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PROSPECTUS
Filed pursuant to Rule 424(b)(4)
SEC File No. 333-41992
10,000,000 SHARES
[DEVX ENERGY LOGO]
COMMON STOCK
---------------------
We are selling 10,000,000 shares of our common stock. This is an initial
public offering of our common stock. Before this offering, our common stock was
quoted on the OTC Bulletin Board under the symbol "QSRI." Although our common
stock was quoted on the OTC Bulletin Board, the public offering price of the
common stock in this offering is not based on the market price of our common
stock but was determined by negotiations between us and the underwriters based
on factors described in "Underwriting."
Our common stock has been approved for trading on the Nasdaq National
Market subject to issuance and will trade under the symbol "DVXE."
You should read this prospectus carefully before you invest.
<TABLE>
<CAPTION>
PER SHARE TOTAL
--------- -----------
<S> <C> <C>
Public offering price....................................... $7.00 $70,000,000
Underwriting discounts and commissions...................... $0.35 $ 3,500,000
Proceeds, before expenses, to us............................ $6.65 $66,500,000
</TABLE>
The underwriters may purchase up to an additional 1,500,000 shares of
common stock from us at the public offering price less the underwriting
discount, to cover over-allotments. The underwriters expect to deliver the
shares against payment in Arlington, Virginia on or about October 31, 2000.
YOU SHOULD READ THE SECTION ENTITLED "RISK FACTORS" BEGINNING ON PAGE 10
FOR A DISCUSSION OF CERTAIN FACTORS YOU SHOULD CONSIDER BEFORE BUYING OUR COMMON
STOCK.
NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES
COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
FRIEDMAN BILLINGS RAMSEY STIFEL, NICOLAUS & COMPANY, INCORPORATED
PROSPECTUS DATED OCTOBER 26, 2000
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[map of the United States with the Company's name and
the following areas highlighted: the Appalachian
Basin, the Mid-Continent, east Texas, the Gulf Coast,
the Permian Basin and south Texas]
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SUMMARY
This summary highlights selected information from this prospectus. This
summary is not complete and may not contain all of the information that you
should consider before investing in our common stock. You should carefully read
the entire prospectus before making an investment decision. Unless otherwise
indicated, this prospectus reflects no exercise of the underwriters'
over-allotment option. Unless otherwise indicated, this prospectus assumes that
the recapitalization described below, including the reverse stock split of every
156 outstanding shares of common stock into one share, has occurred. We have
provided definitions for some of the oil and gas industry terms used in this
prospectus in the "Glossary" beginning on page 73.
In this prospectus, we refer to DevX Energy, Inc. and its subsidiaries as
"DevX," "we," "our" or "our company." Our fiscal year end is June 30. We
recently changed our name from "Queen Sand Resources, Inc." to "DevX Energy,
Inc."
THE COMPANY
We are an independent energy company engaged in the exploration,
development, exploitation and acquisition of on-shore oil and natural gas
properties in conventional producing areas of North America. To date, we have
grown almost exclusively through acquisitions of properties. As a result of our
acquisitions we own a diverse property base concentrated in six producing areas
or basins. Approximately 58% of our proved reserves are concentrated in south
and east Texas. Our assets are primarily long-lived natural gas properties
exhibiting low operating costs.
At June 30, 2000, we owned proved reserves of approximately 133 Bcf of
natural gas and 2 MMBbls of oil aggregating to approximately 145 Bcfe with an
SEC PV-10 value of $217 million and a reserve life index of 12.1 years.
Approximately 68% of our proved reserves were classified as proved developed and
approximately 92% of our proved reserves were natural gas. Our average daily net
production for the three months ending June 30, 2000, was 31.0 MMcfe. At June
30, 2000, we had interests in 667 wells, including 83 service wells.
Assuming completion of the recapitalization described below and this
offering, we expect to be able to execute an annual capital expenditure program
of approximately $20 million. As part of this program, we plan to increase our
exploration expenditures and are currently having discussions with potential
exploration joint venture partners. We expect our cash flow to increase as a
result of the $10.8 million decrease in annual interest expense that we
anticipate from the completion of the recapitalization. Upon completion of this
offering, the indenture governing our 12 1/2% senior notes will be amended to
allow us to increase the level of permitted borrowings under our credit facility
to approximately $49 million. We anticipate that we can fund our capital
expenditure program through a combination of working capital, operating cash
flow and additional borrowings under our credit facility.
Our executive offices and mailing address are 13760 Noel Road, Suite 1030,
Dallas, Texas 75240-7336 and our telephone number at that address is
972-233-9906.
BUSINESS STRATEGY
Our goal is to enhance stockholder value by expanding our oil and natural
gas reserves, production levels and cash flow. Our strategy to achieve these
goals consists of these elements:
- Recapitalizing the company through a significant reduction of debt, a
corresponding increase of equity and the elimination of all preferred
securities;
- Pursuing managed asset growth through:
- actively developing and exploiting our existing higher-potential oil and
natural gas properties, particularly in south and east Texas;
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- selective acquisitions of high-potential oil and natural gas assets that
complement our existing properties, coupled with routine dispositions of
non-core and lower potential properties;
- an increased emphasis on exploration activities; and
- targeted merger(s) where the consolidation with other companies will
give us access to quality reserves within our core areas;
- Maintaining a capital and financial structure with a prudent debt to
equity ratio that will allow us to use cash generated from operations to
fund growth in our production and reserves; and
- Enhancing our board of directors and management team through the addition
of new industry senior executives to assist the company in improving and
expanding its operating capacity and exploration activities.
THE RECAPITALIZATION. Simultaneously with the closing of this offering, we
will complete a recapitalization which includes: (a) a reverse stock split of
every 156 outstanding shares of our common stock into one share; (b) the
exchange of all preferred stock, all warrants exercisable for shares of common
stock and all remaining unexercised common stock repricing rights for 732,500
shares of post reverse-split common stock; and (c) the repurchase of $75 million
face value of our 12 1/2% senior notes for approximately $52.5 million. At our
stockholders meeting on September 18, 2000, our stockholders approved the first
two elements of the recapitalization. The repurchase of our 12 1/2% senior notes
does not require stockholder approval.
When the recapitalization and this offering are complete, our company will:
- recognize a gain on the repurchase of $75 million of our senior notes at
a discount, thereby creating more than $23 million of additional equity
value for our stockholders;
- on a pro forma basis, reduce our debt by approximately $86.0 million,
thereby increasing annual cash flow available to fund growth by $10.8
million and reducing our interest cost per Mcfe by nearly 59%;
- reduce our long-term debt to $57.5 million, which approximates 26% of our
June 30, 2000 SEC PV-10 of $217 million;
- eliminate all outstanding preferred stock;
- eliminate the dilutive effects of current market price conversion and
repricing rights held by some of our stockholders;
- improve our liquidity by using a portion of the proceeds from this
offering to pay down our senior working capital facility and modifying
the indenture governing our senior notes to permit us to increase our
senior working capital facility from $35 million to approximately $49
million; and
- satisfy the listing requirements of the Nasdaq National Market with a
goal of improving the visibility and liquidity of our common stock.
Upon completion of the recapitalization and this offering, there will be
outstanding approximately 11,250,000 shares of our common stock, no shares of
preferred stock and no repricing rights.
DEVELOPMENT AND EXPLOITATION OF EXISTING PROPERTIES. We have identified
over 400 potential development locations and exploitation opportunities on our
properties. We have prioritized these opportunities to concentrate on those
higher impact projects that have the potential to replace and grow our reserves
while maximizing the long-term return on our capital. Our opportunities include:
- additional exploration of well-defined locations on existing properties
such as in the J.C. Martin field in south Texas;
- infill drilling on our producing properties such as in the Gilmer field
in east Texas;
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- recompletion of existing wells in behind-pipe intervals such as in the
Lopeno/Volpe field in south Texas; and
- developing proved undeveloped reserves by drilling low risk, long lived
natural gas wells in the shallow New Albany Shale formation in Kentucky.
PROPERTY ACQUISITIONS AND DIVESTITURES. We will diligently pursue the
acquisition of oil and natural gas properties that we believe will provide us
with a combination of increased production, reserve growth and exploration
potential. Our focus will be on only those properties that can be acquired at
prices that will enhance our overall return on capital. Although we are
currently weighted towards natural gas reserves, we anticipate that we may
return to a more even oil to natural gas ratio. While the acquisition market is
currently very competitive, we believe that there are opportunities to acquire
high quality oil and natural gas properties with these characteristics in the
mid-continent and southwest regions of the United States, where we have
established core areas. In all property acquisitions the company will be seeking
to become the operator. We will also continue to routinely evaluate our
portfolio of properties and periodically divest non-core or low potential
properties.
EXPLORATION. The acquisition market is currently very competitive,
especially for transactions that exceed $50 million. These properties are
generally sold on a tender bid basis which has the effect of bidding up the
price and maximizing the return to the seller. As a result, we have determined
that it is no longer prudent to rely solely on acquisitions for asset growth.
Our growth strategy has evolved from being primarily acquisition driven to a
more balanced approach with an increased emphasis on exploration opportunities.
We believe that this balanced approach will provide for a lower average reserve
replacement cost, thereby improving our return on capital. In order to diversify
our exposure, we generally acquire larger interests in company-operated, lower
risk projects and smaller interests in higher risk/high impact potential
exploration properties. Our plan is for much of our exploration effort to be
conducted with partners who bring a unique experience, expertise or ownership
position in the prospect area of interest and have a successful track record.
MERGER OPPORTUNITIES. With the completion of the recapitalization, we
expect to be able to attract other small capitalization oil and natural gas
companies as merger or consolidation partners as a result of our substantially
deleveraged balance sheet and stronger cash flow. We will be in an excellent
position to make accretive acquisitions of other companies and, through this
process, to use our strong balance sheet and cash flow to effect the
recapitalization of suitable merger candidates that otherwise may not have
access to capital.
CAPITAL AND FINANCIAL STRUCTURE. Our objective is to use a portion of the
net proceeds of this offering and internally generated cash flow to fund our
exploration, development and exploitation programs. We believe that we can
finance our acquisition opportunities at attractive prices with a combination of
equity and debt.
MANAGEMENT TEAM. With the completion of the recapitalization, we will have
the financial capability to pursue our strategy of increased focus on operating
those properties that we own and on exploration as a means to grow our assets.
We intend to continue restructuring our management team to add to our
engineering, geology and geophysical personnel. We also intend to add seasoned
senior oil and gas industry executives with experience in building stockholder
value and in the management of exploration and development projects. On October
6, 2000, Joseph T. Williams became a director and Chairman of the Board of our
company. In addition, on October 26, 2000, Jerry B. Davis and Robert L. Keiser
joined our board of directors. Biographical information for each of Messrs.
Williams, Davis and Keiser is included in "Management." We are also in the
process of recruiting one additional outside, non-employee director whom we
expect will join our board of directors within 90 days after the completion of
the recapitalization and this offering. As part of the restructuring of our
management team, Bruce I. Benn and Robert P. Lindsay will resign from our board
of directors immediately following the successful completion of this offering.
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THE OFFERING
Common stock offered....... 10,000,000 shares(1)
Common stock to be
outstanding after this
offering................. approximately 11,250,000 shares(2)
Use of proceeds............ To repurchase $75 million in aggregate principal
amount of our 12 1/2% senior notes for
approximately $52.5 million and to repay
approximately $11 million of the $14 million
outstanding under our credit agreement as of
October 26, 2000.
Nasdaq National Market
Symbol.................. DVXE
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(1) 11,500,000 shares if the underwriters' over-allotment option is exercised in
full.
(2) Approximately 12,750,000 shares if the underwriters' over-allotment is
exercised in full. Includes the approximately 1,250,000 shares to be issued
in the recapitalization. Does not include 1,000,000 shares reserved for
issuance under our employee stock option plan or 100,000 shares reserved for
issuance under our directors' option plan. Does not include 3,397 shares
issuable on the exercise of warrants at exercise prices ranging from $936 to
$1,248 per share.
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SUMMARY CONSOLIDATED FINANCIAL INFORMATION
The following table presents some of our historical and unaudited pro forma
consolidated financial data. We completed significant acquisitions of producing
oil and natural gas properties during fiscal 1998, which affects the
comparability of the historical financial and operating data for the periods
presented. The financial data for the three years ended June 30, 2000 are
derived from our audited consolidated financial statements. The pro forma
financial data are derived from our pro forma financial statements. The
financial data are not necessarily indicative of our future performance. You
should read the following data in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations," our consolidated
financial statements and the notes to those financial statements as well as the
"Unaudited Pro Forma Condensed Consolidated Financial Statements" included
elsewhere in this prospectus.
<TABLE>
<CAPTION>
HISTORICAL PRO FORMA
----------------------------- ----------
YEAR ENDED JUNE 30, YEAR ENDED
----------------------------- JUNE 30,
1998 1999 2000 2000
-------- -------- ------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
OPERATIONS DATA:
Oil and natural gas sales(1)...................... $ 12,665 $ 33,783 $32,584 $32,584
Oil and natural gas production expenses(1)........ 6,333 9,127 7,097 7,097
-------- -------- ------- -------
Net oil and natural gas revenues.................. 6,332 24,656 25,487 25,487
General and administrative expenses............... 2,259 3,534 3,026 3,026
-------- -------- ------- -------
EBITDA(2)......................................... 4,073 21,122 22,461 22,461
Interest and financing costs(3)................... 3,957 17,003 16,945 6,113
Depletion, depreciation, and amortization(4)...... 4,809 13,354 10,259 10,259
Hedge contract termination costs(5)............... -- -- 3,328 3,328
Ceiling test write-down(6)........................ 28,166 35,033 -- --
Interest and other income......................... (105) (326) (143) (143)
-------- -------- ------- -------
Net income (loss) before extraordinary item....... (32,754) (43,942) (7,928) $ 2,904
-------- -------- ------- =======
Extraordinary loss(7)............................. -- 3,549 1,130
-------- -------- -------
Net income (loss)................................. $(32,754) $(47,491) $(9,058)
======== ======== =======
Net income (loss) per common share before
extraordinary item............................. $ (1.44) $ (1.40) $ (0.18) $ 0.26
</TABLE>
<TABLE>
<CAPTION>
HISTORICAL
------------------------------ PRO FORMA
AT JUNE 30, -----------
------------------------------ AT JUNE 30,
1998 1999 2000 2000
-------- -------- -------- -----------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
BALANCE SHEET DATA (AT END OF PERIOD):
Total current assets............................ $ 6,411 $ 14,019 $ 18,524 $ 18,524
Property and equipment, net..................... 142,467 97,198 92,525 92,525
Deferred assets................................. 4,797 7,993 8,144 4,682
Total assets.................................... 153,675 119,210 119,193 115,731
Total current liabilities....................... 6,836 11,142 10,535 5,847
Long-term obligations, net of current portion... 153,619 133,852 143,500 57,500
Total stockholders' equity (deficit)............ (6,780) (25,784) (34,842) 52,384
</TABLE>
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(1) Oil and natural gas sales and production expenses related to net profits
interests have been presented as if the net profits interests were working
interests. Oil and natural gas sales include revenues relating to the net
profits interests of $6,219,000 for the year ended June 30, 1998,
$29,071,000 for the year ended June 30, 1999, and $28,715,000 for the year
ended June 30, 2000. Oil and natural gas production expenses include
expenses relating to the net profits interests of $1,787,000 for the year
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ended June 30, 1998, $5,931,000 for the year ended June 30,1999, and
$5,725,000 for the year ended June 30, 2000.
(2) EBITDA represents earnings before interest expense, income taxes,
depreciation, depletion and amortization expense, write down of oil and
natural gas properties and extraordinary items and excludes interest and
other income. EBITDA is not a measure of income or cash flows in accordance
with generally accepted accounting principles, but is presented as a
supplemental financial indicator as to our ability to service or incur debt.
EBITDA is not presented as an indicator of cash available for discretionary
spending or as a measure of liquidity. EBITDA may not be comparable to other
similarly titled measures of other companies. Our credit agreement requires
the maintenance of specified EBITDA ratios. EBITDA should not be considered
in isolation or as a substitute for net income, operating cash flow or any
other measure of financial performance prepared in accordance with generally
accepted accounting principles or as a measure of our profitability or
liquidity.
(3) Interest charges payable on outstanding debt obligations.
(4) Depreciation, depletion and amortization includes $22,000 of amortized
deferred charges related to our natural gas price hedging program for the
year ended June 30, 1998. Depreciation, depletion and amortization for the
year ended June 30, 1999 includes amortized deferred charges related to debt
obligations of $1.3 million, and $120,000 of amortized deferred charges
related to our natural gas price hedging program. Depreciation, depletion
and amortization for the year ended June 30, 2000 includes $1,600,000 of
amortized deferred charges related to debt obligations, and $98,000 of
amortized deferred charges related to our natural gas price hedging program.
(5) In conjunction with the execution of our restated credit agreement in
October 1999, we terminated the ceiling portion of a natural gas hedging
contract at a cost of $3,328,000.
(6) In accordance with the full cost method of accounting, the results of
operations for the year ended June 30, 1998 include a writedown of oil and
natural gas properties of $28,166,000 and for the year ended June 30, 1999
include a writedown of $35,033,000.
(7) During July 1998, we terminated a LIBOR interest rate swap agreement at a
cost of $3,549,000. During October 1999, we retired borrowings under our old
credit agreement and entered into a restated credit agreement with a new
lender. As a result, we wrote off $1,130,000 of deferred costs relating to
the old credit agreement.
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SUMMARY OPERATING AND RESERVE DATA
The following table presents some of our operating and reserve data. You
should read the following data in conjunction with "Risk Factors -- Our
profitability is highly dependent on the prices for oil and natural gas, which
can be extremely volatile," "-- Any negative variance in our estimates of proved
reserves and future net revenues could affect the carrying value of our assets,
our income and our ability to borrow funds," and "Business -- Oil and natural
gas reserves" included elsewhere in this prospectus.
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
--------------------------
1998 1999 2000
------ ------- -------
<S> <C> <C> <C>
OPERATING DATA:
Production volumes:
Natural gas (MMcf)........................................ 3,368 12,962 10,618
Oil (MBbl)................................................ 325 500 224
Total (MMcfe)..................................... 5,318 15,960 11,960
Average sales price:
Natural gas (per Mcf)..................................... $ 2.27 $ 2.13 $ 2.59
Oil (per Bbl)............................................. 15.52 12.37 22.76
Natural gas equivalent (per Mcfe)......................... 2.39 2.12 2.72
Selected expenses (per Mcfe):
Lease operating expense................................... $ 1.07 $ 0.49 $ 0.47
Production taxes.......................................... 0.12 0.09 0.12
General and administrative................................ 0.43 0.22 0.25
Depreciation, depletion and amortization(1)............... 0.89 0.74 0.71
Interest expense.......................................... 0.75 1.06 1.42
</TABLE>
<TABLE>
<CAPTION>
AT JUNE 30,
------------------------------
1998 1999 2000
-------- -------- --------
<S> <C> <C> <C>
PROVED RESERVE DATA (END OF PERIOD):
Proved reserves:
Natural gas (MMcf)..................................... 176,095 137,561 132,680
Oil (MBbl)............................................. 7,949 4,624 2,010
Total (MMcfe)..................................... 223,788 165,299 144,740
Percent of proved developed reserves........................ 68.3% 65.0% 67.4%
Percent of natural gas reserves............................. 78.7% 83.2% 91.7%
Reserve Life Index (years)(2)............................... 11.4 10.4 12.1
Estimated future net cash flows before income taxes (in
thousands)................................................ $318,663 $271,993 $467,036
SEC PV-10 (in thousands).................................... $165,120 $130,726 $217,372
</TABLE>
---------------
(1) Represents depreciation, depletion and amortization of oil and natural gas
properties only.
(2) The Reserve Life Index at June 30, 1998 was calculated using pro forma
production of 19,654 MMcfe for the year ended June 30, 1998.
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RISK FACTORS
You should carefully consider the following risks before making an
investment decision. The trading price of our common stock could decline due to
any of these risks, and you could lose all or part of your investment. You also
should refer to the other information set forth in this prospectus, including
our financial statements and the related notes thereto.
RISKS RELATED TO OUR BUSINESS
WE HAVE IN THE PAST EXPERIENCED NET LOSSES AND WE MAY EXPERIENCE NET LOSSES IN
THE FUTURE, WHICH COULD MATERIALLY ADVERSELY AFFECT OUR RESULTS OF OPERATIONS.
Since beginning operations in 1995, we have not been profitable on an
annual basis. We experienced a net loss of approximately $32.8 million for the
year ended June 30, 1998, a net loss of approximately $47.5 million for the year
ended June 30, 1999 and a net loss of approximately $9.1 million for the year
ended June 30, 2000. We may experience net losses in the future as we continue
to incur significant operating expenses and to make capital expenditures. Even
if we do become profitable, we may not sustain or increase profitability on a
quarterly or annual basis in the future. At June 30, 2000, we had an accumulated
deficit of approximately $92.9 million.
OUR PROFITABILITY IS HIGHLY DEPENDENT ON THE PRICES FOR OIL AND NATURAL GAS,
WHICH CAN BE EXTREMELY VOLATILE.
Our revenues, profitability and future growth substantially depend on
prevailing prices for oil and natural gas. Prices for oil and natural gas can be
extremely volatile. Among the factors that can cause this volatility are:
- weather conditions;
- the level of consumer product demand;
- domestic and foreign governmental regulations;
- the price and availability of alternative fuels;
- political conditions in oil and natural gas producing regions;
- the domestic and foreign supply of oil and natural gas;
- the availability, proximity and capacity of gathering systems of natural
gas;
- the price of foreign imports; and
- overall economic conditions.
Prices for oil and natural gas affect the amount of cash flow available to
us for capital expenditures and the repayment of our outstanding debt. Our
ability to maintain or increase our borrowing capacity and to obtain additional
capital on attractive terms is also substantially dependent upon oil and natural
gas prices. In addition, because we currently produce more natural gas than oil,
we face more risk with fluctuations in the price of natural gas than oil. We
have used hedging contracts to reduce our exposure to price changes.
HEDGING OUR PRODUCTION MAY CAUSE US TO FOREGO FUTURE PROFITS.
To reduce our exposure to changes in the prices of oil and natural gas, we
have entered into and may in the future enter into hedging arrangements for a
portion of our oil and natural gas production. The hedges that we have entered
into generally provide a "floor" or "cap and floor" on the prices paid for our
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oil and natural gas production over a period of time. Hedging arrangements may
expose us to the risk of financial loss in some circumstances, including the
following:
- the other party to the hedging contract defaults on its contract
obligations; or
- there is a change in the expected differential between the underlying
price in the hedging agreement and actual prices received.
Reduced revenues resulting from our hedging activities could have an
adverse effect on our financial condition and operations. For the year ended
June 30, 2000, our revenues were reduced by approximately $1.5 million as a
result of our existing hedge contracts. We may have to make additional payments
under these contracts in the future depending on the difference between actual
and hedged prices of oil and natural gas. In addition, these hedging
arrangements may limit the benefit we would otherwise receive from increases in
the prices for oil and natural gas.
Some of our hedging arrangements contain a "cap" whereby we must pay the
counter-party if oil or natural gas prices exceed the price specified in the
contract. We are required to maintain letters of credit with our
counter-parties, and we may be required to provide additional letters of credit
if prices for oil and natural gas futures increase above the "cap" prices. The
amount of these letters of credit is a function of oil and natural gas prices
and the volumes of oil and natural gas subject to the contract. As a result, the
value of these letters of credit will fluctuate with the market prices of oil
and natural gas. These letters of credit are issued pursuant to our credit
agreement and as a result utilize some of our borrowing capacity, reducing funds
available to be borrowed under our credit agreement.
IF WE ARE NOT ABLE TO REPLACE DEPLETED RESERVES, OUR FUTURE RESULTS OF
OPERATIONS WILL BE ADVERSELY AFFECTED.
The rate of production from oil and natural gas properties declines as
reserves are depleted. Our proved reserves will decline as reserves are produced
unless we acquire additional properties containing proved reserves, conduct
successful exploration, development and exploitation activities on new or
currently leased properties or identify additional formations with primary or
secondary reserve opportunities on our properties. If we are not successful in
expanding our reserve base, our future oil and natural gas production, the
primary source of our revenues, will be adversely affected. The level of our
future oil and natural gas production and our results of operations are
therefore highly dependent on the level of our success in finding and acquiring
additional reserves. Our ability to find and acquire additional reserves depends
on our generating sufficient cash flow from operations and other sources of
capital, including borrowings under our credit agreement. We cannot assure you
that we will have sufficient cash flow or cash from other sources to expand our
reserve base. Our ability to continue acquiring producing properties or
companies that own producing properties assumes that major integrated oil
companies and independent oil companies will continue to divest many of their
oil and natural gas properties. We cannot assure you that these divestitures
will continue or that we will be able to acquire producing properties at
acceptable prices.
WE MAY HAVE DIFFICULTY FINANCING OUR PLANNED GROWTH AND CAPITAL EXPENDITURES.
We have experienced and expect to continue to experience substantial
capital expenditure and working capital needs as a result of our exploration,
development, exploitation and acquisition strategy. In the future, we may
require financing, in addition to cash generated from our operations and this
offering, to fund our planned growth and capital expenditures. Over the past two
years, we have experienced constraints on our ability to arrange additional
capital to fund our business plan.
Although we were able to borrow an additional $6.7 million under our credit
agreement as of October 26, 2000, our lenders could reduce our borrowing limit.
If additional capital resources are unavailable, we will be unable to grow our
business and we may curtail our drilling, development and other activities or be
forced to sell some of our assets on an untimely or unfavorable basis.
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OUR LEVEL OF DEBT MAY NOT ALLOW US PROPERLY TO PLAN FOR FUTURE OPPORTUNITIES OR
TO COMPETE EFFECTIVELY.
After completion of this offering and the recapitalization, we will have
debt of approximately $57.5 million. As of June 30, 2000, our ratio of total
indebtedness to total capitalization was 132% and our consolidated total
interest coverage ratio was 1.3 to 1. Assuming the completion of the
recapitalization and this offering with net proceeds to us of at least $63.5
million and the application of the net proceeds of this offering as described in
this prospectus, our ratio of total indebtedness to total capitalization would
be approximately 52% and our consolidated total interest coverage ratio would be
3.7 to 1. In addition, we may borrow more money in the future to fund our
business strategy. This level of debt could:
- increase our vulnerability to general adverse economic and industry
conditions, especially declines in oil and natural gas prices;
- limit our ability to fund future acquisitions, capital expenditures and
other general corporate requirements;
- require us to dedicate a material portion of our cash flow from
operations to payments on our debt;
- limit our flexibility in planning for or reacting to, changes in our
business and industry; and
- limit our ability to, among other things, borrow additional funds, sell
assets and pay dividends.
RESTRICTIVE DEBT COVENANTS LIMIT OUR ABILITY TO FINANCE OUR OPERATIONS, FUND OUR
CAPITAL NEEDS AND ENGAGE IN OTHER BUSINESS ACTIVITIES THAT MAY BE IN OUR
INTEREST.
Our credit agreement and the indenture governing our 12 1/2% senior notes
due 2008 contain significant covenants that, among other things, restrict our
ability to:
- dispose of assets;
- incur additional indebtedness;
- repay other indebtedness;
- pay dividends;
- enter into specified investments or acquisitions;
- repurchase or redeem capital stock;
- merge or consolidate; or
- engage in specified transactions with subsidiaries and affiliates and our
other corporate activities.
Also, our credit agreement requires us to maintain compliance with the financial
ratios included in that agreement. Our ability to comply with these ratios may
be affected by events beyond our control. A breach of any of these covenants or
our inability to comply with the required financial ratios could result in a
default under our credit agreement.
We have in the past been in default of some covenants under our previous
credit agreement. All of these defaults were waived by the lenders. However, if
we default under our current credit agreement, our lender may declare all
amounts borrowed under the credit agreement, together with accrued interest, to
be due and payable. If we do not repay the indebtedness promptly, our lender
could then foreclose against any collateral securing the payment of the
indebtedness. Substantially all of our oil and natural gas interests secure our
credit agreement.
OUR ABILITY TO GENERATE SUFFICIENT CASH TO SERVICE OUR DEBT AND REPLACE OUR
RESERVES DEPENDS ON MANY FACTORS BEYOND OUR CONTROL.
We rely on cash from our operations to pay the principal and interest on
our debt. Our ability to generate cash from operations depends on the level of
production from our properties, general economic
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<PAGE> 13
conditions, including the prices paid for oil and natural gas, success in our
exploration, development and exploitation activities, and legislative,
regulatory, competitive and other factors beyond our control. Our operations may
not generate enough cash to pay the principal and interest on our debt.
WE CANNOT ASSURE YOU THAT WE WILL BE SUCCESSFUL IN MANAGING OUR GROWTH.
The success of our future growth will depend on a number of factors,
including:
- our ability to timely explore, develop and exploit acquired properties;
- our ability to continue to attract and retain skilled personnel;
- our ability to continue to expand our technical, operational and
administrative resources; and
- the results of our drilling program.
Our growth could strain our financial, technical, operational and
administrative resources. Our failure to successfully manage our growth could
adversely affect our operations and net revenues through increased operating
costs and revenues that do not meet our expectations.
WE MAY PURCHASE OIL AND NATURAL GAS PROPERTIES WITH LIABILITIES OR RISKS WE DID
NOT KNOW ABOUT OR THAT WE DID NOT CORRECTLY ASSESS, AND, AS A RESULT, WE COULD
BE SUBJECT TO LIABILITIES THAT COULD ADVERSELY AFFECT OUR RESULTS OF OPERATIONS.
We evaluate and pursue acquisition opportunities, primarily in the
mid-continent and southwest regions of the United States. Before acquiring oil
and natural gas properties, we estimate the recoverable reserves, future oil and
natural gas prices, operating costs, potential environmental and other
liabilities and other factors relating to the properties. We believe our method
of review is generally consistent with industry practices. However, our review
involves many assumptions and estimates, and their accuracy is inherently
uncertain. As a result, we may not discover all existing or potential problems
associated with the properties we buy. We may not become sufficiently familiar
with the properties to fully assess their deficiencies and capabilities. We do
not generally perform inspections on every well, and we may not be able to
observe mechanical and environmental problems even when we conduct an
inspection. Even if we identify problems, the seller may not be willing or
financially able to give contractual protection against these problems, and we
may decide to assume environmental and other liabilities in connection with
acquired properties. If we acquire properties with risks or liabilities we did
not know about or that we did not correctly assess, our financial condition and
results of operations could be adversely affected.
THE OIL AND GAS BUSINESS INVOLVES MANY OPERATING RISKS THAT COULD CAUSE
SUBSTANTIAL LOSSES.
Drilling activities involve the risk that no commercially productive oil or
natural gas reservoirs will be found or produced. We may drill or participate in
new wells that are not productive. We may drill wells that are productive but
that do not produce sufficient net revenues to return a profit after drilling,
operating and other costs. Whether a well is productive and profitable depends
on a number of factors, including the following, many of which are beyond our
control:
- general economic and industry conditions, including the prices received
for oil and natural gas;
- mechanical problems encountered in drilling wells or in production
activities;
- problems in title to our properties;
- weather conditions which delay drilling activities or cause producing
wells to be shut down;
- compliance with governmental requirements; and
- shortages in or delays in the delivery of equipment and services.
If we do not drill productive and profitable wells in the future, our financial
condition and results of operations could be materially and adversely affected
due to decreased cash flow and net revenues.
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<PAGE> 14
In addition to the substantial risk that we may not drill productive and
profitable wells, the following hazards are inherent in oil and natural gas
exploration, development, exploitation, production and gathering, including:
- unusual or unexpected geologic formations;
- unanticipated pressures;
- mechanical failures;
- blowouts where oil or natural gas flows uncontrolled at a wellhead;
- cratering or collapse of the formation;
- explosions;
- pollution; and
- environmental accidents such as uncontrollable flows of oil, natural gas
or well fluids into the environment, including groundwater contamination.
We could suffer substantial losses from these hazards due to injury and loss of
life, severe damage to and destruction of property and equipment, pollution and
other environmental damage and suspension of operations. We carry insurance that
we believe is in accordance with customary industry practices for companies of
our size. However, we do not fully insure against all risks associated with our
business either because this insurance is not available or because we believe
the cost is prohibitive. The occurrence of an event that is not covered, or not
fully covered by insurance, could have a material adverse effect on our
financial condition and results of operations.
OUR EXPLORATION ACTIVITIES INVOLVE A HIGH DEGREE OF RISK AND MAY NOT BE
COMMERCIALLY SUCCESSFUL.
Oil and natural gas exploration involves a high degree of risk that
hydrocarbons will not be found, that they will not be found in commercial
quantities, or that their production will be insufficient to recover drilling,
completion and operating costs. The 3-D seismic data and other technologies we
may use do not allow us to know conclusively prior to drilling a well that oil
or natural gas is present or economically producible. The cost of drilling,
completing and operating a well is often uncertain, and cost factors can
adversely affect the economics of a project. Furthermore, completion of a well
does not guarantee that it will be profitable or even that it will result in
recovery of drilling, completion and operating costs. Therefore, we may not earn
revenues with respect to, or recover costs spent on, our exploration activities.
OUR SECONDARY RECOVERY PROJECTS REQUIRE SIGNIFICANT CAPITAL EXPENDITURES AND MAY
NOT BE COMMERCIALLY SUCCESSFUL.
We face the risk that we will spend a significant amount of money on
secondary recovery operations, such as waterflooding projects, without any
increase in production. Although waterflooding requires significant capital
expenditures, the total amount of reserves that can be recovered though
waterflooding is uncertain. In addition, there is generally a delay between the
initiation of water injection into a formation containing hydrocarbons and any
increase in production that may result from the injection. The degree of
success, if any, of any secondary recovery program depends on a large number of
factors, including the porosity, permeability and heterogeneity of the
formation, the technique used and the location of injection wells.
WE CANNOT CONTROL THE DEVELOPMENT OF A SUBSTANTIAL PORTION OF OUR PROPERTIES
BECAUSE OUR INTERESTS ARE IN THE FORM OF NON-OPERATED NET PROFITS INTERESTS AND
OVERRIDING ROYALTY INTERESTS.
A substantial portion of our oil and natural gas property interests are in
the form of non-operated, net profits interests and royalty interests. As the
owner of non-operated net profits interests and royalty interests, we do not
have the direct right to drill or operate wells or to cause third parties to
propose or
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<PAGE> 15
drill wells on the underlying properties. As a result, the success and timing of
our drilling and development activities on those properties operated by others
depend upon a number of factors outside of our control, including:
- the timing and amount of capital expenditures;
- the operator's expertise and financial resources;
- the approval of other participants in drilling wells; and
- the selection of suitable technology.
If the operators of these properties do not conduct drilling and development
activities on these properties, then our results of operations may be adversely
affected.
WE MAY LOSE TITLE TO OUR ROYALTY INTEREST IN THE J.C. MARTIN FIELD AS A RESULT
OF LITIGATION OVER TITLE TO THE ROYALTY INTEREST.
A portion of our landowner royalty on the J.C. Martin field, which
comprises approximately 10% of our total SEC PV-10 value as of June 30, 2000, is
currently subject to a lawsuit that may create uncertainty as to the title to
our royalty interest. A favorable order of summary judgment has been rendered in
favor of the pension funds managed by the entity that sold us the properties.
The order has been appealed. Eight million dollars of the purchase price we paid
for the Morgan Properties, which include our royalty interest in the J.C. Martin
field, are currently in escrow pending the resolution of this lawsuit. If the
summary judgment is overturned and a final judgment is later entered against the
entity which sold us this property and that judgment unwinds the original
transaction in which the entity acquired its interest in the J.C. Martin field,
the escrowed monies would be returned to us and we would be required to convey
our royalty interest in the J.C. Martin field to the plaintiff retroactive to
the date we acquired the interest.
IF A BANKRUPTCY COURT TREATS ANY OF OUR NET PROFITS INTERESTS AS CONTRACT RIGHTS
INSTEAD OF REAL PROPERTY INTERESTS, WE COULD LOSE ALL OF THE VALUE OF THOSE
INTERESTS.
We cannot assure you whether a court in the states of Kansas and Oklahoma
would treat the net profits interests as contract rights or real property
interests. Our net profits interests in these states comprise approximately 14%
of our SEC PV-10 as of June 30, 2000. If any of the assignors become involved in
bankruptcy proceedings in these states, we face the risk that our net profits
interests might be treated by a bankruptcy court as contract rights instead of
real property interests. If the bankruptcy court treats our net profits
interests as contract rights, then we would be treated as an unsecured creditor
in the bankruptcy, and under the terms of the bankruptcy plan, we could lose all
of the value of the net profits interests. If the bankruptcy court treats the
net profits interests as real property interests, then our interests should not
be materially affected.
ANY NEGATIVE VARIANCE IN OUR ESTIMATES OF PROVED RESERVES AND FUTURE NET
REVENUES COULD AFFECT THE CARRYING VALUE OF OUR ASSETS, OUR INCOME AND OUR
ABILITY TO BORROW FUNDS.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and the timing of
development expenditures, including many factors beyond our control. The reserve
data included in this prospectus represent only estimates. In addition, the
estimates of future net revenue from proved reserves and their present value are
based on assumptions about future production levels, prices and costs that may
not prove to be correct over time. In particular, estimates of oil and natural
gas reserves, future net revenue from proved reserves and the present value of
proved reserves for the oil and natural gas properties described in this
prospectus are based on the assumption that future oil and natural gas prices
remain the same as oil and natural gas prices at June 30, 2000. The NYMEX prices
as of June 30, 2000, used for purposes of our estimates were $32.50 per Bbl of
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<PAGE> 16
oil and $4.33 per MMbtu of natural gas. Any significant variance in actual
results from these assumptions could also materially affect the estimated
quantity and value of our reserves.
WE MAY BE REQUIRED TO WRITE DOWN THE CARRYING VALUE OF OUR PROVED PROPERTIES
UNDER ACCOUNTING RULES AND THESE WRITEDOWNS COULD ADVERSELY AFFECT OUR FINANCIAL
CONDITION.
There is a risk that we will be required to write-down the carrying value
of our oil and natural gas properties when oil and natural gas prices are low.
In addition, write-downs may occur if we have:
- downward adjustments to our estimated proved reserves;
- increases in our estimates of development costs; or
- deterioration in our exploration and exploitation results.
We periodically review the carrying value of our oil and natural gas
properties under the full cost accounting rules of the Securities and Exchange
Commission. Under these rules, the net capitalized costs of oil and natural gas
properties may not exceed a ceiling limit that is based on the present value,
based on flat prices at a single point in time, of estimated future net revenues
from proved reserves, discounted at 10%. If net capitalized costs of oil and
natural gas properties exceed the ceiling limit, we must charge the amount of
this excess to earnings in the quarter in which the excess occurs. At June 30,
1998, we were required to write down the carrying value of our oil and natural
gas properties by $28.2 million. At December 31, 1998, we were required to write
down the carrying value of our oil and natural gas properties by an additional
$35 million. We may not reverse write-downs even if prices increase in
subsequent periods. A write-down does not affect cash flow from operating
activities, but it does reduce the book value of our net tangible assets and
stockholders' equity.
IF WE ARE UNABLE TO COMPETE EFFECTIVELY AGAINST OTHER OIL AND GAS COMPANIES, WE
MAY BE UNABLE TO ACQUIRE NEW PROPERTIES AT ATTRACTIVE PRICES OR TO SUCCESSFULLY
DEVELOP OUR PROPERTIES.
We encounter strong competition from other oil and gas companies in
acquiring properties and leases for the exploration, exploitation and production
of oil and natural gas. Many of our competitors have financial resources, staff
and facilities substantially greater than ours. Our competitors may be able to
pay more for desirable leases and to evaluate, bid for and purchase a greater
number of properties or prospects than our financial or personnel resources will
permit. As a result, we may not be able to buy properties at affordable prices
or to successfully develop our properties. Our ability to explore, develop and
exploit oil and natural gas reserves and to acquire additional properties in the
future will depend on our ability to conduct operations, to evaluate and select
suitable properties and to consummate transactions in this highly competitive
environment.
WE ARE SUBJECT TO GOVERNMENT REGULATION AND LIABILITY, INCLUDING ENVIRONMENTAL
LAWS, THAT COULD REQUIRE SIGNIFICANT EXPENDITURES AND COULD MATERIALLY DECREASE
OUR NET INCOME.
The exploration, development, exploitation, production and sale of oil and
natural gas in the U.S. are subject to many federal, state and local laws and
regulations, including environmental laws and regulations. Under these laws and
regulations, we may be required to make large expenditures that could materially
adversely affect our results of operations. These expenditures could include
payments for personal injuries, property damage, oil spills, the discharge of
hazardous materials, remediation and clean-up costs and other environmental
damages. While we maintain insurance coverage for our operations, we do not
believe that full insurance coverage for all potential environmental damages is
available at a reasonable cost. Failure to comply with these laws and
regulations also may result in the suspension or termination of our operations
and subject us to administrative, civil and criminal penalties. Laws and
regulations protecting the environment have become increasingly stringent in
recent years and may impose liability on us for environmental damage and
disposal of hazardous materials even if we were not negligent or at fault. We
may also be liable for the conduct of others or for our own acts even if our
acts complied with applicable laws at the time we performed those acts.
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RISKS RELATING TO THE OFFERING AND OUR COMMON STOCK
IF WE DO NOT MAINTAIN THE LISTING OF OUR COMMON STOCK ON THE NASDAQ NATIONAL
MARKET OR ANY OTHER STOCK EXCHANGE, THE PRICE OF THE COMMON STOCK MAY BE
DEPRESSED AND YOU MAY HAVE DIFFICULTIES RESELLING THE STOCK.
Our inability to maintain the listing of the common stock on the Nasdaq
National Market or any other stock exchange will negatively affect the liquidity
and marketability of the common stock. On November 11, 1999, Nasdaq delisted our
common stock from trading on the Nasdaq SmallCap Market because of our failure
to meet the minimum net tangible asset base, the minimum market capitalization
and the minimum trading price thresholds. This resulted in our common stock
being quoted on the OTC Bulletin Board before this offering. Many institutional
and other investors refuse to invest in stocks that are traded at levels below
the Nasdaq SmallCap Market which could make our efforts to raise capital more
difficult. In addition, the firms that make a market for our common stock could
discontinue that role. OTC Bulletin Board stocks are often lightly traded or not
traded at all on any given day.
IF THERE IS A CHANGE OF CONTROL OF THE COMPANY, WE WOULD BE IN DEFAULT UNDER OUR
CREDIT AGREEMENT AND WE COULD BE REQUIRED TO REPURCHASE OUR SENIOR NOTES.
If there is a change of control of our company as defined in our credit
agreement, we would be in default under our credit agreement. In addition, the
indenture governing our senior notes contains provisions that, under some
circumstances, will cause our senior notes to become due upon the occurrence of
a change of control as defined in the indenture. If a change of control occurs,
we may not have the financial resources to repay this indebtedness and would be
in default under the indenture. These provisions could also make it more
difficult for a third party to acquire control of us, even if that change of
control might benefit our stockholders.
OUR CERTIFICATE OF INCORPORATION CONTAINS PROVISIONS THAT COULD DISCOURAGE AN
ACQUISITION OR CHANGE OF CONTROL OF OUR COMPANY.
Our certificate of incorporation authorizes our board of directors to issue
preferred stock without stockholder approval. Provisions of our certificate of
incorporation, such as the provision allowing our board of directors to issue
preferred stock with rights more favorable than our common stock, could make it
more difficult for a third party to acquire control of us, even if that change
of control might benefit our stockholders.
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FORWARD-LOOKING STATEMENTS
We have made forward-looking statements in this prospectus that are subject
to risks and uncertainties. These forward-looking statements include information
about possible or assumed future results of our operations. Also, when we use
any of the words "believes," "expects," "intends," "anticipates" or similar
expressions, we are making forward-looking statements. Examples of types of
forward-looking statements include statements on:
- our oil and natural gas reserves;
- future acquisitions;
- future drilling and operations;
- future capital expenditures;
- future production of oil and natural gas; and
- future net cash flow.
You should understand that the following important factors, in addition to those
discussed elsewhere in this prospectus, could affect our future financial
results and performance and cause our results or performance to differ
materially from those expressed in our forward-looking statements:
- the timing and extent of changes in prices for oil and natural gas;
- the need to acquire, develop and replace reserves;
- our ability to obtain financing to fund our business strategy;
- environmental risks;
- drilling and operating risks;
- risks related to exploration, development and exploitation projects;
- competition;
- government regulation; and
- our ability to meet our stated business goals.
We claim the protection of the safe harbor for forward-looking statements
contained in the Private Securities Litigation Reform Act of 1995 for these
statements.
You should consider these risks when you purchase our common stock and the
risks discussed in "Risk Factors" beginning on page 10.
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THE RECAPITALIZATION
INTRODUCTION
Simultaneously with the closing of this offering, we will complete the
recapitalization which includes the following:
- a reverse stock split of every 156 outstanding shares of our common stock
into one share;
- the exchange of 9,600,000 outstanding shares of our Series A preferred
stock for 212,500 shares of post reverse-split common stock;
- the exchange of 2,173 outstanding shares of our Series C preferred stock
and warrants exercisable for 340,153 shares of common stock for 120,000
shares of post reverse-split common stock;
- the exchange of the 1,593,918 remaining unexercised common stock
repricing rights and warrants exercisable for 655,000 shares of common
stock for 400,000 shares of post reverse-split common stock; and
- the repurchase of $75 million face value of our senior notes for
approximately $52.5 million.
At our stockholders meeting on September 18, 2000, our stockholders
approved the first four elements of the recapitalization. The repurchase of our
senior notes does not require stockholder approval.
Our board of directors believes that the recapitalization will have the
following positive effects:
- the recapitalization will significantly improve our chances to access the
equity capital markets and pursue our growth strategy;
- our stockholders' equity will increase after the recapitalization because
the amount of our indebtedness will be reduced at a discount;
- the termination of the dilutive share issuance rights, coupled with the
reverse stock split, will lessen the depressive effects on the market
price of the common stock;
- there will no longer be any outstanding shares of preferred stock having
dividend or liquidation preferences over common stock; and
- no stockholder will have rights to require us to repurchase their stock.
Upon completion of the recapitalization and this offering, there will be
outstanding approximately 11,250,000 shares of our common stock, no shares of
preferred stock and no repricing rights.
BACKGROUND
DILUTIVE EFFECT OF CONVERTIBLE SECURITIES. One of the purposes of the
recapitalization was to eliminate the overhang on our common stock resulting
from the dilutive effects of our outstanding shares of Series A preferred stock,
Series C preferred stock and common stock repricing rights. We issued 9,600,000
shares of Series A preferred stock in March 1997 for total gross proceeds of $5
million. We issued 10,400 shares of Series C preferred stock in December 1997
for total gross proceeds of $10.4 million. We issued 3,428,574 shares of common
stock with repricing rights attached in July 1998 for total gross proceeds of
$24 million and we issued an additional 416,667 shares of common stock with
repricing rights attached in November 1998 for total gross proceeds of $2.5
million.
While each share of Series A preferred stock was convertible into one share
of pre-split common stock, the number of shares of common stock issuable upon
conversion of the Series C preferred stock and upon the exercise of repricing
rights increased as the bid price of our common stock decreased. Assuming a
relevant common stock bid price of $2.00, a share of Series C preferred stock
would be convertible into 500 shares of common stock, a July 1998 repricing
right would be convertible into 3.48 shares of common stock and a November 1998
repricing right would be convertible into 2.84 shares of common stock.
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Assuming a relevant bid price of $0.20, a share of Series C preferred stock
would be convertible into 5,000 shares of common stock, a July 1998 repricing
right would be convertible into 43.8 shares of common stock and a November 1998
repricing right would be convertible into 37.4 shares of common stock. As of
October 4, 2000, there were 9,600,000 shares of Series A preferred stock, 2,173
shares of Series C preferred stock and 1,593,918 repricing rights outstanding.
At that time the relevant bid price of our common stock for the purposes of
conversion of Series C preferred stock or exercise of repricing rights was
$0.049 per share. At that price, we would have been obligated to issue
342,591,531 shares of common stock if all outstanding shares of preferred stock
and repricing rights had been converted into shares of common stock.
ISSUANCE OF SENIOR NOTES. In July 1998 we issued $125 million of 12 1/2%
senior notes due 2008. We used the net proceeds of the sale of these notes to
retire a portion of the Bank of Montreal/Enron bridge facility that we put in
place to complete the purchase of the Morgan Properties. We originally issued
these senior notes in a Rule 144A private placement. These notes have traded at
increasing discounts to face value since they were issued.
THE RECAPITALIZATION
REVERSE STOCK SPLIT. In connection with the recapitalization, we are
effecting a reverse stock split of every 156 outstanding shares of our common
stock into one share. The shares being issued in this offering are post-reverse
stock split shares.
RECAPITALIZATION AGREEMENT. Under the terms of a recapitalization
agreement, effective contemporaneously with the completion of this offering, the
holders of our Series A preferred stock, our Series C preferred stock and all
unexercised common stock repricing rights will exchange their respective
holdings for the following numbers of post-split common stock:
<TABLE>
<CAPTION>
NUMBER OF SHARES OF
CLASS OF HOLDERS POST-SPLIT COMMON STOCK TO BE ISSUED
---------------- ------------------------------------
<S> <C>
Series A preferred stock.............. 212,500
Series C preferred stock.............. 120,000
Repricing rights...................... 400,000
</TABLE>
These shares of post-reverse stock split common stock will be divided pro
rata among the holders of the Series C preferred stock and the common stock
repricing rights, as the case may be. Each holder also agreed, pending
completion of the recapitalization, not to submit any additional demands for the
conversion of their holdings into shares of common stock nor take any other
action to pursue any other rights or remedies to which they may be entitled. All
securities purchase agreements, registration rights agreements, warrants and
other ancillary agreements between the company and the various holders will be
terminated effective contemporaneously with the completion of this offering.
The closing under the recapitalization agreement is subject to the
following:
- stockholder approval of the recapitalization and the reverse stock split,
which was obtained at our stockholders meeting on September 18, 2000;
- our delivery of 732,500 shares of common stock without any restrictive
legend or stop transfer orders, except as otherwise provided in the
recapitalization agreement;
- the completion of an equity financing on or before October 31, 2000
generating net proceeds to us of at least $50 million, which condition
will be satisfied by the completion of this offering;
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- the repurchase of not less than $75 million in original principal amount
of our 12 1/2% senior notes on or before October 31, 2000, which
condition will be satisfied upon the application of the net proceeds of
this offering; and
- the representations and warranties contained in the recapitalization
agreement being true as of the date of the agreement and the date of
delivery of shares of common stock to the Series A preferred stock, the
Series C preferred stock and the repricing rights holders.
From and after the closing under the recapitalization agreement, the
holders of Series A preferred stock, Series C preferred stock and the repricing
rights agreed to release us from any claims that existed before the closing,
other than claims arising out of the recapitalization agreement.
REPURCHASE OF OUR SENIOR NOTES. On September 1, 2000, we commenced a tender
offer to purchase for cash, on a pro rata basis among tendering holders, $75
million principal amount of our 12 1/2% senior notes under the terms and subject
to the conditions set forth in the offer to purchase and consent solicitation
statement. As part of the tender offer, we also solicited the consent of the
holders of notes to two proposed amendments to the indenture. One of the
proposed amendments would amend the restrictive covenant limiting our incurrence
of debt to provide for a dollar for dollar increase in the permitted
indebtedness up to a maximum of $60 million, to the extent that the equity
raised pursuant to this offering exceeds $50 million, net of all costs related
to issuance. The other proposed amendment would provide that a "Change of
Control" will not be deemed to occur as a result of the recapitalization or this
offering. This amendment will permit us to complete the recapitalization and
this offering without triggering the right of each holder, at the holder's
option, to require us to repurchase all or any part of the holder's notes at a
cash price equal to 101% of the principal amount thereof, plus accrued and
unpaid interest and liquidated damages, if any, to the payment date.
We commenced the tender offer pursuant to a participation agreement, dated
as of July 17, 2000, that we had entered into with the holders of approximately
$94 million principal amount of the senior notes. Under the participation
agreement, the holders that entered into the agreement agreed to tender their
notes to us for a price of $650 per $1,000 principal amount of notes and to
consent to the proposed amendments to the indenture governing the senior notes.
One of the conditions to these holders' agreement to tender was that the holders
of at least $110 million principal amount of notes tender their notes pursuant
to the offer.
As of October 4, 2000, the holders of approximately $104.3 million
principal amount of notes had validly tendered and not withdrawn their notes and
had consented to the proposed amendments on or before the consent date. As of
October 6, 2000, we amended the participation agreement with the holders of
approximately $94 million principal amount of notes to (1) increase the tender
offer consideration per $1,000 principal amount of notes tendered and accepted
for payment to $680 and (2) to decrease the minimum tender condition to provide
that one of the conditions to the tender offer is that the holders of
approximately $104 million principal amount of notes tender pursuant to the
offer. As a result, on October 6, 2000, we amended the terms of the offer to
increase the price and decrease the minimum tender condition, and we extended
the expiration date to 5:00 p.m., New York City time, on October 20, 2000. We
have since extended the expiration date to 8:30 a.m., New York City time, on
October 30, 2000.
Under the terms of the offer, as amended, holders who validly tendered
their notes before the consent date will receive total consideration of $700,
which includes $680 for the tender of the notes and $20 for the holder's consent
to the proposed amendments to the indenture, and these holders may not withdraw
their notes after the consent date, which occurred on September 18, 2000.
Holders who validly tender their notes after the consent date and before 8:30
a.m., New York City time on October 30, 2000, the expiration date, will receive
$680 for each $1,000 principal amount of notes validly tendered and accepted for
payment.
As of October 25, 2000, the holders of approximately $104.3 million
principal amount of notes had validly tendered and not withdrawn their notes and
had consented to the proposed amendments on or before the consent date. Under
the terms of the offer, these holders may not withdraw their notes after the
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consent date, which occurred on September 18, 2000. We have executed a
supplement to the indenture effecting the proposed amendment, which will become
operative upon the completion of the tender offer.
The consummation of the tender offer is subject to the satisfaction or
waiver of the following conditions:
- We must complete an equity offering that will yield net proceeds to us of
at least $50 million on terms acceptable to us substantially concurrent
with the completion of the tender offer, which condition will be
satisfied upon the completion of this offering.
- We must have received consents from the holders of at least 66 2/3% of
the principal amount of notes with respect to the proposed amendments to
the indenture. As of October 25, 2000, the holders of approximately 88%
of the notes had consented to the proposed amendments.
- The general conditions described in the offer statement, including that
there has not been any general suspension of trading in, or limitation on
prices for trading in, securities in the United States securities or
financial markets and that no order or law exists that might prohibit the
completion of the offer and some other matters, must be met.
The effect of a repurchase of the notes pursuant to the offer and the
repayment of a portion of the debt under our credit agreement would be to reduce
our annual interest costs from $18 million to less than $8 million. In addition,
EBITDA to interest coverage would increase to approximately 3.7 to 1. As a
result, we will have additional borrowing capacity under the indenture governing
the senior notes and our credit agreement with Ableco Finance LLC with which to
carry out our redevelopment program and finance future acquisitions.
PRICE RANGE OF COMMON STOCK; DIVIDEND HISTORY
Before this offering, our common stock was quoted on the OTC Bulletin Board
under the symbol "QSRI." On October 25, 2000, the last price at which our common
stock was quoted on the OTC Bulletin Board was $0.04 per share, on a pre-reverse
split basis. Our common stock was quoted on the Nasdaq SmallCap Market under the
symbol "QSRI" from May 1997 to November 11, 1999. On November 11, 1999, Nasdaq
delisted our common stock for failing to meet the net tangible asset test, the
minimum market capitalization requirement and the minimum bid price
requirements. The following table sets forth the high and low closing bid prices
for our common stock as reported on Nasdaq and quoted on the OTC Bulletin Board
for the periods stated above. The market prices reported below have also been
adjusted to give retroactive effect to the 156 to 1 reverse stock split.
<TABLE>
<CAPTION>
AS ADJUSTED FOR
HISTORICAL REVERSE STOCK SPLIT
--------------- -----------------------
HIGH LOW HIGH LOW
------ ------ ---------- ----------
<S> <C> <C> <C> <C>
FISCAL YEAR ENDED JUNE 30, 1999
First Quarter....................................... $8.000 $6.500 $1,248.000 $1,014.000
Second Quarter...................................... 7.000 3.375 1,092.000 526.500
Third Quarter....................................... 4.125 1.125 643.500 175.500
Fourth Quarter...................................... 1.469 0.937 229.164 146.172
FISCAL YEAR ENDING JUNE 30, 2000
First Quarter....................................... $0.938 $0.281 $ 146.328 $ 43.836
Second Quarter...................................... 0.594 0.281 92.664 43.836
Third Quarter....................................... 0.530 0.281 82.680 43.836
Fourth Quarter...................................... 0.406 0.094 63.336 14.664
FISCAL YEAR ENDING JUNE 30, 2001
First Quarter....................................... $0.266 $0.047 $ 41.496 $ 7.316
Second Quarter (through October 25, 2000)........... $0.049 $0.040 $ 7.644 $ 6.240
</TABLE>
As of October 3, 2000, we had approximately 938 record holders of our
shares of common stock.
Our common stock has been approved for trading on the Nasdaq National
Market under the symbol "DVXE" subject to issuance.
22
<PAGE> 23
We have never declared or paid any dividends on our common stock. We
currently intend to retain future earnings, if any, for the operation and
development of our business and do not intend to pay any dividends on our common
stock in the foreseeable future. Because DevX Energy, Inc. is a holding company,
our ability to pay dividends depends on the ability of our subsidiaries to pay
cash dividends or make other cash distributions. Our credit agreement prohibits
us from paying cash dividends on our common stock and the senior notes indenture
restricts our payment of dividends on common stock. Our board of directors has
sole discretion over the declaration and payment of future dividends subject to
Delaware corporate law. Any future dividends may also be restricted by any loan
agreements which we may enter into from time to time and will depend on our
profitability, financial condition, cash requirements, future prospects, general
business conditions, the terms of our debt agreements, compliance with the
Delaware General Corporation Law and other factors our board of directors
believes relevant.
USE OF PROCEEDS
We estimate that we will receive net proceeds of approximately $63.5
million, or $73.3 million if the underwriters exercise their over-allotment
option in full, from the sale of the shares of common stock offered by this
prospectus, after deducting underwriting discounts and commissions and estimated
offering expenses.
We intend to use the net proceeds as follows:
- approximately $52.5 million to purchase up to $75 million in aggregate
original principal amount of our 12 1/2% senior notes at a discount; and
- to repay approximately $11 million of the $14 million debt outstanding
under our credit agreement as of October 26, 2000.
<TABLE>
<CAPTION>
AMOUNTS
--------------
(IN THOUSANDS)
<S> <C>
SOURCES
Common stock.......................................... $70,000(1)
Less discount and offering expenses................... $ 6,500
-------
Net proceeds..................................... $63,500
=======
USES
Repurchase of 12 1/2% senior notes(2)................. $52,500
Repayment of debt under our credit agreement(3)....... 11,000
-------
Total....................................... $63,500
=======
</TABLE>
---------------
(1) If the underwriters' over-allotment is exercised in full, the gross proceeds
will be $80.5 million.
(2) We borrowed the $125 million aggregate original principal amount under our
12 1/2% senior notes to acquire net profits interests and overriding royalty
interests in oil and natural gas properties. The interest rate on our senior
notes is 12 1/2% per annum, and the maturity date is July 1, 2008.
(3) As of June 30, 2000, we had $18.5 million debt outstanding under our credit
agreement. The interest rate under our credit agreement is currently 11.5%
per annum, and the maturity date is October 22, 2001.
23
<PAGE> 24
CAPITALIZATION
The following table presents our capitalization as of June 30, 2000 on an
actual basis and on a pro forma basis giving effect to the recapitalization and
this offering, assuming that it yields net proceeds to us of $63.5 million.
You should read this table in conjunction with our consolidated financial
statements and our unaudited pro forma condensed consolidated financial
statements included in this prospectus.
<TABLE>
<CAPTION>
AT JUNE 30, 2000
----------------------
HISTORICAL PRO FORMA
---------- ---------
(IN THOUSANDS)
<S> <C> <C>
Total long-term indebtedness (including current portion):
Credit Agreement.......................................... $ 18,500 $ 7,500
12 1/2% Senior Notes due 2008............................. 125,000 50,000
Other..................................................... 584 584
-------- --------
Total long-term indebtedness...................... 144,084 58,084
Stockholders' equity:
Preferred Stock:
Series A Participating Convertible Preferred Stock,
$0.01 par value; 9,600,000 shares authorized;
9,600,000 shares issued and outstanding............... 96 --
Series B Participating Convertible Preferred Stock,
$0.01 par value; 9,600,000 shares authorized; no
shares issued or outstanding.......................... -- --
Series C Convertible Preferred Stock, $0.01 par value;
10,400 shares authorized; 2,173 shares issued and
outstanding........................................... -- --
Common Stock.............................................. 135 2,633
Additional paid-in capital................................ 65,112 118,959
Accumulated deficit....................................... (92,934) (69,208)
Treasury stock, at cost................................... (7,251) --
-------- --------
Total stockholders' equity (net capital
deficiency)...................................... (34,842) 52,384
-------- --------
Total capitalization.............................. $109,242 $110,468
======== ========
</TABLE>
24
<PAGE> 25
DILUTION
Our pro forma net tangible book value per share of common stock as of June
30, 2000 was zero due to a stockholders' deficit of approximately $34.8 million.
Pro forma net tangible book value per share before this offering represents the
amount of our total tangible assets reduced by the amount of our total
liabilities and divided by the total number of shares of common stock
outstanding assuming that the reverse stock split and the exchange of shares by
the Series A preferred stockholder, the Series C preferred stockholders and the
repricing rights holders have been completed. After giving effect to the entire
recapitalization and the sale of 10,000,000 shares of common stock offered by
us, and after deducting the underwriting discount and estimated offering
expenses payable by us, our pro forma net tangible book value at June 30, 2000
would have been approximately $47.7 million or $4.24 per share of common stock.
This represents an immediate increase in pro forma net tangible book value of
$4.24 per share to existing stockholders and an immediate dilution of $2.76 per
share to new investors purchasing common stock in this offering. Dilution in pro
forma net tangible book value per share represents the difference between the
amount per share paid by purchasers of common stock in this offering and the pro
forma net tangible book value per share of common stock immediately after the
completion of this offering and the recapitalization. The following table
illustrates this dilution:
<TABLE>
<S> <C>
Public offering price per share........................ $ 7.00
Pro forma net tangible book value per share as of June
30, 2000 before the offering......................... $ --
Increase per share attributable to new investors....... $ 4.24
Pro forma net tangible book value per share after the
offering and the recapitalization.................... $ 4.24
Pro forma net tangible book value after the offering
and the recapitalization............................. $47,702,000
Dilution per share to new investors.................... $ 2.76
</TABLE>
The following table summarizes on a pro forma basis, after giving effect to
this offering, as of June 30, 2000, the differences between the existing
stockholders and the new investors with respect to the number of shares of
common stock purchased from us, the total consideration paid to us and the
average price per share paid and before deducting the underwriting discounts and
commissions and our estimated offering expenses:
<TABLE>
<CAPTION>
SHARES PURCHASED TOTAL CONSIDERATION
-------------------- ----------------------
NUMBER PERCENT AMOUNT PERCENT
---------- ------- ------------ -------
<S> <C> <C> <C> <C>
Existing stockholders......................... 1,250,000 11% $ 58,092,000 45%
New investors................................. 10,000,000 89% $ 70,000,000 55%
---------- --- ------------ ---
Total:.............................. 11,250,000 100% $128,092,000 100%
</TABLE>
The preceding tables assume no exercise of the underwriters' over-allotment
option. To the extent the over-allotment option is exercised, there will be
further dilution to new investors. See note 5 of our notes to consolidated
financial statements included in this prospectus.
25
<PAGE> 26
SELECTED CONSOLIDATED FINANCIAL DATA
The following table sets forth our selected consolidated financial data for
each of the periods indicated. The financial data for the five years ended June
30, 2000 are derived from our audited consolidated financial statements. You
should read this information along with our consolidated financial statements
and the notes to those financial statements included in this prospectus. For
further discussion of our consolidated financial statements, see "Management's
Discussion and Analysis of Financial Condition and Results and Operations."
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
-------------------------------------------------
1996 1997 1998 1999 2000
------- ------- -------- -------- -------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C>
OPERATIONS DATA:
Oil and natural gas sales(1)............... $ 2,079 $ 4,381 $ 12,665 $ 33,783 $32,584
Oil and natural gas production
expenses(1).............................. 1,175 2,507 6,333 9,127 7,097
------- ------- -------- -------- -------
Net oil and natural gas revenues........... 904 1,874 6,332 24,656 25,487
General and administrative expenses........ 1,113 1,452 2,259 3,534 3,026
------- ------- -------- -------- -------
EBITDA(2).................................. (209) 422 4,073 21,122 22,461
Interest and financing costs(3)............ 421 878 3,957 17,003 16,945
Depreciation, depletion, and
amortization(4).......................... 630 982 4,809 13,354 10,259
Hedge contract termination costs(5)........ -- -- -- -- 3,328
Ceiling test write-down(6)................. -- -- 28,166 35,033 --
Interest and other income.................. (71) (300) (105) (326) (143)
Extraordinary item(7)...................... -- 171 -- 3,549 1,130
------- ------- -------- -------- -------
Net loss................................... $(1,189) $(1,309) $(32,754) $(47,491) $(9,058)
======= ======= ======== ======== =======
Net loss per common share.................. $ (0.05) $ (0.05) $ (1.44) $ (1.51) $ (0.21)
CASH FLOWS DATA:
Net cash provided by (used in) operating
activities............................... $ (620) $ 263 $ 1,041 $ 9,504 $ (834)
Net cash used in investing activities...... (5,502) (4,305) (154,342) (1,611) (3,874)
Net cash provided by financing
activities............................... 6,622 3,752 154,021 444 7,222
Net increase (decrease) in cash............ 500 (290) 720 8,337 2,514
</TABLE>
<TABLE>
<CAPTION>
AT JUNE 30,
--------------------------------------------------
1996 1997 1998 1999 2000
------- ------- -------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA (AT END OF PERIOD):
Total current assets...................... $ 1,533 $ 1,066 $ 6,411 $ 14,019 $ 18,524
Property and equipment, net............... 9,662 16,187 142,467 97,198 92,525
Deferred assets........................... 88 -- 4,797 7,993 8,144
Total assets.............................. 11,283 17,253 153,675 119,210 119,193
Total current liabilities................. 1,450 3,670 6,836 11,142 10,535
Long-term obligations, net of current
portion................................. 6,670 7,152 153,619 133,852 143,500
Total stockholders' equity (deficit)...... 3,163 6,431 (6,780) (25,784) (34,842)
</TABLE>
---------------
(1) Oil and natural gas sales and production expenses related to net profits
interests have been presented as if the net profits interests were working
interests. Oil and natural gas sales include revenues relating to the net
profits interests of $6,219,000 for the year ended June 30, 1998,
$29,071,000 for the year ended June 30, 1999, and $28,715,000 for the year
ended June 30, 2000. Oil and natural gas production expenses include
expenses relating to the net profits interests of $1,787,000 for the year
ended June 30, 1998, $5,931,000 for the year ended June 30, 1999, and
$5,725,000 for the year ended June 30, 2000.
26
<PAGE> 27
(2) EBITDA represents earnings before interest expense, income taxes,
depreciation, depletion and amortization expense, write down of oil and
natural gas properties and extraordinary items and excludes interest and
other income. EBITDA is not a measure of income or cash flows in accordance
with generally accepted accounting principles, but is presented as a
supplemental financial indicator as to our ability to service or incur debt.
EBITDA is not presented as an indicator of cash available for discretionary
spending or as a measure of liquidity. EBITDA may not be comparable to other
similarly titled measures of other companies. Our credit agreement requires
the maintenance of specified EBITDA ratios. EBITDA should not be considered
in isolation or as a substitute for net income, operating cash flow or any
other measure of financial performance prepared in accordance with generally
accepted accounting principles or as a measure of our profitability or
liquidity.
(3) Interest charges payable on outstanding debt obligations.
(4) Depreciation, depletion and amortization includes $22,000 of amortized
deferred charges related to our natural gas price hedging program for the
year ended June 30, 1998. Depreciation, depletion and amortization for the
year ended June 30, 1999 includes amortized deferred charges related to debt
obligations of $1.3 million, and $120,000 of amortized deferred charges
related to our natural gas price hedging program. Depreciation, depletion
and amortization includes for the year ended June 30, 2000 $1.6 million of
amortized deferred charges related to debt obligations, and $98,000 of
amortized deferred charges related to our natural gas price hedging program.
(5) In conjunction with the execution of our restated credit agreement in
October 1999, we terminated the ceiling portion of a natural gas hedging
contract at a cost of $3,328,000.
(6) In accordance with the full cost method of accounting, the results of
operations for the year ended June 30, 1998 include a writedown of oil and
natural gas properties of $28,166,000 and for the year ended June 30, 1999
include a writedown of $35,033,000.
(7) During February 1997, we recognized a loss of $171,000 in connection with
restructuring a debt obligation. During July 1998, we terminated a LIBOR
interest rate swap agreement at a cost of $3,549,000. During October 1999,
we retired borrowings under our old credit agreement and entered into a
restated credit agreement with a new lender. As a result, we wrote off
$1,130,000 of deferred costs relating to the old credit agreement.
We did not pay dividends in any of the periods presented.
27
<PAGE> 28
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following unaudited pro forma condensed consolidated financial
statements present the effects of: the recapitalization, including the reverse
stock split, the receipt of $63.5 million of net proceeds from this offering,
the acquisition of $75 million original face value of our 12 1/2% senior notes
for approximately $52.5 million and the repayment of a portion of the borrowings
under our credit facility.
The unaudited pro forma condensed consolidated balance sheet presents the
financial position of the company as of June 30, 2000 assuming the proposed
transactions had occurred as of June 30, 2000. This pro forma information is
based upon the historical June 30, 2000 balance sheet of the company included
elsewhere in this prospectus.
The unaudited pro forma condensed consolidated statements of operations
give effect to the proposed transactions as if such transactions had been
entered into on July 1, 1999. This pro forma information is based upon the
historical results of operations of the company for the year ended June 30,
2000, included elsewhere in this prospectus.
The unaudited pro forma condensed consolidated financial statements are
based upon available information and assumptions that management of the company
believes are reasonable. The unaudited pro forma condensed consolidated
financial data do not purport to represent the financial position or results of
operations which would have occurred if these transactions had been completed on
the dates indicated or the company's financial position or results of operations
for any future date or period. You should read this unaudited pro forma
condensed consolidated financial data together with the company's historical
financial statements and the notes to those financial statements included in
this prospectus.
28
<PAGE> 29
DEVX ENERGY, INC.
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET
JUNE 30, 2000
AMOUNTS IN THOUSANDS EXCEPT SHARE AND PER SHARE DATA
<TABLE>
<CAPTION>
PRO FORMA
HISTORICAL ADJUSTMENTS PRO FORMA
------------ ------------ ------------
<S> <C> <C> <C>
ASSETS
Current assets
Cash............................................. $ 11,881 $ 63,500(3) $ 11,881
(52,500)(4)
(11,000)(5)
Other current assets............................. 6,643 6,643
------------ ------------ ------------
Total current assets............................... 18,524 -- 18,524
Net property & equipment........................... 92,525 92,525
Other assets....................................... 8,144 (3,462)(4) 4,682
------------ ------------ ------------
Total assets............................. $ 119,193 $ (3,462) $ 115,731
============ ============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current liabilities
Accounts payable and accrued liabilities......... $ 9,951 $ (4,688)(4) $ 5,263
Current portion of long-term debt................ 584 584
------------ ------------ ------------
Total current liabilities.......................... 10,535 (4,688) 5,847
11,000(5)
Long-term obligations, net of current portion...... 143,500 (75,000)(4) 57,500
------------ ------------ ------------
Total liabilities........................ 154,035 (90,688) 63,347
============ ============ ============
STOCKHOLDERS' EQUITY (DEFICIT)
Preferred stock.................................. 96 (96)(1) --
Common stock..................................... 135 158(1) 2,633
2,340(3)
Additional paid-in capital....................... 65,112 (62)(1) 118,959
61,160(3)
(7,251)(1) (69,208)
Accumulated Deficit.............................. (92,934) 23,726(4)
Treasury stock................................... (7,251) 7,251(1) --
------------ ------------ ------------
Total stockholders' equity (deficit)..... (34,842) 87,226 52,384
------------ ------------ ------------
Total liabilities and stockholders'
equity
(deficit).............................. $ 119,193 $ (3,462) $ 115,731
============ ============ ============
SHARE INFORMATION
Shares Authorized:
Preferred Stock.................................. 50,000,000 -- 50,000,000
Common Stock..................................... 100,000,000 -- 100,000,000
Shares Issued and Outstanding
Preferred Stock.................................... 9,602,173 (9,602,173)(1) --
Common Stock....................................... 80,688,538 732,500(1) 11,250,000
(80,171,038)(2)
10,000,000(3)
</TABLE>
See accompanying notes.
29
<PAGE> 30
DEVX ENERGY, INC.
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED JUNE 30, 2000
AMOUNTS IN THOUSANDS EXCEPT SHARE AND PER SHARE DATA
<TABLE>
<CAPTION>
PRO FORMA
HISTORICAL ADJUSTMENTS PRO FORMA
----------- ------------ -----------
<S> <C> <C> <C>
Revenues:
Oil and natural gas revenues...................... $ 3,967 $ -- $ 3,967
Net profits and royalties interests............... 22,990 22,990
Interest and other income......................... 143 143
----------- ------------ -----------
Total revenues............................ 27,100 27,100
Expenses:
Oil and natural gas production expenses........... 1,372 1,372
General and administrative expenses............... 3,026 3,026
Interest and financing costs...................... 18,561 (9,807)(6) 7,729
(1,025)(7)
Hedge contract termination costs.................. 3,328 3,328
Depreciation, depletion and amortization.......... 8,741 8,741
----------- ------------ -----------
35,028 (10,832) 24,196
Net income (loss) before extraordinary loss......... $ (7,928) $ 10,832 $ 2,904
=========== ============ ===========
Net income (loss) before extraordinary loss per
common share, basic and diluted................... $ (0.18) $ 0.26
=========== ===========
Weighted average shares of common stock outstanding
during the period................................. 43,465,423 732,500(8) 11,011,125
(43,186,798)(9)
10,000,000(10)
</TABLE>
See accompanying notes.
30
<PAGE> 31
DEVX ENERGY, INC.
NOTES TO UNAUDITED PRO FORMA CONDENSED
CONSOLIDATED FINANCIAL STATEMENTS
NOTE A. GENERAL
Simultaneously with the closing of this offering, we will complete a
recapitalization which includes the following:
- a reverse stock split of every 156 outstanding shares of our common stock
into one share;
- the exchange of 9,600,000 outstanding shares of our Series A preferred
stock for 212,500 shares of post reverse-split common stock;
- the exchange of 2,173 outstanding shares of our Series C preferred stock
and warrants exercisable for 340,153 shares of common stock for 120,000
shares of post reverse-split common stock;
- the exchange of the 1,593,918 remaining unexercised common stock
repricing rights and warrants exercisable for 655,000 shares of common
stock for 400,000 shares of post reverse-split common stock; and
- the repurchase of $75 million face value of our senior notes for
approximately $52.5 million.
At our stockholders meeting on September 18, 2000, our stockholders
approved the first four elements of the recapitalization. The repurchase of our
senior notes does not require stockholder approval.
NOTE B. UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET
The accompanying unaudited pro forma condensed consolidated balance sheet
assumes the transactions discussed in Note A above were entered into on June 30,
2000 and reflects the following pro forma adjustments:
(1) To record the effects of the following recapitalization
transactions:
- the exchange of the 9,600,000 outstanding shares of Series A
preferred stock for 212,500 shares of post reverse-split common
stock;
- the exchange of the 2,173 outstanding shares of Series C preferred
stock and warrants exercisable for 340,153 shares of common stock
for 120,000 shares of post reverse-split common stock;
- the exchange of the 1,593,918 remaining unexercised common stock
repricing rights and warrants exercisable for 655,000 shares of
common stock for 400,000 shares of post reverse-split common
stock; and
- the cancellation of existing treasury stock.
(2) To record a proposed reverse stock split of our common stock
whereby every 156 outstanding shares of common stock will be reverse split
into one share outstanding.
(3) To record the net proceeds from this offering of $63.5 million in
cash and the issuance of 10,000,000 shares of post-reverse split common
stock.
(4) To record the retirement at a discount of $75 million original
face value of our outstanding senior notes for approximately $52.5 million,
including the writeoff of unamortized debt issuance costs and accrued
interest payable.
(5) To record repayment of a portion of the borrowings under our
credit facility.
31
<PAGE> 32
NOTE C. UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying unaudited pro forma condensed consolidated statements of
operations assume the transactions discussed in Note A above were entered into
on July 1, 1999 and reflect the following pro forma adjustments:
(6) To record a reduction in interest expense related to the
retirement of $75 million original face value of our outstanding senior
notes.
(7) To record a reduction in interest expense related to the repayment
of a portion of the borrowings under our credit facility.
(8) To record the effects of the number of post reverse stock split
common shares issued to holders of Series A and C preferred stock and stock
repricing rights and warrants in the recapitalization.
(9) To record the effects of the proposed reverse stock split on the
number of weighted average shares outstanding during the period presented.
(10) To record the shares of common stock issued in conjunction with
this offering for net proceeds of $63.5 million.
32
<PAGE> 33
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
We are an independent energy company engaged in the exploration,
development, exploitation and acquisition of oil and natural gas properties in
on-shore, known producing areas, using conventional recovery techniques.
Our goal is to expand our reserve base, cash flow and net income. Our
strategy to achieve these goals consists of these elements:
- develop, exploit and explore our existing oil and natural gas properties;
- identify acquisition opportunities that complement our existing
properties; and
- utilize a well balanced financial structure that will allow us to direct
the cash generated from operations to fund production and reserve growth
without having to be overly reliant on the capital markets.
We use the full cost method of accounting for our investment in oil and
natural gas properties. Under this method, we capitalize all acquisition,
exploration and development costs incurred for the purpose of finding oil and
natural gas reserves, including salaries, benefits and other related general and
administrative costs directly attributable to these activities. We capitalized
general and administrative costs of $0.7 million in the fiscal year ended June
30, 1998, $0.9 million in the fiscal year ended June 30, 1999 and $0.7 million
in the fiscal year ended June 30, 2000. We expense costs associated with
production and general corporate activities in the period incurred. We
capitalize interest costs related to unproved properties and properties under
development. Sales of oil and natural gas properties are accounted for as
adjustments of capitalized costs, with no gain or loss recognized, unless these
adjustments would significantly alter the relationship between capitalized costs
and proved reserves of oil and natural gas.
The following 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.
THE YEAR ENDED JUNE 30, 2000 COMPARED TO THE YEAR ENDED JUNE 30, 1999
REVENUES. Total revenues during the year ended June 30, 2000 were $32.6
million, a decrease of $1.2 million from $33.8 million for the year ended June
30, 1999. Our revenues were derived from the sale of 10.6 Bcf of natural gas at
an average price per Mcf of $2.59 and 224,000 barrels of oil at an average price
per barrel of $22.76. During the year ended June 30, 1999 our revenues were
derived from the sale of 13.0 Bcf of natural gas, at an average price per Mcf of
$2.13, and 500,000 barrels of oil, at an average price per barrel of $12.37.
Overall we produced 12.0 Bcfe at an average price of $2.72 per Mcfe during the
year ended June 30, 2000 as compared to 16.0 Bcfe at an average price of $2.12
per Mcfe during the year ended June 30, 1999. This represents a decrease of 4.0
Bcfe (25%) in production and an increase of $0.60 (28%) in the average price we
received.
We produced 224,000 barrels of oil during the year ended June 30, 2000, a
decrease of 276,000 barrels (55%) from the 500,000 barrels produced during the
comparable period in 1999. The properties that we sold at the end of June 1999
represent 196,000 barrels (71%) of the total decrease of 276,000 barrels.
Production from the properties that we owned during both periods decreased by
80,000 barrels. This represents a 26% decline from volumes produced during the
year ended June 30, 1999.
33
<PAGE> 34
The decrease in production of oil from the properties owned during the
comparative periods is comprised of three components:
- The Segno field has not been meeting production expectations. This under
performance represents approximately 37% of the decrease in production
from the properties that we owned during both periods. Remedial action is
being taken to rehabilitate this field.
- During March 1999, we shut in substantially all of the wells in the
Caprock Field in New Mexico in response to low oil prices. As oil prices
recovered, we returned to production those wells that produce
economically. In addition, we are in the early stages of a redevelopment
program in the Caprock Field to enhance production. We have drilled four
single lateral injection wells and one dual-lateral producing well. These
five wells along with the production facilities and a water injection
plant constitute phase one of the redevelopment program. Phase one covers
640 acres out of the approximate 20,000 acres we control in the Caprock
Field.
- The final component of the production decline is the result of the
natural depletion of our oil reservoirs.
We produced 10.6 Bcf of natural gas during the year ended June 30, 2000,
down from the 13.0 Bcf produced during the comparable period in 1999. The
properties that we sold at the end of June 1999 represent 1.0 Bcf (43%) of the
total decrease of 2.3 Bcf. Production from the properties that we owned during
both periods decreased by 1.3 Bcf. This represents an 11% decline from the
volumes produced during the year ended June 30, 1999. The decrease in production
from the properties owned during the comparative periods is comprised of three
components:
- The Gilmer field has experienced production declines in excess of what
was expected. The operator of the property has commenced drilling and
completion efforts on the first two of a series of proposed infield wells
to increase production.
- Our successful development and exploitation program in south Texas
resumed in August 1999 and ten new wells have been drilled through the
end of June 2000. These wells have high initial production rates and
significant initial decline rates, with approximately half of total
reserves being produced during the first year.
- The final component of the production decline is the result of the
natural depletion of our natural gas reservoirs.
On a Bcfe basis, production for the year ended June 30, 2000 was 12 Bcfe,
down 4.0 Bcfe (25%) from the 16.0 Bcfe produced during the comparable period in
1999. The properties that we sold at the end of June 1999 represent 2.2 Bcfe of
the total decrease of 4.0 Bcfe. Production from the properties that we owned
during both periods decreased by 1.8 Bcfe.
The decrease in revenues resulting from lower production volumes was offset
by the significant industry-wide increase in oil and natural gas prices. The
average price per barrel of oil sold by us during the year ended June 30, 2000
was $22.76, an increase of $10.39 per barrel (84%) over the $12.37 per barrel
during the year ended June 30, 2000. The average price per Mcf of natural gas
sold by us was $2.59 during the year ended June 30, 2000, an increase of $0.46
per Mcf (22%) over the $2.13 per Mcf during the comparable period in 1999. Oil
prices have remained at these elevated levels subsequent to June 30, 2000.
Natural gas prices were volatile throughout the year, and have remained so
subsequent to June 30, 2000. On an Mcfe basis, the average price received by us
during the year ended June 30, 2000 was $2.72, a $0.60 increase (28%) over the
$2.12 we received during the comparable period in 1999.
During the year ended June 30, 2000 we paid $470,000 in cash settlements
pursuant to our oil price-hedging program. The effect on the average oil prices
we received during the period was a decrease of $2.10 per barrel (8%). During
the year ended June 30, 2000 we paid $981,000 in cash settlements and amortized
$98,000 of deferred hedging costs regarding our natural gas price-hedging
program. The net negative effect on the average natural gas prices we received
during the period was $0.10 (4%). Payments
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<PAGE> 35
made as a result of our oil price-hedging program during the year ended June 30,
1999 were insignificant. During the comparable period in 1999 we received $1.7
million in cash settlements and amortized $120,000 of deferred hedging costs
regarding our natural gas price-hedging program. The net positive effect on the
average natural gas prices we received during the period was $0.13 per Mcf (6%).
COSTS AND EXPENSES. Operating costs and expenses for the year ended June
30, 2000, exclusive of a $3.3 million hedge contract termination payment and the
$1.1 million extraordinary loss from the write-down of deferred charges when we
replaced our operating loans, were $37.4 million. Of this total, lease operating
expenses and production taxes were $7.1 million, general and administrative
expenses were $3.0 million, interest charges were $18.6 million and depletion,
depreciation and amortization costs were $8.7 million. Operating costs and
expenses for the year ended June 30, 1999, exclusive of a non-cash ceiling test
write-down of $35.0 million and an extraordinary charge of $3.5 million, were
$43.0 million. Of this total, lease operating expenses and production taxes were
$9.1 million, general and administrative expenses were $3.5 million, interest
charges were $18.4 million and depletion, depreciation and amortization costs
were $11.9 million.
Severance and production taxes, which are based on the revenues derived
from the sale of oil and natural gas, were $1.43 million during the year ended
June 30, 2000, as compared to $1.38 million during the comparable period in
1999, an increase of $55,000, or 4%. While revenues, after adjusting for
commodity hedging contract settlements, decreased 3% during the comparable
periods wellhead revenues increased by 6%. Severance taxes are applied only to
wellhead revenues. Our commodity hedge results were the primary cause for our
severance and production taxes increasing, on a percentage basis, while overall
revenues decreased.
On a cost per Mcfe basis, severance taxes were $0.12 per Mcfe for the year
ended June 30, 2000 compared to $0.09 per Mcfe for the comparable period ending
June 30, 1999, an increase of 39%. Average wellhead prices rose by 41%, from
$2.02 per Mcfe during the year ended June 30, 1999 to $2.85 per Mcfe during the
year ended June 30, 2000.
Our lease operating expenses fell to $5.7 million for the year ended June
30, 2000, a decrease of $2.1 million, or 27%, from the $7.8 million incurred
during the comparable period in 1999. This decrease is primarily the result of
reduced costs from comparable properties and the elimination of costs from the
properties we sold at the end of June 1999. Lease operating expenses were $0.47
per Mcfe during the year ended June 30, 2000, a decrease of $0.02, or 3%, from
the $0.49 per Mcfe incurred during the comparable period in 1999. This
improvement is primarily the result of the sale of properties at the end of June
1999, which had higher operating costs per Mcfe than the properties we currently
own.
General and administrative expenses were $3.0 million during the year ended
June 30, 2000 compared to $3.5 million incurred during the year ended June 30,
1999. This decrease of $508,000 (14%) consists primarily of reduction in
personnel costs and professional fees. On a per unit basis, general and
administrative expenses for the year ended June 30, 2000 were $0.25 per Mcfe, an
increase of $0.03 per Mcfe (14%) from the $0.22 per Mcfe incurred during the
year ended June 30, 1999. This per unit increase in general and administrative
expenses is a result of our decreased level of oil and natural gas production.
Interest expense for the year ended June 30, 2000 was $18.6 million. This
was comprised of $17.0 million paid or payable in cash and $1.6 million of
amortized deferred costs incurred at the time that the related debt obligations
were incurred. During the year ended June 30, 1999 our interest expense was
$18.3 million. This was comprised of $17.0 million paid or payable in cash and
$1.3 million of amortized deferred debt issuance costs incurred at the time that
the related debt obligations were established. The increase of $0.3 million in
amortization of deferred debt issuance costs arose as a result of replacing our
old credit agreement with our new credit agreement. We recorded an extraordinary
loss of $1.1 million, in connection with the replacement of our old credit
agreement, which loss represented the unamortized deferred costs incurred with
respect to the old credit agreement.
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<PAGE> 36
On a per unit basis, cash interest expense for the year ended June 30, 2000
was $1.42 per Mcfe, as compared to $1.06 per Mcfe during the year ended June 30,
1999. This is the result of the 25% reduction in production we had during the
year ended June 30, 2000, as compared to the year ended June 30, 1999.
The decrease in depletion, depreciation and amortization costs of $3.1
million was a result of the 25% decrease in the volume of oil and natural gas
produced by us during the year ended June 30, 2000 as compared to the year ended
June 30, 1999. On a cost per Mcfe basis, the depletion, depreciation and
amortization costs decreased by $0.03 per Mcfe (3%). This decrease is a function
of:
- the $35 million non-cash write-down we recorded at December 31, 1998; and
- the reduced future capital expenditures required to develop the proved
reserves.
EXTRAORDINARY LOSS. In October 1999 we replaced our old credit agreement
with our new credit agreement. As a result we wrote off $1.1 million in
unamortized deferred debt issuance costs associated with the old credit
agreement. In July 1998, we unwound a LIBOR interest rate swap contract at a
cost of $3.5 million.
NET LOSS. We have incurred losses since inception, including $9.1 million,
or $0.21 per common share, for the year ended June 30, 2000 compared to $47.5
million, or $1.51 per common share for the year ended June 30, 1999. The decline
in oil and natural gas prices between December 31, 1997 and December 31, 1998
caused us to record non-cash write-downs of oil and natural gas properties of
$35 million and $28 million during the years ended June 30, 1999 and 1998,
respectively. Future declines in oil and natural gas prices could lead to
additional non-cash write-downs of our oil and natural gas properties.
THE YEAR ENDED JUNE 30, 1999 COMPARED TO THE YEAR ENDED JUNE 30, 1998
REVENUES. Total revenues during the year ended June 30, 1999 were $33.8
million, an increase of $21.1 million over the $12.7 million for the year ended
June 30, 1998. Our revenues were derived from the sale of 13.0 Bcf of natural
gas at an average price per Mcf of $2.13 and 500,000 barrels of oil at an
average price per barrel of $12.37. During the year ended June 30, 1998 our
revenues were derived from the sale of 3.4 Bcf of natural gas, at an average
price per Mcf of $2.27, and 325,000 barrels of oil, at an average price per
barrel of $15.52.
The two periods are not readily comparable because of our significant
growth during the year ended June 30, 1998, primarily resulting from the April
1998 acquisition of the Morgan Properties. Production from properties owned
throughout both periods was 1.0 Bcf of natural gas and 223,000 barrels of oil
during the year ended June 30, 1999. This represents an increase of 0.1 Bcf, or
14%, over the 0.9 Bcf of natural gas, and a decrease of 26,000 barrels, or 11%,
from the 250,000 barrels of oil produced during the year ended June 30, 1998.
The increase in natural gas production is a reflection of our successful
exploitation and development programs implemented during the year ended June 30,
1999, offset by the natural rate of depletion of the reservoirs associated with
these properties. The decrease in oil production is a combination of the
decision to temporarily reduce production from some producing areas with
relatively high production costs, due to the low price of oil received during
the year combined with the natural rate of depletion of the reservoirs
associated with these properties. The production of oil from those properties
temporarily shut in during the period of low oil prices was restored following
the return of oil prices to their currently higher levels. Production from
properties acquired during 1998 was 11.9 Bcf of natural gas and 276,000 barrels
of oil during 1999 as compared to 2.4 Bcf of natural gas and 75,000 barrels of
oil during 1998.
COSTS AND EXPENSES. Operating costs and expenses for the year ended June
30, 1999, exclusive of a non-cash ceiling test write-down of $35.0 million and
an extraordinary charge of $3.5 million, were $43.0 million. Of this total,
lease operating expenses and production taxes were $9.1 million, general and
administrative expenses were $3.5 million, interest charges were $18.3 million
and depletion, depreciation and amortization costs were $11.9 million. Operating
costs and expenses for the year ended June 30, 1998, exclusive of a non-cash
ceiling test write-down of $28.2 million, were $17.4 million. Of this total,
lease
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<PAGE> 37
operating expenses and production taxes were $6.3 million, general and
administrative costs were $2.3 million, interest charges were $4.0 million, and
depletion, depreciation and amortization costs were $4.8 million.
The increase in lease operating expenses and production taxes is a result
of our increased levels of oil and natural gas production. When lease operating
expenses and production taxes are compared on a cost per unit basis, the cost of
producing an Mcfe during the year ended June 30, 1999 decreased by $0.62 per
Mcfe, or 52%, to $0.58 from the $1.19 per Mcfe achieved during the year ended
June 30, 1998. This decrease in production costs per unit is primarily the
result of acquiring properties in April 1998 with lower operating costs per unit
than our other properties.
General and administrative expenses have increased by $1.3 million as a
result of our increased size requiring additional employees and incremental
costs; however, on a per unit basis, general and administrative expenses for the
year ended June 30, 1999 were $0.22 per Mcfe, a decrease of $0.21 per Mcfe, or
49%, from the $0.43 per Mcfe incurred during the year ended June 30, 1998. This
per unit decline in general and administrative expenses is a result of our
increased level of oil and natural gas production.
Interest expense for the year ended June 30, 1999 was $18.3 million. This
is comprised of $17.0 million paid or payable in cash and $1.3 million of
amortized deferred costs incurred at the time that the related debt obligations
were incurred. During the year ended June 30, 1998 total interest expense was
$4.0 million, which was comprised of $3.9 million paid or payable in cash and
$0.1 million of amortized deferred costs incurred at the time that the related
debt obligations were incurred. The increase of $14.3 million in interest
expense is due to an increase in the average interest bearing debt outstanding.
During the year ended June 30, 1999 we had average interest bearing debt
outstanding of $139.3 million, as compared to $48.5 million during the year
ended June 30, 1998. On a per unit basis, cash interest expense for the year
ended June 30, 1999 was $1.06 per Mcfe, as compared to $0.75 per Mcfe during the
year ended June 30, 1998.
The increase in depletion, depreciation and amortization costs of $7.1
million is a result of the increased volume of oil and natural gas produced by
us and the higher per unit cost of acquisition of the properties acquired during
the year ended June 30, 1998. On a cost per Mcfe of reserves the depletion,
depreciation and amortization costs decreased by $0.15 per Mcfe, or 17%,
primarily due to the effects of the non-cash writedowns of $35.0 million
recorded at December 31, 1998 and $28.2 million recorded at June 30, 1998 to
reflect the impact of lower oil and natural gas prices at those two dates. In
accordance with generally accepted accounting principles, at a point in time
coinciding with the quarterly and annual reporting periods, we must test the
carrying value of our oil and natural gas properties, net of related deferred
taxes, against the "cost center ceiling." The "cost center ceiling" is a
calculated amount based on estimated reserve volumes valued at then-current
realized prices held flat for the life of the properties discounted at 10% per
annum plus the lower of cost or estimated fair value of unproved properties. If
the carrying value exceeds the cost center ceiling, the excess must be expensed
in that period and the carrying value of the oil and natural gas reserves
lowered accordingly. Amounts required to be written off may not be reinstated
for any subsequent increase in the cost center ceilings.
EXTRAORDINARY LOSS. As a result of the placement of the $125 million of
12 1/2% senior notes in July, 1998 we unwound an interest rate hedge contract
related to existing floating interest rate bridge loans at a cost of
approximately $3.5 million. As the debt hedged was retired using the proceeds
from the issuance of the senior notes, the costs of terminating the hedge was
recognized as an extraordinary loss.
NET LOSS. We have incurred losses since inception, including $47.5 million,
or $1.51 per common share, for the year ended June 30, 1999, compared to $32.8
million, or $1.44 per share, for the year ended June 30, 1998. These losses are
a reflection of the low oil and natural gas prices experienced during the year
ended June 30, 1999 combined with our high leverage position.
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<PAGE> 38
LIQUIDITY AND CAPITAL RESOURCES
General
Simultaneously with the completion of this offering, we will complete a
recapitalization, which includes the following:
- a reverse stock split of every 156 outstanding shares of our common stock
into one share;
- the exchange of all preferred stock, all warrants exercisable for shares
of common stock and all remaining unexercised common stock repricing
rights for 732,500 shares of post reverse-split common stock;
- the completion of this offering, which will yield net proceeds to us of
$63.5 million; and
- the repurchase of $75 million face value of our 12 1/2% senior notes for
approximately $52.5 million.
Upon completion of the recapitalization, including this offering of common
stock that yields net proceeds to us of $63.5 million, our company will:
- obtain a discount on the repurchase of at least $75 million of our senior
notes, thereby creating more than $23 million of additional equity value
for our stockholders;
- on a pro forma basis, reduce our debt by $86.0 million, thereby
increasing annual cash flow available to fund growth by $10.8 million and
reducing our interest cost per Mcfe by nearly 59%;
- reduce our long-term debt to $57.5 million, which approximates 26% of our
June 30, 2000 SEC PV-10 of $217 million;
- eliminate all outstanding preferred stock;
- eliminate the dilutive effects of current market price conversion and
repricing rights held by some of our stockholders;
- improve our liquidity by using a portion of the proceeds from this
offering to pay down our senior working capital facility and modifying
the indenture governing our senior notes to permit us to increase our
senior working capital facility from $35 million to $49 million; and
- satisfy the listing requirements of the Nasdaq National Market with a
goal of improving the visibility and liquidity of our common stock.
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, development and
exploitation programs and 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 of these needs.
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 previously 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 these 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 and Foothill Capital Corporation
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<PAGE> 39
is subject to restrictions imposed by our 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
CREDIT AGREEMENT. On October 22, 1999, we entered into a 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, to fund, among other
things, development and exploitation expenditures, acquisitions and general
working capital. The restated credit agreement matures on October 22, 2001.
There are no scheduled principal repayments. The restated credit agreement bears
interest as follows:
- when the borrowings are less than $25 million, bank prime plus 2%;
- when the borrowings are $25 million or greater, bank prime plus 4.5%; and
- on amounts securing letters of credit issued on our behalf, 3%.
The interest rate as of September 30, 2000 under this agreement was 11.50% per
annum.
As of October 26, 2000, the maximum amount available to us under the credit
agreement was $30 million, of which $14 million in borrowings and $9.3 million
in letters of credit were outstanding. The funds available under our secured
credit agreement are limited to the lesser of:
- $50 million;
- the borrowing base calculation, which is the sum of: (1) 65% of proved
developed producing, (2) 45% of proved developed non-producing and (3)
40% of proved undeveloped from our reserve reports, updated monthly using
the 5 year NYMEX strip price for crude oil and natural gas; and
- the maximum amount of secured debt available under the senior notes
indenture, which is currently $35 million;
minus $5 million.
Under the credit agreement we must obtain a release of the security
interest held by our secured lenders before we can sell any of our oil or
natural gas properties. In addition, we are limited to making capital
expenditures of not more than $12 million in any 12 month period and not more
than $18 million between July 1, 1999 and October 22, 2001, the maturity date of
the credit agreement. As of June 30, 2000 we had recorded capital expenditures
totaling approximately $7 million against this limitation.
SENIOR NOTES. On July 8, 1998, we completed a private placement of $125
million principal amount of 12 1/2% senior notes due 2008. In addition, on July
8, 1998 and July 20, 1998, we completed the private placement of $31.0 million
of common stock. Pursuant to the note placement, we issued and sold the notes to
institutional buyers pursuant to Rule 144A and Regulation D promulgated under
the Securities Act of 1933. The notes mature on July 1, 2008, and interest on
the notes is payable semiannually on January 1 and July 1 of each year,
commencing January 1, 1999 at the rate of 12 1/2% per annum. The payment of the
notes is guaranteed by the parent company's three operating subsidiaries.
Our 12 1/2% senior notes limit our ability to incur indebtedness. Before
this offering, our maximum permitted indebtedness was limited to $50 million, of
which $35 million may be secured in priority to the 12 1/2% senior notes. To
incur indebtedness in excess of $50 million, we were required to demonstrate
that we would have, on a pro-forma basis over the last 12 months, an interest
coverage ratio (EBITDA divided by cash interest expense) of greater than 2.5
times.
Our senior notes indenture also provides that our senior secured debt,
including the debt under our credit agreement, may exceed $35 million if the
amount over $35 million is incurred pursuant to the
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<PAGE> 40
acquisition of additional assets and the terms of the financing of that
acquisition require that we provide a security interest on the acquired assets.
Upon completion of this offering, our indenture will be amended to provide
for a dollar for dollar increase in the maximum permitted indebtedness to the
extent that the equity raised pursuant to the offering and thereafter, exceeds
$50 million, net of all costs related to the equity issuance, up to a maximum of
$60 million. The permitted amount of senior secured indebtedness would increase
in the same manner as the maximum permitted indebtedness.
HEDGING ARRANGEMENTS AND LETTERS OF CREDIT. Some of our hedging
arrangements contain a "cap" whereby we must pay the counter-party if oil or
natural gas prices exceed the specified price in the contract. We are required
to maintain letters of credit with our counter-parties, and we may be required
to provide additional letters of credit if prices for oil and natural gas
futures increase above the "cap" prices. The amount of letters of credit
required under the hedging arrangements is a function of the market value of oil
and natural gas prices and the volumes of oil and natural gas subject to the
hedging contract. As a result, the amount of the letters of credit will
fluctuate with the market prices of oil and natural gas. These letters of credit
are issued pursuant to our credit agreement and as a result utilize some of our
borrowing capacity, reducing our remaining available funds under our credit
agreement. We recently amended our credit agreement to permit up to $12 million
in letters of credit. As of September 30, 2000, we have provided $6.2 million in
letters of credit to Enron, the counter-party to our hedge contracts containing
"caps." As of September 30, 2000, we had an additional $14 million in
outstanding loans and an unused availability of $9.8 million. In early October,
2000, Enron made a margin call and requested that we increase the amount of the
letters of credit to approximately $9.3 million, which will decrease the unused
availability under our credit agreement to approximately $6.7 million.
EQUITY CAPITAL. From inception through June 30, 2000 we have raised in
excess of $58 million, net of $7.3 million in treasury stock, in equity. After
completing the recapitalization, there will be approximately 1,250,000 shares of
our common stock outstanding in addition to the shares of common stock issued in
this offering. The equity offering contemplated by this prospectus involves
raising an additional $63.5 million, net of costs, for 10,000,000 shares of our
common stock. As a result, after completion of this offering and the
recapitalization, we will have approximately 11,250,000 shares of our common
stock outstanding.
DIVIDENDS. Because DevX Energy, Inc. is a holding company, our ability to
pay dividends depends on the ability of our subsidiaries to pay cash dividends
or make other cash distributions. Our credit agreement prohibits us from paying
cash dividends on our common stock and the senior notes indenture restricts our
payment of dividends on common stock.
Uses of capital
During the period since our inception in August 1994 through April 1998 our
primary method of replacing our production and increasing our reserves was
through acquisitions. Since that time our primary method of replacing production
and enhancing our reserves has been through the development and exploitation of
our oil and natural gas properties. In either case, these activities require
significant capital investments. While our earnings before non-cash charges have
been positive since 1997, we have not been able to generate sufficient cash from
this internal source to fund the replacement of our reserves consumed by
production without relying on external sources of capital. We expect to spend
$13.7 million on discretionary capital expenditures through June 2001 for
exploitation, development and exploration projects, depending on the
availability of funds. As of September 30, 2000 we are contractually obligated
to fund $4.2 million in capital expenditures through June 2001.
Contemporaneously with completion of this offering, our company will:
- purchase $75 million of our senior notes; and
- pay down a portion of our senior working capital facility.
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We continue to evaluate acquisition opportunities; however, there are no
existing agreements regarding any acquisitions. An acquisition may 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 any financing, if
obtained, 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 natural gas prices have increased during
the year ended June 30, 2000. Our results of operations and cash flow have been,
and will continue to be, affected somewhat by the volatility in oil and natural
gas prices. If 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.
CHANGES IN PRICES AND HEDGING ACTIVITIES
Annual average oil and natural gas prices have fluctuated significantly
over the last two years. During the period from July 1, 1998 through June 30,
2000, West Texas Intermediate spot crude oil prices averaged $20.22 per barrel
and traded between a low of $10.73 per barrel and a high of $34.65 per barrel.
During the same period, Henry Hub spot natural gas prices averaged $2.41 per Mcf
and traded between a low of $1.04 per Mcf and a high of $4.59 per Mcf.
The tables below set out our weighted average price per barrel of oil, the
weighted average price per Mcf of natural gas, the impact of our hedging
programs and the related NYMEX indices.
<TABLE>
<CAPTION>
JUNE 30,
------------------------
1998 1999 2000
------ ------ ------
<S> <C> <C> <C>
NATURAL GAS (PER MCF):
Average price received at wellhead.......................... $ 2.24 $ 2.00 $ 2.69
Effect of hedge contracts on average price.................. 0.03 0.13 (0.10)
------ ------ ------
Average price received, including hedge contracts........... $ 2.27 $ 2.13 $ 2.59
Average NYMEX Henry Hub..................................... $ 2.46 $ 2.01 $ 2.78
Average basis differential including hedge contracts........ (0.19) 0.12 (0.19)
Average basis differential excluding hedge contracts........ $(0.22) $(0.01) $(0.09)
OIL (PER BARREL):
Average price received at wellhead.......................... $15.07 $12.37 $24.86
Average effect of hedge contract............................ 0.45 0.00 (2.10)
------ ------ ------
Average price received, including hedge contracts........... $15.52 $12.37 $22.76
Average NYMEX Sweet Light Oil............................... $17.62 $14.45 $25.90
Average basis differential including hedge contracts........ (2.10) (2.08) (3.14)
Average basis differential excluding hedge contracts........ $(2.55) $(2.08) $(1.04)
</TABLE>
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We have a commodity price risk management or hedging strategy that is
designed to provide protection from low commodity prices while providing some
opportunity to enjoy the benefits of higher commodity prices. We have a series
of natural gas futures contracts with Bank of Montreal and with an affiliate of
Enron. This strategy is designed to provide a degree of protection from negative
shifts in natural gas prices as reported on the Henry Hub Nymex Index, on
approximately 73% of our expected natural gas production from reserves currently
classified as proved developed producing during the fiscal year ending June 30,
2001. At the same time, we are able to participate completely in upward
movements in the Henry Hub Nymex Index to the extent of approximately 76% of our
expected natural gas production from reserves currently classified as proved
developed producing for the fiscal year ending June 30, 2001.
The operator of a significant natural gas producing property in which we
hold a net profits interest sold natural gas under a fixed price contract for
the period January 1 through early October 1999. Retrospectively, the prices for
this contract, when compared to Henry Hub prices, were favorable during the
three months ended March 31, 1999 but became unfavorable for the following six
months. The fixed prices under this contract reduced the average wellhead price
we received during the year ended June 30, 2000 by approximately $0.06 per Mcf.
This fixed price contract expired during October 1999.
We had a contract with an affiliate of Enron involving the hedging of a
portion of our future natural gas production involving floor and ceiling prices
as set out in the table below. We shared 50% of the price of NYMEX Henry Hub in
excess of the ceiling price. This contract has expired. The volumes presented in
this table are divided equally over the months during the period:
<TABLE>
<CAPTION>
VOLUME FLOOR CEILING
PERIOD BEGINNING PERIOD ENDING (MMBTU) PRICE PRICE
---------------- ------------- ------- ----- -------
<S> <C> <C> <C> <C>
September 1, 1997 August 31, 1998 600,000 $1.90 $2.66
</TABLE>
We had a contract with an affiliate of Enron involving the hedging of a
portion of our future oil production involving floor and ceiling prices as set
out in the table below. We shared 50% of the price of NYMEX Henry Hub in excess
of the ceiling price. This contract has expired. The volumes presented in this
table are divided equally over the months during the period:
<TABLE>
<CAPTION>
VOLUME FLOOR CEILING
PERIOD BEGINNING PERIOD ENDING (MMBTU) PRICE PRICE
---------------- ------------- ------- ------ -------
<S> <C> <C> <C> <C>
September 1, 1997 August 31, 1998 120,000 $18.00 $20.40
</TABLE>
Effective May 1, 1998 through October 31, 1999 we had a contract with Bank
of Montreal involving the hedging of a portion of our future natural gas
production involving floor and ceiling prices as set out in the table below. The
volumes presented in this table are divided equally over the months during the
period:
<TABLE>
<CAPTION>
VOLUME FLOOR CEILING
PERIOD BEGINNING PERIOD ENDING (MMBTU) PRICE PRICE
---------------- ------------- ------- ----- -------
<S> <C> <C> <C> <C>
January 1, 1999 October 31, 1999 3,608,000 $2.00 $2.70
</TABLE>
Effective November 1, 1999 we unwound the ceiling price limitation on our
natural gas price hedging contract with Bank of Montreal at a cost of $3.3
million. The table below sets out the volume of natural gas that remains under
contract with the Bank of Montreal at a floor price of $2.00 per MMBTU. The
volumes set out in this table are divided equally over the months during the
period:
<TABLE>
<CAPTION>
VOLUME
PERIOD BEGINNING PERIOD ENDING (MMBTU)
---------------- ------------- ---------
<S> <C> <C>
November 1, 1999 December 31, 1999 722,000
January 1, 2000 December 31, 2000 3,520,000
January 1, 2001 December 31, 2001 2,970,000
January 1, 2002 December 31, 2002 2,550,000
January 1, 2003 December 31, 2003 2,250,000
</TABLE>
42
<PAGE> 43
The table below sets out the 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 the volume of natural gas hedged with a swap at
$2.40 per MMBtu with Enron. The volumes presented in this table are divided
equally over the months during the period:
<TABLE>
<CAPTION>
VOLUME
PERIOD BEGINNING PERIOD ENDING (MMBTU)
---------------- ------------- ---------
<S> <C> <C>
January 1, 1999 December 31, 1999 2,710,000
January 1, 2000 December 31, 2000 2,200,000
January 1, 2001 December 31, 2001 1,850,000
January 1, 2002 December 31, 2002 1,600,000
January 1, 2003 December 31, 2003 1,400,000
</TABLE>
The table below sets out the volume of oil hedged with a swap with Enron.
All of these contracts have expired. The volumes presented in this table are
divided equally over the months during the period:
<TABLE>
<CAPTION>
VOLUME
PERIOD BEGINNING PERIOD ENDING (BARRELS) PRICE PER BARREL
---------------- ------------- --------- ----------------
<S> <C> <C> <C>
March 1, 1999 August 31, 1999 60,000 $13.50
April 1, 1999 September 30, 1999 30,000 $14.35
April 1, 1999 September 30, 1999 30,000 $14.82
</TABLE>
The table below sets out the volume of oil hedged with a contract with
Enron involving floor and ceiling prices as set out in the table below. The
volumes presented in this table are divided equally over the months during the
period:
<TABLE>
<CAPTION>
FLOOR CEILING
VOLUME PRICE PER PRICE PER
PERIOD BEGINNING PERIOD ENDING (BARRELS) BARREL BARREL
---------------- ------------- --------- --------- ---------
<S> <C> <C> <C> <C>
December 1, 1999 March 31, 2000 40,000 $22.90 $25.77
April 1, 2000 June 30, 2000 15,000 $23.00 $28.16
July 1, 2000 December 31, 2000 30,000 $22.00 $28.63
</TABLE>
As of June 30, 2000 the fair market value of our hedging contracts,
measured as the estimated cost we would incur to terminate the arrangements, was
$5.3 million. As of June 30, 2000 a 10% increase in oil and natural gas prices
would have resulted in an unfavorable change of $2.0 million in the fair market
value of our hedging contracts and a 10% decrease in oil and natural gas prices
would have resulted in a favorable change of $2.1 million in the fair market
value of our hedging contracts.
NEW ACCOUNTING PRONOUNCEMENT
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities, as amended, which we adopted effective July 1, 2000. The
Statement will require us to recognize all derivatives on the balance sheet at
fair value. Derivatives that are not hedges must be adjusted to fair value
through income. If the derivative is a hedge, depending on the nature of the
hedge, changes in the fair value of derivatives will either be offset against
the change in fair value of the hedged assets, liabilities, or firm commitments
through earnings or recognized in other comprehensive income until the hedged
item is recognized in earnings. The ineffective portion of a derivative's change
in fair value will be immediately recognized in earnings. We estimate that the
fair value of our hedge positions, measured as the costs to terminate the hedge
contracts, represented a net liability to us of approximately $8.7 million at
September 30, 2000. This amount will be reflected on our September 30, 2000
balance sheet.
43
<PAGE> 44
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 rate hedge on our indebtedness under
the credit agreement and short term loans used to finance the April 1998
acquisition of our net profit and royalty interests if we failed to complete the
private placement of the unsecured notes. Once the private placement of the
12 1/2% senior notes was completed, we determined that the interest rate swap no
longer had any on-going value to us. On July 9, 1998, we unwound this swap at a
cost to us of approximately $3.5 million, using a portion of the proceeds from
the placement of our senior notes. This cost was expensed as an extraordinary
loss during the year ended June 30, 1999.
44
<PAGE> 45
BUSINESS
GENERAL
We are an independent energy company engaged in the exploration,
development, exploitation and acquisition of on-shore oil and natural gas
properties in conventional producing areas of North America. To date, we have
grown almost exclusively through acquisitions of properties. As a result of our
acquisitions we own a diverse property base concentrated in six producing areas
or basins. Approximately 58% of our proved reserves are concentrated in south
and east Texas. Our assets are primarily long-lived natural gas properties
exhibiting low operating costs.
At June 30, 2000, we owned proved reserves of approximately 133 Bcf of
natural gas and 2 MMBbls of oil aggregating to approximately 145 Bcfe with an
SEC PV-10 value of $217 million and a reserve life index of 12.1 years.
Approximately 68% of our proved reserves were classified as proved developed and
approximately 92% of our proved reserves were natural gas. Our average daily net
production for the month of June, was 30.6 MMcfe. At June 30, 2000, we had
interests in 667 wells, including 83 service wells.
Following the completion of the recapitalization and this offering, we
expect to be able to execute an annual capital expenditure program of
approximately $20 million. As part of this program, we plan to increase our
exploration expenditures and are currently having discussions with potential
exploration joint venture partners. On a pro forma basis, we expect our cash
flow to increase as a result of the $10.8 million decrease in annual interest
expense that we anticipate from the completion of the recapitalization. Upon
completion of this offering, the indenture governing our 12 1/2% senior notes
will be amended to allow us to increase the level of permitted borrowings under
our credit facility to $49 million. We anticipate that we can fund our capital
expenditure program through a combination of working capital, operating cash
flow and additional borrowings under our credit facility.
Our properties are diversified over 6 asset areas located principally in
the southwestern United States. Our interests in east and south Texas represent
approximately 62% of our proved reserves on an SEC PV-10 basis at June 30, 2000.
In addition, we own substantial properties in Kentucky, New Mexico and Oklahoma.
At June 30, 2000 we had interests in leases covering approximately 177,000
gross, or 74,000 net, acres.
We were incorporated under the laws of Delaware in 1989. The parent company
is principally a holding company, holding the stock of its subsidiaries that own
our assets and conduct our operations. Our principal executive offices and
mailing address are 13760 Noel Road, Suite 1030, Dallas, Texas 75240-7336 and
our telephone number at that address is 972-233-9906.
BUSINESS STRATEGY
Our goal is to enhance stockholder value by expanding our oil and natural
gas reserves, production levels and cash flow. Our strategy to achieve these
goals consists of these elements:
- Recapitalizing the company through a significant reduction of debt, a
corresponding increase of equity and the elimination of all preferred
securities;
- Pursuing managed asset growth through:
- actively developing and exploiting our existing higher potential oil and
natural gas properties, particularly in south and east Texas;
- selective acquisitions of high-potential oil and natural gas assets that
complement our existing properties, coupled with routine dispositions of
non-core and lower potential properties;
- an increased emphasis on exploration activities; and
- targeted merger(s) where the consolidation with other companies will
give us access to quality reserves within our core areas;
45
<PAGE> 46
- Maintaining a capital and financial structure with a prudent debt to
equity ratio that will allow us to use cash generated from operations to
fund growth in our production and reserves; and
- Enhancing our board of directors and management team through the addition
of new industry senior executives to assist the company in improving and
expanding its operating capacity and exploration activities.
THE RECAPITALIZATION. Simultaneously with the closing of this offering, we
will complete a recapitalization which includes: (a) a reverse stock split of
every 156 outstanding shares of our common stock into one share; (b) the
exchange of all preferred stock, all warrants exercisable for shares of common
stock and all remaining unexercised common stock repricing rights for 732,500
shares of post reverse-split common stock; and (c) the repurchase of $75 million
face value of our senior notes for approximately $52.5 million. At our
stockholders meeting on September 18, 2000, our stockholders approved the first
two elements of the recapitalization. The repurchase of our 12 1/2% senior notes
does not require stockholder approval.
When the recapitalization and this offering are complete, our company will:
- recognize a gain on the repurchase of $75 million of our senior notes at
a discount, thereby creating more than $23 million of additional equity
value for our stockholders;
- on a pro forma basis, reduce our debt by $86.0 million, thereby
increasing annual cash flow available to fund growth by $10.8 million and
reducing our interest cost per Mcfe by nearly 59%;
- reduce our long-term debt to $57.5 million, which approximates 26% of our
June 30, 2000 SEC PV-10 of $217 million;
- eliminate all outstanding preferred stock;
- eliminate the dilutive effects of current market price conversion and
repricing rights held by some of our stockholders;
- improve our liquidity by using a portion of the net proceeds of this
offering to pay down our senior working capital facility and by modifying
the indenture governing our senior notes to permit us to increase our
senior working capital facility from $35 million to $49 million; and
- satisfy the listing requirements of the Nasdaq National Market with a
goal of improving the visibility and liquidity of our common stock.
Upon completion of the recapitalization and this offering, there will be
outstanding approximately 11,250,000 shares of our common stock, no shares of
preferred stock and no repricing rights.
DEVELOPMENT AND EXPLOITATION OF EXISTING PROPERTIES. We have identified
over 400 potential development locations and exploitation opportunities on our
properties. We have prioritized these opportunities to concentrate on those
higher impact projects that have the potential to replace and grow our reserves
while maximizing the long-term return on our capital. Our opportunities include:
- additional exploration of well-defined locations on existing properties
such as in the J.C. Martin field in south Texas;
- infill drilling on our producing properties such as in the Gilmer field
in east Texas;
- recompletion of existing wells in behind-pipe intervals such as in the
Lopeno/Volpe field in south Texas; and
- developing proved undeveloped reserves by drilling low risk, long lived
natural gas wells in the shallow New Albany Shale formation in Kentucky.
PROPERTY ACQUISITIONS AND DIVESTITURES. We will diligently pursue the
acquisition of oil and natural gas properties that we believe will provide us
with a combination of increased production, reserve growth and exploration
potential. Our focus will be on only those properties that can be acquired at
prices that will enhance our overall return on capital. Although we are
currently weighted towards gas reserves, we
46
<PAGE> 47
anticipate that we may return to a more even oil to natural gas ratio. While the
acquisition market is currently very competitive, we believe that there are
opportunities to acquire high quality oil and natural gas properties with these
characteristics in the mid-continent and southwest regions of the United States,
where we have established core areas. In all property acquisitions the company
will be seeking to become the operator. We will also continue to routinely
evaluate our portfolio of properties and periodically divest non-core or low
potential properties.
EXPLORATION. The acquisition market is currently very competitive,
especially for transactions that exceed $50 million. These properties are
generally sold on a tender bid basis which has the effect of bidding up the
price and maximizing the return to the seller. As a result, we have determined
that it is no longer prudent to rely solely on acquisitions for asset growth.
Our growth strategy has evolved from being primarily acquisition driven to a
more balanced approach with an increased emphasis on exploration opportunities.
We believe that this balanced approach will provide for a lower average reserve
replacement cost, thereby improving our return on capital. In order to diversify
our exposure, we generally acquire larger interests in company-operated, low
risk projects and smaller interests in higher risk/high impact exploration
properties. Our plan is for much of our exploration effort to be conducted with
partners who bring a unique experience, expertise or ownership position in the
prospect area of interest and have a successful track record.
MERGER OPPORTUNITIES. If we are able to complete the recapitalization, we
expect to be able to attract other small capitalization oil and natural gas
companies as merger or consolidation partners. We will be in an excellent
position to make accretive acquisitions of other companies and, through this
process, to use our strong balance sheet and cash flow to effect the
recapitalization of suitable merger candidates that otherwise may not have
access to capital.
CAPITAL AND FINANCIAL STRUCTURE. Our objective is to use a portion of the
net proceeds of this offering and internally generated cash flow to fund our
exploration, development and exploitation programs. We believe that we can
finance our acquisition opportunities at attractive prices with a combination of
equity and debt.
MANAGEMENT TEAM. With the completion of the recapitalization, we will have
the financial capability to pursue our strategy of increased focus on operating
those properties that we own and on exploration as a means to grow our assets.
We intend to continue restructuring our management team to add to our
engineering, geology and geophysical personnel. We also intend to add seasoned
senior oil and gas industry executives with experience in building stockholder
value and in the management of exploration and development projects. On October
6, 2000, Joseph T. Williams became a director and Chairman of the Board of our
company. In addition, on October 26, 2000, Jerry B. Davis and Robert L. Keiser
joined our board of directors. Biographical information for each of Messrs.
Williams, Davis and Keiser is included in "Management." We are also in the
process of recruiting one additional outside, non-employee director whom we
expect will join our board of directors within 90 days after the completion of
the recapitalization and this offering. As part of the restructuring of our
management team, Bruce I. Benn and Robert P. Lindsay will resign from our board
of directors immediately following the successful completion of this offering.
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<PAGE> 48
PRINCIPAL OIL AND NATURAL GAS PROPERTIES
The following table summarizes information with respect to each of our
principal areas of operation at June 30, 2000.
<TABLE>
<CAPTION>
PERCENT
PERCENT OF
TOTAL OF TOTAL
TOTAL NATURAL PROVED TOTAL SEC SEC
GROSS OIL GAS RESERVES PROVED PV-10 PV-10
WELLS (MBBLS) (MMCF) (BCFE)(1) RESERVES ($000S) (1)
----- ------- ------- --------- -------- -------- -------
<S> <C> <C> <C> <C> <C> <C> <C>
East Texas
Gilmer Field.................. 41 564 51,081 54.5 38% $ 78,438 36%
South Texas
J.C. Martin Field............. 84 -- 16,331 16.3 11% 36,305 17%
Lopeno and Volpe Fields....... 25 60 7,663 8.0 6% 12,856 6%
Other South Texas............. 128 236 2,585 4.0 3% 6,799 3%
--- ----- ------- ----- --- -------- ---
Total South Texas..... 237 296 26,579 28.3 20% 55,960 26%
Kentucky (Appalachian Basin)
Nasgas Field.................. 32 -- 36,665 36.6 25% 31,721 15%
Permian Basin
Caprock (Queen) Field......... 29 181 -- 1.1 1% 872 0%
Other Permian Basin........... 11 324 234 2.2 1% 4,764 2%
--- ----- ------- ----- --- -------- ---
Total Permian Basin... 40 505 234 3.3 2% 5,636 2%
Mid-Continent (25 fields)....... 207 318 16,256 18.2 12% 36,645 17%
Other........................... 27 327 1,865 3.8 3% 8,972 4%
--- ----- ------- ----- --- -------- ---
Total................. 584 2,010 132,680 144.7 100% $217,372 100%
</TABLE>
---------------
(1) The proved reserves and SEC PV-10 were estimated by our internal petroleum
engineers.
The following is an overview of our major fields, by area.
East Texas
GILMER FIELD. The Gilmer field consists of 41 natural gas wells that cover
approximately 13,000 gross acres in Upshur County, in East Texas. The wells
produce from the Cotton Valley Lime formation at a depth of approximately 11,500
feet to 12,000 feet.
Goldston Oil Corporation, or Goldston, has an 80% working interest in, and
is the operator of, our wells, which are in the heart of the Gilmer field. We
own a 47.5% net profits interest in Goldston's working interest.
The Gilmer field is located on the northwestern flank of the Sabine Uplift.
The initial well in the field was drilled in 1986 and the field was delineated
over the following ten years, eventually expanding to 21 natural gas units. The
reservoirs are characterized by low permeability, depletion drive mechanisms and
require stimulation. Well spacing is currently four wells per 640 acre block for
most of the units in the field. A field dedicated treating plant and centralized
compression system provides the operator control in marketing the natural gas.
At June 30, 2000, the Gilmer field contained 55 Bcfe of proved reserves,
which represented approximately 38% of our total proved reserves and 36% of our
SEC PV-10. Our average daily net production from the Gilmer field in June 2000
was approximately 7.8 MMcf of natural gas and 91 Bbls, aggregating 8.3 MMcfe.
Three new wells were drilled in June, July and September 2000, and a fourth
well is being drilled. Two additional proved undeveloped locations are scheduled
to be drilled this year, which management believes will allow the operator to
assess the need for further down spacing. Depending upon economic
48
<PAGE> 49
conditions, the property's value could be increased by accelerating production
through additional down spacing.
South Texas
J.C. MARTIN FIELD. The J.C. Martin field consists of 84 producing natural
gas wells that cover approximately 8,300 gross acres in Zapata County, Texas on
the Mexican border. The field primarily produces from the Lobo 1, 3 and 6 series
of sands in the Wilcox formation at depths of approximately 8,000 feet to 10,000
feet.
Our interests consist of (a) a 13.33% perpetual, non-participating mineral
royalty interest covering the Mecom family ranch and (b) an 80% net profits
interest in Devon Energy Corporation's, or Devon's, 20% working interest in the
ranch. Coastal Oil Corporation, or Coastal, operates all of the wells. The
reservoirs are low permeability, producing through pressure depletion and
requiring fracture stimulations. A portion of our royalty interest in this
property is the subject of litigation involving the predecessor owner. For
further description of this litigation, see "Risk Factors -- Risks Related to
Our Business -- We may lose title to our royalty interest in the J.C. Martin
Field as a result of litigation over title to the royalty interest."
At June 30, 2000, the J.C. Martin field contained 16 Bcfe of proved
reserves, which represented approximately 11% of our total proved reserves and
approximately 17.0% of our SEC PV-10. Our average daily net production from the
J.C. Martin field in June 2000 was 13.4 MMcfe.
Some wells drilled since 1998 in this field tested natural gas from a
deeper Cretaceous zone, the Navarro. This zone previously had not produced on
the lease but had produced significant volumes to the north. We believe that
there may be additional potential on the Mecom Ranch for this zone as only six
wells have actually penetrated the Cretaceous zone. We also believe that
potential exists for reserves in the Middle Wilcox zones at approximately 5,000
feet to 6,000 feet.
LOPENO AND VOLPE FIELDS. The Lopeno and Volpe fields are located in Zapata
County, Texas. These fields consist of 25 wells. All of the wells produce from
multiple reservoirs in the Upper Wilcox formation. Cody Energy, LLC, or Cody, is
the operator of the majority of the wells with Dominion Production &
Exploration, Inc. operating the remainder.
The Lopeno field covers over 6,000 acres and is an extension of a field
originally discovered in 1952. Over 20 sands have produced in the field at
depths ranging from 6,500 feet to 12,000 feet. Typical of the numerous Upper
Wilcox fields along the Texas Gulf Coast, the Lopeno field is highly faulted and
overpressured. The Volpe field is also a Wilcox field located 8 miles north of
Lopeno, Texas. A well was drilled directionally along the trapping fault and is
producing from the Middle Wilcox formation. Multiple Upper Wilcox zones are
classified behind the pipe. Nine proved undeveloped locations have been
identified in these fields.
Until June 30, 2000, we owned a 66.66% net profits interest in Choctaw's
working interests. Choctaw's working interests vary from 15.7% to 75%. Effective
June 30, 2000, we sold our net profits interests in the Lopeno and Volpe fields,
and we purchased primarily working interests in these properties as well as some
additional interests in the Lopeno and Volpe area. As a result of this sale, our
economic interest in the Lopeno-Volpe properties has been reduced by
approximately one-half and we have converted substantially all of the remaining
economic interest from net profits interests to working interests.
At June 30, 2000, immediately after the sale described in the preceding
paragraph, the Lopeno and Volpe fields contained an estimated 8 Bcfe of proved
reserves, which represented approximately 6% of our total proved reserves and
approximately 6% of our SEC PV-10. Our average daily net production from the
fields in June 2000 was 1.2 MMcf/d of natural gas.
We believe that the production in these fields can be enhanced through
workovers and accelerated drilling for the shallow, behind-the-pipe reserves.
49
<PAGE> 50
Kentucky
NASGAS FIELD. We have a 75% working interest in approximately 44,000 gross
acres in Meade, Hardin and Breckinridge Counties, Kentucky. There are currently
32 gross producing natural gas wells located on our leases in Meade County. We
drilled 12 wells in this field during our first year of ownership. These wells
produce from the New Albany Shale formation at depths of approximately 850 feet.
The shale zone has two porosity members and averages 80 feet in thickness. In
addition to the natural gas wells, we also own an interest in two salt-water
disposal wells and a related natural gas gathering system.
At June 30, 2000, these properties contained 37 Bcfe of net proved
reserves, which represents approximately 25% of our total proved reserves and
approximately 15% of our SEC PV-10. We acquired these properties because we
believe they have significant low risk development potential from relatively
shallow formations. Natural gas reserves in the New Albany Shale formation are
long-lived reserves, generally lasting over 40 years. Our average daily net
production from the Nasgas field in June 2000 was 435 Mcf.
New Mexico
CAPROCK (QUEEN) FIELD. The Caprock (Queen) field was our first acquisition
and consists of 29 oil wells, 57 water injection wells, 57 shut-in wells and 76
temporarily abandoned wells on approximately 14,200 gross acres located in Lea
and Chaves Counties, New Mexico. The Caprock field produces from the "Artesia
Red Sand" or Queen sandstone of Permian age at a depth of approximately 3,000
feet. Discovery and delineation wells were drilled from 1940 through 1949.
Development wells were drilled between 1954 and 1956 within the productive
limits of the field, which is approximately twenty miles long and three miles
wide. Primary production was established on 40-acre spacing. Initial waterflood
operations began in 1959 and 1960.
We have a 100% working interest and an 82.6% revenue interest in two
operating units, the Drickey Queen Sand Unit and the Westcap Unit, a 98.3%
working interest and a 79.3% revenue interest in a third operating unit, the
Rock Queen Unit, and a 100% working interest and a 90% revenue interest in the
Trigg and Federal V leases. Our working interest partner, Texican, Inc., or
Texican, owns 25% of our interest in 640 acres of the Drickey Queen Sand Unit
and has an option to participate for 25% of our interest in future development
activities in all of our units except for the Rock Queen Unit. These five
properties comprise the central 14,200 acres of the approximately 26,000
productive acres that contain nine contiguous development units. We have an
option on an additional 5,920 acres within the 26,000 productive acres.
We temporarily shut the field in due to significantly low oil prices in
late 1998 and early 1999. The field was returned to production in October 1999.
Phase I of the program toward redeveloping the waterflood pattern has been
implemented but definitive results are not available at the date of this
prospectus. This program consisted of drilling four single lateral water
injection wells and one dual-lateral producing well. These five wells along with
the production facilities and water injection plant constitute Phase I of the
redevelopment program. Phase I incorporates 640 acres out of the approximate
20,000 acres we control in the Caprock field. We are the operator of this
project.
Mid-Continent
We own interests in oil and gas assets located in the Texas panhandle,
Oklahoma and Kansas, collectively referred to as the mid-continent assets. The
mid-continent assets include 207 wells in 25 fields. These reserves are
concentrated in high quality fields with the value evenly distributed over
diverse, well-known reservoirs with long production histories supported by
stable production declines. These reserves are long-lived assets with a
productive life of 40 years and a reserves-to-production ratio of six years. An
experienced production company operates each of these properties with focused
operations in their respective areas. We own net profits overriding royalty
interests in each of these properties.
50
<PAGE> 51
The net daily production from these properties in June 2000 was 146 BOPD
and 5.6 Mcf, or 6.5 MMcfe. At June 30, 2000, the net proven reserves are
estimated to be 18.2 Bcfe, which represented approximately 12% of our total
proved reserves and 17% of our SEC PV-10.
EXPLORATION, DEVELOPMENT AND EXPLOITATION ACTIVITIES
Our development drilling program is generated largely through our internal
technical evaluation efforts and as a result of our obtaining undeveloped
acreage in connection with producing property acquisitions. In addition, there
are numerous opportunities for infill drilling on our leases currently producing
oil and natural gas. We intend to continue to pursue development drilling
opportunities which offer potentially significant returns to us. Our
exploitation activities consist of the evaluation of additional reserves through
workovers, behind-the-pipe recompletions and secondary recovery operations.
The objective of our overall development and exploitation strategy is to
achieve a balance between low risk workover and recompletion activities and
moderate risk infill and extensional development wells. This
exploitation/development strategy is intended to increase reserves while
minimizing the risk of uneconomic projects. We have budgeted through the fiscal
year ending June 30, 2001 approximately $3.8 million for exploratory drilling
projects.
During the year ended June 30, 2000, we participated in drilling 21 gross,
or 6.9 net, wells, of which 15 gross, or 3.2 net, were productive. However, we
cannot assure you that this past rate of drilling success will continue in the
future. We are currently pursuing development drilling projects on 7 different
fields and anticipate continued growth in drilling activities.
At June 30, 2000, we had identified approximately 115 development locations
and exploitation projects on our acreage. We expect to spend approximately $12.5
million on development locations and exploitation projects during the fiscal
year ending June 30, 2001, depending on the availability of drilling capital.
The following is a brief discussion of our primary areas of development and
exploitation activity:
East Texas
SEGNO FIELD. During April 1999, with an effective date of November 1, 1998,
we converted our 80% net profits interest in Prime Energy's working interest to
an 80% working interest in the proved developed wells and a 50% working interest
in all other proved and unproved locations. We believe this was necessary to
encourage Prime Energy to take steps to develop the field more fully.
We intend to continue participating with the operator, Prime Energy, in the
development of the Segno field. Recent activity includes recompleting several
wells and drilling a new well targeting reserves not yet produced from the Yegua
and Wilcox formations. The operator continues to return wells that are off
production back to service and to improve the field's facilities infrastructure.
Several significant new prospects have been identified utilizing 2-D seismic
data. We are participating in developing options to exploit these prospects. We
have recently agreed to farm out the rights to drill a Middle Wilcox test in
which we will retain a carried interest and a back in after payout.
South Texas
J.C. MARTIN FIELD. The J.C. Martin field produces from the Lobo Trend.
Intense faulting has created many separate reservoirs that are over-pressured
and highly faulted with numerous stacked sands. A 3D seismic study over the
field has identified multiple new locations and initiated a new round of
drilling. Since we acquired our interest in 1998, 23 wells have been drilled,
five of which have been drilled in 2000. In addition to the Lobo reservoirs
evaluated in the reserve report, we believe upside potential exists in the
Navarro and Middle Wilcox zones. We recently recompleted one well in the Middle
Wilcox. The deeper Cretaceous formation, the Navarro zone, also produces in this
field. We expect 10 additional wells to be drilled before June 30, 2001.
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<PAGE> 52
LOPENO/VOLPE FIELDS. We believe significant potential exists in the
Lopeno/Volpe fields to increase production. Over twenty sands have produced in
the Lopeno field and most wells have multiple behind-the-pipe zones. Accelerated
drilling for some of the shallower zones may be justified, improving their
present value. Four proved undeveloped locations have been identified in the
Volpe field that would develop Upper Wilcox sands. We are currently working with
the operator to pursue the necessary workovers and additional drilling. We
anticipate our share of capital expenditures in the Lopeno/Volpe fields will be
approximately $2.4 million through June 2001.
Kentucky
NASGAS FIELD. We believe that the Nasgas field presents opportunities for
low cost developmental drilling at depths of less than 1,000 feet. We expect
that the field will be developed in five phases. The first phase, consisting of
20 wells, was completed in 1996. The second phase, consisting of 12 wells, was
completed in 1998. The remaining development drilling is scheduled to commence
during our 2001 fiscal year. We expect to develop a total of 75 proven locations
at an average cost to us of $64,000 per well.
New Mexico
CAPROCK (QUEEN) FIELD. Exploitation efforts at the Caprock (Queen) field
consist primarily of a waterflood redevelopment project. We, with the assistance
of independent engineering consultants, have evaluated several alternate
development options. We plan to redevelop the Drickey Queen/Westcap Units using
a line drive waterflood pattern. A total of five dual lateral horizontal
producers will be drilled and 14 single lateral horizontal injection wells are
slated to be drilled. Phase I of the program consists of four horizontal water
injection wells and one dual lateral horizontal producer with an associated
water injection plant and production facility and was recently implemented.
Phase I fully developed one 640 acre section of the Drickey Queen Unit. We have
entered into an agreement with Texican regarding Phase I. The agreement requires
Texican to fund 50% of the first $2.0 million of the cost of Phase I. In
consideration of this, Texican will earn a 25% working interest in Phase I in
the Drickey Queen Unit. The Phase I program was implemented in the first quarter
of 2000 and our share of the program cost $1.6 million. We have just begun
injection and production operations in Phase I and do not have definitive
results. We will evaluate the initial results of Phase I over the next few
months.
MARKETING
Our oil and natural gas production is sold to various purchasers typically
in the areas where the oil or natural gas is produced. We do not refine or
process any of the oil and natural gas we produce. We are currently able to
sell, under contract or in the spot market, all of the oil and the natural gas
we are capable of producing at current market prices. Substantially all of our
oil and natural gas is sold under short term contracts or contracts providing
for periodic adjustments or in the spot market; therefore, our revenue streams
are highly sensitive to changes in current market prices. Our market for natural
gas is pipeline companies as opposed to end users. For a description of the
risks of changes in the prices for oil and natural gas, see "Risk
Factors -- Our profitability is highly dependent on the prices for oil and
natural gas, which can be extremely volatile."
In an effort to reduce the effects of the volatility of the price of oil
and natural gas on our operations and cash flow, we adopted a policy of hedging
oil and natural gas prices whenever market prices are in excess of the prices
anticipated in our operating budget and financial plan through the use of
commodity futures, options and swap agreements. We do not engage in speculative
trading. For further description of our hedging strategy, see "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Changes in prices and hedging activities."
For the year ended June 30, 2000, Goldston Oil Corporation accounted for
approximately 28% of our oil and natural gas sales, Coastal Oil and Gas, Inc.
accounted for approximately 16% of our oil and natural gas sales, Devon Energy
Corporation accounted for approximately 12% of our oil and natural gas sales,
and Kaiser Francis Oil Company accounted for approximately 10% of our oil and
natural gas sales. We do not
52
<PAGE> 53
believe that the loss of any of these buyers would have a material effect on our
business or results of operations as we believe we could readily locate other
buyers. However, short term disruptions could occur while we seek alternative
buyers or while lines were being connected to other pipelines.
The market for our oil and natural gas depends on factors beyond our
control, including the:
- price of imports of oil and natural gas;
- the extent of domestic production and imports of oil and natural gas;
- the proximity and capacity of natural gas pipelines and other
transportation facilities;
- weather;
- demand for oil and natural gas;
- the marketing of competitive fuels; and
- the effects of state and federal regulations.
The oil and natural gas industry also competes with other industries in
supplying the energy and fuel requirements of industrial, commercial and
individual consumers.
OIL AND NATURAL GAS RESERVES
The following tables summarize information regarding our estimated proved
oil and natural gas reserves as of June 30, 1998, 1999 and 2000. All of these
reserves are located in the United States. The estimates relating to our proved
oil and natural gas reserves and future net revenues of oil and natural gas
reserves at June 30, 1998 and 1999 with respect to the Morgan Properties
included in this prospectus are based upon reports prepared by Ryder Scott
Company. The estimates, other than with respect to the Morgan Properties, at
June 30, 1998 and 1999 included in this prospectus are based upon reports
prepared by H.J. Gruy and Associates, Inc. The estimates at June 30, 2000 are
based on reserve reports prepared by our internal petroleum engineers. In
accordance with guidelines of the SEC, the estimates of future net cash flows
from proved reserves and their SEC PV-10 are made using oil and natural gas
sales prices in effect as of the dates of the estimates and are held constant
throughout the life of the properties. Our estimates of proved reserves, future
net cash flows and SEC PV-10 were estimated using the following weighted average
prices, before deduction of production taxes:
<TABLE>
<CAPTION>
JUNE 30,
------------------------
1998 1999 2000
------ ------ ------
<S> <C> <C> <C>
Natural Gas (per Mcf)...................................... $ 2.40 $ 2.44 $ 4.45
Oil (per Bbl).............................................. $12.80 $17.11 $31.42
</TABLE>
Reserve estimates are imprecise and may be expected to change, as
additional information becomes available. Furthermore, estimates of oil and
natural gas reserves, of necessity, are projections based on engineering data,
and there are uncertainties inherent in the interpretation of this data as well
as the projection of future rates of production and the timing of development
expenditures. Reservoir engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured in an
exact way, and the accuracy of any reserve estimate is a function of the quality
of available data and of engineering and geological interpretation and
judgement. Reserve reports of other engineers might differ from the reports
contained herein. Results of drilling, testing, and production subsequent to the
date of the estimate may justify revision of this estimate. Future prices
received for the sale of oil and natural gas may be different from those used in
preparing these reports. The amounts and timing of future operating and
development costs may also differ from those used. Accordingly, we cannot assure
you that the reserves set forth herein will ultimately be produced nor can there
be assurance that the proved undeveloped reserves will be developed within the
periods anticipated. The discounted future net cash inflows should not be
construed as representative of the fair market value of the proved oil and
53
<PAGE> 54
natural gas properties, since discounted future net cash inflows are based upon
projected cash inflows which do not provide for changes in oil and natural gas
prices nor for escalation of expenses and capital costs. The meaningfulness of
these estimates is highly dependent upon the accuracy of the assumptions upon
which they were based.
All reserves are evaluated at constant temperature and pressure, which can
affect the measurement of natural gas reserves. Operating costs, development
costs and some production-related and ad valorem taxes were deducted in arriving
at the estimated future net cash flows. No provision was made for income taxes,
and the estimates were based on operating methods and existing conditions at the
prices and operating costs prevailing at the dates indicated above. The
estimates of the SEC PV-10 from future net cash flows differ from the
Standardized Measure set forth in the notes to our consolidated financial
statements, which is calculated after provision for future income taxes. We
cannot assure you that these estimates are accurate predictions of future net
cash flows from oil and natural gas reserves or their present value.
For additional information concerning our oil and natural gas reserves and
estimates of future net revenues attributable thereto, see note 11 of the notes
to consolidated financial statements included in this prospectus.
COMPANY RESERVES
The following tables set forth our proved reserves of oil and natural gas
and the SEC PV-10 thereof for each year in the three-year period ended June 30,
2000.
PROVED OIL AND NATURAL GAS RESERVES(1)
<TABLE>
<CAPTION>
JUNE 30,
------------------------------
1998 1999 2000
-------- -------- --------
<S> <C> <C> <C>
Natural gas reserves (MMcf):
Proved Developed Reserves................................. 120,998 94,614 86,348
Proved Undeveloped Reserves............................... 55,097 42,947 46,332
-------- -------- --------
Total Proved Reserves of natural gas...................... 176,095 137,561 132,680
Oil reserves (MBbl):
Proved Developed Reserves................................. 5,298 2,138 1,868
Proved Undeveloped Reserves............................... 2,651 2,486 142
-------- -------- --------
Total Proved Reserves of oil.............................. 7,949 4,624 2,010
Total Proved Reserves (MMcfe):.............................. 223,788 165,299 144,740
</TABLE>
SEC PV-10 OF PROVED RESERVES(1)(2)
<TABLE>
<CAPTION>
JUNE 30,
------------------------------
1998 1999 2000
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Proved Developed Reserves................................. $131,200 $ 99,650 $163,982
Proved Undeveloped Reserves............................... 33,920 31,076 53,390
-------- -------- --------
Total SEC PV-10................................... $165,120 $130,726 $217,372
</TABLE>
---------------
(1) The data shown at June 30, 1998 and June 30, 1999, excluding data with
respect to the Morgan Properties at June 30, 1998 and June 30, 1999, is
based upon reports prepared by H.J. Gruy and Associates, Inc. The data
included with respect to the Morgan Properties at June 30, 1998 and June 30,
1999 is based upon reserve reports prepared by Ryder Scott Company. The data
for June 30, 2000 is based upon reserve reports prepared by our internal
petroleum engineers.
(2) SEC PV-10 differs from the Standardized Measure set forth in the notes to
our consolidated financial statements, which is calculated after provision
for future income taxes.
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<PAGE> 55
Except for the effect of changes in oil and natural gas prices no major
discovery or other favorable or adverse event is believed to have caused a
significant change in these estimates of our reserves since June 30, 2000.
Except for Form EIA 23, "Annual Survey of Domestic Oil and Gas Reserves,"
filed with the United States Department of Energy, no other estimates of total
proved net oil and natural gas reserves have been filed by us with, or included
in any report to, any United States authority or agency pertaining to our
individual reserves since the beginning of our last fiscal year. Reserves
reported on Form EIA 23 are comparable to the reserves reported by us herein.
OPERATIONS DATA
PRODUCTIVE WELLS
The following table sets forth the number of total gross and net productive
wells in which we owned an interest as of June 30, 2000.
<TABLE>
<CAPTION>
GROSS NET
--------------------- ----------------------
NATURAL NATURAL
OIL GAS TOTAL OIL GAS TOTAL
--- ------- ----- ---- ------- -----
<S> <C> <C> <C> <C> <C> <C>
Texas............................................ 160 159 319 41.9 33.6 75.5
New Mexico....................................... 29 -- 29 28.5 -- 28.5
Louisiana........................................ 1 -- 1 1.0 -- 1.0
Oklahoma......................................... -- 148 148 0.0 19.0 19.0
Kentucky......................................... -- 32 32 -- 22.4 22.4
Other(1)......................................... 1 54 55 0.4 10.8 11.2
--- --- --- ---- ---- -----
Total.................................. 191 393 584 71.8 85.8 157.6
=== === === ==== ==== =====
</TABLE>
---------------
(1) Represents wells located in Kansas, Alabama and Wyoming.
PRODUCTION ECONOMICS
The following table sets forth operating information for the periods
presented.
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
--------------------------
1998 1999 2000
------ ------- -------
<S> <C> <C> <C>
OPERATING DATA
PRODUCTION VOLUMES:
Natural gas (MMcf)....................................... 3,368 12,962 10,618
Oil (MBbl)............................................... 325 500 224
Total (MMcfe).................................. 5,318 15,960 11,960
AVERAGE SALES PRICE:
Natural gas (per Mcf).................................... $ 2.27 $ 2.13 $ 2.59
Oil (per Bbl)............................................ 15.52 12.37 22.76
SELECTED EXPENSES (PER MCFE):
Production taxes......................................... $ 0.12 $ 0.09 $ 0.12
Lease operating expense.................................. 1.07 0.49 0.47
General and administrative............................... 0.43 0.22 0.25
Depreciation, depletion and amortization(1).............. 0.89 0.74 0.71
</TABLE>
---------------
(1) Represents depreciation, depletion and amortization of oil and natural gas
properties only.
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<PAGE> 56
DRILLING ACTIVITY
The following table sets forth our gross and net working interests in
exploratory and development wells, but excluding injection or service wells,
drilled during the indicated periods.
<TABLE>
<CAPTION>
YEARS ENDED JUNE 30,
----------------------------------------
1998 1999 2000
----------- ------------ -----------
GROSS NET GROSS NET GROSS NET
----- --- ----- ---- ----- ---
<S> <C> <C> <C> <C> <C> <C>
EXPLORATORY:
Oil.................................................... 1 0.0 0 0.0 1 0.2
Natural gas............................................ 1 0.3 0 0.0 -- 0.0
Dry.................................................... 1 0.7 1 1.0 1 0.5
-- --- -- ---- -- ---
Total........................................ 3 1.0 1 1.0 2 0.7
DEVELOPMENT:
Oil.................................................... 5 2.1 1 0.2 1 0.8
Natural gas............................................ 10 2.6 26 9.9 13 2.2
Dry.................................................... 1 0.4 1 0.7 1 0.2
-- --- -- ---- -- ---
Total........................................ 16 5.1 28 10.8 15 3.2
TOTAL:
Oil.................................................... 6 2.1 1 0.2 2 1.0
Natural gas............................................ 11 2.9 26 9.9 13 2.2
Dry.................................................... 2 1.1 2 1.7 2 0.7
-- --- -- ---- -- ---
Total........................................ 19 6.1 29 11.8 17 3.9
</TABLE>
Between June 30, 2000 and September 30, 2000, we have drilled 5 gross, 1.2
net, wells which were successful, and we drilled, 1 gross, or 1.0 net, well that
was a dry hole. At September 30, 2000 we were in the process of drilling 1
gross, 0.4 net wells.
DEVELOPED AND UNDEVELOPED ACREAGE
The following table sets forth the approximate gross and net acres in which
we owned an interest as of June 30, 2000.
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
------------------- -------------------
GROSS NET GROSS NET
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Texas.............................................. 47,200 13,800 6,500 1,300
New Mexico......................................... 14,300 14,100 -- --
Louisiana.......................................... 300 300 6,100 3,300
Oklahoma........................................... 37,400 5,300 -- --
Kentucky........................................... 600 400 43,900 30,700
Other(1)........................................... 20,500 5,200 -- --
-------- -------- -------- --------
Total.................................... 120,300 39,100 56,500 35,300
======== ======== ======== ========
</TABLE>
---------------
(1) Represents acreage located in Colorado, Kansas, Alabama and Wyoming.
MARKETS AND COMPETITION
The oil and natural gas industry is highly competitive. Our competitors
include major oil companies, other independent oil and natural gas concerns and
individual producers and operators, many of which have financial resources,
staffs and facilities substantially greater than ours. In addition, we encounter
substantial competition in acquiring oil and natural gas properties, marketing
oil and natural gas and hiring trained personnel. When possible, we try to avoid
open competitive bidding for acquisition opportunities. The principal means of
competition with respect to the sale of oil and natural gas production are
product
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<PAGE> 57
availability and price. While it is not possible for us to state accurately our
position in the oil and natural gas industry, we believe that we represent a
minor competitive factor.
The market for our oil and natural gas production depends on factors beyond
our control, including domestic and foreign political conditions, the overall
level of supply of and demand for oil and natural gas, the price of imports of
oil and natural gas, gas pipelines and other transportation facilities and
overall economic conditions. The oil and gas industry also competes with other
industries in supplying the energy and fuel requirements of industrial,
commercial and individual consumers.
TITLE TO OIL AND NATURAL GAS PROPERTIES
We have acquired interests in producing and non-producing acreage in the
form of working interests, royalty interests, overriding royalty interests and
net profits interests. Substantially all of our property interests, and the
assignors' interests in the working or other interests in the underlying
properties, are held pursuant to leases from third parties. The leases grant the
lessee the right to explore for and extract oil and natural gas from specified
areas. Consideration for these leases usually consists of a lump sum payment,
such as a bonus, and a fixed annual charge, such as a delay rental, prior to
production unless the lease is paid up and, once production has been
established, a royalty based generally upon either the proceeds from the sale of
oil and natural gas or the market value of oil and natural gas produced. Once
wells are drilled, a lease generally continues so long as production of oil and
natural gas continues. In some cases, leases may be acquired in exchange for a
commitment to drill or finance the drilling of a specified number of wells to
predetermined depths. Some of our non-producing acreage is held under leases
from mineral owners or governmental entities which expire at varying dates. We
are obligated to pay annual delay rentals to the lessors of some properties in
order to prevent the leases from terminating. Title to leasehold properties is
subject to royalty, overriding royalty, carried, net profits and other similar
interests and contractual arrangements customary in the oil and natural gas
industry, and to liens incident to operating agreements, liens relating to
amounts owed to the operator, liens for current taxes not yet due and other
encumbrances.
As is customary in the industry, we generally acquire oil and natural gas
acreage without any warranty of title except as to claims made by, through or
under the transferor. Although we have title examined prior to acquisition of
developed acreage in those cases in which the economic significance of the
acreage justifies the cost, there can be no assurance that losses will not
result from title defects or from defects in the assignment of leasehold rights.
In many instances, title opinions may not be obtained if in our judgment it
would be uneconomical or impractical to do so.
The underlying properties are typically subject, in one degree or another,
to one or more of the following:
- royalties and other burdens and obligations, expressed and implied, under
oil and gas leases;
- overriding royalties and other burdens created by the assignor or its
predecessors in title;
- a variety of contractual obligations, including, in some cases,
development obligations, arising under operating agreements, farmout
agreements, production sales contracts and other agreements that may
affect the properties or their titles;
- liens that arise in the normal course of operations, such as those for
unpaid taxes, statutory liens securing unpaid suppliers and contractors
and contractual liens under operating agreements;
- pooling, unitization and communitization agreements, declarations and
orders; and
- easements, restrictions, rights-of-way and other matters that commonly
affect property.
To the extent that these burdens and obligations affect the assignor's
rights to production and the value of production from the underlying properties,
they have been taken into account in calculating our interests and in estimating
the size and value of the reserves attributable to our net profits interests and
royalty interests.
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<PAGE> 58
A substantial portion of our oil and natural gas property interests are in
the form of non-operated, net profits interests and royalty interests. The net
profits interests were conveyed to us by various assignors from the assignor's
net revenue interests in the oil and natural gas properties burdened by the net
profits interests and royalty interests (the "underlying properties"). The
assignors' net revenue interests are generally leasehold working interests less
lease burdens.
NET PROFITS INTERESTS. As the owner of net profits interests, we do not
have the direct right to drill or operate wells or to cause third parties to
propose or drill wells on the underlying properties. If an assignor or any other
working interest owner proposes to drill wells on one of the underlying
properties, then that assignor must give us notice of the proposal. Under an
agreement covering the underlying property, we have the option to pay a
specified percentage of the assignor's working interest share of the expenses of
the well that is proposed. We would then become entitled to a net profits
interest equal to the specified percentage multiplied by the assignor's net
revenue interest in that well. However, if an assignor elects not to participate
in the drilling of a well, we will not be able to participate in that well.
Moreover, if an assignor owns less than a 100% working interest in a proposed
well, and the other owners of working interests in that well elect not to
participate in the well, the well will not be drilled unless the money to pay
the costs allocable to the working interest owners who do not elect to
participate in the well is obtained. The financial strength and the competence
of the various assignors, and to a lesser extent the financial strength and the
competence of other parties owning working interests in the underlying
properties, may have an effect on when and whether wells get drilled on the
underlying properties, and on whether operations are conducted in a prudent and
competent manner.
ROYALTY INTERESTS. The royalty interests are generally in the form of
term royalty interests. The duration of these interests is the same as the
underlying oil and natural gas lease. Some of the royalty interests are
perpetual royalty interests which entitle the owner to a share of production
from the underlying properties under both the current oil and natural gas lease
and any replacement or successor oil and natural gas lease. In all cases, the
royalty interests are non-operating interests, have little or no influence over
oil and natural gas development or operation on the lands they burden but have
limited cost bearing responsibilities.
SALE AND ABANDONMENT OF UNDERLYING PROPERTIES. An assignor has the right
to abandon any well or working interest included in the underlying properties
if, in its opinion, the well or property ceases to produce or is not capable of
producing oil or natural gas in commercially paying quantities. We may not
control the timing of plugging and abandoning wells. The conveyances provide
that the assignor's working interest share of the costs of plugging and
abandoning uneconomic wells are deducted in calculating our net cash flow from
the underlying property.
The assignor can sell the underlying properties, subject to and burdened by
the royalty interests, without our consent. Accordingly, the underlying
properties could be transferred to a party with a weaker financial profile.
REGULATION
General federal and state regulation
Our oil and natural gas exploration, production and related operations are
subject to extensive rules and regulations promulgated by federal and state
agencies. Failure to comply with these rules and regulations can result in
substantial penalties. The regulatory burden on the oil and natural gas industry
increases our cost of doing business and affects our profitability. Because
these rules and regulations are frequently amended or reinterpreted, we are
unable to predict the future cost or impact of complying with these laws.
The State of Texas and many other states require permits for drilling
operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration and production of oil and natural gas.
Many states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and natural gas
properties, the establishment of maximum
58
<PAGE> 59
rates of production from wells, and the regulation of spacing, plugging and
abandonment of these wells. Many states restrict production to the market demand
for oil and natural gas. Some states have enacted statutes prescribing ceiling
prices for natural gas sold within their boundaries.
The Federal Energy Regulatory Commission, or FERC, regulates interstate
natural gas transportation rates and service conditions, which affect the
revenues received by us for sales of our production. Since the mid-1980s, FERC
has issued a series of orders, culminating in Order Nos. 636, 636-A and 636-B,
or Order 636, that have significantly altered the marketing and transportation
of natural gas. Order 636 mandates a fundamental restructuring of interstate
pipeline sales and transportation service, including the unbundling by
interstate pipelines of the sale, transportation, storage and other components
of the city-gate sales services the pipelines previously performed. One of
FERC's purposes in issuing the orders is to increase competition within all
phases of the natural gas industry. Order 636 and subsequent FERC orders on
rehearing have been appealed and are pending judicial review. Because these
orders may be modified as a result of the appeals, it is difficult to predict
the ultimate impact of the orders on us. Generally, Order 636 has eliminated or
substantially reduced the traditional role of intrastate pipelines as
wholesalers of natural gas, and has substantially increased competition and
volatility in natural gas markets.
The price we receive from the sale of oil and natural gas liquids is
affected by the cost of transporting products to market. Effective January 1,
1995, FERC implemented regulations establishing an indexing system for
transportation rates for oil pipelines, which, generally, would index these
rates to inflation, subject to some conditions and limitations. The Railroad
Commission of the State of Texas is considering adopting rules to prevent
discriminatory transportation practices by intrastate natural gas gatherers and
transporters by requiring the disclosure of rate information under varying
conditions of service. We are not able to predict with certainty the effects, if
any, of these regulations on our operations. However, the regulations may
increase transportation costs or reduce wellhead prices for oil and natural gas
liquids.
Finally, from time to time regulatory agencies have imposed price controls
and limitations on production by restricting the rate of flow of oil and natural
gas wells below natural production capacity in order to conserve supplies of oil
and natural gas.
ENVIRONMENTAL REGULATION
The exploration, development and production of oil and natural gas,
including the operation of saltwater injection and disposal wells, are subject
to various federal, state and local environmental laws and regulations. These
laws and regulations can increase the costs of planning, designing, installing
and operating oil and natural gas wells. Our domestic activities are subject to
a variety of environmental laws and regulations, including but not limited to,
the Oil Pollution Act of 1990, or OPA, the Clean Water Act, or CWA, the
Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA,
the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or CAA,
and the Safe Drinking Water Act, or SDWA, as well as state regulations
promulgated under comparable state statutes. We are also subject to regulations
governing the handling, transportation, storage and disposal of naturally
occurring radioactive materials that are found in our oil and natural gas
operations. Civil and criminal fines and penalties may be imposed for
non-compliance with these environmental laws and regulations. Additionally,
these laws and regulations require the acquisition of permits or other
governmental authorizations before undertaking some activities, limit or
prohibit other activities because of protected areas or species, and impose
substantial liabilities for cleanup of pollution.
Under the OPA, a release of oil into water or other areas designated by the
statute could result in our being held responsible for the costs of remediating
the release, OPA specified damages, and natural resource damages. The extent of
that liability could be extensive, as set forth in the statute, depending on the
nature of the release. A release of oil in harmful quantities or other materials
into water or other specified areas could also result in our being held
responsible under the CWA for the costs of remediation, and any civil and
criminal fines and penalties.
CERCLA and comparable state statutes, also known as "Superfund" laws, can
impose joint and several retroactive liability, without regard to fault or the
legality of the original conduct, on specified
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<PAGE> 60
classes of persons for the release of a "hazardous substance" into the
environment. In practice, cleanup costs are usually allocated among various
responsible parties. Potentially liable parties include site owners or
operators, past owners or operators under certain conditions, and entities that
arrange for the disposal or treatment of, or transport hazardous substances
found at the site. Although CERCLA, as amended, currently exempts petroleum,
including but not limited to, oil, natural gas and natural gas liquids from the
definition of hazardous substance, our operations may involve the use or
handling of other materials that may be classified as hazardous substances under
CERCLA. Furthermore, there can be no assurance that the exemption will be
preserved in future amendments of CERCLA, if any.
RCRA and comparable state and local requirements impose standards for the
management, including treatment, storage, and disposal of both hazardous and
nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in
connection with our routine operations. From time to time, proposals have been
made that would reclassify certain oil and natural gas wastes, including wastes
generated during pipeline, drilling, and production operations, as "hazardous
wastes" under RCRA which would make these solid wastes subject to much more
stringent handling, transportation, storage, disposal, and clean-up
requirements. This development could have a significant impact on our operating
costs. While state laws vary on this issue, state initiatives to further
regulate oil and natural gas wastes could have a similar impact.
Oil and natural gas exploration and production, and possibly other
activities, have been conducted at some of our properties by previous owners and
operators. Materials from these operations remain on some of the properties and
in some instances require remediation. In addition, we have agreed to indemnify
sellers of producing properties from whom we have acquired reserves against
certain liabilities for environmental claims associated with these properties.
While we do not believe that costs to be incurred by us for compliance with
environmental regulations and remediating previously or currently owned or
operated properties will be material, there can be no guarantee that these costs
will not result in material expenditures.
Additionally, in the course of our routine oil and natural gas operations,
surface spills and leaks, including casing leaks, of oil or other materials
occur, and we incur costs for waste handling and environmental compliance.
Moreover, we are able to control directly the operations of only those wells for
which we act as the operator. Notwithstanding our lack of control over wells
owned by us but operated by others, the failure of the operator to comply with
the applicable environmental regulations may, in certain circumstances, be
attributable to us.
Is it not anticipated that we will be required in the near future to expend
amounts that are material in relation to our total capital expenditures program
by reason of environmental laws and regulations, but inasmuch as these laws and
regulations are frequently changed, we are unable to predict the ultimate cost
of compliance. There can be no assurance that more stringent laws and
regulations protecting the environment will not be adopted or that we will not
otherwise incur material expenses in connection with environmental laws and
regulations in the future. See "Risk Factors."
EMPLOYEES
As of October 6, 2000, we had 18 full-time employees consisting of 8
officers and 10 support staff. Three of the employees are in Ottawa, Canada, 14
of the employees are located in the Dallas office, and 1 is on site in Kentucky.
In addition, we regularly engage technical consultants and independent
contractors to provide specific advice or to perform administrative or technical
functions.
LITIGATION
The landowner royalty on the J.C. Martin Field is currently the subject of
a lawsuit that has created uncertainty regarding our title to our interest in
the J.C. Martin Field. See "Risk Factors -- Risks Related to Our Business -- We
may lose title to our royalty interest in the J.C. Martin field as a result of
litigation over title to the royalty interest".
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<PAGE> 61
No other legal proceedings are pending other than ordinary routine
litigation incidental to us, the outcome of which management believes will not
have a material adverse effect on our financial condition or results of
operations.
MANAGEMENT
The following sets forth the names, ages and positions of our officers and
directors.
<TABLE>
<CAPTION>
NAME AGE CURRENT POSITION WITH COMPANY
---- --- -----------------------------
<S> <C> <C>
Joseph T. Williams................ 63 Chairman of the Board and Director
Edward J. Munden.................. 49 Chief Executive Officer, President and Director
Jerry B. Davis.................... 69 Director
Robert L. Keiser.................. 57 Director
Bruce I. Benn..................... 47 Executive Vice President
Robert P. Lindsay................. 58 Chief Operating Officer, Executive Vice President
V. Ed Butler...................... 44 Vice President, Asset Management
Ronald Idom....................... 46 Vice President, Acquisitions
William W. Lesikar................ 47 Chief Financial Officer and Vice President
William A. Williamson............. 44 Vice President, Land
</TABLE>
We are also in the process of recruiting one additional outside,
non-employee director whom we expect will join our board within 90 days after
the completion of the recapitalization and this offering.
Effective September 15, 2000, Ronald I. Benn resigned from our company. Mr.
Benn had served as our Chief Financial Officer since 1995 and he is the brother
of Bruce I. Benn, one of our Executive Vice Presidents and, before this
offering, one of our directors. We have entered into a severance agreement with
Mr. Benn pursuant to which we paid him a lump sum severance payment of $200,000
and agreed to provide Mr. Benn medical, dental and life insurance benefits
coverage until June 30, 2002. Mr. Benn has agreed to make himself available to
us at the rate of $1,000 per day for 3 months to assist us in the transition
period with a replacement Chief Financial Officer. We have no obligation to use
his services during this time. The severance agreement includes a mutual
release, a confidentiality provision and a covenant that for one year Mr. Benn
will not induce or solicit any of our employees to terminate employment with us.
We also agreed to indemnify Mr. Benn to the full extent authorized by law for
claims for which Mr. Benn may be liable as a former director, officer or
employee of our company.
The following biographies describe the business experience of our executive
officers and directors.
JOSEPH T. WILLIAMS was appointed director and Chairman of the Board on
October 6, 2000. From July 1998 to August 1999, Mr. Williams served as President
and Chief Executive Officer of MCN Investment Corporation, a diversified energy
company with $2 billion in oil and natural gas, natural gas pipeline and
electrical power assets. Prior to this, Mr. Williams served as President and
Chief Executive Officer of MCNIC Oil and Gas Company, a broad-based exploration
and production company, from August 1997 to July 1998. From June 1995 to
February 1996, Mr. Williams served as Vice Chairman and Chief Executive Officer
of Enserch Exploration, Inc., an oil and as exploration and production company.
Mr. Williams holds a B.S. in Petroleum Engineering from the University of Texas
at Austin.
EDWARD J. MUNDEN has been the President and a director of DevX since March
6, 1995 and has served as our Chief Executive Officer since May 1996. He served
as our Chairman of the Board from October 1997 to October 6, 2000. Since 1989,
he has been a director and co-founder of Capital House Corporation, or CHC,
which is a Canadian venture capital firm located in Ottawa, Canada. Mr. Munden
has held positions in the mining industry with Eldorado Nuclear Limited from
1980 to 1989, the manufacturing industry with Proctor and Gamble Company of
Canada from 1978 to 1980, and the oil and natural gas industry with Union Oil of
Canada Limited from 1974 to 1976. Mr. Munden is a professional geological
engineer and holds a Bachelor of Science degree in Engineering and a Masters of
Business Administration from Queens University in Kingston, Canada.
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<PAGE> 62
JERRY B. DAVIS joined our board on October 26, 2000. Mr. Davis has over 25
years' experience working with Otis Engineering Corporation, an oil field
service company and a division of Halliburton, including serving as President
and Chief Executive Officer from 1990 to 1993. From July 1993 to present, Mr.
Davis has engaged in investment activities and ranching. Mr. Davis holds a
Master of Business Administration from Southern Methodist University, a B.S. in
Petroleum Engineering from Texas A&M University and has a degree in ranch
management from Texas Christian University. Mr. Davis has been appointed to
serve on both our audit and compensation committees.
ROBERT L. KEISER joined our board on October 26, 2000. Mr. Keiser retired
in June 1999 from his position as Chairman of Kerr-McGee Corp., an integrated
energy company. Mr. Keiser also served as Chairman, Chief Executive Officer and
President of Oryx Energy Company, an independent oil and natural gas exploration
company, from 1994 to March 1999, when Oryx Energy Company merged with
Kerr-McGee Corp. From 1988 to 1994, Mr. Keiser served in various capacities with
Oryx Energy Company. Mr. Keiser currently serves as a director of HVIDE Marine
Inc., a company engaged in the business of providing marine support and
transportation services to the energy and chemical industry. Mr. Keiser holds a
B.S. in Petroleum Engineering from The University of Missouri-Rolla. Mr. Keiser
has been appointed to serve on both our audit and compensation committees.
BRUCE I. BENN has been an Executive Vice President of DevX since March 1995
and served as a director of DevX from March 1995 until the completion of this
offering. In 1989, he, together with Ronald I. Benn and Edward J. Munden,
founded CHC and has been a director since then. From 1985 to 1993, he was Vice
President and director of Corporation House Ltd., where he acted as an
investment banker and a financial advisor to resource development, manufacturing
and construction firms around the world. He is an attorney and holds a Masters
of Law degree from the University of London, England, a Baccalaureate of Laws
from the University of Ottawa, Canada, and a Bachelor of Arts in Economics from
Carleton University in Ottawa, Canada. Ronald I. Benn, a former Chief Financial
Officer of the Company, is the brother of Bruce I. Benn.
ROBERT P. LINDSAY joined DevX in 1994 and became Executive Vice President
in September 1995 and Chief Operating Officer in May 1996. Until the completion
of this offering, Mr. Lindsay served as a director of DevX. From 1973 until 1995
Mr. Lindsay was Chief Executive Officer of Lin-mour Drilling Company. Mr.
Lindsay joined Helmerich & Payne, an oil and natural gas drilling and
exploration company headquartered in Tulsa, Oklahoma, in 1965 and held
increasingly senior positions with that company until 1973. Mr. Lindsay holds a
Bachelor of Arts degree in Accounting from the University of Texas.
V. ED BUTLER joined DevX in June 1996 as Vice President, Operations. He has
22 years of experience in oil field engineering and operations. From 1993 to
1995, he was Executive Vice President for Echo Production, Inc. From 1982 to
1993 he held the position of Operations Manager for Triad Energy Corporation. He
has also been a staff engineer for Blocker Exploration Company from 1980 to 1982
and an area production engineer for Texas Oil and Gas Corporation from 1978 to
1980. Mr. Butler holds an M.B.A. from the University of Texas, and a Bachelor of
Science in Petroleum Engineering from Texas A&M University.
RONALD IDOM joined DevX in January 1998 as Vice President, Acquisitions. He
has over 24 years of experience in reservoir engineering and management. From
1991 to 1997, he was Manager Gas Supply for Delhi Gas Pipeline Corporation and
Manager Engineering/Project Development from 1988 to 1991. From 1985 to 1988 he
held the position of Chief Reservoir Engineer for TXO Production Corp. Both
Delhi Gas Pipeline and TXO Production Corp. were subsidiaries of USX/Texas Oil &
Gas Corporation. He also served as acquisition engineer for NRM Petroleum from
1983 to 1985; a self-employed petroleum consultant from 1980 to 1983 and held
various engineering positions with Texas Oil and Gas Corporation from 1976 to
1980. Mr. Idom graduated from Texas A&M University in 1976 with a Bachelor of
Science in Petroleum Engineering.
WILLIAM W. LESIKAR joined DevX in June 1998 as Vice President, Finance and
now serves as our Chief Financial Officer. Mr. Lesikar, a Certified Public
Accountant, has 24 years of experience in finance and accounting with nearly 19
years in the oil and gas industry. From 1981 to 1998, Mr. Lesikar held
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<PAGE> 63
increasing positions of authority with Lyco Energy Corporation of Dallas, Texas
including Controller from 1981 to 1983, and Chief Financial Officer and
Executive Vice President from 1988 to 1998. From 1978 to 1981, Mr. Lesikar was
an audit manager and senior auditor with Arthur Young & Company, now known as
Ernst & Young LLP. From 1976 to 1978, Mr. Lesikar was an auditor with Haskins &
Sells, now known as Deloitte & Touche LLP. Mr. Lesikar holds a Masters of
Business Administration from Southern Methodist University and a Bachelor of
Business Administration from University of Texas at Austin.
WILLIAM A. WILLIAMSON joined DevX in March 1998 as Vice President, Land. He
has over 20 years of experience in petroleum land management. From 1989 to 1998,
he served as President of BAW Energy, Inc. BAW Energy, Inc. was formed primarily
to provide oil and gas asset management from a land and legal perspective to
independent oil and gas companies. Clients of BAW Energy, Inc. included INCO Oil
Corporation, Janex Oil Co., Inc., Walter Exploration, Inc. and DevX. From 1979
to 1989, he was self-employed as an independent petroleum landman. Mr.
Williamson holds a Bachelor of Business Administration in Finance from Texas A&M
University.
EMPLOYMENT AGREEMENT WITH JOSEPH T. WILLIAMS
Effective October 6, 2000, we entered into an employment agreement with
Joseph T. Williams. The initial term of the employment agreement is for 2 years
but it will be automatically extended for a further term of 2 years on each
anniversary date of the agreement unless, at least 60 days before the
anniversary date we notify Mr. Williams that we will not be extending the term.
Mr. Williams will receive a base salary of $250,000 per year. Each year during
the term, our compensation committee will determine a target bonus for Mr.
Williams for that year that will be in the range of between 20% and 120% of Mr.
Williams' base salary. Determination of the actual bonus amount to be paid to
Mr. Williams will be in the discretion of our board of directors and will depend
in part of the performance of the company during the year but in any case will
not be less than 20% of the base salary.
If we terminate Mr. William's employment for reasons other than for cause
or Mr. Williams terminates his employment for good reason, as those terms are
defined in the contract, then we must pay Mr. Williams, in addition to any
accrued but unpaid salary and bonus to which he may then be entitled, the sum of
1 year's base salary plus the greater of his target bonus for that year or the
actual bonus paid or payable with respect to the previous year. If termination
occurs for those reasons within 2 years of a change of control or Mr. Williams
resigns for any reason during the 13th month following a change of control, then
Mr. Williams will be entitled to receive 3 times that amount. If termination is
for reasons other than for cause or Mr. Williams terminates his employment for
good reason he will also be entitled to receive health benefits for 3 years
after termination as well as any benefits he might then be entitled to under any
supplemental retirement plan we may have in place at the time. In addition, all
of Mr. Williams' unvested stock options will vest immediately or he may elect to
receive the cash equivalent of any unexercised stock options. We have also
agreed to make additional payments to indemnify Mr. Williams should the
severance payments attract excise tax under Article 4999 of the Internal Revenue
Code.
"Change of control" is defined to include a merger or sale of our company
if we are not the surviving entity, the sale of all or substantially all of our
assets, the approval by our stockholders of a plan of liquidation or
dissolution, specified changes in the composition of our board of directors, the
acquisition of beneficial ownership of an aggregate of 15% of the voting power
of our outstanding voting securities by any person or group who beneficially
owned at least 10% of the voting power on October 6, 2000, the acquisition of
beneficial ownership of an additional 5% of the voting power by any person or
group who beneficially owned at least 10% of the voting power on October 6,
2000, the execution by us and a stockholder of a contract that by its terms
grants the stockholder or its affiliate, the right to veto or block decisions or
actions of our board of directors, or the bankruptcy of our company. Neither the
recapitalization approved by our stockholders at the annual meeting on September
18, 2000 nor the public offering contemplated by this registration statement
will constitute a change of control for the purposes of Mr. William's employment
agreement.
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<PAGE> 64
Under the employment agreement, we agreed to issue to Mr. Williams options
to purchase 250,000 shares of post-reverse split common stock. The exercise
price for these options will be the public offering price per share of common
stock in this offering. The grant of the options is subject to the approval by
our stockholders of an amendment to our 1997 Incentive Equity Plan to increase
the number of options that may be awarded under the plan. Fifty percent of these
options will vest on each of the first two anniversary dates of the grant. If we
fail to deliver the options or fail to receive stockholder approval before the
first anniversary date of the contract, then we must pay Mr. Williams the cash
equivalent of the options. In addition, we have also entered into an
indemnification agreement with Mr. Williams.
COMPENSATION OF NON-EMPLOYEE DIRECTORS
The board of directors has adopted a policy whereby each non-employee
director is paid an annual retainer fee of $18,000 plus meeting fees of $1,000
for each board of directors meeting and $1,000 for each committee meeting (other
than telephonic meetings) attended by the director unless the committee meeting
is held on the same day as a board meeting, in which case the fee is $500. The
company also reimburses its directors for travel, lodging and related expenses
they may incur attending board of directors and committee meetings. In addition,
subject to stockholder approval of an amendment to our directors' nonqualified
stock option plan to increase the number of shares subject to the plan, we will
grant each non-employee director options to purchase 3,000 shares of common
stock upon the director's joining our board and options to purchase 3,000 shares
for each year of service on our board. The price of shares that may be purchased
upon exercise of an option will be the fair market value of the common stock on
the date of grant. With respect to the initial grant of options to Messrs. Davis
and Keiser, the exercise price will be the public offering price per share of
common stock in this offering. If we do not obtain stockholder approval of the
amendment to the option plan, then we will pay the directors the cash equivalent
of the options. In addition, we will enter into indemnification agreements with
our non-employee directors.
MANAGEMENT AND DIRECTORS OPTIONS
Our board has approved, subject to stockholder approval, an amendment to
our incentive equity plan to increase the number of shares issuable under the
plan to 1,000,000 post-reverse split shares of common stock. In addition, our
board has approved, subject to stockholder approval, an amendment to our
nonqualified directors option plan to increase the number of shares issuable
under the plan to 100,000 post-reverse split shares of common stock.
It is currently contemplated that the compensation committee, comprised of
Messrs. Davis and Keiser will meet before the completion of this offering to
consider a proposal to grant, subject to stockholder approval of the plan
amendment described above, options to management and employees, and the number
of options granted may exhaust the number of shares reserved under the plan, as
amended. It is contemplated that these options would be exercisable for a period
of 10 years with an exercise price equal to the price to the public in this
offering.
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<PAGE> 65
SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth information with respect to the number of
shares of common stock and voting stock (includes Series A preferred stock which
is entitled to vote on all matters submitted to a vote by the holders of common
stock) beneficially owned as of October 25, 2000, except as noted below by (1)
all holders of shares of common stock and voting stock known by the company to
own beneficially more than 5% of the outstanding shares of any class of the
voting stock, (2) the executive officers of the company, (3) each director of
the company and (4) all directors and executive officers of our company as a
group.
<TABLE>
<CAPTION>
AMOUNT AND APPROXIMATE PRO FORMA AMOUNT PRO FORMA
NATURE PERCENTAGE OF AND NATURE OF APPROXIMATE
OF BENEFICIAL VOTING STOCK BENEFICIAL PERCENTAGE OF
OWNERSHIP OWNED BEFORE OWNERSHIP AFTER VOTING STOCK
NAME AND ADDRESS BEFORE THE THE THE OWNED AFTER THE
OF BENEFICIAL OWNER RECAPITALIZATION RECAPITALIZATION RECAPITALIZATION(1) RECAPITALIZATION(1)
----------------------------- ---------------- ---------------- ------------------- -------------------
<S> <C> <C> <C> <C>
OFFICERS AND DIRECTORS:
Joseph T. Williams(2)(3)..... 0 * 0 *
Edward J. Munden(2)(3)....... 6,600,000(4) 7.4% 42,307(4) 0.38%
Jerry B. Davis(2)............ 0 * 0 *
Robert L. Keiser(2).......... 0 * 0 *
Bruce I. Benn(3)............. 6,600,000(4) 7.4% 42,307(4) 0.38%
Robert P. Lindsay(2)(3)...... 6,614,286(4)(5) 7.4% 42,398(4)(5) 0.38%
William W. Lesikar(3)........ 0 * 0 *
All executive officers and
directors as a group (5
persons)................... 6,614,286(4) 7.4% 42,398(4) 0.38%
FIVE PERCENT STOCKHOLDERS:
Joint Energy Development
Investments Limited
Partnership................ 12,234,952(6) 13.6% 229,391 2.04%
1400 Smith St
Houston, Texas 77002-7361
EIBOC Investments Ltd........ 6,600,000(4) 7.3% 42,308(4) 0.38%
Charlton House
White Park Road
Bridgetown, Barbados W.I.
JNC Opportunity Fund, Ltd.... 13,947,161(7) 15.4% 292,193 2.60%
c/o Encore Capital
Management, LLC
12007 Sunrise Valley
Drive,
Suite 460
Reston, Virginia 20191
</TABLE>
---------------
* Less than 1 percent.
(1) Assumes that the recapitalization, the reverse stock split and this offering
of 10,000,000 shares of common stock have occurred.
(2) Does not include shares issuable on the exercise of options granted, subject
to stockholder approval of an amendment to our option plans to the following
persons: Joseph T. Williams -- 250,000; Jerry B. Davis -- 3,000 and Robert
L. Keiser -- 3,000. In addition, does not include shares issuable on the
exercise of options that may be granted subject to stockholder approval of
an amendment to our incentive equity plan, to Messrs. Munden and Lindsay.
For a further description, see "Management -- Management and directors
options."
(3) Executive officer and/or director.
(4) Edward J. Munden, Ronald I. Benn and Bruce I. Benn have a beneficial
interest in the shares of common stock owned by EIBOC Investments Ltd., or
EIBOC. In addition, EIBOC has granted an
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<PAGE> 66
irrevocable proxy to Messrs. Munden, Benn, Benn and Lindsay to vote
6,600,000 shares, or 42,308 post reverse split shares, owned of record by
EIBOC. Accordingly, the 6,600,000 shares, or 42,308 post reverse split
shares, owned of record by EIBOC have been included as beneficially owned by
each of the foregoing individuals, and by all executive officers and
directors as a group.
(5) Mr. Lindsay acquired 14,286 shares, or 91 post reverse split shares, of
common stock in the name of his children and disclaims any beneficial
interest in these shares.
(6) Ownership as of July 21, 2000. Includes 9,600,000 shares of common stock
issuable upon conversion of the 9,600,000 shares of Series A preferred stock
and 2,634,952 shares of common stock. JEDI is a limited partnership, the
general partner of which is Enron Capital Management Limited Partnership,
which is an indirect wholly-owned subsidiary of Enron Corp. Upon the
occurrence of certain events of default (as defined in our restated
certificate of incorporation), JEDI, the holder of the Series A preferred
stock, has the right to require us to repurchase the Series A preferred
stock.
(7) Ownership as of July 21, 2000. Includes 364,500 shares of pre-split common
stock issuable upon exercise of warrants held by JNC Opportunity Fund, Ltd.,
or JNC. Also includes 283,827 shares of pre-split common stock held by
Diversified Strategies Fund, L.P., under common management with JNC, and
10,500 shares of pre-split common stock issuable to Diversified Strategies
Fund, L.P. upon exercise of warrants. Does not include 76,825,534 shares of
pre-split common stock issuable to JNC and 1,688,355 shares of pre-split
common stock issuable to Diversified upon exercise of repricing rights as of
July 21, 2000 (computed without regard to the covenants in the securities
purchase agreement limiting the number of shares of common stock an
individual holder may beneficially own).
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<PAGE> 67
DESCRIPTION OF CAPITAL STOCK
Our authorized capital stock consists of 100,000,000 shares of common stock
and 50,000,000 shares of preferred stock. Immediately after this offering, we
will have approximately 11,250,000 shares of common stock outstanding and no
shares of preferred stock outstanding.
COMMON STOCK
The holders of shares of common stock have full voting power for the
election of directors and for all other purposes. Each holder of common stock
has one vote for each share. The shares of common stock do not have cumulative
voting rights.
Subject to the rights of holders of any outstanding shares of preferred
stock, holders of common stock are entitled to dividends in the amounts and at
the times declared by our board of directors in its discretion out of funds
legally available for the payment of dividends. Holders of common stock have no
subscription, redemption, sinking fund, conversion or preemptive rights. The
outstanding shares of common stock are fully paid and nonassessable. After
payment is made in full to the holders of any outstanding shares of preferred
stock in the event of any liquidation, our remaining assets and funds will be
distributed to the holders of common stock according to their respective shares.
For a description of provisions of our certificate of incorporation that
could make it more difficult for a third party to acquire control of us, see
"Risk Factors -- Our certificate of incorporation contains provisions that could
discourage an acquisition or change of control of our company."
PREFERRED STOCK
At the direction of our board, we may issue shares of preferred stock from
time to time. Our board of directors may, without any action by holders of the
common stock:
- adopt resolutions to issue preferred stock in one or more classes or
series;
- fix or change the number of shares constituting any class or series of
preferred stock; and
- establish or change the rights of the holders of any class or series of
preferred stock.
The rights any class or series of preferred stock may evidence may include:
- general or special voting rights;
- preferential liquidation or preemptive rights;
- preferential cumulative or noncumulative dividend rights;
- redemption or put rights; and
- conversion or exchange rights.
We may issue shares of, or rights to purchase, preferred stock the terms of
which might:
- adversely affect voting or other rights evidenced by, or amounts
otherwise payable with respect to, the common stock;
- discourage an unsolicited proposal to acquire us; or
- facilitate a particular business combination involving us.
Any of these actions could discourage a transaction that some or a majority
of our stockholders might believe to be in their best interests or in which our
stockholders might receive a premium for their stock over its then market price.
TRANSFER AGENT AND REGISTRAR
The transfer agent and registrar for the common stock is Continental Stock
Transfer and Trust Company, 2 Broadway, New York, New York 10004.
WARRANTS
There are currently outstanding warrants to purchase an aggregate of 3,397
shares of post-reverse split shares of common stock at exercise prices ranging
from $936 to $1,248 per share. We issued these warrants to the placement agents
in connection with previous equity private placements.
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<PAGE> 68
SHARES ELIGIBLE FOR FUTURE SALE
Upon completion of this offering and the recapitalization, we will have
outstanding approximately 11,250,000 shares of common stock, assuming no
exercise of the underwriter's over-allotment option. Of the shares of common
stock that will be outstanding after this offering, approximately 11,145,314
shares will be freely tradable without restriction or further registration under
the Securities Act except that any shares purchased by our "affiliates," as that
term is defined in Rule 144 under the Securities Act, generally may be sold only
in compliance with the limitations of Rule 144 described below and the shares
acquired by some of our stockholders in the recapitalization will be subject to
transfer restrictions described below in "Underwriting -- Future sales." All of
the remaining 104,686 shares of common stock will be "restricted" securities as
that term is defined in Rule 144. The "restricted" securities may not be resold
unless they are registered under the Securities Act or are sold pursuant to an
available exemption from registration, including Rule 144 under the Securities
Act. Upon expiration of the lock-up agreements described below, 104,686 of the
restricted shares will be eligible for resale at various times thereafter upon
expiration of applicable holding periods. Restricted securities may be sold in
the public market only if they qualify for an exemption from registration under
Rule 144, including Rule 144(k), or Rule 701 under the Securities Act.
RULE 144
In general, under Rule 144 as currently in effect, commencing 90 days after
the date of this prospectus, a person who has beneficially owned shares of our
common stock for at least one year is entitled to sell within any three-month
period a number of shares that does not exceed the greater of:
- 1% of the number of shares of common stock then outstanding, which is
expected to be approximately 112,500 shares upon completion of this
offering, assuming no exercise of the underwriters' over-allotment option
or
- the average weekly trading volume of the common stock on the Nasdaq
National Market during the four calendar weeks preceding the filing of a
notice on Form 144 with respect to the sale, subject to the restrictions
specified in Rule 144.
Sales under Rule 144 are also subject to manner of sale provisions and notice
requirements and to the availability of current public information about us.
RULE 144(k)
Under Rule 144(k), a person who is not one of our affiliates at any time
during the three months preceding a sale and who has beneficially owned the
shares proposed to be sold for at least two years is entitled to sell the shares
under Rule 144(k) without complying with the manner of sale, public information,
volume limitation or notice provisions of Rule 144. Therefore, unless otherwise
restricted, Rule 144(k) shares may be sold immediately upon completion of this
offering.
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UNDERWRITING
Subject to the terms and conditions of an underwriting agreement, the
underwriters named below are acting through their representatives, Friedman,
Billings, Ramsey & Co., Inc. and Stifel, Nicolaus & Company, Incorporated. The
underwriters have agreed with us, subject to the terms and conditions of the
underwriting agreement, to purchase from us the number of shares of common stock
shown opposite their names below. Other than the shares covered by the
over-allotment option, the underwriters are obligated to purchase and accept
delivery of all the shares of common stock if any are purchased.
<TABLE>
<CAPTION>
UNDERWRITER NUMBER OF SHARES
----------- ----------------
<S> <C>
Friedman, Billings, Ramsey & Co., Inc. ..................... 6,037,500
Stifel, Nicolaus & Company, Incorporated.................... 2,587,500
Advest, Inc. ............................................... 125,000
William Blair & Company, LLC................................ 125,000
Dominick & Dominick LLC..................................... 125,000
Fahnestock & Co. Inc. ...................................... 125,000
First Southwest Company..................................... 125,000
Janney Montgomery Scott LLC................................. 125,000
Jefferies & Company, Inc. .................................. 125,000
Sanders Morris Harris, Inc. ................................ 125,000
Scott & Stringfellow, Inc. ................................. 125,000
Suntrust Equitable Securities Corporation................... 125,000
Tucker Anthony Incorporated................................. 125,000
----------
Total............................................. 10,000,000
==========
</TABLE>
The underwriters propose initially to offer the shares of common stock in
part directly to the public at the initial public offering price shown on the
cover page of this prospectus and in part to dealers, including the
underwriters, at this price less a discount not in excess of $0.21 per share.
The underwriters may allow, and such dealers may re-allow other dealers, a
discount not in excess of $0.10 per share.
The following table shows the underwriting discounts and commissions to be
paid to the underwriters by us. These amounts represent the public offering
price per share minus the amount paid by the underwriters per share and are
shown assuming both no exercise and full exercise of the underwriters' option to
purchase additional shares of common stock. The underwriters' compensation was
determined through negotiations between their representatives and us. In
addition, Friedman, Billings, Ramsey & Co., Inc., has performed services related
to identifying and evaluating various strategic alternatives since August 1999
and will receive 2% of the gross proceeds of this offering as a fee for these
services and reimbursement of its out-of-pocket expenses, including fees and
disbursements of its legal counsel and petroleum consultant.
<TABLE>
<CAPTION>
EXERCISE NO EXERCISE FULL EXERCISE
-------- ----------- -------------
<S> <C> <C>
Total underwriting fees..................................... $3,500,000 $4,025,000
Underwriting fee per share................................ 0.35 0.35
</TABLE>
OVER-ALLOTMENT. The underwriters have an option, exercisable within 30 days
after the date of this prospectus, to purchase up to an aggregate of 1,500,000
additional shares of common stock at the public offering price less the
underwriting discounts and commissions. The underwriters may exercise this
option solely to cover over-allotments, if any, made in this offering. If the
underwriters exercise this option, each underwriter will purchase shares in
approximately the same proportion as indicated in the table above.
INDEMNITY. DevX has agreed to indemnify the underwriters against some types
of liabilities, including liabilities under the Securities Act. DevX has also
agreed to contribute to payments that the underwriters may be required to make
with respect to any of those liabilities. In addition, we have agreed to make
the
69
<PAGE> 70
underwriters insured parties under our directors and officers insurance policy
prior to the consummation of the offering.
FUTURE SALES. DevX, its officers and directors have agreed not to offer,
pledge, sell, hedge or otherwise transfer or dispose of, directly or indirectly,
any shares of common stock or any securities convertible into or exercisable or
exchangeable for common stock for a period of 180 days from the date of this
prospectus. Transfers or dispositions can be made sooner with the prior written
consent of Friedman, Billings, Ramsey & Co., Inc., which may be given at any
time without public notice. During this 180-day period, we have agreed not to
file any registration statement with respect to any shares of our common stock.
In addition, the Series A preferred stockholder, each Series C preferred
stockholder and each repricing rights holder has agreed in the recapitalization
agreement signed as part of the recapitalization not to sell, on any given
trading day during the six month period immediately following the closing date
of this offering, more than the percentage of total shares received by the
holder equal to the percentage that the holder's shares comprise of the total
number of all post reverse-split common shares outstanding immediately after the
close of this offering. For example, a holder that ends up with 1% of our total
shares outstanding after this offering shall be permitted to sell only up to 1%
of the shares the holder owns on any given day within the six-month period after
the closing of this offering.
OFFERS IN OTHER JURISDICTIONS. Neither we nor the underwriters have taken
any action that would permit a public offering of the shares of common stock
offered by this prospectus in any jurisdiction other than the United States
where action for that purpose is required. The shares of common stock offered by
this prospectus may not be offered or sold, directly or indirectly, nor may this
prospectus or any other offering material or advertisements related to the offer
and sale of these shares of common stock be distributed or published, in any
jurisdiction, except under circumstances that will result in compliance with the
applicable rules and regulations of such jurisdiction. This prospectus is not an
offer to sell or a solicitation of an offer to buy any shares of common stock
offered hereby in any jurisdiction in which such an offer or solicitation is
unlawful.
DISCRETIONARY ACCOUNT SALES. Friedman, Billings, Ramsey & Co., Inc. has
advised us that the underwriters do not expect discretionary sales by the
underwriters to exceed five percent of the shares offered by this prospectus.
STABILIZATION. In connection with this offering, the underwriters may
engage in transactions in the over-the-counter market or otherwise that
stabilize, maintain or otherwise affect the price of the common stock.
Specifically, the underwriters may over allot this offering, creating a
syndicate short position. In addition, the underwriters may bid for and purchase
shares of common stock. In addition, Friedman, Billings Ramsey & Co., Inc., on
behalf of the underwriters, may reclaim selling concessions allowed to an
underwriter or dealer for distributing the common stock in the offering if the
syndicate repurchases previously distributed shares of common stock to cover
syndicate short positions, in stabilizing transactions or otherwise. These
activities may stabilize or maintain the market price of the common stock above
independent market levels. The underwriters are not required to engage in these
activities and may discontinue any of these activities at any time.
DETERMINATION OF OFFERING PRICE. Though immediately prior to this offering
our common stock was quoted on the OTC Bulletin Board, the public offering price
of the common stock in this offering is not based on the market price of our
common stock but was determined by negotiations between us and the underwriters.
Among the factors considered in determining the public offering price were:
- prevailing market conditions;
- our results of operations in recent periods;
- the present stage of our development;
- the market capitalizations and development stages of other companies that
we and the underwriters believe to be comparable to us; and
- estimates of our growth potential.
70
<PAGE> 71
LEGAL MATTERS
The validity of the issuance of the shares of common stock offered by this
prospectus will be passed on for us by Haynes and Boone, LLP. Certain legal
matters relating to the common stock offered by this prospectus will be passed
on by Fulbright & Jaworski L.L.P., as counsel for the underwriters.
ENGINEERS
The estimates relating to our proved oil and natural gas reserves and
future net revenues of oil and natural gas reserves as of June 30, 1998 and 1999
(other than with respect to the Morgan Properties) included in this prospectus
and incorporated in this prospectus by reference to our Annual Report on Form
10-K for the year ended June 30, 2000 are based upon estimates of the reserves
prepared by H.J. Gruy in reliance upon its reports and upon the authority of
H.J. Gruy as experts in petroleum engineering.
The estimates relating to our proved oil and natural gas reserves and
future net revenues of oil and natural gas reserves at June 30, 1998 and 1999
with respect to the Morgan Properties included in this prospectus and
incorporated in this prospectus by reference to our Annual Report on Form 10-K
for the year ended June 30, 2000 are based upon estimates of the reserves
prepared by Ryder Scott, independent consulting petroleum engineers, in reliance
upon its report and upon the authority of Ryder Scott as experts in petroleum
engineering.
The estimates relating to our proved oil and natural gas reserve and future
net revenues of oil and natural gas reserves as of June 30, 2000 were prepared
by our internal petroleum engineers.
EXPERTS
Ernst & Young LLP, independent auditors, have audited our consolidated
financial statements at June 30, 2000 and 1999, and for each of the three years
in the period ended June 30, 2000, as set forth in their report. We have
included our financial statements in the prospectus and elsewhere in the
registration statement in reliance on Ernst & Young LLP's report, given on their
authority as experts in accounting and auditing.
WHERE YOU CAN FIND MORE INFORMATION
This prospectus is part of a registration statement we have filed with the
SEC relating to our common stock. As permitted by SEC rules, this prospectus
does not contain all of the information we have included in the registration
statement and the accompanying exhibits and schedules we filed with the SEC. You
may refer to the registration statement, exhibits and schedules for more
information about us and our common stock. In addition, we are required to file
current reports, quarterly reports, annual reports, proxy statements and other
information with the SEC. You can read and copy the registration statement,
exhibits and schedules and other filings at the SEC's Public Reference Room at
450 Fifth Street, N.W., Washington, D.C. 20549, and at the SEC's regional
offices located at 7 World Trade Center, 13th Floor, New York, New York 10048,
and at Suite 1400, 500 West Madison Street, Chicago, Illinois 60661. You can
obtain information about the operation of the SEC's Public Reference Room by
calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet site that
contains reports, proxy and information statements, and other information
regarding issuers that file electronically with the SEC. The address for that
site on the world wide web is sec.gov. Our Internet site on the world wide web
is qsri.com. Neither the information on our web site nor the SEC's web site is
part of this prospectus and references in this prospectus to our web site or any
other web site are inactive textual references only.
71
<PAGE> 72
INCORPORATION BY REFERENCE
The SEC allows us to "incorporate by reference" the information we file
with them, which means that we can disclose important information to you by
referring you to those documents. The information incorporated by reference is
an important part of this prospectus. We incorporate by reference the documents
listed below and filed with the SEC under Sections 13(a), 13(c), 14 or 15(d) of
the Securities Exchange Act of 1934:
- Annual Report on Form 10-K for the year ended June 30, 2000;
- Current Report on Form 8-K dated September 18, 2000; and
- The description of our common stock contained in our Registration
Statement on Form 10-SB filed under Section 12 of the Securities Exchange
Act of 1934.
We will provide these filings to any person, including any beneficial
owner, to whom this prospectus is delivered, at no cost, upon written or oral
request to us as follows:
13760 Noel Road, Suite 1030
Dallas, Texas 75240-7336
Attn: William W. Lesikar
Telephone: (972) 233-9906
You should rely only on the information incorporated by reference or
provided in this prospectus. We have not authorized anyone else to provide you
with different information. We are not making an offer of these securities in
any state where the offer is not permitted. You should not assume that the
information in this prospectus is accurate as of any date other than the date on
the front of those documents.
72
<PAGE> 73
GLOSSARY
The terms defined in this glossary are used throughout this prospectus.
"AVERAGE NYMEX PRICE." The average of the NYMEX closing prices for the near
month.
BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to crude oil or other liquid hydrocarbons.
BBL/D. Bbl per day.
BCF. One billion cubic feet of natural gas.
BCFE. One billion cubic feet of natural gas equivalents, converting one Bbl
of oil to six Mcf of gas.
"BEHIND-THE-PIPE." Hydrocarbons in a potentially producing horizon
penetrated by a well bore the production of which has been postponed pending the
production of hydrocarbons from another formation penetrated by the well bore.
The hydrocarbons are classified as proved but non-producing reserves.
"DEVELOPMENT WELL." A well drilled within the proved boundaries of an oil
or natural gas reservoir with the intention of completing the stratigraphic
horizon known to be productive.
"DRY WELL." A development or exploratory well found to be incapable of
producing either oil or natural gas in sufficient quantities to justify
completion as an oil or natural gas well.
"EXPLORATORY WELL." A well drilled to find oil or natural gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or natural gas in another reservoir, or to extend a known
reservoir.
"GROSS ACRES" or "GROSS WELLS." The total number of acres or wells, as the
case may be, in which a working interest is owned.
MBBL. One thousand barrels of crude oil or other liquid hydrocarbons.
MCF. One thousand cubic feet of natural gas.
MCF/D. Mcf per day.
MCFE. One thousand cubic feet of natural gas equivalents, converting one
Bbl of oil to six Mcf of gas.
MMBBL. One million barrels of crude oil or other liquid hydrocarbons.
MMCFE. One million cubic feet of natural gas equivalents, converting one
Bbl of oil to six Mcf of gas.
MMCF. One million cubic feet of natural gas.
"MORGAN PROPERTIES" means the net profits interests and royal interest
revenues we purchased in April 1998 from pension funds managed by J.P. Morgan
Investments.
"NET ACRES" or "NET WELLS." The sum of the fractional working interests
owned in gross acres or gross wells.
"NET PROFITS INTEREST." A share of the gross oil and natural gas production
from a property, measured by net profits from the operation of the property,
that is carved out of the working interest. This is a non-operating interest.
"NON-PRODUCING RESERVES." Non-producing reserves consist of (i) reserves
from wells that have been completed and tested but are not yet producing due to
lack of market or minor completion problems that are expected to be corrected,
and (ii) reserves currently behind-the-pipe in existing wells which are expected
to be productive due to both the well log characteristics and analogous
production in the immediate vicinity of the well.
NYMEX. New York Mercantile Exchange.
73
<PAGE> 74
"PRODUCING WELL," "PRODUCTION WELL" or "PRODUCTIVE WELL." A well that is
producing oil or natural gas or that is capable of production.
"PROVED DEVELOPED PRODUCING." Proved developed producing reserves are
proved developed reserves which are currently capable of producing in commercial
quantities.
"PROVED DEVELOPED RESERVES." Proved developed reserves are oil and natural
gas reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods. Additional oil and natural gas
expected to be obtained through the application of fluid injection or other
improved recovery techniques for supplementing the natural forces and mechanisms
of primary recovery should be included as "proved developed reserves" only after
testing by a pilot project or after the operation of an installed program has
confirmed through production response that increased recovery will be achieved.
"PROVED RESERVES." The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
"PROVED UNDEVELOPED RESERVES" or PUD. Proved undeveloped reserves are oil
and natural gas reserves that are expected to be recovered from new wells on
undrilled acreage, or from existing wells where a relatively major expenditure
is required for recompletion. Reserves on undrilled acreage shall be limited to
those drilling units offsetting productive units that are reasonably certain of
production when drilled. Proved reserves for other undrilled units can be
claimed only where it can be demonstrated with certainty that there is
continuity of production from the existing productive formation. Under no
circumstances should estimates for proved undeveloped reserves be attributable
to any acreage for which an application of fluid injection or other improved
recovery techniques is contemplated, unless such techniques have been proved
effective by actual tests in the area and in the same reservoir.
"RECOMPLETION." A recompletion is an operation to abandon the production of
oil and/or natural gas from a well in one zone within the existing wellbore and
to make the well produce oil and/or natural gas from a different, separately
producible zone within the existing wellbore.
"RESERVE LIFE INDEX." The estimated productive life of a proved reservoir
based upon the economic limit of such reservoir producing hydrocarbons in paying
quantities assuming certain price and cost parameters. For purposes of this
prospectus, reserve life is calculated by dividing the proved reserves (on a
Mcfe basis) at the end of the period by production volumes for the previous 12
months.
"ROYALTY INTEREST." An interest in an oil and natural gas property
entitling the owner to a share of oil and natural gas production free of costs
of production.
"SEC PV-10." The present value of proved reserves is an estimate of the
discounted future net cash flows from each of the properties at June 30, 2000,
or as otherwise indicated. Net cash flow is defined as net revenues less, after
deducting production and ad valorem taxes, future capital costs and operating
expenses, but before deducting federal income taxes. As required by rules of the
Commission, the future net cash flows have been discounted at an annual rate of
10% to determine their "present value." The present value is shown to indicate
the effect of time on the value of the revenue stream and should not be
construed as being the fair market value of the properties. In accordance with
Commission rules, estimates have been made using constant oil and natural gas
prices and operating costs, at June 30, 2000, or as otherwise indicated.
"SECONDARY RECOVERY." A method of oil and natural gas extraction in which
energy sources extrinsic to the reservoir are utilized.
"SERVICE WELL." A well used for water injection in secondary recovery
projects or for the disposal of produced water.
"STANDARDIZED MEASURE." Under the Standardized Measure, future cash flows
are estimated by applying year-end prices, adjusted for fixed and determinable
escalations, to the estimated future production of year-end proved reserves.
Future cash inflows are reduced by estimated future production
74
<PAGE> 75
and development costs based on period-end costs to determine pretax cash
inflows. Future income taxes are computed by applying the statutory tax rate to
the excess of pretax cash inflows over our tax basis in the associated
properties. Tax credits, net operating loss carryforwards, and permanent
differences are also considered in the future tax calculation. Future net cash
inflows after income taxes are discounted using a 10% annual discount rate to
arrive at the Standardized Measure.
"UNDEVELOPED ACREAGE." Lease acreage on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of oil and natural gas regardless of whether such acreage contains
proved reserves.
"WORKING INTEREST." The operating interest which gives the owner the right
to drill, produce and conduct operating activities on the property and a share
of production, subject to all royalties, overriding royalties and other burdens
and to all costs of exploration to, development and operations and all risks in
connection therewith.
75
<PAGE> 76
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Report of Ernst & Young LLP, Independent Auditors........... F-2
Consolidated Financial Statements
Consolidated Balance Sheets as of June 30, 1999 and 2000.... F-3
Consolidated Statements of Operations for the Years ended
June 30, 1998, 1999, and 2000............................. F-4
Consolidated Statements of Stockholders' Equity (Net Capital
Deficiency) for the Years ended June 30, 1998, 1999, and
2000...................................................... F-5
Consolidated Statements of Cash Flows for the Years ended
June 30, 1998, 1999, and 2000............................. F-6
Notes to Consolidated Financial Statements.................. F-7
</TABLE>
F-1
<PAGE> 77
REPORT OF ERNST & YOUNG LLP, INDEPENDENT AUDITORS
The Board of Directors and Stockholders
DevX Energy, Inc.
We have audited the accompanying consolidated balance sheets of DevX
Energy, Inc. (formerly Queen Sand Resources, Inc.) and subsidiaries as of June
30, 1999 and 2000, and the related consolidated statements of operations,
stockholders' equity (net capital deficiency), and cash flows for each of the
three years in the period ended June 30, 2000. These consolidated financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audit.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of DevX Energy,
Inc. (formerly Queen Sand Resources, Inc.) and subsidiaries as of June 30, 1999
and 2000, and the results of their operations and their cash flows for each of
the three years in the period ended June 30, 2000, in conformity with accounting
principles generally accepted in the United States.
Dallas, Texas
August 18, 2000
F-2
<PAGE> 78
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
JUNE 30,
---------------------------
1999 2000
------------ ------------
<S> <C> <C>
ASSETS
Current assets:
Cash...................................................... $ 9,367,000 $ 11,881,000
Accounts receivable....................................... 4,499,000 6,530,000
Note receivable from employee............................. 79,000 --
Other..................................................... 74,000 113,000
------------ ------------
Total current assets........................................ 14,019,000 18,524,000
------------ ------------
Property and equipment, at cost:
Oil and gas properties, based on full cost accounting
method................................................. 178,421,000 182,280,000
Other equipment........................................... 392,000 405,000
------------ ------------
178,813,000 182,685,000
Less accumulated depreciation and amortization............ (81,615,000) (90,160,000)
------------ ------------
Net property and equipment.................................. 97,198,000 92,525,000
Other assets................................................ 7,993,000 8,144,000
------------ ------------
$119,210,000 $119,193,000
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable.......................................... $ 1,419,000 $ 355,000
Accrued liabilities....................................... 9,681,000 9,596,000
Current portion of long-term obligations.................. 42,000 584,000
------------ ------------
Total current liabilities................................... 11,142,000 10,535,000
Long-term obligations, net of current portion............... 133,852,000 143,500,000
Commitments and contingencies
Stockholders' equity (net capital deficiency):
Preferred stock, $.01 par value:
Authorized shares -- 50,000,000 at June 30, 1999 and
2000
Issued and outstanding shares -- 9,604,698 and
9,602,173 at June 30, 1999 and 2000, respectively.... 96,000 96,000
Aggregate liquidation preference -- $10,051,950 and
$7,446,225 at June 30, 1999 and 2000, respectively
Common stock, $.0015 par value:
Authorized shares -- 100,000,000 at June 30, 1999 and
2000
Issued and outstanding shares -- 33,442,210 and
80,688,538 at June 30, 1999 and 2000, respectively... 65,000 135,000
Additional paid-in capital................................ 64,912,000 65,112,000
Accumulated deficit....................................... (83,606,000) (92,934,000)
Treasury stock, at cost................................... (7,251,000) (7,251,000)
------------ ------------
Total stockholders' equity (net capital
deficiency)..................................... (25,784,000) (34,842,000)
------------ ------------
Total liabilities and stockholders' equity........ $119,210,000 $119,193,000
============ ============
</TABLE>
See accompanying notes.
F-3
<PAGE> 79
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
-----------------------------------------
1998 1999 2000
------------ ------------ -----------
<S> <C> <C> <C>
Revenues:
Oil and gas sales................................. $ 6,446,000 $ 4,591,000 $ 3,967,000
Net profits and royalty interests................. 4,432,000 23,140,000 22,990,000
Interest and other................................ 105,000 326,000 143,000
------------ ------------ -----------
10,983,000 28,057,000 27,100,000
Expenses:
Production expenses............................... 4,547,000 3,196,000 1,372,000
Depreciation and amortization..................... 4,809,000 11,885,000 8,741,000
Hedge contract termination costs.................. -- -- 3,328,000
Write-down of oil and gas properties.............. 28,166,000 35,033,000 --
General and administrative........................ 2,259,000 3,533,000 3,026,000
Interest and financing costs...................... 3,956,000 18,352,000 18,561,000
------------ ------------ -----------
43,737,000 71,999,000 35,028,000
------------ ------------ -----------
Loss before extraordinary item...................... (32,754,000) (43,942,000) (7,928,000)
Extraordinary loss.................................. -- 3,549,000 1,130,000
------------ ------------ -----------
Net loss............................................ $(32,754,000) $(47,491,000) $(9,058,000)
============ ============ ===========
Loss before extraordinary item per common share..... $ (1.44) $ (1.40) $ (0.18)
============ ============ ===========
Net loss per common share........................... $ (1.44) $ (1.51) $ (0.21)
============ ============ ===========
Weighted average common shares outstanding.......... 22,719,177 31,434,465 43,465,423
============ ============ ===========
</TABLE>
See accompanying notes.
F-4
<PAGE> 80
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(NET CAPITAL DEFICIENCY)
YEARS ENDED JUNE 30, 1998, 1999, AND 2000
<TABLE>
<CAPTION>
PREFERRED STOCK COMMON STOCK ADDITIONAL TOTAL
------------------- --------------------- PAID-IN ACCUMULATED STOCKHOLDERS'
SHARES AMOUNT SHARES AMOUNT CAPITAL TREASURY DEFICIT EQUITY
--------- ------- ---------- -------- ----------- ----------- ------------ -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Balance at June 30,
1997................... 9,600,000 $96,000 20,825,552 $ 46,000 $14,474,000 $(5,000,000) $ (3,185,000) $ 6,431,000
Issuance of common
stock for services... -- -- 150,000 -- 300,000 -- -- 300,000
Issuance of common
stock for oil and gas
properties........... -- -- 1,337,500 2,000 4,810,000 -- -- 4,812,000
Issuance of common
stock for cash....... -- -- 2,010,715 3,000 4,883,000 -- -- 4,886,000
Issuance of convertible
preferred stock and
warrants to purchase
common stock for
cash................. 10,400 -- -- -- 9,544,000 -- -- 9,544,000
Net loss............... -- -- -- -- -- -- (32,754,000) (32,754,000)
--------- ------- ---------- -------- ----------- ----------- ------------ ------------
Balance at June 30,
1998................... 9,610,400 96,000 24,323,767 51,000 34,011,000 (5,000,000) (35,939,000) (6,781,000)
Issuance of common
stock for oil and gas
properties........... -- -- 8,740 -- 65,000 -- -- 65,000
Issuance of common
stock for cash....... -- -- 3,845,241 6,000 23,668,000 -- -- 23,674,000
Issuance of common
stock upon exercise
of
warrants............. -- -- 2,474,236 4,000 6,996,000 -- -- 7,000,000
Issuance of common
stock pursuant to
repricing
rights............... -- -- 1,384,016 2,000 (2,000) -- -- --
Issuance of common
stock on conversion
of convertible
preferred
stock................ (3,550) -- 1,328,639 2,000 (2,000) -- -- --
Issuance of common
stock as stock
dividend............. -- -- 77,571 -- 176,000 -- (176,000) --
Repurchase of
convertible preferred
stock................ (2,152) -- -- -- -- (2,251,000) -- (2,251,000)
Net loss............... -- -- -- -- -- -- (47,491,000) (47,491,000)
--------- ------- ---------- -------- ----------- ----------- ------------ ------------
Balance at June 30,
1999................... 9,604,698 96,000 33,442,210 65,000 64,912,000 (7,251,000) (83,606,000) (25,784,000)
Issuance of common
stock pursuant to
repricing rights..... -- -- 38,113,785 56,000 (56,000) -- -- --
Issuance of common
stock on conversion
of convertible
preferred
stock................ (2,525) -- 8,217,831 12,000 (12,000) -- -- --
Issuance of common
stock as stock
dividend............. -- -- 914,712 2,000 268,000 -- (270,000) --
Net loss............... -- -- -- -- -- -- (9,058,000) (9,058,000)
--------- ------- ---------- -------- ----------- ----------- ------------ ------------
Balance at June 30,
2000................... 9,602,173 $96,000 80,688,538 $135,000 $65,112,000 $(7,251,000) $(92,934,000) $(34,842,000)
========= ======= ========== ======== =========== =========== ============ ============
</TABLE>
See accompanying notes.
F-5
<PAGE> 81
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
-------------------------------------------
1998 1999 2000
------------- ------------ ------------
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net loss.......................................... $ (32,754,000) $(47,491,000) $ (9,058,000)
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Extraordinary loss.............................. -- 3,549,000 1,130,000
Depreciation and amortization................... 4,809,000 13,354,000 10,288,000
Write-down of oil and gas properties............ 28,166,000 35,033,000 --
Unrealized foreign currency translation gains... (18,000) (19,000) (54,000)
Issuance of common stock for services........... 300,000 -- --
Changes in operating assets and liabilities:
Accounts receivable.......................... (4,580,000) 747,000 (1,952,000)
Other assets................................. (45,000) (18,000) (39,000)
Accounts payable and accrued liabilities..... 5,163,000 4,349,000 (1,149,000)
------------- ------------ ------------
Net cash provided by (used in) operating
activities...................................... 1,041,000 9,504,000 (834,000)
INVESTING ACTIVITIES
Additions to oil and gas properties............... (154,242,000) (11,474,000) (7,410,000)
Proceeds from sales of oil and gas properties..... -- 10,024,000 3,551,000
Net additions to other property and equipment..... (100,000) (161,000) (15,000)
------------- ------------ ------------
Net cash used in investing activities............. (154,342,000) (1,611,000) (3,874,000)
FINANCING ACTIVITIES
Proceeds from revolving credit facilities......... 103,000,000 12,300,000 26,898,000
Proceeds from (repayments on) bridge financing
facilities...................................... 58,860,000 (58,860,000) --
Debt issuance costs............................... (4,898,000) (4,665,000) (1,957,000)
Termination of LIBOR swap agreement............... -- (3,549,000) --
Payments on revolving credit facilities........... (15,358,000) (96,800,000) (16,398,000)
Proceeds from issuance of 12 1/2% Senior Notes.... 121,000 125,000,000 --
Costs of proposed recapitalization................ -- -- (1,066,000)
Redemption of DEM bonds........................... -- -- (213,000)
Payments on notes payable......................... (2,064,000) (1,325,000) --
Proceeds from sale of convertible preferred stock
and warrants to purchase common stock........... 9,544,000 -- --
Proceeds from the issuance of common stock........ 4,886,000 30,674,000 --
Repurchase of common and preferred stock.......... -- (2,251,000) --
Payments on capital lease obligation.............. (70,000) (80,000) (42,000)
------------- ------------ ------------
Net cash provided by financing activities......... 154,021,000 444,000 7,222,000
Net increase in cash.............................. 720,000 8,337,000 2,514,000
Cash at beginning of year......................... 310,000 1,030,000 9,367,000
------------- ------------ ------------
Cash at end of year............................... $ 1,030,000 $ 9,367,000 $ 11,881,000
============= ============ ============
</TABLE>
See accompanying notes.
F-6
<PAGE> 82
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 1998, 1999, AND 2000
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
DevX Energy, Inc. (formerly Queen Sand Resources, Inc.) (DevX or the
Company) was formed on August 9, 1994, under the laws of the State of Delaware.
At June 30, 2000, EIBOC Investments Ltd. (EIBOC) held approximately 6,600,000
shares of the Company's common stock, par value $.0015 per share (Common Stock),
representing approximately 7% of the Company's outstanding shares of Common
Stock on a fully diluted basis. Certain officers of the Company have beneficial
interests in EIBOC (see Note 5). Joint Energy Development Investments Limited
Partnership (JEDI), an affiliate of Enron Corp. (Enron), holds approximately 13%
of the Company's voting capital stock on a fully diluted basis.
The Company is engaged in one industry segment: the acquisition,
exploration, development, production, and sale of crude oil and natural gas. The
Company's business activities are carried out primarily in Kentucky, Louisiana,
New Mexico, Oklahoma, and Texas.
The Company is highly leveraged. At June 30, 2000, the Company's ratio of
total indebtedness to total capitalization was 132%. The Company's revenues,
profitability, and ability to repay its indebtedness and related interest
charges are highly dependent upon prevailing prices for oil and natural gas. As
the Company produces more natural gas than oil, it faces more risk related to
fluctuations in natural gas prices than oil prices. To reduce the exposure to
changes in the prices of oil and natural gas, the Company has entered into
certain hedging arrangements (see Note 4). However, a sustained period of
depressed oil and natural gas prices could have a material adverse effect on the
Company's results of operations and financial condition.
The Company has proposed a recapitalization of the Company, which would
include:
(i) A reverse stock split of one common share for every 156 shares of
common stock outstanding
(ii) The exchange of all outstanding convertible preferred stock and
warrants and repricing rights exercisable for shares of the Company's
common stock for 732,500 shares of post reverse split common stock (see
Note 5)
(iii) The repurchase of $75 million face value of the Company's
12 1/2% Senior Notes for approximately $49 million with a portion of the
net proceeds from a public offering of common stock
There can be no assurance that the Company will be able to successfully
complete the proposed recapitalization or the proposed public offering.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of
the Company and its wholly owned subsidiaries. All significant intercompany
balances and transactions have been eliminated in consolidation.
Property and Equipment
The Company follows the full cost method of accounting for its oil and gas
activities under which all costs, including general and administrative expenses
directly associated with property acquisition, exploration, and development
activities, are capitalized. Capitalized general and administrative expenses
directly associated with acquisitions, exploration, and development of oil and
gas properties were approximately $721,000, $931,000, and $706,000 for the years
ended June 30, 1998, 1999, and 2000, respectively. Capitalized costs are
amortized by the unit-of-production method using estimates of proved
F-7
<PAGE> 83
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
oil and gas reserves prepared by independent engineers. The costs of unproved
properties are excluded from amortization until the properties are evaluated.
Sales of oil and gas properties are accounted for as adjustments to the
capitalized cost center unless such sales significantly alter the relationship
between capitalized costs and proved reserves of oil and gas attributable to the
cost center, in which case a gain or loss is recognized.
The Company limits the capitalized costs of oil and gas properties, net of
accumulated amortization, to the estimated future net revenues from proved oil
and gas reserves less estimated future development and production expenditures
discounted at 10%, plus the lower of cost or estimated fair value of unproved
properties, as adjusted for related estimated future tax effects. If capitalized
costs exceed this limit (the full cost ceiling), the excess is charged to
depreciation and amortization expense. During the years ended June 30, 1998 and
1999, the Company recorded full cost ceiling write-downs of $28,166,000 and
$35,033,000, respectively.
Amortization of the capitalized costs of oil and gas properties and limits
to capitalized costs are based on estimates of oil and gas reserves which are
inherently imprecise and are subject to change based on factors such as crude
oil and natural gas prices, drilling results, and the results of production
activities, among others. Accordingly, it is reasonably possible that such
estimates could differ materially in the near term from amounts currently
estimated.
Depreciation of other property and equipment is provided principally by the
straight-line method over the estimated service lives of the related assets.
Equipment under capital lease is recorded at the lower of fair value or the
present value of future minimum lease payments and are depreciated over the
lease term.
Costs incurred to operate, repair, and maintain wells and equipment are
charged to expense as incurred.
Certain of the Company's oil and gas activities are conducted jointly with
others and, accordingly, the financial statements reflect only the Company's
proportionate interest in such activities.
The Company does not expect future costs for site restoration,
dismantlement and abandonment, postclosure, and other exit costs which may occur
in the sale, disposal, or abandonment of a property to be material.
Revenue Recognition
The Company uses the sales method of accounting for oil and gas revenues.
Under the sales method, revenues are recognized based on actual volumes of oil
and gas sold to purchasers.
Environmental Matters
The Company is subject to extensive federal, state, and local environmental
laws and regulations. These laws, which are constantly changing, regulate the
discharge of materials into the environment and may require the Company to
remove or mitigate the environmental effects of the disposal or release of
petroleum or chemical substances at various sites. Environmental expenditures
are expensed or capitalized depending on their future economic benefit.
Expenditures that relate to an existing condition caused by past operations and
that have no future economic benefits are expensed. Liabilities for expenditures
of a noncapital nature are recorded when environmental assessment and/or
remediation is probable, and the costs can be reasonably estimated.
Income Taxes
Income taxes are accounted for under the asset and liability method, under
which deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the
F-8
<PAGE> 84
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
financial statement carrying amounts of existing assets and liabilities and
their respective tax bases and operating loss and tax credit carryforwards.
Deferred tax assets and liabilities are measured using enacted tax rates. The
effect on deferred tax assets and liabilities of a change in tax rates is
recognized in income in the period that includes the enactment date. The
measurement of deferred tax assets is adjusted by a valuation allowance, if
necessary, to recognize the extent to which, based on available evidence, the
future tax benefits more likely than not will be realized.
Statement of Cash Flows
The Company considers all highly liquid investments purchased with an
original maturity of three months or less to be cash equivalents.
During 1998 and 1999, the Company issued an aggregate of 1,337,500 and
8,740 shares of Common Stock, respectively, valued at $4,812,000 and $65,000,
respectively, in connection with the acquisitions of certain interests in oil
and gas properties. During 1998, in connection with certain promotional services
rendered by an unrelated party, the Company issued 150,000 shares of Common
Stock valued at $300,000.
Net Loss Per Common Share
Net loss per common share is presented in accordance with Statement of
Financial Accounting Standards No. 128, Earnings Per Share, which requires
companies to present basic earnings per share calculated based on the weighted
average number of common shares outstanding during the period, and, if
applicable, diluted earnings per share which is calculated based on the weighted
average number of common shares outstanding during the period plus any dilutive
common equivalent shares outstanding. As the Company incurred net losses during
each of the years ended June 30, 1998, 1999, and 2000, the loss per common share
data is based on the weighted average common shares outstanding and excludes the
effects of the Company's potentially dilutive securities (see Note 5).
Stock Compensation
The Company has elected to follow Accounting Principles Board Opinion No.
25, Accounting for Stock Issued to Employees (APB 25), in accounting for its
employee stock options. Under APB 25, if the exercise price of an employee's
stock options equals or exceeds the market price of the underlying stock on the
date of grant and certain other plan conditions are met, no compensation expense
is recognized.
Concentrations of Credit Risk
The Company sells crude oil and natural gas to various customers. In
addition, the Company participates with other parties in the operation of crude
oil and natural gas wells. Substantially all of the Company's accounts
receivable are due from either purchasers of crude oil and natural gas or
participants in crude oil and natural gas wells for which the Company serves as
the operator. Generally, operators of crude oil and natural gas properties have
the right to offset future revenues against unpaid charges related to operated
wells. The Company's receivables are generally unsecured.
For the year ended June 30, 1998, two oil and gas companies accounted for
17% and 13%, respectively, of the Company's oil and gas sales. For the year
ended June 30, 1999, four oil and gas companies accounted for 30%, 12%, 11%, and
9%, respectively, of the Company's oil and gas sales. For the year ended June
30, 2000, four oil and gas companies accounted for 28%, 16%, 12%, and 10%,
respectively, of the Company's oil and gas sales. The Company does not believe
that the loss of any of these buyers would have a material effect on the
Company's business or results of operations as it believes it could readily
locate other buyers.
F-9
<PAGE> 85
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements, and the reported amounts of revenue and expenses during the
reporting period. Because of the use of estimates inherent in the financial
reporting process, actual results could differ from those estimates.
Comprehensive Income
Comprehensive income is defined as the change in equity of a business
enterprise during a period from transactions and other events and circumstances
from non-owner sources. For the years ended June 30, 1998, 1999, and 2000, there
were no differences between the Company's net losses and total comprehensive
income.
Derivatives
The Company utilizes certain derivative financial instruments to hedge
future oil and gas prices and interest rate risk (see Note 4). Gains and losses
arising from the use of the instruments are deferred until realized. Gains and
losses from ongoing settlements of hedges of oil and gas prices are reported as
oil and gas sales. Gains and losses from ongoing settlements of interest rate
hedges are reported in interest expense.
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities, as amended, which will be adopted by the Company
effective July 1, 2000. The Statement will require the Company to recognize all
derivatives on the balance sheet at fair value. Derivatives that are not hedges
must be adjusted to fair value through income. If the derivative is a hedge,
depending on the nature of the hedge, changes in the fair value of derivatives
will either be offset against the change in fair value of the hedged assets,
liabilities, or firm commitments through earnings or recognized in other
comprehensive income until the hedged item is recognized in earnings. The
ineffective portion of a derivative's change in fair value will be immediately
recognized in earnings. Based on the Company's derivative positions at June 30,
2000, the Company estimates that, upon adoption, it will report a gain from the
cumulative effect of adoption of approximately $413,000, and a reduction in
other comprehensive income of $5,907,000.
2. ACQUISITIONS
On April 20, 1998, the Company acquired certain nonoperated net profits
interests and royalty interests (collectively, the Morgan Properties) for net
cash consideration of approximately $137.9 million from pension funds managed by
J.P. Morgan Investments (the Morgan Property Acquisition). The Morgan Property
Acquisition was financed with borrowings under the Company's previous credit
agreement and two subordinated bridge credit facilities (see Note 3). The
results of operations of the Morgan Properties have been included in the
consolidated financial statements from the date of acquisition.
The Company's interest in the Morgan Properties primarily takes the form of
nonoperated net profits overriding royalty interests, whereby the Company is
entitled to a percentage of the net profits from the operations of the
properties. The oil and gas properties burdened by the Morgan Properties are
primarily located in East Texas, South Texas, and the mid-continent region of
the United States.
F-10
<PAGE> 86
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Presented below are the oil and gas sales and associated production
expenses associated with the Morgan Properties, which are presented in the
accompanying consolidated statements of operations for the years ended June 30,
1998, 1999 and 2000, respectively, as net profits and royalty interests
revenues.
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
--------------------------------------
1998 1999 2000
---------- ----------- -----------
<S> <C> <C> <C>
Oil and gas sales.............................. $6,219,000 $29,071,000 $28,715,000
Production expenses............................ 1,787,000 5,931,000 5,725,000
---------- ----------- -----------
Net profits and royalty interests.............. $4,432,000 $23,140,000 $22,990,000
========== =========== ===========
</TABLE>
3. CURRENT AND LONG-TERM DEBT
A summary of current and long-term debt follows:
<TABLE>
<CAPTION>
JUNE 30,
---------------------------
1999 2000
------------ ------------
<S> <C> <C>
12 1/2% Senior Notes, due July 2008...................... $125,000,000 $125,000,000
12% unsecured DEM bonds, due July 2000................... 852,000 584,000
Revolving credit agreement............................... 8,000,000 18,500,000
Capital lease obligations................................ 42,000 --
------------ ------------
133,894,000 144,084,000
Less current portion of debt and capitalized lease
obligation............................................. 42,000 584,000
------------ ------------
Total long-term obligations.................... $133,852,000 $143,500,000
============ ============
</TABLE>
On April 17, 1998, the Company entered into an amended and restated credit
agreement with Bank of Montreal and certain affiliates of JEDI. During October
1999, the Company entered into an amended and restated revolving credit
agreement (the Credit Agreement) with new lenders, replacing the existing lender
group. The Credit Agreement allows the Company to borrow up to $30 million
(subject to borrowing base limitations). Borrowings under the Credit Agreement
are secured by a first lien on the Company's oil and natural gas properties.
Borrowings under the Credit Agreement bear interest at prime plus 2% on
borrowings under $25 million and prime plus 4.5%, if borrowings exceed $25
million. Borrowings under the Credit Agreement totaled $18.6 million at June 30,
2000. The interest rate at June 30, 2000, was 11.5%. The loan under the Credit
Agreement expires on October 22, 2001. The Company is subject to certain
affirmative and negative financial and operating covenants under the Credit
Agreement, including maintaining a minimum interest coverage ratio of 1.0X,
based on the last twelve-month operating results. At June 30, 2000, the Company
was in compliance with these covenants.
Letters of credit up to a maximum of $7.5 million may be issued on behalf
of the Company under the Credit Agreement, which bear interest at 3%. Any
outstanding letters of credit reduce the Company's ability to borrow under the
Credit Agreement. At June 30, 2000, the Company had a letter of credit
outstanding in the amount of $6.2 million to an affiliate of Enron to secure a
swap exposure (see Note 4).
As of June 30, 1999, $8,000,000 was outstanding under the Company's
previous credit agreement. In connection with entering into the Credit
Agreement, the Company retired borrowings under its previous credit agreement,
terminating the arrangement. As a result, the Company recorded an extraordinary
loss of $1,130,000 relating to the unamortized deferred costs of the previous
agreement.
On July 8, 1998, the Company completed a private placement of $125,000,000
principal amount of 12 1/2% Senior Notes (the Notes) due July 1, 2008. Interest
on the Notes is payable semiannually on January 1 and July 1 of each year,
commencing January 1, 1999, at the rate of 12 1/2% per annum. The
F-11
<PAGE> 87
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Notes are senior unsecured obligations of the Company and rank pari passu with
any existing and future unsubordinated indebtedness of the Company. The Notes
rank senior to all unsecured subordinated indebtedness of the Company. The Notes
contain customary covenants that limit the Company's ability to incur additional
debt, pay dividends, and sell assets of the Company. Substantially all of the
proceeds from the issuance of the Notes were used to retire indebtedness
incurred in connection with the acquisition of the Morgan Properties.
Beginning in July 1995, the Company initiated private debt offerings
whereby it could issue up to a maximum of 5,000,000 Deutschmark (DEM)
denominated 12% notes due on July 15, 2000, of which DEM 1,600,000 and DEM
1,200,000 were outstanding at June 30, 1999 and 2000, respectively. On July 15,
2000, the Company retired all remaining outstanding notes for approximately
$584,000.
During the years ended June 30, 1998, 1999, and 2000, the Company made cash
payments of interest totaling approximately $3,946,000, $9,105,000, and
$16,944,000, respectively.
4. HEDGING ACTIVITIES
The Company uses swaps, floors, and collars to hedge oil and natural gas
prices. Swaps are settled monthly based on differences between the prices
specified in the instruments and the settlement prices of futures contracts
quoted on the New York Mercantile Exchange (NYMEX). Generally, when the
applicable settlement price is less than the price specified in the contract,
the Company receives a settlement from the counterparty based on the difference
multiplied by the volume hedged. Similarly, when the applicable settlement price
exceeds the price specified in the contract, the Company pays the counterparty
based on the difference. The Company generally receives a settlement from the
counterparty for floors when the applicable settlement price is less than the
price specified in the contract, which is based on the difference multiplied by
the volumes hedged. For collars, generally the Company receives a settlement
from the counterparty when the settlement price is below the floor and pays a
settlement to the counterparty when the settlement price exceeds the cap. No
settlement occurs when the settlement price falls between the floor and cap.
The Company had a collar with an affiliate of JEDI to hedge 50,000 MMBtu of
natural gas production and 10,000 barrels of oil production monthly. The
agreements, effective September 1, 1997, and terminating August 31, 1998, called
for a natural gas and oil ceiling and floor price of $2.66 and $1.90 per MMBtu
and $20.40 and $18.00 per barrel, respectively. During the years ended June 30,
1998 and 1999, the Company recognized net hedging gains of approximately
$120,000 and $85,000, respectively, relating to these agreements, which are
included in oil and gas sales.
The Company has implemented a comprehensive hedging strategy for its
natural gas production over the next few years. The table below sets out volumes
of natural gas hedged with a floor price of $1.90 per MMBtu with Enron, an
affiliate of JEDI, which received a fee of $478,000 during the year ended June
30, 1998, for entering into this agreement. The volumes presented in this table
are divided equally over the months during the period.
<TABLE>
<CAPTION>
VOLUME
PERIOD BEGINNING PERIOD ENDING (MMBtu)
---------------- ------------- ---------
<S> <C> <C>
May 1, 1998.......................................... December 31, 1998 885,000
January 1, 1999...................................... December 31, 1999 1,080,000
January 1, 2000...................................... December 31, 2000 880,000
January 1, 2001...................................... December 31, 2001 740,000
January 1, 2002...................................... December 31, 2002 640,000
January 1, 2003...................................... December 31, 2003 560,000
</TABLE>
F-12
<PAGE> 88
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The table below sets out volume of natural gas hedged with a swap at $2.40
per MMBtu with Enron. The volumes presented in this table are divided equally
over the months during the period.
<TABLE>
<CAPTION>
VOLUME
PERIOD BEGINNING PERIOD ENDING (MMBtu)
---------------- ------------- ---------
<S> <C> <C>
May 1, 1998.......................................... December 31, 1998 2,210,000
January 1, 1999...................................... December 31, 1999 2,710,000
January 1, 2000...................................... December 31, 2000 2,200,000
January 1, 2001...................................... December 31, 2001 1,850,000
January 1, 2002...................................... December 31, 2002 1,600,000
January 1, 2003...................................... December 31, 2003 1,400,000
</TABLE>
Effective May 1, 1998 through October 31, 1999, the Company had a collar
with Bank of Montreal involving the hedging of a portion of future natural gas
production involving floor and ceiling prices as set out in the table below. The
volumes presented in this table are divided equally over the months during the
period.
<TABLE>
<CAPTION>
VOLUME FLOOR CEILING
PERIOD BEGINNING PERIOD ENDING (MMBTU) PRICE PRICE
---------------- ------------- --------- ----- -------
<S> <C> <C> <C> <C>
May 1, 1998........................... December 31, 1998 3,540,000 $2.00 $2.70
January 1, 1999....................... October 31, 1999 3,608,000 2.00 2.70
</TABLE>
Effective November 1, 1999, the Company unwound the ceiling price
limitation of this collar at a cost of $3.3 million. The table below sets out
the volume of natural gas that remains under contract at a floor price of $2.00
per MMBtu. The volumes presented in this table are divided equally over the
months during the period.
<TABLE>
<CAPTION>
VOLUME
PERIOD BEGINNING PERIOD ENDING (MMBtu)
---------------- ------------- ---------
<S> <C> <C>
November 1, 1999..................................... December 31, 1999 722,000
January 1, 2000...................................... December 31, 2000 3,520,000
January 1, 2001...................................... April 30, 2001 990,000
May 1, 2001.......................................... December 31, 2001 1,980,000
January 1, 2002...................................... April 30, 2002 850,000
May 1, 2002.......................................... December 31, 2002 1,700,000
January 1, 2003...................................... December 31, 2003 2,250,000
</TABLE>
During the years ended June 30, 1998, 1999, and 2000, the Company
recognized hedging gains (losses) of approximately $122,000, $1,690,000, and
$(981,000), respectively, relating to these agreements, which are included in
net profits and royalty interests revenues.
During the year ended June 30, 1999, the Company entered into a swap
agreement with an affiliate of JEDI to hedge 12,000 barrels of oil production
monthly at $17.00 per barrel, for the months of October, November, and December
1998. The Company recognized hedging gains of approximately $147,000 relating to
this agreement which are included in net profits and royalty interests revenues.
During the year ended June 30, 1999, the Company entered into a swap
agreement with an affiliate of JEDI to hedge 10,000 barrels of oil production
monthly at $13.50 per barrel for the six months March through August 1999, and
for 5,000 barrels of oil production monthly at $14.35 per barrel, and for 5,000
barrels of oil production monthly at $14.82 per barrel for the six months April
through September 1999. During the years ended June 30, 1999 and 2000, the
Company recognized hedging losses of approximately
F-13
<PAGE> 89
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
$231,000 and $358,000, respectively, relating to this agreement which are
included in net profits and royalty interests revenues.
The table below sets out the volume of oil hedged with a collar with Enron
involving floor and ceiling prices as set out in the table below. The volumes
presented in this table are divided equally over the months during the period.
<TABLE>
<CAPTION>
VOLUME FLOOR CEILING
PERIOD BEGINNING PERIOD ENDING (MMBtu) PRICE PRICE
---------------- ------------- ------- ------ -------
<S> <C> <C> <C> <C>
December 1, 1999..................... March 31, 2000 40,000 $22.90 $25.77
April 1, 2000........................ June 30, 2000 15,000 $23.00 $28.16
July 1, 2000......................... December 31, 2000 30,000 $22.00 $28.63
</TABLE>
During the year ended June 30, 2000, the Company recognized hedging losses
of approximately $112,000 relating to this contract.
The Company entered into a forward LIBOR interest rate swap effective for
the period June 30, 1998 through June 29, 2009, at a rate of 6.3% on $125
million, which could be unwound at any time at the option of the Company. On
July 9, 1998, as a result of the retirement of the Bridge Facilities and
borrowings under the Credit Agreement, the Company terminated the agreement at a
cost of $3,549,000. The cost of termination has been reflected as an
extraordinary loss in the accompanying consolidated statement of operations for
the year ended June 30, 1999.
5. STOCKHOLDERS' EQUITY
General
The Company's Certificate of Incorporation authorizes issuance of: (i)
50,000,000 shares of preferred stock of the Company, par value $.01 per share
(the Preferred Stock), of which 9,600,000 shares have been designated as Series
A Preferred Stock, 9,600,000 shares have been designated as Series B Preferred
Stock; and (ii) 100,000,000 shares of Common Stock. During the year ended June
30, 1998, 10,400 shares of Preferred Stock were designated and issued as Series
C Preferred Stock.
Any authorized but unissued or unreserved Common Stock and undesignated
Preferred Stock is available for issuance at any time, on such terms and for
such purposes as the Board of Directors may deem advisable in the future without
further action by stockholders of the Company, except as may be required by law
or the Series A or Series C Certificate of Designation. The Board of Directors
of the Company has the authority to fix the rights, powers, designations, and
preferences of the undesignated Preferred Stock and to provide for one or more
series of undesignated Preferred Stock. The authority will include, but will not
be limited to: determination of the number of shares to be included in the
series; dividend rates and rights; voting rights, if any; conversion privileges
and terms; redemption conditions; redemption values; sinking funds; and rights
upon involuntary or voluntary liquidation.
Capital Stock Purchase Agreements
In March 1997, the Company entered into a Securities Purchase Agreement
(the JEDI Purchase Agreement) with JEDI and a Securities Purchase Agreement (the
Forseti Purchase Agreement) with Forseti Investments Ltd. (Forseti).
In May 1997, pursuant to the JEDI Purchase Agreement, JEDI acquired
9,600,000 shares of Series A Participating Convertible Preferred Stock, par
value $0.01 per share, of the Company (the Series A Preferred Stock), certain
warrants to purchase Common Stock, and nondilution rights as in regard to future
stock issuances. The aggregate consideration received by the Company consisted
of $5,000,000 ($0.521 per share).
F-14
<PAGE> 90
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In connection with the issuance of the Series A Preferred Stock, the
Company granted JEDI certain maintenance rights and certain demand and piggyback
registration rights with respect to the shares of Common Stock issuable upon
conversion of the Series A Preferred Stock.
Pursuant to the terms of the Series A Preferred Stock, JEDI may designate a
number of directors to the Company's Board of Directors, such that the
percentage of the number of directors that JEDI may designate approximates the
percentage voting power JEDI has with respect to the Company's Common Stock. In
addition, upon certain events of default (as defined in the Series A Certificate
of Designation), JEDI will have the right to elect a majority of the directors
of the Company and an option to sell the Series A Preferred Stock to the
Company.
In May 1997, pursuant to the Forseti Purchase Agreement, the Company
repurchased 9,600,000 shares of Common Stock owned by Forseti in exchange for
(i) $5,000,000 ($0.521 per share) cash, (ii) the issuance by the Company of
Class A Common Stock Purchase Warrants to purchase 1,000,000 shares of Common
Stock at an initial exercise price of $2.50 per share (the Class A Warrants) and
Class B Common Stock Purchase Warrants to purchase 2,000,000 shares of Common
Stock at an initial exercise price of $2.50 per share (the Class B Warrants, and
together with the Class A Warrants, the Forseti Warrants), and (iii) certain
contingent payments. Forseti had the option of either selling or exercising the
Forseti Warrants or receiving the contingent payments. During the year ended
June 30, 1998, Forseti elected to sell the warrants to a third party and, thus,
lost the rights to receive any contingent payments.
The JEDI Purchase Agreement contains certain positive and negative
covenants. The Company was in compliance with all of the applicable covenants at
June 30, 1999 and 2000.
Pursuant to the JEDI Purchase Agreement, JEDI, EIBOC, and certain officers
of the Company (Management Stockholders) entered into a Stockholders Agreement
whereby JEDI, EIBOC, and the Management Stockholders agreed to certain
restrictions on the transfer of shares of Common Stock held by EIBOC and the
transfer of shares of Common Stock or securities convertible, exercisable, or
exchangeable for shares of Common Stock held by JEDI. The Stockholders Agreement
will terminate on the earlier of (i) the fifth anniversary of the date of the
Stockholders Agreement or (ii) the date on which JEDI and its affiliates
beneficially own in the aggregate less than 10% of the voting power of the
Company's capital stock.
Series A Preferred Stock
The holders of shares of Series A Preferred Stock are generally entitled to
vote (on an as-converted basis) as a single class with the holders of the Common
Stock, together with all other classes and series of stock of the Company that
are entitled to vote as a single class with the Common Stock, on all matters
coming before the Company's stockholders.
For so long as at least 960,000 shares of Series A Preferred Stock are
outstanding, the following matters require the approval of the holders of shares
of Series A Preferred Stock, voting together as a separate class:
(i) The amendment of any provision of the Company's Certificate of
Incorporation or the bylaws
(ii) The creation, authorization, or issuance of, or the increase in
the authorized amount of, any class or series of shares ranking on a parity
with or prior to the Series A Preferred Stock either as to dividends or
upon liquidation, dissolution, or winding up
(iii) The merger or consolidation of the Company with or into any
other corporation or other entity or the sale of all or substantially all
of the Company's assets
F-15
<PAGE> 91
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(iv) The reorganization, recapitalization, or restructuring or similar
transaction that requires the approval of the stockholders of the Company
The holders of shares of Series A Preferred Stock have the right, acting
separately as a class, to elect a number of members to the Company's Board of
Directors. The number shall be a number such that the quotient obtained by
dividing such number by the maximum authorized number of directors is as close
as possible to being equal to the percentage of the outstanding voting power of
the Company entitled to vote generally in the election of directors represented
by the outstanding shares of Series A Preferred Stock at the relevant time.
A holder of shares of Series A Preferred Stock has the right, at the
holder's option, to convert all or a portion of its shares into shares of Common
Stock at any time at an initial rate of one share of Series A Preferred Stock
for one share of Common Stock.
The Series A Certificate of Designation provides for customary adjustments
to the number of shares issuable upon conversion in the event of certain
dividends and distributions to holders of Common Stock, certain
reclassifications of the Common Stock, stock splits, and combinations and
mergers and similar transactions.
The holders of the shares of Series A Preferred Stock are entitled to
receive dividends (other than a dividend or distribution paid in shares of, or
warrants, rights, or options exercisable for or convertible into or exchangeable
for, Common Stock) when and if declared by the Board of Directors on the Common
Stock in an amount equal to the amount each such holder would have received if
such holder's shares of Series A Preferred Stock had been converted into Common
Stock. The holders of Series A Preferred Stock will also have the right to
certain dividends upon and during the continuance of an Event of Default.
Upon the liquidation, dissolution, or winding up of the Company, the
holders of the shares of Series A Preferred Stock, before any distribution to
the holders of Common Stock, are entitled to receive an amount per share equal
to $.521 plus all accrued and unpaid dividends thereon (Liquidation Preference).
The holders of the shares of Series A Preferred Stock will not be entitled to
participate further in the distribution of the assets of the Company.
The Series A Certificate of Designation provides that an Event of Default
will be deemed to have occurred if the Company fails to comply with any of its
covenants in the JEDI Purchase Agreement, provided that the Company will have a
30-day cure period with respect to the non-compliance with certain covenants.
Upon the occurrence but only during the continuance of an Event of Default,
the holders of Series A Preferred Stock are entitled to receive, in addition to
other dividends payable to holders of Series A Preferred Stock, when and if
declared by the Board of Directors, cumulative preferential cash dividends
accruing from the date of the Event of Default in an amount per share per annum
equal to 6% of the Liquidation Preference in effect at the time of accrual of
such dividends, payable quarterly in arrears on or before the 15th day after the
last day of each calendar quarter during which such dividends are payable.
Unless full cumulative dividends accrued on shares of Series A Preferred Stock
have been or contemporaneously are declared and paid, no dividend may be
declared or paid or set aside for payment on the Common Stock or any other
junior securities (other than a dividend or distribution paid in shares of, or
warrants, rights, or options exercisable for or convertible into or exchangeable
for, Common Stock or any other junior securities), nor shall any Common Stock
nor any other junior securities be redeemed, purchased, or otherwise acquired
for any consideration, nor may any monies be paid to or made available for a
sinking fund for the redemption of any shares of any such securities.
Upon the occurrence and during the continuance of an Event of Default
resulting from the failure to comply with certain covenants, the holders of
shares of Series A Preferred Stock have the right, acting
F-16
<PAGE> 92
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
separately as a class, to elect a number of persons to the Board of Directors of
the Company that, along with any members of the Board of Directors who are
serving at the time of such action, will constitute a majority of the Board of
Directors.
Upon the occurrence of an Event of Default resulting from the failure to
comply with certain covenants, each holder of shares of Series A Preferred Stock
has the right, by written notice to the Company, to require the Company to
repurchase, out of funds legally available therefor, such holder's shares of
Series A Preferred Stock for an amount in cash equal to the Liquidation
Preference in effect at the time of the Event of Default.
Concurrently with the transfer of any shares of Series A Preferred Stock to
any person (other than a direct or indirect affiliate of JEDI or other entity
managed by Enron Corp. or any of its affiliates), the shares of Series A
Preferred Stock so transferred will automatically convert into a like number of
shares of Series B Preferred Stock. At June 30, 1998, 1999, and 2000, 9,600,000
shares of Series A Preferred Stock were outstanding.
Series B Preferred Stock
The Series B Certificate of Designation authorizes the issuance of up to
9,600,000 shares of Series B Preferred Stock. The terms of the Series B
Preferred Stock are substantially similar to those of the Series A Preferred
Stock, except that the holders of Series B Preferred Stock will not (i) have
class voting rights except as required under Delaware corporate law, (ii) be
entitled to any remedies upon an event of default, or (iii) be entitled to elect
any directors of the Company, voting separately as a class. At June 30, 1998,
1999 and 2000, no shares of Series B Preferred Stock were outstanding.
Series C Preferred Stock
The holders of shares of Series C Preferred Stock are not entitled to vote
with the holders of the Common Stock except as required by law or as set forth
below. For so long as any shares of Series C Preferred Stock are outstanding,
the following matters will require the approval of the holders of at least
two-thirds of the then outstanding shares of Series C Preferred Stock, voting
together as a separate class:
(i) Alter or change the rights, preferences, or privileges of the
Series C Preferred Stock or any other capital stock of the Company so as to
affect adversely the Series C Preferred Stock
(ii) Create any new class or series of capital stock having a
preference over or ranking pari passu with the Series C Preferred Stock as
to redemption, the payment of dividends or distribution of assets upon a
Liquidation Event (as defined in the Series C Certificate of Designation)
or any other liquidation, dissolution, or winding up of the Company
(iii) Increase the authorized number of shares of Preferred Stock of
the Company
(iv) Re-issue any shares of Series C Preferred Stock which have been
converted in accordance with the terms hereof
(v) Issue any Senior Securities (other than the Company's Series B
Preferred Stock pursuant to the terms of the Company's Series A Preferred
Stock) or Pari Passu Securities (each, as defined in the Series C
Certificate of Designation)
(vi) Declare, pay, or make any provision for any dividend or
distribution with respect to the Common Stock or any other capital stock of
the Company ranking junior to the Series C Preferred Stock as to dividends
or as to the distribution of assets upon liquidation, dissolution, or
winding up of the Company
F-17
<PAGE> 93
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The holders of at least two-thirds of the then outstanding shares of Series
C Preferred Stock can agree to allow the Company to alter or change the rights,
preferences, or privileges of the shares of Series C Preferred Stock. Holders of
the Series C Preferred Stock that did not agree to such alteration or change
shall have the right for a period of thirty days following such change to
convert their Series C Preferred Stock to Common Stock.
A holder of shares of Series C Preferred Stock has the right, at the
holder's option, to convert all or a portion of its shares into shares of Common
Stock at any time. The number of shares of Common Stock into which a share of
Series C Preferred Stock may be converted will be determined as of the
conversion date according to a formula set forth in the Series C Certificate of
Designation. Generally, the conversion rate is equal to the aggregate stated
value of the shares to be converted divided by a floating conversion price that
may not exceed $7.35 per share. On December 24, 2001, all shares of Series C
Preferred Stock that are then outstanding shall be automatically converted into
shares of Common Stock.
The Series C Certificate of Designation provides for customary adjustments
to the number of shares issuable upon conversion in the event of certain
dividends and distributions to holders of Common Stock, certain
reclassifications of the Common Stock, stock splits, combinations and mergers,
and similar transactions and certain changes of control.
The holders of the shares of Series C Preferred Stock are entitled to
receive cumulative dividends, when and if declared by the Board of Directors,
subject to the prior payment of any accumulated and unpaid dividends to holders
of Senior Securities, but before payment of dividends to holders of Junior
Securities (as defined in the Series C Certificate of Designation), on each
share of Series C Preferred Stock in an amount equal to the stated value of such
share multiplied by 5%.
Upon the liquidation, dissolution, or winding up of the Company, the
holders of the shares of Series C Preferred Stock, before any distribution to
the holders of Junior Securities, and after payments to holders of Senior
Securities, will be entitled to receive an amount equal to the stated value of
the Series C Preferred Stock (subject to ratable adjustment in the event of
reclassification of the Series C Preferred Stock or other similar event) plus
any accrued and unpaid dividends thereon.
The Company has the right to redeem all of the outstanding Series C
Preferred Stock under certain conditions. Holders of Series C Preferred Stock
have the right to tender shares for redemption upon the occurrence of certain
events, which are in the control of management. During fiscal year 1999, the
Company repurchased 2,152 shares of Series C Preferred Stock at a cost of
$2,251,000.
During the years ended June 30, 1999 and 2000, 3,550 shares and 2,525
shares, respectively, of Series C Preferred Stock were converted into 1,328,639
shares and 8,217,831 shares, respectively, of Common Stock. Additionally, 77,571
shares and 914,712 shares of Common Stock, representing accrued but unpaid
dividends due to the converting Series C Preferred Stock holders, were issued
upon conversion during fiscal years 1999 and 2000, respectively. At June 30,
1998, 1999, and 2000, 10,400 shares, 4,698 shares, and 2,173 shares of Series C
Preferred Stock were outstanding.
Common Stock
During July 1998, the Company completed the private placement of an
aggregate of 3,428,574 shares of the Company's Common Stock at $7.00 per share
(the July Equity Offerings) which included certain repricing rights (the
Repricing Rights) to acquire additional shares of Common Stock (Repricing Common
Shares) and warrants (the Warrants) to purchase an aggregate of up to 1,085,000
shares of Common Stock (Warrant Common Shares). Additionally, JEDI exercised
warrants to acquire an aggregate of 980,935 shares of Common Stock at $3.33 per
share and nondilution rights to purchase 693,301 shares of the Company's Common
Stock at $2.50 per share and another entity exercised warrants
F-18
<PAGE> 94
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
to acquire an aggregate of 800,000 shares of Common Stock at $2.50 per share
(collectively, the Warrant Exercises).
During November 1998, the Company completed the private placement of an
aggregate of 416,667 shares of the Company's Common Stock at $6.00 per share
(the November Equity Offerings and, collectively with the July Equity Offerings,
the Equity Offerings) which included certain repricing rights (the Repricing
Rights) to acquire additional shares of Common Stock (Repricing Common Shares)
and warrants (the Warrants) to purchase an aggregate of up to 206,340 shares of
Common Stock (Warrant Common Shares).
The Repricing Rights allow the purchasers of the Common Shares under the
Equity Offerings to receive Repricing Common Shares based on the following
formula:
<TABLE>
<C> <S>
(Repricing Price - Market Price)
-------------------------------- X Common Shares
Market Price
</TABLE>
The Repricing Price is a percentage increase in the purchase price paid for
the Common Shares (up to 128% over the following eight months). The Repricing
Rights can only be exercised one time and the Company can repurchase the
Repricing Rights under certain conditions. During the years ended June 30, 1999
and 2000, 1,384,016 shares and 38,113,785 shares, respectively, of Common Stock
were issued upon exercise of Repricing Rights.
Each holder of Repricing Common Shares or Repricing Rights has the right to
require the Company to repurchase all or a portion of such holder's Repricing
Common Shares or Repricing Rights upon the occurrence of a Major Transaction or
a Triggering Event, both of which are under the control of management of the
Company.
The Warrants are exercisable for three years commencing July 8, 1998 and
November 23, 1998, at an exercise price equal to 110% of the Purchase Price. The
Warrants provide for customary adjustments to the exercise price and number of
shares to be issued in the event of certain dividends and distributions to
holders of Common Stock, stock splits, combinations, and mergers. The Warrants
also include customary provisions with respect to, among other things, transfer
of the Warrants, mutilated or lost warrant certificates, and notices to
holder(s) of the Warrants.
Warrants
Certain institutional investors hold warrants to purchase an aggregate of
1,525,153 shares of Common Stock at prices ranging from $6.00 to $8.00 per
share. The warrants held by the institutional investors expire at various times
from December 24, 2000 through November 25, 2001.
F-19
<PAGE> 95
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Stock Options
Employee stock option activity for the years ended June 30, 1998, 1999, and
2000 is as follows:
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
------------------------------------------------------------
1998 1999 2000
------------------ ------------------ ------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE
------- -------- ------- -------- ------- --------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at July 1....... -- $ -- 173,000 $5.25 763,500 $6.87
Granted................... 173,000 5.25 590,500 7.38 -- --
Exercised................. -- -- -- -- -- --
Canceled.................. -- -- -- -- (34,500) 7.38
------- ------- -------
Outstanding at June 30...... 173,000 $5.25 763,500 $6.87 729,000 $6.84
======= ======= =======
Exercisable options
outstanding at June 30.... -- $ -- 96,500 $5.25 496,636 $6.67
======= ======= =======
</TABLE>
The weighted average grant date fair value of stock options granted during
1998 and 1999 were $3.22 and $6.23, respectively. The grant date fair values
were estimated at the date of grant using the Black-Scholes option pricing
model. As of June 30, 2000, the weighted average remaining contractual life of
outstanding stock options was 7.3 years.
Statement of Financial Accounting Standards No. 123, Accounting for
Stock-Based Compensation (SFAS 123), requires the disclosure of pro forma net
income and earnings per share information computed as if the Company had
accounted for its employee stock options under the fair value method set forth
in SFAS 123. The fair value for these options was estimated at the date of grant
using a Black-Scholes option pricing model with the following weighted average
assumptions, respectively: a risk-free interest rate of 5.88% and 6.00% during
1998 and 1999, respectively; a dividend yield of 0%; and a volatility factor of
0.51 and 0.792 during 1998 and 1999, respectively. In addition, the fair value
of these options was estimated based on an expected weighted average life of 7.5
years and 10 years during 1998 and 1999, respectively.
The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions, including the expected stock price
volatility. Because the Company's employee stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimate, in
management's opinion, the existing models do not necessarily provide a reliable
single measure of the fair value of its employee stock options.
For purposes of pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options' vesting period. The Company's
pro forma information follows:
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
------------------------------------------
1998 1999 2000
------------ ------------ ------------
<S> <C> <C> <C>
Pro forma net loss......................... $(32,928,000) $(48,917,000) $(10,106,000)
Loss per common share...................... $ (1.45) $ (1.56) $ (0.23)
</TABLE>
F-20
<PAGE> 96
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
6. FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company defines the fair value of a financial instrument as the amount
at which the instrument could be exchanged in a current transaction between
willing parties. The carrying value of accounts receivable, accounts payable,
and accrued liabilities approximates fair value because of the short maturity of
those instruments. The estimated fair value of the Company's long-term
obligations is estimated based on the current rates offered to the Company for
similar maturities. At June 30, 1999 and 2000, the carrying value of long-term
obligations exceeded their fair values by approximately $41,250,000 and
$76,875,000, respectively. At June 30, 1998, the carrying value of long-term
obligations approximates their fair values. At June 30, 2000, the fair value of
the Company's hedging contracts, measured as the estimated cost to the Company
to terminate the arrangements, was approximately $5,256,000.
7. RELATED PARTY TRANSACTIONS
The Company has entered into various hedging arrangements with affiliates
of Enron (see Note 4).
The Company had entered into a revolving credit facility with ECT, an
affiliate of Enron. During the year ended June 30, 1998, commitment fees of
approximately $200,000 and interest totaling approximately $9,000 was paid to
ECT in connection with this facility. This agreement was terminated in October
1999.
Enron, through its affiliates, participated in indebtedness incurred in
connection with the acquisition of the Morgan Properties. During the years ended
June 30, 1999 and 2000, Enron received interest payments of approximately
$365,000 and $88,000, respectively, from the Company relating to such
participation.
The Company paid Enron approximately $100,000 during both of the years
ended June 30, 1999 and 2000, under the terms of an agreement which allows the
Company to consult, among other things, with Enron's engineering staff.
8. INCOME TAXES
The Company's effective tax rate differs from the U.S. statutory rate for
each of the years ended June 30, 1998, 1999, and 2000, due to losses for which
no deferred tax benefit was recognized. The tax effects of the primary temporary
differences giving rise to the deferred federal income tax assets and
liabilities as determined under Statement of Financial Accounting Standards No.
109, Accounting for Income Taxes, at June 30, 1999 and 2000, follow:
<TABLE>
<CAPTION>
1999 2000
------------ ------------
<S> <C> <C>
Deferred income tax assets (liabilities):
Reverse acquisition costs.............................. $ 43,000 $ 21,000
Net operating loss carryforwards....................... 10,965,000 19,744,000
Statutory depletion carryforward....................... 126,000 126,000
Oil and gas properties, principally due to differences
in depreciation and amortization.................... 16,902,000 11,109,000
Other.................................................. (146,000) (221,000)
------------ ------------
27,890,000 30,779,000
Less valuation allowance................................. (27,890,000) (30,779,000)
------------ ------------
Net deferred income tax asset............................ $ -- $ --
============ ============
</TABLE>
The net changes in the total valuation allowance for the years ended June
30, 1999 and 2000, were increases of $15,677,000 and $2,889,000, respectively.
The Company's net operating loss carryforwards begin expiring in 2010.
F-21
<PAGE> 97
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. COMMITMENTS AND CONTINGENCIES
The Company is involved in certain disputes and other matters arising in
the normal course of business. Although the ultimate resolution of these matters
cannot be reasonably estimated at this time, management does not believe that
they will have a material adverse effect on the financial condition or results
of operations of the Company.
10. OIL AND GAS PRODUCING ACTIVITIES
The following tables set forth supplementary disclosures for oil and gas
producing activities in accordance with Statement of Financial Accounting
Standards No. 69.
Results of Operations for Producing Activities
The following sets forth certain information with respect to results of
operations from oil and gas producing activities for the years ended June 30,
1998, 1999, and 2000:
<TABLE>
<CAPTION>
1998 1999 2000
------------ ------------ ------------
<S> <C> <C> <C>
Oil and gas sales.......................... $ 6,446,000 $ 4,591,000 $ 3,967,000
Net profits and royalty interests
revenues................................. 4,432,000 23,140,000 22,990,000
Production expenses........................ (4,547,000) (3,196,000) (1,372,000)
Depreciation and amortization.............. (4,736,000) (11,803,000) (8,452,000)
Write-down of oil and gas properties....... (28,166,000) (35,033,000) --
------------ ------------ ------------
Results of operations (excludes corporate
overhead and interest expense)........... $(26,571,000) $(22,301,000) $ 17,133,000
============ ============ ============
</TABLE>
Depreciation and amortization of oil and gas properties was $0.89, $0.74,
and $0.71 per Mcfe produced for the years ended June 30, 1998, 1999, and 2000,
respectively.
The following table summarizes capitalized costs relating to oil and gas
producing activities and related amounts of accumulated depreciation and
amortization at June 30, 1999 and 2000:
<TABLE>
<CAPTION>
1999 2000
------------ ------------
<S> <C> <C>
Oil and gas properties -- proved......................... $178,421,000 $182,280,000
Accumulated depreciation and amortization................ (81,469,000) (89,921,000)
------------ ------------
Net capitalized costs.................................... $ 96,952,000 $ 92,359,000
============ ============
</TABLE>
Costs Incurred
The following sets forth certain information with respect to costs
incurred, whether expensed or capitalized, in oil and gas activities for the
years ended June 30, 1998, 1999, and 2000:
<TABLE>
<CAPTION>
1998 1999 2000
------------ ----------- ------------
<S> <C> <C> <C>
Property acquisition costs.................. $153,196,000 $ 580,000 $ --
============ =========== ============
Development costs........................... $ 6,031,000 $10,340,000 $ 6,198,000
============ =========== ============
</TABLE>
11. SUPPLEMENTARY OIL AND GAS DATA (UNAUDITED)
Reserve Quantity Information
The following table presents the Company's estimate of its proved oil and
gas reserves, all of which are located in the United States. The Company
emphasizes that reserve estimates are inherently imprecise
F-22
<PAGE> 98
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
and that estimates of new discoveries are more imprecise than those of producing
oil and gas properties. Accordingly, the estimates are expected to change as
future information becomes available. The estimates at June 30, 1997, 1998, and
1999, have been prepared by independent petroleum reservoir engineers. The
estimate at June 30, 2000, has been prepared by the Company's petroleum
engineers.
<TABLE>
<CAPTION>
OIL (Bbls) GAS (Mcf)
---------- -----------
<S> <C> <C>
Proved reserves:
Balance at June 30, 1997.................................. 6,709,000 20,973,000
Purchases of minerals in place............................ 4,301,000 158,528,000
Revisions of previous estimates and other................. (2,736,000) (38,000)
Production................................................ (325,000) (3,368,000)
---------- -----------
Balance at June 30, 1998.................................. 7,949,000 176,095,000
Sales of minerals in place................................ (2,735,000) (18,243,000)
Revisions of previous estimates and other................. (90,000) (7,329,000)
Production................................................ (500,000) (12,962,000)
---------- -----------
Balance at June 30, 1999.................................. 4,624,000 137,561,000
Sales of minerals in place................................ (1,000) (7,752,000)
Revisions of previous estimates and other................. (2,389,000) 13,489,000
Production................................................ (224,000) (10,618,000)
---------- -----------
Balance at June 30, 2000.................................. 2,010,000 132,680,000
========== ===========
Proved developed reserves:
Balance at June 30, 1997.................................. 2,188,000 12,412,000
========== ===========
Balance at June 30, 1998.................................. 5,298,000 120,998,000
========== ===========
Balance at June 30, 1999.................................. 2,138,000 94,614,000
========== ===========
Balance at June 30, 2000.................................. 1,868,000 86,348,000
========== ===========
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves
The Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves (Standardized Measure) is a disclosure requirement
under Statement of Financial Accounting Standards No. 69.
The Standardized Measure of discounted future net cash flows does not
purport to be, nor should it be interpreted to present, the fair value of the
Company's oil and gas reserves. An estimate of fair value would also take into
account, among other things, the recovery of reserves not presently classified
as proved, the value of unproved properties, and consideration of expected
future economic and operating conditions.
Under the Standardized Measure, future cash flows are estimated by applying
year-end prices, adjusted for fixed and determinable escalations, to the
estimated future production of year-end proved reserves. Future cash inflows are
reduced by estimated future production and development costs based on period-end
costs to determine pretax cash inflows. Future income taxes are computed by
applying the statutory tax rate to the excess of pretax cash inflows over the
Company's tax basis in the associated properties. Tax credits, net operating
loss carryforwards, and permanent differences are also considered in the future
tax calculation. Future net cash inflows after income taxes are discounted using
a 10% annual discount rate to arrive at the Standardized Measure.
F-23
<PAGE> 99
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Standardized Measure of discounted future net cash flows relating to
proved oil and gas reserves as of June 30, 1999 and 2000, are as follows:
<TABLE>
<CAPTION>
1999 2000
------------- -------------
<S> <C> <C>
Future cash inflows.................................... $ 415,013,000 $ 653,511,000
Future costs and expenses:
Production expenses.................................. (124,209,000) (171,740,000)
Development costs.................................... (18,811,000) (14,735,000)
Future income taxes.................................... (33,933,000) (95,642,000)
------------- -------------
Future net cash flows.................................. 238,060,000 371,394,000
10% annual discount for estimated timing of cash
flows................................................ (123,642,000) (198,539,000)
------------- -------------
Standardized measure of discounted future net cash
flows................................................ $ 114,418,000 $ 172,855,000
============= =============
</TABLE>
The weighted average price of oil and gas at June 30, 1999 and 2000, used
in calculating the Standardized Measure were $17.11 and $31.42 per barrel,
respectively, and $2.44 and $4.45 per MCF, respectively.
Changes in the Standardized Measure of discounted future net cash flows
relating to proved oil and gas reserves for the years ended June 30, 1998, 1999,
and 2000, are as follows:
<TABLE>
<CAPTION>
1998 1999 2000
------------ ------------ ------------
<S> <C> <C> <C>
Beginning balance.......................... $ 30,146,000 $142,315,000 $114,418,000
Purchases of minerals in place............. 139,292,000 -- --
Sales of minerals in place................. -- (16,035,000) (12,953,000)
Developed during the period................ 6,031,000 10,340,000 6,198,000
Net change in prices and costs............. (15,593,000) 2,187,000 126,368,000
Revisions of previous estimates............ (13,784,000) (22,121,000) 13,225,000
Accretion of discount...................... 3,015,000 14,232,000 11,442,000
Net change in income taxes................. (461,000) 6,452,000 (61,709,000)
Sales of oil and gas produced, net of
production expenses...................... (6,331,000) (22,952,000) (24,134,000)
------------ ------------ ------------
Balance at June 30......................... $142,315,000 $114,418,000 $172,855,000
============ ============ ============
</TABLE>
The future cash flows shown above include amounts attributable to proved
undeveloped reserves requiring approximately $12,930,000 of future development
costs. If these reserves are not developed, the future net cash flows shown
above would be significantly reduced.
Estimates of economically recoverable gas and oil reserves and of future
net revenues are based upon a number of variable factors and assumptions, all of
which are to some degree speculative and may vary considerably from actual
results. Therefore, actual production, revenues, taxes, development, and
operating expenditures may not occur as estimated. The reserve data are
estimates only, are subject to many uncertainties, and are based on data gained
from production histories and on assumptions as to geologic formations and other
matters. Actual quantities of gas and oil may differ materially from the amounts
estimated.
F-24
<PAGE> 100
DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
12. QUARTERLY FINANCIAL RESULTS (UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
-------------------------------------------------------
SEPTEMBER 30 DECEMBER 31 MARCH 31 JUNE 30
------------ ------------ ----------- -----------
<S> <C> <C> <C> <C>
YEAR ENDED JUNE 30, 1999
Total revenues..................... $ 7,353,000 $ 6,984,000 $ 6,734,000 $ 6,986,000
Write-downs of oil and gas
properties....................... -- $(35,033,000) -- --
Operating income................... $ 6,188,000 $ 6,295,000 $ 6,015,000 $ 6,363,000
Loss before extraordinary item..... $(2,104,000) $(37,678,000) $(1,977,000) $(2,183,000)
Extraordinary loss................. $(3,549,000) -- -- --
Net loss........................... $(5,653,000) $(37,678,000) $(1,977,000) $(2,183,000)
Loss before extraordinary item per
common share..................... $ (0.07) $ (1.25) $ (0.06) $ (0.07)
Net loss per common share.......... $ (0.19) $ (1.25) $ (0.06) $ (0.07)
</TABLE>
<TABLE>
<CAPTION>
THREE MONTHS ENDED
-------------------------------------------------------
SEPTEMBER 30 DECEMBER 31 MARCH 31 JUNE 30
------------ ------------ ----------- -----------
<S> <C> <C> <C> <C>
YEAR ENDED JUNE 30, 2000
Total revenues..................... $ 5,543,000 $ 6,653,000 $ 6,673,000 $ 8,231,000
Operating income................... $ 5,385,000 $ 6,533,000 $ 6,101,000 $ 7,709,000
Income (loss) before extraordinary
item............................. $(2,242,000) $ (4,258,000) $(1,618,000) $ 190,000
Extraordinary loss................. $ -- $ (1,130,000) $ -- $ --
Net income (loss).................. $(2,242,000) $ (5,388,000) $(1,618,000) $ 190,000
Income (loss) before extraordinary
item per common share............ $ (0.07) $ (0.12) $ (0.04) $ 0.00
Net income (loss) per common
share............................ $ (0.07) $ (0.15) $ (0.04) $ 0.00
</TABLE>
F-25
<PAGE> 101
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NO DEALER, SALESPERSON OR OTHER PERSON IS AUTHORIZED TO GIVE ANY
INFORMATION OR TO REPRESENT ANYTHING NOT CONTAINED IN THIS PROSPECTUS. YOU MUST
NOT RELY ON ANY UNAUTHORIZED INFORMATION OR REPRESENTATIONS. THIS PROSPECTUS IS
AN OFFER TO SELL ONLY THE SHARES OFFERED HEREBY, BUT ONLY UNDER CIRCUMSTANCES
AND IN JURISDICTIONS WHERE IT IS LAWFUL TO DO SO. THE INFORMATION CONTAINED IN
THIS PROSPECTUS IS CURRENT ONLY AS OF ITS DATE.
TABLE OF CONTENTS
<TABLE>
<S> <C>
Summary................................. 3
Risk Factors............................ 10
Forward-Looking Statements.............. 18
The Recapitalization.................... 19
Price Range of Common Stock; Dividend
History............................... 22
Use of Proceeds......................... 23
Capitalization.......................... 24
Dilution................................ 25
Selected Consolidated Financial
Data.................................. 26
Unaudited Pro Forma Condensed
Consolidated Financial Statements..... 28
Management's Discussion and Analysis of
Financial Condition and Results of
Operations............................ 33
Business................................ 45
Management.............................. 61
Security Ownership of Certain Beneficial
Owners and Management................. 65
Description of Capital Stock............ 67
Shares Eligible for Future Sale......... 68
Underwriting............................ 69
Legal Matters........................... 71
Engineers............................... 71
Experts................................. 71
Where You Can Find More Information..... 71
Incorporation by Reference.............. 72
Glossary................................ 73
Index to Consolidated Financial
Statements............................ F-1
</TABLE>
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10,000,000 SHARES
COMMON STOCK
[DEVX ENERGY LOGO]
---------------------
PROSPECTUS
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FRIEDMAN BILLINGS RAMSEY
STIFEL, NICOLAUS &
COMPANY, INCORPORATED
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