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U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-Q
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[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 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 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days. YES [X] NO [ ]
APPLICABLE ONLY TO CORPORATE ISSUERS: Indicate the number of shares outstanding
of each of the issuer's classes of common stock, as of May 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)
MARCH 31, DECEMBER 31,
2001 2000
-------------- --------------
ASSETS
Current assets:
Cash $ 13,198,000 $ 10,985,000
Other current assets 10,902,000 10,740,000
-------------- --------------
Total current assets 24,100,000 21,725,000
Net property and equipment 99,210,000 97,091,000
Other assets 4,141,000 4,174,000
-------------- --------------
$ 127,451,000 $ 122,990,000
============== ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and other $ 8,369,000 $ 7,507,000
Derivatives 112,000 1,507,000
-------------- --------------
Total current liabilities 8,481,000 9,014,000
Long-term obligations, net of current portion 50,000,000 50,000,000
Derivatives 9,363,000 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
March 31, 2001 and December 31, 2000 2,983,000 2,983,000
Additional paid-in capital 60,159,000 60,159,000
Retained earnings 5,828,000 834,000
Accumulated other comprehensive loss (9,363,000) (12,246,000)
-------------- --------------
Total stockholders' equity 59,607,000 51,730,000
-------------- --------------
$ 127,451,000 $ 122,990,000
============== ==============
See accompanying notes to unaudited consolidated condensed financial statements.
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DEVX ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31
-----------------------------
2001 2000
------------- -------------
Revenues:
Oil and gas sales $ 1,091,000 $ 907,000
Net profits and royalty interests 11,121,000 5,701,000
Interest and other income 122,000 65,000
------------- -------------
Total revenues 12,334,000 6,673,000
------------- -------------
Expenses:
Oil and gas production expenses 697,000 572,000
Depreciation, depletion and amortization 2,288,000 2,215,000
General and administrative 890,000 747,000
Interest and financing expense 1,870,000 4,757,000
------------- -------------
Total expenses 5,745,000 8,291,000
------------- -------------
Operating income (loss) 6,589,000 (1,618,000)
Change in fair value of derivatives 1,459,000 --
------------- -------------
Income (loss) before income taxes 8,048,000 (1,618,000)
Income taxes 3,054,000 --
------------- -------------
Net income (loss) $ 4,994,000 $ (1,618,000)
Earnings per common share:
Basic and diluted $ 0.39 $ (5.59)
============= =============
Weighted average shares outstanding:
Basic 12,748,612 289,224
============= =============
Diluted 12,825,616 289,224
============= =============
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)
THREE MONTHS ENDED
MARCH 31
--------------------------------
2001 2000
-------------- --------------
Cash flows from operating activities:
Net income (loss) $ 4,994,000 $ (1,618,000)
Depreciation, depletion and amortization 2,511,000 2,592,000
Change in fair market value of derivatives (1,459,000) --
Net change in operating assets and liabilities 574,000 (5,457,000)
-------------- --------------
Net cash provided by (used in) operating activities 6,620,000 (4,483,000)
-------------- --------------
Cash flows used in investing activities:
Additions to property and equipment (4,407,000) (1,906,000)
Proceeds from sale of oil & gas properties -- 212,000
-------------- --------------
Net cash (used in) investing activities (4,407,000) (1,694,000)
Cash flows from financing activities:
Proceeds from long-term debt -- 6,500,000
Payments on long-term obligations -- (2,390,000)
-------------- --------------
Net cash provided by financing activities -- 4,110,000
-------------- --------------
Net increase (decrease) in cash 2,213,000 (2,067,000)
Cash at beginning of period 10,985,000 3,376,000
-------------- --------------
Cash at end of period $ 13,198,000 $ 1,309,000
============== ==============
See accompanying notes to unaudited consolidated condensed financial statements.
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DEVX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
MARCH 31, 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 March 31, 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 March 31,
2001, the Company recognized a decrease in the derivative liability and an
associated other comprehensive income totaling approximately $2,883,000.
During the three months ended March 31, 2001, the Company recognized a non-cash
gain of $1,459,000 in earnings related to the net change in fair value of our
derivative contracts which have not been designated as hedges.
During the three months ended March 31, 2001, the Company paid $2,811,000 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 March 31, 2001, the Company's
comprehensive income differed from net income by approximately $2,883,000
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 loss for
the three months ended March 31, 2000.
4. EARNINGS PER SHARE
The following table sets forth the computation of basic and diluted earnings per
common share:
THREE MONTHS ENDED
MARCH 31
---------------------------------
2001 2000
--------------- ---------------
Numerator:
Numerator for basic earnings per common
share - net earnings $ 4,994,000 $ (1,618,000)
=============== ===============
Denominator:
Denominator for basic earnings per common 12,748,612 289,224
share - weighted average shares
Dilutive effect of employee stock options 77,004 --
--------------- ---------------
Denominator for diluted earnings per common
share - adjusted weighted average shares 12,825,616 289,224
=============== ===============
Earnings per common share - basic and diluted $ 0.39 $ (5.59)
=============== ===============
Weighted average common shares outstanding and losses per common share for the
three months ended March 31, 2000 have been restated for the effects of a
156-to-1 reverse stock split.
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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 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 March 31, 2001 will not
necessarily be indicative of the operating results for the full fiscal year
ending December 31, 2001.
THREE MONTHS ENDED MARCH 31
----------------------------------
2001 2000
--------------- ---------------
Oil and gas sales (1) $ 13,954,000 $ 7,929,000
Oil and gas production expenses (1) 2,439,000 1,903,000
General and administrative expenses 890,000 747,000
--------------- ---------------
EBITDA (2) 10,625,000 5,279,000
Interest expense, excluding amortization of
deferred charges (3) (1,647,000) (4,356,000)
Depreciation, depletion and amortization (4) (2,511,000) (2,593,000)
Interest and other income 122,000 52,000
Change in fair value of derivatives 1,459,000 --
Income tax expense (3,054,000) --
--------------- ---------------
Net income (loss) from operations $ 4,994,000 $ (1,618,000)
=============== ===============
- ---------------------
(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 $223,000 and $400,000
of amortized deferred charges related to debt obligations and $0 and
$22,000 of amortized deferred charges related to the Company's natural
gas price-hedging program for the three months ended March 31, 2001 and
2000, respectively.
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THREE MONTHS ENDED
MARCH 31
-----------------------------
2001 2000
------------- -------------
PRODUCTION VOLUMES:
Natural gas (MMcf) 2,232 2,581
Oil (MBbls) 44 57
Total natural gas equivalent (MMcfe) 2,495 2,923
AVERAGE SALES PRICE:
Natural gas ($/Mcf) $ 5.70 $ 2.51
Oil ($/Bbl) $ 28.28 $ 25.62
Natural gas equivalent (per Mcfe) $ 5.59 $ 2.71
SELECTED EXPENSES (PER MCFE):
Lease operating expense $ 0.71 $ 0.52
Production taxes $ 0.26 $ 0.13
Depreciation, depletion and amortization of oil
and natural gas properties $ 0.91 $ 0.74
General and administrative expenses $ 0.36 $ 0.26
Interest and financing charges $ 0.66 $ 1.49
The following discussion of the results of operations and financial condition
should be read in conjunction with the Consolidated Condensed Financial
Statements and related Notes thereto included herein.
THE THREE MONTHS ENDED MARCH 31, 2001 COMPARED TO THE THREE MONTHS ENDED MARCH
31, 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 $6.0 million, or 76%, to $13.9 million
for the three months ended March 31, 2001 from $7.9 million during the
comparable period in 2000. Natural gas contributed 91% of our total revenues for
the March 2001 quarter and 82% during the March 2000 quarter.
We produced 44,000 barrels of crude oil during the three months ended March 31,
2001, a decrease of 13,000 barrels, or 23%, from the 57,000 barrels produced
during the comparable period in 2000.
We produced 2.2 Bcf of natural gas during the three months ended March 31, 2001,
a decrease of 349 MMcf, or 14%, from the 2.6 Bcf produced during the comparable
period in 2000. This decrease consists of a decrease of 271 MMcf, or 11%, from
the properties that we owned during both periods and a decrease of 78 MMcf from
the properties that we sold at the end of June 2000. The production during the
first quarter of 2001 was impacted by the following:
o Production in our J.C. Martin field declined due to a temporary delay
in our drilling program;
o Decreases due to natural decline; and
o Offsetting the decreases, production in our Gilmer field increased due
to the completion of new wells.
On a thousand cubic feet of natural gas equivalent ("Mcfe") basis, production
for the three months ended March 31, 2001 was 2.5 Bcfe, down 0.4 Bcfe, or 15%,
from the 2.9 Bcfe produced during the comparable period in 2000. Production from
properties that we owned during both periods was down 351 MMcfe, or
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12% during the three months ended March 31, 2001 when compared to production
during the three months ended March 31, 2000.
The increase in revenues was due to a significant, industry-wide increase in oil
and natural gas prices, partially offset by lower production volume. The average
price per barrel of crude oil sold by us during the three months ended March 31,
2001 was $28.28, an increase of $2.66 per barrel, or 10%, over the $25.62 per
barrel during the three months ended March 31, 2000. The average price per Mcf
of natural gas sold by us was $5.70 during the three months ended March 31,
2001, an increase of $3.19 per Mcf, or 127%, over the $2.51 per Mcf during the
comparable period in 2000. Crude oil and natural gas prices have remained at
these elevated levels subsequent to March 31, 2001. On an Mcfe basis, the
average price received by us during the three months ended March 31, 2001 was
$5.59, a $2.88 increase, or 106%, over the $2.71 we received during the
comparable period in 2000.
During the three months ended March 31, 2001, we paid $2,811,000 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 $1.26 per
Mcf. During the comparable period in 2000, we paid $52,000 in cash settlements
and amortized $22,000 of deferred hedging costs regarding our natural gas
price-hedging program. The net negative effect on the average natural gas prices
we received during the 2000 period was $0.02 per Mcf. During the three months
ended March 31, 2001, no crude oil price-hedging contracts were in place. During
the comparable period in 2000, we paid $89,000 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
$661,000 during the three months ended March 31, 2001, as compared to $373,000
during the comparable period in 2000. This increase of $288,000, or 77%, is
primarily the result of the 143% increase in wellhead prices we received during
the three months ended March 31, 2001, offset by the 15% decline in production
from the three months ended March 31, 2000.
On a cost per Mcfe basis, severance taxes were $0.26 per Mcfe for the three
months ended March 31, 2001, compared to $0.13 per Mcfe for the comparable
period ending March 31, 2000, an increase of 100%. Average wellhead prices rose
by 143% from $2.76 per Mcfe during the three months ended March 31, 2000 to
$6.72 per Mcfe during the three months ended March 31, 2001.
PRODUCTION EXPENSES: Our lease operating expenses increased to $1.8 million for
the three months ended March 31, 2001, an increase of $0.3 million, or 16%, from
the $1.5 million incurred during the comparable period in 2000. This increase is
due to an increase in property tax accrual during the three months ended March
31, 2001, compared to the three months ended March 31, 2000. Lease operating
expenses were $0.71 per Mcfe during the three months ended March 31, 2001, an
increase of $0.19, or 36%, from the $0.52 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 $2.3 million for the three months
ended March 31,2001, an increase of 4% over $2.2 million for the comparable
period in 2000. On a Mcfe basis, depletion and oil field equipment related
depreciation was $0.91 per Mcfe during the three months, an increase of $0.17
per Mcfe, or 23%, from the $0.74 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 $143,000, or 19%, in
general and administrative costs for the three months ended March 31, 2001 was
due primarily to increased employee-related costs.
INTEREST EXPENSE: Interest expense decreased by $2.9 million to $1.9 million for
the three months ended March 31, 2001, compared to $4.8 million for the three
months ended March 31, 2000. The interest expense of $1.9 million is comprised
of $1.7 million in cash interest charges and $0.2 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 three
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months ended March 31, 2000, there were $0.4 million of amortized deferred debt
issuance costs included in the interest expense of $4.8 million.
CHANGE IN DERIVATIVE FAIR VALUE: We adopted Statement of Financial Accounting
Standards No. 133, Accounting for Derivative Instruments and Hedging Activities
(SFAS No. 133), on July 1, 2000. During the quarter ended March 31, 2001, we
recorded a gain of $1.5 million representing the change in fair value of our
derivative contracts that are not accounted for as hedges.
NET INCOME: For the three months ended March 31, 2001, we recorded net income of
$5.0 million or $0.39 per basic and diluted share, compared to a loss of $1.6
million or $5.59 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 quarter ended December 31, 2000, we completed a public offering of
11,500,000 shares of common stock generating net proceeds to us after deducting
underwriters' discounts and offering expenses of approximately $73.1 million.
The net proceeds were used to finance the repurchase of $75 million face value
of our Senior Notes for approximately $52.5 million, repay bank debt of
approximately $14 million and fund working capital.
As of May 1, 2001, under our credit agreement we:
o had no indebtedness outstanding;
o had $7.1 million reserved to secure a letter of credit; and
o were permitted to borrow an additional $36.4 million.
We have planned development and exploitation activities for all of our major
operating areas. We plan to spend $25-27 million in capital activities during
2001, of which, $2.7 million is contractually committed. Of the total planned
capital expenditures, 15 to 35 percent 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, 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.
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 May
1, 2001, under this facility, we had no indebtedness outstanding, had $7.1
million reserved to secure a letter of credit, and were
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permitted to borrow an additional $36.4 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 three months ended March 31,
2001.
We have a letter of credit outstanding under the credit agreement in the amount
of $7.1 million, as of May 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
exploitation of our oil and natural gas properties. We have recently entered
into two exploration joint ventures and expect to allocate 15 to 35 percent of
our 2001 capital spending to exploration activities. We expect to spend $25-27
million on capital spending during 2001 for exploitation, development and
exploration projects. As of March 31, 2001, we are contractually obligated to
fund $2.7 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
decline in prices, we would evaluate our projects and may delay or defer some of
our planned activities. During the three months ended March 31, 2001, we
recorded $4.4 million in capital expenditures.
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 May 1, 2001, we have provided $7.1
million in letters of credit related to our hedge contracts containing "caps."
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INFLATION
During the past several years, we have experienced some inflation in oil and gas
prices with moderate increases in property acquisition and development costs.
During the fiscal year ended December 31, 2000, we received higher commodity
prices for the natural resources produced from our properties than we received
for the year ended December 31, 1999. Oil and natural gas prices have remained
at these levels during the three months ended March 31, 2001. Our results of
operations and cash flow have been, and will continue to be, affected to a
certain extent by the volatility in oil and natural gas prices. Should we
continue to experience increases 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; and reduced availability of
equipment and crews.
CHANGES IN PRICES AND HEDGING ACTIVITIES
Annual average oil and natural gas prices have fluctuated significantly over the
last two years. The table below sets out our weighted average price per barrel
of oil and the weighted average price per Mcf of natural gas, the impact of our
hedging programs and the related NYMEX indices.
THREE MONTHS ENDED
MARCH 31
------------------------
2001 2000
---------- ----------
Gas (per Mcf)
Price received at wellhead $ 6.96 $ 2.53
Effect of hedge contracts $ (1.26) $ (0.02)
Effective price received, including hedge contracts $ 5.70 $ 2.51
Average NYMEX Henry Hub $ 7.27 $ 2.49
Average basis differential including hedge contracts $ (1.57) $ 0.02
Average basis differential excluding hedge contracts $ (0.31) $ 0.04
Oil (per barrel)
Price received at wellhead $ 28.28 $ 27.18
Effect of hedge contracts $ -- $ (1.56)
Effective price received, including hedge contracts $ 28.28 $ 25.62
Average NYMEX Sweet Light Oil $ 28.69 $ 28.74
Average basis differential including hedge contracts $ (0.41) $ (3.12)
Average basis differential excluding hedge contracts $ (0.41) $ (1.56)
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.
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The table below sets out the volume of natural gas that remains under contract
with the Bank of Montreal at a floor price of $2.00 per MMBtu. The volumes set
out in this table are divided equally over the months during the period:
Volume
Period Beginning Period Ending (MMBtu)
- ---------------- ------------- -------
January 1, 2001 December 31, 2001 2,970,000
January 1, 2002 December 31, 2002 2,550,000
January 1, 2003 December 31, 2003 2,250,000
The table below sets out volume of natural gas hedged with a floor price of
$1.90 per MMBtu with Enron. The volumes presented in this table are divided
equally over the months during the period:
Volume
Period Beginning Period Ending (MMBtu)
- ---------------- ------------- -------
January 1, 2001 December 31, 2001 740,000
January 1, 2002 December 31, 2002 640,000
January 1, 2003 December 31, 2003 560,000
The table below sets out volume of natural gas hedged with a swap at $2.40 per
MMBtu with Enron. The volumes presented in this table are divided equally over
the months during the period:
Volume
Period Beginning Period Ending (MMBtu)
- ---------------- ------------- -------
January 1, 2001 December 31, 2001 1,850,000
January 1, 2002 December 31, 2002 1,600,000
January 1, 2003 December 31, 2003 1,400,000
The table below sets out 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:
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
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."
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PART II
OTHER INFORMATION
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.
A portion of our landowner royalty on the J.C. Martin field, which comprises
approximately 11% of our total SEC PV-10 value as of December 31, 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 defendant pension funds managed by the entity that sold us the
properties. The Plaintiff's appeal of that order was dismissed on May 10, 2001.
There can be no assurance that the Plaintiff will not seek leave to further
appeal the order to a higher court. 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 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 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.
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 14th day of May, 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)
14