<PAGE> 1
U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
----------
FORM 10-Q
---------
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED DECEMBER 31, 1999
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ___ TO ___
Commission File No. 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 ROAD, SUITE 1030
L.B. #31, DALLAS, TEXAS 75240-7336
(Address of principal executive offices)(Zip code)
(REGISTRANTS' TELEPHONE NUMBER, INCLUDING AREA CODE) (972) 233-9906
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 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 [ ]
APPLICABLE ONLY TO CORPORATE ISSUERS: Indicate the number of shares outstanding
of each of the issuer's classes of common stock, as of February 9, 2000:
41,551,009
<PAGE> 2
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(UNAUDITED)
<TABLE>
<CAPTION>
DECEMBER 31, JUNE 30,
1999 1999
-------------- --------------
<S> <C> <C>
Assets
Current assets:
Cash $ 3,376,000 $ 9,367,000
Other current assets 5,186,000 4,652,000
-------------- --------------
Total current assets 8,562,000 14,019,000
Net property and equipment 95,982,000 97,198,000
Other assets 8,074,000 7,993,000
-------------- --------------
$ 112,618,000 $ 119,210,000
============== ==============
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable and accrued liabilities $ 11,049,000 $ 11,100,000
Current portion of long-term debt 877,000 42,000
-------------- --------------
Total current liabilities 11,926,000 11,142,000
Long-term obligations, net of current portion 134,106,000 133,852,000
Commitments
Stockholders' deficit:
Preferred stock, $.01 par value, authorized 50,000,000 shares:
issued and outstanding 9,604,248 and 9,604,698 shares at
December 31 and June 30, 1999, respectively 96,000 96,000
Common stock, $.0015 par value, authorized 100,000,000 shares:
issued and outstanding 36,965,830 and 33,442,210 shares at
December 31 and June 30, 1999, respectively 70,000 65,000
Additional paid-in capital 64,945,000 64,912,000
Accumulated deficit (91,274,000) (83,606,000)
Treasury stock (7,251,000) (7,251,000)
-------------- --------------
Total stockholders' deficit (33,414,000) (25,784,000)
-------------- --------------
$ 112,618,000 $ 119,210,000
============== ==============
</TABLE>
See accompanying notes to unaudited interim period
consolidated condensed financial statements.
Pg. 2
<PAGE> 3
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS SIX MONTHS
ENDED ENDED
DECEMBER 31 DECEMBER 31
1999 1998 1999 1998
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Revenues
Oil and gas revenues $ 1,423,000 $ 1,394,000 $ 1,782,000 $ 2,748,000
Net profits and royalties interests 5,167,000 5,590,000 10,330,000 11,515,000
Interest and other income 63,000 -- 85,000 66,000
------------ ------------ ------------ ------------
Total revenues 6,653,000 6,984,000 12,197,000 14,329,000
Expenses:
Oil and gas production expenses 120,000 688,000 279,000 1,853,000
General and administrative expenses 755,000 717,000 1,475,000 1,379,000
Interest and financing costs 4,517,000 4,421,000 9,153,000 8,918,000
Hedge contract termination costs (Note 4) 3,328,000 -- 3,328,000 --
Depreciation, depletion and amortization 2,191,000 3,893,000 4,461,000 6,928,000
Write-down of oil and gas properties -- 35,033,000 -- 35,033,000
------------ ------------ ------------ ------------
10,911,000 44,752,000 18,696,000 54,111,000
------------ ------------ ------------ ------------
Net loss from operations (4,258,000) (37,768,000) (6,499,000) (39,782,000)
Extraordinary losses (Note 5) (1,130,000) -- (1,130,000) (3,549,000)
------------ ------------ ------------ ------------
Net loss $ (5,388,000) $(37,768,000) $ (7,629,000) $(43,331,000)
============ ============ ============ ============
Net loss before extraordinary losses per
common share $ (0.12) $ (1.25) $ (0.19) $ (1.32)
Net loss per common share $ (0.15) $ (1.25) $ (0.22) $ (1.43)
Weighted average shares of common stock
outstanding during the period 35,476,000 31,190,000 34,659,000 30,317,000
</TABLE>
See accompanying notes to unaudited interim period
consolidated condensed financial statements.
Pg. 3
<PAGE> 4
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<TABLE>
<CAPTION>
SIX MONTHS ENDED DECEMBER 31,
1999 1998
-------------- --------------
<S> <C> <C>
Operating activities:
Net loss $ (7,629,000) $ (43,331,000)
Depletion, depreciation and amortization of oil and gas assets 4,348,000 6,758,000
Write-down of oil and gas properties -- 35,033,000
Amortization of deferred costs 1,980,000 738,000
Unrealized gains (losses) on foreign exchange obligations (126,000) 25,000
Net changes in operating assets and liabilities (585,000) 1,814,000
-------------- --------------
Net cash provided by (used in) operating activities (2,012,000) 1,037,000
-------------- --------------
Investing activities - additions to property and equipment (3,137,000) (7,392,000)
Financing activities:
Debt issuance costs (1,948,000) (4,385,000)
Proceeds from long-term obligations 12,792,000 125,000,000
Payments on long-term obligations (11,686,000) (142,385,000)
Payments on capital lease obligations -- (37,000)
Proceeds from the sale of preferred and common stock -- 32,423,000
Repurchase of Series C Preferred Stock for Treasury -- (2,251,000)
-------------- --------------
Net cash provided by (used in) financing activities (842,000) 8,365,000
-------------- --------------
Net increase (decrease) in cash (5,991,000) 2,010,000
Cash at beginning of period 9,367,000 1,029,000
-------------- --------------
Cash at end of period $ 3,376,000 $ 3,039,000
============== ==============
</TABLE>
See accompanying notes to unaudited interim period
consolidated condensed financial statements.
Pg. 4
<PAGE> 5
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
December 31, 1999
(unaudited)
(1) Basis of Presentation
The accompanying consolidated financial statements include the accounts
of Queen Sand Resources, Inc. and its wholly owned subsidiaries
(collectively, the "Company") after elimination of all significant
intercompany balances and transactions. The financial statements have
been prepared in conformity with generally accepted accounting principles
which require management to make estimates and assumptions that affect
the amounts reported in the financial statements and accompanying notes.
While management has based its assumptions and estimates on the facts and
circumstances currently known, final amounts may differ from such
estimates.
The interim financial statements contained herein are unaudited but, in
the opinion of management, include all adjustments (consisting only of
normal recurring entries) necessary for a fair presentation of the
financial position and results of operations of the Company for the
periods presented. The results of operations for the three and six months
ended December 31, 1999 are not necessarily indicative of the operating
results for the full fiscal year ending June 30, 2000. 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 Annual Report filed on Form 10-K
for the fiscal year ended June 30, 1999, as amended.
Subsequent to March 31, 1999, the Company determined that the costs
associated with the termination of a LIBOR interest rate swap agreement
in the first quarter of fiscal year 1999 should have been expensed upon
termination. Consequently, the interim financial information for the
first six months of 1999 has been restated from the information contained
in the Company's Form 10-Q for the three and six months ended December
31, 1998, as previously filed with the Securities and Exchange
Commission, as if the costs of the LIBOR interest rate swap termination
had been expensed during the first quarter.
In June 1997, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("FAS") No. 130, "Reporting
Comprehensive Income" ("FAS 130"), which established standards for
reporting and display of comprehensive income and its components in a
full set of general-purpose financial statements. 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 three and six months ended December 31, 1999 and 1998,
the Company's net income and comprehensive income were the same.
In June 1998, the FASB issued FAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("FAS 133") which established
accounting and reporting standards for derivative instruments, including
certain derivative instruments embedded in other contracts, and for
hedging activities. FAS 133 requires that an entity recognize all
derivatives as either assets or liabilities in the statement of financial
position and measure those instruments at fair value. The Company will
adopt the provisions of FAS 133 beginning July 1, 2000. The Company has
not yet determined what the effect of FAS 133 will be on the earnings and
financial position of the Company.
(2) Debt Issuance
During October 1999, the Company amended and restated its credit
agreement (the "Restated Credit Agreement") and new lenders were
substituted for the old Bank of Montreal lead lending group (the "Old
Credit Agreement"). The Restated Credit Agreement allows the Company to
borrow up to $25 million until March 31, 2000 and, if there has not been
an event of default during that period, $30 million thereafter. The loan
bears interest at prime plus 2% on loan balances under $25 million and
prime plus 4.5% on the loan balance if the amount outstanding is $25
million or greater. The Restated Credit Agreement matures on October 22,
2001. Pursuant to the Restated Credit Agreement, we are subject to
certain affirmative and negative financial
Pg. 5
<PAGE> 6
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
December 31, 1999
(unaudited)
(continued)
and operating covenants that are usual and customary for transactions of
this nature including maintaining a minimum interest coverage ratio of
1.0x, based on the last 12 months operating results. On October 28, 1999
the Company borrowed $12.8 million under the Restated Credit Agreement,
which was used as follows: (i) $8.0 million to retire the borrowings
under the Old Credit Agreement; (ii) $0.3 million to pay accrued interest
charges and outstanding fees to the former lenders; (iii) $3.3 million to
unwind the ceiling component of a hedging contract with Bank of Montreal;
and (iv) $1.2 million to fund the costs of the transaction. At December
31, 1999 there was $9.0 million outstanding under the Restated Credit
Agreement.
(3) Common Stock Issuance
During the three and six months ended December 31, 1999 the Company
issued 2,128,951 and 2,395,676 shares, respectively, of its common stock
pursuant to the repricing rights held by certain stockholders. In
addition, certain holders of the Company's Series `C' preferred stock
converted 40 and 450 shares, respectively, of the Series `C' preferred
stock into 99,423 and 1,039,817 shares, respectively, of the Company's
common stock. A further 8,170 and 88,129 shares, respectively, of the
Company's common stock was issued as a stock dividend in conjunction with
this conversion.
(4) Hedging Activities
During the three and six months ended December 31, 1999 the Company paid
$3,000 and $361,000, respectively, in cash settlements on its crude oil
hedges and $139,000 and $367,000 in cash settlements on its natural gas
hedges and amortized $27,000 and $54,000, respectively, of deferred
natural gas hedging costs. In conjunction with the execution of the
Restated Credit Agreement in October 1999 (see note 2), the Company
terminated the ceiling portion of one of its natural gas hedge contracts
at a cost of $3.3 million. At December 31, 1999 the Company had a letter
of credit in the amount of $2.6 million outstanding ($1.8 million at
February 9, 2000) to secure a swap exposure.
(5) Extraordinary Losses
During October 1999 the Company retired the borrowings under the Old
Credit Agreement and entered into the Restated Credit Agreement with
another lender. As a result, the Company has written off the remaining
$1,130,000 of deferred costs related to the Old Credit Agreement.
During July 1998 the Company terminated a LIBOR interest rate swap
agreement at a cost of $3,549,000.
Pg. 6
<PAGE> 7
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
our current expectations which are based on our historical operating trends,
estimates of proved reserves and other information currently available to us.
These statements assume, among other things, (i) that no significant changes
will occur in the operating environment for the our oil and gas properties, gas
plants and gathering systems, and (ii) that there will be no material
acquisitions or divestitures. We caution that the Forward-Looking Statements are
subject to all of 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,
counterparty risk and lack of capital resources. Many of these risks are
described in our Annual Report on Form 10-K for the fiscal year ended June 30,
1999 filed with the Securities and Exchange Commission in October 1999, as
amended. We 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,
presented as if our net profits interests had been accounted for as working
interests. The financial data were derived from our Consolidated Financial
Statements and should be read in conjunction with the Consolidated Financial
Statements and related Notes thereto included herein. The results of operations
for the three and six months ended December 31, 1999 will not necessarily be
indicative of the operating results for the full fiscal year ending June 30,
2000.
<TABLE>
<CAPTION>
THREE MONTHS SIX MONTHS
ENDED DECEMBER 31 ENDED DECEMBER 31
---------------------------- ----------------------------
1999 1998 1999 1998
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Oil and gas sales (1) $ 8,207,000 $ 9,405,000 $ 15,080,000 $ 18,509,000
Oil and gas production expenses (1) 1,777,000 3,076,000 3,313,000 6,033,000
General and administrative expenses 755,000 717,000 1,475,000 1,379,000
------------ ------------ ------------ ------------
EBITDA 5,675,000 5,612,000 10,292,000 11,097,000
Interest expense, excluding amortization
of deferred charges (2) 4,205,000 4,228,000 8,363,000 8,417,000
Depreciation, depletion and amortization(3) 2,476,000 4,119,000 5,197,000 7,495,000
Hedge contract termination costs 3,328,000 -- 3,328,000 --
Write-down of oil and gas properties -- 35,033,000 -- 35,033,000
------------ ------------ ------------ ------------
Net loss from operations (4,334,000) (37,768,000) (6,596,000) (39,848,000)
Interest and other income 76,000 -- 97,000 66,000
Extraordinary loss (1,130,000) -- (1,130,000) (3,549,000)
------------ ------------ ------------ ------------
Net loss $ (5,388,000) $(37,768,000) $ (7,629,000) $(43,331,000)
============ ============ ============ ============
</TABLE>
(1) Oil and 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 $312,000 and $790,000 of
amortized deferred charges related to debt obligations for the three and
six months ended December 31, 1999, ($194,000 and $671,000 for the three
and six months ended December 31, 1998) respectively, and $27,000 and
$54,000 of amortized deferred charges related to the Company's gas price
hedging program for the three and six months ended December 31, 1999,
($32,000 and $66,000 for the three and six months ended December 31, 1998),
respectively.
Pg. 7
<PAGE> 8
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
DECEMBER 31 DECEMBER 31
----------------------- -----------------------
1999 1998 1999 1998
<S> <C> <C> <C> <C>
PRODUCTION DATA
Oil (Mbbls) 54.7 121.9 114.3 275.0
Gas (MMcf) 2,858.8 3,741.2 5,527.6 7,049.5
Mmcfe 3,187.1 4,472.8 6,213.7 8,699.6
MBOE 531.2 745.5 1,035.6 1,449.9
AVERAGE SALES PRICE
Oil (per Bbl) $ 23.05 $ 12.97 $ 18.29 $ 12.75
Gas (per Mcf) $ 2.43 $ 2.09 $ 2.35 $ 2.13
Per Mcfe $ 2.58 $ 2.10 $ 2.43 $ 2.13
Per BOE $ 15.45 $ 12.62 $ 14.56 $ 12.77
AVERAGE COST ($/MCFE) DATA:
Production and operating costs $ 0.45 $ 0.59 $ 0.44 $ 0.60
Production and severance taxes $ 0.10 $ 0.10 $ 0.09 $ 0.10
Depreciation, depletion and amortization $ 0.66 $ 0.83 $ 0.70 $ 0.79
General and administrative expenses $ 0.24 $ 0.16 $ 0.24 $ 0.16
Interest and financing expense $ 1.32 $ 0.95 $ 1.35 $ 0.97
</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.
THE THREE MONTHS ENDED DECEMBER 31, 1999 COMPARED TO THE THREE MONTHS ENDED
DECEMBER 31, 1998
RESULTS OF OPERATIONS
The following discussion and analysis reflects the operating results as if the
net profits interest were working interests. We believe that this will provide
the readers of the report with a more meaningful understanding of the underlying
operating results and conditions for the period.
REVENUES: Our total revenues declined by $1.2 million (13%) to $8.2 million for
the three months ended December 31, 1999, from $9.4 million during the
comparable period in 1998.
We produced 54,000 barrels of crude oil during the three months ended December
31, 1999, a decrease of 67,000 barrels (55%) from the 122,000 barrels produced
during the comparable period in 1998. This decrease was comprised of an overall
decrease of 14,000 barrels (20%) from the properties that we owned during both
periods and a decrease of 53,000 barrels from the properties that we sold at the
end of June 1999. The decrease in production of crude oil from the properties
owned during the comparative quarters is comprised of three components:
o One of our fields has not been meeting production expectations. This
under performance represents approximately 50% of the overall decrease in
production. Remedial action is being taken to rehabilitate this field.
o Subsequent to December 31, 1998 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 process of implementing phase
one of a redevelopment program in the Caprock Field, the objective of
which is to significantly enhance production.
o The final component of this decline is the result of the natural
depletion of the crude oil reservoirs, offset by the results of our
successful development and exploitation program.
We produced 2.9 million Mcf of natural gas during the three months ended
December 31, 1999, a decrease of 882,000 Mcf (24%) from the 3.7 million Mcf
produced during the comparable period in 1998. This decrease consists of a
decrease of 624,000 Mcf (18%) from the properties that we owned during both
periods and a decrease of 258,000 Mcf from the properties that we sold at the
end of June 1999. The decrease in production from the
Pg. 8
<PAGE> 9
properties owned during the comparative quarters is a result of the natural
depletion of the natural gas reservoirs, offset by our successful development
and exploitation program that started in August.
On a thousand cubic feet of gas equivalent ("Mcfe") basis, production for the
three months ended December 31, 1999 was 3.2 Bcfe, down 1.3 Bcfe (29%) from the
4.5 Bcfe produced during the comparable period in 1998. Production from
properties that we owned during both periods was down 578,000 Mcf (18%) during
the three months ended December 31, 1999 when compared to production during the
three months ended December 31, 1998.
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 crude oil sold by us during the three months ended
December 31, 1999 was $23.05, an increase of $10.08 per barrel (78%) from the
$12.97 per barrel during the three months ended December 31, 1998. The average
price per Mcf of natural gas sold by the Company was $2.43 during the three
months ended December 31, 1999, an increase of $0.34 per Mcf (16%) from the
$2.09 per Mcf during the comparable period in 1998. Crude oil prices have
remained at these elevated levels subsequent to December 31, 1999. Natural gas
prices were volatile throughout the quarter, and have remained so subsequent to
December 31, 1999. On an Mcfe basis, the average price received by us during the
three months ended December 31, 1999 was $2.58, a $0.48 increase (22%) from the
$2.10 we received during the comparable period in 1998.
During the three months ended December 31, 1999 we paid $3,000 in cash
settlements pursuant to our crude oil price-hedging program. The effect on the
average crude oil prices we received during the period was a decrease of $0.06
per barrel (0.3%). During the three months ended December 31, 1999 we paid
$139,000 in cash settlements and amortized $27,000 of deferred hedging costs
regarding our natural gas price-hedging program. The net negative effect on the
average natural gas prices we received during the period was $0.05 (2%). During
the comparable period in 1998 we received $223,000 in cash settlements and
amortized $33,000 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 $0.06 per Mcf (2%). We received an additional
$227,000 on our oil price-hedging program during the three months ended December
31, 1998, representing a positive effect on the average crude oil prices we
received of $1.20 per barrel (10%).
SEVERANCE AND PRODUCTION TAXES: Severance and production taxes, which are based
on the revenues derived from the sale of crude oil and natural gas, were
$327,000 ($0.10 per Mcfe) during the three months ended December 31, 1999, as
compared to $433,000 ($0.10 per Mcfe) during the comparable period in 1998. The
decrease of $106,000 (25%) is a result of the 13% decrease in revenues for the
three month period ended December 31, 1999, as compared to the same period for
1998. In addition, production taxes as a percentage of oil and gas sales
declined from 4.6% to 4.0% as a result of the June 1999 property sale.
PRODUCTION EXPENSES: Our lease operating expenses fell to $1.4 million for the
three months ended December 31, 1999, a decrease of $1.2 million (45%) from the
$2.6 million incurred during the comparable period in 1998. This decrease is
primarily the result of the 18% decline in the production of crude oil and
natural gas from comparable properties and the drop in production from the
properties we sold at the end of June 1999. Lease operating expenses were $0.45
per Mcfe during the three months ended December 31, 1999, a decrease of $0.14
(23%) from the $0.59 per Mcfe incurred during the comparable period in 1998.
This improvement is primarily the result of the sale of properties at the end of
June 1999. The properties we sold had higher operating costs per Mcfe than the
properties we currently own.
DEPLETION, DEPRECIATION AND AMORTIZATION EXPENSE: Depletion and oil field
equipment related depreciation costs were $2.1 million ($0.66 per Mcfe) during
the three months ended December 31, 1999, a decrease of $1.6 million (43%) over
the $3.7 million ($0.83 per Mcfe) charged to income during the comparable period
in 1998. The decrease in the provision is primarily a result of the 29% Mcfe
decrease in our production for the three month period ended December 31, 1999,
as compared to the same period for 1998. On a cost per Mcfe basis, the decrease
of $0.16 per Mcfe (20%) is primarily the result of the $28 million and $35
million non-cash write-downs of oil and gas property carrying values we recorded
at June 30, 1998 and December 31, 1998, respectively. We were not required to
record a similar write-down at December 31, 1999.
Pg. 9
<PAGE> 10
GENERAL AND ADMINISTRATIVE EXPENSES: The increase of $46,000 in general and
administrative costs for the three months ended December 31, 1999, compared to
the same period for 1998, is primarily the result of increased professional fees
as we evaluate the most effective way to restructure our capital structure.
INTEREST EXPENSE: Interest expense increased by $96,000, to $4.5 million for the
three months ended December 31, 1999, compared to $4.4 million for the three
months ended December 31, 1998. The interest expense of $4.5 million is
comprised of $4.2 million in cash interest charges and $285,000 of amortized
deferred costs. During the three months ended December 31, 1998 there were
$194,000 of amortized deferred costs included in the interest expense of $4.4
million. The increase of $91,000 in amortized deferred costs arose as a result
of changing the maturity date of the Bank of Montreal led Credit Agreement (the
"Old Credit Agreement") from April 2003 to October 2000.
EXTRAORDINARY LOSS: In October 1999 we replaced the Old Credit Agreement with an
Amended and Restated Credit Agreement with Ableco Finance LLP and Foothill
Capital Corporation (the "Restated Credit Agreement"). As a result, we wrote-off
$1,130,000 in unamortized deferred costs associated with the Old Credit
Agreement.
NET LOSS: We have incurred losses since inception, including $5.4 million ($0.15
per common share) for the three months ended December 31, 1999 compared to $39.0
million ($1.25 per common share) for the three months ended December 31, 1998.
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 gas properties of
$28 million and $35 million for the year ended June 30, 1998 and for the three
and six months ended December 31, 1998, respectively. Further declines in oil
and natural gas prices could lead to additional non-cash write-downs of our oil
and gas properties. We currently believe, but cannot assure, that our future
revenues from crude oil and natural gas will continue to be sufficient to cover
our production costs and operating expenses, excluding depletion, depreciation
and amortization, provided that the prevailing prices for crude oil and natural
gas do not decline further and production volume is maintained. We entered the
2000 fiscal year (July 1, 1999 to June 30, 2000) with a plan to improve
production from our oil and gas properties. During the three months ended
December 31, 1999 we produced 3.2 Bcfe, an increase of 160 million Mcf (5%) over
the 3.0 Bcfe we produced during the 3 months ended September 30, 1999. Our
revenues, profitability and future rate of growth are substantially dependent
upon prevailing prices for crude oil and natural gas and the volumes of crude
oil and natural gas we produce (see `-Changes in Prices and Hedging
Activities'). In addition, our proved reserves will decline as crude oil and
natural gas are produced unless we are successful in acquiring additional
properties containing proved reserves or conducting successful exploration and
development activities.
THE SIX MONTHS ENDED DECEMBER 31, 1999 COMPARED TO THE SIX MONTHS ENDED DECEMBER
31, 1998
RESULTS OF OPERATIONS
The following discussion and analysis reflects the operating results as if the
net profits interests were working interests. We believe that this will provide
the readers of the report with a more meaningful understanding of the underlying
operating results and conditions for the period.
REVENUES: Our total revenues fell by $3.4 million (19%) to $15.1 million for the
six months ended December 31 1999, from $18.5 million during the comparable
period in 1998.
We produced 114,000 barrels of crude oil during the six months ended December
31, 1999, a decrease of 161,000 barrels (58%) from the 275,000 barrels produced
during the comparable period in 1998. This decrease was comprised of a decrease
of 56,000 barrels (33%) from the properties that we owned during both periods
and a decrease of 105,000 barrels from the properties we sold at the end of June
1999. The decrease in production of crude oil from the properties owned during
the comparative quarters is comprised of three approximately equal components:
o One of our fields has not been meeting production expectations. Remedial
action is being taken to rehabilitate this field.
o Subsequent to December 31, 1998 we shut in substantially all of the wells
in the Caprock Field in New Mexico
Pg. 10
<PAGE> 11
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 process of implementing phase one of a redevelopment program in the
Caprock Field, the objective of which is to significantly enhance
production.
o The final component of this decline is a result of the natural depletion
of the crude oil reservoirs, offset by the result of our successful
development and exploitation program.
We produced 5.5 Bcf of natural gas during the six months ended December 31,
1999, a decrease of 1.5 Bcf (22%) from the 7.0 Bcf produced during the
comparable period in 1998. This decrease consists of a decrease of 961,000 Mcf
(15%) from the properties that we owned during both periods and a decrease of
561,000 Mcf from the properties we sold at the end of June 1999. The decrease in
production from the properties owned during the comparative quarters is a result
of the natural depletion of the natural gas reservoirs offset by our successful
development and exploitation program.
On a thousand cubic feet of gas equivalent ("Mcfe") basis, production for the
six months ended December 31, 1999 was 6.2 Bcfe, down 2.5 Bcfe (29%) from the
8.7 Bcfe produced during the comparable period in 1998. Production from
properties that we owned during both periods was down 1.3 million Mcf (17%)
during the six months ended December 31, 1999 when compared to production during
the six months ended December 31, 1998.
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 crude oil sold by us during the six months ended
December 31, 1999 was $18.29, an increase of $5.54 per barrel (44%) from the
$12.75 per barrel during the six months ended December 31, 1998. The average
price per Mcf of natural gas sold by us was $2.35 during the six months ended
December 31, 1999, an increase of $0.22 per Mcf (10%) from the $2.13 per Mcf
during the comparable period in 1998. Crude oil prices have remained at these
elevated levels subsequent to December 31, 1999. Natural gas prices were
volatile throughout the quarter, and have remained so subsequent to December 31,
1999. On an Mcfe basis, the average price received by us during the six months
ended December 31, 1999 was $2.43, a $0.30 increase (14%) from the $2.13 we
received during the comparable period in 1998.
During the six months ended December 31, 1999 we paid $365,000 in cash
settlements pursuant to our crude oil price-hedging program. The effect on the
average crude oil prices we received during the period was a decrease of $3.16
per barrel (15%). During the six months ended December 31, 1999 we paid $366,000
in cash settlements and amortized $54,000 of deferred hedging costs regarding
our natural gas price-hedging program. The net negative effect on the average
natural gas prices we received during the period was $0.06 (2%). During the
comparable period in 1998 we received $681,000 in cash settlements and amortized
$66,000 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 $0.10 per Mcf (5%). We received an additional $232,000 on
our oil price-hedging program during the six months ended December 31, 1998,
representing a positive effect on the average crude oil prices we received of
$0.84 per barrel (7%).
SEVERANCE AND PRODUCTION TAXES: Severance and production taxes, which are based
on the revenues derived from the sale of crude oil and natural gas, were
$585,000 ($0.09 per Mcfe) during the six months ended December 31, 1999, as
compared to $844,000 ($0.10 per Mcfe) during the comparable period in 1997. The
decrease of $259,000 (31%) is primarily a result of the 19% decrease revenues
for the six month period ended December 31, 1999, as compared to the same period
for 1998. In addition, production taxes as a percentage of oil and gas sales
declined from 4.6% to 4.0% as a result of the June 1999 property sale.
PRODUCTION EXPENSES: The Company's lease operating expenses fell to $2.7 million
for the six months ended December 31, 1999, a decrease of $2.5 million (47%)
from the $5.2 million incurred during the comparable period in 1998. This
decrease is primarily the result of the 17% decline in our production of crude
oil and natural gas from comparable properties and the drop in production from
the properties we sold at the end of June 1999. Lease operating expenses were
$0.44 per Mcfe during the six months ended December 31, 1999, a decrease of
$0.16 (26%) from the $0.60 per Mcfe incurred during the comparable period in
1998. This improvement is primarily the result of the sale of properties at the
end of June 1999. The properties we sold had higher operating costs per Mcfe
than the properties we currently own.
DEPLETION, DEPRECIATION AND AMORTIZATION EXPENSE: Depletion and oil field
equipment related depreciation costs
Pg. 11
<PAGE> 12
were $4.3 million ($0.70 per Mcfe) during the six months ended December 31,
1999, a decrease of $2.5 million (37%) from the $6.8 ($0.79 per Mcfe) charged to
income during the comparable period in 1998. On a cost per Mcfe basis, the
decrease of $0.09 per Mcfe (11%) is primarily the result of the $28 million and
$35 million non-cash write-downs of oil and gas property carrying values we
recorded at June 30, 1998 and December 31, 1998, respectively. We were not
required to record a similar write-down at December 31, 1999.
GENERAL AND ADMINISTRATIVE EXPENSES: The increase of $96,000 in general and
administrative costs for the six months ended December 31, 1999, compared to the
same period for 1998, is primarily the result of increased professional fees as
we evaluate the most effective way to restructure our capital structure.
INTEREST EXPENSE: Interest expense was $9.2 million for the six months ended
December 31, 1999, an increase of $65,000 over the $9.1 million incurred during
the six months ended December 31, 1998. The interest expense of $9.2 million is
comprised of $8.4 million in cash interest charges and $790,000 in amortized
deferred costs as compared to $8.4 million in cash interest charges and $671,000
of amortized deferred costs for the six months ended December 31, 1998. The
$53,000 increase in amortized deferred costs arose as a result of changing the
maturity date of the Old Credit Agreement from April 2003 to October 2000.
EXTRAORDINARY LOSS: In October 1999 we replaced the Old Credit Agreement with
the Restated Credit Agreement. As a result, we have written-off $1,130,000 in
unamortized deferred costs associated with the Old Credit Agreement. In July
1998 we unwound a LIBOR interest rate swap at a cost of $3,549,000.
NET LOSS: We have incurred losses since inception, including $7.6 million ($0.22
per common share) for the six months ended December 31, 1999 compared to $43.0
million ($1.32 per common share) for the six months ended December 31, 1998. 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 gas properties of $28
million and $35 million for the year ended June 30, 1998 and for the three and
six months ended December 31, 1998, respectively. Further declines in oil and
natural gas prices could lead to additional non-cash write-downs of our oil and
gas properties. We currently believe, but cannot assure, that our future
revenues from crude oil and natural gas will continue to be sufficient to cover
our production costs and operating expenses, excluding depletion, depreciation
and amortization, provided that the prevailing prices for crude oil and natural
gas do not decline further and production volume is maintained. We entered the
2000 fiscal year (July 1, 1999 to June 30, 2000) with a plan to improve
production from our oil and gas properties. During the three months ended
December 31, 1999 we produced 3.2 Bcfe, an increase of 160 million Mcf (5%) over
the 3.0 Bcfe we produced during the 3 months ended September 30, 1999. Our
revenues, profitability and future rate of growth are substantially dependent
upon prevailing prices for crude oil and natural gas and the volumes of crude
oil and natural gas we produce (see `-Changes in Prices and Hedging
Activities'). In addition, our proved reserves will decline as crude oil and
natural gas are produced unless we are successful in acquiring additional
properties containing proved reserves or conducting successful exploration and
development activities.
LIQUIDITY AND CAPITAL RESOURCES
GENERAL
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
further development of our existing proved reserves as well as additional
acquisitions. Historically cash from operations has not been sufficient to fund
the further development of our existing proved reserves or to fund additional
acquisitions. There can be no assurance that cash from operations will be
sufficient in the future to cover all such purposes.
Pg. 12
<PAGE> 13
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. 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 sources will be available to us to meet our
budgeted capital spending. Furthermore, our ability to borrow other than under
the Restated Credit Agreement dated as of October 22, 1999 with Ableco Finance
LLP (`Ableco') and Foothill Capital Corporation (`Foothill') is subject to
restrictions imposed by the Restated 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 our development and
exploitation efforts.
SOURCES OF CAPITAL: Our principal sources of capital for funding our business
activities have been cash flow from operations, debt financings and the issuance
of equity securities. Historically, our sources of funds from debt financings
included funds available under the Old Credit Agreement, DEM denominated bonds
issued to European investors, the 12.5% Senior Notes and a capital lease.
On October 22, 1999 Ableco and Foothill acquired our outstanding note from Bank
of Montreal, as agent for the lenders party to the Old Credit Agreement. We then
entered into the Restated Credit Agreement dated October 22, 1999 with Ableco
and Foothill. The Restated 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 $25 million, of which $14.75 million is
outstanding as of February 9, 2000.
The Restated Credit Agreement matures on October 22, 2001. There are no
scheduled principal repayments. The Restated Credit Agreement bears interest 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%
The funds were used as follows:
o $8.0 million to retire the borrowings under the Old Credit Agreement;
o $0.3 million to pay accrued interest charges and outstanding
restructuring fees to the former lenders;
o $3.3 million to terminate the ceiling component of a natural gas hedging
contract with Bank of Montreal;
o $1.2 million to fund the costs (principally fees paid to the lenders and
their counsel) of the transaction
In addition, we have a letter of credit outstanding in the amount of $1.8
million, as of February 9, 2000, to an affiliate of Enron Corporation to secure
a swap exposure.
Although 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, our level of debt may
adversely affect our ability:
o to obtain additional financing for working capital, capital expenditures
or other purposes, should we need to so do; or
o to acquire additional oil and natural gas properties or to make
acquisitions utilizing new borrowings.
We are currently exploring the opportunity to raise additional equity. However,
there can be no assurances that we will be able to obtain additional financing,
if required, or that such financing, if obtained, will be on terms favorable to
us.
USES OF CAPITAL
Since commencing our oil and natural gas operations in August 1994 we have
completed 19 acquisitions of oil and natural gas producing properties. Through
December 31, 1999 we have expended a total of $181 million in acquiring,
developing and exploiting oil and natural gas producing properties. Initially,
our operations represented a net use of funds. As demonstrated in the operating
results for the year ended June 30, 1999 and the three and six months ended
December 31, 1999 we currently generate a positive cash flow from operations.
During the three and six months ended December 31, 1999 we spent $2.7 million
and $3.1 million, respectively, on developing and exploiting our oil and natural
gas producing properties. We expect to spend a further $3.9 million on
discretionary capital expenditures through June 2000 for exploitation and
development projects. We are not contractually
Pg. 13
<PAGE> 14
obligated to fund any capital expenditures through June 2000. During the three
and six months ended December 31, 1999 we incurred debt issuance and other
deferred costs of $1.3 million and $1.9 million, respectively.
During January 2000 we redeemed DEM 400,000 ($211,000) of our 12% DEM
denominated bonds for DEM 392,000 ($206,000). The remaining DEM 1,200,000
($633,000) of these bonds mature on July 15, 2000.
We continue to evaluate acquisition opportunities, however there are no existing
agreements regarding any acquisitions. An acquisition would require the issuance
of additional debt and or equity securities. There are no assurances that we
will be able to obtain additional financing, or that such financing, if
obtained, will be on terms favorable to us.
In light of our highly levered capital structure, we have retained the services
of Friedman, Billings, Ramsey and Co., Inc. ("FBR") to advise and assist us in
restructuring our capital structure.
INFLATION
During the past several years, we have experienced moderate increases in
property acquisition and development costs. During the fiscal year ended June
30, 1999 we received somewhat lower commodity prices for the natural resources
produced from our properties. Oil and gas prices have increased during the three
and six months ended December 31, 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 be also be a corresponding increase in
oil and natural as finding and development 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>
THREE MONTHS ENDED SIX MONTHS ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31, DECEMBER 31,
1999 1998 1999 1998
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Gas (per mcf)
Price received at wellhead $ 2.48 $ 2.03 $ 2.41 $ 2.03
Effect of hedge contracts (0.05) 0.06 (0.06) 0.10
------------ ------------ ------------ ------------
Effective price received, including hedge contracts $ 2.43 $ 2.09 $ 2.35 $ 2.13
Average NYMEX Henry Hub $ 2.60 $ 2.13 $ 2.60 $ 2.08
Average basis differential including hedge contracts $ (0.17) $ (0.04) $ (0.25) $ 0.05
Average basis differential excluding hedge contracts $ (0.12) $ (0.10) $ (0.19) $ (0.05)
Oil (per barrel)
Average price received at wellhead per barrel $ 23.11 $ 11.77 $ 21.45 $ 11.91
Average effect of hedge contract (0.06) 1.20 (3.16) 0.84
------------ ------------ ------------ ------------
Average price received, including hedge contracts $ 23.05 $ 12.97 $ 18.29 $ 12.75
Average NYMEX Sweet Light Oil $ 24.51 $ 12.92 $ 23.12 $ 13.53
Average basis differential including hedge contracts $ (1.46) $ 0.05 $ (4.83) $ (0.78)
Average basis differential excluding hedge contracts $ (1.40) $ (1.15) $ (1.67) $ (1.62)
</TABLE>
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, in the fullness of time, unfavorable for
the following six months. The fixed prices under this contract reduced the
average wellhead price we received during the six months ended December 31, 1999
by approximately $0.11 per Mcf. This fixed price contract expired during October
1999.
Pg. 14
<PAGE> 15
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 crude 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 3,608,333 $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 721,667
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>
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:
Pg. 15
<PAGE> 16
<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 crude 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 crude 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
</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 no longer had the
variable rate debt required to offset the interest rate hedge position. 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 Notes proceeds. This cost was expensed
as an extraordinary loss during the three months ended September 30, 1998.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See Item 3. "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Changes in Prices and Hedging Activities".
PART II - OTHER INFORMATION
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
OTHER ISSUANCES OF COMMON STOCK. During the three and six months ended December
31, 1999, pursuant to Section 3(a)(9) of the Securities Act, the Company issued
an aggregate of 2,128,951 and 2,395,676 shares, respectively, of Common Stock to
stockholders who exercised 78,000 and 100,957 repricing rights, respectively,
under the Amended and Restated Securities Purchase Agreement dated as of July 8,
1998 among the Company and the buyers signatory thereto. The repricing rights
were issued in connection with a July 1998 private placement and permit the
holders to acquire shares of Common Stock without the payment of additional
consideration if the
Pg. 16
<PAGE> 17
Company's Common Stock does not achieve certain price thresholds in excess of
the original issuance of the shares purchased by the holders in the July 1998
private placement. The resale of these shares of Common Stock is registered
pursuant to Registration Statements on Form S-3 filed by the Company and
declared effective by the Securities and Exchange Commission.
During the three and six months ended December 31, 1999, pursuant to Section
3(a)(9) of the Securities Act, the Company issued an aggregate of 107,593 and
1,127,946 shares, respectively, upon conversion of 40 and 450 shares,
respectively, of the Company's Series C Convertible Preferred Stock by the
holders thereof. The resale of these shares of Common Stock is registered
pursuant to a Registration Statement on Form S-3 filed by the Company and
declared effective by the Securities and Exchange Commission.
Due to the current market price of the Company's Common Stock, it is likely that
additional shares of Common Stock will be issued upon exercise of Repricing
Rights and upon conversion of the Series C Convertible Preferred Stock.
ITEM 5. OTHER INFORMATION
AMENDED CREDIT FACILITY Please see Part I - Item 2 "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Liquidity and
Capital Resources" for a discussion of the Restated Credit Facility and the
termination of the ECT Revolving Credit Facility. Certain documentation with
respect to the Restated Credit Agreement was filed with our Quarterly Report on
Form 10-Q for the quarter ended September 30, 1999.
NASDAQ SMALLCAP MARKET LISTING At the close of business November 10, 1999 our
common stock was delisted from the Nasdaq SmallCap Market. This action was
solely attributable to our inability to satisfy the Nasdaq SmallCap Market
maintenance standards for the continued listing of common stock. Our common
stock is listed on the OTC:Bulletin Board under the symbol QSRI.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) EXHIBITS.
27 Financial Data Schedule
(b) REPORTS ON FORM 8-K.
NONE
Pg. 17
<PAGE> 18
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrants have duly caused this report to be signed on their behalf by the
undersigned thereunto duly authorized.
<TABLE>
<S> <C>
QUEEN SAND RESOURCES, INC. (DELAWARE)
By: /s/ EDWARD. J. MUNDEN
------------------------------------
Edward. J. Munden
President and Chief Executive Officer
By: /s/ RONALD BENN
------------------------------------
Ronald Benn
Chief Financial Officer
QUEEN SAND RESOURCES, INC. (NEVADA)
By: /s/ EDWARD. J. MUNDEN
------------------------------------
Edward. J. Munden
President and Chief Executive Officer
By: /s/ RONALD BENN
------------------------------------
Ronald Benn
Vice President (Principal Financial Officer)
QUEEN SAND OPERATING COMPANY
By: /s/ EDWARD. J. MUNDEN
------------------------------------
Edward. J. Munden
President and Chief Executive Officer
By: /s/ RONALD BENN
------------------------------------
Ronald Benn
Vice President (Principal Financial Officer)
CORRIDA RESOURCES, INC.
By: /s/ EDWARD. J. MUNDEN
------------------------------------
Edward. J. Munden
President and Chief Executive Officer
By: /s/ RONALD BENN
------------------------------------
Ronald Benn
Treasurer (Principal Financial Officer)
</TABLE>
Pg. 18
<PAGE> 19
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------ -----------
<S> <C>
27 Financial Data Schedule
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<CIK> 0000943548
<NAME> QUEEN SAND RESOURCES, INC.(DEL)
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> JUN-30-1999
<PERIOD-START> JUL-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 3,376,000
<SECURITIES> 0
<RECEIVABLES> 5,186,000
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 8,562,000
<PP&E> 95,982,000
<DEPRECIATION> 0
<TOTAL-ASSETS> 112,618,000
<CURRENT-LIABILITIES> 11,926,000
<BONDS> 134,106,000
0
96,000
<COMMON> 70,000
<OTHER-SE> 64,945,000
<TOTAL-LIABILITY-AND-EQUITY> 112,618,000
<SALES> 1,782,000
<TOTAL-REVENUES> 12,197,000
<CGS> 279,000
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 9,153,000
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