1
U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
----------
FORM 10-Q
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[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2001
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ___ TO ___
Commission File No. 0-21179
DEVX ENERGY, INC.
DEVX ENERGY, INC.
DEVX OPERATING COMPANY
CORRIDA RESOURCES, INC.
(Exact name of registrants as specified in their charter)
DELAWARE 75-2615565
NEVADA 75-2564071
NEVADA 75-2593510
NEVADA 75-2691594
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification Nos.)
13760 NOEL ROAD, SUITE 1030
L.B. #44, DALLAS, TEXAS 75240-7336
(Address of principal executive offices)(Zip code)
(972) 233-9906
(Registrants' telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. YES [X] NO [ ]
APPLICABLE ONLY TO CORPORATE ISSUERS: Indicate the number of shares outstanding
of each of the issuer's classes of common stock, as of August 1, 2001:
12,748,612
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PART I
FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
DEVX ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(UNAUDITED)
<Table>
<Caption>
JUNE 30, DECEMBER 31,
2001 2000
------------- -------------
ASSETS
Current assets:
Cash $ 11,232,000 $ 10,985,000
Other current assets 9,736,000 10,740,000
------------- -------------
Total current assets 20,968,000 21,725,000
Net property and equipment 101,892,000 97,091,000
Other assets 4,629,000 4,174,000
------------- -------------
$ 127,489,000 $ 122,990,000
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and other $ 5,125,000 $ 7,507,000
Derivatives -- 1,507,000
------------- -------------
Total current liabilities 5,125,000 9,014,000
Long-term obligations, net of current portion 50,000,000 50,000,000
Derivatives 4,184,000 12,246,000
Commitments -- --
Stockholders' equity:
Common stock, $0.234 par value, authorized 100,000,000 shares:
Issued and outstanding 12,748,612 shares at
June 30, 2001 and December 31, 2000 2,983,000 2,983,000
Additional paid-in capital 60,159,000 60,159,000
Retained earnings 9,222,000 834,000
Accumulated other comprehensive loss (4,184,000) (12,246,000)
------------- -------------
Total stockholders' equity 68,180,000 51,730,000
------------- -------------
Total liabilities and stockholders' equity $ 127,489,000 $ 122,990,000
============= =============
</Table>
See accompanying notes to unaudited consolidated condensed financial statements.
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DEVX ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
(UNAUDITED)
<Table>
<Caption>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30 JUNE 30
----------------------------- -----------------------------
2001 2000 2001 2000
------------ ------------ ------------ ------------
Revenues:
Oil and gas sales $ 1,097,000 $ 1,277,000 $ 2,188,000 $ 2,184,000
Net profits and royalty interests 7,980,000 6,960,000 19,101,000 12,661,000
Interest and other income (expense) 137,000 (6,000) 259,000 59,000
------------ ------------ ------------ ------------
Total revenues 9,214,000 8,231,000 21,548,000 14,904,000
------------ ------------ ------------ ------------
Expenses:
Oil and gas production expenses 301,000 522,000 998,000 1,094,000
Depreciation, depletion and amortization 2,376,000 2,065,000 4,663,000 4,280,000
General and administrative 1,198,000 804,000 2,088,000 1,551,000
Interest and financing expense 1,812,000 4,650,000 3,682,000 9,407,000
------------ ------------ ------------ ------------
Total expenses 5,687,000 8,041,000 11,431,000 16,332,000
Change in fair value of derivatives 1,736,000 -- 3,195,000 --
------------ ------------ ------------ ------------
Income (loss) before income taxes 5,263,000 190,000 13,312,000 (1,428,000)
Income taxes (1,871,000) -- (4,926,000) --
------------ ------------ ------------ ------------
Net income (loss) $ 3,392,000 $ 190,000 $ 8,386,000 $ (1,428,000)
============ ============ ============ ============
Earnings (loss) per common share:
Basic $ 0.27 $ 0.50 $ 0.66 $ (4.25)
============ ============ ============ ============
Diluted $ 0.26 $ 0.15 $ 0.65 $ (4.25)
============ ============ ============ ============
Weighted average shares outstanding:
Basic 12,748,612 382,397 12,748,612 335,937
============ ============ ============ ============
Diluted 12,842,259 1,286,239 12,833,937 335,937
============ ============ ============ ============
</Table>
See accompanying notes to unaudited consolidated condensed financial statements.
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DEVX ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<Table>
<Caption>
SIX MONTHS ENDED
JUNE 30
-----------------------------
2001 2000
------------ ------------
Cash flows from operating activities:
Net income (loss) $ 8,386,000 $ (1,428,000)
Depreciation, depletion and amortization 5,061,000 5,060,000
Change in fair market value of derivatives (3,195,000) --
Net change in operating assets and liabilities (541,000) (3,491,000)
------------ ------------
Net cash provided by operating activities 9,711,000 141,000
------------ ------------
Cash flows used in investing activities:
Additions to property and equipment (9,737,000) (4,288,000)
Proceeds from sale of oil & gas properties 273,000 3,551,000
------------ ------------
Net cash used in investing activities (9,464,000) (737,000)
------------ ------------
Cash flows from financing activities:
Proceeds from long-term debt -- 9,394,000
Payments on long-term obligations -- (293,000)
------------ ------------
Net cash provided by financing activities -- 9,101,000
------------ ------------
Net increase in cash 247,000 8,505,000
Cash at beginning of period 10,985,000 3,376,000
------------ ------------
Cash at end of period $ 11,232,000 $ 11,881,000
============ ============
</Table>
See accompanying notes to unaudited consolidated condensed financial statements.
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DEVX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
JUNE 30, 2001
(UNAUDITED)
1. BASIS OF PRESENTATION
The accompanying consolidated financial statements include the accounts of DevX
Energy, Inc. and its wholly owned subsidiaries (collectively, the "Company")
after elimination of all significant intercompany balances and transactions. The
financial statements have been prepared in conformity with generally accepted
accounting principles which require management to make estimates and assumptions
that affect the amounts reported in the financial statements and accompanying
notes. While management has based its assumptions and estimates on the facts and
circumstances currently known, final amounts may differ from such estimates.
The interim financial statements contained herein are unaudited but, in the
opinion of management, include all adjustments (consisting only of normal
recurring entries) necessary for a fair presentation of the financial position
and results of operations of the Company for the periods presented. The results
of operations for the three months ended June 30, 2001 are not necessarily
indicative of the operating results for the full fiscal year ending December 31,
2001. Moreover, these financial statements do not purport to contain complete
disclosure in conformity with generally accepted accounting principles and
should be read in conjunction with the Company's Annual Report on Form 10-K for
the transition period ended December 31, 2000.
2. DERIVATIVES
The Company utilizes certain derivative financial instruments -- primarily
swaps, floors and collars -- to reduce the risk of adverse changes in future oil
and natural gas prices. Effective July 1, 2000, the Company adopted Statement of
Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities (SFAS No. 133), which requires the Company to recognize
all derivatives on the balance sheet at fair value. The Company estimates fair
value based on quotes obtained from the counter-parties to the derivative
contracts. The Company recognizes the fair value of derivative contracts that
expire in less than one year as current assets or liabilities. Those that expire
in more than one year are recognized as long-term assets or liabilities.
Derivatives that are not accounted for as hedges are adjusted to fair value
through income. If the derivative is designated as a hedge, depending on the
nature of the hedge, changes in fair value are either 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 Company has designated a natural gas swap as a cash flow hedge. For
derivatives classified as cash flow hedges, changes in fair value are recognized
in other comprehensive income until the hedged item is recognized in earnings.
The ineffective portion of any change in the fair value of a derivative
designated as a hedge is immediately recognized in earnings. Hedge effectiveness
is measured quarterly based on the relative fair value between the derivative
contract and the hedged item over time. During the three months ended June 30,
2001, the Company recognized a decrease in the derivative liability and an
associated decrease in other comprehensive loss totaling approximately
$5,179,000. During the six months ended June 30, 2001, the Company recognized a
decrease in the derivative liability and an associated decrease in other
comprehensive loss totaling approximately $8,062,000. As of June 30, 2001, other
current assets included $963,000 and other assets include $938,000 related to
the fair value of derivative contracts.
During the three and six months ended June 30, 2001, the Company recognized
non-cash gains of $1,736,000 and $3,195,000, respectively, in earnings related
to the net change in fair value of derivative contracts which have not been
designated as hedges.
During the three and six months ended June 30, 2001, the Company paid $1,081,000
and $3,892,000, respectively, in cash settlements on its natural gas hedges
which are included in net profits and royalty interests.
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3. 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 three months ended June 30, 2001, the Company's
comprehensive income differed from net income by approximately $5,179,000
related to the change in fair value of a natural gas swap contract designated as
a hedge. There were no differences between comprehensive income and net income
for the three months ended June 30, 2000. For the six-month period ending June
30, 2001, the Company's comprehensive income differed from net income by
approximately $8,062,000 related to the change in fair market value of a natural
gas swap contract designated as a hedge. There were no differences between
comprehensive income and net loss for the six months ended June 30, 2000.
4. EARNINGS (LOSS) PER SHARE
The following table sets forth the computation of basic and diluted earnings per
common share:
<Table>
<Caption>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30 JUNE 30
--------------------------- --------------------------
2001 2000 2001 2000
------------ ----------- ----------- -----------
Numerator:
Numerator for basic earnings (loss)
per common share - net earnings
(loss) $ 3,392,000 $ 190,000 $ 8,386,000 $(1,428,000)
============ =========== =========== ===========
Denominator:
Denominator for basic earnings per
common share - weighted average
shares 12,748,612 382,397 12,748,612 335,937
Dilutive effect of employee stock
options 93,647 -- 85,325 --
Dilutive effect of common stock
repricing rights -- 903,842 -- --
------------ ----------- ----------- -----------
Denominator for diluted earnings per
common share - adjusted weighted
average shares 12,842,259 1,286,239 12,833,937 335,937
============ =========== =========== ===========
Earnings (loss) per common share
Basic $ 0.27 $ 0.50 $ 0.66 $ (4.24)
============ =========== =========== ===========
Diluted $ 0.26 $ 0.15 $ 0.65 $ (4.25)
============ =========== =========== ===========
</Table>
Weighted average common shares outstanding and losses per common share for the
three and six months ended June 30, 2000 have been restated for the effects of a
156-to-1 reverse stock split.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
FORWARD-LOOKING STATEMENTS
We have made forward-looking statements in this document 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
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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
document, 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.
SELECTED FINANCIAL DATA
The following tables set forth selected financial data for the Company,
presented as if our net profits interests had been accounted for as working
interests. The financial data were derived from the Consolidated Financial
Statements of the Company and should be read in conjunction with the
Consolidated Financial Statements and related Notes thereto included herein. The
results of operations for the three months ended June 30, 2001 will not
necessarily be indicative of the operating results for the full fiscal year
ending December 31, 2001.
<Table>
<Caption>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30 JUNE 30
----------------------------- -----------------------------
2001 2000 2001 2000
------------ ------------ ------------ ------------
Oil and gas sales (1) $ 10,658,000 $ 9,575,000 $ 24,612,000 $ 17,504,000
Oil and gas production expenses (1) 1,882,000 1,881,000 4,321,000 3,784,000
General and administrative expenses 1,198,000 804,000 2,088,000 1,551,000
------------ ------------ ------------ ------------
EBITDA (2) 7,578,000 6,890,000 18,203,000 12,169,000
Interest expense, excluding
amortization of deferred charges (3) (1,637,000) (4,226,000) (3,284,000) (8,582,000)
Depreciation, depletion and
amortization (4) (2,551,000) (2,468,000) (5,061,000) (5,060,000)
Interest and other income (expense) 137,000 (6,000) 259,000 45,000
Change in fair value of derivatives 1,736,000 -- 3,195,000 --
Income tax expense (1,871,000) -- (4,926,000) --
------------ ------------ ------------ ------------
Net income (loss) from operations $ 3,392,000 $ 190,000 $ 8,386,000 $ (1,428,000)
============ ============ ============ ============
</Table>
- -----------------
(1) Oil and natural gas sales and production expenses related to net profits
interests have been presented as if such net profits interests had been
accounted for as working interests, net of cash settlements on hedges.
(2) EBITDA represents earnings before interest expense, income taxes,
depreciation, depletion and amortization expense, and excludes interest and
other income and change in derivative fair value. 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 $175,000 and $424,000 of
amortized deferred charges related to debt obligations and $0 and $22,000
of amortized deferred charges related to the Company's natural gas
price-hedging program for the three months ended June 30, 2001 and 2000,
respectively. Depreciation, depletion and amortization includes $398,000
and $824,000 of amortized deferred charges related to debt obligations and
$0 and $44,000 of amortized deferred charges related to the Company's
natural gas price-hedging program for the six months ended June 30, 2001
and 2000, respectively.
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<Table>
<Caption>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30 JUNE 30
------------------ ----------------
2001 2000 2001 2000
------ ------ ------ ------
PRODUCTION VOLUMES:
Natural gas (MMcf) 2,282 2,509 4,514 5,090
Oil (MBbls) 44 53 87 110
Total natural gas equivalent (MMcfe) 2,544 2,825 5,039 5,749
AVERAGE SALES PRICE:
Natural gas ($/Mcf) $ 4.18 $ 3.20 $ 4.93 $ 2.85
Oil ($/Bbl) $25.83 $29.16 $27.06 $27.33
Natural gas equivalent (per Mcfe) $ 4.19 $ 3.39 $ 4.88 $ 3.04
SELECTED EXPENSES (PER MCFE):
Lease operating expense $ 0.65 $ 0.50 $ 0.68 $ 0.51
Production taxes $ 0.09 $ 0.17 $ 0.18 $ 0.15
Depreciation, depletion and amortization
of oil and natural gas properties $ 0.93 $ 0.72 $ 0.92 $ 0.73
General and administrative expenses $ 0.47 $ 0.28 $ 0.41 $ 0.27
Interest and financing charges $ 0.64 $ 1.50 $ 0.65 $ 1.49
</Table>
The following discussion of the results of operations and financial condition
should be read in conjunction with the Consolidated Condensed Financial
Statements and related Notes thereto included herein.
THE THREE MONTHS ENDED JUNE 30, 2001 COMPARED TO THE THREE MONTHS ENDED JUNE 30,
2000
RESULTS OF OPERATIONS
The following discussion and analysis reflects the operating results as if the
net profits interests were working interests. We believe that this will provide
the readers of the report with a more meaningful understanding of the underlying
operating results and conditions for the period.
REVENUES: Our total revenues increased by $1.1 million, or 11%, to $10.7 million
for the three months ended June 30, 2001 from $9.6 million during the comparable
period in 2000. Natural gas contributed 89% of our total revenues for the June
2001 quarter and 84% during the June 2000 quarter.
Our production of both oil and natural gas decreased for second quarter 2001
compared with second quarter 2000. Excessive leverage and depressed natural gas
prices during 1999 and the first half of 2000 resulted in our curtailing capital
spending and selling certain producing properties during those periods. Further,
and for similar reasons, we have made no acquisitions of producing properties
since April 1998. As a result, our production volumes have continued to decline.
Improved natural gas prices and completion of our recapitalization during the
second half of 2000 have allowed us to increase our capital spending activity,
beginning during the third quarter 2000. We have increased development
expenditures and initiated an on-going exploration effort, both of which are
intended to increase our production rates and proven reserves.
We produced 44,000 barrels of crude oil during the three months ended June 30,
2001, a decrease of 9,000 barrels, or 17%, from the 53,000 barrels produced
during the comparable period in 2000.
We produced 2.3 Bcf of natural gas during the three months ended June 30, 2001,
a decrease of 227 MMcf, or 9%, from the 2.5 Bcf produced during the comparable
period in 2000. This decrease consists of a decrease of 187 MMcf, or 8%, from
the properties that we owned during both periods and a decrease of
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40 MMcf from the properties that we sold at the end of June 2000. The production
during the second quarter of 2001 was impacted by decreases due to natural
decline offset by increased production in our Gilmer field due to the completion
of new wells.
Production in the New Albany Shale Gas field in Kentucky was curtailed in the
first half of this year due to a partial plant shutdown of the industrial market
that was purchasing our production. In June 2001, sales to this market were
permanently discontinued. At that time, we were building additional gathering
lines to service existing and future wells and should be connecting all wells to
an interstate transmission line during September 2001. Our development activity
in the field is continuing, and we are currently drilling 50 wells utilizing two
drilling rigs. Completing operations on new wells will begin during August 2001.
On a thousand cubic feet of natural gas equivalent ("Mcfe") basis, production
for the three months ended June 30, 2001 was 2.5 Bcfe, down 0.3 Bcfe, or 10%,
from the 2.8 Bcfe produced during the comparable period in 2000. Production from
properties that we owned during both periods was down 239 MMcfe, or 9%, during
the three months ended June 30, 2001 when compared to production during the
three months ended June 30, 2000.
The increase in revenue is due to a significant industry-wide increase in
natural gas prices which reached historic highs during the first quarter of
2001. Natural gas prices during second quarter 2001 were below first quarter
levels but remained well above second quarter 2000 prices. The average price per
Mcf of natural gas sold by us was $4.18 during the three months ended June 30,
2001, an increase of $0.98 per Mcf, or 30%, over the $3.20 per Mcf realized
during the comparable period in 2000. The average price per barrel of crude oil
sold by us during the three months ended June 30, 2001 was $25.83, a decrease of
$3.33 per barrel, or 11%, below the $29.16 per barrel during the three months
ended June 30, 2000. On a Mcfe basis, the average price received by us during
the three months ended June 30, 2001 was $4.19, a $0.80 increase, or 24%, over
the $3.39 we received during the comparable period in 2000.
During the three months ended June 30, 2001, we paid $1,081,000 in cash
settlements under our natural gas price-hedging program. The net negative effect
on the average natural gas prices we received during the period was $0.47 per
Mcf. During the comparable period in 2000, we paid $564,000 in cash settlements
and amortized $22,000 of deferred hedging costs regarding our natural gas
price-hedging program. The net negative effect on the average natural gas prices
we received during the 2000 period was $0.22 per Mcf. During the three months
ended June 30, 2001, no crude oil price-hedging contracts were in place. During
the comparable period in 2000, we paid $20,000 in cash settlements pursuant to
our crude oil price-hedging program.
SEVERANCE AND PRODUCTION TAXES: Severance and production taxes, which are based
on the revenues derived from the sale of crude oil and natural gas, were
$221,000 during the three months ended June 30, 2001 compared to $474,000 during
the comparable period in 2000. This decrease of $253,000, or 53%, is primarily
the result of receiving severance tax rebates in our Gilmer and J.C. Martin
fields.
On a cost per Mcfe basis, severance taxes were $0.09 per Mcfe for the three
months ended June 30, 2001 compared to $0.17 per Mcfe for the comparable period
ending June 30, 2000, a decrease of 48%.
PRODUCTION EXPENSES: Our lease operating expenses increased to $1.7 million for
the three months ended June 30, 2001, an increase of $0.3 million, or 31%, from
the $1.4 million incurred during the comparable period in 2000. This is due to
higher ad valorem tax accruals in this period compared to the comparable period
in 2000. Lease operating expenses were $0.65 per Mcfe during the three months
ended June 30, 2001, an increase of $0.15, or 30%, from the $0.50 per Mcfe
incurred during the comparable period in 2000. The increase in average costs per
unit is a result of higher ad valorem tax accruals combined with lower
production volumes.
DEPLETION, DEPRECIATION AND AMORTIZATION EXPENSE: Depletion and oil field
equipment related depreciation costs were $2.4 million for the three months
ended June 30, 2001, an increase of 15% over the $2.1 million for the comparable
period in 2000. On a Mcfe basis, depletion and oil field equipment related
depreciation was $0.93 per Mcfe during the three months, an increase of $0.21
per Mcfe, or 30%, from the
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$0.72 Mcfe per during the comparable period in 2000. The increase, on a cost per
Mcfe basis, is primarily due to capitalized costs increasing at a faster rate
than the reserve base.
GENERAL AND ADMINISTRATIVE EXPENSES: The increase of $394,000, or 49%, in
general and administrative costs for the three months ended June 30, 2001 is a
result of increased audit fees and engineering costs; increased franchise taxes;
and increased employee-related costs.
INTEREST EXPENSE: Interest expense decreased by $2.8 million to $1.8 million for
the three months ended June 30, 2001 compared to $4.7 million for the three
months ended June 30, 2000. The interest expense of $1.8 million is comprised of
$1.6 million in cash interest charges and $0.2 million of amortized deferred
debt issuance costs. The decrease in interest expense resulted from the
repurchase during 2000 of $75.0 million of our senior notes and reduction in
other long-term debt of $14.0 million. During the three months ended June 30,
2000, there were $0.4 million of amortized deferred debt issuance costs included
in the interest expense of $4.7 million.
CHANGE IN DERIVATIVE FAIR VALUE: During the quarter ended June 30, 2001, we
recorded a gain of $1.7 million representing the change in fair value of our
derivative contracts that are not accounted for as hedges. We adopted Statement
of Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities (SFAS No. 133), on July 1, 2000. Accordingly, no
comparable amounts were recorded during the quarter ended June 30, 2000.
NET INCOME: For the three months ended June 30, 2001, we recorded net income of
$3.4 million or $0.27 and $0.26 per basic and diluted share, respectively,
compared to income of $0.2 million or $0.50 per basic and $0.15 per diluted
share for 2000. The reduction of debt and increased natural gas prices are the
primary causes of the significantly improved results.
THE SIX MONTHS ENDED JUNE 30, 2001 COMPARED TO THE SIX MONTHS ENDED JUNE 30,
2000
RESULTS OF OPERATIONS
The following discussion and analysis reflects the operating results as if the
net profits interests were working interests. We believe that this will provide
the readers of the report with a more meaningful understanding of the underlying
operating results and conditions for the period.
REVENUES: Our total revenues increased by $7.1 million, or 41%, to $24.6 million
for the six months ended June 30, 2001 from $17.5 million during the comparable
period in 2000. Natural gas contributed 90% of our total revenues for the six
months ended June 2001 and 83% during the comparable period in 2000.
Our production of both oil and natural gas decreased for the six months ended
June 30, 2001 compared with the six months ended June 30, 2000. Excessive
leverage and depressed natural gas prices during 1999 and the first half of 2000
resulted in our curtailing capital spending and selling certain producing
properties during those periods. Further, and for similar reasons, we have made
no acquisitions of producing properties since April 1998. As a result, our
production volumes have continued to decline. Improved natural gas prices and
completion of our recapitalization during the second half of 2000 have allowed
us to increase our capital spending activity, beginning during the third quarter
2000. We have increased development expenditures and initiated an on-going
exploration effort, both of which are intended to increase our production rates
and proven reserves.
We produced 87,000 barrels of crude oil during the six months ended June 30,
2001, a decrease of 23,000 barrels, or 20%, from the 110,000 barrels produced
during the comparable period in 2000.
We produced 4.5 Bcf of natural gas during the six months ended June 30, 2001, a
decrease of 576 MMcf, or 11%, from the 5.1 Bcf produced during the comparable
period in 2000. This decrease consists of a decrease of 458 MMcf, or 9%, from
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the properties that we owned during both periods and a decrease of 118 MMcf
from the properties that we sold at the end of June 2000. The production during
the first six months of 2001 was impacted by decreases due to natural decline
offset by increased production in the Gilmer field due to completion of new
wells.
Production in the New Albany Shale Gas field in Kentucky was curtailed in the
first half of this year due to a partial plant shutdown of the industrial market
that was purchasing our production. In June 2001, sales to this market were
permanently discontinued. At that time, we were building additional gathering
lines to service existing and future wells and should be connecting all wells to
an interstate transmission line during September 2001. Our development activity
in the field is continuing, and we are currently drilling 50 wells utilizing two
drilling rigs. Completing operations on new wells will begin during August 2001.
On a thousand cubic feet of natural gas equivalent ("Mcfe") basis, production
for the six months ended June 30, 2001 was 5.0 Bcfe, down 0.7 Bcfe, or 12%, from
the 5.7 Bcfe produced during the comparable period in 2000. Production from
properties that we owned during both periods was down 589 MMcfe, or 10%, during
the six months ended June 30, 2001 when compared to production during the six
months ended June 30, 2000.
The increase in revenues was due to a significant, industry-wide increase in
natural gas prices, partially offset by lower production volume and slightly
lower oil prices. The average price per barrel of crude oil sold by us during
the six months ended June 30, 2001 was $27.06, a decrease of $0.27 per barrel,
or 1%, below the $27.33 per barrel during the six months ended June 30, 2000.
The average price per Mcf of natural gas sold by us was $4.93 during the six
months ended June 30, 2001, an increase of $2.08 per Mcf, or 73%, over the $2.85
per Mcf during the comparable period in 2000.
During the six months ended June 30, 2001, we paid $3,892,000 in cash
settlements under our natural gas price-hedging program. The net negative effect
on the average natural gas prices we received during the period was $0.86 per
Mcf. During the comparable period in 2000, we paid $616,000 in cash settlements
and amortized $44,000 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 2000 period was $0.12 per Mcf. During the six months
ended June 30, 2001, no crude oil price-hedging contracts were in place. During
the comparable period in 2000, we paid $109,000 in cash settlements pursuant to
our crude oil price-hedging program.
SEVERANCE AND PRODUCTION TAXES: Severance and production taxes, which are based
on the revenues derived from the sale of crude oil and natural gas, were
$882,000 during the six months ended June 30, 2001 compared to $847,000 during
the comparable period in 2000. This increase of $35,000, or 4%, is primarily the
result of increased revenues we received during the six months ended June 30,
2001, offset by severance tax rebates on our Gilmer and J.C. Martin fields
received during the first six months of 2001.
On a cost per Mcfe basis, severance taxes were $0.18 per Mcfe for the six months
ended June 30, 2001 compared to $0.15 per Mcfe for the comparable period ending
June 30, 2000, an increase of 19%. Average wellhead prices rose by 78% from
$3.17 per Mcfe during the six months ended June 30, 2000 to $5.65 per Mcfe
during the six months ended June 30, 2001.
PRODUCTION EXPENSES: Our lease operating expenses increased to $3.4 million for
the six months ended June 30, 2001, an increase of $0.5 million, or 17%, from
the $2.9 million incurred during the comparable period in 2000. This increase is
due to increased ad valorem tax accruals during the six months ended June 30,
2001 compared to the six months ended June 30, 2000. Lease operating expenses
were $0.68 per Mcfe during the six months ended June 30, 2001, an increase of
$0.17, or 34%, from the $0.51 per Mcfe incurred during the comparable period in
2000. The increase in average costs per unit is a result of increased total
costs and lower production volumes.
DEPLETION, DEPRECIATION AND AMORTIZATION EXPENSE: Depletion and oil field
equipment related depreciation costs were $4.7 million for the six months ended
June 30, 2001, an increase of 9% over the $4.3 million for the comparable period
in 2000. On a Mcfe basis, depletion and oil field equipment related
10
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depreciation was $0.92 per Mcfe during the six months, an increase of $0.19 per
Mcfe, or 26%, from the $0.73 Mcfe per during the comparable period in 2000. The
increase, on a cost per Mcfe basis, is primarily due to capitalized costs
increasing at a faster rate than the reserve base.
GENERAL AND ADMINISTRATIVE EXPENSES: The increase of $537,000, or 35%, in
general and administrative costs for the 6-month period ending June 30, 2001 is
a result of increased audit fees; increased regulatory fees, mainly franchise
taxes; increased employee-related costs; and increased engineering costs.
INTEREST EXPENSE: Interest expense decreased by $5.7 million to $3.7 million for
the six months ended June 30, 2001 compared to $9.4 million for the six months
ended June 30, 2000. The interest expense of $3.7 million is comprised of $3.3
million in cash interest charges and $0.4 million of amortized deferred debt
issuance costs. The decrease in interest expense resulted from the repurchase of
$75.0 million of our senior notes and reduction in other long-term debt of $14.0
million. During the six months ended June 30, 2000, there were $0.8 million of
amortized deferred debt issuance costs included in the interest expense of $9.4
million.
CHANGE IN DERIVATIVE FAIR VALUE: During the six months ended June 30, 2001, we
recorded a gain of $3.2 million representing the change in fair value of our
derivative contracts that are not accounted for as hedges. We adopted Statement
of Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities (SFAS No. 133), on July 1, 2000. Accordingly, no
comparable amounts were recorded during the six months ended June 30, 2000.
NET INCOME: For the six months ended June 30, 2001, we recorded net income of
$8.4 million or $0.66 and $0.65 per basic and diluted share, respectively,
compared to a loss of $1.4 million or $4.25 per basic and diluted share for
2000. The reduction of debt and increased natural gas prices are the primary
causes of the significantly improved results.
LIQUIDITY AND CAPITAL RESOURCES
GENERAL
During the year ended December 31, 1999 and the first half of 2000, our
acquisition and development spending were significantly curtailed as a result of
the combined impact of depressed natural gas prices and excessive leverage. We
also sold producing properties during those periods. As a result of reduced
spending combined with property sales, our production rates have been declining.
During 1999, we invested $7.5 million in development activities and sold
producing properties for proceeds of $10.2 million. During the first half of
2000, we invested $4.0 million in development of our properties and sold
producing properties for proceeds of $3.4 million.
Increasing natural gas prices during the last half of 2000 and completion of our
recapitalization during October 2000 enabled us to increase our capital spending
activities, and during the last half of 2000, we spent $9.1 million in capital
activities. As planned, our capital spending level has continued to grow as we
invested $9.7 million during the first six months of 2001, including $2.3
million in exploration activities. Our plans for the remainder of 2001 call for
additional capital spending ranging between $17 million and $20 million, of
which 15% to 25% is allocated to exploration activities.
The increased spending levels are intended to increase our reserves and
production rates. We intend to fund the investing activities using our existing
cash balances, cash generated from operations and, to the extent necessary, our
revolving credit facility.
We have planned development and exploitation activities for all of our major
operating areas. We plan to spend a total of $27-30 million in capital
activities during 2001. During the six months ended June 30, 2001, we have spent
$9.7 million and have a further $11.3 million contractually committed. Of the
total planned capital expenditures for the year, 18-24% is allocated to
exploration activities. We believe our cash flow from operations combined with
our existing credit facility will be sufficient to fund our planned exploration,
development and exploitation activities for 2001. In addition, we are continuing
to evaluate oil and natural gas properties for future acquisition. Historically,
11
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we have used the proceeds from the sale of our securities in the private equity
market and borrowings under our credit facilities to raise cash to fund
acquisitions or repay indebtedness incurred for acquisitions. We have also used
our securities as a medium of exchange for other companies' assets in connection
with acquisitions. However, there can be no assurance that such sources will be
available to us to meet our budgeted capital spending. Furthermore, our ability
to borrow other than under the amended and restated credit agreement with Ableco
Finance LLP and Foothill Capital Corporation is subject to restrictions imposed
by our credit agreement and the indenture governing our senior notes. 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.
Part of the Company's strategy to increase shareholder value is to actively seek
corporate acquisitions and mergers. On April 24, 2001, we announced that we had
received written indications of interest that could result in the merger or sale
of the Company. At the same time, we announced that we had instructed our
investment bankers to evaluate those expressions of interest as well as other
merger or sale alternatives. None of the indications of interest have resulted
in a definitive agreement. Natural gas prices have decreased during the past few
months, and that decrease has reduced the value prospective buyers place on the
Company. We continue to have discussions with prospective buyers and merger
partners, continuing to seek a price that we believe is a fair and reasonable
valuation of the Company.
SOURCES OF CAPITAL
We have a credit agreement with Ableco Finance LLC and Foothill Capital
Corporation which allows for borrowings up to $50 million, subject to borrowing
base limitations, from such lenders to fund, among other things, development and
exploitation expenditures, acquisitions and general working capital. Our
borrowing base under the credit agreement is currently $43.5 million. As of
August 1, 2001, under this facility, we had no indebtedness outstanding, had
$3.4 million reserved to secure a letter of credit, and were permitted to borrow
an additional $40.1 million. Under the credit agreement, we have provided a
first lien on all of our assets to secure our obligations under the agreement.
The credit agreement matures on April 22, 2003. There are no scheduled principal
repayments. The credit agreement bears interest as follows:
o When the borrowings are less than $30 million or borrowings are less than
67% of the borrowing base as defined in the agreement, bank prime plus 2%;
o When the borrowings are $30 million or greater and borrowings exceed 67% of
the borrowing base as defined in the agreement, bank prime plus 3.5%;
o On amounts securing letters of credit issued on our behalf, 3%.
The credit agreement contains certain affirmative and negative financial
covenants, including maintaining interest coverage ratio greater than 1, a
minimum of 1.5-to-1 working capital ratio (calculated as set out in the credit
agreement) and a $30 million annual limit on capital spending. The Company has
been in compliance with all covenants during the six months ended June 30, 2001.
We have a letter of credit outstanding under the credit agreement in the amount
of $3.4 million, as of August 1, 2001, to secure a swap exposure. The letter of
credit has the effect of reducing our credit availability under the credit
agreement.
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 April 1998, our primary method of replacing
production and enhancing our reserves has been through the development and
12
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exploitation of our oil and natural gas properties. We have recently entered
into two exploration joint ventures and expect to allocate 18-24% of our 2001
capital spending to exploration activities. We expect to spend $27-30 million on
capital spending during 2001 for exploitation, development and exploration
projects. As of June 30, 2001, we are contractually obligated to fund $11.3
million in capital expenditures through December 2001. We believe that cash flow
from operations and our credit agreement will be sufficient to fund our planned
activities. However, our cash flow from operations is significantly affected by
the uncertainty of commodity prices. If there were a significant, protracted
decline in prices, we would evaluate our projects and may delay or defer some of
our planned activities. During the six months ended June 30, 2001, we recorded
$9.7 million in capital expenditures. Of this amount, $2.3 million relate to
exploration activities with the balance of $7.4 million used in property
development.
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 such financing, if
obtained, will be on terms favorable to us.
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. Our credit agreement permits up to
$12 million in letters of credit. As of August 1, 2001, we have provided $3.4
million in letters of credit related to our hedge contracts containing "caps."
INFLATION
Although inflation has not had a significant impact on our results of operations
during the past several years, oil and gas production and development costs,
lease acquisition and operating costs, labor availability, drilling costs
(including costs of pipe, drill fluids and rig crews) and availability of rigs,
fluctuate in response to overall industry conditions and demand for leases and
rigs. Moreover, the prices we receive for our production fluctuate upward and
downward, often significantly and often in a short period of time. This can and
will affect our revenues from quarter to quarter.
CHANGES IN PRICES AND HEDGING ACTIVITIES
Annual average oil and natural gas prices have fluctuated significantly over the
last two years. The table below sets out our weighted average price per barrel
of oil and the weighted average price per Mcf of natural gas, the impact of our
hedging programs and the related NYMEX indices.
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15
<Table>
<Caption>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30 JUNE 30
------------------ ------------------
2001 2000 2001 2000
------- ------- ------- -------
GAS (PER MCF)
Price received at wellhead $ 4.65 $ 3.43 $ 5.79 $ 2.97
Effect of hedge contracts $ (0.47) $ (0.23) $ (0.86) $ (0.12)
Effective price received
including hedge contracts $ 4.18 $ 3.20 $ 4.93 $ 2.85
Average NYMEX Henry Hub $ 4.78 $ 3.43 $ 6.03 $ 2.96
Average basis differential
including hedge contracts $ (0.60) $ (0.23) $ (1.10) $ (0.11)
Average basis differential
excluding hedge contracts $ (0.13) $ -- $ (0.24) $ 0.01
OIL (PER BARREL)
Price received at wellhead $ 25.83 $ 29.54 $ 27.06 $ 28.33
Effect of hedge contracts $ -- $ (0.38) $ -- $ (1.00)
Effective price received
including hedge contracts $ 25.83 $ 29.16 $ 27.06 $ 27.33
Average NYMEX Sweet Light Oil $ 27.96 $ 28.62 $ 28.33 $ 28.68
Average basis differential including
hedge contracts $ (2.13) $ 0.54 $ (1.27) $ (1.35)
Average basis differential excluding
hedge contracts $ (2.13) $ 0.92 $ (1.27) $ (0.35)
</Table>
We have a commodity price risk management or hedging strategy that is designed
to provide protection from low commodity prices while providing some opportunity
to enjoy the benefits of higher commodity prices. We have a series of natural
gas futures contracts with various counter-parties. This strategy is designed to
provide a degree of protection from negative shifts in natural gas prices as
reported on the Henry Heb Nymex Index. For the year ending December 31, 2001, we
have 8.7 Bcf hedged at a weighted average floor price of $3.00/Mcf and 5.0 Bcf
hedged with a weighted average ceiling price of $5.38/Mcf. For the six months
ending December 31, 2001, we have 4.1 Bcf hedged at a weighted average floor
price of $2.76 Mcf and 2.3 Bcf hedged with a weighted average ceiling price of
$4.84/Mcf.
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)
- ---------------- ----------------- ---------
January 1, 2001 December 31, 2001 2,970,000
January 1, 2002 December 31, 2002 2,550,000
January 1, 2003 December 31, 2003 2,250,000
</Table>
The table below sets out 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)
- ---------------- ----------------- ---------
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>
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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)
- ---------------- ----------------- ---------
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 natural gas and floor and ceiling prices
hedged with Texaco. 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
---------------- ------------- ------- ----- -------
January 1, 2001 March 31, 2001 1,125,000 $5.44 $8.29
April 1, 2001 June 30, 2001 675,000 $4.07 $6.42
July 1, 2001 December 31, 2001 1,350,000 $4.07 $6.51
January 1, 2002 December 31, 2002 900,000 $4.00 $6.75
</Table>
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See "Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations - Changes in Prices and Hedging Activities."
15
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PART II
OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
A portion of our royalty interest in the J.C. Martin field, which comprises
approximately 8% of our total SEC PV-10 value as of December 31, 2000, is
currently subject to a lawsuit issued by a former owner against the pension
funds managed by the entity that sold us our royalty interest in the properties
in 1998. We are not parties to the lawsuit. Among other things, the lawsuit
seeks rescission of the 1989 sale of the properties to the pension funds from
whom we obtained our royalty interest and, accordingly, may create uncertainty
as to our title. On November 5, 1997, a summary judgment order was issued in
favor of the defendants dismissing the plaintiff's title claims. The plaintiff's
appeal of that order was dismissed on May 10, 2001. The plaintiff's application
for a rehearing of the first appeal was rejected on June 7, 2001. On July 23,
2001, the plaintiff filed an application for leave to further appeal the order
for summary judgment to a higher court. It is not known when a decision on the
leave application will be issued. If the leave application is granted, an appeal
hearing will be scheduled in due course. A dismissal of the leave application
will effectively terminate the lawsuit as it pertains to the title issue.
Although we are of the view that the plaintiff's case is without merit, there
can be no assurance that the motion for leave to appeal will not be granted, or
if leave is granted, that the appeal will not succeed. Eight million dollars of
the purchase price we paid for the Morgan Properties, which include our royalty
interest in the J.C. Martin field, were placed in an interest bearing escrow
account pending the resolution of this lawsuit. As of June 30, 2001, the balance
in the escrow account inclusive of interest was approximately $9.4 million. If
the summary judgment is overturned on appeal and a final judgment is later
entered against the entity who sold us this property and that judgment unwinds
the original transaction in which the entity acquired its interest in the J.C.
Martin field, the balance in the escrow account would be returned to us and we
would be required to convey our royalty interest, plus production proceeds, in
the J.C. Martin field to the plaintiff retroactive to the date we acquired the
interest.
ITEM 5. OTHER INFORMATION
On February 13, 2001, we announced the implementation of a four-part strategy
directed at growing our asset base and increasing shareholder value. This
strategy consists of: (1) establishing an exploration program to add reserves at
competitive finding costs; (2) developing and exploiting our existing
properties; (3) pursuing selective property acquisitions; and (4) actively
seeking corporate acquisitions and mergers. On April 24, 2001, we announced that
we had received written indications of interest that could result in the merger
or sale of the company for cash or a combination of cash and stock. At the same
time, we announced that we had instructed our investment bankers to evaluate the
expressions of interest as well as other merger or sale alternatives to maximize
stockholder value. None of the indications of interest have resulted in a
definitive agreement. Natural gas prices have decreased during the past few
months, and that decrease has reduced the value prospective buyers place on the
company. We continue to have discussions with prospective buyers and merger
partners, continuing to seek a price that we believe is a fair and reasonable
valuation of the company.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) EXHIBITS.
None.
(B) REPORTS ON FORM 8-K.
None.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized this 9th day of August 2001.
DEVX ENERGY, INC. (DELAWARE)
By: /s/ Edward J. Munden
-----------------------------------
Edward J. Munden
President and Chief Executive Officer
By: /s/ William W. Lesikar
-----------------------------------
William W. Lesikar
Chief Financial Officer
DEVX ENERGY, INC. (NEVADA)
By: /s/ Edward J. Munden
-----------------------------------
Edward J. Munden
President and Chief Executive Officer
By: /s/ William W. Lesikar
-----------------------------------
William W. Lesikar
Vice President (Principal Financial Officer)
DEVX OPERATING COMPANY
By: /s/ Edward J. Munden
-----------------------------------
Edward J. Munden
President and Chief Executive Officer
By: /s/ William W. Lesikar
-----------------------------------
William W. Lesikar
Vice President (Principal Financial Officer)
CORRIDA RESOURCES, INC.
By: /s/ Edward J. Munden
-----------------------------------
Edward J. Munden
President and Chief Executive Officer
By: /s/ William W. Lesikar
-----------------------------------
William W. Lesikar
Treasurer (Principal Financial Officer)