Loss ($693,327) ($13,519) ($2,138,286) ($627,015)
=========== =========== =========== ===========
</TABLE>
8
<PAGE> 9
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
March 31 March 31
------------------ -----------------
1998 1997 1998 1997
<S> <C> <C> <C> <C>
Sales Data
Oil (Bbls) 60,531 42,145 184,562 100,611
Gas (Mcf) 244,370 163,261 736,058 366,182
Oil and Gas (BOE) 101,259 69,355 307,238 161,641
Average Sales Price
Oil (per Bbl) $16.60 $21.29 $17.19 $21.91
Gas (per Mcf) $ 2.06 $ 2.70 $ 2.28 $ 2.49
Per BOE $14.89 $19.30 $15.78 $19.29
Average Cost Data ($/BOE):
Production and operating costs $10.95 $ 9.35 $10.35 $10.10
Depreciation, Depletion and Amortization $ 4.63 $ 4.18 $ 4.36 $ 4.62
General and Administrative Expenses $ 4.22 $ 5.22 $ 5.36 $ 5.64
Interest and Financing Expense $ 2.56 $ 3.32 $ 2.93 $ 4.06
</TABLE>
The following discussion of the results of operations and financial condition
should be read in conjunction with the Consolidated Financial Statements and
related Notes thereto included herein.
RESULTS OF OPERATIONS
The Three Months Ended March 31, 1998 Compared To The Three Months Ended March
31, 1997
Revenues The Company's total revenues rose by $169,000 (13%) to $1,507,000 for
the three months ended March 31, 1998, from $1,338,000 for the comparable period
in 1997. This increase is a result of a 46% increase in the barrels of oil
equivalent ("BOEs") produced offset by a 22.8% decrease in selling prices.
The Company produced 60,531 barrels of crude oil during the three months ended
March 31, 1998, an increase of 18,386 barrels (44%) over the 42,145 barrels
produced during the comparable period in 1997. This increase was comprised of a
decrease of 6,404 (27%) barrels from the properties that the Company owned
during both periods and an increase of 24,790 barrels from the properties
acquired during the period April 1, 1997 to March 31, 1998. The decrease in
production of crude oil from the properties owned during the comparative
quarters is primarily a reflection of natural depletion of the crude oil
producing reservoirs, and the temporary loss of production from certain
properties due to work-overs during the three months ended March 31, 1998.
The Company produced 244,370 Mcf of natural gas during the three months ended
March 31, 1998, an increase of 81,109 Mcf (50%) over the 163,261 Mcf produced
during the comparable period in 1997. This increase consists primarily of 80,687
Mcf from the properties acquired during the period from April 1, 1997 to March
31, 1998. The increase in production from the properties owned during the
comparative quarters is a result of the successful work-over of certain
producing and non-producing wells, off-set by the natural depletion of the
natural gas producing reservoirs.
The average selling price of oil was $16.60 per bbl for the three months ended
March 31, 1998, compared to $21.29 per bbl in the comparable period in 1997.
This decrease of $4.69 per bbl (22%) is a result of general decreases in oil
prices. The average selling price of natural gas was $2.06 per Mcf for the three
months ended March 31, 1998, compared to $2.70 per Mcf in the comparable period
in 1997. This decrease of $0.64 per Mcf (24%) is a result of general decreases
in natural gas prices during the three months ended March 31, 1998.
9
<PAGE> 10
Production Expenses The Company's lease operating expenses ("LOEs") rose to
$1,109,000 for the three months ended March 31, 1998, an increase of $460,000
(71%) from the comparable period in 1997. This increase is a combination of the
46% increase in production and an increase in non-recurring LOEs. The average
LOE per BOE was $10.95 per BOE during the three months ended March 31, 1998, an
increase of $1.60 (17%) over the average LOE per BOE of $9.35 for the comparable
period in 1997. Recurring LOE's, those costs incurred in the normal operations
of the Company, were $751,000 during the three months ended March 31, 1998, or
$7.42 per BOE, as compared to $633,000, or $9.13 per BOE, during the comparable
period in 1997. This represents a $1.71 per BOE (19%) improvement. The Company
believes that this improvement per BOE is a result of improved efficiencies at
an operating level and the acquisition of properties with lower average
operating costs per BOE than those the Company has owned during the preceding
years. Non-recurring LOEs, which are work-over costs incurred to increase
production from existing producing reservoirs and thus are arguably more capital
in nature, which must be treated as expenses under the Securities and Exchange
Commission accounting rules, were $358,000 ($3.53 per BOE) during the three
months ended March 31, 1998, as compared to only $15,000 ($0.22 per BOE) during
the comparable period in 1997. This $343,000 increase in non-recurring LOEs is
consistent with the Company's strategy of redeveloping its properties to
increase production, the objective of which is to increase production and reduce
the LOE per BOE. The Company believes that this program will have the desired
effect on production and LOEs over the long term.
Depreciation, Depletion and Amortization Expense Depreciation, depletion, and
amortization ("DD&A") costs were $469,000 for the three months ended March 31,
1998, an increase of $179,000 (62%) over the $290,000 recognized during the
comparable period in 1997. This increase relates primarily to the 46% increase
in BOE produced. The DD&A cost per BOE was $4.63 during the three months ended
March 31, 1998, an increase of $0.45 per BOE (11%) over the $4.18 per BOE for
the comparable period in 1997. While the depletion expense per BOE has remained
constant at $4.07 for the two comparable periods, the depreciation and
amortization expense for the three months ended March 31, 1998 has risen by
$0.45 per BOE to $0.56 per BOE compared to $0.11 per BOE for the comparable
period in 1997. This increase is related to the depreciation on the additional
office equipment required to support the increase in operations and the
amortization of the deferred financing costs associated with the Subordinated
Credit facility with Enron.
General and Administrative Costs The general and administrative costs of the
Company were $428,000 during the three months ended March 31, 1998, as compared
to $362,000 for the comparable period in 1997. This increase of $65,000 (18%) is
a result of the increased activity of the Company. On a cost per BOE produced
basis, general and administrative expenses were $4.22 per BOE, a decrease of
$1.00 per BOE from the $5.22 per BOE for the comparable period in 1997.
Interest Expense The Company incurred interest charges of $260,000 during the
three months ended March 31, 1998, compared to $230,000 for the comparable
period in 1997. This increase of $30,000 (13%) is a reflection of the increase
in the average interest bearing debt of the Company, from $6.8 million for the
three months ended March 31, 1997 to $9.2 million during the three months ended
March 31, 1998. This increase in the average interest bearing debt of $2.4
million was used primarily to finance a $15 million deposit related to the
Morgan Property Acquisition that closed on April 20, 1998.
The Nine Months Ended March 31, 1998 Compared To The Nine Months Ended March 31,
1997
Revenues The Company's total revenues rose by $1,732,000 (56%) to $4,849,000 for
the nine months ended March 31, 1998, from $3,118,000 for the comparable period
in 1997. This increase is a result of increases in both the BOE produced offset
by a decrease in selling prices.
The Company produced 184,562 barrels of crude oil during the nine months ended
March 31, 1998, an increase of 83,951 barrels (83%) over the 100,611 barrels
produced during the comparable period in 1997. This increase was comprised of a
decrease of 13,150 barrels (17%) from the properties that the Company owned
during both periods and an increase of 97,101 barrels from the properties
acquired during the period from April 1, 1997 to March 31, 1998. The decrease in
production of crude oil from the properties owned during the comparative nine
months is
10
<PAGE> 11
primarily a reflection of natural depletion of the crude oil producing
reservoirs, and the temporary loss of production from certain properties due to
work-overs during the nine months ended March 31, 1998.
The Company produced 736,058 Mcf of natural gas during the nine months ended
March 31, 1998, an increase of 369,876 Mcf (101%) over the 366,182 Mcf produced
during the comparable period in 1997. This increase was comprised of an increase
of 53,569 Mcf (18%) from the properties the Company owned during both periods
and an increase of 316,307 Mcf from the properties acquired during the period
from April 1, 1997 to March 31, 1998. The increase in production from the
properties owned during the comparative nine months is a result of the
successful drilling of four wells and the work over of certain producing and
non-producing wells, off-set by the natural depletion of the natural gas
producing reservoirs.
The average selling price of oil was $17.19 per bbl for the nine months ended
March 31, 1998, compared to $21.91 per bbl in the comparable period in 1997.
This decrease of $4.72 per bbl (22%) is a result of general decreases in oil
prices. The average selling price of natural gas was $2.28 per Mcf for the nine
months ended March 31, 1998, compared to $2.49 per Mcf in the comparable period
in 1997. This decrease of $0.21per Mcf (9%) is a result of general decreases in
natural gas prices during the nine months ended March 31, 1998.
Production Expenses The Company's lease operating expenses rose to $3,183,000
for the nine months ended March 31, 1998, an increase of $1,551,000 (95%) from
the comparable period in 1997. The increase is a combination of the 90% increase
in production and an increase in the LOE per BOE. The average LOE per BOE was
$10.35 per BOE during the nine months ended March 31, 1998, an increase of $0.25
(2%) over the average LOE per BOE of $10.10 for the comparable period in 1997.
Recurring LOEs, those costs incurred in the normal operations of the Company,
were $2,419,000 during the nine months ended March 31, 1998, or $7.87 per BOE,
as compared to $1,602,000, or $9.91 per BOE, during the comparable period in
1997. This represents a $2.04 per BOE (21%) improvement. The Company believes
that this improvement is a result of improved efficiencies at an operating level
and the acquisition of properties with lower average operating costs per BOE
than those the Company has owned during the preceding years. Non-recurring LOEs,
which are work over costs incurred to increase production from existing
producing reservoirs and thus are arguably more capital in nature, but must be
treated as expenses under the Securities and Exchange Commission accounting
rules, were $763,000 ($2.48 per BOE) during the nine months ended March 31,
1998, as compared to only $30,000 ($0.19 per BOE) during the comparable period
in 1997. This $733,000 increase in non-recurring LOE's is consistent with the
Company's strategy of redeveloping its properties to increase production, the
objective of which is to increase production and reduce the LOE per BOE. The
Company believes are that this program will have the desired effect on
production and LOEs over the long term.
Depreciation, Depletion and Amortization Expense Depreciation depletion, and
amortization (DD&A) costs were $1,340,000 for the nine months ended March 31,
1998, an increase of $593,000 (79%) over the $747,000 recognized during the
comparable period in 1997. This increase relates primarily to the 90% increase
in BOE produced. The DD&A cost per BOE was $4.36 during the nine months ended
March 31, 1998, a decrease of $0.26 per BOE (6%) over the $4.62 per BOE for the
comparable period in 1997. Depletion expense for the nine months ended March 31,
1998 was $4.07 per BOE as compared to $4.50 per BOE for the comparable period in
1997. This decrease of $0.43 per BOE (10%) in depletion expense per BOE is
primarily the result of a reduction in the expected future capital costs
required to bring the Company's reserves into production. The depreciation and
amortization expense for the nine months ended March 31, 1998 was $0.29 per BOE,
compared to $0.12 per BOE for the comparable period in 1997. This increase is
related to the depreciation on the additional office equipment required to
support the increase in operations and the amortization of the deferred
financing costs associated with the Subordinated Credit facility with Enron.
General and Administrative Costs The general and administrative costs of the
Company were $1,646,000 during the nine months ended March 31, 1998, as compared
to $911,000 for the comparable period in 1997. This increase of $735,000 (81%)
consists of an unusually high, one-time expense of $300,000 for financial public
relations services. The Company issued 150,000 restricted shares of its common
stock in consideration of these services. After adjusting for this item, general
and administrative expenses rose by $435,000 (48%). On a cost per BOE produced
basis, general and administrative expenses were $5.36 per BOE, a decrease of
$0.28 per BOE (5%)
11
<PAGE> 12
from the $5.64 per BOE for the comparable period in 1996. After adjusting for
the unusual item described above, general and administrative expenses were only
$4.38 per BOE.
Interest Expense The Company incurred interest charges of $899,000 during the
nine months ended March 31, 1998 compared to $656,000 for the comparable period
in 1997. This increase of $243,000 (37%) is a reflection of the increase in the
average interest bearing debt of the Company, from $7.0 million for the nine
months ended March 31, 1997 to $13.5 million during the nine months ended March
31, 1998. This increase in the average interest bearing debt of $6.5 million in
debt was used primarily to finance the acquisition of more than $9 million of
oil and gas producing properties and to fund a $15 million deposit a property
acquisition that closed on April 20, 1998.
LIQUIDITY AND CAPITAL RESOURCES
General The Company's general financial strategy is to use cash from operations
to service interest on the Company's indebtedness, to pay ongoing operating
expenses, and to contribute limited amounts toward further development of the
Company's 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 of those purposes.
The Company will continue to be dependent on external funding sources to carry
out its planned redevelopment and acquisition program. If such additional funds
are not available, the Company will be required to delay or reduce substantially
both of such activities.
Indebtedness
The changes to the indebtedness of the Company during and subsequent to the
three months ending March 31, 1998 are primarily the result of the Morgan
Property Acquisition.
Senior Credit Facility On April 17, 1998, the Company amended and restated its
Credit Agreement with the Bank of Montreal, as agent for the lenders party
thereto. The Credit Agreement provides for borrowings up to $96 million from
such lenders to, among other things, fund working capital, capital expenditures
and make additional acquisitions as and if appropriate opportunities are
identified. On March 20, 1998 the Company received approval from such lenders to
borrow up to $20 million under this revolving loan facility and on April 17,
1998, the Company received approval to borrow up to $96 million under the Credit
Agreement, of which $92 million was outstanding as of May 14, 1998. The proceeds
under the Credit Agreement have been used to fund the Morgan Property
Acquisition and to fund working capital needs, including capital expenditures.
The Credit Agreement matures on August 1, 2003. In the event of a default on the
indebtedness under the Credit Agreement, not subsequently waived by the bank, it
is unlikely that the Company would be able to continue its business.
Indebtedness incurred under the Credit Agreement generally bears interest under
various interest rate pricing options based upon a Federal Funds rate (plus
.5%), Prime Rate or LIBOR rate options. LIBOR rate loans bear an applicable
margin over the LIBOR rate of (i) 2.25%, if the greater than 90% of the
available Borrowing Base has been drawn, (ii) 2%, if greater than 75% and not
more than 90% of the available Borrowing Base has been drawn, (iii) 1.5%, if
greater than 40% but not more than 75% of the available Borrowing Base has been
drawn, and (iv) 1%, if not more than 40% of the available Borrowing Base has
been drawn. The Company has a LIBOR contract on $152 million for the period
April 20, 1998 to May 20, 1998 of 5.65625%. The LIBOR rate is subject to change
on each reset date. The next reset date is May 20, 1998. There is no margin
applicable for base rate pricing options.
The Credit Agreement is secured by a first lien on the oil and natural gas
properties of the Company and the stock of two subsidiaries of the Company. In
addition, Resourcesthe Company and its operating subsidiaries (other than Queen
Sand Resources, Inc. a Nevada corporation ("QSRn") which is the borrower)
entered into guaranty agreements guaranteeing the repayment of the indebtedness
under the Credit Agreement.
Pursuant to the Credit Agreement, the Company is subject to certain affirmative
and negative financial and operating covenants that are usual and customary for
transactions of this nature. The affirmative covenants
12
<PAGE> 13
include, but are not limited to, covenants to (i) provide annual audited and
unaudited interim financial information, (ii) provide notices of the occurrence
of certain material events affecting the Company, (iii) maintain and preserve
its existence and oil and gas properties and other material properties, (iv)
implement and comply with certain environmental procedures, (v) perform its
obligations under the Credit Agreement, (vi) provide reserve reports, (vii)
deliver certain title information, (viii) grant a security interest in oil and
gas properties that are not currently subject to a lien under the Credit
Agreement such that the mortgaged property includes at least 85% (with an
obligation to use reasonable efforts to maintain 95%) of the SEC PV-10 of the
Company's total proved reserves, and (ix) deliver certain information relating
to compliance with ERISA laws and regulations. The negative covenants include,
but are not limited to, covenants (i) not to incur any indebtedness except as
expressly permitted under the Credit Agreement, (ii) not to make any loans or
advances to or investments in any person except as expressly permitted under the
Credit Agreement, (iii) (with respect to the Company) not to declare or pay any
dividends or redeem or otherwise acquire for value any capital stock of the
Company except for stock dividends and certain permitted repurchases of Series C
Preferred Stock (defined below), (iv) not to enter into sale and leaseback
transactions, (v) not to materially change the character of its business as an
independent oil and natural gas exploration and production company, (vi) not to
enter into lease agreements except as expressly permitted under the Credit
Agreement, (vii) not to merge with or sell all or substantially all of its
property or assets to any other person; (viii) not to permit the borrowed
proceeds under the Credit Agreement to be used for any purpose except as
expressly permitted under the Credit Agreement, (viii) not to violate ERISA laws
and regulations, (ix) not to discount or sell any notes or accounts receivable,
(x) to maintain a working capital ratio of at least 1.0 to 1.0, (xi) to maintain
a tangible net worth of at least $18.5 million plus the amount equal to 75% of
the net proceeds of any equity offering, (xii) to pay its trade accounts payable
when due, (xiii) maintain a fixed charge coverage ratio of at least 1.5 to 1.0,
(xiii) not to violate environmental laws and regulations, (xiv) not to enter
into transactions with affiliates other than those entered into in the ordinary
course of business on fair and reasonable terms, (xv) not to create any
additional subsidiaries or issue stock of any subsidiaries, (xvi) not to enter
into negative pledge agreements, (xvii) not to enter into any contracts which
warrant production of oil and natural gas and not allow gas imbalances,
take-or-pay or other prepayments which would require the delivery of oil or
natural gas at some future time without receiving full payment therefor to
exceed 5% of the current aggregate monthly gas production from the mortgaged oil
and natural gas properties, (xviii) not to amend or modify any material
agreements, (xix) not to repay other indebtedness except as expressly permitted
under the Credit Agreement and (xx) not make or pay capital expenditures more
than specified amounts.
The Credit Agreement also contains usual and customary events of default and
provides remedies to the lenders in the event of default. The events of default
include (i) default in payment when due of any principal of or interest on
indebtedness under the Credit Agreement, (ii) default in payment when due of any
principal of or interest on any other indebtedness aggregating $500,000 or more
or an event shall occur which requires the Company to mandatorily redeem any
Preferred Stock, (iii) breach of a representation and warranty under the Credit
Agreement, (iv) default in performance of obligations under the Credit
Agreement, (v) the Company shall admit in writing its inability to pay debts as
they become due, (v) voluntary or involuntary bankruptcy, (vi) a judgment in
excess of $100,000 shall be entered and not vacated within 30 days, (vii) the
security agreements under the Credit Agreement shall cease to be in full force
and effect and (viii) the Company discontinues its usual business or any person
or group of persons (other than JEDI, Enron or its affiliates) shall have
acquired beneficial ownership of 30% or more of the outstanding shares of voting
stock of the Company or individuals who constitute the Board of Directors of the
Company cease to constitute a majority of the then-current Board of Directors of
the Company. Although the Company believes that its cash flows and available
sources of financing will be sufficient to satisfy the interest payments on its
debt at currently prevailing interest rates and oil and natural gas prices, the
Company's level of debt may adversely affect the Company's ability: (i) to
obtain additional financing for working capital, capital expenditures or other
purposes, should it need to so do; or (ii) to acquire additional oil and natural
gas properties or to make acquisitions utilizing new borrowings. There can be no
assurances that the Company will be able to obtain additional financing, if
required, or that such financing, if obtained, will be on terms favorable to the
Company.
Note Purchase Agreement
On April 17, 1998, the Company entered into a Note Purchase Agreement, with the
Bank of Montreal, Enron and Joint Energy Development Investments II Limited
Partnership (("JEDI II"), an affiliate of Enron, respectively (Bank of Montreal,
Enron and JEDI II are referred to collectively as the ("Purchaser") in respect
of the issuance, by QSRn, of $30 million aggregate principal amount of Variable
Rate Senior Second Secured Notes due 2003.
13
<PAGE> 14
Pursuant to the Note Purchase Agreement, the Company borrowed $20 million from
Bank of Montreal, $5 million from Enron and $5 million from JEDI II. The
facility under the Note Purchase Agreement was established to provide bridge
financing to allow the Company to consummate the Morgan Property Acquisition. As
of May 14, 1998, $30 million was outstanding under the Note Purchase Agreement.
The notes issued pursuant to the Note Purchase Agreement are subject to payment
of interest at a varying rate per annum equal to LIBOR plus 4% through July 17,
1998, LIBOR plus 5% thereafter through August 17, 1998, LIBOR plus 6% thereafter
through October 17, 1998 and the interest rate is fixed at 14% per annum
thereafter if the Company elects to extend such notes as described below. The
notes are secured by a second lien on certain of the Company's oil and natural
gas properties.
Pursuant to the Note Purchase Agreement, the Company is subject to certain
customary financial and operating covenants. The Company has granted the
Purchasers registration rights with respect to the resale of the notes.
The maturity date of the notes issued under the Note Purchase Agreement is
October 14, 1998, unless the Company pays each of the Purchasers an extension
fee equal to 2% of the then outstanding principal balance thereof. If the notes
issued under the Note Purchase Agreement are extended, then the Company may
repay the notes but upon such prepayment must pay a premium of 7% for
prepayments in 1998, which premium decreases over time to 0% in 2002 and after.
The Company will be in default under the notes if the Company is in default
under the terms of any indebtedness of $500,000 or more or there is a mandatory
redemption event with respect to the Company's outstanding preferred stock.
Equity Bridge Note Purchase Agreement
On April 17, 1998, the Company entered into an Equity Bridge Note Purchase
Agreement, with each of the Purchasers in respect of the issuance by QSRn of $30
million aggregate principal amount of Variable Rate Senior Third Secured Notes
due 2004. Pursuant to the Equity Bridge Note Purchase Agreement, the Company
borrowed $20 million from Bank of Montreal, $5 million from Enron and $5 million
from JEDI II. The facility under the Equity Bridge Note Purchase Agreement was
established to provide bridge financing to allow the Company to consummate the
Morgan Property Acquisition. As of May 14, 1998, $30 million was outstanding
under the Equity Bridge Note Purchase Agreement.
The notes issued pursuant to the Equity Bridge Note Purchase Agreement are
subject to payment of interest at a varying rate per annum equal to LIBOR plus
6% through July 17, 1998, LIBOR plus 7% thereafter through August 17, 1998,
LIBOR plus 8% thereafter through October 17, 1998 and the interest rate is fixed
at 16% per annum thereafter if the Company elects to extend such notes as
described below. The notes are secured by a lien on certain of the Company's oil
and natural gas properties; however, the notes are expressly subordinate in
right of payment to the indebtedness under the Credit Agreement and the notes
issued under the Note Purchase Agreement.
Pursuant to the Equity Bridge Note Purchase Agreement, the Company is subject to
certain customary financial and operating covenants.
In connection with the transactions contemplated under the Equity Bridge Note
Purchase Agreement, the Company entered into a Warrant Agreement with the
Purchasers pursuant to which the Company issued a warrant to each of the
Purchasers. Each of the Purchasers has warrants to purchase, subject to the
satisfaction of certain conditions precedent, (i) a proportionate share of 2% of
the outstanding shares of the Company's Common Stock on a fully diluted basis,
multiplied by the percentage of indebtedness outstanding under the notes on July
20, 1998, (ii) a proportionate share of an additional 2% of the outstanding
shares of the Company's Common Stock on a fully diluted basis, multiplied by the
percentage of indebtedness outstanding under the notes on August 16, 1998 and
(iii) a proportionate share of an additional 10% of the outstanding shares of
the Company's Common Stock on a fully diluted basis multiplied by the percentage
of indebtedness outstanding under the notes on October 21, 1998. The purchase
price for the exercise of the warrants is $0.0015 per share. The exercise price
and the number of shares of Common Stock for which the warrants are exercisable
are subject to customary adjustments. The warrants will be null and void if all
of the indebtedness under the notes is repaid in full before July 20, 1998.
14
<PAGE> 15
The Company also granted registration rights to the Purchasers with respect to
the resale of Common Stock issuable pursuant to the warrants. The Purchasers
have one demand registration right and in addition, the Purchasers may demand
that the Company register the Common Stock for resale on a Form S-3 Registration
Statement up to three times. The Company also granted unlimited piggyback
registration rights to the Purchasers with respect to the resale of the Common
Stock issuable pursuant to the warrants.
The maturity date of the notes issued under the Equity Bridge Note Purchase
Agreement is October 21, 1998, unless the Company pays each of the Purchasers an
extension fee equal to 4% of the then outstanding principal balance thereof. If
the notes issued under the Equity Bridge Note Purchase Agreement are extended,
then the Company may repay the notes but upon such prepayment must pay a premium
of 7% for prepayments in 1998, which premium decreases over time to 0% in 2002
and after.
The Company will be in default under the notes if the Company is in default
under the terms of any indebtedness of $500,000 or more or there is a mandatory
redemption event with respect to the Company's outstanding pPreferred stock.
Subordinated Credit Facility Effective December 29, 1997, the Company
established a Subordinated Revolving Credit Facility (the "Subordinated Credit
Facility") with ("Enron")ECTEnron, as a lender and as agent for the lenders
thereto, to fund capital costs incurred with future development projects and to
fund further acquisitions. The Subordinated Credit Facility is subordinate to
the Senior Credit Facility, the Variable Rate Senior Second Secured Notes due
2003 and the Variable Rate Senior Third Secured Equity Bridge Notes due 2004.
The Subordinated Credit Facility provides for borrowings up to $10.0 million,
subject to borrowing base limitations, which has been initially set at an amount
equal to forty percent (40%) of the borrowing base established from time to time
under the Senior Credit Facility. This facility is intended to provide bridge
financing for development projects and acquisitions to be completed on
relatively short notice or until the affected assets are eligible to be included
in the borrowing base for the Senior Credit Facility or financed with
longer-term indebtedness or equity capital; provided, that the availability for
acquisitions under the facility is limited to the lesser of $5,000,000 or the
borrowing base as in effect from time to time. The Company had borrowed $1
million on March 20, 1998, all of which was repaid on April 20, 1998. The
Company does not have any borrowings under this facility as of May 14, 1998 and
is not allowed to draw any funds under this facility due until such time as the
Variable Rate Senior Second Secured Notes 2003 and Variable Rate Senior Third
Secured Notes due 2004 are repaid in their entirety. Borrowings in excess of
certain amounts under the Subordinated Credit Facility will reduce the available
borrowing base under the Senior Credit Facility. The loan is secured by a fourth
priority lien and security interest (behind the first lien position of the
Senior Credit Facility, the Variable Rate Senior Second Secured Notes due 2003
and the Variable Rate Senior Third Secured Equity Bridge Notes due 2004.) in
approximately eighty-five percent (85%) of the oil and gas properties of the
Company.
The Subordinated Credit Facility is subject to payment of interest at a
fluctuating rate per annum equal to: (i) the rate of one percent (1%) above the
then highest rate of interest being paid on any portion of the indebtedness owed
under the Senior Credit Facility; or (ii) the rate of fifteen percent (15%),
depending upon whether there is any indebtedness owed under the Senior Credit
Facility outstanding or whether there has been a certain amount of indebtedness
owed to Enron for certain time periods
The maturity date for the Subordinated Credit Facility is the earlier of
December 30, 2002 or the date that is 60 days after the Company receives written
notice that the lenders and their affiliates beneficially own in the aggregate
less than ten percent (10%) of the capital stock of the Company entitled to vote
in the election of directors. From March 31, 1998 through the maturity date, the
Company will pay interest on the outstanding loans at quarterly intervals, on
the last business day of every March, June, September and December. In addition,
the Subordinated Credit Facility provides for certain voluntary prepayments and
certain mandatory prepayments of amounts borrowed under the facility.
The Company paid an affiliate of Enrona fee of $200,000 in connection with the
arrangement of the Subordinated Credit Facility. In addition, commencing March
31, 1998, and on each payment date thereafter, the Company is obligated to pay
Enron, for the account of each lender under the Subordinated Credit Facility, a
fee of 3/8% per annum on the daily average of the unadvanced portion of the
facility for the period since January 12, 1998 or the previous payment date to
such payment date.
15
<PAGE> 16
The Company is subject to various covenants under the Subordinated Credit
Facility, which covenants are substantially similar to the covenants described
above with respect to the Senior Credit Facility. In addition to the covenants,
the Subordinated Credit Facility contains representations, warranties, covenants
and default provisions customary for a facility of this type.
Regulation S Bond Through May 14, 1998 the Company was engaged in the
distribution in Europe of Deutschemark denominated (DEM) 12% Bonds ("12% Bonds")
totaling DEM 3.95 million ($2.2 million). Under Regulation S of the Securities
Act, the Company is prohibited from selling these Bonds to U.S. persons (as
defined in Regulation S). The Company has discontinued its efforts to sell any
additional 12% Bonds.
The Company is obligated to make periodic interest payments (January 15 and July
15 of each year) and to repay the principal when it comes due on July 15, 2000
in DEM. All interest payments have been paid in full at the time they came due.
The funds generated by the Company from operations, which form the primary
source of funds to pay the interest, are denominated in $US. The source of funds
required to repay the principal outstanding on these bonds has not yet been
identified, since the bonds do not mature until July 15, 2000. The Company is
exposed to the risk that, upon repayment, the exchange rate between DEM and $US
may be less favorable than that which existed at the time that the bonds were
issued. This would result in the Company having to repay a larger amount of $US
than it received initially. Changes in the $US equivalent of the DEM bonds
arising from changes to the DEM:$US exchange rate are recognized monthly. At
March 31, 1998 the Company had recorded unrealized exchange rate gains of
approximately $348,000 (at June 30, 1997 $300,000). However, there are no
assurances that the Company will continue to realize gains related to favorable
changes in the DEM:$US exchange rates in the future. Unfavorable changes to the
DEM:$US exchange rate will result in the Company recording unrealized exchange
rate losses related to the changes as they occur. The Company believes it has
the opportunity to enter into arrangements to manage its DEM:$US exchange rate
risk. At this time, the Company has not entered into any such arrangements.
Private Placements of Equity Securities
In March 1998 the Company issued 337,500 shares of Common Stock pursuant to
Section 4(2) of the Securities Act of 1933, valued at $5.00 per share
($1,687,500), in partial consideration of certain natural gas producing
properties in Kentucky.
Between January 1 and March 31, 1998 the Company issued 248,608 shares of its
common stock to JEDI pursuant to its right of non-dilution. These common stock
issuances, for $2.50 per share ($619,020) were related to the 500,000 shares of
common stock issued on the exercise of the 500,000 Class A Warrants exercised
during the period. On May 5, 1998 the Company issued 614,064 shares of its
common stock to JEDI for $1.85 ($1,136,018) pursuant to the exercise of 614,064
warrants.
Between January 1 and March 31, 1998 the Company issued 500,000 shares of its
common stock to a "non-U.S. person" pursuant to the exercise of 500,000 Class A
Warrants for $2.50 per share ($1,250,000).
Other Sources
The Company intends to issue additional equity and debt securities to reduce the
outstanding balance on the Credit Agreement with the Bank of Montreal and to
repay in their entirety the Variable Rate Senior Second Secured Notes due 2003
and the Variable Rate Senior Third Secured Notes due 2003 and the Variable Rate
Senior Third Secured Notes due 2004. There can be no assurances that the Company
can complete these private equity and debt placements. The Company does not have
sufficient liquidity or capital to undertake all potential acquisition prospects
or to fund fully the development of any prospect. Therefore, the Company 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 the Company has been
able to obtain such financings and to enter into such sharing arrangements in
certain of its projects to date, there can be no assurance that it will continue
to be able to
16
<PAGE> 17
do so. Alternatively, the Company 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
the Company's 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
the Company is contractually obligated are discretionary and depend exclusively
on cash availability from outside sources such as bank debt and the sale of
securities or properties.
Commodity Price and Interest Rate Hedges
The Company entered into agreements with Enron to hedge 50,000 MMBtu of natural
gas production and 10,000 barrels of oil production monthly. The agreements,
which are effective September 1, 1997, and terminate August 31, 1998, call for a
gas and oil ceiling and floor price of $2.66 and $1.90 per MMBtu of natural gas
and $20.40 and $18.00 per barrel of crude oil, respectively. If the average
market price of oil and gas per month, as defined in the agreements, exceeds the
ceiling price, the Company must pay Enron an amount equal to one-half of the
amount of the hedged quantities multiplied by the difference between the ceiling
price and the market price. If the average market price, as defined, falls below
the floor price, Enron will pay the Company an amount equal to the amount of the
hedged quantities multiplied by the difference in the floor price and the market
price. Pursuant to these hedging agreements, the Company received cumulative net
payments from Enron of $74,000 as a result of crude oil prices below the floor
price in the agreement during the three months ended March 31, 1998.
Effective May 1, 1998 through December 31, 2003 the Company is under two
separate contracts with Enron regarding the hedging a portion of its future
natural gas production.
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>
Period Beginning Period Ending Volume
(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>
Period Beginning Period Ending Volume
(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 December 31, 2003 the Company has a contract
involving the hedging of a portion of its 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.
17
<PAGE> 18
<TABLE>
<CAPTION>
Period Beginning Period Ending Volume Floor Ceiling
(MMBTU) Price Price
<S> <C> <C> <C> <C>
May 1, 1998 December 31, 1998 3,540,000 $2.00 $2.70
January 1, 1999 December 31, 1999 4,330,000 $2.00 $2.70
January 1, 2000 December 31, 2000 3,520,000 $2.00 $2.70
January 1, 2001 April 30, 2001 990,000 $2.00 $2.70
May 1, 2001 December 31, 2001 1,980,000 $2.00 $2.80
January 1, 2002 April 30, 2002 850,000 $2.00 $2.80
May 1, 2002 December 31, 2002 1,700,000 $2.00 $2.90
January 1, 2003 December 31, 2003 2,250,000 $2.00 $2.90
</TABLE>
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 6.30% on $125 million.
This financial instrument can be unwound at any time at the option of the
Company.
Year 2000 Computer Issue
The Company's management has conducted a review of its information systems and
related data-processing activities to assess its exposure to the Year 2000
issue.
The Company currently uses Year 2000 compliant accounting software and
engineering evaluation software for acquisition analysis, as well as internal
engineering applications. The Company's spreadsheet and word processing software
is also Year 2000 compliant.
The Company has potential Year 2000 exposure with regard to its third party
relationships and services including its bank and bank accounts and other vendor
and/or service providers who utilize computers. Though the Company has no
control over Year 2000 compliance implementation by these parties, the Company
has inquired and been assured that all of the Company's service providers are
currently or will be Year 2000 compliant.
18
<PAGE> 19
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
None
Item 2. Changes in Securities and Use of Proceeds
Issuance of Notes On April 20, 1998 the Company's wholly owned subsidiary, QSRn,
issued to certain institutional lenders secured debt obligations (see part I -
Item 2. Management's Discussion and Analysis - Plan of Operations - Liquidity
and Capital Resource - "Notes Purchase Agreement" and "Equity Bridge Note
Agreement" for a description of these securities).
Issuance of Common Stock On March 9, 1998 the Company issued 337,500 shares of
common stock pursuant to Section 4(2) of the Securities Act of 1933, valued at
$5.00 per share ($1,687,500), in partial consideration for certain natural gas
producing properties in Kentucky.
Item 3. Defaults Upon Senior Securities
None
Item 4. Submission of Matters to a Vote of Security Holders
None
Item 5. Other information
None
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
None
(b) Reports on Form 8-K
1. Current Report on Form 8-K dated March 3, 1998 disclosing certain
matters under Item 9.
2. Current Report on Form 8-K dated March 19, 1998, as amended by Form
8-K A-1, dated April 17, 1998, reporting a matter under items 2 and
7.
19
<PAGE> 20
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934 the
registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
QUEEN SAND RESOURCES, INC.
By: /s/ Edward J. Munden
------------------------------------------
Edward J. Munden
Chairman of the Board, President and Chief
Executive Officer
By: /s/ Ronald I. Benn
------------------------------------------
Ronald I. Benn
Chief Financial Officer
Date: May 15, 1998
20
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> JUN-30-1997
<PERIOD-START> JUL-01-1997
<PERIOD-END> MAR-31-1998
<CASH> 1,136,695
<SECURITIES> 0
<RECEIVABLES> 1,416,366
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 2,553,061
<PP&E> 30,466,047
<DEPRECIATION> 0
<TOTAL-ASSETS> 48,323,496
<CURRENT-LIABILITIES> 2,611,108
<BONDS> 23,309,967
0
96,104
<COMMON> 49,812
<OTHER-SE> 22,256,505
<TOTAL-LIABILITY-AND-EQUITY> 48,323,496
<SALES> 4,849,281
<TOTAL-REVENUES> 4,849,281
<CGS> 1,108,734
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 1,091,980
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 259,635
<INCOME-PRETAX> 0
<INCOME-TAX> 0
<INCOME-CONTINUING> (693,327)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (693,327)
<EPS-PRIMARY> (0.03)
<EPS-DILUTED> 0
</TABLE>
