1
================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[ ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED _______
OR
[X] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM JULY 1, 2000 TO
DECEMBER 31, 2000
COMMISSION FILE NUMBER 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 RD., SUITE 1030
DALLAS, TEXAS 75240-7336
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
(REGISTRANTS' TELEPHONE NUMBER, INCLUDING AREA CODE) (972) 233-9906
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
COMMON STOCK, PAR VALUE $0.234 PER SHARE
(TITLE OF CLASS)
----------
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 [ ]
INDICATE BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO
ITEM 405 OF REGULATION S-K IS NOT CONTAINED HEREIN, AND WILL NOT BE CONTAINED,
TO THE BEST OF REGISTRANTS' KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION
STATEMENTS INCORPORATED BY REFERENCE IN PART III OF THIS FORM 10-K OR ANY
AMENDMENT OF THIS FORM 10-K. [ ]
STATE THE AGGREGATE MARKET VALUE OF THE VOTING AND NON-VOTING COMMON
EQUITY HELD BY NON-AFFILIATES (ALL DIRECTORS AND OFFICERS ARE PRESUMED TO BE
AFFILIATES FOR THIS CALCULATION) OF THE REGISTRANT ON MARCH 16, 2001, WAS
$106,280,467 BASED ON THE CLOSING PRICE PER SHARE OF THE COMMON STOCK ON SUCH
DATE.
THE NUMBER OF SHARES OF COMMON STOCK, PAR VALUE $0.234 PER SHARE, OF
REGISTRANT OUTSTANDING ON MARCH 15, 2001 WAS 12,748,612.
DOCUMENTS INCORPORATED BY REFERENCE
PORTIONS OF THE REGISTRANT'S PROXY STATEMENT FOR THE 2001 ANNUAL
MEETING OF STOCKHOLDERS, EXPECTED TO BE FILED ON OR PRIOR TO APRIL 30, 2001, ARE
INCORPORATED BY REFERENCE INTO PART III.
================================================================================
2
TABLE OF CONTENTS
PAGE
----
PART I................................................................................................1
Item 1. Business...................................................................2
Item 2. Description of Properties.................................................22
Item 3. Legal Proceedings.........................................................22
Item 4. Submission of Matters to a Vote of Security Holders.......................22
PART II..............................................................................................23
Item 5. Market for the Common Stock and Related Stockholder Matters...............23
Item 6. Selected Financial Data...................................................25
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.....................................................26
Item 7A. Quantitative and Qualitative Disclosures About Market Risk................35
Item 8. Financial Statements and Supplementary Data...............................36
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure..................................................36
PART III.............................................................................................37
Item 10. Directors and Executive Officers of the Registrant........................37
Item 11. Executive Compensation....................................................37
Item 12. Security Ownership of Certain Beneficial Owners and Management............37
Item 13. Certain Relationships and Related Transactions............................37
PART IV..............................................................................................41
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K...........41
SIGNATURE PAGE.......................................................................................45
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS..........................................................F-1
3
DEVX ENERGY, INC.
PART I
A WARNING ABOUT FORWARD-LOOKING STATEMENTS
We have made forward-looking statements in this Annual Report on Form
10-K 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:
o our oil and natural gas reserves;
o future acquisitions;
o future drilling and operations;
o future capital expenditures;
o future production of oil and natural gas; and
o future net cash flow.
You should understand that the following important factors, in addition
to those discussed elsewhere in this Annual Report on Form 10-K, 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:
o the timing and extent of changes in prices for oil and natural
gas;
o the need to acquire, develop and replace reserves;
o our ability to obtain financing to fund our business strategy;
o environmental risks;
o drilling and operating risks;
o risks related to exploitation and development projects;
o competition;
o government regulation; and
o our ability to meet our stated business goals.
We claim the protection of the safe harbor for forward-looking
statements contained in the Private Securities Litigation Reform Act of 1995 for
these statements.
You should consider these risks when you purchase our common stock and
the risks discussed in "Item 1. Business -- Risk Factors."
SUBSIDIARY REGISTRANTS
Due to requirements of the Securities and Exchange Commission, certain
subsidiaries of the parent company are also shown as co-registrants on this
Annual Report on Form 10-K. Unless otherwise stated, the information provided in
the Form 10-K describes the business, assets, financial condition and financial
results of the parent company and the consolidated subsidiaries as if they were
one entity. As used herein, references to "DevX Energy, Inc.," "us" or "we" are
to DevX Energy, Inc., a Delaware corporation, and its consolidated subsidiaries.
1
4
ITEM 1. BUSINESS
GENERAL
THE COMPANY
We are an independent energy company engaged in the exploration,
development, exploitation and acquisition of oil and natural gas properties in
conventional producing areas of North America. To date, we have grown almost
exclusively through acquisitions of properties and development drilling. As a
result of our acquisitions, we own a diverse property base concentrated in six
producing areas or basins. Approximately one-half of our proved reserves are
concentrated in south and east Texas. Our assets are primarily long-lived
natural gas properties exhibiting low operating costs.
At December 31, 2000, we owned proved reserves of approximately 130 Bcf
of natural gas and 1.4 MMBbls of oil aggregating to approximately 138 Bcfe with
an SEC PV-10 value of $534 million and a reserve life index of 12.4 years.
Approximately 67% of our proved reserves were classified as proved developed and
approximately 94% of our proved reserves were natural gas. Our average daily net
production for the 12 months ending December 31, 2000 was 30.4 MMcfe. At
December 31, 2000, we had interests in 669 wells, including 83 service wells.
We have budgeted through fiscal year ending December 31, 2001
approximately $25 million to $27 million for drilling and exploration
activities. Our EBITDA for the twelve months ended December 31, 2000 was $29.8
million at an average realized price of $3.80 per Mcfe.
We were incorporated under the laws of Delaware on May 11, 1989. Our
executive offices and mailing address are 13760 Noel Road, Suite 1030, Dallas,
Texas 75240-7336 and our telephone number at that address is 972-233-9906. On
September 18, 2000, we changed our name from Queen Sand Resources, Inc. to DevX
Energy, Inc. We also changed our fiscal year end from June 30 to December 31,
effective December 31, 2000. The information in this transition report on Form
10-K is presented on a calendar year basis covering the 12-month periods ended
December 31, unless otherwise stated.
BUSINESS STRATEGY
Our goal is to enhance shareholder value by expanding our oil and
natural gas reserves, production levels and cash flow. Our strategy to achieve
these goals consists of these elements:
o pursuing managed asset growth through:
o actively developing and exploiting our existing
higher potential oil and natural gas properties;
o selective acquisitions of high potential oil and
natural gas assets that complement our existing
properties, coupled with routine dispositions of
non-core and lower potential properties;
o an increased emphasis on exploration activities; and
o targeted merger(s) where the consolidation with other
companies will provide access to quality reserves
within our core areas;
o maintaining a capital and financial structure with prudent
debt to equity ratios that will allow us to use cash generated
from operations to fund growth in our production and reserves;
and
o maintaining a management team of senior industry executives to
assist the company in enhancing and expanding its operational
and exploration activities.
2
5
DEVELOPMENT AND EXPLOITATION OF EXISTING PROPERTIES. We have identified
over 100 proved development locations and exploitation opportunities on our
properties. We have prioritized these opportunities to concentrate on those
higher impact projects that have the potential to replace production and to grow
our reserves while maximizing the long-term return on our capital. Our
opportunities include:
o additional exploitation of well-defined locations on existing
properties such as in the J.C. Martin field in south Texas;
o in-fill drilling on our producing properties such as in the
Gilmer field in east Texas;
o recompletion of existing wells in behind-pipe intervals such
as in the Lopeno and Volpe fields in south Texas; and
o developing proved undeveloped and probable reserves by
drilling low risk, long-lived natural gas wells in the shallow
New Albany Shale formation in Kentucky.
PROPERTY ACQUISITIONS AND DIVESTITURES. We are pursuing the acquisition
of oil and natural gas properties that we believe will provide us with a
combination of increased production, reserve growth and exploration potential.
Although we are currently weighted towards natural gas reserves, we continue to
pursue opportunities for oil reserves as well as natural gas reserves. While the
acquisition market is currently very competitive, we believe that there are
opportunities to acquire high quality oil and natural gas properties with these
characteristics in the mid-continent and southwest regions of the United States,
where we have established core areas. In all property acquisitions, the company
will be seeking to become the operator. We will also continue to routinely
evaluate our portfolio of properties and periodically divest non-core or low
potential properties.
EXPLORATION. The acquisition market is currently very competitive,
especially for transactions that exceed $50 million. These properties are
generally sold on a tender bid basis which has the effect of bidding up the
price and maximizing the return to the seller. As a result, we have determined
that it is no longer prudent to rely solely on acquisitions for asset growth.
Our growth strategy has evolved from being primarily acquisition driven to a
more balanced approach with an increased emphasis on exploration opportunities.
We believe that this balanced approach will provide for a lower average reserve
replacement cost, thereby improving our financial results. In order to diversify
our exposure, we generally acquire larger interests in company-operated, low
risk projects and smaller interests in higher risk/high impact exploration
properties. Our plan is for much of our exploration effort to be conducted with
partners who bring a unique experience, expertise or ownership position in the
prospect area of interest and have a successful track record.
MERGER OPPORTUNITIES. With our substantially de-leveraged balance
sheet, stronger cash flow following the Recapitalization (see "Recent
Developments") and our long-life reserves, we are actively evaluating the
Company's fit in a consolidating industry, and considering various alternatives.
This could result in our purchasing properties or a company that would enhance
the value of the Company or in selling the Company to another company to create
immediate shareholder value.
CAPITAL AND FINANCIAL STRUCTURE. Our objective is to use a portion of
the net proceeds of our public offering of common stock (see "Recent
Developments") and internally generated cash flow to fund our exploration,
development and exploitation programs. We believe that we can finance our
acquisition opportunities at attractive costs with a combination of equity and
debt.
MANAGEMENT TEAM. During the course of fiscal 2000, we added several
seasoned senior oil and gas industry executives with experience in building
stockholder value and in the management of exploration and development projects.
We also increased the number of technical personnel during the year.
3
6
RECENT DEVELOPMENTS
THE RECAPITALIZATION. On October 31, 2000, we completed a
recapitalization (the "Recapitalization") which included: (a) a reverse stock
split of one common share for every 156 shares of our common stock; (b) the
exchange of all preferred stock then outstanding, all warrants exercisable for
shares of common stock and all unexercised common stock repricing rights for
732,500 shares of post reverse-split common stock; and (c) the repurchase of $75
million face value of our senior notes for approximately $52.5 million. Our
stockholders approved the Recapitalization at a stockholders meeting held on
September 18, 2000.
THE OFFERING. During the months of October and November 2000, we
completed the offering of an aggregate of 11,500,000 shares of post reverse
split common stock at a price to the public of $7.00 per share (the "Offering").
The sale of 10,000,000 shares under the Offering was completed on October 31,
2000, and a further 1,500,000 shares were sold to the underwriters on November
29, 2000 pursuant to the exercise of their overallotment option. The net
proceeds to the company, after deducting the underwriters' discount and offering
expenses, were approximately $73.1 million. Approximately $66.5 million of the
net proceeds of the Offering were applied to reduce debt and the remainder was
applied to working capital of the company.
As a result of the completion of the Recapitalization and the Offering,
our company:
o reduced the face value of our outstanding debt to $50 million;
o eliminated all outstanding preferred stock;
o eliminated the dilutive effects of the conversion and
repricing rights held by some of our stockholders;
o improved our liquidity by modifying the indenture governing
our senior notes to permit us to increase our senior working
capital facility from $35 million to $48.5 million; and
o enabled us to list our common stock on the Nasdaq National
Market under the trading symbol "DVXE."
MANAGEMENT TEAM AND BOARD CHANGES. Ted Collins, Jr. and Eli Rebich
resigned from the Board of Directors in May and June 2000, respectively. On
September 15, 2000, Ronald I. Benn resigned as Chief Financial Officer and was
replaced by William W. Lesikar. On October 6, 2000, Joseph T. Williams joined
the company as Chairman. On October 26, 2000, Robert L. Keiser and Jerry B.
Davis were appointed to the Board of Directors. On November 14, 2000, Patrick J.
Keeley was also appointed to the Board of Directors. On December 7, 2000, Bruce
I. Benn and Robert P. Lindsay resigned their respective positions as Executive
Vice President and Chief Operating Officer.
PRINCIPAL OIL AND NATURAL GAS PROPERTIES
As of December 31, 2000, we owned interests in 586 gross producing
wells, representing 155 net wells. The following is an overview of our major
fields, by area.
EAST TEXAS
GILMER FIELD. The Gilmer field consists of 45 natural gas wells that
cover approximately 9,030 gross acres in Upshur County in east Texas. The wells
produce from the Cotton Valley Lime formation at a depth of approximately 11,500
feet to 12,000 feet.
Goldston Oil Corporation, or Goldston, has an 80% working interest in,
and is the operator of, our wells, which are in the heart of the Gilmer field.
We own a 47.5% net profits interest in Goldston's working interest.
The Gilmer field is located on the northwestern flank of the Sabine
Uplift. The initial well in the field was drilled in 1986 and the field was
delineated over the following ten years. The reservoirs are characterized by low
permeability, depletion drive mechanisms and require stimulation. Well spacing
is currently four wells per 640-acre
4
7
block for most of the units in the field. A field dedicated treating plant and
centralized compression system provides the operator control in marketing the
natural gas.
Our average daily net production from the Gilmer field in December 2000
was approximately 10 MMcf of natural gas and 138 Bbls of oil, aggregating 10.7
MMcfe.
Seven new wells have been drilled since June 2000, an eighth well is
being drilled and ten additional proved undeveloped locations are scheduled to
be drilled. Depending upon economic conditions, the property's value could be
increased by accelerating production through additional down spacing.
SOUTH TEXAS
J.C. MARTIN FIELD. The J.C. Martin field consists of 84 producing
natural gas wells that cover approximately 8,300 gross acres in Zapata County,
Texas on the Mexican border. The field primarily produces from the Lobo 1, 3 and
6 series of sands in the Wilcox formation at depths of approximately 8,000 feet
to 10,000 feet.
Our interests consist of (a) a 13.33% perpetual, non-participating
mineral royalty interest covering the Mecom family ranch and (b) an 80% net
profits interest in Devon Energy Corporation's 20% working interest in the
ranch. Coastal Oil Corporation, or Coastal, operates all of the wells. The
reservoirs are low permeability, producing through pressure depletion and
requiring fracture stimulations. A portion of our royalty interest in this
property is the subject of litigation involving the predecessor owner. For
further description of this litigation, see "Item 3. Legal Proceedings."
Our average daily net production from the J.C. Martin field in December
2000 was 7 MMcfe.
Two new wells have been drilled since January 2001, and a third well is
being drilled. The first two wells had initial production rates of 2,300 Mcf per
day and 1,400 Mcf per day, respectively, net to our interest.
Some wells drilled since 1998 in this field tested natural gas from a
deeper Cretaceous zone, the Navarro. This zone previously had not produced on
the lease but had produced significant volumes to the north. We believe that
there may be additional potential on the Mecom Ranch for this zone as only six
wells have actually penetrated the Cretaceous zone. We also believe that
potential exists for reserves in the Middle Wilcox zones at approximately 5,000
feet to 6,000 feet.
LOPENO AND VOLPE FIELDS. The Lopeno and Volpe fields are located in
Zapata County, Texas. These fields contain 24 wells. All of the wells produce
from multiple reservoirs in the Upper Wilcox formation. Cody Energy, LLC is the
operator of the majority of the wells with Dominion Production & Exploration,
Inc. operating the remainder. We own interests in almost 4,700 gross acres in
the Lopeno and Volpe fields.
The Lopeno field is an extension of a field originally discovered in
1952. Over 20 sands have produced in the field at depths ranging from 6,500 feet
to 12,000 feet. Typical of the numerous Upper Wilcox fields along the Texas Gulf
Coast, the Lopeno field is highly faulted and overpressured. The Volpe field is
also a Wilcox field located 8 miles north of Lopeno, Texas. A well was drilled
directionally along the trapping fault and produced from the Middle Wilcox
formation. Twelve proved undeveloped locations have been identified in these
fields.
Until June 30, 2000, we owned a 66.66% net profits interest in working
interests owned by Choctaw II Oil & Gas Ltd., or Choctaw. Choctaw's working
interests vary from 15.7% to 75%. Effective June 30, 2000, we sold our net
profits interests in the Lopeno and Volpe fields, and we purchased primarily
working interests in these properties as well as some additional interests in
the Lopeno and Volpe area. As a result of this sale, our economic interest in
the Lopeno and Volpe properties has been reduced by approximately one-half and
we have converted substantially all of the remaining economic interest from net
profits interests to working interests.
Our average daily net production from the fields in December 2000 was
600 Mcfe of natural gas.
We believe that the production in these fields can be enhanced through
workovers and accelerated drilling for the shallow, behind-the-pipe reserves.
5
8
KENTUCKY
NASGAS FIELD. We own working interests ranging between 60% and 100% in
approximately 14,000 gross acres in Meade, Hardin and Breckinridge Counties,
Kentucky. There are currently 32 gross producing natural gas wells located on
our leases in Meade and Hardin Counties. These wells produce from the New Albany
Shale formation at depths of approximately 850 feet. The shale zone has two
porosity members and averages 80 feet in thickness. In addition to the natural
gas wells, we also own an interest in two salt-water disposal wells and a
related natural gas gathering system. Natural gas reserves in the New Albany
Shale formation are long-lived reserves, generally lasting over 50 years. Our
average daily net production from the Nasgas field in December 2000 was 400 Mcf.
MID-CONTINENT
We own interests in oil and gas assets located in the Texas panhandle,
Oklahoma and Kansas, collectively referred to as the mid-continent assets. The
mid-continent assets include 212 wells in 25 fields. These reserves are
concentrated in high quality fields with the value evenly distributed over
diverse, well-known reservoirs with long production histories supported by
stable production declines. These reserves are long-lived assets with a
productive life of 40 years and a reserves-to-production ratio of 15 years. An
experienced production company operates each of these properties with focused
operations in their respective areas. We own net profits overriding royalty
interests in each of these properties.
The net daily production from these properties in December 2000 was 100
Bbls and 5.8 MMcf, or 6.4 MMcfe.
EXPLORATION, DEVELOPMENT AND EXPLOITATION ACTIVITIES
During the past several months, we have entered into two exploration
joint ventures, one of which focuses primarily on west Texas/Permian Basin
opportunities and the other focuses primarily on south Texas prospects. Our
plans for the year ending December 31, 2001 call for allocating between 15% and
35% of our capital expenditures to exploration activities. Our development
drilling program is generated largely through our internal technical evaluation
efforts and as a result of our obtaining undeveloped acreage in connection with
producing property acquisitions. In addition, there are numerous opportunities
for in-fill drilling on our leases currently producing oil and natural gas. We
intend to continue to pursue development drilling opportunities which offer
potentially significant returns to us. Our exploitation activities consist of
the evaluation of additional reserves through workovers, behind-the-pipe
recompletions and secondary recovery operations.
During the year ended December 31, 2000, we participated in drilling 20
gross, or 5.3 net, wells, of which 15 gross, or 3.8 net, were productive.
However, we cannot assure you that this past rate of drilling success will
continue in the future. We are currently pursuing development drilling projects
in 6 different fields and anticipate continued growth in drilling activities.
At December 31, 2000, we had identified over 100 proved development
locations on our acreage. We expect to spend approximately $25 million to $27
million on exploration, development and exploitation projects during the fiscal
year ending December 31, 2001.
The following is a brief discussion of our primary areas of development
and exploitation activity:
EAST TEXAS
GILMER FIELD. We are currently engaged in an in-fill drilling program
at the Gilmer field. This development program began in May 2000, and we have
kept one rig drilling continuously in the field since. As of March 1, 2001, we
have completed six wells, are completing a seventh well, and are drilling an
eighth well. We believe the operator intends to keep the rig drilling in the
Gilmer field and has identified an additional 22 potential locations, 10 of
which are classified as proved undeveloped locations.
6
9
SOUTH TEXAS
J.C. MARTIN FIELD. The J.C. Martin field produces from the Lobo Trend.
Intense faulting has created many separate reservoirs that are over-pressured
and highly faulted with numerous stacked sands. A 3D seismic study over the
field has identified multiple new locations and initiated a new round of
drilling. Since we acquired our interest in 1998, 23 wells have been drilled, 5
of which were drilled in 2000. In addition to the Lobo reservoirs evaluated in
the reserve report, we believe upside potential exists in the Navarro and Middle
Wilcox zones. We recently recompleted one well in the Middle Wilcox. The deeper
Cretaceous formation, the Navarro zone, also produces in this field. Since
December 2000, we have drilled two wells, are drilling a third well, and expect
to drill three more wells this year.
LOPENO AND VOLPE FIELDS. We believe meaningful potential exists in the
Lopeno and Volpe fields to increase production. Over twenty sands have produced
in the Lopeno field and most wells have multiple behind-the-pipe zones.
Accelerated drilling for some of the shallower zones may be justified, improving
their present value. Twelve proved undeveloped locations have been identified in
the Lopeno and Volpe fields that would develop Upper Wilcox sands. We are
currently working with the operator to pursue the necessary workovers and
additional drilling.
KENTUCKY
NASGAS FIELD. We believe that the Nasgas field presents opportunities
for low cost developmental drilling at depths of less than 1,000 feet. We are in
the process of completing a 25-well drilling program, which commenced during
October 2000. We have commenced drilling operations on the first of 50
additional wells we plan to drill during 2001. These wells have long lives,
often exceeding 50 years. We anticipate our share of capital expenditures in the
Nasgas field will be approximately $7 million through December 2001.
EXPLORATION JOINT VENTURES
We have recently entered into two exploration joint ventures. Both
utilize 3-D seismic analysis to explore for potential oil and gas reservoirs.
The first agreement was signed in September 2000 and focuses primarily on the
Permian Basin in west Texas. The majority of the prospects target the Wolfcamp
formation at 6,000 feet to 8,000 feet. As of March 2001, we have participated in
seven wells with an ownership interest of between 1.3% and 27.1%, or an average
of 7.1%. Three are producing, three are waiting on completion and one was a dry
hole. We are currently negotiating a participation in two additional 3-D seismic
surveys in this area that would encompass approximately thirty square miles. We
expect our interest in additional prospects in Pecos County, Texas to range
between 10% and 15% and for prospects other than those in Pecos County to range
between 25% and 75%.
The second agreement was signed in January 2001 and focuses primarily
on the Frio and Wilcox formations in south Texas. These prospects are generally
higher reserve potential and higher risk than those in west Texas. As of March
2001, we have committed to participating in three prospects in this joint
venture. The first well is anticipated to spud prior to the end of March 2001.
We expect to participate with interests ranging between 15% and 30% in prospects
in this venture.
We expect to spend 15% to 35% of our total capital budget on
exploration activities.
MARKETING
Our oil and natural gas production is sold to various purchasers
typically in the areas where the oil or natural gas is produced. We do not
refine or process any of the oil and natural gas we produce. We are currently
able to sell, under contract or in the spot market, all of the oil and the
natural gas we are capable of producing at current market prices. Substantially
all of our oil and natural gas is sold under short term contracts or contracts
providing for periodic adjustments or in the spot market; therefore, our revenue
streams are highly sensitive to changes in current market prices. Our market for
natural gas is pipeline companies as opposed to end users. For a description of
the risks of changes in the prices for oil and natural gas, see "Item 1.
Business - Risk Factors - Risks Related to Our Business -- Our profitability is
highly dependent on the prices for oil and natural gas, which can be extremely
volatile."
7
10
In an effort to reduce the effects of the volatility of the price of
oil and natural gas on our operations and cash flow, we adopted an approach of
hedging oil and natural gas prices whenever market prices are in excess of the
prices anticipated in our operating budget and financial plan through the use of
commodity futures, options and swap agreements. We do not engage in speculative
trading. For further description of our hedging strategy, see "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations - Changes in Prices and Hedging Activities."
For the year ended December 31, 2000, Goldston Oil Corporation
accounted for approximately 31% of our oil and natural gas sales, Coastal Oil
and Gas, Inc. accounted for approximately 18% of our oil and natural gas sales,
Devon Energy Corporation accounted for approximately 13% of our oil and natural
gas sales, and Kaiser Francis Oil Company accounted for approximately 14% of our
oil and natural gas sales. We do not believe that the loss of any of these
buyers would have a material effect on our business or results of operations as
we believe we could readily locate other buyers. However, short term disruptions
could occur while we seek alternative buyers or while lines were being connected
to other pipelines.
OIL AND NATURAL GAS RESERVES
The following tables summarize information regarding our estimated
proved oil and natural gas reserves as of December 31, 1998, 1999 and 2000. All
of these reserves are located in the United States. The estimates relating to
our proved oil and natural gas reserves and future net revenues of oil and
natural gas reserves at December 31, 1998 are based on reserve reports prepared
by our internal petroleum engineers. The estimates at December 31, 1999 with
respect to the Morgan Properties included in this Annual Report on Form 10-K are
based upon reports prepared by Ryder Scott Company. The estimates at December
31, 1999 other than with respect to the Morgan Properties included in this form
are based upon reports prepared by H.J. Gruy and Associates, Inc. The estimates
at December 31, 2000 are based on reserve reports prepared by Ryder Scott
Company. In accordance with guidelines of the SEC, the estimates of future net
cash flows from proved reserves and their SEC PV-10 are made using oil and
natural gas sales prices in effect as of the dates of the estimates and are held
constant throughout the life of the properties. Our estimates of proved
reserves, future net cash flows and SEC PV-10 were estimated using the following
weighted average prices, before deduction of production taxes:
DECEMBER 31
------------------------
2000 1999 1998
------ ------ ------
Natural gas (per Mcf) $10.92 $ 2.35 $ 1.84
Oil (per Bbl) $25.88 $23.91 $10.79
Reserve estimates are imprecise, and may be expected to change as
additional information becomes available. Furthermore, estimates of oil and
natural gas reserves, of necessity, are projections based on engineering data,
and there are uncertainties inherent in the interpretation of these data as well
as the projection of future rates of production and the timing of development
expenditures. Reservoir engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured in an
exact way, and the accuracy of any reserve estimate is a function of the quality
of available data and of engineering and geological interpretation and
judgement. Reserve reports of other engineers might differ from the reports
contained herein. Results of drilling, testing and production subsequent to the
date of the estimate may justify revision of this estimate. Future prices
received for the sale of oil and natural gas may be different from those used in
preparing these reports. The amounts and timing of future operating and
development costs may also differ from those used. Accordingly, we cannot assure
you that the reserves set forth herein will ultimately be produced or can there
be assurance that the proved undeveloped reserves will be developed within the
periods anticipated. The discounted future net cash inflows should not be
construed as representative of the fair market value of the proved oil and
natural gas properties, since discounted future net cash inflows are based upon
projected cash inflows which do not provide for changes in oil and natural gas
prices nor for escalation of expenses and capital costs. The meaningfulness of
these estimates is highly dependent upon the accuracy of the assumptions upon
which they were based.
8
11
All reserves are evaluated at constant temperature and pressure, which
can affect the measurement of natural gas reserves. Operating costs, development
costs and some production-related and ad valorem taxes were deducted in arriving
at the estimated future net cash flows. No provision was made for income taxes,
and the estimates were based on operating methods and existing conditions at the
prices and operating costs prevailing at the dates indicated above. The
estimates of the SEC PV-10 from future net cash flows differ from the
Standardized Measure set forth in the notes to our consolidated financial
statements, which is calculated after provision for future income taxes. We
cannot assure you that these estimates are accurate predictions of future net
cash flows from oil and natural gas reserves or their present value.
For additional information concerning our oil and natural gas reserves
and estimates of future net revenues attributable thereto, see Note 12 of the
notes to consolidated financial statements included in this Annual Report on
Form 10-K.
COMPANY RESERVES
The following tables set forth our proved reserves of oil and natural
gas and the SEC PV-10 thereof for each year in the three-year period ended
December 31, 2000.
PROVED OIL AND NATURAL GAS RESERVES(1)
DECEMBER 31
------------------------------
2000 1999 1998
-------- -------- --------
NATURAL GAS RESERVES (MMcf):
Proved Developed Reserves 84,669 86,044 120,373
Proved Undeveloped Reserves 45,107 53,954 51,632
-------- -------- --------
Total Proved Reserves of natural gas 129,776 139,998 172,005
OIL RESERVES (MBbl):
Proved Developed Reserves 1,253 1,937 4,317
Proved Undeveloped Reserves 108 2,516 2,562
-------- -------- --------
Total Proved Reserves of oil 1,361 4,453 6,879
TOTAL PROVED RESERVES (MMcfe) 137,942 166,716 213,279
SEC PV-10 OF PROVED RESERVES(1)
DECEMBER 31
------------------------------
2000 1999 1998
-------- -------- --------
(IN THOUSANDS)
SEC PV-10(2):
Proved Developed Reserves $392,086 $ 88,007 $ 94,871
Proved Undeveloped Reserves 142,133 43,115 17,700
-------- -------- --------
TOTAL SEC PV-10 $534,219 $131,122 $112,571
- ---------
(1) The data shown at December 31, 1998 is based upon reserve reports prepared
by our internal petroleum engineers. The data shown at December 31, 1999
with respect to the Morgan Properties is based upon reserve reports
prepared by Ryder Scott Company. The estimates at December 31, 1999 other
than with respect to the Morgan Properties are based upon reserve reports
prepared by H.J. Gruy and Associates, Inc. The estimates at December 31,
2000 are based on reserve reports prepared by Ryder Scott Company.
(2) SEC PV-10 differs from the Standardized Measure set forth in the notes to
our consolidated financial statements, which is after a provision for
future income taxes. These amounts do not reflect the impact of any of our
derivative contracts used to hedge commodity price risk, as the contracts
are financial contracts and do not contemplate physical delivery of oil or
natural gas.
9
12
Except for the effect of changes in oil and natural gas prices no major
discovery or other favorable or adverse event is believed to have caused a
significant change in these estimates of our reserves since December 31, 2000.
Except for Form EIA 23, "Annual Survey of Domestic Oil and Gas
Reserves," filed with the United States Department of Energy, no other estimates
of total proven net oil and natural gas reserves have been filed by us with, or
included in any report to, any United States authority or agency pertaining to
our individual reserves since the beginning of our last fiscal year. Reserves
reported on Form EIA 23 are comparable to the reserves reported by us herein.
OPERATIONS DATA
PRODUCTIVE WELLS
The following table sets forth the number of total gross and net
productive wells in which we owned an interest as of December 31, 2000.
GROSS NET
--------------------- ---------------------
OIL GAS TOTAL OIL GAS TOTAL
----- ----- ----- ----- ----- -----
Texas 150 166 316 37.2 35.0 72.3
New Mexico 29 -- 29 28.5 -- 28.5
Oklahoma -- 153 153 -- 19.6 19.6
Kentucky -- 32 32 -- 22.4 22.4
Other(1) 2 54 56 1.4 10.8 12.1
----- ----- ----- ----- ----- -----
Total 181 405 586 67.1 87.8 154.9
===== ===== ===== ===== ===== =====
- ----------
(1) Represents wells located in Alabama, Kansas, Louisiana and Wyoming.
PRODUCTION ECONOMICS
The following table sets forth certain operating information for the
periods presented.
YEARS ENDED DECEMBER 31
------------------------------------
2000 1999 1998
---------- ---------- ----------
OPERATING DATA
PRODUCTION VOLUMES:
Natural gas (MMcf) 9,797 11,441 9,931
Oil (MBbl) 216 339 481
Total (MMcfe) 11,096 13,474 12,814
AVERAGE SALES PRICE, NET OF CASH SETTLEMENTS ON
HEDGE POSITIONS:
Natural gas (per Mcf) $ 3.69 $ 2.24 $ 2.16
Oil (per Bbl) 27.89 14.05 13.26
SELECTED EXPENSES (PER MCFE):
Production taxes $ 0.16 $ 0.08 $ 0.15
Lease operating expense, including ad
valorem taxes 0.55 0.39 0.66
General and administrative 0.41 0.27 0.19
Depreciation, depletion and amortization (1) 0.77 0.68 0.79
- ----------
(1) Represents depreciation, depletion and amortization of oil and natural gas
properties only.
10
13
DRILLING ACTIVITY
The following table sets forth our gross and net working interests in
exploratory and development wells (but excluding injection or service wells)
drilled during the indicated periods.
YEARS ENDED DECEMBER 31
----------------------------------------------
2000 1999 1998
------------- ------------- -------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
EXPLORATORY:
Oil 2 0.2 1 0.2 -- --
Natural gas 1 -- -- -- -- --
Dry 2 1.0 1 1.0 -- --
----- ----- ----- ----- ----- -----
Total 5 1.2 2 1.2 -- --
DEVELOPMENT:
Oil 1 0.8 -- -- 5 2.0
Natural gas 11 2.8 9 1.9 33 11.7
Dry 3 0.5 1 0.5 2 1.2
----- ----- ----- ----- ----- -----
Total 15 4.1 10 2.4 40 14.9
TOTAL:
Oil 3 1.0 1 0.2 5 2.0
Natural gas 12 2.8 9 1.9 33 11.7
Dry 5 1.5 2 1.5 2 1.2
----- ----- ----- ----- ----- -----
Total 20 5.3 12 3.6 40 14.9
Since December 31, 2000, we have successfully drilled 6 gross, 1.2 net,
wells, through March 1, 2001. At March 1, 2001, we were in the process of
drilling 29 gross, 26.0 net, wells.
DEVELOPED AND UNDEVELOPED ACREAGE
The following table sets forth the approximate gross and net acres in
which we owned an interest as of December 31, 2000.
DEVELOPED UNDEVELOPED
----------------- -----------------
GROSS NET GROSS NET
------- ------- ------- -------
Texas 47,203 13,777 6,497 1,300
New Mexico 14,280 14,126 -- --
Louisiana 302 302 6,081 3,315
Oklahoma 37,440 5,336 -- --
Kentucky 636 428 13,886 12,748
Other(1) 20,510 5,190 -- --
------- ------- ------- -------
Total 120,371 39,159 26,464 17,363
======= ======= ======= =======
- ----------
(1) Represents acreage located in Alabama, Colorado, Kansas, and Wyoming.
MARKETS AND COMPETITION
The oil and natural gas industry is highly competitive. Our competitors
include major oil companies, other independent oil and natural gas concerns and
individual producers and operators, many of which have financial resources,
staffs and facilities substantially greater than ours. In addition, we encounter
substantial competition in acquiring oil and natural gas properties, marketing
oil and natural gas and hiring trained personnel. When possible, we try to avoid
open competitive bidding for acquisition opportunities. The principal means of
competition with respect to the sale of oil and natural gas production are
product availability and price. While it is not possible for us to state
accurately our position in the oil and natural gas industry, we believe that we
represent a minor competitive factor.
11
14
The market for our oil and natural gas production depends on factors
beyond our control, including domestic and foreign political conditions, the
overall level of supply of and demand for oil and natural gas, the price of
imports of oil and natural gas, access to natural gas pipelines and other
transportation facilities and overall economic conditions. The oil and gas
industry also competes with other industries in supplying the energy and fuel
requirements of industrial, commercial and individual consumers.
TITLE TO OIL AND NATURAL GAS PROPERTIES
We have acquired interests in producing and non-producing acreage in
the form of working interests, royalty interests, overriding royalty interests
and net profits interests. Substantially all of our property interests, and the
assignors' interests in the working or other interests in the underlying
properties, are held pursuant to leases from third parties. The leases grant the
lessee the right to explore for and extract oil and natural gas from specified
areas. Consideration for these leases usually consists of a lump sum payment,
such as a bonus, and a fixed annual charge, such as a delay rental, prior to
production unless the lease is paid up and, once production has been
established, a royalty based generally upon either the proceeds from the sale of
oil and natural gas or the market value of oil and natural gas produced. Once
wells are drilled, a lease generally continues so long as production of oil and
natural gas continues. In some cases, leases may be acquired in exchange for a
commitment to drill or finance the drilling of a specified number of wells to
predetermined depths. Some of our non-producing acreage is held under leases
from mineral owners or governmental entities which expire at varying dates. We
are obligated to pay annual delay rentals to the lessors of some properties in
order to prevent the leases from terminating. Title to leasehold properties is
subject to royalty, overriding royalty, carried, net profits and other similar
interests and contractual arrangements customary in the oil and natural gas
industry, and to liens incident to operating agreements, liens relating to
amounts owed to the operator, liens for current taxes not yet due and other
encumbrances.
As is customary in the industry, we generally acquire oil and natural
gas acreage without any warranty of title except as to claims made by, through
or under the transferor. Although we have title examined prior to acquisition of
developed acreage in those cases in which the economic significance of the
acreage justifies the cost, there can be no assurance that losses will not
result from title defects or from defects in the assignment of leasehold rights.
In many instances, title opinions may not be obtained if in our judgment it
would be uneconomical or impractical to do so.
The underlying properties are typically subject, in one degree or
another, to one or more of the following:
o royalties and other burdens and obligations, expressed and
implied, under oil and gas leases;
o overriding royalties and other burdens created by the assignor
or its predecessors in title;
o a variety of contractual obligations, including, in some
cases, development obligations, arising under operating
agreements, farmout agreements, production sales contracts and
other agreements that may affect the properties or their
titles;
o liens that may arise in the normal course of operations, such
as those for unpaid taxes, statutory liens securing unpaid
suppliers and contractors and contractual liens under
operating agreements;
o pooling, unitization and communitization agreements,
declarations and orders; and
o easements, restrictions, rights-of-way and other matters that
commonly affect property.
To the extent that these burdens and obligations affect the assignor's
rights to production and the value of production from the underlying properties,
they have been taken into account in calculating our interests and in estimating
the size and value of the reserves attributable to our net profits interests and
royalty interests.
A substantial portion of our oil and natural gas property interests is
in the form of non-operated, net profits interests and royalty interests. The
net profits interests were conveyed to us by various assignors from the
assignor's net revenue interests in the oil and natural gas properties burdened
by the net profits interests and royalty interests (the
12
15
"underlying properties"). The assignors' net revenue interests are generally
leasehold working interests less lease burdens.
NET PROFITS INTERESTS. As the owner of net profits interests, we do not
have the direct right to drill or operate wells or to cause third parties to
propose or drill wells on the underlying properties. If an assignor or any other
working interest owner proposes to drill wells on one of the underlying
properties, then that assignor must give us notice of the proposal. Under an
agreement covering the underlying property, we have the option to pay a
specified percentage of the assignor's working interest share of the expenses of
the well that is proposed. We would then become entitled to a net profits
interest equal to the specified percentage multiplied by the assignor's net
revenue interest in that well. However, if an assignor elects not to participate
in the drilling of a well, we will not be able to participate in that well.
Moreover, if an assignor owns less than a 100% working interest in a proposed
well, and the other owners of working interests in that well elect not to
participate in the well, the well will not be drilled unless the money to pay
the costs allocable to the working interest owners who do not elect to
participate in the well is obtained. The financial strength and the competence
of the various assignors, and to a lesser extent the financial strength and the
competence of other parties owning working interests in the underlying
properties, may have an effect on when and whether wells get drilled on the
underlying properties, and on whether operations are conducted in a prudent and
competent manner.
ROYALTY INTERESTS. The royalty interests are generally in the form of
term royalty interests. The duration of these interests is the same as the
underlying oil and natural gas lease. Some of the royalty interests are
perpetual royalty interests which entitle the owner to a share of production
from the underlying properties under both the current oil and natural gas lease
and any replacement or successor oil and natural gas lease. In all cases, the
royalty interests are non-operating interests, have little or no influence over
oil and natural gas development or operation on the lands they burden but have
limited cost bearing responsibilities.
SALE AND ABANDONMENT OF UNDERLYING PROPERTIES. An assignor has the
right to abandon any well or working interest included in the underlying
properties if, in its opinion, the well or property ceases to produce or is not
capable of producing oil or natural gas in commercially paying quantities. We
may not control the timing of plugging and abandoning wells. The conveyances
provide that the assignor's working interest share of the costs of plugging and
abandoning uneconomic wells are deducted in calculating our net cash flow from
the underlying property.
The assignor can sell the underlying properties, subject to and
burdened by the royalty interests, without our consent. Accordingly, the
underlying properties could be transferred to a party with a weaker financial
profile.
REGULATION
GENERAL FEDERAL AND STATE REGULATION
Our oil and natural gas exploration, production and related operations
are subject to extensive rules and regulations promulgated by federal and state
agencies. Failure to comply with these rules and regulations can result in
substantial penalties. The regulatory burden on the oil and natural gas industry
increases our cost of doing business and affects our profitability. Because
these rules and regulations are frequently amended or reinterpreted, we are
unable to predict the future cost or impact of complying with these laws.
The State of Texas and many other states require permits for drilling
operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration and production of oil and natural gas.
Many states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and natural gas
properties, the establishment of maximum rates of production from wells, and the
regulation of spacing, plugging and abandonment of these wells. Many states
restrict production to the market demand for oil and natural gas. Some states
have enacted statutes prescribing ceiling prices for natural gas sold within
their boundaries.
The Federal Energy Regulatory Commission, or FERC, regulates interstate
natural gas transportation rates and service conditions, which affect the
revenues received by us for sales of our production. Since the mid-1980s, FERC
has issued a series of orders, culminating in Order Nos. 636, 636-A and 636-B,
or Order 636, that have significantly altered the marketing and transportation
of natural gas. Order 636 mandates a fundamental restructuring of interstate
pipeline
13
16
sales and transportation service, including the unbundling by interstate
pipelines of the sale, transportation, storage and other components of the
city-gate sales services the pipelines previously performed. One of FERC's
purposes in issuing the orders is to increase competition within all phases of
the natural gas industry. Order 636 and subsequent FERC orders on rehearing have
been appealed and are pending judicial review. Because these orders may be
modified as a result of the appeals, it is difficult to predict the ultimate
impact of the orders on us. Generally, Order 636 has eliminated or substantially
reduced the traditional role of intrastate pipelines as wholesalers of natural
gas, and has substantially increased competition and volatility in natural gas
markets.
The price we receive from the sale of oil and natural gas liquids is
affected by the cost of transporting products to market. Effective January 1,
1995, FERC implemented regulations establishing an indexing system for
transportation rates for oil pipelines, which, generally, would index these
rates to inflation, subject to some conditions and limitations.
Finally, from time to time regulatory agencies have imposed price
controls and limitations on production by restricting the rate of flow of oil
and natural gas wells below natural production capacity in order to conserve
supplies of oil and natural gas.
ENVIRONMENTAL REGULATION
The exploration, development and production of oil and natural gas,
including the operation of saltwater injection and disposal wells, are subject
to various federal, state and local environmental laws and regulations. These
laws and regulations can increase the costs of planning, designing, installing
and operating oil and natural gas wells. Our domestic activities are subject to
a variety of environmental laws and regulations, including but not limited to,
the Oil Pollution Act of 1990, or OPA, the Clean Water Act, or CWA, the
Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA,
the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or CAA,
and the Safe Drinking Water Act, or SDWA, as well as state regulations
promulgated under comparable state statutes. We are also subject to regulations
governing the handling, transportation, storage and disposal of naturally
occurring radioactive materials that are found in our oil and natural gas
operations. Civil and criminal fines and penalties may be imposed for
non-compliance with these environmental laws and regulations. Additionally,
these laws and regulations require the acquisition of permits or other
governmental authorizations before undertaking some activities, limit or
prohibit other activities because of protected areas or species, and impose
substantial liabilities for cleanup of pollution.
Under the OPA, a release of oil into water or other areas designated by
the statute could result in our being held responsible for the costs of
remediating the release, OPA specified damages, and natural resource damages.
The extent of that liability could be extensive, as set forth in the statute,
depending on the nature of the release. A release of oil in harmful quantities
or other materials into water or other specified areas could also result in our
being held responsible under the CWA for the costs of remediation, and any civil
and criminal fines and penalties.
CERCLA and comparable state statutes, also known as "Superfund" laws,
can impose joint and several retroactive liability, without regard to fault or
the legality of the original conduct, on specified classes of persons for the
release of a "hazardous substance" into the environment. In practice, cleanup
costs are usually allocated among various responsible parties. Potentially
liable parties include site owners or operators, past owners or operators under
certain conditions, and entities that arrange for the disposal or treatment of,
or transport hazardous substances found at the site. Although CERCLA, as
amended, currently exempts petroleum, including but not limited to, oil, natural
gas and natural gas liquids from the definition of hazardous substance, our
operations may involve the use or handling of other materials that may be
classified as hazardous substances under CERCLA. Furthermore, there can be no
assurance that the exemption will be preserved in future amendments of CERCLA,
if any.
RCRA and comparable state and local requirements impose standards for
the management, including treatment, storage, and disposal of both hazardous and
nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in
connection with our routine operations. From time to time, proposals have been
made that would reclassify certain oil and natural gas wastes, including wastes
generated during pipeline, drilling, and production operations, as "hazardous
wastes" under RCRA which would make these solid wastes subject to much more
stringent handling, transportation, storage, disposal, and clean-up
requirements. This development could have a significant impact on our
14
17
operating costs. While state laws vary on this issue, state initiatives to
further regulate oil and natural gas wastes could have a similar impact.
Oil and natural gas exploration and production, and possibly other
activities, have been conducted at some of our properties by previous owners and
operators. Materials from these operations remain on some of the properties and
in some instances require remediation. In addition, we have agreed to indemnify
sellers of producing properties from whom we have acquired reserves against
certain liabilities for environmental claims associated with these properties.
While we do not believe that costs to be incurred by us for compliance with
environmental regulations and remediating previously or currently owned or
operated properties will be material, there can be no guarantee that these costs
will not result in material expenditures.
Additionally, in the course of our routine oil and natural gas
operations, surface spills and leaks, including casing leaks, of oil or other
materials occur, and we incur costs for waste handling and environmental
compliance. Moreover, we are able to control directly the operations of only
those wells for which we act as the operator. Notwithstanding our lack of
control over wells owned by us but operated by others, the failure of the
operator to comply with the applicable environmental regulations may, in certain
circumstances, be attributable to us.
It is not anticipated that we will be required in the near future to
expend amounts that are material in relation to our total capital expenditures
program by reason of environmental laws and regulations, but inasmuch as these
laws and regulations are frequently changed, we are unable to predict the
ultimate cost of compliance. There can be no assurance that more stringent laws
and regulations protecting the environment will not be adopted or that we will
not otherwise incur material expenses in connection with environmental laws and
regulations in the future. For a description of the risks associated with
environmental regulations, see "- Risk Factors."
EMPLOYEES
As of March 6, 2001, we had 21 full-time employees consisting of 6
officers and 15 support staff. Three of the employees are based in Ottawa,
Canada, 16 of the employees are located in the Dallas office, and 2 are on site
in Kentucky. In addition, we regularly engage technical consultants and
independent contractors to provide specific advice or to perform administrative
or technical functions.
RISK FACTORS
RISKS RELATED TO OUR BUSINESS
WE HAVE IN THE PAST EXPERIENCED NET LOSSES AND WE MAY EXPERIENCE NET LOSSES IN
THE FUTURE, WHICH COULD MATERIALLY ADVERSELY AFFECT OUR RESULTS OF OPERATIONS.
Between the time we began operations in 1994 and December 31, 1999, we
were not profitable on an annual basis. We experienced a net loss from
continuing operations of approximately $71.1 million for the year ended December
31, 1998, and a net loss from continuing operations of approximately $10.7
million for the year ended December 31, 1999. For the year ended December 31,
2000, we had income from continuing operations of approximately $2.7 million. We
may experience net losses in the future as we continue to incur significant
operating expenses and to make capital expenditures. We may not sustain or
increase profitability on a quarterly or annual basis in the future. At October
31, 2000, we eliminated an accumulated deficit of approximately $68.1 million in
connection with a quasi-reorganization.
15
18
OUR PROFITABILITY IS HIGHLY DEPENDENT ON THE PRICES FOR OIL AND NATURAL GAS,
WHICH CAN BE EXTREMELY VOLATILE.
Our revenues, profitability and future growth substantially depend on
prevailing prices for oil and natural gas. Prices for oil and natural gas can be
extremely volatile. Among the factors that can cause this volatility are:
o weather conditions;
o the level of consumer product demand;
o domestic and foreign governmental regulations;
o the price and availability of alternative fuels;
o political conditions in oil and natural gas producing regions;
o the domestic and foreign supply of oil and natural gas;
o the availability, proximity and capacity of gathering systems
of natural gas;
o the price of foreign imports; and
o overall economic conditions.
Prices for oil and natural gas affect the amount of cash flow available
to us for capital expenditures and the repayment of our outstanding debt. Our
ability to maintain or increase our borrowing capacity and to obtain additional
capital on attractive terms is also substantially dependent upon oil and natural
gas prices. In addition, because we currently produce more natural gas than oil,
we face more risk with fluctuations in the price of natural gas than oil. We
have used hedging contracts to reduce our exposure to price changes.
HEDGING OUR PRODUCTION MAY CAUSE US TO FOREGO FUTURE PROFITS.
To reduce our exposure to changes in the prices of oil and natural gas,
we have entered into and may in the future enter into hedging arrangements for a
portion of our oil and natural gas production. The hedges that we have entered
into generally provide a "floor" or "cap and floor" on the prices paid for our
oil and natural gas production over a period of time. Hedging arrangements may
expose us to the risk of financial loss in some circumstances, including the
following:
o the other party to the hedging contract defaults on its
contract obligations; or
o there is a change in the expected differential between the
underlying price in the hedging agreement and actual prices
received.
Reduced revenues resulting from our hedging activities could have an
adverse effect on our financial condition and operations. For the year ended
December 31, 2000, our revenues were reduced by $3.5 million as a result of cash
settlements made under our existing hedge contracts. We may have to make
additional payments under these contracts in the future depending on the
difference between actual and hedged prices of oil and natural gas. In addition,
these hedging arrangements may limit the benefit we would otherwise receive from
increases in the prices for oil and natural gas.
Some of our hedging arrangements contain a "cap" whereby we must pay
the counter-party if oil or natural gas prices exceed the price specified in the
contract. We are required to maintain letters of credit with our
counter-parties, and we may be required to provide additional letters of credit
if prices for oil and natural gas futures increase above the "cap" prices. The
amount of these letters of credit is a function of the market value of oil and
natural gas prices and the volumes of oil and natural gas subject to the
contract. As a result, the value of these letters of credit will fluctuate with
the market prices of oil and natural gas. These letters of credit are issued
pursuant to our credit agreement and as a result utilize some of our borrowing
capacity, reducing funds available to be borrowed under our credit agreement.
IF WE ARE NOT ABLE TO REPLACE DEPLETED RESERVES, OUR FUTURE RESULTS OF
OPERATIONS WILL BE ADVERSELY AFFECTED.
The rate of production from oil and natural gas properties declines as
reserves are depleted. Our proved reserves will decline as reserves are produced
unless we acquire additional properties containing proved reserves, conduct
successful exploration, development and exploitation activities on new or
currently leased properties or identify additional formations with primary or
secondary reserve opportunities on our properties. If we are not successful in
16
19
expanding our reserve base, our future oil and natural gas production, the
primary source of our revenues, will be adversely affected. The level of our
future oil and natural gas production and our results of operations are
therefore highly dependent on the level of our success in finding and acquiring
additional reserves. Our ability to find and acquire additional reserves depends
on our generating sufficient cash flow from operations and other sources of
capital, including borrowings under our credit agreement. We cannot assure you
that we will have sufficient cash flow or cash from other sources to expand our
reserve base. Our ability to continue acquiring producing properties or
companies that own producing properties assumes that major integrated oil
companies and independent oil companies will continue to divest many of their
oil and natural gas properties. We cannot assure you that these divestitures
will continue or that we will be able to acquire producing properties at
acceptable prices.
WE MAY HAVE DIFFICULTY FINANCING OUR PLANNED GROWTH AND CAPITAL EXPENDITURES.
We have experienced and expect to continue to experience substantial
capital expenditure and working capital needs as a result of our exploration,
development, exploitation and acquisition strategy. In the future, we may
require financing, in addition to cash generated from our operations and the
proposed offering of our common stock, to fund our planned growth and capital
expenditures. Over the past two years, we have experienced constraints on our
ability to arrange additional capital to fund our business plan.
Although we were able to borrow an additional $35 million under our
credit agreement as of March 6, 2001, our lenders could reduce our borrowing
limit. If additional capital resources are unavailable, we will be unable to
grow our business and we may curtail our drilling, development and other
activities or be forced to sell some of our assets on an untimely or unfavorable
basis.
RESTRICTIVE DEBT COVENANTS LIMIT OUR ABILITY TO FINANCE OUR OPERATIONS, FUND OUR
CAPITAL NEEDS AND ENGAGE IN OTHER BUSINESS ACTIVITIES THAT MAY BE IN OUR
INTEREST.
Our credit agreement and the indenture governing our 12 1/2% senior
notes due 2008 contain significant covenants that, among other things, restrict
our ability to:
o dispose of assets;
o incur additional indebtedness;
o repay other indebtedness;
o pay dividends;
o enter into specified investments or acquisitions;
o repurchase or redeem capital stock;
o merge or consolidate; or
o engage in specified transactions with subsidiaries and
affiliates and our other corporate activities.
Also, our credit agreement requires us to maintain compliance with the financial
ratios included in that agreement. Our ability to comply with these ratios may
be affected by events beyond our control. A breach of any of these covenants or
our inability to comply with the required financial ratios could result in a
default under our credit agreement.
We have in the past been in default of some covenants under our
previous credit agreement. All of these defaults were waived by the lenders.
However, if we default under our current credit agreement, our lender may
declare all amounts borrowed under the credit agreement, together with accrued
interest, to be due and payable. If we do not repay the indebtedness promptly,
our lender could then foreclose against any collateral securing the payment of
the indebtedness. Substantially all of our oil and natural gas interests secure
our credit agreement.
OUR ABILITY TO GENERATE SUFFICIENT CASH TO SERVICE OUR DEBT AND REPLACE OUR
RESERVES DEPENDS ON MANY FACTORS BEYOND OUR CONTROL.
We rely on cash from our operations to pay the principal and interest
on our debt. Our ability to generate cash from operations depends on the level
of production from our properties, general economic conditions, including the
prices paid for oil and natural gas, success in our exploration, development and
exploitation activities, and legislative,
17
20
regulatory, competitive and other factors beyond our control. Our operations may
not generate enough cash to pay the principal and interest on our debt.
WE CANNOT ASSURE YOU THAT WE WILL BE SUCCESSFUL IN MANAGING OUR GROWTH.
The success of our future growth will depend on a number of factors,
including:
o our ability to timely explore, develop and exploit acquired
properties;
o our ability to continue to attract and retain skilled
personnel;
o our ability to continue to expand our technical, operational
and administrative resources; and
o the results of our drilling program.
Our growth could strain our financial, technical, operational and
administrative resources. Our failure to successfully manage our growth could
adversely affect our operations and net revenues through increased operating
costs and revenues that do not meet our expectations.
WE MAY PURCHASE OIL AND NATURAL GAS PROPERTIES WITH LIABILITIES OR RISKS WE DID
NOT KNOW ABOUT OR THAT WE DID NOT CORRECTLY ASSESS, AND, AS A RESULT, WE COULD
BE SUBJECT TO LIABILITIES THAT COULD ADVERSELY AFFECT OUR RESULTS OF OPERATIONS.
We evaluate and pursue acquisition opportunities, primarily in the
mid-continent and southwest regions of the United States. Before acquiring oil
and natural gas properties, we estimate the recoverable reserves, future oil and
natural gas prices, operating costs, potential environmental and other
liabilities and other factors relating to the properties. We believe our method
of review is generally consistent with industry practices. However, our review
involves many assumptions and estimates, and their accuracy is inherently
uncertain. As a result, we may not discover all existing or potential problems
associated with the properties we buy. We may not become sufficiently familiar
with the properties to fully assess their deficiencies and capabilities. We do
not generally perform inspections on every well, and we may not be able to
observe mechanical and environmental problems even when we conduct an
inspection. Even if we identify problems, the seller may not be willing or
financially able to give contractual protection against these problems, and we
may decide to assume environmental and other liabilities in connection with
acquired properties. If we acquire properties with risks or liabilities we did
not know about or that we did not correctly assess, our financial condition and
results of operations could be adversely affected.
THE OIL AND GAS BUSINESS INVOLVES MANY OPERATING RISKS THAT COULD CAUSE
SUBSTANTIAL LOSSES.
Drilling activities involve the risk that no commercially productive
oil or natural gas reservoirs will be found or produced. We may drill or
participate in new wells that are not productive. We may drill wells that are
productive but that do not produce sufficient net revenues to return a profit
after drilling, operating and other costs. Whether a well is productive and
profitable depends on a number of factors, including the following, many of
which are beyond our control:
o general economic and industry conditions, including the prices
received for oil and natural gas;
o mechanical problems encountered in drilling wells or in
production activities;
o problems in title to our properties;
o weather conditions which delay drilling activities or cause
producing wells to be shut down;
o compliance with governmental requirements; and
o shortages in or delays in the delivery of equipment and
services.
If we do not drill productive and profitable wells in the future, our
financial condition and results of operations could be materially and adversely
affected due to decreased cash flow and net revenues.
18
21
In addition to the substantial risk that we may not drill productive
and profitable wells, the following hazards are inherent in oil and natural gas
exploration, development, exploitation, production and gathering, including:
o unusual or unexpected geologic formations;
o unanticipated pressures;
o mechanical failures;
o blowouts where oil or natural gas flows uncontrolled at a
wellhead;
o cratering or collapse of the formation;
o explosions;
o pollution; and
o environmental accidents such as uncontrollable flows of oil,
natural gas or well fluids into the environment, including
groundwater contamination.
We could suffer substantial losses from these hazards due to injury and
loss of life, severe damage to and destruction of property and equipment,
pollution and other environmental damage and suspension of operations. We carry
insurance that we believe is in accordance with customary industry practices for
companies of our size. However, we do not fully insure against all risks
associated with our business either because this insurance is not available or
because we believe the cost is prohibitive. The occurrence of an event that is
not covered, or not fully covered by insurance, could have a material adverse
effect on our financial condition and results of operations.
OUR EXPLORATION ACTIVITIES INVOLVE A HIGH DEGREE OF RISK AND MAY NOT BE
COMMERCIALLY SUCCESSFUL.
Oil and natural gas exploration involves a high degree of risk that
hydrocarbons will not be found, that they will not be found in commercial
quantities, or that their production will be insufficient to recover drilling,
completion and operating costs. The 3-D seismic data and other technologies we
may use do not allow us to know conclusively prior to drilling a well that oil
or natural gas is present or economically producible. The cost of drilling,
completing and operating a well is often uncertain, and cost factors can
adversely affect the economics of a project. Furthermore, completion of a well
does not guarantee that it will be profitable or even that it will result in
recovery of drilling, completion and operating costs. Therefore, we may not earn
revenues with respect to, or recover costs spent on, our exploration activities.
WE CANNOT CONTROL THE DEVELOPMENT OF A SUBSTANTIAL PORTION OF OUR PROPERTIES
BECAUSE OUR INTERESTS ARE IN THE FORM OF NON-OPERATED NET PROFITS INTERESTS AND
OVERRIDING ROYALTY INTERESTS.
A substantial portion of our oil and natural gas property interests are
in the form of non-operated, net profits interests and royalty interests. As the
owner of non-operated net profits interests and royalty interests, we do not
have the direct right to drill or operate wells or to cause third parties to
propose or drill wells on the underlying properties. As a result, the success
and timing of our drilling and development activities on those properties
operated by others depend upon a number of factors outside of our control,
including:
o the timing and amount of capital expenditures;
o the operator's expertise and financial resources;
o the approval of other participants in drilling wells; and
o the selection of suitable technology.
If the operators of these properties do not conduct drilling and
development activities on these properties, then our results of operations may
be adversely affected.
WE MAY LOSE TITLE TO OUR ROYALTY INTEREST IN THE J.C. MARTIN FIELD AS A RESULT
OF LITIGATION OVER TITLE TO THE ROYALTY INTEREST.
A portion of our landowner royalty on the J.C. Martin field, which
comprises approximately 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
19
22
to our royalty interest. A favorable order of summary judgment has been rendered
in favor of the pension funds managed by the entity that sold us the properties.
The order has been appealed. Eight million dollars of the purchase price we paid
for the Morgan Properties, which include our royalty interest in the J.C. Martin
field, are currently in escrow pending the resolution of this lawsuit. If the
summary judgment is overturned and a final judgment is later entered against the
entity 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
to the plaintiff our royalty interest in the J.C. Martin field and the net
proceeds received by us since the date we acquired our interest.
IF A BANKRUPTCY COURT TREATS ANY OF OUR NET PROFITS INTERESTS AS CONTRACT RIGHTS
INSTEAD OF REAL PROPERTY INTERESTS, WE COULD LOSE ALL OF THE VALUE OF THOSE
INTERESTS.
We cannot assure you whether a court in the states of Kansas and
Oklahoma would treat the net profits interests as contract rights or real
property interests. Our net profits interests in these states comprise 14% of
our SEC-PV-10 as of December 31, 2000. If any of the assignors become involved
in bankruptcy proceedings in these states, we face the risk that our net profits
interests might be treated by a bankruptcy court as contract rights instead of
real property interests. If the bankruptcy court treats our net profits
interests as contract rights, then we would be treated as an unsecured creditor
in the bankruptcy, and under the terms of the bankruptcy plan, we could lose all
of the value of the net profits interests. If the bankruptcy court treats the
net profits interests as real property interests, then our interests should not
be materially affected.
ANY NEGATIVE VARIANCE IN OUR ESTIMATES OF PROVED RESERVES AND FUTURE NET
REVENUES COULD AFFECT THE CARRYING VALUE OF OUR ASSETS, OUR INCOME AND OUR
ABILITY TO BORROW FUNDS.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and the timing of
development expenditures, including many factors beyond our control. The reserve
data included in this report represent only estimates. In addition, the
estimates of future net revenue from proved reserves and their present value are
based on assumptions about future production levels, prices and costs that may
not prove to be correct over time. In particular, estimates of oil and natural
gas reserves, future net revenue from proved reserves and the present value of
proved reserves for the oil and natural gas properties described in this report
are based on the assumption that future oil and natural gas prices remain the
same as oil and natural gas prices at December 31, 2000. The NYMEX prices as of
December 31, 2000, used for purposes of our estimates were $26.83 per Bbl of
NYMEX Light Sweet Crude and $10.415 per MMbtu for Henry Hub natural gas. Any
significant variance in actual results from these assumptions could also
materially affect the estimated quantity and value of our reserves.
WE MAY BE REQUIRED TO WRITE DOWN THE CARRYING VALUE OF OUR PROVED PROPERTIES
UNDER ACCOUNTING RULES AND THESE WRITE-DOWNS COULD ADVERSELY AFFECT OUR
FINANCIAL CONDITION.
There is a risk that we will be required to write-down the carrying
value of our oil and natural gas properties when oil and natural gas prices are
low. In addition, write-downs may occur if we have:
o downward adjustments to our estimated proved reserves,
o increases in our estimates of development costs or
o deterioration in our exploration and exploitation results.
We periodically review the carrying value of our oil and natural gas
properties under the full cost accounting rules of the Securities and Exchange
Commission. Under these rules, the net capitalized costs of oil and natural gas
properties may not exceed a ceiling limit that is based on the present value,
based on flat prices at a single point in time, of estimated future net revenues
from proved reserves, discounted at 10%. If net capitalized costs of oil and
natural gas properties exceed the ceiling limit, we must charge the amount of
this excess to earnings in the quarter in which the excess occurs. At June 30,
1998, we were required to write down the carrying value of our oil and natural
gas properties by $28.2 million. At December 31, 1998, we were required to write
down the carrying value of our oil and natural gas properties by an additional
$35 million. We may not reverse write-downs even if prices increase in
subsequent periods. A write-down does not affect cash flow from operating
activities, but it does reduce the book value of our net tangible assets and
stockholders' equity.
20
23
IF WE ARE UNABLE TO COMPETE EFFECTIVELY AGAINST OTHER OIL AND GAS COMPANIES, WE
MAY BE UNABLE TO ACQUIRE NEW PROPERTIES AT ATTRACTIVE PRICES OR TO SUCCESSFULLY
DEVELOP OUR PROPERTIES.
We encounter strong competition from other oil and gas companies in
acquiring properties and leases for the exploration, exploitation and production
of oil and natural gas. Many of our competitors have financial resources, staff
and facilities substantially greater than ours. Our competitors may be able to
pay more for desirable leases and to evaluate, bid for and purchase a greater
number of properties or prospects than our financial or personnel resources will
permit. As a result, we may not be able to buy properties at affordable prices
or to successfully develop our properties. Our ability to explore, develop and
exploit oil and natural gas reserves and to acquire additional properties in the
future will depend on our ability to conduct operations, to evaluate and select
suitable properties and to consummate transactions in this highly competitive
environment.
WE ARE SUBJECT TO GOVERNMENT REGULATION AND LIABILITY, INCLUDING ENVIRONMENTAL
LAWS THAT COULD REQUIRE SIGNIFICANT EXPENDITURES AND COULD MATERIALLY DECREASE
OUR NET INCOME.
The exploration, development, exploitation, production and sale of oil
and natural gas in the U.S. are subject to many federal, state and local laws
and regulations, including environmental laws and regulations. Under these laws
and regulations, we may be required to make large expenditures that could
materially and adversely affect our results of operations. These expenditures
could include payments for personal injuries, property damage, oil spills, the
discharge of hazardous materials, remediation and clean-up costs and other
environmental damages. While we maintain insurance coverage for our operations,
we do not believe that full insurance coverage for all potential environmental
damages is available at a reasonable cost. Failure to comply with these laws and
regulations also may result in the suspension or termination of our operations
and subject us to administrative, civil and criminal penalties. Laws and
regulations protecting the environment have become increasingly stringent in
recent years and may impose liability on us for environmental damage and
disposal of hazardous materials even if we were not negligent or at fault. We
may also be liable for the conduct of others or for our own acts even if our
acts complied with applicable laws at the time we performed those acts.
RISKS RELATING TO OUR COMMON STOCK
IF WE DO NOT MAINTAIN THE LISTING OF OUR COMMON STOCK ON THE NASDAQ NATIONAL
MARKET OR ANY OTHER STOCK EXCHANGE, THE PRICE OF THE COMMON STOCK MAY BE
DEPRESSED AND YOU MAY HAVE DIFFICULTIES RESELLING THE STOCK.
On October 26, 2000, our common stock was listed for trading on the
Nasdaq National Market under the trading symbol "DVXE." In order to maintain our
listing on the National Market we must continue to meet certain minimum net
tangible asset base, minimum market capitalization and minimum trading price
thresholds. Failure to maintain the listing of our common stock on the Nasdaq
National Market or any other stock exchange could negatively affect the
liquidity and marketability of the common stock. We were delisted from the
Nasdaq Small Cap Market on November 11, 1999 due to our failure to satisfy
certain listing requirements.
IF THERE IS A CHANGE OF CONTROL OF THE COMPANY, WE WOULD BE IN DEFAULT UNDER OUR
CREDIT AGREEMENT AND WE COULD BE REQUIRED TO REPURCHASE OUR SENIOR NOTES.
If there is a change of control of our company as defined in our credit
agreement, we would be in default under our credit agreement. In addition, the
indenture governing our senior notes contains provisions that, under some
circumstances, will cause our senior notes to become due upon the occurrence of
a change of control as defined in the indenture. If a change of control occurs,
we may not have the financial resources to repay this indebtedness and would be
in default under the indenture. These provisions could also make it more
difficult for a third party to acquire control of us, even if that change of
control might benefit our stockholders.
OUR CERTIFICATE OF INCORPORATION CONTAINS PROVISIONS THAT COULD DISCOURAGE AN
ACQUISITION OR CHANGE OF CONTROL OF OUR COMPANY.
Our certificate of incorporation authorizes our board of directors to
issue preferred stock without stockholder approval. Provisions of our
certificate of incorporation, such as the provision allowing our board of
directors to issue
21
24
preferred stock with rights more favorable than our common stock, could make it
more difficult for a third party to acquire control of us, even if that change
of control might benefit our stockholders.
OUR STOCKHOLDERS MAY EXPERIENCE SUBSTANTIAL DILUTION IN THE FUTURE
Our board of directors may issue shares of common stock and preferred
stock in the future which may dilute our stockholders' ownership. We are
authorized to issue 100,000,000 shares of common stock (12,748,612 shares were
issued and outstanding at March 15, 2001). We are also authorized to issue
50,000,000 shares of preferred stock (no shares of preferred stock were issued
and outstanding at March 15, 2001).
FUTURE SALES OF OUR COMMON STOCK MAY ADVERSELY AFFECT THE MARKET PRICE
Future sales by stockholders could adversely affect the prevailing
market price of our common stock. As of March 15, 2001 we had 12,748,612 shares
of common stock outstanding.
Of the issued and outstanding shares of our common stock, 12,016,112
are freely tradable without restriction or further registration under the
Securities Act of 1933. The remaining 732,500 issued and outstanding shares of
common stock are subject to contractual restrictions which limits the quantity
that can be sold at any given time. These contractual restrictions will expire
on April 30, 2001.
ITEM 2. DESCRIPTION OF PROPERTIES
GENERAL
We occupy approximately 8,360 square feet of office space at 13760 Noel
Road, Suite 1030, Dallas, Texas, under a lease that expires in October 2003. We
also occupy approximately 2,000 square feet of space in Ottawa, Ontario for
offices for certain of our executive officers located there under a lease that
expires in August 2003. We lease property for a rig yard in New Mexico.
OTHER
For a description of our oil and natural gas properties, oil and
natural gas reserves, acreage, wells, production and drilling activity, see
"Item 1. Business."
ITEM 3. LEGAL PROCEEDINGS
The landowner royalty on the J.C. Martin field is currently the subject
of a lawsuit that has created uncertainty regarding our title to our interest in
the J.C. Martin field. For a description of this litigation, see "Item 1.
Business - Risk Factors - Risks Related to Our Business - We may lose title to
our royalty interest in the J.C. Martin field as a result of litigation over
title to the royalty interest."
No other legal proceedings are pending other than ordinary routine
litigation incidental to us, the outcome of which management believes will not
have a material adverse effect on our financial condition or results of
operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the last 3 months of the fiscal year ended December 31, 2000, no
matter was submitted by us to a vote of our stockholders through the
solicitation of proxies or otherwise.
22
25
PART II
ITEM 5. MARKET FOR THE COMMON STOCK AND RELATED STOCKHOLDER MATTERS
MARKET INFORMATION
Our common stock has been listed for trading on the Nasdaq National
Market System under the trading symbol "DVXE" since October 26, 2000. From
November 11, 1999 to October 26, 2000 our stock was quoted on the Nasdaq OTC
Bulleting Board under the trading symbol "QSRI." From May 1997 to November 10,
1999 our common stock was quoted on the Nasdaq Small Cap Market under the symbol
"QSRI." See "Item 1. Business - Risk Factors - Risks Relating to Our Common
Stock." The following table sets forth the high and low closing bid prices for
our common stock as reported on Nasdaq Small Cap Market, quoted on the OTC
Bulletin Board or listed on the Nasdaq National Market for the periods
indicated, and the prices before October 26, 2000 have been adjusted to give
effect to the 156-to-1 reverse stock split of our common stock. We have no
shares of preferred stock outstanding.
HIGH LOW
------- -------
YEAR ENDED DECEMBER 31, 1999
First Quarter $643.50 $175.50
Second Quarter $229.16 $146.17
Third Quarter $146.33 $ 43.84
Fourth Quarter $ 92.66 $ 43.84
FISCAL YEAR ENDED DECEMBER 31, 2000
First Quarter $ 82.68 $ 43.84
Second Quarter $ 63.38 $ 14.63
Third Quarter $ 46.32 $ 7.32
Fourth Quarter $ 8.38 $ 7.32
TRANSFER AGENT
The Transfer Agent for our common stock is Continental Stock Transfer &
Trust Company, 2 Broadway, New York, New York 10004.
HOLDERS
The approximate number of record holders of our common stock as of
March 15, 2001 was 4,338, inclusive of those brokerage firms and/or clearing
houses holding our common stock for their clientele (with each such brokerage
house and/or clearing house being considered as one holder).
CAPITAL STOCK ISSUANCES
During the three months ended December 31, 2000, we issued 12,748,612
shares of post reverse-split common stock. Of this amount, 732,500 shares were
issued pursuant to Section 3(a) (9) of the Securities Act of 1933, for no
additional consideration to stockholders who exchanged all their outstanding
preferred stock, warrants or repricing rights, 516,112 shares were issued
pursuant to Section 3(a) (9) of the Securities Act of 1933 to the holder of pre
reverse split common stock in exchange for their shares and 11,500,000 shares
were issued pursuant to the Registration Statement on Form S-2 filed with the
Securities and Exchange Commission under file number 333-41992 and declared
effective on October 25, 2000. The company also issued a total of 642,500
options to its employees on October 27, 2000 under the company's 1997 Incentive
Equity Plan. The exercise price of these options is $7.00 per optioned share. A
total of 490,000 of these options vest in two equal annual installments
beginning on October 27, 2001 and the remaining 152,500 options vest in three
equal annual installments beginning on October 27, 2001. The company also issued
a total of 90,000 options to its directors under the Directors' Non-Qualified
Stock Option Plan. The exercise price of 9,000 of these Non-Qualified options is
$7.00 per optioned share and the exercise price of the remaining 81,000 options
is $7.0625 per optioned share. The options issued under the Directors'
Non-Qualified Stock Option Plan will vest immediately upon stockholder approval.
All 732,500 options were issued subject to stockholder approval of amendments to
the plans.
23
26
DIVIDENDS
We have never declared or paid any dividends on our common stock. We
currently intend to retain future earnings, if any, for the operation and
development of our business and do not intend to pay any dividends on our common
stock in the foreseeable future. Because DevX Energy, Inc. is a holding company,
our ability to pay dividends depends on the ability of our subsidiaries to pay
cash dividends or make other cash distributions. Our credit agreement prohibits
us from paying cash dividends on our common stock and the senior notes indenture
restricts our payment of dividends on common stock. Our board of directors has
sole discretion over the declaration and payment of future dividends subject to
Delaware corporate law. Any future dividends may also be restricted by any loan
agreements which we may enter into from time to time and will depend on our
profitability, financial condition, cash requirements, future prospects, general
business conditions, the terms of our debt agreements and certificate of
incorporation and other factors our board of directors believes relevant.
24
27
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth for the periods indicated certain of our
summary historical consolidated financial information. The summary historical
consolidated financial information for each of the years in the five years ended
December 31, 2000 have been derived from our audited consolidated financial
statements. During 2000, we changed our year end from June 3 to December 31. The
information in the table below has been presented on a calendar year basis. We
completed material acquisitions of producing properties in some of the periods
presented which affects the comparability of the historical financial and
operating data for all periods presented. The summary historical information
below should be read in conjunction with "Item 7. Management's Discussion and
Analysis of Financial Condition and Results and Operations," our Consolidated
Financial Statements and the notes thereto.
YEAR ENDED DECEMBER 31
-------------------------------------------------------------
2000 1999 1998 1997 1996
--------- --------- --------- --------- ---------
(IN THOUSANDS OF DOLLARS, EXCEPT PER SHARE DATA)
OPERATIONS DATA:
Oil and natural gas sales(1) $ 42,205 $ 30,354 $ 27,832 $ 5,950 $ 3,030
Oil and natural gas production expenses(1) 7,941 6,408 10,292 3,600 1,650
--------- --------- --------- --------- ---------
Net oil and natural gas revenues 34,264 23,946 17,540 2,350 1,380
General and administrative expenses 4,497 3,629 2,420 2,120 1,080
--------- --------- --------- --------- ---------
EBITDA(2) 29,767 20,317 15,120 230 300
Hedge contract termination costs -- 3,328 -- -- --
Interest and financing costs(3) 15,659 16,949 11,735 1,110 770
Depletion, depreciation, and amortization(4) 10,242 11,056 11,433 1,400 840
Ceiling test write-down(5) -- -- 63,199 -- --
Interest and other income (90) (357) (156) (310) (70)
Unrealized losses on derivative contracts 1,945 -- -- -- --
Income tax benefit (642) -- -- -- --
--------- --------- --------- --------- ---------
Income (loss) from continuing operations $ 2,653 $ (10,659) $ (71,091) $ (1,970) $ (1,240)
========= ========= ========= ========= =========
Income (loss) per common share ($/share)(6)
Basic $ 1.12 $ (49.52) $ (414.90) $ (11.49) $ (7.80)
========= ========= ========= ========= =========
Diluted $ 0.87 $ (49.52) $ (414.90) $ (11.49) $ (7.80)
========= ========= ========= ========= =========
CASH FLOWS DATA:
Net cash provided by (used in) in
operating $ 6,514 $ 693 $ 8,377 $ (520) $ (400)
activities
Net cash provided by (used in) investing (9,573) 2,036 (163,584) (10,090) (6,750)
activities
Net cash provided by (used in) financing 10,668 (2,392) 155,131 12,830 7,810
activities
Net increase (decrease) in cash 7,609 337 (76) 2,210 650
AT DECEMBER 31
-------------------------------------------------------------
2000 1999 1998 1997 1996
--------- --------- --------- --------- ---------
BALANCE SHEET DATA (AT END OF PERIOD):
Total current assets $ 21,725 $ 8,562 $ 8,475 $ 4,512 $ 1,390
Property and equipment, net 97,091 95,982 107,966 26,085 11,080
Deferred assets 4,174 8,074 12,060 13 --
Total assets 122,990 112,618 128,501 30,610 12,470
Total current liabilities 9,014 11,926 10,203 3,765 6,130
Long-term obligations, net of current 50,000 134,106 136,294 7,281 2,600
portion
Derivatives 12,246 -- -- -- --
Total stockholders' equity (deficit) 51,730 (33,414) (17,996) 19,564 3,740
- ---------
(1) Oil and natural gas sales and production expenses related to net profits
interests have been presented as if such net profits interests were working
interests.
(2) EBITDA represents earnings before interest expense, income taxes,
depreciation, depletion and amortization expense, hedge contract
termination costs, write-down of oil and natural gas properties and
extraordinary items and excludes interest and other income. EBITDA is not a
measure of income or cash flows in accordance with generally accepted
accounting principles, but is presented as a supplemental financial
indicator as to our ability to service or incur debt. EBITDA is not
presented as an indicator of cash available for discretionary spending or
as a measure of liquidity. EBITDA may not be comparable to other similarly
titled measures of other companies. Our credit agreement requires the
maintenance of specified EBITDA ratios. EBITDA should not be considered in
isolation or as a substitute for net income, operating cash flow or any
other measure of financial performance prepared in accordance with
generally accepted accounting principles or as a measure of our
profitability or liquidity.
(3) Interest charges payable on outstanding debt obligations.
(4) Depreciation, depletion and amortization includes amortized deferred
charges related to debt obligations of $1.6 million for the year ended
December 31, 2000, and $1.5 million for the year ended December 31, 1999,
and $0.5 million for the year ended December 31, 1998.
(5) In accordance with the full cost method of accounting, the results of
operations for the year ended December 31, 1998 include a write-down of oil
and natural gas properties of $63,199,000.
(6) Per share amounts have been retroactively adjusted to reflect the effect of
a reverse stock split of one common share for every 156 shares of our
common stock.
25
28
We did not pay any cash dividends during any of the periods presented.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
GENERAL
We are an independent energy company engaged in the exploration,
development, exploitation and acquisition of oil and natural gas properties in
on-shore, known producing areas, using conventional recovery techniques.
Our goal is to expand our reserve base, cash flow and net income and to
generate an attractive return on capital. Our strategy to achieve these goals
consists of these elements:
o develop, exploit and explore our existing oil and natural gas
properties;
o identify acquisition opportunities that complement our existing
properties; and
o utilize a well balanced financial structure that will allow us
to direct the cash generated from operations to fund production
and reserve growth without having to be overly reliant on the
capital markets.
We use the full cost method of accounting for our investment in oil and
natural gas properties. Under this method, we capitalize all acquisition,
exploration and development costs incurred for the purpose of finding and
developing oil and natural gas reserves, including salaries, benefits and other
related general and administrative costs directly attributable to these
activities. We capitalized general and administrative costs of $1,287,000 in the
fiscal year ended December 31, 1998, $813,000 in the fiscal year ended December
31, 1999 and $691,000 in the fiscal year ended December 31, 2000. We expense
costs associated with production and general corporate activities in the period
incurred. We capitalize interest costs related to unproved properties and
properties under development. Sales of oil and natural gas properties are
accounted for as adjustments of capitalized costs, with no gain or loss
recognized, unless these adjustments would significantly alter the relationship
between capitalized costs and proved reserves of oil and natural gas.
The following table sets forth certain operating information for the
periods presented. Information is presented as if the net profits interests had
been accounted for as working interests. The three periods are not readily
comparable because we acquired and disposed of certain producing oil and natural
gas producing properties during some of the periods presented. More
specifically, during April 1998, we acquired the net profits interests. During
the summers of 1999 and 2000, we sold some of our producing properties.
YEAR ENDED DECEMBER 31
--------------------------------------
2000 1999 1998
---------- ---------- ----------
PRODUCTION DATA:
Natural gas (Mcf) 9,797,000 11,441,000 9,931,000
Oil (Bbls) 216,000 339,000 481,000
Mcfe 11,096,000 13,474,000 12,814,000
AVERAGE SALES PRICE, NET OF CASH SETTLEMENTS ON HEDGES:
Natural gas ($/Mcf) $ 3.69 $ 2.24 $ 2.16
Oil ($/Bbl) 27.89 14.05 13.26
Mcfe ($Mcfe) 3.80 2.25 2.17
AVERAGE COST ($/MCFE) DATA:
Production and operating costs $ 0.55 $ 0.39 $ 0.66
Production and severance taxes 0.16 0.08 0.15
General and administrative costs 0.41 0.27 0.19
Interest expense (excluding amortization of deferred debt
issuance costs) 1.41 1.26 0.92
Depletion, depreciation, and amortization (excluding write-down of oil
and natural gas properties) 0.77 0.68 0.79
26
29
The following discussion of the results of operations and financial
condition should be read in conjunction with our consolidated financial
statements and related notes thereto included herein, and reflects the operating
results as if the net profits interests were accounted for as working interests.
We believe that this presentation will provide the reader with a more meaningful
understanding of the underlying operating results and conditions for the period.
THE YEAR ENDED DECEMBER 31, 2000 COMPARED TO THE YEAR ENDED DECEMBER 31, 1999
RESULTS OF OPERATIONS
REVENUES. Total revenues during the year ended December 31, 2000 were
$42.2 million, an increase of $11.8 million from the $30.4 million for the year
ended December 31, 1999. Our revenues were derived from the sale of 9.8 Bcf of
natural gas at an average price per Mcf of $3.69 and 216,000 barrels of oil at
an average price per barrel of $27.89. During the year ended December 31, 1999
our revenues were derived from the sale of 11.4 Bcf of natural gas, at an
average price per Mcf of $2.24, and 339,000 barrels of oil, at an average price
per barrel of $14.05. Overall we produced 11.1 Bcfe at an average price of $3.80
per Mcfe during the year ended December 31, 2000 as compared to 13.5 Bcfe at an
average price of $2.25 per Mcfe during the year ended December 31, 1999. This
represents a decrease of 2.4 Bcfe (18%) in production and an increase of $1.55
(69%) in the average price we received.
We produced 216,000 barrels of oil during the year ended December 31,
2000, a decrease of 123,000 barrels (36%) from the 339,000 barrels produced
during the comparable period in 1999. The properties that we sold during 1999
represent 92,000 barrels (75%) of the total decrease of 123,000 barrels.
Production from the properties that we owned during both periods decreased by
31,000 barrels. This represents a 13% decline from volumes produced during the
year ended December 31, 1999. The decrease in production of oil from the
properties owned during the comparative periods is comprised of two components:
o The Segno field has not been meeting production expectations.
This under performance represents approximately 77% of the
decrease in production from the properties that we owned
during both periods. Some of the capital projects planned for
2000 were not carried out by the operator of the property. We
have agreed to join with the operator in farming out certain
Middle Wilcox rights in the property.
o The final component of the production decline is the result of
the natural depletion of our oil reservoirs.
We produced 9.8 Bcf of natural gas during the year ended December 31,
2000, down from the 11.4 Bcf produced during the comparable period in 1999. The
properties that we sold during 1999 represent 0.4 Bcf (27%) of the total
decrease of 1.6 Bcf. Production from the properties that we owned during both
periods decreased by 1.2 Bcf. This represents an 11% decline from the volumes
produced during the year ended December 31, 1999. The decrease in natural gas
production from the properties owned during the comparative periods is comprised
of three components:
o The Gilmer field declined approximately 14% from the prior
year which represents 42% of the decrease in production from
the properties that we owned during both periods. The operator
of the property commenced a drilling program during mid-year
2000. By December 31, 2000, five new wells had been drilled
and four of those had been placed on production with average
initial production rates of 815 Mcf per well, net to our
interest.
o The Lopeno and Volpe fields natural gas production was down
65% from 1999, or 47% of the total decrease in production from
properties that we owned during both periods. As of June 20,
2000 we sold approximately one-half of our interest in the
property, which accounts for approximately 20% of the
reduction. In addition, during the fourth quarter, one new
well was unsuccessful and a workover did not achieve expected
results. We believe that meaningful development and
exploitation potential remains in these properties.
o The final component of the production decline is the result of
the natural depletion of our natural gas reservoirs.
27
30
On a billion cubic feet of gas equivalent ("Bcfe") basis, production
for the year ended December 31, 2000 was 11.1 Bcfe, down 2.4 Bcfe (18%) from the
13.5 Bcfe produced during the comparable period in 1999. The properties that we
sold at the end of June 1999 represent 1.0 Bcfe of the total decrease of 2.4
Bcfe. Production from the properties that we owned during both periods decreased
by 1.4 Bcfe.
The decrease in revenues resulting from lower production volumes was
offset by the significant industry-wide increase in oil and natural gas prices.
The average price per barrel of oil sold by us during the year ended December
31, 2000 was $27.89, an increase of $13.84 per barrel (99%) over the $14.05 per
barrel during the year ended December 31, 1999. The average price per Mcf of
natural gas sold by us was $3.69 during the year ended December 31, 2000, an
increase of $1.45 per Mcf (65%) over the $2.24 per Mcf during the comparable
period in 1999. Oil prices have remained at these elevated levels subsequent to
December 31, 2000. Natural gas prices were volatile throughout the year, and
have remained so subsequent to December 31, 2000. On an Mcfe basis, the average
price received by us during the year ended December 31, 2000 was $3.80, a $1.55
increase (69%) over the $2.25 we received during the comparable period in 1999.
During the year ended December 31, 2000 we paid $203,000 in cash
settlements pursuant to our oil price-hedging program. The effect on the average
oil prices we received during the period was a decrease of $0.94 per barrel
(3%). During the year ended December 31, 2000 we paid $3,317,000 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 period was $0.35 (9%). Payments made
as a result of our oil price-hedging program during the year ended December 31,
1999 were $592,000, which reduced our average oil price by $1.75 per barrel
(12%). During 1999 we received $643,000 in cash settlements and amortized
$120,000 of deferred hedging costs regarding our natural gas price-hedging
program. The net positive effect on the average natural gas prices we received
during the period was $0.06 per Mcf (3%).
COSTS AND EXPENSES. Operating costs and expenses for the year ended
December 31, 2000, exclusive of the effect of mark-to-market accounting for
derivative contracts used to hedge oil and natural gas prices, were $38.3
million. Of this total, lease operating expenses and production taxes were $7.9
million, general and administrative expenses were $4.5 million, interest charges
were $17.3 million and depletion, depreciation and amortization costs were $8.6
million. Operating costs and expenses for the year ended December 31, 1999,
exclusive of a $3.3 million hedge contract termination payment and the $1.1
million extraordinary loss from the write-down of deferred charges when we
replaced our operating loans, were $38.0 million. Of this total, lease operating
expenses and production taxes were $6.4 million, general and administrative
expenses were $3.6 million, interest charges were $18.6 million and depletion,
depreciation and amortization costs were $9.4 million.
Severance and production taxes, which are based on the revenues derived
from the sale of oil and natural gas, were $1.8 million during the year ended
December 31, 2000, as compared to $1.1 million during 1999, an increase of
$700,000, or 63%. The increase is primarily as a result of increased wellhead
revenues.
On a cost per Mcfe basis, severance taxes were $0.16 per Mcfe for the
year ended December 31, 2000 compared to $0.08 per Mcfe for the comparable
period ending December 31, 1999, an increase of 100%. The increase in our
average wellhead prices, which rose by 83%, from $2.25 per Mcfe during the year
ended December 31, 1999 to $4.12 per Mcfe during 2000, caused the increase in
per unit severance taxes.
Our lease operating expenses grew to $6.1 million for the year ended
December 31, 2000, an increase of $0.8 million, or 16%, from the $5.3 million
incurred during the comparable period in 1999. The increase had three primary
causes. We receive periodic rebates related to processing costs in our Gilmer
property. These rebates, which reduce our total processing costs, were higher in
1999 than 2000, due to timing of payments during 1999 and lower plant throughput
during 2000. During a portion of 1999, we shut-in several oil producing
properties, in response to depressed crude oil prices, in order to reduce total
costs. Those properties were back on production for the full year during 2000.
Finally, these two increases were offset by the effect of costs related to
properties we sold during 1999. Lease operating expenses were $0.55 per Mcfe
during the year ended December 31, 2000, an increase of $0.16, or 41%, from the
$0.39 per Mcfe incurred during the comparable period in 1999. This increase in
average costs per Mcfe is a result of increased total costs being spread over
lower production volumes.
28
31
General and administrative expenses were $4.5 million for 2000 compared
to $3.6 million incurred during 1999. This increase of $868,000 (24%) consists
primarily of costs related to severance payments and certain staffing changes,
approximately $740,000 of which are non-recurring costs. On a per unit basis,
general and administrative expenses for the year ended December 31, 2000 were
$0.41 per Mcfe, an increase of $0.14 per Mcfe (52%) from the $0.27 per Mcfe
incurred during the year ended December 31, 1999. This per unit increase in
general and administrative expenses is a result of our increased total expenses
spread over a decreased level of oil and natural gas production.
Interest expense for the year ended December 31, 2000 was $17.3
million. This was comprised of $15.7 million paid or payable in cash and $1.6
million of amortization of deferred costs incurred at the time that the related
debt obligations were incurred. During the year ended December 31, 1999 our
interest expense was $18.6 million. This was comprised of $16.9 million paid or
payable in cash and $1.7 million of amortized deferred debt issuance costs
incurred at the time that the related debt obligations were established.
Interest expense was reduced slightly as a result of a reduction of our debt
during the fourth quarter of 2000 in connection with our recapitalization.
On a per unit basis, cash interest expense for the year ended December
31, 2000 was $1.41 per Mcfe, as compared to $1.26 per Mcfe during 1999. This is
the result of the 18% reduction in production we had during 2000, as compared to
1999, offset by slightly reduced interest expense for 2000 compared to 1999.
The decrease in depletion, depreciation and amortization costs of $0.8
million was a result of the 18% decrease in the volume of oil and natural gas
produced by us during the year ended December 31, 2000 as compared to the year
ended December 31, 1999. On a cost per Mcfe of reserves, the depletion,
depreciation and amortization costs increased by $0.09 per Mcfe (13%). This
increase is a function of higher unamortized capitalized costs for 2000 and a
reduction in total reserve quantities.
INCOME TAX BENEFIT. As a result of our recapitalization in October
2000, we were able to recognize the expected future benefits of utilizing a
portion of our net operating loss carryforwards to offset taxes payable in
future years. As a result, we reported a net tax benefit in income approximating
$0.6 million during 2000.
EXTRAORDINARY GAIN (LOSS). In October 2000 we completed a public
offering of our stock and used a portion of the proceeds to repurchase $75
million face value of our 12.5% senior notes for $52.5 million. In connection
with this recapitalization, we recorded an extraordinary gain of $21.1 million.
In October 1999 we replaced our old credit agreement with our new credit
agreement. As a result, we wrote off $1.1 million in unamortized deferred debt
issuance costs associated with the old credit agreement.
CUMULATIVE EFFECT OF ACCOUNTING CHANGE AND CHANGE IN FAIR VALUE OF
DERIVATIVES. Effective July 1, 2000, we adopted Statement of Financial
Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging
Activities, or SFAS 133, which requires us to recognize all derivatives on the
balance sheet at fair value. Upon adoption of SFAS 133, we had four open
derivative contracts, one of which has been designated as a hedge. At adoption,
we recognized a derivative liability and a reduction in other comprehensive
income of approximately $5.5 million as a cumulative effect of accounting change
for the derivative contract designated as a hedge. In connection with the other
three derivative contracts, we recognized a net derivative asset of
approximately $0.6 million and a related gain of approximately $0.4 million in
the income statement as a cumulative effect of accounting change.
During the six months ended December 31, 2000, we recognized a non-cash
loss of approximately $1.9 million in earnings related to the net change in the
fair value of our derivative contracts which have not been designated as hedges.
NET INCOME. For the year ended December 31, 2000, we recorded net
income of $24.2 million or $10.24 per basic share ($7.96 per diluted share),
compared to a loss of $11.8 million, or $54.76 per basic and diluted share, for
1999. The reduction of debt and increased natural gas prices are the primary
causes of the significantly improved results.
29
32
THE YEAR ENDED DECEMBER 31, 1999 COMPARED TO THE YEAR ENDED DECEMBER 31, 1998
RESULTS OF OPERATIONS
REVENUES. Total revenues during the year ended December 31, 1999 were
$30.4 million, an increase of $2.5 million from the $27.8 million for 1998. Our
revenues were derived from the sale of 11.4 Bcf of natural gas at an average
price per Mcf of $2.24 and 339,000 barrels of oil at an average price per barrel
of $14.05. During 1998, our revenues were derived from the sale of 9.9 Bcf of
natural gas, at an average price per Mcf of $2.16, and 481,000 barrels of oil,
at an average price per barrel of $13.26. Overall we produced 13.5 Bcfe at an
average price of $2.25 per Mcfe during 1999 as compared to 12.8 Bcfe at an
average price of $2.17 per Mcfe during 1998. This represents an increase of 0.7
Bcfe (5%) in production and an increase of $0.08 (4%) in the average price we
received.
We produced 339,000 barrels of oil during the year ended December 31,
1999, a decrease of 142,000 barrels (29%) from the 481,000 barrels produced
during 1998. The properties that we sold during 1999 represent 115,000 barrels
(81%) of the total decrease of 141,000 barrels. Production from the properties
that we owned during both periods decreased by 27,000 barrels. This represents a
10% decline from volumes produced during the year ended December 31, 1998. The
decrease in production of oil from the properties owned during the comparative
periods is comprised of three components:
o During March 1999, we shut in substantially all of the wells
in the Caprock field in New Mexico in response to low oil
prices. As oil prices recovered late in 1999, we returned to
production those wells that produce economically.
o As an offset to the total decrease in oil volumes, production
from our net profits interests, which were acquired during
April 1998, were up during 1999, reflecting a full year's
production from those properties.
o The final component of the production decline is the result of
the natural depletion of our oil reservoirs.
o We produced 11.4 Bcf of natural gas during 1999, up from the
9.9 Bcf produced during 1998. The increase is primarily a
reflection of a full year's production from our net profits
interests, which were acquired during April 1998. The total
increase was offset by properties that we sold during 1999,
which resulted in reduced gas volumes of 0.6 Bcf.
On a billion cubic feet of gas equivalent ("Bcfe") basis, production
for 1999 was 13.5 Bcfe, up 0.7 Bcfe (5%) from the 12.8 Bcfe produced during
1998. A full year's production during 1999 from the net profits interest
properties generated increased volumes of 2.1 Bcfe. Offsetting the increase, the
properties that we sold at the end of June 1999 represent a reduction of 1.3
Bcfe.
The average price per barrel of oil sold by us during 1999 was $14.05,
an increase of $0.79 per barrel (6%) over the $13.26 per barrel realized during
1998. The average price per Mcf of natural gas sold by us was $2.24 during 1999,
an increase of $0.08 per Mcf (4%) over the $2.16 per Mcf received during 1998.
On an Mcfe basis, the average price received by us during 1999 was $2.25, a
$0.08 increase (4%) over the $2.17 we received during 1998.
During the year ended December 31, 1999 we paid $592,000 in cash
settlements pursuant to our oil price-hedging program. The effect on the average
oil prices we received during the period was a decrease of $1.75 per barrel
(12%). During 1999, we received 643,000 in cash settlements and amortized
$108,000 of deferred hedging costs regarding our natural gas price-hedging
program. The net positive effect on the average natural gas prices we received
during the period was $0.06 (3%). Payments received as a result of our oil
price-hedging program during 1998 were $380,000, which increased our average oil
price by $0.79 per barrel (6%). During 1998, we also received $803,000 in cash
settlements and amortized $89,000 of deferred hedging costs regarding our
natural gas price-hedging program. The net positive effect on the average
natural gas prices we received during the period was $0.08 per Mcf (4%).
COSTS AND EXPENSES. Operating costs and expenses for the year ended
December 31, 1999, exclusive of a $3.3 million hedge contract termination
payment and the $1.1 million extraordinary loss from the write-down of deferred
charges when we replaced our operating loans, were $38.0 million. Of this total,
lease operating expenses and
30
33
production taxes were $6.4 million, general and administrative expenses were
$3.6 million, interest charges were $18.6 million and depletion, depreciation
and amortization costs were $9.4 million. Operating costs and expenses for the
year ended December 31, 1998, exclusive of an extraordinary charge of $3.5
million, were $35.8 million. Of this total, lease operating expenses and
production taxes were $10.3 million, general and administrative expenses were
$2.4 million, interest charges were $12.2 million and depletion, depreciation
and amortization costs were $10.9 million.
Severance and production taxes, which are based on the revenues derived
from the sale of oil and natural gas, were $1.1 million during 1999, compared to
$1.9 million during 1998, a decrease of $800,000, or 42%. These taxes amounted
to approximately 4% of wellhead revenues during 1999, down from 7% of wellhead
revenues during 1998. The reduction is a result of the substantial changes in
our property base resulting from the acquisition of the net profits interests
during 1998 and the sale of certain properties during 1999, coupled with the
fact that two significant net profits interests receive severance tax
abatements.
On a cost per Mcfe basis, severance taxes were $0.08 per Mcfe for the
year ended December 31, 1999, compared to $0.15 per Mcfe for 1998, a decrease of
47%. The change in our property base mentioned above more than offsets the
effect of slightly higher wellhead prices received during 1999 over 1998.
Our lease operating expenses fell to $5.3 million for the year ended
December 31, 1999, a decrease of $3.1 million, or 37%, from the $8.4 million
incurred during 1998. The decrease had three primary causes. We sold certain
properties during June 1999, eliminating the costs associated with operating
those properties. We receive periodic rebates related to processing costs in our
Gilmer property. These rebates, which reduce total net processing costs, were
higher in 1999 than 1998 due to timing of payments during 1999. During a portion
of 1999, we shut-in several oil producing properties, in response to depressed
crude oil prices, in order to reduce total costs. Lease operating expenses were
$0.39 per Mcfe during 1999, a decrease of $0.27, or 41%, from the $0.66 per Mcfe
incurred in 1998. This improvement is primarily the result of lower total costs,
as discussed above.
General and administrative expenses increased $1.2 million over 1998,
primarily as a result of our increased payroll costs, higher occupancy costs
related to our move into larger offices and increased professional fees. On a
per unit basis, general and administrative expenses for 1999 were $0.27 per
Mcfe, up $0.08 from the $0.19 per Mcfe for 1998. This per unit increase in
general and administrative expenses is a result of our increased total costs.
Interest expense for 1999 was $18.6 million, an increase of $6.4
million, or 52%, over the $12.2 million recorded during 1998. The increase
reflects the increased borrowings incurred in connection with our purchase of
the net profits interests during April 1998.
On a per unit basis, cash interest expense was $1.26 per Mcfe during
1999, as compared to $0.92 per Mcfe for 1998. This is a result of our total cash
interest expense increasing at a faster rate than our growth in production
volumes.
Depletion, depreciation and amortization costs decreased $1.4 million
during 1999 primarily as a result of the significant reduction in unamortized
costs during 1998, related to a non-cash write-down of $63 million we recorded
during 1998. On a cost per Mcfe of reserves the depletion, depreciation and
amortization costs decreased by $0.11 per Mcfe (14%).
EXTRAORDINARY LOSS. In October 1999 we replaced our old credit
agreement with our new credit agreement. As a result, we wrote off $1.1 million
in unamortized deferred debt issuance costs associated with the old credit
agreement. In July 1998, we unwound a LIBOR interest rate swap contract at a
cost of $3.5 million.
NET LOSS. We incurred a loss of $11.8 million, or $54.76 per basic
share, for the year ended December 31, 1999 compared to $74.6 million, or
$435.61 per basic share for the year ended December 31, 1998. The decline in oil
and natural gas prices between December 31, 1997 and December 31, 1998 caused us
to record non-cash write-downs of oil and natural gas properties of $63 million
during 1998.
31
34
LIQUIDITY AND CAPITAL RESOURCES
GENERAL
We completed a recapitalization on October 31, 2000. See "Item 1.
Business - Recent Developments." The key components of the recapitalization
were: (a) a reverse stock split of one common share for every 156 shares of our
common stock; (b) the exchange of all preferred stock then outstanding, all
warrants exercisable for shares of common stock and all unexercised common stock
repricing rights for 732,500 shares of post reverse-split common stock; and (c)
the repurchase of $75 million face value of our senior notes for approximately
$52.5 million. In addition we completed a public offering of 11,500,000 shares
of post reverse-split 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 our senior notes, repay
bank debt of approximately $14 million and fund working capital.
Our board of directors decided to effect a quasi-reorganization given
the infusion of new equity capital, the reduction in debt, changes in management
and changes in the our operations. Accordingly, our accumulated deficit as of
the date of the recapitalization, $68.1 million, was eliminated against
additional paid-in capital. The historical carrying values of our assets and
liabilities were not adjusted in connection with the quasi-reorganization.
As of March 15, 2001, under our credit agreement we:
o had no indebtedness outstanding;
o had $8.5 million reserved to secure a letter of credit; and
o were permitted to borrow an additional $35 million.
Our general financial strategy is to use cash flow from operations,
debt financings and the issuance of equity securities to service interest on our
indebtedness, to pay ongoing operating expenses, and to contribute toward the
further development of our existing proved reserves as well as additional
acquisitions. There can be no assurance that cash from operations will be
sufficient in the future to cover all such purposes.
We have planned exploration, development and exploitation activities
for all of our major operating areas. We plan to spend $25 million to $27
million in capital activities during 2001, with 15 percent to 35 percent of that
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. 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, and 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 funds will be available to us to meet our budgeted capital
spending. Furthermore, our ability to borrow other than under the credit
agreement is subject to restrictions imposed by the 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 both of such activities.
SOURCES OF CAPITAL
We have a credit agreement with Ableco Finance LLC and Foothill Capital
Corporation which allows for borrowings of up to $50 million, subject to
borrowing base limitations, from such lenders to fund, among other things,
development and exploitation expenditures, acquisitions and general working
capital. Our borrowing base under the credit agreement is currently $43.5
million, none of which was outstanding as of March 15, 2001. Under the credit
agreement we have provided a first lien on all of our assets to secure our
obligations under the agreement. The credit
32
35
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 and
operating covenants, including maintaining an interest coverage ratio greater
than one, a minimum of 1.5-to-1 working capital ratio (calculated as set set out
in the credit agreement) and a $30 million annual limit on capital spending. At
December 31, 2000, the Company exceeded the capital spending limitation, for
which the lender issued a waiver. The credit agreement was amended during
January 2001 to increase the capital spending limitation, and we believe the new
limit is sufficient to accommodate our plans for 2001.
We have a letter of credit outstanding under the credit agreement in
the amount of $8.5 million, as of March 15, 2001, to an affiliate of Enron to
secure a swap exposure. This letter of credit has the effect of reducing our
credit availability under the credit agreement.
In October and November 2000 we completed a public offering of
11,500,000 shares of post reverse-split 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 original principal amount of our senior notes for
approximately $52.5 million, to repay approximately $14 million then outstanding
under the credit agreement and to fund working capital.
We have implemented a commodity gas price hedging program that provides
a degree of protection against significant decreases in oil and gas prices. The
interest payable under our senior notes is fixed at 12.5%. If we incur debt
under the Abelco credit agreement, the interest expense will be variable.
We may not have sufficient liquidity or capital to undertake all
acquisition prospects which we may wish to pursue. Therefore, we will continue
to be dependent on raising substantial amounts of additional capital through any
one or a combination of institutional or bank debt financing, equity offerings,
debt offerings and internally generated cash flow, or by forming sharing
arrangements with industry participants. Although we have been able to obtain
such financings and to enter into such sharing arrangements in certain of our
projects to date, there can be no assurance that we will continue to be able to
do so. Alternatively, we may consider issuing additional securities in exchange
for producing properties. There can be no assurance that any such financings or
sharing arrangement can be obtained.
Further acquisitions and development activities in addition to those
for which we are contractually obligated are discretionary and depend to a
significant degree on cash availability from outside sources such as bank debt
and the sale of securities or properties.
USES OF CAPITAL
During the period since our inception in August 1994 through April
1998, our primary method of replacing our production and increasing our reserves
was through acquisitions. Since that time, our primary method of replacing
production and enhancing our reserves was 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 percent to 35
percent of our 2001 capital spending to exploration activities. We expect to
spend between $25 million and $27 million on discretionary capital expenditures
during 2001 for exploitation, development and exploration projects. 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. As of March 1, 2001, we are contractually
obligated to fund $6.7 million in capital expenditures through December 2001.
33
36
INFLATION
During the past several years, we have experienced some inflation in
oil and natural 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 did during the year ended December 31, 1999. Our results of operations
and cash flow have been, and will continue to be, affected to a certain extent
by the volatility in oil and natural gas prices. Should we experience a
significant increase in oil and natural gas prices that is sustained over a
prolonged period, we could expect that there would also be a corresponding
increase in oil and natural gas finding costs, lease acquisition costs, and
operating expenses.
CHANGES IN PRICES AND HEDGING ACTIVITIES
Annual average oil and natural gas prices have fluctuated significantly
over the last two years. The table below sets out our weighted average price per
barrel of oil and the weighted average price per Mcf of natural gas, the impact
of our hedging programs and the related NYMEX indices.
DECEMBER 31
--------------------------
2000 1999 1998
------ ------ ------
NATURAL GAS (PER MCF):
Price received at wellhead $ 4.04 $ 2.18 $ 2.08
Effect of hedge contracts (0.35) (0.06) 0.08
------ ------ ------
Effective price received, including hedge contracts 3.69 2.24 2.16
Average NYMEX Henry Hub 3.91 2.27 2.14
Average basis differential excluding hedge contracts 0.13 (0.09) (0.06)
Average basis differential including hedge contracts (0.22) (0.03) 0.02
OIL (PER BARREL):
Average price received at wellhead per barrel 28.83 15.80 12.47
Average effect of hedge contract (0.94) (1.75) 0.79
------ ------ ------
Average price received, including hedge contracts 27.89 14.05 13.26
Average NYMEX Sweet Light Oil 30.20 19.24 14.46
Average basis differential excluding hedge contracts (1.37) (3.44) (1.99)
Average basis differential including hedge contracts (2.31) (5.19) (1.20)
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 Hub 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.
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
34
37
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 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
HEDGES OF OIL AND NATURAL GAS PRODUCTION
To reduce our exposure to changes in the prices of oil and natural gas,
we have entered into and may in the future enter into arrangements to hedge our
oil and natural gas production, whereby gains and losses in the fair value of
the derivative instruments are generally offset by price changes in the
underlying commodity. The hedges that we have entered into generally provide a
`floor' or `cap and floor' on the prices paid for our oil and natural gas
production over a period of time. Hedging arrangements may expose us to the risk
of financial loss in some circumstances, including the following:
o our production does not meet the minimum production
requirements under the agreement;
o the other party to the hedging contract defaults on its
contract obligations; or
o there is a change in the expected differential between the
underlying price in the hedging agreement and actual prices
received.
35
38
Due to our risk assessment procedures and internal controls, we believe
that the use of these derivative instruments does not expose us to material
risk, however, the use of derivative instruments for the hedging activities
could affect our results of operations in particular quarterly or annual
periods. The use of these instruments limits the downside risk of adverse price
movements, but it may also limit our ability to benefit from favorable price
movements.
Our hedging strategy is designed to provide protection from low
commodity prices while providing some opportunity to enjoy the benefits of
higher commodity prices. We have a series of natural gas futures contracts with
Bank of Montreal, an affiliate of Enron and Texaco. See "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Changes in Prices and Hedging Activities" for a complete description of our
hedging positions.
As of December 31, 2000 the fair value of our hedging contracts,
measured as the estimated cost we would incur to terminate the arrangements, was
$13.5 million. As of December 31, 2000 a 10% increase in oil and natural gas
prices would have resulted in an unfavorable change of $3.3 million in the fair
value of our hedging contracts and a 10% decrease in oil and natural gas prices
would have resulted in a favorable change of $3.3 million in the fair value of
our hedging contracts.
INTEREST RATES
At December 31, 2000, our exposure to interest rates relates primarily
to borrowings under our credit agreement. As of December 31, 2000, we are not
using any derivatives to manage interest rate risk. Interest is payable on
borrowings under the credit agreement based on a floating rate. As of December
31, 2000, and as of March 15, 2001, we have no amounts borrowed under our credit
agreement. Our excess cash balances are invested in short-term money market
instruments at floating rates.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
For the Financial Statements required by Item 8, see the Consolidated
Financial Statements included elsewhere in this Annual Report on Form 10-K.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
There are no changes or disagreements required to be reported under
this Item 9.
36
39
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item will be set forth under the
captions "Election of Directors," "Section 16(a) Beneficial Ownership Reporting
Compliance," and "Executive Officers" of our proxy statement for our 2000 Annual
Meeting of Stockholders (the "Proxy Statement") which will be filed with the
Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934
(the "Exchange Act") and is incorporated herein by reference. The Proxy
Statement is expected to be filed on or prior to April 30, 2001.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is set forth under the caption
"Executive Compensation" of our Proxy Statement, which will be filed with the
Commission pursuant to Regulation 14A under the Exchange Act and is incorporated
herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is set forth under the caption
"Security Ownership of Certain Beneficial Owners and Management" of our Proxy
Statement which will be filed with the Commission pursuant to Regulation 14A
under the Exchange Act and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is set forth under the captions
"Executive Compensation," " Director Compensation" and "Certain Relationships
and Related Party Transactions" of our Proxy Statement which will be filed with
the Commission pursuant to Regulation 14A under the Exchange Act and is
incorporated herein by reference.
37
40
GLOSSARY
The terms defined in this glossary are used throughout this Form 10-K.
"average NYMEX price." The average of the NYMEX closing prices for the
near month.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used
herein in reference to crude oil or other liquid hydrocarbons.
Bbl/d. Bbl per day.
Bcf. One billion cubic feet of natural gas.
Bcfe. One billion cubic feet of natural gas equivalents, converting one
Bbl of oil to six Mcf of gas.
"behind-the-pipe." Hydrocarbons in a potentially producing horizon
penetrated by a well bore the production of which has been postponed pending the
production of hydrocarbons from another formation penetrated by the well bore.
The hydrocarbons are classified as proved but non-producing reserves.
"development well." A well drilled within the proved boundaries of an
oil or natural gas reservoir with the intention of completing the stratigraphic
horizon known to be productive.
"dry well." A development or exploratory well found to be incapable of
producing either oil or natural gas in sufficient quantities to justify
completion as an oil or natural gas well.
"exploratory well." A well drilled to find oil or natural gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or natural gas in another reservoir, or to extend a known
reservoir.
"gross acres" or "gross wells." The total number of acres or wells, as
the case may be, in which a working interest is owned.
MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet of natural gas.
Mcf/d. Mcf per day.
Mcfe. One thousand cubic feet of natural gas equivalents, converting
one Bbl of oil to six Mcf of gas.
MMBbl. One million barrels of crude oil or other liquid hydrocarbons.
MMcfe. One million cubic feet of natural gas equivalents, converting
one Bbl of oil to six Mcf of gas.
MMcf. One million cubic feet of natural gas.
"Morgan Properties" means the net profits interests and royal interest
revenues we purchased in April 1998 from pension funds managed by J.P. Morgan
Investments.
"net acres" or "net wells." The sum of the fractional working interests
owned in gross acres or gross wells.
"net profits interest." A share of the gross oil and natural gas
production from a property, measured by net profits from the operation of the
property, that is carved out of the working interest. This is a non-operating
interest.
38
41
"non-producing reserves." Non-producing reserves consist of (i)
reserves from wells that have been completed and tested but are not yet
producing due to lack of market or minor completion problems that are expected
to be corrected, and (ii) reserves currently behind-the-pipe in existing wells
which are expected to be productive due to both the well log characteristics and
analogous production in the immediate vicinity of the well.
NYMEX. New York Mercantile Exchange.
"producing well," "production well" or "productive well." A well that
is producing oil or natural gas or that is capable of production.
"proved developed producing." Proved developed producing reserves are
proved developed reserves which are currently capable of producing in commercial
quantities.
"proved developed reserves." Proved developed reserves are oil and
natural gas reserves that can be expected to be recovered through existing wells
with existing equipment and operating methods. Additional oil and natural gas
expected to be obtained through the application of fluid injection or other
improved recovery techniques for supplementing the natural forces and mechanisms
of primary recovery should be included as "proved developed reserves" only after
testing by a pilot project or after the operation of an installed program has
confirmed through production response that increased recovery will be achieved.
"proved reserves." The estimated quantities of crude oil, natural gas
and natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
"proved undeveloped reserves" or PUD. Proved undeveloped reserves are
oil and natural gas reserves that are expected to be recovered from new wells on
undrilled acreage, or from existing wells where a relatively major expenditure
is required for recompletion. Reserves on undrilled acreage shall be limited to
those drilling units offsetting productive units that are reasonably certain of
production when drilled. Proved reserves for other undrilled units can be
claimed only where it can be demonstrated with certainty that there is
continuity of production from the existing productive formation. Under no
circumstances should estimates for proved undeveloped reserves be attributable
to any acreage for which an application of fluid injection or other improved
recovery techniques is contemplated, unless such techniques have been proved
effective by actual tests in the area and in the same reservoir.
"recompletion." A recompletion is an operation to abandon the
production of oil and/or natural gas from a well in one zone within the existing
wellbore and to make the well produce oil and/or natural gas from a different,
separately producible zone within the existing wellbore.
"Reserve Life Index." The estimated productive life of a proved
reservoir based upon the economic limit of such reservoir producing hydrocarbons
in paying quantities assuming certain price and cost parameters. For purposes of
this Form 10-K, reserve life is calculated by dividing the proved reserves (on a
Mcfe basis) at the end of the period by production volumes for the previous 12
months.
"royalty interest." An interest in an oil and natural gas property
entitling the owner to a share of oil and natural gas production free of costs
of production.
"SEC PV-10." The present value of proved reserves is an estimate of the
discounted future net cash flows from each of the properties at December 31,
2000, or as otherwise indicated. Net cash flow is defined as net revenues less,
after deducting production and ad valorem taxes, future capital costs and
operating expenses, but before deducting federal income taxes. As required by
rules of the Commission, the future net cash flows have been discounted at an
annual rate of 10% to determine their "present value." The present value is
shown to indicate the effect of time on the value of the revenue stream and
should not be construed as being the fair market value of the properties. In
accordance with Commission rules, estimates have been made using constant oil
and natural gas prices and operating costs, at December 31, 2000, or as
otherwise indicated.
39
42
"secondary recovery." A method of oil and natural gas extraction in
which energy sources extrinsic to the reservoir are utilized.
"service well." A well used for water injection in secondary recovery
projects or for the disposal of produced water.
"Standardized Measure." Under the Standardized Measure, future cash
flows are estimated by applying year-end prices, adjusted for fixed and
determinable escalations, to the estimated future production of year-end proved
reserves. Future cash inflows are reduced by estimated future production and
development costs based on period-end costs to determine pretax cash inflows.
Future income taxes are computed by applying the statutory tax rate to the
excess of pretax cash inflows over the Company's tax basis in the associated
properties. Tax credits, net operating loss carryforwards, and permanent
differences are also considered in the future tax calculation. Future net cash
inflows after income taxes are discounted using a 10% annual discount rate to
arrive at the Standardized Measure.
"undeveloped acreage." Lease acreage on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and natural gas regardless of whether such acreage contains
proved reserves.
"working interest." The operating interest which gives the owner the
right to drill, produce and conduct operating activities on the property and a
share of production, subject to all royalties, overriding royalties and other
burdens and to all costs of exploration, development and operations and all
risks in connection therewith.
40
43
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) (1) FINANCIAL STATEMENTS
See Index to Consolidated Financial Statements following the signature
page to this Annual Report on Form 10-K.
(a) (2) FINANCIAL STATEMENT SCHEDULES
All Schedules are omitted because the information is not required under
the related instructions or is inapplicable or because the information
is included in the Consolidated Financial Statements or related notes.
(a) (3) EXHIBITS
3.1 Restated Certificate of Incorporation of the Company, filed as
Exhibit 4.5 to the Company's Registration Statement on Form
S-3 (No. 333-47577) filed with the Securities and Exchange
Commission on March 9, 1998, which Exhibit is incorporated
herein by reference
3.2 Certificate of Designation of Series C Convertible Preferred
Stock of the Company, filed as an Exhibit to the Company's
Current Report on Form 8-K dated December 24, 1997, which
Exhibit is incorporated herein by reference.
3.3 Certificate of Amendment to the Restated Certificate of
Incorporation of the Company, filed with the Secretary of
State for the State of Delaware on September 19, 2000 which
Certificate was filed as an Exhibit to the Company's
Registration Statement on Form S-2 filed with the Securities
and Exchange Commission on October 6, 2000 (No. 333-41992),
which Exhibit is incorporated herein by reference.
3.4* Certificate of Amendment to the Restated Certificate of
Incorporation of the Company, filed with the Secretary of
State for the State of Delaware on October 26, 2000, which
Certificate is filed herewith.
3.5 Amended and Restated Bylaws of the Company, filed as an
Exhibit to the Company's Current Report on Form 8-K dated
March 27, 1997, which Exhibit is incorporated herein by
reference.
4.1 Indenture, dated July 1, 1998, in regard to 12 1/2% Senior
Notes due 2008 by and among the Company and certain of its
subsidiaries and Harris Trust and Savings Bank, as Trustee,
filed as an Exhibit to the Company's Current Report on Form
8-K dated July 8, 1998, which Exhibit is incorporated herein
by reference.
4.2* First Supplement to Indenture dated October 12, 2000 among
the Company, certain of its subsidiaries and Harris Trust and
Savings Bank as Trustee, which Exhibit is filed herewith.
4.3 Settlement Agreement dated as of July 17, 2000 between the
Company and the stockholders named therein, filed as an
Exhibit to the Company's Registration Statement on Form S-2
filed with the Securities and Exchange Commission on October
6, 2000 (No. 333-41992), which Exhibit is incorporated herein
by reference.
4.4 Participation Agreement dated as of July 17, 2000 between the
Company and the holders of its 12 1/2% senior notes therein
filed as an Exhibit to the Company's Registration Statement on
Form S-2 filed with the Securities and Exchange Commission on
October 6, 2000 (No. 333-41992) which Exhibit is incorporated
herein by reference.
4.5 Amendment to Participation Agreement dated as of October 4,
2000 between the Company and certain holders of its 12 1/2%
senior notes therein filed as an Exhibit to the Company's
Registration Statement on Form S-2 filed with the Securities
and Exchange Commission on October 6, 2000 (No. 333-41992),
which Exhibit is incorporated herein by reference
10.1 Queen Sand Resources 1997 Incentive Equity Plan, filed as an
Exhibit to the Company's Registration Statement on Form S-4
filed with the Securities and Exchange Commission on August
13, 1998, which Exhibit is incorporated herein by reference.
10.2* Form of DevX Energy, Inc. Restated and Amended Incentive
Equity Plan filed herewith**.
10.3* Form of Option Agreement issued under the Amended and Restated
Incentive Equity Plan filed herewith**.
41
44
10.4 Directors' Non-Qualified Stock Option Plan filed as Appendix A
to the Company's Definitive Proxy Statement on Schedule 14A
dated October 23, 1998, which Exhibit is incorporated herein
by reference**.
10.5* Form of DevX Energy, Inc. Restated and Amended Directors'
Non-Qualified Stock Option Plan filed herewith**.
10.6* Form of Option Agreement issued under the Amended and Restated
Directors' Non-Qualified Stock Option Plan filed herewith**.
10.7 Amended and Restated Credit Agreement among the Company, DevX
Energy, Inc., a Nevada corporation, (formerly known as Queen
Sand Resources, Inc.), Ableco Finance LLC, as Collateral
Agent, and the lenders signatory thereto, effective as of
October 22, 1999, filed as an Exhibit to the Company's
Quarterly Report on Form 10-Q for the quarter ended September
30, 1999.
10.8 Second Amended And Restated Guaranty Agreement dated as of
October 22, 1999 by the Company as Guarantor in favor of
Ableco Finance LLC, as Collateral Agent for the lender group
and the lenders signatory thereto, filed as an Exhibit to the
Company's Quarterly Report on Form 10-Q for the quarter ended
September 30, 1999.
10.9 Second Amended And Restated Guaranty Agreement dated as of
October 22, 1999 by DevX Operating Company a Nevada
corporation, (formerly known as Queen Sand Operating Co.), as
Guarantor, in favor of Ableco Finance LLC, as Collateral Agent
for the lender group, and the lenders signatory thereto, filed
as an Exhibit to the Company's Quarterly Report on Form 10-Q
for the quarter ended September 30, 1999.
10.10 Second Amended And Restated Guaranty Agreement dated as of
October 22, 1999 by Corrida Resources, Inc. as Guarantor, in
favor of Ableco Finance LLC, as Collateral Agent for the
lender group, and the lenders signatory thereto, filed as an
Exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1999.
10.11 Security Agreement dated as of October 22, 1999, by and among
the Company, DevX Energy, Inc., a Nevada corporation,
(formerly known as Queen Sand Resources, Inc.), DevX Operating
Company (formerly known as Queen Sand Operating Co.), Corrida
Resources, Inc. and Ableco Finance LLC, as collateral agent
for the lender group, and the lenders signatory thereto, filed
as an Exhibit to the Company's Quarterly Report on Form 10-Q
for the quarter ended September 30, 1999.
10.12 Second Amended and Restated Pledge and Security Agreement
dated as of October 22, 1999, by DevX Energy, Inc., a Nevada
corporation, (formerly known as Queen Sand Resources, Inc.),
in favor of Ableco Finance LLC, as Collateral Agent for the
lender group, and the lenders signatory thereto, filed as an
Exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1999.
10.13 Second Amended and Restated Pledge and Security Agreement
dated as of October 22, 1999, by the Company in favor of
Ableco Finance LLC, as Collateral Agent for the lender group,
and the lenders signatory thereto, filed as an Exhibit to the
Company's Quarterly Report on Form 10-Q for the quarter ended
September 30, 1999.
10.14 Amendment No. 1 to Credit Agreement dated May 2000 among the
Company, DevX Energy, Inc., a Nevada corporation (formerly
known as Queen Sand Resources, Inc.), Ableco Finance LLC, as
Collateral Agent, and the lenders signatory thereto, filed as
an Exhibit to the Company's Registration Statement on Form S-2
(No. 333-41992), which Exhibit is incorporated by reference.
10.15 Amendment No. 2 to Credit Agreement dated June 30, 2000 among
the Company, DevX Energy, Inc., a Nevada corporation,
(formerly known as Queen Sand Resources, Inc.), Ableco Finance
LLC, as Collateral Agent, and the lenders signatory thereto,
filed as an Exhibit to the Company's Registration Statement on
Form S-2 filed with the Securities and Exchange Commission on
October 6, 2000, (No. 333-41992), which Exhibit is
incorporated by reference.
10.16 Amendment No. 3 to Credit Agreement dated September , 2000
among the Company, DevX Energy, Inc., a Nevada corporation
(formerly known as Queen Sand Resources, Inc.), Ableco Finance
LLC,
42
45
as Collateral Agent, and the lenders signatory thereto, filed
as an Exhibit to the Company's Registration Statement on Form
S-2 filed with the Securities and Exchange Commission on
October 6, 2000 (No. 333-41992), which Exhibit is incorporated
by reference.
10.17 Amendment No. 4 to Credit Agreement dated October 24, 2000
among the Company, DevX Energy, Inc., a Nevada corporation,
Ableco Finance LLC, as Collateral Agent, and the lenders
signatory thereto, filed as an Exhibit to the Company's
Quarterly Report on Form 10-Q for the quarter ended September
30, 2000, which Exhibit is incorporated by reference.
10.18* Amendment No. 5 to Credit Agreement dated January 31, 2001
among the Company, DevX Energy, Inc., a Nevada corporation,
Ableco Finance LLC, as Collateral Agent, and the lenders
signatory thereto, which Amendment is filed herewith.
10.19* Employment Agreement dated as of October 6, 2000 between the
Company and Joseph T. Williams which agreement is filed
herewith**.
10.20* Form of Directors' Indemnity Agreement signed by Jerry B.
Davis and Robert L. Keiser.**
10.21 Employment Agreement dated December 15, 1997 between the
Company and Robert P. Lindsay, filed as an Exhibit to the
Company's Registration Statement on Form S-4 filed with the
Securities and Exchange Commission on August 13, 1998 (No.
333-61403) which Exhibit is incorporated herein by
reference**.
10.22* Release Agreement dated December 7, 2000 between the Company
and Robert P. Lindsay which agreement is filed herewith**.
10.23 Employment Agreement dated December 15, 1997 among the
Company, Queen Sand Resources (Canada) Inc. and Bruce I. Benn,
filed as an Exhibit to the Company's Registration Statement on
Form S-4 filed with the Securities and Exchange Commission on
August 13, 1998 (No. 333-61403) which Exhibit is incorporated
herein by reference**.
10.24* Release Agreement dated December 7, 2000 between the Company
and Bruce I. Benn which agreement is filed herewith**.
10.25 Employment Agreement dated December 15, 1997 among the
Company, Queen Sand Resources (Canada) Inc. and Ronald Benn,
filed as an Exhibit to the Company's Registration Statement on
Form S-4 filed with the Securities and Exchange Commission on
August 13, 1998 (No. 333-61403) which Exhibit is incorporated
herein by reference**.
10.26 Release Agreement dated September 15, 2000 between the Company
and Ronald I. Benn filed as an Exhibit to the Company's
Registration Statement on Form S-2 filed with the Securities
and Exchange Commission on October 6, 2000 (No. 333-41992),
which Exhibit is incorporated by reference**.
10.27* Employment Agreement dated as of November 10, 2000 between the
Company and Edward J. Munden which agreement is filed
herewith**.
10.28* Employment Agreement dated as of November 10, 2000 between the
Company and William W. Lesikar which agreement is filed
herewith**.
10.29* Employment Agreement dated as of November 10, 2000 between the
Company and Brian J. Barr which agreement is filed herewith**.
21.1 List of the subsidiaries of the registrant filed as an Exhibit
to the Company's Registration Statement on Form S-4 filed with
the Securities and Exchange Commission on August 13, 1999 (No.
333-61403) which Exhibit is incorporated by reference.
23.1* Consent of Ernst & Young LLP.
23.2* Consent of Ryder Scott Company.
23.3* Consent of H.J. Gruy and Associates, Inc.
- -----------
* Indicates filed herewith.
** Indicates management contract
43
46
(b) REPORTS ON FORM 8-K
During the last quarter of the fiscal year ended December 31, 2000, the
Company filed the following reports:
(i) A Current Report on Form 8-K, dated November 29, 2000 pursuant to
Item 5 with respect to the sale of 1,500,000 shares of the
Company's common stock pursuant to the exercise of an
underwriters' over-allotment option.
(ii) A Current Report on Form 8-K, dated November 10, 2000 pursuant to
Item 5 with respect to the appointment of Patrick J. Keeley to
the Board of Directors, and pursuant to Item 8 with respect to a
change in fiscal year-end to December 31, 2000 and pursuant to
Item 9 regarding an estimate of SEC PV-10 reserve value as of
September 30, 2000.
(c) FINANCIAL STATEMENT SCHEDULE AND AUDITORS' REPORT.
No other financial statement schedules are filed as part of this Form
10-K since the required information is included in the financial statements,
including the notes thereto, or circumstances requiring the inclusion of such
schedules are not present.
44
47
SIGNATURE PAGE
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) 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 ON THE 30TH DAY OF MARCH,
2001.
DEVX ENERGY, INC.
By: /s/ EDWARD J. MUNDEN
-------------------------------------
Name: Edward J. Munden
Title: Chief Executive Officer and President
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT IN THE CAPACITIES INDICATED ON THE 30TH DAY OF MARCH 2001.
SIGNATURE TITLE
- --------- -----
/s/ JOSEPH T. WILLIAMS CHAIRMAN OF THE BOARD
- --------------------------
JOSEPH T. WILLIAMS
/s/ EDWARD J. MUNDEN PRESIDENT, CHIEF EXECUTIVE
- -------------------------- OFFICER AND DIRECTOR
EDWARD J. MUNDEN (PRINCIPAL EXECUTIVE OFFICER)
/s/ WILLIAM W. LESIKAR CHIEF FINANCIAL OFFICER (PRINCIPAL
- -------------------------- FINANCIAL OFFICER AND ACCOUNTING OFFICER)
WILLIAM W. LESIKAR
/s/ ROBERT L. KEISER DIRECTOR
- --------------------------
ROBERT L. KEISER
/s/ JERRY B. DAVIS DIRECTOR
- --------------------------
JERRY B. DAVIS
/s/ PATRICK J. KEELEY DIRECTOR
- --------------------------
PATRICK J. KEELEY
45
48
DEVX ENERGY, INC. AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Report of Ernst & Young LLP, Independent Auditors.......................... F-2
Consolidated Financial Statements
Consolidated Balance Sheets as of December 31, 2000 and 1999............... F-3
Consolidated Statements of Operations for the
Years ended December 31, 2000, 1999 and 1998.......................... F-4
Consolidated Statements of Stockholders' Equity (Net Capital
Deficiency) for the Years ended December 31, 2000, 1999 and 1998...... F-5
Consolidated Statements of Cash Flows for the
Years ended December 31, 2000, 1999 and 1998.......................... F-7
Notes to Consolidated Financial Statements................................. F-8
49
REPORT OF ERNST & YOUNG LLP, INDEPENDENT AUDITORS
The Board of Directors and Stockholders
DevX Energy, Inc.
We have audited the accompanying consolidated balance sheets of DevX Energy,
Inc. and subsidiaries as of December 31, 2000 and 1999, and the related
consolidated statements of operations, stockholders' equity (net capital
deficiency), and cash flows for each of the three years in the period ended
December 31, 2000. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audit.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of DevX Energy, Inc.
and subsidiaries as of December 31, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.
As discussed in Note 1 to the consolidated financial statements, effective July
1, 2000, the Company adopted Statement of Financial Accounting Standards No.
133, "Accounting for Derivative Instruments and Hedging Activities."
Dallas, Texas
March 1, 2001
F-2
50
DEVX ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31
------------------------------
2000 1999
------------- -------------
ASSETS
Current assets:
Cash $ 10,985,000 $ 3,376,000
Accounts receivable 10,557,000 4,727,000
Other 183,000 459,000
------------- -------------
Total current assets 21,725,000 8,562,000
------------- -------------
Property and equipment, at cost:
Oil and gas properties, based on full cost accounting method 191,204,000 181,549,000
Other equipment 446,000 402,000
------------- -------------
191,650,000 181,951,000
Less accumulated depreciation and amortization (94,559,000) (85,969,000)
------------- -------------
Net property and equipment 97,091,000 95,982,000
Other assets 2,953,000 8,074,000
Deferred tax asset 1,221,000 --
------------- -------------
$ 122,990,000 $ 112,618,000
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 1,004,000 $ 2,328,000
Accrued liabilities 6,503,000 8,721,000
Current portion of long-term obligations -- 877,000
Derivatives 1,507,000 --
------------- -------------
Total current liabilities 9,014,000 11,926,000
Long-term obligations, net of current portion 50,000,000 134,106,000
Derivatives 12,246,000 --
Commitments and contingencies
Stockholders' equity (net capital deficiency):
Preferred stock, $0.01 par value:
Authorized shares - 50,000,000 at December 31, 2000 and 1999
Issued and outstanding shares - 0 and 9,604,248 at December 31,
2000 and 1999, respectively -- 96,000
Aggregate liquidation preference - $0 and $9,678,000 at December 31,
2000 and 1999, respectively
Common stock, $0.234 par value:
Authorized shares - 100,000,000 at December 31, 2000 and 1999
Issued and outstanding shares - 12,748,612 and 236,960 at
December 31, 2000 and 1999, respectively 2,983,000 70,000
Additional paid-in capital 60,159,000 64,945,000
Retained earnings (deficit) ($68,130,000 of accumulated deficit
eliminated in the quasi-reorganization of October 31, 2000) 834,000 (91,274,000)
Accumulated other comprehensive loss (12,246,000)
Treasury stock, at cost -- (7,251,000)
------------- -------------
Total stockholders' equity (net capital deficiency) 51,730,000 (33,414,000)
------------- -------------
Total liabilities and stockholders' equity $ 122,990,000 $ 112,618,000
============= =============
See accompanying notes.
F-3
51
DEVX ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
YEAR ENDED DECEMBER 31
--------------------------------------------
2000 1999 1998
------------ ------------ ------------
Revenues:
Oil and gas sales $ 4,484,000 $ 3,625,000 $ 5,852,000
Net profits and royalty interests 31,507,000 21,955,000 15,947,000
Interest and other 90,000 345,000 156,000
------------ ------------ ------------
Total revenues 36,081,000 25,925,000 21,955,000
------------ ------------ ------------
Expenses:
Production expenses 1,727,000 1,622,000 4,326,000
Depreciation and amortization 8,637,000 9,418,000 10,866,000
Hedge contract termination costs -- 3,328,000 --
Write-down of oil and gas properties -- -- 63,199,000
General and administrative 4,497,000 3,629,000 2,420,000
------------ ------------ ------------
Total expenses 14,861,000 17,997,000 80,811,000
------------ ------------ ------------
Operating income (loss) 21,220,000 7,928,000 (58,856,000)
Other expenses:
Interest and financing costs 17,264,000 18,587,000 12,235,000
Change in fair value of derivatives 1,945,000 -- --
------------ ------------ ------------
Income (loss) before income taxes, extraordinary items,
and cumulative effect of accounting change 2,011,000 (10,659,000) (71,091,000)
Income tax benefit 642,000 -- --
------------ ------------ ------------
Income (loss) before extraordinary items and cumulative
effect of accounting change 2,653,000 (10,659,000) (71,091,000)
Extraordinary gain (loss), net of tax 21,144,000 (1,130,000) (3,549,000)
------------ ------------ ------------
Income (loss) before cumulative effect of accounting change
23,797,000 (11,789,000) (74,640,000)
Cumulative effect of accounting change, net of tax 413,000 -- --
------------ ------------ ------------
Net income (loss) $ 24,210,000 $(11,789,000) $(74,640,000)
============ ============ ============
Basic income (loss) per share amounts:
Income (loss) before cumulative effect of accounting
change and extraordinary items $ 1.12 $ (49.52) $ (414.90)
Extraordinary gain (loss) 8.94 (5.24) (20.71)
------------ ------------ ------------
Income (loss) before cumulative effect of accounting
change 10.06 (54.76) (435.61)
Cumulative effect of accounting change 0.18 -- --
------------ ------------ ------------
Net income (loss) $ 10.24 $ (54.76) $ (435.61)
============ ============ ============
Diluted income (loss) per shares amounts:
Income (loss) before cumulative effect of accounting
change and extraordinary items $ 0.87 $ (49.52) $ (414.90)
Extraordinary gain (loss) 6.95 (5.24) (20.71)
------------ ------------ ------------
Income (loss) before cumulative effect of accounting
change 7.82 (54.76) (435.61)
Cumulative effect of accounting change 0.14 -- --
------------ ------------ ------------
Net income (loss) $ 7.96 $ (54.76) $ (435.61)
============ ============ ============
Weighted average shares outstanding:
Basic 2,364,817 215,268 171,344
Diluted 3,041,386 215,268 171,344
See accompanying notes.
F-4
52
DEVX ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(NET CAPITAL DEFICIENCY)
YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
PREFERRED STOCK COMMON STOCK ADDITIONAL
---------------------------- --------------------------- PAID-IN
SHARES AMOUNT SHARES AMOUNT CAPITAL TREASURY
------------ ------------ ------------ ------------ ------------ ------------
Balance at December 31, 1997 9,610,400 $ 96,000 144,395 $ 48,000 $ 29,020,000 $ (5,000,000)
Issuance of common
stock for oil and
gas properties -- -- 2,219 1,000 1,751,000 --
Issuance of common
stock for cash -- -- 34,013 8,000 26,972,000 --
Issuance of common
stock upon exercise
of warrants -- -- 15,860 4,000 6,996,000 --
Issuance of common
stock pursuant to
repricing rights -- -- 4,984 1,000 (1,000) --
Issuance of common
stock on conversion
of convertible
preferred stock (2,290) -- 2,534 -- -- --
Issuance of common
stock as stock
dividend -- -- 111 -- 98,000 --
Repurchase of
convertible
preferred stock (2,152) -- -- -- -- (2,251,000)
Net loss -- -- -- -- -- --
------------ ------------ ------------ ------------ ------------ ------------
Balance at December 31, 1998 9,605,958 96,000 204,116 62,000 64,836,000 (7,251,000)
Issuance of common
stock pursuant to
repricing rights -- -- 19,245 5,000 (5,000) --
Issuance of common
stock on
conversion of
convertible preferred
stock (1,710) -- 12,642 3,000 (3,000) --
Issuance of common
stock as stock
dividend -- -- 957 -- 117,000 --
Net loss -- -- -- -- -- --
------------ ------------ ------------ ------------ ------------ ------------
Balance at December 31, 1999 9,604,248 $ 96,000 236,960 $ 70,000 $ 64,945,000 $ (7,251,000)
ACCUMULATED
OTHER RETAINED TOTAL
COMPREHENSIVE EARNINGS STOCKHOLDERS'
LOSS (DEFICIT) EQUITY
------------ ------------ ------------
Balance at December 31, 1997 $ -- $ (4,630,000) $ 19,534,000
------------ ------------ ------------
Issuance of common
stock for oil and
gas properties -- -- 1,752,000
Issuance of common
stock for cash -- -- 26,980,000
Issuance of common
stock upon exercise
of warrants -- -- 7,000,000
Issuance of common
stock pursuant to
repricing rights -- -- --
Issuance of common
stock on conversion
of convertible
preferred stock -- -- --
Issuance of common
stock as stock
dividend -- (98,000) --
Repurchase of
convertible
preferred stock -- -- (2,251,000)
Net loss -- (74,640,000) (74,640,000)
------------ ------------ ------------
Balance at December 31, 1998 -- (79,368,000) (21,625,000)
Issuance of common
stock pursuant to
repricing rights -- -- --
Issuance of common
stock on
conversion of
convertible preferred
stock -- -- --
Issuance of common
stock as stock
dividend -- (117,000) --
Net loss -- (11,789,000) (11,789,000)
------------ ------------ ------------
Balance at December 31, 1999 $ -- $(91,274,000) $(33,414,000)
F-5
53
DEVX ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (CONTINUED)
(NET CAPITAL DEFICIENCY)
YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
PREFERRED STOCK COMMON STOCK ADDITIONAL
---------------------------- --------------------------- PAID-IN
SHARES AMOUNT SHARES AMOUNT CAPITAL TREASURY
------------ ------------ ------------ ------------ ------------ ------------
Issuance of common
stock for cash -- $ -- 11,498,878 $ 2,691,000 $ 70,421,000 $ --
Issuance of common
stock pursuant to
repricing rights -- -- 628,962 147,000 (147,000) --
Issuance of common
stock on conversion
of convertible
preferred stock (9,604,248) (96,000) 378,519 89,000 7,000 --
Issuance of common
stock as stock
dividend -- -- 5,293 1,000 231,000 --
Retire treasury stock -- -- -- (15,000) (7,236,000) 7,251,000
Reclassification of
accumulated deficit
pursuant to
quasi-reorganization -- -- -- -- (68,130,000) --
Other -- -- -- -- 68,000 --
Net income -- -- -- -- -- --
Cumulative effect
of accounting change -- -- -- -- -- --
Unrealized losses on
derivatives -- -- -- -- -- --
Comprehensive
income -- -- -- -- -- --
------------ ------------ ------------ ------------ ------------ ------------
Balance at
December 31, 2000 -- $ -- $ 12,748,612 $ 2,983,000 $ 60,159,000 $ --
============ ============ ============ ============ ============ ============
ACCUMULATED
OTHER RETAINED TOTAL
COMPREHENSIVE EARNINGS STOCKHOLDERS'
LOSS (DEFICIT) EQUITY
------------ ------------ ------------
Issuance of common
stock for cash $ -- $ -- $ 73,112,000
Issuance of common
stock pursuant to
repricing rights -- -- --
Issuance of common
stock on conversion
of convertible
preferred stock -- -- --
Issuance of common
stock as stock
dividend -- (232,000) --
Retire treasury stock -- -- --
Reclassification of
accumulated deficit
pursuant to
quasi-reorganization -- 68,130,000 --
Other -- -- 68,000
Net income 24,210,000 24,210,000
Cumulative effect
of accounting change (5,515,000) -- (5,515,000)
Unrealized losses on
derivatives (6,731,000) -- (6,731,000)
Comprehensive
income -- -- (11,964,000)
------------ ------------ ------------
Balance at
December 31, 2000 $(12,246,000) $ 834,000 $ 51,730,000
============ ============ ============
See accompanying notes.
F-6
54
DEVX ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31
-----------------------------------------------
2000 1999 1998
------------- ------------- -------------
OPERATING ACTIVITIES
Income (loss) before extraordinary items and cumulative effect of
change in accounting $ 2,653,000 $ (10,659,000) $ (71,091,000)
Adjustments to reconcile income (loss) to net cash provided by
operating activities:
Deferred tax benefit (1,424,000) -- --
Depreciation and amortization 8,637,000 9,313,000 10,850,000
Amortization of deferred costs 1,605,000 1,242,000 738,000
Write-down of oil and gas properties -- -- 63,199,000
Change in market value of derivatives 1,945,000 -- --
Unrealized foreign currency translation gains (43,000) (131,000) --
Changes in operating assets and liabilities:
Accounts receivable (5,830,000) 246,000 (3,660,000)
Other assets 276,000 4,000 (379,000)
Accounts payable and accrued liabilities (1,305,000) 678,000 8,720,000
------------- ------------- -------------
Net cash provided by operating activities 6,514,000 693,000 8,377,000
INVESTING ACTIVITIES
Additions to oil and gas properties (13,043,000) (7,494,000) (153,961,000)
Proceeds from sales of oil and gas properties 3,386,000 10,236,000 --
Other 84,000 (706,000) (9,623,000)
------------- ------------- -------------
Net cash provided by (used in) investing activities (9,573,000) 2,036,000 (163,584,000)
FINANCING ACTIVITIES
Proceeds from revolving credit facilities 14,000,000 20,032,000 92,800,000
Debt issuance costs -- (1,130,000) --
Termination of LIBOR swap agreement -- -- (3,549,000)
Payment on revolving credit facilities (23,106,000) (21,227,000) (87,671,000)
Proceeds from issuance of 12.5% senior notes -- -- 125,000,000
Redemption of 12.5% senior notes (52,504,000) -- --
Redemption of DEM bonds (791,000) -- (1,206,000)
Payments on notes payable -- -- (1,901,000)
Proceeds from the issuance of common stock 73,112,000 -- 33,980,000
Repurchase of common and preferred stock -- -- (2,251,000)
Payments on capital lease obligation (43,000) (67,000) (71,000)
------------- ------------- -------------
Net cash provided by (used in) financing activities 10,668,000 (2,392,000) 155,131,000
Net increase (decrease) in cash 7,609,000 337,000 (76,000)
Cash at beginning of year 3,376,000 3,039,000 3,115,000
------------- ------------- -------------
Cash at end of year $ 10,985,000 $ 3,376,000 $ 3,039,000
============= ============= =============
See accompanying notes.
F-7
55
DEVX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
GENERAL
DevX Energy, Inc. (DEVX or the Company, formerly Queen Sand Resources, Inc.) was
formed on August 9, 1994, under the laws of the State of Delaware. The Company
is engaged in one industry segment: the acquisition, exploration, development,
production and sale of crude oil and natural gas. The Company's business
activities are carried out primarily in Kentucky, Oklahoma and Texas. Effective
December 31, 2000, the Company changed its fiscal year end to December 31. The
accompanying financial statements have been prepared on a calendar year for each
period presented.
PRINCIPLES OF CONSOLIDATION
The accompanying consolidated financial statements include the accounts of the
Company and its wholly owned subsidiaries. All significant intercompany balances
and transactions have been eliminated in consolidation.
PROPERTY AND EQUIPMENT
The Company follows the full cost method of accounting for its oil and gas
activities under which all costs, including general and administrative expenses
directly associated with property acquisition, exploration and development
activities, are capitalized. Capitalized general and administrative expenses
directly associated with acquisitions, exploration and development of oil and
gas properties were approximately $691,000, $813,000 and $1,287,000 for the
years ended December 31, 2000, 1999 and 1998, respectively. Capitalized costs
are amortized by the unit-of-production method using estimates of proved oil and
gas reserves prepared by independent engineers. The costs of unproved properties
are excluded from amortization until the properties are evaluated. Sales of oil
and gas properties are accounted for as adjustments to the capitalized cost
center unless such sales significantly alter the relationship between
capitalized costs and proved reserves of oil and gas attributable to the cost
center, in which case a gain or loss is recognized.
The Company limits the capitalized costs of oil and gas properties, net of
accumulated amortization, to the estimated future net revenues from proved oil
and gas reserves less estimated future development and production expenditures
discounted at 10%, plus the lower of cost or estimated fair value of unproved
properties, as adjusted for related estimated future tax effects. If capitalized
costs exceed this limit (the full cost ceiling), the excess is charged to
depreciation and amortization expense. During the year ended December 31, 1998,
the Company recorded full cost ceiling write-downs of $63,199,000.
Amortization of the capitalized costs of oil and gas properties and limits to
capitalized costs are based on estimates of oil and gas reserves which are
inherently imprecise and are subject to change based on factors such as crude
oil and natural gas prices, drilling results, and the results of production
activities, among others. Accordingly, it is reasonably possible that such
estimates could differ materially in the near term from amounts currently
estimated.
Depreciation of other property and equipment is provided principally by the
straight-line method over the estimated service lives of the related assets.
Equipment under capital lease is recorded at the lower of fair value or the
present value of future minimum lease payments and is depreciated over the lease
term.
Costs incurred to operate, repair and maintain wells and equipment are charged
to expense as incurred.
F-8
56
DEVX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Certain of the Company's oil and gas activities are conducted jointly with
others and, accordingly, the financial statements reflect only the Company's
proportionate interest in such activities.
The Company does not expect future costs for site restoration, dismantlement and
abandonment, postclosure, and other exit costs which may occur in the sale,
disposal or abandonment of a property to be material.
REVENUE RECOGNITION
The Company uses the sales method of accounting for oil and gas revenues. Under
the sales method, revenues are recognized based on actual volumes of oil and gas
sold to purchasers.
ENVIRONMENTAL MATTERS
The Company is subject to extensive federal, state and local environmental laws
and regulations. These laws, which are constantly changing, regulate the
discharge of materials into the environment and may require the Company to
remove or mitigate the environmental effects of the disposal or release of
petroleum or chemical substances at various sites. Environmental expenditures
are expensed or capitalized depending on their future economic benefit.
Expenditures that relate to an existing condition caused by past operations and
that have no future economic benefits are expensed. Liabilities for expenditures
of a noncapital nature are recorded when environmental assessment and/or
remediation is probable and the costs can be reasonably estimated.
INCOME TAXES
Deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases and operating loss and tax credit carryforwards. Deferred tax assets and
liabilities are measured using enacted tax rates. The effect on deferred tax
assets and liabilities of a change in tax rates is recognized in income in the
period that includes the enactment date. The measurement of deferred tax assets
is adjusted by a valuation allowance, if necessary, to recognize the extent to
which, based on available evidence, the future tax benefits more likely than not
will be realized.
STATEMENT OF CASH FLOWS
The Company considers all highly liquid investments purchased with an original
maturity of three months or less to be cash equivalents.
During 1998, the Company issued an aggregate of 2,219 shares of Common Stock
valued at $1,752,000 in connection with the acquisition of certain interests in
oil and gas properties.
INCOME (LOSS) PER COMMON SHARE
Basic income or loss per share is calculated based on the weighted average
number of common shares outstanding during the period. If applicable, diluted
earnings per share is calculated based on the weighted average number of common
shares outstanding during the period plus any dilutive common equivalent shares
outstanding. As the Company incurred net losses during each of the years ended
December 31, 1999 and 1998, the loss per common
F-9
57
DEVX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
share data is based on the weighted average common shares outstanding and
excludes the effects of the Company's potentially dilutive securities (Note 6).
The following table reconciles basic and diluted weighted average shares
outstanding:
2000 1999 1998
--------- --------- ---------
Basic weighted average shares 2,364,817 215,268 171,344
Dilutive effect of:
Common stock repricing rights 673,627 -- --
Employee stock options 2,942 -- --
--------- --------- ---------
Diluted weighted average shares 3,041,386 215,268 171,344
========= ========= =========
Losses per common share for periods prior to the completion of the Company's
recapitalization transaction (Note 2) have been restated for the effects of a
156-to-1 reverse stock split.
STOCK COMPENSATION
The Company has elected to follow Accounting Principles Board Opinion No. 25,
Accounting for Stock Issued to Employees (APB 25), in accounting for its
employee stock options. Under APB 25, if the exercise price of an employee's
stock options equals or exceeds the market price of the underlying stock on the
date of grant and certain other plan conditions are met, no compensation expense
is recognized.
In March 2000, the Financial Accounting Standards Board issued Interpretation
No. 44, Accounting for Certain Transactions Involving Stock Compensation (FIN
44), an interpretation of APB 25. FIN 44, which was adopted prospectively by the
Company as of July 1, 2000, requires certain changes to the previous practice
regarding the accounting for certain stock compensation arrangements. FIN 44
does not change APB 25's intrinsic value method, under which compensation
expense is generally not recognized for grants of stock options to employees
with an exercise price equal to the market price of the stock at the date of
grant, but it has narrowed its application. The adoption of FIN 44 did not have
a significant effect on the Company's existing accounting for its employee stock
options.
CONCENTRATIONS OF RISK
The Company sells crude oil and natural gas to various customers. In addition,
the Company participates with other parties in the operation of crude oil and
natural gas wells. Substantially all of the Company's accounts receivable are
due from either purchasers of crude oil and natural gas or participants in crude
oil and natural gas wells for which the Company serves as the operator.
Generally, operators of crude oil and natural gas properties have the right to
offset future revenues against unpaid charges related to operated wells. The
Company's receivables are generally unsecured.
For the year ended December 31, 2000, four oil and gas companies accounted for
31%, 18%, 14% and 13%, respectively, of the Company's oil and gas sales. For the
year ended December 31, 1999, four oil and gas companies accounted for 29%, 14%,
12% and 9%, respectively, of the Company's oil and gas sales. For the year ended
December 31, 1998, three oil and gas companies accounted for 29%, 12% and 11%,
respectively, of the Company's
F-10
58
DEVX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
oil and gas sales. The Company does not believe that the loss of any of these
buyers would have a material effect on the Company's business or results of
operations as it believes it could readily locate other buyers.
The Company's revenues and profitability are highly dependent upon the
prevailing prices for oil and natural gas. As the Company produces more natural
gas than oil, it faces more risk related to fluctuations in natural gas prices
than oil prices. To reduce the exposure to changes in the price of oil and
natural gas, the Company has entered into certain derivative contracts (Note 5).
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements, and
the reported amounts of revenue and expenses during the reporting period.
Because of the use of estimates inherent in the financial reporting process,
actual results could differ from those estimates.
COMPREHENSIVE INCOME
Comprehensive income is defined as the change in equity of a business enterprise
during a period from transactions and other events and circumstances from
non-owner sources. For the year ended December 31, 2000, the Company's
comprehensive income differed from net income by approximately $12,246,000, due
to the recognition in comprehensive income of unrealized losses related to
certain of the Company's derivative instruments which have been designated as
hedges. For the years ended December 31, 1999 and 1998, there were no
differences between the Company's net losses and total comprehensive income.
DERIVATIVES
The Company utilizes certain derivative financial instruments, primarily swaps,
floors and collars, to hedge future oil and 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. Prior to adoption of SFAS No. 133, gains and losses arising from the
use of derivative instruments were deferred until realized. The Company
estimates fair value based on quotes obtained from the counterparties 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 other income. If the derivative is 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.
Upon adoption of SFAS No. 133, the Company had four open derivative contracts.
One contract, a natural gas swap, has been designated 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
F-11
59
DEVX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
item over time. At adoption, the Company recognized a derivative liability and a
reduction in other comprehensive income of approximately $5,515,000 as a
cumulative effect of accounting change for this cash flow hedge. During the six
months ended December 31, 2000, the Company recognized an increase in the
derivative liability and an associated other comprehensive loss totaling
approximately $6,731,000. No amounts were recognized in earnings for hedging
ineffectiveness during 2000.
Additionally upon adoption, the Company recognized a net derivative asset of
approximately $651,000 for the remaining three open derivative contracts, and a
related gain of approximately $413,000 as a cumulative effect of accounting
change in earnings. During the six months ended December 31, 2000, the Company
recognized a loss of approximately $1,945,000 related to the net change in the
fair value of derivative contracts which have not been designated as hedges.
Gains and losses from settlements of hedges of oil and gas prices are reported
as oil and gas sales. Gains and losses from settlements of interest rate hedges
are reported in interest expense.
2. QUASI-REORGANIZATION
On October 31, 2000, the Company completed a public offering of 10,000,000
shares of its common stock at a price per share to the public of $7.00. An
additional 1,500,000 shares were sold during November 2000 upon the
underwriter's exercise of its over-allotment option. The aggregate net proceeds
to the Company (after deducting underwriter discount and expenses, and costs to
repurchase fractional shares aggregating 1,122 shares of common stock) were
approximately $73,112,000. Simultaneously with the closing of the October 31,
2000 offering, the Company completed a recapitalization transaction which
included: (a) a reverse stock split of every 156 outstanding shares of common
stock into one share; (b) the exchange of all preferred stock, all warrants
exercisable for shares of common stock and all unexercised common stock
repricing rights (Note 6) for 732,500 shares of post reverse-split common stock;
(c) the repurchase of $75 million face value of 12.5% senior notes (Note 4) for
$52,504,000; and (d) the Company used proceeds from the offering to pay down the
balance on its revolving credit facility by $14 million ($11 million at closing
and $3 million from the exercise of the over-allotment option) (the
Recapitalization).
The Company's board of directors decided to effect a quasi-reorganization given
the infusion of new equity capital, the reduction in debt, changes in management
and changes in the Company's operations. Accordingly, the Company's accumulated
deficit as of the date of the Recapitalization, $68,130,000, was eliminated
against additional paid-in capital. The historical carrying values of the
Company's assets and liabilities were not adjusted in connection with the
quasi-reorganization.
Information presented for shares of common stock for all periods prior to the
Recapitalization has been restated to retroactively reflect the effects of the
reverse stock split.
3. NET PROFITS AND ROYALTY INTERESTS
During 1998, the Company acquired certain nonoperated net profits interests and
royalty interests (collectively, the Morgan Properties) from pension funds
managed by J.P. Morgan Investments. The Company's interest in the Morgan
Properties primarily takes the form of nonoperated net profits overriding
royalty interests, whereby the Company is entitled to a percentage of the net
profits from the operations of the properties. The oil and gas properties
burdened by the Morgan Properties are primarily located in East Texas, South
Texas and the mid-continent region of the United States.
F-12
60
DEVX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. NET PROFITS AND ROYALTY INTERESTS (CONTINUED)
Presented below are the oil and gas sales and associated production expenses
associated with the Company's net profits and royalty interests, which are
presented in the accompanying consolidated statements of operations for the
years ended December 31, 2000, 1999 and 1998, respectively, as net profits and
royalty interests revenues.
YEAR ENDED DECEMBER 31
---------------------------------------
2000 1999 1998
----------- ----------- -----------
Oil and gas sales $37,721,000 $26,741,000 $21,913,000
Production expenses 6,214,000 4,786,000 5,966,000
----------- ----------- -----------
Net profits and royalty interests $31,507,000 $21,955,000 $15,947,000
=========== =========== ===========
4. CURRENT AND LONG-TERM DEBT
A summary of current and long-term debt follows:
DECEMBER 31
---------------------------
2000 1999
------------ ------------
12.5% senior notes, due July 2008 $ 50,000,000 $125,000,000
12% unsecured DEM bonds, due July 2000 -- 834,000
Revolving credit agreement -- 9,106,000
Capital lease obligations -- 43,000
------------ ------------
50,000,000 134,983,000
Less current portion of debt and capitalized lease
obligation -- 877,000
------------ ------------
Total long-term obligations $ 50,000,000 $134,106,000
============ ============
During October 1999, the Company entered into an amended and restated revolving
credit agreement (the Credit Agreement) with new lenders. In connection with
entering into the Credit Agreement, the Company retired borrowings under its
previous credit agreement, terminating the arrangement. As a result, the Company
recorded an extraordinary loss of $1,130,000 relating to the write-off of the
unamortized deferred costs of the previous agreement. The Credit Agreement
allows the Company to borrow up to $43.5 million (subject to borrowing base
limitations). Borrowings under the Credit Agreement are secured by a first lien
on the Company's oil and natural gas properties. Borrowings under the Credit
Agreement bear interest at prime plus 2% on borrowings under $25 million and
prime plus 4.5%, if borrowings exceed $25 million. There were no outstanding
borrowings under the Credit Agreement at December 31, 2000. The interest rate at
December 31, 2000, was 11.5%. The loan under the Credit Agreement expires on
October 22, 2001. The Company is subject to certain affirmative and negative
financial and operating covenants under the Credit Agreement, including
maintaining a minimum interest coverage ratio, a minimum working capital ratio
and certain limitations on capital spending. At December 31, 2000, the Company
exceeded the capital spending limitation, for which the lender issued a waiver.
Letters of credit up to a maximum of $12 million may be issued on behalf of the
Company under the Credit Agreement, which bear interest at 3%. Any outstanding
letters of credit reduce the Company's ability to borrow
F-13
61
DEVX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
4. CURRENT AND LONG-TERM DEBT
under the Credit Agreement. At December 31, 2000, the Company had a letter of
credit outstanding in the amount of $8.5 million to secure a swap exposure (Note
5).
Effective January 31, 2001, the Credit Agreement was amended to extend the
maturity date to April 22, 2003, increase the capital spending limitation and
modify the interest rate. Borrowings under the amended Credit Agreement bear
interest as follows: 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%; 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%; and
on amounts securing letters of credit issued on our behalf, 3%.
On July 8, 1998, the Company completed a private placement of $125,000,000
principal amount of 12.5% senior notes (the Notes) due July 1, 2008. Interest on
the Notes is payable semiannually on January 1 and July 1 of each year,
commencing January 1, 1999, at the rate of 12.5% per annum. The Notes are senior
unsecured obligations of the Company and rank pari passu with any existing and
future unsubordinated indebtedness of the Company. The Notes rank senior to all
unsecured subordinated indebtedness of the Company. The Notes contain customary
covenants that limit the Company's ability to incur additional debt, pay
dividends and sell assets of the Company. Substantially all of the proceeds from
the issuance of the Notes were used to retire indebtedness incurred in
connection with the acquisition of the Morgan Properties. In connection with the
Recapitalization, the Company retired $75,000,000 face amount of the Notes,
recognizing an extraordinary gain of $21,144,000 (Note 2).
The Company's payment obligations under the Notes are jointly, severally and
unconditionally guaranteed by the Company's subsidiaries. The Company has no
significant assets and no operations other than those conducted by its
subsidiaries. No restrictions exist on the ability of the subsidiaries to make
loans or pay dividends to the Company.
Beginning in July 1995, the Company initiated private debt offerings whereby it
could issue up to a maximum of 5,000,000 Deutschmark (DEM) denominated 12% notes
due on July 15, 2000, of which DEM 1,600,000 were outstanding at December 31,
1999. During 2000, the Company retired all remaining outstanding notes for
approximately $791,000.
During the years ended December 31, 2000, 1999 and 1998, the Company made cash
payments of interest totaling approximately $15,800,000, $16,402,000 and
$3,953,000, respectively.
5. DERIVATIVES AND HEDGING ACTIVITIES
The Company uses swaps, floors and collars to hedge oil and natural gas prices.
Swaps are settled monthly based on differences between the prices specified in
the instruments and the settlement prices of futures contracts quoted on the New
York Mercantile Exchange (NYMEX). Generally, when the applicable settlement
price is less than the price specified in the contract, the Company receives a
settlement from the counterparty based on the difference multiplied by the
volume hedged. Similarly, when the applicable settlement price exceeds the price
specified in the contract, the Company pays the counterparty based on the
difference. The Company generally receives a settlement from the counterparty
for floors when the applicable settlement price is less than the price specified
in the contract, which is based on the difference multiplied by the volumes
hedged. For collars, generally the Company receives a settlement from the
counterparty when the settlement price is below the floor and pays a settlement
to the counterparty when the settlement price exceeds the cap. No settlement
occurs when the settlement price falls between the floor and cap.
F-14
62
DEVX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5. DERIVATIVES AND HEDGING ACTIVITIES (CONTINUED)
The Company had a collar with an affiliate of Enron Corp. (Enron), a stockholder
of the Company, to hedge 50,000 MMBtu of natural gas production and 10,000
barrels of oil production monthly. The agreements, effective September 1, 1997,
and terminating August 31, 1998, called for a natural gas and oil ceiling and
floor price of $2.66 and $1.90 per MMBtu and $20.40 and $18.00 per barrel,
respectively. During the year ended December 31, 1998, the Company recognized
net hedging gains of approximately $233,000 relating to these agreements, which
are included in oil and gas sales.
The table below sets out volumes of natural gas hedged with a floor price of
$1.90 per MMBtu with Enron, which received a fee of $478,000 during the year
ended December 31, 1998 for entering into this agreement. The volumes presented
in this table are divided equally over the months during the period.
VOLUME
PERIOD BEGINNING PERIOD ENDING (MMBtu)
- ---------------- ----------------- ---------
May 1, 1998 December 31, 1998 885,000
January 1, 1999 December 31, 1999 1,080,000
January 1, 2000 December 31, 2000 880,000
January 1, 2001 December 31, 2001 740,000
January 1, 2002 December 31, 2002 640,000
January 1, 2003 December 31, 2003 560,000
The table below sets out volumes 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)
- ---------------- ----------------- ---------
May 1, 1998 December 31, 1998 2,210,000
January 1, 1999 December 31, 1999 2,710,000
January 1, 2000 December 31, 2000 2,200,000
January 1, 2001 December 31, 2001 1,850,000
January 1, 2002 December 31, 2002 1,600,000
January 1, 2003 December 31, 2003 1,400,000
Effective November 1, 1999, the Company unwound the ceiling price limitation of
this collar at a cost of $3.3 million. The table below sets out volumes of
natural gas that remains under contract at a floor price of $2.00 per MMBtu. The
volumes presented in this table are divided equally over the months during the
period.
VOLUME
PERIOD BEGINNING PERIOD ENDING (MMBtu)
- ---------------- ----------------- ---------
November 1, 1999 December 31, 1999 722,000
January 1, 2000 December 31, 2000 3,520,000
January 1, 2001 December 31, 2001 2,970,000
January 1, 2002 December 31, 2002 2,550,000
January 1, 2003 December 31, 2003 2,250,000
F-15
63
DEVX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5. DERIVATIVES AND HEDGING ACTIVITIES (CONTINUED)
During the years ended December 31, 2000, 1999 and 1998, the Company recognized
hedging gains (losses) of approximately $(3,324,000), $644,000 and $803,000,
respectively, relating to cash settlements under these agreements, which are
included in net profits and royalty interests revenues.
During the year ended December 31, 1998, the Company entered into a swap
agreement with Enron to hedge 12,000 barrels of oil production monthly at $17.00
per barrel, for the months of October, November and December 1998. The Company
recognized hedging gains of approximately $147,000 relating to this agreement,
which are included in net profits and royalty interests revenues.
During the year ended December 31, 1999, the Company entered into a swap
agreement with Enron to hedge 10,000 barrels of oil production monthly at $13.50
per barrel for the six months March through August 1999, and for 5,000 barrels
of oil production monthly at $14.35 per barrel, and for 5,000 barrels of oil
production monthly at $14.82 per barrel for the six months April through
September 1999. During the year ended December 31, 1999, the Company recognized
hedging losses of approximately $589,000 relating to this agreement, which are
included in net profits and royalty interests revenues.
The table below sets out volumes of oil hedged with a collar with Enron
involving floor and ceiling prices as set out in the table below. The volumes
presented in this table are divided equally over the months during the period.
VOLUME FLOOR CEILING
PERIOD BEGINNING PERIOD ENDING (MMBtu) PRICE PRICE
- ---------------- ----------------- ------ ------ ---------
December 1, 1999 March 31, 2000 40,000 $22.90 $25.77
April 1, 2000 June 30, 2000 15,000 $23.00 $28.16
July 1, 2000 December 31, 2000 30,000 $22.00 $28.63
During the years ended December 31, 2000 and 1999, the Company recognized
hedging losses of approximately $3,000 and $203,000, respectively, relating to
this contract.
During the year ended December 31, 2000, the Company entered into a series of
collars to hedge a portion of future natural gas production involving floor and
ceiling prices as set out below. 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
The aggregate fair value of the Company's derivative contracts at December 31,
2000 represented a net liability of $13,540,000.
The Company entered into a forward LIBOR interest rate swap effective for the
period June 30, 1998 through June 29, 2009 at a rate of 6.3% on $125 million,
which could be unwound at any time at the option of the Company. On July 9,
1998, as a result of the retirement of the Bridge Facilities and borrowings
under the Credit Agreement, the
F-16
64
DEVX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5. DERIVATIVES AND HEDGING ACTIVITIES (CONTINUED)
Company terminated the agreement at a cost of $3,549,000. The cost of
termination has been reflected as an extraordinary loss in the accompanying
consolidated statement of operations for the year ended December 31, 1998.
6. STOCKHOLDERS' EQUITY
GENERAL
The Company's Certificate of Incorporation authorizes the issuance of: (a)
50,000,000 shares of preferred stock of the Company, par value $.01 per share
(the Preferred Stock), of which 9,600,000 shares have been designated as Series
A Preferred Stock, 9,600,000 shares have been designated as Series B Preferred
Stock and 10,400 shares have been designated as Series C Preferred Stock and (b)
100,000,000 shares of Common Stock, par value $0.234.
Any authorized but unissued or unreserved Common Stock and undesignated
Preferred Stock is available for issuance at any time, on such terms and for
such purposes as the Board of Directors may deem advisable in the future without
further action by stockholders of the Company, except as may be required by law
or the Series A or Series C Certificate of Designation. The Board of Directors
of the Company has the authority to fix the rights, powers, designations and
preferences of the undesignated Preferred Stock and to provide for one or more
series of undesignated Preferred Stock. The authority will include, but will not
be limited to: determination of the number of shares to be included in the
series; dividend rates and rights; voting rights, if any; conversion privileges
and terms; redemption conditions; redemption values; sinking funds; and rights
upon involuntary or voluntary liquidation.
In connection with the Recapitalization, the Company implemented a 156-to-1
reverse split of its common stock which reduced the total number of shares of
common stock outstanding from 80,688,538 pre-split shares (par value $0.0015) to
517,234 post-split shares (par value $0.234).
In connection with the Recapitalization, the holders of the Series A Preferred
Stock and the Series C Preferred Stock and common stock repricing rights
exchanged all their remaining shares of the Series A Preferred Stock, Series C
Preferred Stock and common stock repricing rights, together with all their
respective warrants and non-dilution rights for an aggregate of 732,500 shares
of post reverse-split common stock.
As of December 31, 2000, there were no shares of Preferred Stock, no common
stock repricing rights, no stock purchase warrants and 12,748,612 shares of
common stock outstanding.
SERIES A PREFERRED STOCK
In March 1997, the Company entered into a Securities Purchase Agreement with
Joint Energy Development Limited Partnership II, an affiliate of Enron
(respectively the "JEDI Purchase Agreement and "JEDI") under which JEDI acquired
9,600,000 shares of Series A Preferred Stock, certain warrants to purchase
common stock and nondilution rights in regards to future stock issuances by the
Company. The aggregate consideration received by the Company consisted of
$5,000,000.
In connection with the Recapitalization, JEDI accepted 212,500 shares of post
reverse-split common stock in exchange for all 9,600,000 shares of Series A
Preferred Stock and stock warrants that it then held, and the surrender of all
its remaining nondilution and other rights under the JEDI Purchase Agreement. As
a result of that transaction, the JEDI Purchase Agreement was terminated. As of
December 31, 2000, there were no shares of Series A Preferred Stock outstanding.
F-17
65
DEVX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
6. STOCKHOLDERS' EQUITY (CONTINUED)
SERIES B PREFERRED STOCK
No shares of Series B Preferred Stock have been issued.
SERIES C PREFERRED STOCK
In December 1997, the Company sold 10,000 shares of Series C Preferred Stock to
various investors in a private placement for gross proceeds of $10,000,000. The
investors also received warrants to purchase 2,180 shares of common stock in the
transaction. The Company issued an additional 400 shares of Series C Preferred
Stock in consideration of placement agent fees incurred with respect to the
transaction.
During the year ended December 31, 1998, the Company repurchased for cash a
total of 2,152 shares of Series C Preferred Stock. In addition, an aggregate of
2,290 shares of Series C Preferred Stock was converted into 2,534 shares of
common stock and 111 shares of common stock were issued in payment of dividends
that had accrued in respect of the 2,290 shares of Series C Preferred Stock that
were converted during the year.
During the year ended December 31, 1999, an aggregate of 1,710 shares of Series
C Preferred Stock was converted into 12,642 shares of common stock. In addition,
957 shares of common stock were issued in payment of dividends that had accrued
in respect of the 1,710 shares of Series C Preferred Stock that were converted
during the year.
During the year ended December 31, 2000, an aggregate of 2,075 shares of Series
C Preferred Stock was converted into 46,019 shares of common stock. In addition,
5,293 shares of common stock were issued in payment of dividends that had
accrued in respect of the 2,075 shares of Series C Preferred Stock that were
converted during the year.
In connection with the Recapitalization, the Company issued 120,000 shares of
common stock in exchange for the 2,173 shares of Series C Preferred Stock that
remained outstanding at the time plus the warrants. As of December 31, 2000,
there were no shares of Series C Preferred Stock or related stock purchase
warrants outstanding.
COMMON STOCK
During 1998, the Company completed the private placement of an aggregate of
34,013 shares of the Company's Common Stock for aggregate net proceeds of
approximately $26,980,000 (the Equity Offerings). In connection with the sale of
24,841 shares in the Equity Offerings, the Company granted certain common stock
reset rights (the Repricing Rights) for each share sold. Each Repricing Right
granted the holder the right to receive, in certain circumstances, additional
shares of common stock for no consideration. Additionally, warrants to purchase
an aggregate of 8,278 shares of the Company's common stock were granted to
purchasers of common stock.
During 1998, 15,860 shares of common stock were issued upon the exercise of
certain stock purchase warrants. The Company received aggregate net proceeds of
$7,000,000 from these exercises.
During 1998, the Company issued a total of 4,984 shares of common stock pursuant
to the exercise of 6,939 Repricing Rights. During 1999, the Company issued a
total of 19,245 shares of common stock pursuant to the exercise of 1,294
Repricing Rights. In 2000, the Company issued a total of 228,962 shares of
common stock pursuant to the exercise of 6,199 Repricing Rights.
F-18
66
DEVX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
6. STOCKHOLDERS' EQUITY (CONTINUED)
In connection with the Recapitalization, the holders of all remaining Repricing
Rights exchanged all their remaining Repricing Rights, together with all
outstanding warrants that had been issued as part of the Equity Offerings, for
an aggregate of 400,000 shares of common stock.
As of December 31, 2000, there were no Repricing Rights or stock purchase
warrants outstanding.
STOCK OPTIONS
YEAR ENDED DECEMBER 31
---------------------------------------------------------------------
2000 1999 1998
--------------------- ------------------- -------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE
-------- --------- ------- --------- ------- ---------
Outstanding at January 1 4,894 $1,071.04 4,894 $1,071.04 1,173 $ 819.00
Granted 732,500 7.01 -- -- 3,721 1,150.50
Exercised -- -- -- -- -- --
Canceled (4,894) 1,071.04 -- -- -- --
-------- ----- ----
Outstanding at December 31 732,500 $ 7.01 4,894 $1,071.04 4,894 $1,071.04
======== ===== =====
Exercisable options outstanding
at December 31 -- $ -- 640 $ 998.65 293 $ 819.00
======== ===== =====
The weighted average grant date fair values of stock options granted during 2000
and 1998 were $2.10 and $971.88, respectively. The grant date fair values were
estimated at the date of grant using the Black-Scholes option pricing model. As
of December 31, 2000, the weighted average remaining contractual life of
outstanding stock options was 9.8 years.
Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based
Compensation (SFAS 123), requires the disclosure of pro forma net income and
earnings per share information computed as if the Company had accounted for its
employee stock options under the fair value method set forth in SFAS 123. The
fair value for these options was estimated at the date of grant using a
Black-Scholes option pricing model with the following weighted average
assumptions, respectively: a risk-free interest rate of 5.75% and 6.00% during
2000 and 1998, respectively; a dividend yield of 0%; and a volatility factor of
0.256 and 0.792 during 2000 and 1998, respectively. In addition, the fair value
of these options was estimated based on an expected weighted average life of 4
years and 10 years during 2000 and 1998, respectively.
The Black-Scholes option valuation model was developed for use in estimating the
fair value of traded options which have no vesting restrictions and are fully
transferable. In addition, option valuation models require the input of highly
subjective assumptions, including the expected stock price volatility. Because
the Company's employee stock options have characteristics significantly
different from those of traded options, and because changes in the subjective
input assumptions can materially affect the fair value estimate, in management's
opinion, the existing models do not necessarily provide a reliable single
measure of the fair value of its employee stock options.
F-19
67
DEVX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
6. STOCKHOLDERS' EQUITY (CONTINUED)
For purposes of pro forma disclosures, the estimated fair value of the options
is amortized to expense over the options' vesting period. The Company's pro
forma information follows:
YEAR ENDED DECEMBER 31
--------------------------------------------
2000 1999 1998
----------- ------------- -------------
Pro forma net income/(loss) $22,797,000 $(12,573,000) $(74,674,000)
Basic income/(loss) per share $ 9.64 $ (58.41) $ (435.81)
Diluted income/(loss) per share $ 7.50 $ (58.41) $ (435.81)
7. FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company defines the fair value of a financial instrument as the amount at
which the instrument could be exchanged in a current transaction between willing
parties. The carrying value of accounts receivable, accounts payable and accrued
liabilities approximates fair value because of the short maturity of those
instruments. The estimated fair value of the Company's long-term obligations is
estimated based on the current rates offered to the Company for similar
maturities. At December 31, 2000, 1999 and 1998, the carrying value of long-term
obligations exceeded their fair values by approximately $14,500,000, $62,500,000
and $22,500,000, respectively. The estimated fair value of the Company's
derivative contracts at December 31, 2000 represented a net liability of
approximately $13,540,000.
8. RELATED PARTY TRANSACTIONS
The Company has entered into various hedging arrangements with affiliates of
Enron (Note 4).
The Company had entered into a revolving credit facility with ECT, an affiliate
of Enron. During the year ended December 31, 1998, commitment fees of
approximately $200,000 and interest totaling approximately $9,000 were paid to
ECT in connection with this facility. This agreement was terminated in October
1999.
Enron, through its affiliates, participated in indebtedness incurred in
connection with the acquisition of the Morgan Properties. During the year ended
December 31, 1999, Enron received interest payments of approximately $286,000
from the Company relating to such participation.
The Company paid Enron approximately $75,000 and $100,000 during the years ended
December 31, 2000 and 1999, respectively, under the terms of an agreement which
allows the Company to consult, among other things, with Enron's engineering
staff.
F-20
68
DEVX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
9. INCOME TAXES
The provision (benefit) for income taxes attributable to continuing operations
is as follows:
YEAR ENDED DECEMBER 31
----------------------------------------
2000 1999 1998
----------- ----------- -----------
Current $ 782,000 $ -- $ --
Deferred (1,424,000) -- --
----------- ----------- -----------
$ (642,000) $ -- $ --
=========== =========== ===========
The provision for income taxes differs from amounts computed at the statutory
federal income tax rate for the year ended December 31, 2000 as follows:
Statutory income tax provision $ 716,000
State income taxes, net of federal benefit 63,000
Change in valuation allowance (1,221,000)
Utilization of net operating loss carryforwards (203,000)
Other, net 3,000
-----------
$ (642,000)
===========
The Company's effective tax rate differs from the U.S. statutory rate for each
of the years ended December 31, 1999 and 1998 due to losses for which no
deferred tax benefit was recognized. The tax effects of the primary temporary
differences giving rise to the deferred federal income tax assets and
liabilities at December 31, 2000 and 1999, follow:
2000 1999
------------ ------------
Deferred income tax assets (liabilities):
Unrealized derivative losses $ 5,097,000 $ --
Net operating loss carryforwards 8,116,000 21,576,000
Oil and gas properties, principally due to differences in
depreciation and amortization 212,000 3,438,000
Other (3,000) (76,000)
------------ ------------
13,422,000 24,938,000
Less valuation allowance (12,201,000) (24,938,000)
------------ ------------
Net deferred income tax asset $ 1,221,000 $ --
============ ============
The net changes in the total valuation allowance for the years ended December
31, 2000 and 1999 were a decrease and an increase of $12,737,000 and $3,000,000,
respectively. The Company's net operating loss carryforwards (NOLs) begin
expiring in 2018. The Company is limited to an annual utilization of its NOLs of
approximately $1,100,000 as a result of the Recapitalization. To the extent that
the Company utilizes in the future NOLs existing as of the date of the
Recapitalization but which were not recognized as deferred tax assets prior to
the Recapitalization, the benefit of the NOLs will be credited to additional
paid-in capital. During 2000, the Company utilized NOLs approximating $68,000
(tax effected), which was credited to additional paid-in capital.
F-21
69
DEVX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
9. INCOME TAXES (CONTINUED)
During 2000, NOLs of approximately $21,144,000 were used to offset taxable
income associated with the extraordinary gain recognized upon the retirement of
$75,000,000 of Notes (Note 4).
10. COMMITMENTS AND CONTINGENCIES
The Company is involved in certain disputes and other matters arising in the
normal course of business. Although the ultimate resolution of these matters
cannot be reasonably estimated at this time, management does not believe that
they will have a material adverse effect on the financial condition or results
of operations of the Company.
11. OIL AND GAS PRODUCING ACTIVITIES
The following tables set forth supplementary disclosures for oil and gas
producing activities in accordance with Statement of Financial Accounting
Standards No. 69.
RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES
The following sets forth certain information with respect to results of
operations from oil and gas producing activities for the years ended December
31, 2000, 1999 and 1998:
2000 1999 1998
------------ ------------ ------------
Oil and gas sales $ 4,484,000 $ 3,625,000 $ 5,852,000
Net profits and royalty interests revenues 31,507,000 21,955,000 15,947,000
Production expenses (1,727,000) (1,622,000) (4,326,000)
Depreciation and amortization (8,560,000) (9,281,000) (10,749,000)
Write-down of oil and gas properties -- -- (63,199,000)
------------ ------------ ------------
Results of operations (excludes corporate
overhead and interest expense) $ 25,704,000 $ 14,677,000 $(56,475,000)
============ ============ ============
Depreciation and amortization of oil and gas properties was $0.78, $0.70, and
$0.85 per Mcfe produced for the years ended December 31, 2000, 1999 and 1998,
respectively.
The following table summarizes capitalized costs relating to oil and gas
producing activities and related amounts of accumulated depreciation and
amortization at December 31, 2000 and 1999:
2000 1999
------------- -------------
Oil and gas properties - proved $ 191,204,000 $ 181,549,000
Accumulated depreciation and amortization (94,214,000) (85,771,000)
------------- -------------
Net capitalized costs $ 96,990,000 $ 95,778,000
============= =============
F-22
70
DEVX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
11. OIL AND GAS PRODUCING ACTIVITIES (CONTINUED)
COSTS INCURRED
The following sets forth certain information with respect to costs incurred,
whether expensed or capitalized, in oil and gas activities for the years ended
December 31, 2000, 1999 and 1998:
2000 1999 1998
------------ ------------- ------------
Property acquisition costs $ -- $ -- $141,262,000
============ ============= ============
Development costs $ 13,043,000 $ 7,494,000 $ 12,699,000
============ ============= ============
12. SUPPLEMENTARY OIL AND GAS DATA (UNAUDITED)
RESERVE QUANTITY INFORMATION
The following table presents the Company's estimate of its proved oil and gas
reserves, all of which are located in the United States. The Company emphasizes
that reserve estimates are inherently imprecise and that estimates of new
discoveries are more imprecise than those of producing oil and gas properties.
Accordingly, the estimates are expected to change as future information becomes
available. The estimates at December 31, 1999 and 2000 have been prepared by
independent petroleum reservoir engineers. The estimates at December 31, 1997
and 1998 have been prepared by the Company's petroleum engineers.
OIL (Bbls) GAS (Mcf)
------------ ------------
Proved reserves:
Balance at December 31, 1997 7,115,000 20,979,000
Purchases of minerals in place 3,579,000 160,913,000
Revisions of previous estimates and other (3,334,000) 44,000
Production 481,000 9,931,000
------------ ------------
Balance at December 31, 1998 6,879,000 172,005,000
Sales of minerals in place (2,735,000) (18,243,000)
Revisions of previous estimates and other 648,000 (2,323,000)
Production 339,000 11,441,000
------------ ------------
Balance at December 31, 1999 4,453,000 139,998,000
Sales of minerals in place (1,000) (7,035,000)
Revisions of previous estimates and other (2,875,000) 6,610,000
Production 216,000 9,797,000
------------ ------------
Balance at December 31, 2000 1,361,000 129,776,000
============ ============
Proved developed reserves:
Balance at December 31, 1997 2,352,000 12,566,000
============ ============
Balance at December 31, 1998 4,317,000 120,373,000
============ ============
Balance at December 31, 1999 1,937,000 86,044,000
============ ============
Balance at December 31, 2000 1,253,000 84,669,000
============ ============
F-23
71
DEVX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
12. SUPPLEMENTARY OIL AND GAS DATA (UNAUDITED) (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES
The Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves (Standardized Measure) is a disclosure requirement under
Statement of Financial Accounting Standards No. 69.
The Standardized Measure of discounted future net cash flows does not purport to
be, nor should it be interpreted to present, the fair value of the Company's oil
and gas reserves. An estimate of fair value would also take into account, among
other things, the recovery of reserves not presently classified as proved, the
value of unproved properties and consideration of expected future economic and
operating conditions.
Under the Standardized Measure, future cash flows are estimated by applying
year-end prices, adjusted for fixed and determinable escalations, to the
estimated future production of year-end proved reserves. Future cash inflows are
reduced by estimated future production and development costs based on period-end
costs to determine pretax cash inflows. Future income taxes are computed by
applying the statutory tax rate to the excess of pretax cash inflows over the
Company's tax basis in the associated properties. Tax credits, net operating
loss carryforwards and permanent differences are also considered in the future
tax calculation. Future net cash inflows after income taxes are discounted using
a 10% annual discount rate to arrive at the Standardized Measure.
The Standardized Measure of discounted future net cash flows relating to proved
oil and gas reserves as of December 31, 2000 and 1999, is as follows:
2000 1999
--------------- ---------------
Future cash inflows $ 1,451,177,000 $ 435,370,000
Future costs and expenses:
Production expenses (223,812,000) (133,463,000)
Development costs (21,441,000) (24,984,000)
Future income taxes (370,200,000) (30,500,000)
--------------- ---------------
Future net cash flows 835,724,000 246,423,000
10% annual discount for estimated timing of cash flows (465,502,000) (129,744,000)
--------------- ---------------
Standardized Measure of discounted future net cash flows $ 370,222,000 $ 116,679,000
=============== ===============
F-24
72
DEVX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
12. SUPPLEMENTARY OIL AND GAS DATA (UNAUDITED) (CONTINUED)
Changes in the Standardized Measure of discounted future net cash flows relating
to proved oil and gas reserves for the years ended December 31, 2000, 1999 and
1998 are as follows:
2000 1999 1998
------------- ------------- -------------
Beginning balance $ 116,679,000 $ 108,287,000 $ 28,111,000
Purchases of minerals in place -- -- 135,418,000
Sales of minerals in place (12,953,000) (16,035,000) --
Developed during the period 13,043,000 7,494,000 12,699,000
Net change in prices and costs 501,474,000 62,102,000 (70,744,000)
Revisions of previous estimates (74,940,000) (21,368,000) 6,665,000
Accretion of discount 11,668,000 10,829,000 2,811,000
Net change in income taxes (150,485,000) (10,672,000) 10,800,000
Sales of oil and gas produced, net of
production expenses (34,264,000) (23,958,000) (17,473,000)
============= ============= =============
Balance at December 31 $ 370,222,000 $ 116,679,000 $ 108,287,000
============= ============= =============
The weighted average prices of oil and gas used in calculating the Standardized
Measure at December 31, 2000, 1999 and 1998 were as follows:
2000 1999 1998
-------- -------- --------
Natural gas (Per MCF) $ 10.92 $ 2.35 $ 1.84
Oil (per Bbl) $ 25.88 $ 23.91 $ 10.79
The future cash flows shown above for 2000 include amounts attributable to
proved undeveloped reserves requiring approximately $20,648,000 of future
development costs. If these reserves are not developed, the future net cash
flows shown above would be significantly reduced.
Estimates of economically recoverable oil and natural gas reserves and of future
net revenues are based upon a number of variable factors and assumptions, all of
which are to some degree speculative and may vary considerably from actual
results. Therefore, actual production, revenues, taxes, development and
operating expenditures may not occur as estimated. The reserve data are
estimates only, are subject to many uncertainties and are based on data gained
from production histories and on assumptions as to geologic formations and other
matters. Actual quantities of oil and natural gas may differ materially from the
amounts estimated.
F-25
73
DEVX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
13. QUARTERLY FINANCIAL RESULTS (UNAUDITED)
2000
------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
------------ ------------ ------------ ------------
Total revenues $ 6,673,000 $ 8,231,000 $ 10,276,000 $ 10,901,000
Operating income $ 6,101,000 $ 7,709,000 $ 9,812,000 $ 10,732,000
Income (loss) before extraordinary
item and cumulative effect of
accounting change $ (1,618,000) $ 190,000 $ 1,377,000 $ 2,704,000
Extraordinary gain $ -- $ -- $ 21,144,000
Cumulative effect of accounting
change, net of tax $ -- $ -- $ 413,000 $ --
Net income (loss) $ (1,618,000) $ 190,000 $ 1,790,000 $ 23,848,000
Income (loss) before extraordinary
item and cumulative effect of
accounting change per common share
$ (5.59) $ 0.15 $ 0.83 $ 0.30
Net income (loss) per common share $ (5.59) $ 0.15 $ 1.08 $ 2.69
1999
------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
------------ ------------ ------------ ------------
Total revenues $ 6,734,000 $ 6,986,000 $ 5,543,000 $ 6,653,000
Operating income $ 6,015,000 $ 6,363,000 $ 5,385,000 $ 6,533,000
Loss before extraordinary item $ (1,977,000) $ (2,183,000) $ (2,242,000) $ (4,258,000)
Extraordinary loss $ -- $ -- $ -- $ (1,130,000)
Net loss $ (1,977,000) $ (2,183,000) $ (2,242,000) $ (5,388,000)
Loss before extraordinary item per
common share $ (0.06) $ (0.07) $ (0.07) $ (0.12)
Net loss per common share $ (0.06) $ (0.07) $ (0.07) $ (0.15)
F-26
74
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
3.1 Restated Certificate of Incorporation of the Company, filed as
Exhibit 4.5 to the Company's Registration Statement on Form
S-3 (No. 333-47577) filed with the Securities and Exchange
Commission on March 9, 1998, which Exhibit is incorporated
herein by reference
3.2 Certificate of Designation of Series C Convertible Preferred
Stock of the Company, filed as an Exhibit to the Company's
Current Report on Form 8-K dated December 24, 1997, which
Exhibit is incorporated herein by reference.
3.3 Certificate of Amendment to the Restated Certificate of
Incorporation of the Company, filed with the Secretary of
State for the State of Delaware on September 19, 2000 which
Certificate was filed as an Exhibit to the Company's
Registration Statement on Form S-2 filed with the Securities
and Exchange Commission on October 6, 2000 (No. 333-41992),
which Exhibit is incorporated herein by reference.
3.4* Certificate of Amendment to the Restated Certificate of
Incorporation of the Company, filed with the Secretary of
State for the State of Delaware on October 26, 2000, which
Certificate is filed herewith.
3.5 Amended and Restated Bylaws of the Company, filed as an
Exhibit to the Company's Current Report on Form 8-K dated
March 27, 1997, which Exhibit is incorporated herein by
reference.
4.1 Indenture, dated July 1, 1998, in regard to 12 1/2% Senior
Notes due 2008 by and among the Company and certain of its
subsidiaries and Harris Trust and Savings Bank, as Trustee,
filed as an Exhibit to the Company's Current Report on Form
8-K dated July 8, 1998, which Exhibit is incorporated herein
by reference.
4.2* First Supplement to Indenture dated October 12, 2000 among
the Company, certain of its subsidiaries and Harris Trust and
Savings Bank as Trustee, which Exhibit is filed herewith.
4.3 Settlement Agreement dated as of July 17, 2000 between the
Company and the stockholders named therein, filed as an
Exhibit to the Company's Registration Statement on Form S-2
filed with the Securities and Exchange Commission on October
6, 2000 (No. 333-41992), which Exhibit is incorporated herein
by reference.
4.4 Participation Agreement dated as of July 17, 2000 between the
Company and the holders of its 12 1/2% senior notes therein
filed as an Exhibit to the Company's Registration Statement on
Form S-2 filed with the Securities and Exchange Commission on
October 6, 2000 (No. 333-41992) which Exhibit is incorporated
herein by reference.
4.5 Amendment to Participation Agreement dated as of October 4,
2000 between the Company and certain holders of its 12 1/2%
senior notes therein filed as an Exhibit to the Company's
Registration Statement on Form S-2 filed with the Securities
and Exchange Commission on October 6, 2000 (No. 333-41992),
which Exhibit is incorporated herein by reference
10.1 Queen Sand Resources 1997 Incentive Equity Plan, filed as an
Exhibit to the Company's Registration Statement on Form S-4
filed with the Securities and Exchange Commission on August
13, 1998, which Exhibit is incorporated herein by reference.
10.2* Form of DevX Energy, Inc. Restated and Amended Incentive
Equity Plan filed herewith**.
10.3* Form of Option Agreement issued under the Amended and Restated
Incentive Equity Plan filed herewith**.
75
10.4 Directors' Non-Qualified Stock Option Plan filed as Appendix A
to the Company's Definitive Proxy Statement on Schedule 14A
dated October 23, 1998, which Exhibit is incorporated herein
by reference**.
10.5* Form of DevX Energy, Inc. Restated and Amended Directors'
Non-Qualified Stock Option Plan filed herewith**.
10.6* Form of Option Agreement issued under the Amended and Restated
Directors' Non-Qualified Stock Option Plan filed herewith**.
10.7 Amended and Restated Credit Agreement among the Company, DevX
Energy, Inc., a Nevada corporation, (formerly known as Queen
Sand Resources, Inc.), Ableco Finance LLC, as Collateral
Agent, and the lenders signatory thereto, effective as of
October 22, 1999, filed as an Exhibit to the Company's
Quarterly Report on Form 10-Q for the quarter ended September
30, 1999.
10.8 Second Amended And Restated Guaranty Agreement dated as of
October 22, 1999 by the Company as Guarantor in favor of
Ableco Finance LLC, as Collateral Agent for the lender group
and the lenders signatory thereto, filed as an Exhibit to the
Company's Quarterly Report on Form 10-Q for the quarter ended
September 30, 1999.
10.9 Second Amended And Restated Guaranty Agreement dated as of
October 22, 1999 by DevX Operating Company a Nevada
corporation, (formerly known as Queen Sand Operating Co.), as
Guarantor, in favor of Ableco Finance LLC, as Collateral Agent
for the lender group, and the lenders signatory thereto, filed
as an Exhibit to the Company's Quarterly Report on Form 10-Q
for the quarter ended September 30, 1999.
10.10 Second Amended And Restated Guaranty Agreement dated as of
October 22, 1999 by Corrida Resources, Inc. as Guarantor, in
favor of Ableco Finance LLC, as Collateral Agent for the
lender group, and the lenders signatory thereto, filed as an
Exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1999.
10.11 Security Agreement dated as of October 22, 1999, by and among
the Company, DevX Energy, Inc., a Nevada corporation,
(formerly known as Queen Sand Resources, Inc.), DevX Operating
Company (formerly known as Queen Sand Operating Co.), Corrida
Resources, Inc. and Ableco Finance LLC, as collateral agent
for the lender group, and the lenders signatory thereto, filed
as an Exhibit to the Company's Quarterly Report on Form 10-Q
for the quarter ended September 30, 1999.
10.12 Second Amended and Restated Pledge and Security Agreement
dated as of October 22, 1999, by DevX Energy, Inc., a Nevada
corporation, (formerly known as Queen Sand Resources, Inc.),
in favor of Ableco Finance LLC, as Collateral Agent for the
lender group, and the lenders signatory thereto, filed as an
Exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1999.
10.13 Second Amended and Restated Pledge and Security Agreement
dated as of October 22, 1999, by the Company in favor of
Ableco Finance LLC, as Collateral Agent for the lender group,
and the lenders signatory thereto, filed as an Exhibit to the
Company's Quarterly Report on Form 10-Q for the quarter ended
September 30, 1999.
10.14 Amendment No. 1 to Credit Agreement dated May 2000 among the
Company, DevX Energy, Inc., a Nevada corporation (formerly
known as Queen Sand Resources, Inc.), Ableco Finance LLC, as
Collateral Agent, and the lenders signatory thereto, filed as
an Exhibit to the Company's Registration Statement on Form S-2
(No. 333-41992), which Exhibit is incorporated by reference.
10.15 Amendment No. 2 to Credit Agreement dated June 30, 2000 among
the Company, DevX Energy, Inc., a Nevada corporation,
(formerly known as Queen Sand Resources, Inc.), Ableco Finance
LLC, as Collateral Agent, and the lenders signatory thereto,
filed as an Exhibit to the Company's Registration Statement on
Form S-2 filed with the Securities and Exchange Commission on
October 6, 2000, (No. 333-41992), which Exhibit is
incorporated by reference.
10.16 Amendment No. 3 to Credit Agreement dated September , 2000
among the Company, DevX Energy, Inc., a Nevada corporation
(formerly known as Queen Sand Resources, Inc.), Ableco Finance
LLC,
76
as Collateral Agent, and the lenders signatory thereto, filed
as an Exhibit to the Company's Registration Statement on Form
S-2 filed with the Securities and Exchange Commission on
October 6, 2000 (No. 333-41992), which Exhibit is incorporated
by reference.
10.17 Amendment No. 4 to Credit Agreement dated October 24, 2000
among the Company, DevX Energy, Inc., a Nevada corporation,
Ableco Finance LLC, as Collateral Agent, and the lenders
signatory thereto, filed as an Exhibit to the Company's
Quarterly Report on Form 10-Q for the quarter ended September
30, 2000, which Exhibit is incorporated by reference.
10.18* Amendment No. 5 to Credit Agreement dated January 31, 2001
among the Company, DevX Energy, Inc., a Nevada corporation,
Ableco Finance LLC, as Collateral Agent, and the lenders
signatory thereto, which Amendment is filed herewith.
10.19* Employment Agreement dated as of October 6, 2000 between the
Company and Joseph T. Williams which agreement is filed
herewith**.
10.20* Form of Directors' Indemnity Agreement signed by Jerry B.
Davis and Robert L. Keiser.**
10.21 Employment Agreement dated December 15, 1997 between the
Company and Robert P. Lindsay, filed as an Exhibit to the
Company's Registration Statement on Form S-4 filed with the
Securities and Exchange Commission on August 13, 1998 (No.
333-61403) which Exhibit is incorporated herein by
reference**.
10.22* Release Agreement dated December 7, 2000 between the Company
and Robert P. Lindsay which agreement is filed herewith**.
10.23 Employment Agreement dated December 15, 1997 among the
Company, Queen Sand Resources (Canada) Inc. and Bruce I. Benn,
filed as an Exhibit to the Company's Registration Statement on
Form S-4 filed with the Securities and Exchange Commission on
August 13, 1998 (No. 333-61403) which Exhibit is incorporated
herein by reference**.
10.24* Release Agreement dated December 7, 2000 between the Company
and Bruce I. Benn which agreement is filed herewith**.
10.25 Employment Agreement dated December 15, 1997 among the
Company, Queen Sand Resources (Canada) Inc. and Ronald Benn,
filed as an Exhibit to the Company's Registration Statement on
Form S-4 filed with the Securities and Exchange Commission on
August 13, 1998 (No. 333-61403) which Exhibit is incorporated
herein by reference**.
10.26 Release Agreement dated September 15, 2000 between the Company
and Ronald I. Benn filed as an Exhibit to the Company's
Registration Statement on Form S-2 filed with the Securities
and Exchange Commission on October 6, 2000 (No. 333-41992),
which Exhibit is incorporated by reference**.
10.27* Employment Agreement dated as of November 10, 2000 between the
Company and Edward J. Munden which agreement is filed
herewith**.
10.28* Employment Agreement dated as of November 10, 2000 between the
Company and William W. Lesikar which agreement is filed
herewith**.
10.29* Employment Agreement dated as of November 10, 2000 between the
Company and Brian J. Barr which agreement is filed herewith**.
21.1 List of the subsidiaries of the registrant filed as an Exhibit
to the Company's Registration Statement on Form S-4 filed with
the Securities and Exchange Commission on August 13, 1999 (No.
333-61403) which Exhibit is incorporated by reference.
23.1* Consent of Ernst & Young LLP.
23.2* Consent of Ryder Scott Company.
23.3* Consent of H.J. Gruy and Associates, Inc.
- -----------
* Indicates Filed herewith.
** Indicates Management Contract