1
U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-Q
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[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2000
[ ] 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)
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(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 May 9, 2000: 55,923,190
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PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(UNAUDITED)
MARCH 31, JUNE 30,
2000 1999
------------- -------------
Assets
Current assets:
Cash $ 1,309,000 $ 9,367,000
Other current assets 5,613,000 4,652,000
------------- -------------
Total current assets 6,922,000 14,019,000
Net property and equipment 95,506,000 97,198,000
Other assets 8,110,000 7,993,000
------------- -------------
$ 110,538,000 $ 119,210,000
============= =============
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable and accrued liabilities $ 6,477,000 $ 11,100,000
Current portion of long-term debt 593,000 42,000
------------- -------------
Total current liabilities 7,070,000 11,142,000
Long-term obligations, net of current portion 138,500,000 133,852,000
Commitments
Stockholders' deficit (Note 3):
Preferred stock, $.01 par value, authorized 50,000,000 shares:
issued and outstanding 9,602,565 and 9,604,698 shares at
March 31, 2000 and June 30, 1999, respectively 96,000 96,000
Common stock, $.0015 par value, authorized 100,000,000 shares:
issued and outstanding 55,349,985 and 33,442,210 shares at
March 31, 2000 and June 30, 1999, respectively 111,000 65,000
Additional paid-in capital 65,087,000 64,912,000
Accumulated deficit (93,075,000) (83,606,000)
Treasury stock (7,251,000) (7,251,000)
------------- -------------
Total stockholders' deficit (35,032,000) (25,784,000)
------------- -------------
$ 110,538,000 $ 119,210,000
============= =============
See accompanying notes to unaudited interim period
consolidated condensed financial statements.
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QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
(UNAUDITED)
THREE MONTHS NINE MONTHS
ENDED ENDED
MARCH 31 MARCH 31
---------------------------- ----------------------------
2000 1999 2000 1999
------------ ------------ ------------ ------------
Revenues:
Oil and gas revenues $ 907,000 $ 785,000 $ 2,689,000 $ 3,533,000
Net profits and royalties interests 5,701,000 5,818,000 16,030,000 17,333,000
Interest and other income 65,000 131,000 150,000 197,000
------------ ------------ ------------ ------------
Total revenues 6,673,000 6,734,000 18,869,000 21,063,000
Expenses:
Oil and gas production expenses 572,000 719,000 851,000 2,573,000
General and administrative expenses 747,000 863,000 2,222,000 2,242,000
Interest and financing costs 4,757,000 4,429,000 13,910,000 13,346,000
Hedge contract termination costs (Note 4) -- -- 3,328,000 --
Depreciation, depletion and amortization 2,215,000 2,700,000 6,676,000 9,628,000
Write-down of oil and gas properties -- -- -- 35,033,000
------------ ------------ ------------ ------------
Net loss from operations (1,618,000) (1,977,000) (8,118,000) (41,759,000)
Extraordinary losses (Note 5) -- -- (1,130,000) (3,549,000)
------------ ------------ ------------ ------------
Net loss $ (1,618,000) $ (1,977,000) $ (9,248,000) $(45,308,000)
============ ============ ============ ============
Net loss before extraordinary losses per
common share $ (0.04) $ (0.06) $ (0.21) $ (1.35)
============ ============ ============ ============
Net loss per common share $ (0.04) $ (0.06) $ (0.24) $ (1.47)
============ ============ ============ ============
Weighted average shares of common stock
outstanding during the period 45,119,000 32,170,000 38,105,000 30,829,000
============ ============ ============ ============
See accompanying notes to unaudited interim period
consolidated condensed financial statements.
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QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(UNAUDITED)
NINE MONTHS ENDED MARCH 31,
------------------------------
2000 1999
------------- -------------
Operating activities:
Net loss $ (9,248,000) $ (45,308,000)
Extraordinary loss 1,130,000 3,549,000
Depletion, depreciation, amortization of oil and gas assets
and write-down of oil and gas properties 6,524,000 44,474,000
Amortization of deferred charges 1,267,000 860,000
Unrealized gains on foreign exchange obligations (53,000) (85,000)
Net changes in operating assets and liabilities (5,584,000) 664,000
------------- -------------
Net cash provided by (used in) operating activities (5,964,000) 4,154,000
------------- -------------
Investing activities:
Additions to property and equipment (5,044,000) (9,950,000)
Proceeds from sale of property and equipment 212,000 --
------------- -------------
Net cash used in investing activities (4,832,000) (9,950,000)
------------- -------------
Financing activities:
Increase in deferred assets (2,514,000) (4,384,000)
Termination of LIBOR swap agreement -- (3,549,000)
Proceeds from long-term obligations 19,292,000 132,000,000
Payments on long-term obligations (13,998,000) (142,385,000)
Payments on capital lease obligations (42,000) (56,000)
Proceeds from the sale of preferred and common stock -- 30,803,000
Repurchase of Series C Preferred Stock for Treasury -- (2,251,000)
------------- -------------
Net cash provided by financing activities 2,738,000 10,178,000
------------- -------------
Net increase (decrease) in cash (8,058,000) 4,382,000
Cash at beginning of period 9,367,000 1,029,000
------------- -------------
Cash at end of period $ 1,309,000 $ 5,411,000
============= =============
See accompanying notes to unaudited interim period
consolidated condensed financial statements.
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QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
March 31, 2000
(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 nine
months ended March 31, 2000 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 nine months of 1999 has been restated from the information
contained in the Company's Form 10-Q for the three and nine months ended
March 31, 1999, 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 nine months ended March 31, 2000 and 1999, 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 previous lending group led by Bank of Montreal (the
"Old Credit Agreement"). The Restated Credit Agreement allowed the
Company to borrow up to $25 million until March 31, 2000 and $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.
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QUEEN SAND RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
March 31, 2000
(unaudited)
(continued)
Pursuant to the Restated Credit Agreement, we are subject to certain
affirmative and negative financial 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. At March 31, 2000, the Company was in compliance with
these covenants. At March 31, 2000, there were $13.5 million outstanding
($12.0 million at May 9, 2000) under the Restated Credit Agreement.
(3) Common Stock Issuance
During the three and nine months ended March 31, 2000 the Company issued
13,699,353 and 16,095,029 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 1,683 and 2,133 shares, respectively, of the Series `C'
preferred stock into 4,224,117 and 5,263,934 shares, respectively, of the
Company's common stock. A further 460,683 and 548,812 shares,
respectively, of the Company's common stock were issued in payment of
accrued cumulative dividends in conjunction with this conversion.
(4) Hedging Activities
During the three and nine months ended March 31, 2000 the Company paid
$89,000 and $450,000, respectively, in cash settlements on its crude oil
hedges and $52,000 and $417,000 in cash settlements on its natural gas
hedges and amortized $22,000 and $76,000, 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 March 31, 2000 the Company had a letter of
credit in the amount of $3.1 million outstanding ($3.6 million at May 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 wrote 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.
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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 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 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 nine months ended March 31, 2000 will not necessarily be
indicative of the operating results for the full fiscal year ending June 30,
2000.
THREE MONTHS NINE MONTHS
ENDED MARCH 31 ENDED MARCH 31
---------------------------- ----------------------------
OPERATIONS DATA: 2000 1999 2000 1999
------------ ------------ ------------ ------------
Oil and gas sales(1) $ 7,929,000 $ 7,659,000 $ 23,009,000 $ 26,168,000
Oil and gas production expenses(1) 1,903,000 1,935,000 5,216,000 7,968,000
General and administrative expenses 747,000 863,000 2,222,000 2,242,000
------------ ------------ ------------ ------------
EBITDA 5,279,000 4,861,000 15,571,000 15,958,000
Interest expense, excluding amortization
of deferred charges(2) 4,356,000 4,164,000 12,720,000 12,580,000
Depreciation, depletion and amortization(3) 2,593,000 2,805,000 7,791,000 10,301,000
Hedge contract termination costs -- -- 3,328,000 --
Write-down of oil and gas properties -- -- -- 35,033,000
------------ ------------ ------------ ------------
Net loss from operations (1,670,000) (2,108,000) (8,268,000) (41,956,000)
Interest and other income 52,000 131,000 150,000 197,000
Extraordinary loss -- -- (1,130,000) (3,549,000)
------------ ------------ ------------ ------------
Net loss $ (1,618,000) $ (1,977,000) $ (9,248,000) $(45,308,000)
============ ============ ============ ============
(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 $400,000 and $1,191,000
of amortized deferred charges related to debt obligations for the three and
nine months ended March 31, 2000, ($355,000 and $1,026,000 for the three
and nine months ended March 31, 1999) respectively, and $22,000 and $76,000
of amortized deferred charges related to the Company's gas price hedging
program for the three and nine months ended March 31, 2000, ($27,000 and
$93,000 for the three and nine months ended March 31, 1999), respectively.
Pg.7
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THREE MONTHS ENDED NINE MONTHS ENDED
MARCH 31 MARCH 31
-------------------------- --------------------------
2000 1999 2000 1999
---------- ---------- ---------- ----------
PRODUCTION DATA
Oil (Mbbls) 57.0 123.0 171.4 398.0
Gas (MMcf) 2,581.0 3,105.0 8,108.6 10,154.5
Mmcfe 2,923.5 3,843.0 9,137.2 12,542.6
MBOE 487.2 640.5 1,522.9 2,090.4
AVERAGE SALES PRICE
Oil (per Bbl) $ 25.62 $ 8.78 $ 20.73 $ 11.52
Gas (per Mcf) $ 2.51 $ 2.12 $ 2.40 $ 2.13
Per Mcfe $ 2.71 $ 1.99 $ 2.52 $ 2.09
Per BOE $ 16.27 $ 11.96 $ 15.11 $ 12.52
AVERAGE COST ($/MCFE) DATA:
Production and operating costs $ 0.52 $ 0.43 $ 0.47 $ 0.55
Production and severance taxes $ 0.13 $ 0.07 $ 0.10 $ 0.09
Depreciation, depletion and amortization $ 0.74 $ 0.64 $ 0.71 $ 0.75
General and administrative expenses $ 0.26 $ 0.22 $ 0.24 $ 0.18
Interest and financing expense $ 1.49 $ 1.08 $ 1.39 $ 1.00
The following discussion of the results of operations and financial condition
should be read in conjunction with the Consolidated Condensed Financial
Statements and related Notes thereto included herein.
THE THREE MONTHS ENDED MARCH 31, 2000 COMPARED TO THE THREE MONTHS ENDED MARCH
31, 1999
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 increased by $270,000 (3%) to $7.9 million for the
three months ended March 31, 2000, from $7.7 million during the comparable
period in 1999.
We produced 57,000 barrels of crude oil during the three months ended March 31,
2000, a decrease of 66,000 barrels (54%) from the 123,000 barrels produced
during the comparable period in 1999. This decrease was comprised of an overall
decrease of 16,000 barrels (22%) from the properties that we owned during both
periods and a decrease of 50,000 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 During March 1999, we shut in substantially all of the wells in the
Caprock Field in New Mexico in response to low oil prices. As oil prices
recovered, we returned to production those wells that produce
economically. In addition, we are in the early stages of a redevelopment
program in the Caprock Field, the objective of which is to significantly
enhance production. We have drilled four single lateral injection wells
and one dual-lateral producing well. These five wells along with the
production facilities and a water injection plant constitute phase one of
the redevelopment program. Phase one incorporates 640 acres out of the
approximate 20,000 acres we control in the Caprock Field.
o The final component of this decline is the result of the natural depletion
of the crude oil reservoirs.
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We produced 2.6 Bcf of natural gas during the three months ended March 31, 2000,
a decrease of 524,000 Mcf (17%) from the 3.1 Bcf produced during the comparable
period in 1999. This decrease consists of a decrease of 308,000 Mcf (11%) from
the properties that we owned during both periods and a decrease of 216,000 Mcf
from the properties that we sold at the end of June 1999. The decrease in
production from the properties owned during the comparative quarters is
comprised of three components:
o One of our fields has experienced production declines in excess of what was
expected. The operator of the property has commenced drilling the first of
three proposed infield wells to increase production.
o Our successful development and exploitation program in south Texas resumed
in August 1999 and seven new wells have been drilled through the end of
March. These wells have high initial production rates, significant initial
decline rates, and approximately half of total reserves are produced during
the first year.
o The final component of this decline is the result of the natural depletion
of the natural gas reservoirs.
On a thousand cubic feet of gas equivalent ("Mcfe") basis, production for the
three months ended March 31, 2000 was 2.9 Bcfe, down 0.9 Bcfe (24%) from the 3.8
Bcfe produced during the comparable period in 1999. Production from properties
that we owned during both periods was down 402,000 Mcfe (12%) during the three
months ended March 31, 2000 when compared to production during the three months
ended March 31, 1999.
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
March 31, 2000 was $25.62, an increase of $16.84 per barrel (192%) from the
$8.78 per barrel during the three months ended March 31, 1999. The average price
per Mcf of natural gas sold by us was $2.51 during the three months ended March
31, 2000, an increase of $0.39 per Mcf (18%) from the $2.12 per Mcf during the
comparable period in 1999. Crude oil prices have remained at these elevated
levels subsequent to March 31, 2000. Natural gas prices were volatile throughout
the quarter, and have remained so subsequent to March 31, 2000. On an Mcfe
basis, the average price received by us during the three months ended March 31,
2000 was $2.71, a $0.72 increase (36%) from the $1.99 we received during the
comparable period in 1999.
During the three months ended March 31, 2000 we paid $89,000 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 $1.56 per barrel
(6%). During the three months ended March 31, 2000 we paid $52,000 in cash
settlements and amortized $22,000 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 $0.02 (1%). During the
comparable period in 1999 we received $765,000 in cash settlements and amortized
$27,000 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 $0.24 per Mcf (13%). We paid $14,000 on our oil
price-hedging program during the three months ended March 31, 1999, representing
a reduction on the average crude oil prices we received of $0.11 per barrel
(1%).
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
$373,000 during the three months ended March 31, 2000, as compared to $275,000
during the comparable period in 1999, an increase of $98,000 (36%). Revenues
rose only 3% during the comparable periods, as wellhead revenues increased by
17%, offset by the impact of our commodity hedging contracts. Severance taxes
are applied only to the wellhead revenues. Our commodity hedge results were the
primary cause for our severance and production taxes increasing, on a percentage
basis, more than revenues.
On a cost per Mcfe basis, severance taxes were $0.13 per Mcfe for the three
months ended March 31, 2000 compared to $0.07 per Mcfe for the comparable period
ending March 31, 1999, an increase of 78%. Average wellhead prices rose by 54%,
from $1.80 per Mcfe during the three months ended March 31, 1999 to $2.76 per
Mcfe during the three months ended March 31, 2000.
PRODUCTION EXPENSES: Our lease operating expenses fell to $1.5 million for the
three months ended March 31, 2000, a decrease of $130,000 (8%) from the $1.7
million incurred during the comparable period in 1999. This decrease is
primarily the result of reduced costs from comparable properties and the
elimination of costs from the properties we sold at the end of June 1999. Lease
operating expenses were $0.52 per Mcfe during the three months ended March 31,
2000, an increase of $0.09 (21%) from the $0.43 per Mcfe incurred during the
comparable period in 1999. The increase in average costs per Mcfe is primarily
the result of remedial action we have undertaken on the fields where
Pg.9
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production has declined in excess of expectations offset by an improvement
arising from 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 $2.2 million ($0.74 per Mcfe) during
the three months ended March 31, 2000, a decrease of $302,000 (12%) over the
$2.5 million ($0.64 per Mcfe) charged to income during the comparable period in
1999. This decrease in the provision is primarily a result of the 24% Mcfe
decrease in our production for the three month period ended March 31, 2000, as
compared to the same period for 1999. On a cost per Mcfe basis, the increase of
$0.10 per Mcfe (16%) is primarily the result of revisions we have made to our
expected capital expenditure programs, as part of our quarterly review of our
crude oil and natural gas reserves.
GENERAL AND ADMINISTRATIVE EXPENSES: The decrease of $116,000 in general and
administrative costs for the three months ended March 31, 2000 is primarily the
result of reductions in the activities undertaken during the quarter, as
compared to the same period for 1999.
INTEREST EXPENSE: Interest expense increased by $237,000, to $4.8 million for
the three months ended March 31, 2000, compared to $4.5 million for the three
months ended March 31, 1999. The interest expense of $4.8 million is comprised
of $4.4 million in cash interest charges and $400,000 of amortized deferred debt
issuance costs. During the three months ended March 31, 1999 there were $355,000
of amortized deferred debt issuance costs included in the interest expense of
$4.5 million. The increase of $45,000 in amortized deferred debt issuance costs
arose as a result of replacing the Bank of Montreal led Credit Agreement (the
"Old Credit Agreement") with an Amended and Restated Credit Agreement with
Ableco Finance LLP and Foothill Capital Corporation (the "Restated Credit
Agreement").
NET LOSS: We have incurred losses since inception, including $1.6 million ($0.04
per common share) for the three months ended March 31, 2000 compared to $2.1
million ($0.06 per common share) for the three months ended March 31, 1999. The
decline in oil and natural gas prices between December 31, 1997 and December 31,
1998 caused us to record non-cash write-downs of oil and gas properties of $28
million and $35 million for the years ended June 30, 1998 and June 30, 1999,
respectively. Future 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 significantly and
production volume is maintained. During the three months ended March 31, 2000 we
produced 2.9 Bcfe, a decrease of 0.3 Bcfe (8%) from the 3.2 Bcfe we produced
during the 3 months ended December 31, 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 NINE MONTHS ENDED MARCH 31, 2000 COMPARED TO THE NINE MONTHS ENDED
MARCH 31, 1999
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 $3.2 million (12%) to $23.0 million for the
nine months ended March 31 2000, from $26.2 million during the comparable period
in 1999.
We produced 171,000 barrels of crude oil during the nine months ended March 31,
2000, a decrease of 227,000 barrels (57%) from the 398,000 barrels produced
during the comparable period in 1999. This decrease was comprised of a decrease
of 72,000 barrels (29%) from the properties that we owned during both periods
and a decrease of 155,000 barrels from the properties we sold at the end of June
1999. The decrease in production of crude
Pg.10
11
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. This under
performance represents approximately 50% of the overall decrease in
production. Remedial action is being taken to rehabilitate this field.
o During March 1999 we shut in substantially all of the wells in the Caprock
Field in New Mexico in response to low oil prices. As oil prices
recovered, we returned to production those wells that produce
economically. In addition, we are in the early stages of a redevelopment
program in the Caprock Field, the objective of which is to significantly
enhance production. We have drilled four single lateral injection wells
and one dual-lateral producing well. These five wells along with the
production facilities and a water injection plant constitute phase one of
the redevelopment program. Phase one incorporates 640 acres out of the
approximate 20,000 acres we control in the Caprock Field.
o The final component of this decline is the result of the natural depletion
of the crude oil reservoirs.
We produced 8.1 Bcf of natural gas during the nine months ended March 31, 2000,
a decrease of 2.0 Bcf (20%) from the 10.2 Bcf produced during the comparable
period in 1999. This decrease consists of a decrease of 1.3 Bcf (14%) from the
properties that we owned during both periods and a decrease of 777,000 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 comprised of three
components:
o One of our fields has experienced production declines in excess of what was
expected. The operator of the property has commenced drilling the first of
three proposed infield wells to increase production.
o Our successful development and exploitation program in south Texas resumed
in August 1999 and seven new wells have been drilled through the end of
March. These wells have high initial production rates, significant initial
decline rates, and approximately half of total reserves are produced during
the first year.
o The final component of this decline is the result of the natural depletion
of the natural gas reservoirs.
Production for the nine months ended March 31, 2000 was 9.1 Bcfe, down 3.4 Bcfe
(27%) from the 12.5 Bcfe produced during the comparable period in 1999.
Production from properties that we owned during both periods was down 1.7 Bcfe
(16%) during the nine months ended March 31, 2000 when compared to production
during the nine months ended March 31, 1999.
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 nine months ended
March 31, 2000 was $20.73, an increase of $9.21 per barrel (80%) from the $11.52
per barrel during the nine months ended March 31, 1999. The average price per
Mcf of natural gas sold by us was $2.40 during the nine months ended March 31,
1998, an increase of $0.27 per Mcf (13%) from the $2.13 per Mcf during the
comparable period in 1999. Crude oil prices have remained at these elevated
levels subsequent to March 31, 2000. Natural gas prices were volatile throughout
the quarter, and have remained so subsequent to March 31, 2000. On an Mcfe
basis, the average price received by us during the nine months ended March 31,
2000 was $2.52, a $0.43 increase (21%) from the $2.09 we received during the
comparable period in 1999.
During the nine months ended March 31, 2000 we paid $450,000 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 $2.62 per barrel
(11%). During the nine months ended March 31, 2000 we paid $417,000 in cash
settlements and amortized $76,000 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 1999 we received $1,446,000 in cash settlements and
amortized $94,000 of deferred hedging costs regarding our natural gas
price-hedging program. The net positive effect on the average natural gas prices
we received during the period was $0.13 per Mcf (7%). We received an additional
$133,000 on our oil price-hedging program during the nine months ended March 31,
1999, representing a positive effect on the average crude oil prices we received
of $0.33 per barrel (3%).
SEVERANCE AND PRODUCTION TAXES: Severance and production taxes, which are based
on the revenues derived from
Pg.11
12
the sale of crude oil and natural gas, were $957,000 during the nine months
ended March 31, 2000, as compared to $1.1 million during the comparable period
in 1999, a decrease of $161,000 (14%). Revenues decreased 12% during the
comparable periods. While wellhead revenues decreased only 3%, the impact of our
commodity hedging contracts caused further reductions in our revenues. Severance
taxes are applied only to wellhead revenues. Our commodity hedge results were
the primary cause for our severance and production taxes decreasing, on a
percentage basis, more significantly than revenues.
On a cost per Mcfe basis, severance taxes were $0.10 per Mcfe for the nine
months ended March 31, 2000 compared to $0.09 per Mcfe for the comparable period
ending March 31, 1999, an increase of 17%. Average wellhead prices rose by 33%,
from $1.96 per Mcfe during the nine months ended March 31, 1999 to $2.61 per
Mcfe during the nine months ended March 31, 2000.
PRODUCTION EXPENSES: The Company's lease operating expenses fell to $4.3 million
for the nine months ended March 31, 2000, a decrease of $2.6 million (38%) from
the $6.8 million incurred during the comparable period in 1999. This decrease is
primarily the result of reduced costs from comparable properties and the
elimination of costs from the properties we sold at the end of June 1999. Lease
operating expenses were $0.47 per Mcfe during the nine months ended March 31,
2000, a decrease of $0.08 (15%) from the $0.55 per Mcfe incurred during the
comparable period in 1999. This improvement is primarily the result of the sale
of properties at the end of June 1999. 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 $6.5 million ($0.71 per Mcfe) during
the nine months ended March 31, 2000, a decrease of $2.8 million (30%) from the
$9.3 million ($0.75 per Mcfe) charged to income during the comparable period in
1999. On a cost per Mcfe basis, the decrease of $0.04 per Mcfe (4%) 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 $20,000 (1%) in general and
administrative costs for the nine months ended March 31, 2000, compared to the
same period for 1999, is reflective of the normal fluctuations in activities
undertaken by us.
INTEREST EXPENSE: Interest expense was $13.9 million for the nine months ended
March 31, 2000, an increase of $305,000 over the $13.6 million incurred during
the nine months ended March 31, 1999. The interest expense of $13.9 million is
comprised of $12.7 million in cash interest charges and $1.2 in amortized
deferred debt issuance costs as compared to $12.6 million in cash interest
charges and $1.0 million of amortized deferred debt issuance costs for the nine
months ended March 31, 1999. The increase of $200,000 in amortized deferred debt
issuance costs arose as a result of replacing the Old Credit Agreement with the
Restated Credit Agreement.
EXTRAORDINARY LOSS: In October 1999 we replaced the Old Credit Agreement with
the Restated Credit Agreement. As a result, we wrote off $1,130,000 in
unamortized deferred debt issuance 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 $9.2 million ($0.24
per common share) for the nine months ended March 31, 2000 compared to $45.3
million ($1.47 per common share) for the nine months ended March 31, 1999. The
decline in oil and natural gas prices between December 31, 1997 and December 31,
1998 caused us to record non-cash write-downs of oil and gas properties of $28
million and $35 million during the year ended June 30, 1998 and the nine months
ended March 31, 1999, respectively. Future 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 significantly and production volume is maintained. During the
three months ended March 31, 2000 we produced 2.9 Bcfe, decrease of 0.3 Bcfe
(8%) over the 3.2 Bcfe we produced during the 3 months ended December 31, 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
Pg.12
13
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.
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, which would reduce production and cash flow.
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 we entered into the Restated Credit Agreement 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 $12.0 million is
outstanding as of May 9, 2000. The Restated Credit Agreement matures on October
22, 2001. There are no scheduled principal repayments. The Restated Credit
Agreement bears interest (11% as of May 9, 2000) as follows:
o when the borrowings are less than $25 million, bank prime plus 2%;
o when the borrowings are $25 million or greater, bank prime plus 4.5%;
o on amounts securing letters of credit issued on our behalf, 3%.
In addition, we have a letter of credit outstanding in the amount of $3.6
million, as of May 9, 2000, to an affiliate of Enron Corporation to secure a
swap exposure.
Pg.13
14
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 do so; 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 assurance 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
March 31, 2000, we have expended a total of $185 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 nine months ended
March 31, 2000, we currently generate positive earnings before non-cash charges.
During the three and nine months ended March 31, 2000, we spent $1.7 million and
$5.0 million, respectively, on developing and exploiting our oil and natural gas
producing properties. We expect to spend a further $1.1 million on discretionary
capital expenditures through June 2000 for exploitation and development
projects. As of May 9, 2000, we are contractually obligated to fund $1.0 million
in capital expenditures. We plan to fund our discretionary and contractual
capital expenditures using operating cash flows and borrowings under the
Restated Credit Agreement. During the three and nine months ended March 31, 2000
we incurred debt issuance and other deferred costs of $0.5 million and $2.4
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
($593,000) 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. We are pursuing discussions with certain
holders of our 12.5% Senior Notes, Series A Convertible Preferred Stock, Series
C Convertible Preferred Stock and reset rights. Our goal is to achieve a
mutually satisfactory restructuring of our obligations under these instruments
in order that we can execute our growth strategy that has been substantially
interrupted since the Morgan property acquisition in 1998. However, there can be
no assurances that we will be able to complete any restructuring, or that such
restructuring, if completed, will be on terms favorable to us.
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 nine months ended March 31, 2000. Our results of operations and cash flow
have been, and will continue to be, affected to a certain extent by the
volatility in oil and natural gas prices. Should we experience a significant
increase in oil and natural gas prices that is sustained over a prolonged
period, we could expect that there would also be a corresponding increase in oil
and natural gas finding and development costs, lease acquisition costs and
operating expenses.
Pg.14
15
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.
THREE MONTHS ENDED NINE MONTHS ENDED
MARCH 31, MARCH 31,
2000 1999 2000 1999
------ ------ ------ ------
Gas (per mcf)
Price received at wellhead $ 2.53 $ 1.88 $ 2.46 $ 2.00
Effect of hedge contracts (0.02) 0.24 (0.06) 0.13
------ ------ ------ ------
Effective price received, including hedge contracts $ 2.51 $ 2.12 $ 2.40 $ 2.13
Average NYMEX Henry Hub $ 2.49 $ 1.75 2.57 $ 1.97
Average basis differential including hedge contracts $ 0.02 $ 0.37 $(0.17) $ 0.16
Average basis differential excluding hedge contracts $ 0.04 $ 0.13 $(0.11) $ 0.03
Oil (per barrel)
Average price received at wellhead per barrel $27.18 $ 8.89 $23.35 $11.19
Average effect of hedge contract (1.56) (0.11) (2.62) 0.33
------ ------ ------ ------
Average price received, including hedge contracts $25.62 $ 8.78 $20.73 $11.52
Average NYMEX Sweet Light Oil $28.74 $13.06 $24.99 $13.38
Average basis differential including hedge contracts $(3.12) $(4.28) $(4.26) $(1.86)
Average basis differential excluding hedge contracts $(1.56) $(4.17) $(1.64) $(2.19)
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 nine months ended March 31, 2000
by approximately $0.08 per Mcf. This fixed price contract expired during October
1999.
We had a contract with an affiliate of Enron involving the hedging of a portion
of our future natural gas production involving floor and ceiling prices as set
out in the table below. We shared 50% of the price of NYMEX Henry Hub in excess
of the ceiling price. This contract has expired. The volumes presented in this
table are divided equally over the months during the period.
Volume Floor Ceiling
Period Beginning Period Ending (MMBtu) Price Price
---------------- ------------- ------- ----- -----
September 1, 1997 August 31, 1998 600,000 $1.90 $2.66
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.
Volume Floor Ceiling
Period Beginning Period Ending (Barrels) Price Price
---------------- ------------- --------- ----- -----
September 1, 1997 August 31, 1998 120,000 $18.00 $20.40
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.
Pg.15
16
Volume Floor Ceiling
Period Beginning Period Ending (MMBtu) Price Price
---------------- ------------- ------- ----- -----
January 1, 1999 October 31, 1999 3,608,333 $2.00 $2.70
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:
Volume
Period Beginning Period Ending (MMBtu)
- ---------------- ------------- -------
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
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:
Volume
Period Beginning Period Ending (MMBtu)
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
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:
Volume
Period Beginning Period Ending (MMBtu)
- ---------------- ------------- -------
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
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:
Volume
Period Beginning Period Ending (Barrels) Price per Barrel
- ---------------- ------------- --------- ----------------
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
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.
Pg.16
17
Volume Floor Price Ceiling Price
Period Beginning Period Ending (Barrels) per Barrel per Barrel
- ---------------- ------------- --------- ---------- ----------
December 1, 1999 March 31, 2000 40,000 $22.90 $25.77
April 1, 2000 June 30, 2000 15,000 $23.00 $28.16
July 1, 2000 December 31, 2000 30,000 $22.00 $28.63
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 2. "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 nine months ended March
31, 2000, pursuant to Section 3(a)(9) of the Securities Act, the Company issued
an aggregate of 13,699,353 and 16,095,029 shares, respectively, of Common Stock
to stockholders who exercised 599,097 and 700,054 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 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 Company is a party to
registration rights agreements with the holders of the repricing rights by which
the Company is obligated to register that number of shares of Common Stock
sufficient to satisfy any and all demands for exercise of the reset rights
remaining at any particular time. The Company no longer has a sufficient number
of shares of Common Stock so registered to satisfy the exercise of any of the
currently remaining reset rights. The Securities Purchase Agreements entered
into by the Company and the holders of the repricing rights give the holders in
certain circumstances, including a default in the Company's registration
obligations, the right to demand that the Company repurchase the outstanding
reset rights and shares of common stock having unexercised repricing rights. The
Company does not presently have sufficient funds available to effect such a
repurchase but no demand for repurchase has been made by the holders. The
Company notes that after July 8, 2000, an effective registration statement will
not be required to allow the shares of common stock issued pursuant to the
exercise of repricing rights to be sold without any restricted legend.
During the three and nine months ended March 31, 2000 pursuant to Section
3(a)(9) of the Securities Act, the Company issued an aggregate of 4,224,117 and
5,263,934 shares, respectively, upon conversion of 1,683 and 2,133 shares,
respectively, of the Company's Series C Convertible Preferred Stock by the
holders thereof. A further 460,683 and 548,812 shares of Common Stock were
issued in payment of accrued cumulative dividends in
Pg.17
18
conjunction with this conversion during the three and nine months ended March
31, 2000, respectively. The Company notes that an effective registration
statement is no longer required to allow the shares of common stock issued
pursuant to the conversion of Series C Convertible Preferred Stock to be sold
without any restricted legend.
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 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) EXHIBITS.
27 FINANCIAL DATA SCHEDULE
(b) REPORTS ON FORM 8-K.
NONE
Pg.18
19
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.
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 CO.
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)
Pg.19
20
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
- ------ -----------
27 Financial Data Schedule