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SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 000-33275
Warren Resources Inc.
(Exact name of registrant as specified in its charter)
New York 11-3024080
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification
Number)
489 Fifth Avenue, New York, New York 10017
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (212) 697-9660
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $.001 par value 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 registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate market value of the registrant's voting Common Stock held by
non-affiliates of the registrant as of April 10, 2002: There is no publicly
quoted market value for the registrant's voting Common Stock
As of April 10, 2002, there were 17,537,579 shares of the registrant's
voting Common Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: NONE
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1
WARREN RESOURCES INC.
FORM 10-K
TABLE OF CONTENTS
PART I Page
----
Items 1 Business and Properties 3
and
2:
27
Item 3: Legal Proceedings
Item 4: Submission of Matters to a Vote of Security Holders 28
PART II
Item 5: Market for Registrant's Common Equity and Related Stockholder Matters 28
Item 6: Selected Consolidated Financial Data 29
Item 7: Management's Discussion and Analysis of Financial Condition and Results 30
of Operations
Item 7A: Quantitative and Qualitative Disclosures About Market Risk 39
Item 8: Financial Statements and Supplementary Data 53
Item 9: Changes in and Disagreements with Accountants on Accounting and Financial 53
Disclosure
PART III
Item 10: Directors and Executive Officers of the Registrant 53
Item 11: Executive Compensation 57
Item 12: Security Ownership of Certain Beneficial Owners and Management 64
Item 13: Certain Relationships and Related Transactions 66
PART IV
Item 14: Exhibits, Financial Statement Schedules and Reports on Form 8-K 67
2
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Warren's logo is a trademark or service mark of Warren. Other trademarks or
service marks appearing herein are the property of their respective holders.
----------------------
As used in this document, "Warren," "we," "us," and "our" refer to Warren
Resources Inc. and its subsidiaries. The term "Pedco" refers to our wholly owned
subsidiary Petroleum Development Corporation and its subsidiaries. The term
"Pinnacle" refers to our formerly wholly owned subsidiary CJS Pinnacle Petroleum
Services, LLC.
----------------------
For abbreviations or definitions of certain terms used in the oil and gas
industry and in this registration statement, please refer to the section
entitled "Glossary of Oil and Gas Terms" beginning on page 24.
PART I
The statements contained in this annual report on Form 10-K that are not
historical are "forward-looking statements," as that term is defined in Section
21E of the Exchange Act, that involve a number of risks and uncertainties.
Forward-looking statements use forward-looking terms such as "believe,"
"expect," "may," "intend," "will," "project," "budget," "should," "anticipate"
or other similar words. These statements discuss forward-looking information
such as:
o anticipated capital expenditures and budgets;
o future cash flows and borrowings;
o pursuit of potential future acquisition or drilling
opportunities;
o sources of funding for exploration and development;
o estimated oil and gas reserves;
o market conditions in the oil and gas industry; and
o the anticipated outcome of litigation and the impact of
governmental regulations.
These forward-looking statements are based on assumptions that we believe
are reasonable, but they are open to a wide range of uncertainties and business
risks, including the risks described under "Risk Factors" contained in
Management's Discussion and Analysis of Financial Condition and Results of
Operations in this Form 10-K, and actual operations and results may differ
materially from those expressed in this Form 10-K. When considering these
forward-looking statements, you should keep in mind the risk factors and other
cautionary statements in this registration statement. We will not update these
forward-looking statements unless the securities laws require us to do so.
Items 1 and 2: Business and Properties
Overview
We are an independent energy company engaged in the acquisition,
exploration and development of domestic onshore natural gas and oil reserves. We
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own natural gas and oil interests in approximately 428,103 gross (201,868 net)
acres. Less than 3% of our net acreage has been developed. We are an active
developer of coalbed methane natural gas in the Rocky Mountain region. We own
natural gas and oil interests in approximately 204,184 gross (175,036 net) acres
in Rocky Mountain areas where there is significant coalbed methane drilling
activity. Of this acreage, we own or have under contract natural gas and oil
interests in approximately 175,821 gross (152,010 net) acres in the Washakie
Basin, which comprises approximately the southeast third of the Greater Green
River Basin in Wyoming. Based on the results of a 21 well test program conducted
in the Washakie Basin during 2000, we recently commenced a significant
exploratory and development drilling program in this basin with approximately
165 drill sites initially identified. Our remaining coalbed methane acreage is
located in the Powder River Basin of Wyoming and Montana, where we have drilled
123 wells, of which 117 wells are currently producing. Additionally, we own
natural gas and oil interests in properties in east Texas and in the Los Angeles
Basin of California that we are developing primarily through directional and
horizontal drilling.
Our principal source of funding for exploration, development and production
activities has been privately placed drilling programs that we sponsor and
manage. Since 1992, we have sponsored 29 drilling programs that have raised
approximately $217 million. We acquire acreage, develop drilling prospects and
manage the drilling activity in which our drilling program investors
participate. We contribute acreage to the drilling programs and pay all tangible
drilling costs, while the other investors in the drilling programs pay all
intangible drilling costs. Petroleum Development Corporation, a New Mexico
corporation, or "Pedco," our wholly owned subsidiary, typically contracts with
the drilling programs to conduct drilling services on a turnkey, fixed-price
basis. Under such contracts, the drilling programs pay a specific price to
Pedco, based on the depth of the well, for each well drilled regardless of the
actual amount of time, materials and expenses required by Pedco to drill the
well. Other than the interest we hold in our drilling programs on an indirect
basis, we have not retained any direct interest in the wells drilled for the
account of our drilling programs.
All of our natural gas and oil drilling, completion, production and land
operations are conducted through Pedco. Pedco was formed on March 26, 1973.
Pedco is based in Albuquerque, New Mexico with regional offices in Gillette,
Wyoming and Beeville, Texas. Some of Pedco's operations are undertaken through
its wholly owned subsidiary, Pedeco, Inc., a Texas corporation.
At December 31, 2001, we had estimated net proved reserves of 53.4 Bcfe. We
own approximately 27% of these reserves through our interest in the drilling
programs we manage and 73% directly. Based on average prices on that date of
$1.76 per Mcf of natural gas and $13.87 per Bbl of oil, the PV-10 value of these
proved reserves was approximately $20 million. At December 31, 2001, our
drilling programs had 59.2 Bcfe of estimated proved reserves with a PV-10 value
of $35 million, not including our interests in these programs.
As of December 31, 2001, we had interests in 207 producing wells and were
the operator of 64% of these wells. As of the same date, the daily gross
production of these wells was 33.8 Mmcfe, of which 12.8 Mmcfe was attributable
to Warren and its drilling programs. Although Warren was entitled to a
percentage of production, historically, due to production subordination
agreements with our drilling programs, substantially all production was
allocated to investors in our drilling programs. Commencing July 1, 2001, 25% of
new production from interests in wells owned by the drilling programs formed in
1999 and subsequent years will be directly allocated to Warren pursuant to
governing agreements with our drilling programs.
Our exploration and development is focused on:
o coalbed methane in Wyoming and Montana;
o waterflood redevelopment in the Wilmington Field in California;
and
o horizontal and vertical drilling in Texas, New Mexico and the
Rocky Mountain region.
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We have significant operational experience in drilling and producing
coalbed methane and in designing and drilling directional and horizontal wells.
Specifically, we have drilled over 150 coalbed methane wells in the Powder River
and Washakie Basins since commencing such operations in 1995. We have also
managed full scale field development of several areas in the Powder River Basin.
Additionally, we have drilled more than 120 horizontal wells covering
approximately 20 different geological formations in many of the major domestic
producing basins. The executives who manage our natural gas and oil operations
have extensive experience in drilling, completion and production activities. We
believe our experience with highly specialized drilling and completion
operations allows us to more efficiently develop our existing property base and
better evaluate new opportunities. For more information about the experience and
background of our executives and significant employees see "Item 10-Directors
and Executive Officers."
Current Developments
In mid-February 2002, our work-over drilling subsidiary, CJS Pinnacle
Petroleum Services, LLC, completed the sale of substantially all of its assets
to Basic Energy Services, Inc. of Midland Texas for total consideration of $4.2
million, consisting of $3.7 million in cash plus up to $500,000 of credits with
Basic over a 36 month period for future workover, completion, swabbing, plugging
and abandonment or related well services. This credit is to be provided at
Basic's rate schedule and prices in effect at the time, and is limited to
$25,000 credit per month, plus during the last 18 months of the contract a 50%
discount for services in excess of $25,000 per month. Pinnacle also provided
Basic with a non-competition agreement for three years within a 200 mile radius
of Beeville, Texas and Artesia, New Mexico.
Coalbed Methane Properties
Coalbed Methane Compared to Traditional Natural Gas
The primary component of commercial natural gas is methane. Methane can
also be found in coal deposits, as it is created by the same biological and
geological forces that transform organic material into coal. Methane is stored
in coal seams in four different ways:
o as free gas trapped within the pore spaces and natural fractures
of the coal;
o as dissolved gas in the water within the coal seam;
o as absorbed gas on the surface of the coal; and
o as absorbed gas held within the molecular structure of the coal
itself.
Methane stored in coal deposits by all four of these methods is released
upon the removal of water from coal seams. The removal of water reduces the
amount of pressure on free and dissolved gas in the coal allowing it to be
produced. As a result, coalbed methane wells typically produce significant
amounts of water when they are first drilled, often for the first one or two
years of a generally projected eight to fifteen year life of these wells. During
this de-watering phase, water production typically decreases while gas
production typically increases. After this initial production phase, gas
production typically declines over the remaining producing life of the wells.
While traditional natural gas wells and coalbed methane wells require
largely the same infrastructure and produce the same end product, coalbed
methane production differs from traditional natural gas production in the
following ways:
o Other than dehydration and compression, coalbed methane typically
needs no other processing after extraction prior to entering a
pipeline, reducing production costs;
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o Although certain structural features such as fractures enhance
production of coalbed methane, such structural features are
generally not necessary for production, making the discovery of
coalbed methane reserves less expensive;
o Methane bearing coals exist at much shallower depths than the
formations that traditionally contain natural gas, allowing
coalbed methane to be produced from shallower wells using more
readily available equipment, such as water well rigs, thereby
reducing drilling costs; and
o Since the location of coal seams is typically known through prior
mining activity or from data provided by existing wells drilled
to deeper formations, extensive geophysical or seismic data is
not required to drill a coalbed methane well.
It should be noted that coalbed methane reservoirs require a cleat system
to be productive. Cleats are formed during the coalification process and provide
the path for the methane to travel to the wellbore. The size and number of the
cleats determines the permeability and productubility of the coalbed reservoir.
It is possible that an adequate cleat system may not develop.
Our Coalbed Methane Operations
We have two primary areas of operations in the Rocky Mountain region. The
primary drilling season in these areas runs from May through November to January
due to weather and environmental considerations. While most of our drilling
activity to date has occurred in the Powder River Basin, most of our acreage is
located in the Washakie Basin. Our ownership in this acreage is held principally
through working interest leaseholds. Since 1995, we have been operating in the
Powder River Basin of Wyoming and Montana and have drilled 123 coalbed methane
wells in three fields in the Powder River Basin, all of which we operate. As of
December 31, 2001, the average daily production from these three fields was 9.2
Mmcf per day, of which 7.2 Mmcf was attributable to us and our drilling
programs. As of December 31, 2001, we held leases covering approximately 28,363
gross (23,026 net) acres in the Powder River Basin with proved coalbed methane
reserves of 1.4 Bcfe attributable to our interest, or approximately 3% of our
net proved reserves.
In the second half of 1999, we began acquiring acreage in the Washakie
Basin, which is a portion of the greater Green River Basin in south-central
Wyoming. Our acreage position in the Washakie Basin has grown through a series
of transactions to approximately 175,821 gross (152,010 net) acres, not
including a farmout from Anadarko Petroleum Corporation consisting of 51,120 net
acres discussed below. In 2000, we participated in an initial test program on
this acreage in which 21 wells were drilled to test the quality of the coals in
this basin. Based on the test data and our six years of experience operating
coalbed methane wells in the Powder River Basin, we believe that the gas content
of the coals in the Washakie Basin compares favorably to the coals in the Powder
River Basin. However, proved reserves can not be attributed to this area until
sufficient production history is established. Currently, there are no producing
wells in which Warren has an interest in the Washakie Basin although there is
limited production by third parties. However, there are 10 wells in which we own
interest in the Washakie Basin that we currently expect are capable of producing
6
commercial amounts of gas as early as March 2002. These wells are awaiting
completion and pipeline hookup. On June 1, 2001, the Bureau of Land Management
of the U.S. Department of the Interior, or "BLM," issued a policy statement that
allows for the drilling of a maximum of 200 wells in the Washakie Basin, subject
to restrictions discussed below, during the preparation of an environmental
impact statement currently targeted for completion by the end of 2003. Of these
200 wells, we have been allocated 165 wells, including wells allocated to the
Anadarko farmout. Without the Anadarko farmout, our preliminary estimate is that
we would be allocated 125 wells.
Powder River Basin
LX-Bar and Piper Federal/Haight-Less Fields
In these fields, we own interests in approximately 4,230 gross (951 net)
acres located near the town of Gillette in Campbell County, Wyoming. Our total
estimated net proven reserves in this portion of the Powder River Basin at
December 31, 2001 were 1.4 Bcfe, substantially all of which were attributable to
coalbed methane. In 1999, we drilled 56 wells in the LX-Bar Field, all but one
of which are currently producing, with an additional 32 wells drilled since
March 2000, 30 of which are currently producing, with the remainder expected to
be on production by the second quarter of 2002. We have an average working
interest of 9.2% and operate 100% of the wells in this field. At December 31,
2001, gross production from these wells in the LX-Bar Field was approximately
6.4 Mmcf per day, of which 5.1 Mmcf per day was attributable to us and our
drilling programs. In November 2001, we drilled and completed the six remaining
wells in the LX-Bar Field for approximately $800,000, which was funded out of
our available cash reserves at that date.
Wells in the LX-Bar Field produce from two coal seams. The shallower
seam is the Anderson seam, at an average depth of 450 feet, with an average net
thickness of 35 feet. The average cost in the Anderson seam has been
approximately $70,000 per well, including gathering and compression systems and
pipeline connections. The deeper coal seam is the Canyon seam, the depth of
which averages 800 feet, with an average net thickness of 65 feet. The average
cost in the Canyon seam has been approximately $125,000 per well, including
gathering and compression systems and pipeline connections. We have identified a
third potential coal seam at an average depth of 900 feet, which we are
currently evaluating for future drilling.
To transport our gas from our LX-Bar area, we converted an existing 6.5
mile oil pipeline to a gas pipeline in the third quarter of 1999. This pipeline
allows us to sell our gas into the Williston Basin Interstate pipeline which
serves markets in the Midwest and has historically provided a higher price than
markets available from pipelines to the south of this area. Selling our gas into
the Williston Basin Interstate pipeline allows us to sell to the Ventura Gas
Market in Chicago as opposed to selling into the Colorado Interstate Gas, "CIG,"
at CIG's posted price. For the five year period from 1997 through 2001, the
twelve month average price received as of the first of each month at the Ventura
Gas Market was $2.96 per Mmbtu and for the same period the average CIG posted
price was $2.53 per Mmbtu. We currently hold 9 Mmcf per day of firm transport
through year-end 2002 with lesser capacity thereafter, and typically sell any
additional LX-Bar production on an interruptible basis on this line.
Since August 2000, we have drilled 25 wells in the Piper Federal Field, of
which 24 are producing as of December 31, 2001. The remaining well is not
capable of commercial production. All of our current wells in the Piper Federal
Field produce from the shallow Wyodak coal seam, which has an average depth of
850 feet and an average net thickness of 80 feet. Prior to 2000, we participated
in the drilling of eight wells in the Haight-Less Field. All of these wells
produced from the shallow Wyodak coal seam. Our average cost per well in this
seam has been approximately $100,000, including gathering and compression
systems and pipeline connections. We operate 100% of the wells in these fields.
At December 31, 2001, these wells were producing approximately 2.8 Mmcf per day
gross, of which 2.1 Mmcf is attributable to us and our drilling programs.
Although we have no plans to drill any further wells in these fields during
2001, we plan to test a deeper coal seam at 1,350 feet during 2002. The
production from these wells is sold into a Colorado Interstate Gas pipeline on
an interruptible basis. This means that from time to time the sale of the
production into this pipeline may be delayed or interrupted for production for
which other sellers have space on the pipeline on a firm commitment basis.
Historically, these delays and interruptions have not been significant.
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Kirby-Decker Prospect
We hold approximately 24,133 gross (22,075 net) acres in this field in
Bighorn County, Montana. As of December 31, 2001, we drilled two wells in the
northern portion of the acreage that we deemed nonproductive and plan to drill
two additional wells in the southern portion of the acreage during 2002, at a
cost of approximately $125,000 per expected well, including gathering and
compression systems and pipeline connections. These wells will be drilled to the
Wall coal seam, which has an average depth of 700 feet and an average net
thickness of 55 feet. We have identified two deeper seams at 1,200 and 1,300
feet that we may evaluate for future drilling. These initial wells are part of
the data acquisition phase of the Montana Statewide Oil and Gas Environmental
Impact Statement, or "EIS," and Amendment of the Powder River and Billings
Resource Management Plan being prepared by the state of Montana. This EIS, which
will outline the methods by which any development will take place in this area,
is currently expected to be completed by the end of 2002. Until the EIS is
complete and pipeline connections are established, there will be no production
from wells in this field. Until sufficient production is established, proved
reserves can not be attributed to this area. See "Items 1 and 2-Business and
Properties-Regulation- Environmental Matters-Powder River Basin-Montana" for
more information on the EIS.
Washakie Basin
The Washakie Basin is a sub-basin on the eastern flank of the Greater Green
River Basin in Wyoming. In the eastern section of Warren's Washakie Basin
property, the Mesa Verde formation dip angle is 1-2 degrees. The Mesa Verde
formation contain coals which are generally shallow (700 to 1500 feet). Then, it
plunges to 16-20 degrees on the Western rim of the Washakie Basin along a
54-mile hinge line to an approximate depth of 7,000 feet. The hinge line forms
at the point at which the Mesa Verde formation begins to plunge. Based on the
data we have collected, we believe the gas content of the coals in this basin
compares favorably to that in the coal deposits of the Powder River Basin.
However, we can not attribute proved reserves to this area until sufficient
production history is established. Currently, there is very limited coalbed
methane production in the Washakie Basin.
We now hold approximately 175,821 gross (152,010 net) acres, not including
the 51,120 acre farmout from Anadarko that covers a majority of the Washakie
Basin in Carbon County, Wyoming. We own a 100% working interest in the majority
of this acreage, with an average net revenue interest of 82.5%. We have been
acquiring our acreage in the Washakie Basin since July 1999. In the first
purchase in 1999 in the south half of the basin, we acquired approximately 40%
of our current acreage through a series of purchases from a group of privately
held independent companies at approximately $50 per acre, for a total
consideration of $3.8 million. The remaining acreage in this basin was acquired
in 2000 at an average cost of $105 per net acre, for an additional consideration
of $8.5 million. Acreage costs in the Washakie Basin increased significantly
between 1999 and 2000 due to positive results from a 20 well test drilled with
Tower Columbia Corporation and Stone & Wolf. These test drilling results
substantiated the existence of commercial amounts of natural gas from the test
wells and provided additional geological data that supported commercial
development over a wider potential area in the basin. The first farmout with
Union Pacific Resources Company, now owned by Anadarko Petroleum Corporation,
covers 51,120 net acres, and is subject to a 25% reduction if Anadarko elects to
take a 25% cost bearing working interest. If Anadarko participates as a working
interest owner, they will receive a 25% working interest at a net revenue
interest of 82.5%. Therefore, their retained net revenue interest would be
20.625% and Anadarko would deliver a 61.875% net revenue interest to us on the
farmed-out acreage. We have the right to drill and test up to five pilot
programs of five wells each. After these pilot drilling programs phase are
tested, we can submit development areas around any pilot program to encompass up
to 36 sections around each pilot program. At such time, Anadarko must elect to
participate in the development area comprising approximately 85,000 acres
(including approximately 34,000 acres owned by us) with a 25% working interest
or will deliver an 82.5% net revenue interest in the farmout acreage. During the
pilot program phase and as of December 31, 2001, we have drilled 21 wells on the
Anadarko farmout acreage and have earned spacing units for such wells
encompassing approximately 2200 acres (7 wells on 40-acre spacing, 4 wells on
80-acre spacing, and 10 wells on 160-acre spacing). The initial phase of the
farmout for drilling pilot program required us to drill a total minimum of 5
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wells on the entire "Contract Lands" and expired on January 31, 2002. Prior to
that time and due to various federal governmental delays in the permit approval
process, we requested in writing a twelve month extension of the initial pilot
phase from Anadarko in order to continue drilling more exploratory pilot wells
than the 21 already drilled. On February 1, 2002, Anadarko informed us in
writing that our request for an extension was denied. We strongly disagree with
Anadarko's denial of an extension and believe our rights under the farmout
agreement have been perpetuated because of governmental delay. However, at a
minimum, we believe we have earned at least 2200 acres by drilling 21 wells on
this acreage during the pilot program phase prior to the January 31, 2002
expiration date. We are currently in the process of discussing the matter with
Anadarko and determining the manner in which we can resolve this disagreement.
The second farmout from Big West Oil & Gas, Inc. and Flying J Oil & Gas, Inc.
covers approximately 21,695 gross (17,655 net) acres and is subject to a 50%
reduction if Big West elects to participate in the drilling of the wells, or a
30% reduction at well payout if they do not participate. Under the terms of our
agreements as amended, with Big West and Flying J, we are required to drill
eight wells and complete related disposal facilities before March 31, 2002. As
of December 31, 2001, seven earning wells (to earn acreage under the farmout)
and a water disposal well have been drilled and by mutual agreement the
remaining earning well is to be drilled and a 90 day production test is to be
completed by September 1, 2002 before Big West is required to elect to
participate for their 50% of the farmout acreage. Based on the completion of
such wells, we have earned or will earn approximately 9,259 net acres under the
Big West farmout.
Based on the initial 21 well test program, geologic work we have completed,
the BLM interim drilling policy and other regulations, we have developed an
exploration and development plan for our Washakie Basin acreage. As the Washakie
Basin encompasses a number of protected wildlife habitats and archeological
sites, the BLM's interim drilling policy and other federal or state regulations
play a significant role in determining the method in which we will develop our
Washakie Basin acreage. Specifically, these rules:
o limit the number and spacing of wells drilled;
o determine the time and manner of construction of access roads,
pipelines and other ancillary facilities; and
o requires us to seek approval from federal and state agencies for
the drilling of wells and construction of ancillary facilities.
For more information about these restrictions, see "Items 1 and 2-Business and
Properties-Regulation."
Initially, we plan to drill between 125 and 165 wells in groups of wells or
pods on 80 and 160 acre spacing. Nine of these pods will run from the northern
to the southern border of our acreage and each pod will contain a central water
injection well. It typically takes from four to ten days to drill these wells
that have targeted depths between 1,200 to 3,600 feet. We drilled 26 coalbed
methane wells and two water injection wells in 2001. Based upon preliminary data
from drilling, completion and test results, we believe that 22 of the 26 wells
drilled are potentially productive. Based on our current acreage position and
the drilling done to date, over 650 potential drilling locations have been
identified. The amounts to be funded by our drilling programs depend on amounts
actually raised in these programs in future years.
While there is currently limited pipeline infrastructure in the basin,
there are three significant pipelines that run across or near our Washakie Basin
acreage with total capacity of approximately 1.0 Bcf per day. We initially plan
to transport our production through the existing pipeline running through the
southern portion of our property that currently has a rated total capacity of 60
Mmcf per day and available capacity of 20 Mmcf per day. We believe this
represents sufficient capacity for the production we expect to bring on line in
2002. Over the longer term, we plan to build the gas gathering and transmission
infrastructure to transport our production to the northern border of our acreage
where there are several existing transportation options and several planned
expansions. The timing of construction of a gas gathering and transmission
system is contingent upon results. If only one pod in this area in the northern
portion of our acreage has positive drilling results, a system to tie into
existing infrastructure would cost approximately $250,000, which would likely be
completed by the end of 2002. Positive drilling results in the majority of the
northern half of the basin, might lead to construction and completion of such a
system by the end of 2003, at cost estimated to be approximately $1.0 million.
This area is compact in width and close to existing infrastructure. If the
entire length of the Washakie Basin proves to be productive, an entirely new
gathering system over a much larger area would need to be built to handle the
potential volume of gas produced at a cost of approximately $10.0 million, which
would likely require Warren to seek the assistance of a substantial pipeline
company to finance and construct such a system.
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Our Other Natural Gas and Oil Activities
Approximately 95% of our total net proven reserves are located in two
distinct areas:
o the Wilmington Field in the Los Angeles Basin of southern
California; and
o in east Texas where we target the James Lime and Cotton Valley
formations.
Much of our drilling activities in these established natural gas and oil
fields has and will continue to involve horizontal drilling. While a
conventional or vertical well is drilled downward in a straight line
perpendicular to the surface of the earth, a horizontal well by means of such
technologies as steerable motors and well-bore guidance telemetry is initially
drilled perpendicular to the surface and turned to horizontal at the depth of
the targeted formation with the wellbore path proceeding in a parallel path
through the target formation. Multiple laterals, often drilled in a V-pattern
and sometimes targeting different pay-zones, increase the well-bore footage in
the pay-zone. Horizontal wells are drilled as either new wells or re-entry of an
existing well. Horizontal wells, planned and drilled to target a specific
formation, may be more effective in draining certain geologic formations than
vertical wells, which is the case in our James Lime horizontal wells.
Alternatively, as in the case of many of our Wilmington Field wells, because the
surface location of the well does not correspond vertically with the location of
the targeted oil reservoir, a directional well is drilled, linking the surface
location to the target area.
Wilmington Field
Located in the heart of the Los Angeles Basin, the Wilmington Field is one
of the largest fields in California and the United States, having produced over
2.5 billion barrels of oil since its discovery in the 1920's. Effective December
31, 1998, we acquired an undivided 47% working interest in a 1,440 gross acre
area in the Wilmington Townlot Unit #1 located within the Wilmington Field. Our
operations in the Wilmington Field are governed by a Joint Venture Agreement and
Purchase and Sale Agreement dated May 1999 with our joint venture partner. Under
the Joint Venture Agreement, Pedco initially acts as the operator, drilling and
completing each well drilled in this area. However, upon commencement of
production of these wells, our joint venture partner acts as the operator.
Additionally, we pay 100% percent of the intangible drilling and completion
costs and 50% of tangible costs and receive 95% of net revenues before payout of
project costs and 80% after payout from new production.
Our drilling activities in the Wilmington Field involve the use of the
inverted five-spot method, which is one water injection well surrounded by four
oil wells. The water injection well serves to increase pressure in the target
geologic zone, moving oil away from the injector well and towards the oil wells.
In 1999, we drilled three injector wells and four oil wells. Pedco conducted the
drilling and completion operations and upon completion, our joint venture
partner took over as operator of these wells. In late 1999, our drilling
activities in this field were suspended due to litigation with our joint venture
partner as described in "Item 3--Legal Proceedings" below. In this dispute, the
Joint Venture Agreement and Purchase and Sale Agreement were upheld in a binding
arbitration in February 2001 with the order issued in July 2001. Because new
litigation was commenced in August 2001, we have been unable to recommence
drilling activities, which are unlikely to begin again until the disputes with
our joint venture partner are finally resolved. At December 31, 2001, we believe
our estimated net proved reserves in this field were approximately 8 Mmbbls (50
Bcfe), 99% of which were proved undeveloped reserves. As of December 31, 2001,
the average daily production from this field was 266 Bbls per day, net to Warren
and its drilling programs. Oil produced in this field is marketed to Huntway
Refinery at a posted price of approximately 80% of WTI Cushing.
10
East Texas-James Lime/Cotton Valley Formations
We hold approximately 110,075 gross (9,792 net) acres, where we are
targeting the James Lime and Cotton Valley formations in east Texas. The natural
gas reservoirs in this formation are low porosity and low permeability
carbonates and are naturally fractured. While geologic data indicates that there
is significant gas in place in the James Lime formation, it is generally not
well suited to development with traditional vertical wells. Vertical James Lime
wells typically drain a very limited area in their immediate vicinity given the
low porosity and low permeability of the formation. Horizontal wells, while more
expensive to drill, have the potential to significantly increase the amount of
gas production per well bore. In addition to horizontal drilling, many operators
in the area are experimenting with hydraulic fracture stimulation that has
initially shown positive results. The success of our operations in this field is
dependent on our ability to control costs and on our engineering expertise,
particularly the ability to accurately drill horizontal wells to specific
geologic targets. Our operations in this field are conducted in conjunction with
other independent operators and our working interests in the wells in this field
range from 13% to 87.5%.
From May 2000, when we first began work in this field, until December 31,
2001, we drilled ten wells, of which nine are currently producing. We are the
operator of 50% of the wells in this field. All of these wells were drilled
laterally and range in depth from 6,000 to 9,000 feet and have total lengths
ranging from 3,500 to 8,000 feet per lateral, with an average total cost to
Warren of $1.3 million per well for its average 39% working interest. As of
December 31, 2001, the production from these eight wells was 6.2 Mmcf per day,
of which 1.5 Mmcf was attributable to us and our drilling programs. At December
31, 2001, our total net proved reserves in this area attributable to Warren and
its drilling programs was 2.9 Bcfe, of which 0.7 Bcfe was attributable to our
interest.
Drilling Programs
Since 1992, we have sponsored and managed 29 privately placed drilling
programs which have served as our principal funding source for exploration,
development and production activities, and which enables investors to
participate in our drilling activities. Most of the programs have been organized
as limited partnerships. For each drilling program, we form a joint venture with
either a limited partnership (between Warren and investors) or with investors
who are direct working interest owners. These 29 programs have raised
approximately $217 million. We act as the sole managing general partner of each
drilling program. Investors in the limited partnership programs may purchase
either limited or general partnership interests (typically general partnership
interests), and receive their allocable share of income, expenses, cash
distributions and tax benefits generated by their payment of 100% of the
intangible drilling costs of the program's wells. Once drilling is completed for
the drilling programs, the investors generally have the right to convert their
general partnership interests into limited partnership interests. For drilling
programs formed since 1996, if a two-thirds majority of interests affirmatively
consents, the form of the drilling program may be changed to a limited liability
company. Of the drilling programs formed between 1997 and 1999, seven drilling
programs have voted to become limited liability companies.
Cost and Revenue Sharing at the Joint Venture Level. We enter into joint
venture agreements with the drilling programs whereby we assign to the drilling
programs 75% of our working interest and we retain the remaining 25% working
interest, before payout, in properties to be drilled with funds provided by
investors in the drilling programs, while we pay for the tangible equipment for
our working interest. The drilling program investors pay intangible drilling
costs to drill the wells and the drilling programs receive 75% of the net
revenue from the wells before well payout (60% after payout). Warren pays 100%
of the tangible completion costs on successful wells for 25% of the net revenue
from the wells before payout (40% after payout).
11
Cost and Revenue Sharing within the Drilling Programs. The investor
partners contribute 100% of the cash capital for 90% of the drilling program
revenue from oil and gas production before payout (75% after payout). We assign
75% of our working interest in the leases to the drilling programs, and receive
as our proportionate share 10% of the drilling program's net revenues before
payout, subject to production subordination. Our revenue share at both the joint
venture and drilling program levels is subject to a production subordination
clause for drilling programs formed prior to 1999 under which the drilling
programs have received 100% of net revenue. We have forgone our share of cash
flow from net revenues to the joint venture under provisions for us to do so
until aggregate production for each program exceeds 30 Bbls of oil equivalent
per day per well. For programs formed during and after 1999, we began receiving
our 25% interest in July 2001 without subordination. Prior to such time, we
voluntarily waived our 25% interest in such revenue to the joint venture. After
payout, the subordination of our interest in production is terminated.
After Payout Revenue Sharing. After payout, or the point in time at which
aggregate distributions to investors equal 100% of their original capital
invested, the drilling program's share of the joint venture's revenues decreases
from 75% to 60% and our share of revenue at the joint venture level increases
from 25% to 40%. Thus we receive from our interests in the drilling programs a
55% after-payout interest in the wells' revenues: 40% at the joint venture
level, plus 25% of the drilling program's 60% after-payout interest in the
wells, or an additional 15% interest in the wells. To date, none of our drilling
programs have reached payout status.
Interests in the programs have been sold through broker-dealers who are
members of the National Association of Securities Dealers, Inc. In addition to a
5% commission paid by the drilling program, we pay or reimburse all costs and
expenses associated with a program's organization and offering, customarily
ranging between 2% and 7% of investor subscriptions. In addition, in most of the
programs offered prior to September 30, 2000, we issued warrants to the drilling
programs and to broker-dealers in the selling group that entitled them to
purchase shares of our common stock, all of which have been exercised or have
expired.
As of December 31, 2001, investors in our drilling programs have received
cash distributions ranging from below 10% for programs formed since 1998 to 50%
to 80% for seven programs formed in 1995 or earlier, excluding two programs
formed in 1993 that have been liquidated. Currently cash distributions to
investors are made monthly. In 29 drilling programs, investors have contributed
approximately $217 million. Our sponsored programs have distributed to investors
approximately $49.2 million through December 31, 2001. We plan to continue
sponsoring drilling programs. To the extent they have funds available, our
drilling programs will continue to participate on a pro rata basis in all of our
drilling activities.
We typically contract with the drilling programs to conduct drilling
services for them on a turnkey fixed-price basis, generally subject to a profit
limitation ranging from 25% to 37.5%. Nine of the 29 programs have no
limitations on turnkey profits. Pursuant to these turnkey drilling agreements,
we are paid a fixed price for the drilling of each well and if the actual costs
we incur exceed the fixed contract price in the agreement, we pay these costs
without any recourse to the drilling program. If the actual costs incurred by us
are less than the fixed price we receive, we retain the excess.
Although generally we enter into drilling subcontracts primarily with
unrelated parties to drill wells covered by our turnkey agreements with
affiliated partnerships, from time to time field services have been provided by
our subsidiary Pinnacle. The portion of Pinnacle's drilling activities performed
for affiliated partnerships and joint ventures was 5% during 2001 and 2000.
In addition, we have marketing agreements with many of the drilling
programs under which we purchase oil and gas produced by affiliated joint
ventures and partnerships at current field prices, which we then transport and
market to third parties. We construct our own gas transportation lines that
connect wells owned by joint ventures and partnerships to the pipelines owned by
gas transportation companies. We enter into transportation contracts with these
companies and sales contracts for the sale of oil and gas to the third party
purchasers.
We are entitled to receive a $350 monthly management fee per well to cover
ongoing administrative costs, plus reimbursement of out-of-pocket expenses. This
fee has been waived since inception of the programs but will commence upon the
distribution of January 2002 production. Pedco, our wholly owned subsidiary,
also serves as the operator of the wells under a standard form of joint
operating agreement.
12
Twenty of our drilling programs entered into a buy/sell agreement, pursuant
to which an investor may tender his interest commencing seven years after the
program's closing for repurchase by the program or other investors. If the
programs or other investors do not purchase the withdrawing investor's interest,
we agree to repurchase, directly or indirectly through a third party, the
investor's interest in the drilling program at fair market value, as determined
by an independent petroleum engineer at the time of repurchase or a formula
repurchase price for drilling programs formed in 1997 and prior. For example,
the 1994 drilling program investors will first be able to exercise their
repurchase rights in December 2001 based on a repurchase price equal to an
investor's original capital invested in the program, reduced by the greater of
either total distributions made to the investor to the repurchase date or by 10%
of the original subscription price for each $1.00 the oil price is below $13.00
per Bbl at the time of repurchase, with adjustment for the change in the
Consumer Price Index since the date of initial investment. If the repurchase
price were calculated at October 1, 2001, an investor in a 1994 program would be
entitled to sell his interest for approximately 24% of his original investment.
For programs formed after 1997, the repurchase price cannot exceed an investor's
allocable share of the net present value of estimated proved reserves as
determined by an independent petroleum engineer. The buy/sell feature was
eliminated for programs beginning after 2001.
We, together with other joint venture working interest owners and investors
holding interests as working interest general partners, are jointly and
severally liable for each drilling program's debts, obligations and liabilities.
We maintain a $50 million per incident limit casualty insurance policy covering
all the programs collectively and indemnify each program and all investors
against any liability caused by our gross negligence, willful misconduct, bad
faith, fraud or breach of fiduciary duty, or for any obligation relating to
casualty losses that exceed our insurance limits and the program's assets.
As managing general partner, Warren manages and operates the business of
each of the partnerships on a day-to-day basis. However, the prior written
consent (ranging from 51% to 100%) of investor partners is required in matters
such as raising additional capital, borrowing money on behalf of the
partnerships, entering certain agreements with affiliates of Warren, the sale,
conveyance, assignment or pledge of substantially all of the partnership's or
assets; or the rollup or merger of the partnerships into or with any other
entity; confess a judgment or make an assignment of partnership property for the
benefit of creditors or other similar actions. Additionally, the partners can
remove Warren as the managing general partner at any time by a vote of more than
66.7% of all partners.
Under the terms of our drilling programs, we generally retain the right to
engage in natural gas and oil exploration and production through other entities
and for our own account. From time to time, we may engage in transactions that
are in competition with our partners or co-venturers or be faced with decisions
that could have conflicting impacts on our businesses. Involvement in these
different transactions may limit the time we have available to attend to any
particular transaction. It may also adversely affect the funds we have available
to service our financial commitments to partners or co-venturers. We may also
render certain services or provide goods for our drilling programs at fees that
are competitive with the market price.
Natural Gas and Oil Reserves
The following table presents our estimated proved natural gas and oil
reserves and the PV-10 value of our interests in net reserves in producing
properties as of December 31, 1999, 2000 and 2001 based on reserve reports
prepared by Williamson Petroleum Consultants, Inc., Midland, Texas, independent
petroleum engineers. The PV-10 values shown in the table are not intended to
represent the current market value of the estimated oil and natural gas reserves
we own. For further information concerning the PV-10 values of these proved
reserves, please read note M of the notes to our consolidated financial
statements.
A significant portion of our proved reserves has been accumulated through
our interests in the drilling programs for which we serve as managing general
partner. The estimates of future net cash flows and their present values, based
on period end prices, assume that certain of the drilling programs in which we
own interests will achieve payout status in the future. As of December 31, 2001
none of the active 29 drilling programs managed by us had achieved payout
status. As of July 1, 2001, we began receiving our before payout share of
production, typically 25%, from all programs formed in 1999. We anticipate we
will be receiving our before payout share of production in the first quarter of
2002 for all programs formed during 2000.
13
Year Ended December 31,
---------------------------
1999 2000 2001
---- ---- ----
Estimated Proved Natural Gas and Oil Reserves:
Net natural gas reserves (Bcf):
Proved developed 2.174 8.034 1.648
Proved undeveloped 2.819 3.482 0.847
---------- -------- ------
Total 4.993 11.516 2.495
========== ======== ======
Net oil reserves (Bcfe):
Proved developed 1.439 1.456 0.049
Proved undeveloped 60.897 69.164 50.821
---------- -------- -------
Total 62.336 70.620 50.870
========== ======== =======
Total Proved Natural Gas & Oil Reserves (Bcfe) 67.329 82.136 53.365
========== ======== =======
Estimated Present Value of Proved Reserves:
PV-10 Value (discounted at 10% per annum) (in
thousands)
Proved developed $ 1,862 $ 28,435 $ 1,246
Proved undeveloped 77,896 89,392 19,236
---------- -------- --------
Total $ 79,758 $117,827 $ 20,482
========== ======== ========
Standardized Measure of Discounted Future net Cash
Flows: $ 60,203 $ 89,096 $ 19,512
========== ======== ========
Prices Used in Calculating End of Year Proved
Reserves:
Oil (per Bbl) $ 20.50 $ 20.37 $ 13.87
Natural Gas (per Mcf) 1.54 8.53 1.76
There are numerous uncertainties 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 set forth in this registration statement are only estimates. Although we
believe these estimates to be reasonable, reserve estimates are imprecise and
may be expected to change as additional information becomes available. Estimates
of natural gas and oil reserves, of necessity, are projections based on
engineering data and there are uncertainties inherent in the interpretation of
this data, as well as the projection of future rates of production and the
timing of development expenditures. Reservoir engineering is a subjective
process of estimating underground accumulations of natural gas and oil that
cannot be exactly measured. Therefore, estimates of the economically recoverable
quantities of natural gas and oil attributable to any particular group of
properties, classifications of the reserves based on risk of recovery and the
estimates are a function of the quality of available data and of engineering and
geological interpretation and judgment and the future net cash flows expected
therefrom, prepared by different engineers or by the same engineers at different
times, may vary substantially. There also can be no assurance that the reserves
set forth herein will ultimately be produced or that the proved undeveloped
reserves will be developed within the periods anticipated. Actual production,
revenues and expenditures with respect to our reserves will likely vary from
estimates, and such variances may be material. In addition the estimates of
future net revenues from our proved reserves and the present value thereof are
based upon certain assumptions about future production levels, prices and costs
that may not be correct.
We emphasize, with respect to the estimates prepared by independent
petroleum engineers, that PV-10 value should not be construed as representative
of the fair market value of our proved natural gas and oil properties since
discounted future net cash flows are based upon projected cash flows which do
not provide for changes in natural gas and oil prices or for the escalation of
expenses and capital costs. The meaningfulness of such estimates is highly
dependent upon the accuracy of the assumptions upon which they are based. Actual
future prices and costs may differ materially from those estimated. You are
cautioned not to place undue reliance on the reserve data included in this
registration statement. Under SEC guidelines, estimates of the PV-10 value of
proved reserves must be made using oil and gas sales prices at the date for the
valuation, which prices are held constant throughout the life of the properties.
Commodity prices were unusually high at year-end 2000, especially gas prices,
and have declined since that time. NYMEX pricing for natural gas ranged from
$2.13 to $10.10 per Mcf during 2000 and from $1.91 to $9.82 per Mcf during 2001.
NYMEX pricing for oil ranged from $23.70 to $37.80 per Bbl during 2000 and from
$17.45 to $32.19 per Bbl during 2001.
14
Productive Wells
The following table sets forth our gross and net productive wells as of
December 31, 2001:
Natural Gas Wells Oil Wells Total
----------------------------- ------------------------ ----------------------------
Gross Net Gross Net Gross Net
------------- ------------ --------- ----------- ---------- -----------
California............. 0 0.0 5 2.9 5 2.9
Montana................ 0 0.0 0 0.0 0 0.0
New Mexico............. 8 1.1 10 1.4 18 2.5
Texas.................. 17 4.2 26 6.5 43 10.7
Wyoming................ 132 12.1 4 0.4 136 12.5
Other.................. 2 0.9 3 1.4 5 2.3
------------- ------------ --------- ----------- ---------- -----------
Total......... 159 18.3 48 12.6 207 30.9
============= ============ ========= =========== ========== ===========
Gross wells represent all wells in which we have an interest. Net wells
represent the total of our fractional undivided working interest in those wells.
Drilling Activity
The following table sets forth our drilling activities for the three years
1999, 2000 and 2001:
Year Ended December 31,
-----------------------------------------------------------------
1999 2000 2001
------------------- -------------------- ------------------
Gross Net
Exploratory Wells(1)
Productive(2) 14 4.8 1 0.3 6 2.8
Nonproductive(3) 4 1.4 2 0.7 20 9.5
Development Wells(1)
Productive(2) 92 31.6 69 23.7 10 4.7
Nonproductive(3) 1 0.3 0 0.0 0 0
------- ------ ------- ------ ------- -------
TOTAL 111 38.1 72 24.7 36 17.0
======= ====== ======= ====== ======= =======
- ------------
(1) An exploratory well is a well drilled either in search of a new, as yet
undiscovered oil or gas reservoir or to greatly extend the known limits of
a previously discovered reservoir. A development well is a well drilled
within the presently proved productive area of an oil or gas reservoir, as
indicated by reasonable interpretation of available data, with the
objective of completing in that reservoir.
(2) A productive well is an exploratory or development well found to be capable
of producing either oil or gas in sufficient quantities to justify
completion as an oil or gas well.
(3) A nonproductive well is an exploratory or development well that is not a
producing well.
Natural Gas and Oil Acreage
The following table sets forth our acreage position as of December 31,
2001:
Developed Undeveloped Total
----------------------------- ------------------------ --------------------------
Gross Net Gross Net Gross Net
------------- ------------ ---------- ---------- ---------- ---------
California.............. 1,128 407 312 113 1,440 520
Montana................. 160 158 23,973 21,917 24,133 22,075
New Mexico.............. 14,636 2,248 800 260 15,436 2,508
Texas................... 15,053 1,973 186,342 20,261 201,395 22,234
Wyoming (1)............. 6,762 3,760 173,289 149,201 180,051 152,961
Other................... 1,296 428 4,352 1,143 5,648 1,571
------------- ------------ ---------- ---------- ---------- ---------
Total.......... 39,035 8,974 389,068 192,895 428,103 201,869
============= ============ ========== ========== ========== =========
(1) These numbers do not include the gross and net acres covered by the
Anadarko farmout. See "Items 1 and 2 --Business and Properties -- Coalbed
Methane Properties -- Washakie Basin" above.
15
Production Volumes, Sales Prices and Production Costs
The following table summarizes our net natural gas and oil production
volumes, our average sales prices and expenses for the periods indicated. Our
volumes are attributable to our direct interests in producing properties and the
production we are allocated from our 1999 and subsequent drilling programs where
we typically receive 25% of the production from such programs. For these
purposes, our net production will be production that is owned by us either
directly or indirectly through our drilling programs, after deducting royalty,
limited partner and other similar interests. The lease operating and
depreciation, depletion and amortization expenses shown are related only to our
net production. The majority of our lease operating expense is from workovers
and other operating costs paid by us on behalf of our drilling programs and does
not represent lease operating expense related to our net production.
Years Ended December 31,
--------------------------------
1999 2000 2001
---------- -------- --------
Production:
Natural Gas (Mmcf) 13.7 29.9 32.6
Oil (Mbbls) 4.3 3.2 2.3
Total Equivalents (Mmcfe) 39.5 49.1 46.7
Average Sales Price Per Unit:
Natural Gas Without Hedge ($ per Mcf) $2.24 $3.33 $3.07
Hedge Loss - (0.07) (0.24)
---------- -------- --------
Actual Natural Gas 2.24 3.26 2.83
---------- -------- --------
Oil ($ Mbbls) $ 14.89 $ 26.26 $ 16.74
Total Equivalents ($ per Mcfe) $ 2.40 $ 3.70 $ 2.82
Expenses (per Mcfe):
Lease Operating Expense (For Our Net Production) $ 0.76 $ 1.46 $ 1.50
Purchasers and Marketing
We sell our oil and natural gas production and that of our drilling
programs to various purchasers in the areas where the oil and natural gas is
produced. The oil is sold to crude oil purchasers at storage tankage that we own
located on the lease of property. The natural gas is sold into pipelines and
re-marketed or used by various gas purchasers. We are currently able to sell all
of the oil and natural gas produced on our behalf and that of our drilling
programs. Substantially all of this oil and gas is sold under monthly contracts
that allow for periodic adjustments in pricing according to market demands.
Approximately 66% of Warren's gas production is subject to a firm commitment
contract for transportation space (but not sales) with Williston Basin
Interstate relating to its LX-Bar lease for 9 MMcf per day, which contract
terminates on December 31, 2002. The price for gas provided is the market price
at the time. Additionally, we have a firm commitment contract relating to its
Piper Federal lease covering requirements for us to deliver 2.5 MMcf per day.
The maximum penalty for any deficiency below 90% of cumulative contracted
volumes would be $0.42 per mcf. This contract terminates on December 31, 2004.
The marketing of oil and natural gas can be affected by factors beyond our
control, the effects of which cannot be predicted. For more information about
the risks to our business posed by our marketing activities see "Item
7-Management's Discussion and Analysis of Financial Condition and Results of
Operation-Risk Factors-The marketability of our production is dependent upon
factors over which we have no control."
For the year ended December 31, 2001, the largest purchasers for our
production and that of our drilling programs included Tenaska Marketing
Ventures, Western Gas Resources, Inc. and Huntway Refining Company, which
accounted for 30%, 8% and 16%, respectively, of the oil and gas sold by us and
our drilling programs. We do not believe, however, that the loss of any of these
purchasers would have a material adverse effect on our operations. Our contracts
with Tenaska and Western have minimum deliverability requirements. From May 2000
to February 2001, we were deficient on approximately 274,000 Mcf related to our
firm commitment contracts due to delays in obtaining water discharge permits for
32 new coalbed methane wells on our LX-Bar property. The deficiency was covered
by gas balancing agreements and outright purchases of gas at a net cost of
approximately $600,000. We have not been deficient on any firm commitments
contracts subsequent to February 2001. Our firm commitment contracts have ranged
from approximately 6,000 to 9,000 Mcf per day.
16
We compete with a number of other potential purchasers of natural gas and
oil leases and producing properties, many of which have greater financial
resources than we do. In general, the bidding for natural gas and oil leases has
become particularly intense in the Powder River and Washakie Basins with bidders
evaluating potential acquisitions with varying product pricing parameters and
other criteria that result in widely divergent bid prices. The presence of
bidders willing to pay prices higher than are supported by our evaluation
criteria could further limit our ability to acquire natural gas and oil leases.
In addition, low or uncertain prices for properties can cause potential sellers
to withhold or withdraw properties from the market. In this environment, we
cannot guarantee that there will be a sufficient number of suitable natural gas
and oil leases available for acquisition or that we can sell natural gas and oil
leases or obtain financing for, or participants to join in, the development of
prospects.
Our Service and Operational Activities
Our drilling, completion, production and land operations are conducted,
managed and supervised for us and our drilling programs through Pedco, our
wholly owned subsidiary. After a long-term joint venture relationship with Pedco
that began in 1990, we acquired Pedco on September 1, 2000. See "Item 13-Certain
Relationships and Related Transactions." Through Pedco, we employ six petroleum
engineers, several drilling supervisors, landmen and administrative personnel,
as well as field supervisors. Pedco also employs three geologists on a contract
basis. Pursuant to joint venture agreements, Pedco has been the contract
operator for the majority of our wells for the past ten years, and is the
operator of 64% of the wells in which we and our drilling programs had interests
as of December 31, 2001.
We previously provided drilling and certain field services through
Pinnacle, another wholly owned subsidiary, the assets of which were sold as of
February 14, 2002. At the time of sale, Pinnacle employed approximately 45 rig
hands and owned eight operational workover rigs, one operational
horizontal/recompletion rig, one operational swabbing unit and one
non-operational swabbing unit. Two workover rigs were located in Beeville, Texas
and the rest of Pinnacle's equipment was based in Artesia, New Mexico. During
2001 and 2000, approximately 5% of Pinnacle's operations were in support of
Pedco, the balance was for third parties on a variety of contract terms,
including hourly, daily or per job rates.
Regulation
General
Our business is affected by numerous laws and regulations, including
energy, environmental, conservation, tax and other laws and regulations relating
to the energy industry. Changes in any of these laws and regulations could have
a material adverse effect on our business. In view of the many uncertainties
with respect to current and future laws and regulations, including their
applicability to us, we cannot predict the overall effect of such laws and
regulations on our future operations.
We believe that our operations comply in all material respects with
applicable laws and regulations and that the existence and enforcement of such
laws and regulations have no more restrictive an effect on our operations than
on other similar companies in the energy industry. Warren anticipates no
material estimated capital expenditures to comply with federal and state
environmental requirements. To date, state-wide reclamation bonds and our $50
million casualty and environmental insurance have been adequate to meet such
requirements. Additionally, we have posted a $3.2 million US Treasury Bond as
collateral for a $4.0 million reclamation bond for the Wilmington Field. The
following discussion contains summaries of certain laws and regulations and is
qualified in its entirety by the foregoing.
Proposals and proceedings that might affect the oil and gas industry are
pending before Congress, the Federal Energy Regulatory Commission, or "FERC",
the Minerals Management Service, or "MMS", state legislatures and commissions
and the courts. We cannot predict when or whether any such proposals may become
effective. In the past, the natural gas industry has been heavily regulated.
There is no assurance that the regulatory approach currently pursued by various
agencies will continue indefinitely. Notwithstanding the foregoing, we do not
anticipate that compliance with existing federal, state and local laws, rules
and regulations will have a material or significantly adverse effect upon our
capital expenditures, earnings or competitive position. No material portion of
our business is subject to re-negotiation of profits or termination of contracts
or subcontracts at the election of the federal government.
17
Federal Regulation of Sales and Transportation of Natural Gas
Historically, the transportation and sale of natural gas in interstate
commerce has been regulated under several laws enacted by Congress and the
regulations passed under these laws by FERC. Our sales of natural gas are
affected by the availability, terms and cost of transportation. The price and
terms of access to pipeline transportation are subject to extensive federal and
state regulation. From 1985 to the present, several major regulatory changes
have been implemented by Congress and FERC that affect the economics of natural
gas production, transportation and sales. In addition, FERC is continually
proposing and implementing new rules and regulations affecting those segments of
the natural gas industry, most notably interstate natural gas transmission
companies, that remain subject to FERC's jurisdiction. These initiatives may
also affect the intrastate transportation of gas under certain circumstances.
The stated purpose of many of these regulatory changes is to promote competition
among the various sectors of the natural gas industry.
The ultimate impact of the complex rules and regulations issued by FERC
cannot be predicted. In addition, many aspects of these regulatory developments
have not become final but are still pending judicial and final FERC decisions.
We cannot predict what further action FERC will take on these matters. Some of
FERC's more recent proposals may, however, adversely affect the availability and
reliability of interruptible transportation service on interstate pipelines. We
do not believe that we will be affected by any action taken materially
differently than other natural gas producers, gatherers and marketers with whom
we compete.
Federal Regulation of Sales and Transportation of Crude Oil
Our sales of crude oil, condensate and natural gas liquids are currently
not regulated and are made at market prices. In a number of instances, however,
the ability to transport and sell such products are dependent on pipelines whose
rates and terms of service are subject to FERC jurisdiction under the Interstate
Commerce Act. Some of the regulations implemented by FERC in recent years could
result in an increase in the cost of transportation service on certain petroleum
pipelines. However, we do not believe that these regulations affect us any
differently than other producers of these products.
Operations on Federal Oil and Gas Leases
We conduct a sizeable portion of our operations on federal oil and natural
gas leases which are administered by the MMS. Federal leases contain relatively
standard terms and require compliance with detailed MMS regulations and orders,
which are subject to change. Under certain circumstances, the MMS may require
any of our operations on federal leases to be suspended or terminated. Any such
suspension or termination could materially and adversely affect our financial
condition, cash flows and operations. The MMS issued a final rule that amended
its regulations governing the valuation of oil produced from federal leases.
This new rule, which became effective June 1, 2000, provides that the MMS will
collect royalties based on the market value of oil produced from federal leases.
The lawfulness of the new rule has been challenged in federal court. We cannot
predict whether this new rule will be upheld in federal court, nor can we
predict whether the MMS will take further action on this matter. However, we do
not believe that this new rule will affect us any differently than other
producers and marketers of oil.
State Regulation
Our operations are also subject to regulation at the state and in some
cases, county, municipal and local governmental levels. Such regulation includes
requiring permits for the drilling of wells, maintaining bonding requirements in
order to drill or operate wells and regulating the location of wells, the method
of drilling and casing wells, the surface use and restoration of properties upon
which wells are drilled, the plugging and abandonment of wells and the disposal
of fluids used and produced in connection with operations. Our operations are
also subject to various conservation laws and regulations pertaining to the size
of drilling and spacing units or proration units and the unitization or pooling
of oil and gas properties.
In addition, state conservation laws, which frequently establish maximum
rates of production from oil and gas wells, generally prohibit the venting or
flaring of gas and impose certain requirements regarding the rates of
production. State regulation of gathering facilities generally includes various
safety, environmental and, in some circumstances, nondiscriminatory take
requirements, but, except as noted above, does not generally entail rate
regulation. These regulatory burdens may affect profitability, but we are unable
to predict the future cost or impact of complying with such regulations.
18
Environmental Matters
General
We are subject to extensive federal, state and local environmental laws and
regulations that restrict or limit our business activities for purposes of
protecting human health and the environment. Compliance with the multitude of
regulations issued by federal, state, and local administrative agencies can be
burdensome and costly. State environmental regulatory programs are generally
very similar to the corresponding federal environmental regulatory programs, and
federal environmental regulatory programs are often delegated to the states.
Our oil and gas exploration and production operations are subject to state
and/or federal solid waste regulations that govern the storage, treatment, and
disposal of solid and hazardous wastes. However, much of the solid waste
generated by our oil and gas exploration and production activities is exempt
from regulation as hazardous waste under federal, and many state, regulatory
programs. To the extent our operations generate solid waste, such waste is
generally subject to state regulations. We have not experienced difficulty in
complying with applicable solid waste regulations in the areas in which we
operate.
In addition to oil and gas, our production operations generate produced
water as a waste material. This water can sometimes be disposed of by
discharging it under discharge permits issued pursuant to the Clean Water Act,
or an equivalent state program. We have not experienced difficulties in
obtaining discharge permits in areas where such permits are issued. Another
common method of produced water disposal is subsurface injection in disposal
wells. Such disposal wells are permitted under the Safe Drinking Water Act, or
an equivalent state regulatory program. The drilling, completion, and operation
of produced water disposal wells is integral to oil and gas operations. We
already operate produced water disposal wells, particularly in association with
our coalbed methane production operations. We are experienced in these
activities and are able to perform these activities in a cost-effective manner.
Air emissions from some of our equipment, such as gas compressors, are
potentially subject to regulations under the Clean Air Act, or equivalent state
regulatory programs. To the extent that our air emissions are regulated, they
are generally regulated by permits issued by state regulatory agencies. We have
not encountered difficulties in obtaining air permits, where needed.
Some of our exploration and production activities occur on federal leases.
This is particularly true of our coalbed methane operations. Exploration and
production operations on federal leases are generally performed in accordance
with a record of decision issued by the BLM after performance of an
environmental impact study. A record of decision typically includes
environmental and land use provisions that restrict and limit exploration and
production activities on federal leases. Much of our coalbed methane operations
are subject to records of decision and we have not experienced any material
difficulty in complying with their terms and conditions. Nor do we anticipate
any material adverse effect on our operations from terms and conditions in
records of decision that are pending from the BLM.
In the event that spills or releases of crude oil or produced water occur,
we would be subject to spill notification and response regulations under the
Clean Water Act, or equivalent state regulatory programs. Depending on the
nature and location of our operations, we may also be required to prepare spill
response plans under the Clean Water Act, or equivalent state regulatory
programs.
19
Failure to comply with such regulations may result in the imposition of
substantial administrative, civil, or criminal penalties, or restrict or
prohibit our desired business activities. Environmental laws and regulations
impose liability, sometimes strict liability, for environmental cleanup costs
and natural resource damages. Other environmental laws and regulations may delay
or prohibit exploration and production activities in environmentally sensitive
areas or impose additional costs on these activities.
We believe that we are in substantial compliance with current applicable
environmental laws and regulations and that continued compliance with existing
requirements will not have a material adverse impact on us. Costs associated
with responding to a major spill of crude oil or produced water, or costs
associated with remediation of environmental contamination, are the most likely
occurrences which could result in a material adverse impact on our capital
expenditures, earnings, or competitive position. We are not currently liable for
any such environmental cleanup costs, and we operate our producing properties in
a prudent manner in order to avoid or minimize such liabilities.
In addition, changes in applicable federal, state and local environmental
laws and regulations have the potential to adversely affect our operations. In
this regard, our coalbed methane drilling and production operations are subject
to ongoing BLM oversight and recurring BLM approvals and could be affected by
changes in BLM regulations or policies. However, we are not aware of any pending
changes in state or federal environmental statutes or regulations that would
have a material adverse impact on our operations.
We anticipate that total maximum daily load water quality standards may be
promulgated within five years for surface water bodies in areas where we
operate, including the Powder River Basin of Wyoming and Montana. However, we do
not expect that any total maximum daily load regulations, or standards
promulgated in any area where we operate to result in a material increase in our
produced water disposal costs, as we already inject much of our produced water
in disposal wells, and would be able to cost-effectively drill and operate
additional disposal wells as needed.
Coalbed Methane Operations
The majority of our production is from coalbed methane operations which
generate water and air discharges that are subject to significant regulatory
control. Naturally occurring groundwater is typically produced by our coalbed
methane production operations. This produced water is disposed of by
re-injection into the subsurface through disposal wells, discharge to the
surface, or in evaporation ponds. Whichever disposal method is used, produced
water must be disposed of in compliance with permits issued by federal and state
regulatory agencies, and in compliance with applicable federal, state and local
environmental regulations. To date, we have been able to obtain necessary
surface discharge or disposal well permits and we have been able to discharge
produced water and operate our produced water disposal wells in substantial
compliance with our permits and applicable federal, state and local laws and
regulations without undue cost or burden to our business activities. Our coalbed
methane operations involve the use of gas-fired compressors to transport gas
which we produced. Emissions of nitrogen oxides and other combustion by-products
from individual compressors or multiple compressors at one location may be great
enough to subject the compressors to federal and state air quality requirements
for pre-construction and operating permits. To date, we have not experienced
significant delays or problems in obtaining the required air permits and have
been able to operate these compressors in substantial compliance with our
permits and applicable federal, state and local laws and regulations without
undue cost or burden to our business activities. Another air emission associated
with our coalbed methane operations that may be subject to regulation and
permitting requirements is particulate matter resulting from construction
activities and vehicle traffic. To date, we have not experienced any difficulty
complying with environmental requirements related to particulate matter.
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Powder River Basin
Wyoming. Drilling and production operations on our Powder River Basin
leases in Wyoming are subject to environmental rules, requirements and permits
issued by federal, state and local regulatory agencies, including the BLM and
the Wyoming Department of Environmental Quality, or "DEQ." The BLM has imposed
environmental limitations and conditions on coalbed methane drilling, production
and related construction activities on federal leases in certain specific areas
of the Powder River Basin. These conditions and requirements are imposed through
a record of decision issued pursuant to an environmental impact statement. The
BLM may also impose site-specific conditions on development activities, such as
drilling and the construction of right-of-ways, before it approves required
applications for permits to drill and plans of development. We believe that we
have operated our Wyoming Powder River Basin federal leases in substantial
compliance with the BLM's current requirements. The BLM is currently developing
an environmental impact statement, or "EIS," for oil and gas development in the
Powder River Basin of Wyoming. This Powder River Basin EIS is expected to be
completed, and a record of decision issued, by the end of 2002. At the present
time, we have no ability to determine whether this EIS or future BLM
site-specific approvals will result in conditions or requirements more stringent
than, or materially different from, current BLM regulation of Powder River Basin
coalbed methane operations in Wyoming.
Our Wyoming Powder River Basin coalbed methane production operations are
also subject to Wyoming DEQ environmental regulations and permit requirements.
Permits required from the Wyoming DEQ include air emission and produced water
discharge permits. To date, we have not experienced any difficulty in obtaining
air permits from the Wyoming DEQ. Injection wells are used to dispose of
produced water when surface discharge permits cannot be obtained from the
Wyoming DEQ. We have three permitted injection wells for our Wyoming Powder
River Basin operations. We anticipate the need to permit, drill and operate
additional injection wells in the event additional subsurface disposal capacity
is needed.
Montana. Our acreage leased in Montana for coalbed methane exploration
and production is currently not significantly developed. Most of our coalbed
methane leases in the Kirby-Decker Prospect of Montana are not federal leases.
However, the Montana Board of Oil and Gas, or "BOG," has agreed to perform an
EIS for coalbed methane operations in the state as part of a settlement
agreement. The Montana BOG agreed to a moratorium on permitting coalbed methane
wells pending completion of this environmental impact statement. This EIS, which
will specify the conditions under which coalbed methane development will be
permitted in Montana, is expected to be completed by the end of 2002. At the
present time, we have no ability to determine whether conditions or limitations
will be imposed that would preclude or significantly hamper development of our
coalbed methane properties in the Kirby-Decker Prospect in Montana.
Washakie Basin
The Washakie Basin is located in Wyoming and is currently the subject of
the Atlantic Rim EIS being developed by BLM. The initial, or scoping, phase of
the Atlantic Rim EIS covering our coalbed methane leases in the Washakie Basin
is currently under way. Completion of the environmental impact statement and
issuance of a record of decision is currently expected by the end of 2003.
21
The BLM has issued an interim drilling policy allowing some coalbed methane
drilling and production activity in the Atlantic Rim project area pending
completion of the EIS. The interim drilling policy authorizes drilling,
completing, and producing no more than 200 wells until completion of the
Atlantic Rim EIS. We have been allocated approximately 165 of the 200 authorized
wells. The interim policy requires the wells to be drilled in nine pods of no
more than 24 wells per pod. A pod is defined as two or more production wells
with supporting infrastructure, such as access roads, injection wells, product
pipelines, water pipelines, power lines and other necessary ancillary
facilities. The Atlantic Rim project area contains federally designated
threatened and endangered species and two wildlife habitat areas that have been
designated as areas of critical environmental concern. Sensitive areas such as
critical habitat and archeological sites must be avoided in constructing the
pods. Federal and non-federal leases in the Atlantic Rim project area are
subject to the 200 well limit. To date, we have received BLM and state approval
of drilling permits for twelve wells, and approval of right-of-ways for four
pods.
The BLM may modify the interim drilling policy at any time and the policy,
as with any agency decision, is subject to challenge by interested parties. The
interim policy requires an environmental assessment for each of the nine pods.
Public comment is allowed on each environmental assessment, and BLM approval of
each environmental assessment must be obtained before pod construction can
commence. In addition, many of the restrictions, conditions and limitations on
our drilling, production and construction activities in the Washakie Basin will
be specified by the BLM in the final Atlantic Rim record of decision. Finally,
conditions and restrictions on drilling, production and construction activities
may be imposed through site-specific BLM approvals required for applications for
permits to drill and plans of development. As a result, such development
activities will remain contingent on BLM approval for much of the project life.
Our Washakie Basin coalbed methane production operations are also subject
to DEQ environmental regulations and permit requirements. Permits required from
the Wyoming DEQ include air emission and produced water discharge permits. To
date, we have not experienced any difficulties in obtaining any air permits
needed for our Washakie Basin operations from the Wyoming DEQ. Produced water
disposal will be limited to subsurface injection in the portion of the Washakie
Basin within the Colorado River drainage area. We have received permits for
eight produced water injection wells in the Atlantic Rim project area. Should
additional subsurface disposal capacity be needed, we will need to obtain
permits for additional injection wells. Surface discharge of water remains an
option in those portions of the basin outside of the Colorado River drainage
area.
Wilmington Field
The Wilmington Field is located in the Los Angeles metropolitan area in
California. Under the joint venture agreement governing operations in this
field, we are operator for drilling and completion activities and our joint
venture partner is operator for production activities. This field is located in
a mixed light industrial and residential area near the Port of Los Angeles.
Field activities include drilling wells to develop our lease acreage and
operating a waterflood to maximize crude oil production.
22
Stringent environmental regulations, restrictive permit conditions and the
possibility of permit denials from a multiplicity of state, regional and local
regulatory agencies may inhibit or add cost to future Wilmington Field
development activities. Despite prudent operation and preventative measures,
drilling and waterflooding production operations may result in spills and other
accidental releases of produced and injection fluids. Remediation and associated
costs from a release of produced fluids in an urban environment may also be
significant. This potential liability is accentuated by the location of our
Wilmington Field leases in California and in an urban setting, including
proximity to residential areas. To date and to our knowledge, there are no
environmentally related lawsuits or other third-party claims or complaints
pending against us relating to our interests or activities in the Wilmington
Field.
East Texas and North Louisiana
We have a significant acreage position in the Cotton Valley and James Lime
formations of east Texas and north Louisiana. Currently, these leases are
relatively undeveloped. As a result, we believe the current potential for
environmental liability associated with these properties is lower than for other
properties that are more fully developed.
Operating Hazards And Insurance
The oil and natural gas business involves a variety of operating risks,
including fires, explosions, blowouts, environmental hazards and other potential
events which can adversely affect our operations. Any of these problems could
adversely affect our ability to conduct operations and cause us to incur
substantial losses. Such losses could reduce or eliminate the funds available
for exploration, exploitation or leasehold acquisitions or result in loss of
properties.
In accordance with industry practice, we maintain insurance against some,
but not all, potential risks and losses. We do not carry business interruption
insurance. For some risks, we may elect not to obtain insurance if we believe
the cost of available insurance is excessive relative to the risks presented. In
addition, pollution and environmental risks generally are not fully insurable at
a reasonable cost. If a significant accident or other event occurs and is not
fully covered by insurance, it could adversely affect us.
Title to Properties
In most situations, as is customary in the oil and gas industry, only a
preliminary title examination is conducted at the time we acquire oil and gas
leases covering properties for possible drilling operations. Prior to the
commencement of drilling operations, a more complete title examination of the
drill site tract often is conducted by independent attorneys. Once production
from a given well is established, we usually prepare a division order title
report indicating the proper parties and percentages for payment of production
proceeds, including royalties. The level of title examination often differs from
property to property. For example, we acquired our interest in the Wilmington
Field with no warranty of title at all, no representation as to the percentage
working or net revenue interest we acquired and no title opinion as to the
acquired interest. On a gross acreage basis we estimate that no complete title
search has been conducted on approximately 5.0% of such gross acreage, which
represents approximately 94% of our year-end 2001 proved reserves. Our
properties are subject to customary royalty interests, liens incident to
operating agreements, liens for current taxes and other burdens which we believe
do not materially interfere with the use of or affect the value of our
properties.
23
Employees
At December 31, 2001, we had 98 full-time employees. We believe that our
relationships with our employees are good. None of our employees are covered by
a collective bargaining agreement. From time to time, we use the services of
independent consultants and contractors to perform various professional
services, particularly in the areas of geological, permitting and environmental
assessment. Independent contractors often perform field and on-site production
operation services for us, including pumping, maintenance, dispatching,
inspection and testing.
Facilities
Our principal executive offices are located at 489 Fifth Avenue, 32nd
Floor, New York, New York 10017, and our telephone number is (212) 697-9660. We
lease approximately 4,097 square feet of office space for our New York office
under a lease that expires in 2008. Our regional office in Albuquerque, New
Mexico occupies 3,000 square feet under a lease expiring May 31, 2003. Our Rocky
Mountain operations are headquartered in a 3,150 square foot space in Gillette,
Wyoming. Pedco owns a ranch with a 3,000 square foot field office in Beeville,
Texas. We believe that suitable additional space to accommodate our anticipated
growth will be available in the future on commercially reasonable terms.
Glossary of Abbreviations and Terms
The following are abbreviations and definitions of certain terms commonly
used in the oil and gas industry and this registration statement:
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in
reference to oil or other liquid hydrocarbons.
Bcf. One billion cubic feet of natural gas at standard atmospheric
conditions.
Bcfe. One billion cubic feet equivalent of natural gas, calculated by
converting oil to equivalent Mcf at a ratio of 6 Mcf to 1 Bbl of oil.
Completion. The installation of permanent equipment for the production of
oil or natural gas.
Developed Acreage. The number of acres which are allocated or assignable to
producing wells or wells capable of production.
Exploitation. The continuing development of a known producing formation in
a previously discovered field. To make complete or maximize the ultimate
recovery of oil or natural gas from the field by work including development
wells, secondary recovery equipment or other suitable processes and technology.
Exploration. The search for natural accumulations of oil and natural gas by
any geological, geophysical or other suitable means.
Farmout or Farmin. An agreement where the owner of a working interest in an
oil and gas lease assigns the working interest or a portion thereof to another
party who desires to drill on the leased acreage. Generally, the assignee is
required to drill one or more wells in order to earn its interest in the
acreage. The assignor usually retains a royalty or reversionary interest in the
lease. The interest received by an assignee is a farmin while the interest
transferred by the assignor is a farmout.
Fracturing. The technique of improving a well's production or injection
rates by pumping a mixture of fluids into the formation and rupturing the rock,
creating an artificial channel. As part of this technique, sand or other
material may also be injected into the formation to keep the channel open, so
that fluids or gases may more easily flow through the formation.
24
Gross Acres. The total acres in which we have a working interest.
Gross Wells. The total number of producing wells in which we own any amount
of working interest.
Horizontal Drilling. A drilling operation in which a portion of the well is
drilled horizontally within a productive or potentially productive formation.
This operation usually yields a well which has the ability to produce higher
volumes than a vertical well drilled in the same formation.
Injection Well or Injector. A well which is used to place liquids or gases
into the producing zone during secondary/tertiary recovery operations to assist
in maintaining reservoir pressure and enhancing recoveries from the field.
Intangible Drilling Costs. Expenditures made for wages, fuel, repairs,
hauling and supplies necessary for the drilling or recompletion of an oil or gas
well and the preparation of such well for the production of oil or gas, but
without any salvage value, which expenditures are generally accepted in the oil
and gas industry as being currently deductible for federal income tax purposes.
Examples of such costs include:
o ground clearing, drainage construction, location work, road
making, temporary roads and ponds, surveying and geological
works;
o drilling, completion, logging, cementing, acidizing, perforating
and fracturing of wells;
o hauling mud and water, perforating, swabbing, supervision and
overhead;
o renting horizontal tools, milling tools and bits; and
o construction of derricks, pipelines and other physical structures
necessary for the drilling or preparation of the wells.
Lease. An instrument which grants to another (the lessee) the exclusive
right to enter to explore for, drill for, produce, store and remove oil and
natural gas on the mineral interest, in consideration for which the lessor is
entitled to certain rents and royalties payable under the terms of the lease.
Typically, the duration of the lessee's authorization is for a stated term of
years and "for so long thereafter" as minerals are producing.
Mbbl. One thousand barrels of oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet of natural gas.
Mcfe. One thousand cubic feet equivalent of natural gas, calculated by
converting oil to equivalent Mcf at a ratio of 6 Mcf to 1 Bbl of oil.
Mmbbl. One million barrels of oil or other liquid hydrocarbons.
Mmcf. One million cubic feet of natural gas, measured at standard
atmospheric conditions.
Mmcfe. One million cubic feet equivalent of natural gas, calculated by
converting oil to equivalent Mcf at a ratio of 6 Mcf to 1 Bbl of oil.
Net Acres. Gross acres multiplied by the percentage working interest owned
by Warren.
PV-10 Value. The present value of estimated future revenues to be generated
from the production of proved reserves calculated in accordance with SEC
guidelines, net of estimated lease operating expense, production taxes and
future development costs, using prices and costs as of the date of estimation
without future escalation, without giving effect to non-property related
expenses such as general and administrative expenses, debt service and
depreciation, depletion and amortization or Federal income taxes and discounted
using an annual discount rate of 10%.
25
Net Wells. The sum of all the complete and partial well ownership interests
(i.e., if we own 25% percent of the working interest in eight producing wells,
the subtotal of this interest to the total net producing well count would be two
net producing wells).
Net Production. Production that is owned by Warren less royalties and
production due others.
NYMEX. New York Mercantile Exchange.
Operator. The individual or company responsible for the exploration,
exploitation and production of an oil or natural gas well or lease.
Permeability. The capacity of a geologic formation to allow water, natural
gas or oil to pass through it.
Porosity. The ratio of the volume of all the pore spaces in a geologic
formation to the volume of the whole formation.
Royalty. An interest in an oil and natural gas lease that gives the owner
of the interest the right to receive a portion of the production from the leased
acreage, or of the proceeds of the sale thereof, but generally does not require
the owner to pay any portion of the costs of drilling or operating the wells on
the leased acreage. Royalties may be either landowner's royalties, which are
reserved by the owner of the leased acreage at the time the lease is granted, or
overriding royalties, which are usually reserved by an owner of the leasehold in
connection with a transfer to a subsequent owner.
Secondary Recovery. An artificial method or process used to restore or
increase production from a reservoir after the primary production by the natural
producing mechanism and reservoir pressure has experienced partial depletion.
Gas injection and waterflooding are examples of this technique.
Standardized Measure of Discounted Future Net Cash Flows. The present value
of future discounted net cash flows attributed to proved oil and gas properties
made by applying year-end prices of oil and gas (with consideration of price
changes only to the extent provided by contractual arrangements) to the
estimated future production of proved oil and gas reserves, less estimated
future expenditures (based on year-end costs) to be incurred in developing and
producing the proved reserves, less estimated future income tax expenses (based
on year-end statutory tax rates, with consideration of future tax rates already
legislated) to be incurred on pretax net cash flows less tax basis of the
properties and available credits, and assuming continuation of existing economic
conditions. The estimated future net cash flows are then discounted using a rate
of 10% per year to reflect the estimated timing of the future cash flows.
Tangible Drilling Costs. Expenditures necessary to develop oil or gas
wells, including acquisition, transportation and storage costs, which typically
are capitalized and depreciated for federal income tax purposes. Examples of
such expenditures include:
o well casings;
o wellhead equipment;
o water disposal facilities;
o metering equipment;
o pumps;
o gathering lines; and
o storage tanks.
26
3-D Seismic. The method by which a three dimensional image of the earth's
subsurface is created through the interpretation of reflection seismic data
collected over a surface grid. 3-D seismic surveys allow for a more detailed
understanding of the subsurface than do conventional surveys and contribute
significantly to field appraisal, exploitation and production.
Waterflood. A secondary recovery operation in which water is injected into
the producing formation in order to maintain reservoir pressure and force oil
toward and into the producing wells.
Working Interest. An interest in an oil and natural gas lease that gives
the owner of the interest the right to drill for and produce oil and natural gas
on the leased acreage and requires the owner to pay a share of the costs of
drilling and production operations.
Item 3: Legal Proceedings
Except as provided below, we are not engaged in any material legal
proceedings to which we or our subsidiaries are a party or to which any of our
property is subject.
On September 28, 1999, Magness Petroleum Company, our joint venture partner
in the Wilmington Field, filed a complaint against Warren, Pedco, and certain
Warren subsidiaries in the Superior Court of Los Angeles County, alleging that
we had breached our joint venture agreement with Magness and an alleged oral
agreement regarding advance payment of expenses for drilling and completion
operations. Magness sought dissolution of the joint venture, an accounting and a
declaratory judgment as to the rights of the parties under the joint venture
agreement. We were successful in enforcing the arbitration provision in the
joint venture agreement and entered into an agreement with Magness to submit the
matter for arbitration by the Judicial Arbitration Mediation Services, or
"JAMS," before the Honorable Keith J. Wisot, a retired Los Angeles Superior
Court Judge. Judge Wisot, as the arbitrator, ruled that the joint venture
agreement is a valid enforceable agreement, declined to dissolve the joint
venture, denied Magness' claims for breach of contract, and held that he and
JAMS would retain jurisdiction to enforce the award. On August 8, 2001, Magness
filed a demand with the American Arbitration Association, or "AAA," reasserting
its claims for dissolution of the joint venture and breach of contract. On
August 20, 2001, Warren filed a request to resume arbitration before Judge Wisot
and Magness filed an objection to such jurisdiction. On September 19, 2001,
Warren petitioned the Superior Court of California for Los Angeles County to
compel Magness to enter binding arbitration with Warren before Judge Wisot and
JAMS. On October 5, 2001, Magness cross-petitioned to compel Warren to enter
binding arbitration with Magness before AAA. On January 3, 2002, the Los Angeles
Superior Court granted Warren's petition, denied Magness' petition and ordered
Magness to discontinue its efforts to remove the controversy from the
jurisdiction of JAMS and to proceed forthwith to arbitration before Judge Wisot
of JAMS. Magness appealed this ruling by the Superior Court and on February 6,
2002, the Court of Appeal of the State of California stayed the January 3, 2002
order compelling arbitration before JAMS, pending a hearing on the lower court's
ruling. Accordingly, pending final resolution, further development of the
Wilmington Field will be curtailed.
27
In 1998, Pedco was sued in the 81st Judicial District Court of Frio County,
Texas by Stricker Drilling Company, Inc. and Manning Safety Systems to recover
the value of lost equipment based on a well blow out. Warren was later joined in
the suit as a defendant. As a result of the lawsuit, Gotham Insurance Company,
Pedco's well blow-out insurer, intervened. The suit was settled in 1999 with all
parties except Gotham. Gotham paid over $1.7 million under the insurance policy
and now seeks a refund of approximately $1.5 million of monies paid, denying
coverage, and alleging fraud and misrepresentation and a failure of Pedco to act
with due diligence and pursuant to safety regulations. Pedco countersued for the
remaining proceeds under the policy coverage. In the summer and fall of 2000,
summary judgments were entered for Pedco on essentially all claims except its
bad faith claims against Gotham. Gotham's claims against Pedco and Warren were
rejected. Final judgment was rendered on May 14, 2001 in Pedco's favor for the
remaining policy proceeds, interest and attorney fees. Gotham has appealed the
final judgment. Pedco is defending the judgment on appeal although seeking to
reverse the ruling denying its bad faith claim. The case on appeal is set for
oral argument on March 28, 2002.
In December 1999, the family of Robert Sanchez, an employee of Pinnacle,
brought a wrongful death action against Pinnacle and Wilson Supply Company in
the 93rd Judicial District Court of Hidalgo County, Texas alleging negligence
and gross negligence. The lawsuit claims Robert Sanchez was injured in April of
1999 while working on a crew drilling a well in Wilson County, Texas. He later
died, allegedly as a result of the injuries he received. The well operator,
Pedeco Inc., a wholly owned subsidiary of Pedco, was added as a defendant in May
2001. While the amount of claimed damages in the plaintiffs' petition is
unspecific, it appears that the plaintiffs are claiming economic damages of
approximately $1.0 million for lost wages, lost household services and medical
expenses of the decedent. Pinnacle and Pedeco are being defended by insurance
defense counsel. Mediation of the case occurred on September 6, 2001. As a
result of mediation and settlement discussions, Pinnacle and Pedeco settled
their portions of the final settlement amount for sums within the scope of
applicable insurance coverage.
We are also a party to legal actions arising in the ordinary course of our
business. In the opinion of our management, based in part on consultation with
legal counsel, the liability, if any, under these claims is either adequately
covered by insurance or would not have a material adverse effect on us.
Item 4: Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of security holders during the fourth
quarter of the fiscal year 2001.
PART II
Item 5: Market for the Registrant's Common Equity and Related Stockholder
Matters
No Public Market -- Shares Eligible For Future Sale
There is no public market for our common stock. Future sales of substantial
amounts of common stock in any public trading market which develops could
adversely affect the market price of our common stock. As of April 10, 2002,
17,537,579 shares of common stock were issued and outstanding. Pursuant to Rule
144 under the Securities Act, commencing on March 26, 2002, which is 90 days
following the effectiveness of our Form 10 registration statement, approximately
9,666,547 shares of our common stock became freely tradeable in accordance with
Rule 144 and approximately 7,871,032 shares, including 6,045,949 shares owned by
affiliates, may be sold in accordance with the volume limitation imposed by Rule
144.
28
As of April 10, 2002, 2,995,613 shares of our common stock are issuable
upon the exercise of options granted or to be granted under our various stock
option plans. See "Item 11- "Executive Compensation-Employee Benefit Plans" and
note D to our consolidated financial statements. As of that same date, 6,247,439
shares of common stock were issuable upon the conversion of our convertible
debt.
Registration Rights
As of December 31, 2001, holders of approximately 3,493,571 shares of our
common stock issued pursuant to the exercise of our Class A, B, C and D warrants
and 6,216,022 shares of our common stock issuable upon conversion of existing
convertible debt are eligible to sell such shares under Rule 144. A substantial
number of such shares may have rights, subject to some conditions including the
consent of any underwriter, to include their shares in registration statements
that we may file, if any, to register shares of our common stock under the
Securities Act for ourselves or other shareholders.
Holders
As of April 10, 2002, there were approximately 3,500 holders of our common
stock.
Dividend Policy
We have never paid or declared any cash dividends on our common stock. We
currently intend to retain earnings, if any, to finance the growth and
development of our business and we do not expect to pay any cash dividends on
our common stock in the foreseeable future. Payment of future cash dividends, if
any, will be at the discretion of our board of directors after taking into
account various factors, including our financial condition, operating results,
current and anticipated cash needs and plans for expansion
Item 6: Selected Consolidated Financial Data
The following tables present selected financial and operating data for
Warren and its subsidiaries as of and for the periods indicated. You should read
the following selected data along with "Item 7-Management's Discussion and
Analysis of Financial Condition and Results of Operations," our financial
statements and the related notes and other information included in this
registration statement. The selected financial data as of December 31, 1997,
1998, 1999, 2000 and 2001 has been derived from our financial statements, which
were audited by Grant Thornton LLP, independent auditors, and were prepared in
accordance with generally accepted accounting principles in the United States.
The historical results presented below are not necessarily indicative of the
results to be expected for any future period.
29
Year ended December 31,
-----------------------------------------------------------------
1997 1998 1999 2000 2001
---------- ---------- ----------- ----------- -----------
(Amounts in thousands, except share information)
Consolidated Statement of Operations Data:
Revenues:
Turnkey contracts $28,198 $ 24,161 $ 25,406 $ 33,985 $ 30,103
Oil & gas sales from marketing activities - - - 15,421 14,867
Well Services - - 2,611 4,297 5,574
Oil & gas sales 90 63 68 200 948
---------- ---------- ----------- ----------- -----------
Total operating revenues 28,288 24,224 28,085 53,903 51,492
Costs and operating expenses:
Turnkey contracts 22,220 20,340 18,126 22,783 25,953
Cost of oil and gas marketing activities (1) - - - 15,800 15,299
Well services - - 1,351 3,168 3,519
Production and exploration 1,875 37 43 355 568
Depreciation, depletion and 14,462
Amortization 7,950 8,149 9,197 3,065
Remarketing Obligation 3,319
General and administrative 4,083 3,931 4,491 6,416 5,485
---------- ---------- ----------- ----------- -----------
Total operating expenses 36,128 32,457 33,208 51,587 68,605
---------- ---------- ----------- ----------- -----------
---------- ---------- ----------- ----------- -----------
Income (loss) from operations (7,840) (8,233) (5,123) 2,316 (17,113)
Other income (expense):
Interest and other income 1,890 2,439 1,641 2,457 1,977
Interest expense (3,277) (4,673) (5,791) (6,968) (5,776)
Net gain (loss) on investment - 5,489 (1,104) 587 (10)
---------- ---------- ----------- ----------- -----------
Income (loss) before income taxes and (20,922)
extraordinary item (9,227) (4,978) (10,377) (1,608)
Income tax expense (credit) (395) 591 702 (412) 152
---------- ---------- ----------- ----------- -----------
Income (loss) before extraordinary item (8,832) (5,569) (11,079) (1,196) (21,074)
Change in accounting principle for deferred
Organizational costs (1,250) - - - -
---------- ---------- ----------- ----------- -----------
Net income (loss) $ (10,082) $ (5,569) $ (11,079) $ (1,196) $ (21,074)
========== ========== =========== =========== ===========
Weighted average number of common shares
Outstanding:
Basic and diluted 7,386,195 9,106,998 11,115,522 12,461,814 17,532,882
Net income (loss) per common share:
Basic and diluted $ (1.36) $ (0.61) $ (1.00) $ (0.10) $ (1.20)
Consolidated Statement of Cash Flows Data:
Net cash provided by (used in):
Operating Activities $ 2,081 $ (155) $ 16,502 $ 10,659 $ (15,712)
Investing Activities (15,912) 5,626 (21,540) (19,012) (17,635)
Financing Activities 12,587 12,611 16,726 26,701 (2,700)
Year ended December 31,
---------------------------------------------------------------
1997 1998 1999 2000 2001
------- ------- ------- -------- ---------
Balance Sheet Data:
Cash and cash
equivalents $10,543 $28,934 $40,622 $ 58,970 $ 22,924
Total assets 60,458 60,458 82,144 128,649 94,900
Total long-term debt 33,657 38,311 56,306 60,447 58,561
Shareholders' equity (deficit) (5,970) (3,784) (14,618) 14,876 (6,434)
Item 7: Management's Discussion and Analysis of Financial Condition and Results
of Operations
You should read the following discussion and analysis together with our
financial statements and accompanying notes appearing elsewhere in this
registration statement. The following information contains forward-looking
statements. See "Forward-Looking Statements." Actual results may differ
materially from those anticipated due to many factors, including those set forth
under "Risk Factors" below.
30
Critical Accounting Policies
Oil and Gas Producing Activities
We use the successful efforts method of accounting for our investments in
natural gas and oil properties. Under this method, we capitalize lease
acquisition costs and intangible drilling and development costs on successful
exploratory wells and all development wells. Wells are depleted on a field by
field basis and are evaluated on a field by field basis for impairment. We have
substantially subordinated to investors all of our joint venture and general
partner's rights to production for wells syndicated to our drilling programs
formed during or prior to 1998.
We review our natural gas and oil properties on a field level for
impairment when circumstances indicate that the capitalized costs less
accumulated depreciation, depletion and amortization or the "carrying value," of
the property may not be recoverable. If the carrying value of the property
exceeds the expected future undiscounted cash flows, an amount equal to the
excess of the carrying value over the fair value of the property (generally
based upon discounted cash flow) is charged to expense. An impairment results in
a non-cash charge to earnings but does not affect cash flows.
Our oil and gas producing activities are dependent upon the price of
natural gas and oil. Declines in the price of natural gas and oil may result in
write downs of our oil and gas properties and a related impairment expense.
Additionally, price declines of natural gas and oil could result in our wells
becoming uneconomical to operate. As a result, we may be required to expend
funds for plugging and abandoning wells which are deemed to be uneconomical.
Lastly, price declines may result in delays developing our proved undeveloped
reserves. A significant portion of our proved reserves has not been developed.
As a result, price declines may render drilling projects uneconomical to
develop.
Turnkey Contract Activities
We provide turnkey contract drilling services to affiliated drilling
programs whereby the investors pay intangible development costs and we pay lease
acquisition and completion costs, including lease and well equipment. We record
revenue from turnkey drilling contracts on the percentage of completion method
based on total costs incurred to total estimated costs to complete. We contract
to drill wells on behalf of drilling programs for a fixed price based on our
estimate of cost we will incur for the well given the location, depth, formation
characteristics and type of drilling (vertical, directional or horizontal). We
subsequently enter into third party contracts to drill the well at current
market rates. Since the drilling contract is on a day work or "per day" basis,
the longer the drilling rig is on the well, the higher our costs are in the
well. If problems are encountered during drilling which require more effort from
our third party subcontractors our gross profits will be reduced on the well. If
substantial problems occur such as the loss of the hole, lost equipment downhole
or a blow out, we may incur a loss on the well. Our estimates of cost to
complete wells drive our revenue recognition under percentage of completion. We
may recognize profits on wells in progress in a period, but if we underestimate
the cost to complete the wells we may recognize losses on the wells in a
subsequent period.
At December 31, 2001, we had estimated remaining cash contractual drilling
commitments under the turnkey drilling contracts with the drilling programs
formed in 1999 and 2000, of $3.3 million and $11.9 million, respectively, for
some wells that were timely commenced in early 2000 and 2001, but were not yet
completed due to a number of unforeseen factors even though we are continuing to
proceed with reasonable diligence. Under the turnkey drilling contracts, we had
received full cash payment from the drilling programs in 1999 and 2000 for all
of the wells to be drilled on behalf of the 1999 and 2000 drilling programs. In
the course of drilling the wells already completed on behalf of the 1999
program, drilling cost overruns were incurred such that the stated total
drilling costs to be incurred by the 1999 drilling program have already been
expended on the drilling program's behalf.
31
During 2001, we raised $18.1 million in new drilling programs. This amount
compares to $46.5 million and $40.9 million raised for our drilling programs
during 2000 and 1999, respectively. We believe there were a number of factors
affecting us in 2001 that caused us to raise fewer drilling funds in 2001
compared to the prior years. Foremost, our 2000 and prior drilling programs
performed more poorly in 2001 compared to prior years, largely as a result of
the decrease in cash distributions to drilling program investors because of
significant decreases in energy prices during 2001 compared to 2000.
Additionally, regulatory delays related to various permits to complete the
development of our coalbed methane (CBM) reserves in the Washakie Basin and the
pending litigation relating to our interest in the Wilmington field in
California reduced potential cash distributions. We believe the factors that
caused such energy price declines and production delays in 2001 were many,
including without limitation: the year began with a nationwide natural gas
shortage accompanied by historically high gas prices in January 2001, which
created an immediate increase in drilling and supply response by natural gas
producers, and by year-end 2001 delivered gas prices had substantially declined;
the onset of a nationwide economic recession with a loss of consumer confidence,
that further reduced demand for oil and gas; an unseasonably cool summer
followed by an unusually mild winter for most of the country (especially the
highly populated northeast) which reduced retail demand for gas; the tragic
events of September 11th and their impact on the general industrial and consumer
markets for oil and gas; the legal wrangling throughout 2001 with our joint
venture partner Magness Petroleum Company over developing the reserves in the
Wilmington field in California; and the bureaucratic delays throughout 2001 by
the U.S. Bureau of Land Management based in Rawlins, Wyoming involving the
environmental approval processes covering drilling, gathering, rights of way,
water disposal, surface disturbances, air quality and wildlife stipulations that
were necessary for us to commence CBM gas production in the Washakie Basin in
Wyoming.
As we drill the wells for our drilling programs, we recognize turnkey
revenue under the percentage of completion method. As a result of raising fewer
funds from our drilling programs during 2001 when compared to 2000 and 1999, we
expect turnkey revenue and aggregate gross profit to decrease during 2002 when
compared to 2001 and 2000.
We were paid the total turnkey drilling contract price for the 1999
programs in 1999 and the 2000 programs in 2000, commenced drilling within 90
days after the end of the applicable preceding tax year for each of respective
programs, and have proceeded with reasonable diligence since that date to drill
and complete the wells. Since in 2000 and 2001 we have expended as the turnkey
contractor for the benefit of the 1999 programs an amount greater than the total
turnkey contract price less the permitted profit margin earned by us for such
programs, although we have more wells to complete, we believe that we are in
compliance with the turnkey contract. Further, at March 31, 2002, although we
have remaining obligations for the 2000 programs, we believe that we are in
compliance with the turnkey contract.
Repurchase Agreements
Under certain repurchase agreements, the investors in certain drilling
programs have a right to have their interests purchased by a repurchase agent or
us. We unconditionally guarantee the repurchase agent's performance. The
purchase price is calculated at a formula price and is payable from seven to 25
years from the date of admission to the drilling program. We determine the
amount of the repurchase liability by computing the present value of the excess
of the formula price over the estimated discounted present value of future net
revenues of proved developed and undeveloped reserves of each drilling program
net of future capital costs and our working interests. A portion of some
drilling program properties are proved undeveloped leases which must be drilled
by us using funds from an outside party or from us to provide cash flow to the
drilling programs which satisfy the repurchase obligation. We have estimated
that those undeveloped leases will require approximately $26,800,000 of
development expenditures in 2002, 2003 and 2004 to complete these wells.
32
The determination of whether a repurchase liability exists is based upon
estimates of future net cash flows from reserve studies prepared by petroleum
engineers. These reserve studies are inherently imprecise and will change as
future information becomes available. Decreases in prices received for oil and
gas produced by drilling programs results in smaller cash distributions to
investors and payout may not occur before the future date at which the investors
have a right to require repurchase of their interests. Under the formula for
repurchase in 1997 and earlier drilling programs, low oil and gas prices at the
future date may result in us being required to repurchase investor interests at
prices greater than fair value. An expense recognition would therefore be
necessary.
If oil and gas prices decrease we may determine that proved undeveloped
leases in drilling programs are not economical to drill and develop. As a
result, cash flow from these leases will not be distributed to investors and
payout may be delayed. If payout has not occurred in these drilling programs
before the date investors can require repurchase of their interests, we may be
required to purchase interests containing proved undeveloped leases based on a
petroleum engineer's estimate of the present value of net cash flow. The price
paid may be in excess of the fair value of the interest resulting in a charge to
expense. At December 31, 2000 and 2001, the face amounts of U.S. treasury bonds
securing such repurchase agreements were $5.7 million and $4.6 million,
respectively, and the market value was $2.0 million and $1.6 million,
respectively.
Liquidity and Capital Resources
We have funded our activities primarily with the proceeds raised through
privately placed drilling programs and our private sale of our equity and debt
securities. These private placements primarily were made through a network of
independent broker dealers. Since 1992, we have raised approximately $217
million through the private placements of interests in 29 drilling programs.
Additionally, we have raised $58.7 million through the issuance of our debt
securities and $52.2 million through the issuance of our equity securities. In
our drilling programs, we fund the costs associated with acreage acquisition and
the tangible portion of drilling activities, while investors in the drilling
programs fund all intangible drilling costs.
Cumulatively, a total of $105.6 million has been raised during fiscal years
2001, 2000 and 1999 through the private placements of interests in our drilling
programs. For the fiscal year ended December 31, 2001, we have not privately
placed any of our debt or equity securities. Cumulatively, we raised
approximately $32.3 million in 2000 and 1999 through the private placement of
our debt securities and $15.3 million in 2000 and 1999 primarily related to the
exercise of warrants for our common stock.
Our most material commitment of funds relates to the drilling programs. Our
deferred revenue balance relating to our drilling commitments totaled $32.9
million at December 31, 2001. This commitment varies pro rata with the amount of
funds raised through our drilling funds.
We are obligated to make equal annual deposits to a bond sinking fund for
certain debentures. These deposits include U.S. treasury bonds with maturity
dates prior to the maturity date of the related debenture. The estimated annual
sinking fund requirements disclosed below are calculated using U.S. treasury
bond pricing as of December 31, 2001. The holders of debentures may annually ask
us to redeem up to 10% of the original amount we issued. The following tables
present our contractual obligations due by period and other commitments by
period.
33
The contractual obligations table below assumes the maximum amount is
tendered each year, net of the effects of the sinking fund requirements. The
table does not give effect to the conversion of any bonds to stock which would
reduce payments due.
Payments due by period
Contractual Obligations Less Than 1-3 4-5 After
as of December 31, 2001 Total 1 Year Years Years 5 Years
Debentures - net of Sinking Fund
Requirements $24,085,330 $ 1,527,018 $ 4,491,174 $ 3,615,026 $14,452,112
Debenture Sinking Fund Requirements 34,053,370 3,220,352 7,031,566 7,907,714 15,893,738
Other long-term debt 421,912 392,721 29,191 - -
Leases 1,073,693 229,677 338,036 311,372 194,608
----------- ----------- ----------- ----------- -----------
Total $59,634,305 $ 5,369,768 $11,889,967 $11,834,112 $30,540,458
----------- ----------- ----------- ----------- -----------
For partnerships formed before 1998, the repurchase price is computed as
the original capital contribution of the investor reduced by the greater of (1)
cash distributions we made to the investor, or (2) 10% for every $1.00 which the
oil price at the repurchase date is below $13.00 per barrel adjusted by the
consumer price index changes since the programs formation. For programs formed
1998 and later, the repurchase price cannot exceed the present value of the
program's proved reserves. If we purchase interests in drilling programs, we
receive the pro rata share of the reserves and related future net cash flows.
The table below presents the repurchase commitment associated with 20 drilling
programs, giving no effect to any reserve value that is acquired in repurchase.
Amount of repurchase commitment per period
Other Commitments Less Than 1-3 4-5 After
as of December 31, 2001 Total 1 Year Years Years 5 Years
Partnership repurchase commitments
Pre-1998 partnerships without present $ 48,502,432 $ 1,033,145 $ 44,191,538 $ - $ 3,277,749
Value limit
1998 and later partnerships with present
value limit 101,966,839 - - 46,988,321 54,978,518
------------ ----------- ------------ ------------ -----------
Total $150,469,271 $ 1,033,145 $ 44,191,538 $ 46,988,321 $58,256,267
------------ ----------- ------------ ------------ ------------
During the year ended December 31, 2001, our liquidity decreased from
working capital of $10.3 million at December 31, 2000 to a working capital
deficit of $8.9 million at December 31, 2001. This decrease substantially
resulted from $16.9 million we expended for acquisition, exploration and
development of our oil and gas properties. The major portion that we spent was
for our Powder River and Washakie Basin projects and our interest in east Texas
(James Lime and Cotton Valley formations), from which we have received only
limited oil and gas revenue. We also incurred $2.7 million to third parties in
conjunction with a potential public offering, with $0.8 million of deferred
expenses to be deducted from offering proceeds. We expect to file a registration
statement to commence our initial public offering after the completion of the
SEC's review of our Form 10 filing. Finally, we underestimated costs on certain
east Texas turnkey wells we drilled for programs which were in progress at
December 31, 2000. The additional costs resulted in additional expenditures of
$6.8 million.
34
Management Plans for 2002
The Company has incurred a net loss of approximately $21,100,000 during
2001. At December 31, 2001, current liabilities exceeded current assets by
approximately $8,800,000 and total liabilities exceeded total assets by
approximately $6,400,000.
The 2001 net loss includes approximately $15,200,000 of non-cash charges
including oil and gas properties and drilling rig impairments and recognition of
a liability related to the Company's contingent obligation to purchase
partnership interests. The oil and gas impairment and contingent repurchase
obligation were measured using March 15, 2002 oil and gas prices, which were
significantly below prior year prices. During 2001, the Company raised $18.1
million for its drilling programs compared to $46.5 million and $40.9 million in
2000 and 1999, respectively. As a result, the Company's turnkey revenue and
total gross profit in 2002 will be less than in 2001 and 2000 and the number of
the Company's oil and gas properties developed through partnership arrangements
will be reduced.
In order to improve operations and liquidity and meet its cash flow needs,
we have or intend to do the following:
o Sold CJS Pinnacle Petroleum Services, LLC, the Company's
work-over drilling rig subsidiary for $4.2 million in February
2002 (see Notes C and R).
o Sell interests in some of our undeveloped oil and gas leases. The
Company is currently in extended negotiations for several sales
of a portion of its oil and gas interests which it is anticipated
will be closed in 2002. Although there are no definitive
agreements, the Company has received offers to buy certain of its
undeveloped oil and gas leases that have significantly
appreciated when compared to their original cost.
o Raise additional capital through the sale of preferred stock and
common stock.
o Obtain a credit facility based in part on the value of our proven
reserves.
o Continue our privately placed drilling programs, which based on
prior experience management anticipates raising approximately $30
million in 2002.
o Generate turnkey profit and operating cash flow from our turnkey
drilling contracts equal to approximately 25% of the total amount
of turnkey price.
o Reduce fixed overhead expenses and primarily conduct development
drilling operations in the Company's two main target areas,
coalbed methane properties in Wyoming and oil formations in the
Wilmington field in California.
As a result of these plans, management believes that it will generate
sufficient cash flows to meet its current obligations in 2002.
Results of Operations
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Turnkey contract revenue and expenses. Turnkey contract revenue decreased
$3.9 million in 2001 to $30.1 million, an 11% decrease compared to levels during
2000. The decrease in turnkey revenue resulted from an increase in the estimated
costs totaling $6.8 million to complete our drilling obligation relating to the
2000 and 1999 drilling programs. Additionally, turnkey contract expense
increased $3.2 million during 2001 to $26 million, a 14% increase compared to
2000. This increase resulted from an increase in drilling and completion
activities on behalf of the drilling programs during 2001 compared to 2000. The
level of drilling activity is affected by the amount of funds raised from our
drilling programs in the prior fiscal year. We raised $46.5 million from our
drilling programs during 2000 compared to $40.9 million during 1999.
35
Gross profit from turnkey contract revenue and expenses was $4.1 million or
14% in 2001. This compared to gross profit of $11.2 million or 33% in 2000. The
decrease in gross profit percentage during 2001 resulted from an increase in the
estimated costs totaling $6.8 million to complete our drilling obligation
relating to the 2000 and 1999 drilling programs.
Natural gas and oil sales and costs from marketing activities. Natural gas
and oil sales from marketing activities decreased $0.6 million in 2001 to $14.9
million, a 4% decrease compared to 2000. Cost of oil and gas marketing
activities decreased $0.5 million in 2001 to $15.3 million, a 3% decrease
compared to 2000. These decreases resulted from a decrease in the average prices
of natural gas and oil during 2001 compared to 2000. The average price of
natural gas and oil marketed and sold during 2001 was $2.29 and $15.49,
respectively. This compared to the average price of natural gas and oil marketed
and sold during 2000 of $2.57 and $23.70, respectively. This decrease was offset
by an increase in natural gas and oil related to our drilling programs being
purchased by us at the wellhead and subsequently marketed and sold. Natural gas
and oil production allocated to drilling programs totaled 5.1 Bcfe in 2001
compared to 4.1 Bcfe in 2000.
The gross profit (loss) from marketing activities for 2001 was a $0.4
million loss as well as for 2000. Both losses resulted from a hedging
transaction, which expired on March 31, 2001. The total hedging loss incurred by
Warren was $0.5 million from January 2001 to March 2001 compared to a hedging
loss of $1.6 million for 2000.
Well services activities. Well services revenue increased $1.3 million in
2001 to $5.6 million, a 30% increase compared to 2000. Well services expense
increased $0.4 million in 2001 to $3.5 million, an 11% increase compared to
2000. The increase in well services revenue results from drilling supervision
revenue of $0.9 million during 2001 compared to $0.3 million during 2000.
Additionally, the increases in revenue and expenses resulted from increases in
drilling rig day rates and increased rig utilization during 2001 compared to
2000.
Gross profit from well services activities was $2.1 million or 37% in 2001.
This compared to gross profit of $1.1 million or 26% in 2000. This increase in
gross profit percentage during 2001 resulted from drilling and supervision fees
of $0.9 million during 2001 compared to $0.3 during 2000. Also, increases in
productivity resulted from increases in drilling rig day rates and increased rig
utilization during 2001 compared to 2000. Additionally, $1.0 million of well
services depreciation expense is included in depreciation, depletion and
amortization for 2001 and 2000.
Natural gas and oil sales and production and exploration expenses. We have
interests in natural gas and oil production attributable to our drilling
programs. Through and prior to June 30, 2001, virtually all of our production
was subordinated to our investors in the drilling programs. Beginning in the
third quarter of 2001, we received an additional $0.3 million in natural gas and
oil revenue from our interests in production from certain wells in drilling
programs formed during 1999 and 2000. Our share of pre-payout production from
these programs is generally 25% of the production allocated to these drilling
programs.
Interest and other income. Interest income decreased $0.5 million in 2001
to $2.0 million, a 20% decrease compared to 2000. Primarily, the decrease is
attributable to lower interest rates during 2001 than in 2000.
Net gain (loss) on investments. Net loss on investments was $10 thousand
for 2001. Net gain on investments was $0.6 million for 2000. Originally, Warren
obtained U.S. treasury bonds, which typically represented less than 1% of
Warren's total current assets, to assure the financial capability to repurchase
partnership units under the partnership agreements and fund the repayment of
outstanding debentures. This obligation was eliminated for the majority of
partnership units and debenture holders in 1998. As a result, these escrowed
U.S. treasury bonds were released for Warren's unrestricted use and liquidated
shortly thereafter.
36
Primarily, investments represent zero coupon U.S. treasury bonds held in
our inventory. Fluctuations in net gain or loss on investments resulted from
changes in long term interest rates.
General and administrative expenses. General and administrative expenses
decreased $0.9 million in 2001 to $5.5 million, a 15% decrease compared to 2000.
Primarily, this decrease resulted from a decrease in certain pre and post
production expenses paid by us for the benefit of the drilling programs.
Predominantly, these pre-production expenses represent lease operating expenses
incurred prior to the commencement of production. Post production expenses
represent repairs to equipment during the first 12 months of production.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased $11.4 million in 2001 to $14.5 million, a 372%
increase compared to 2000. This increase resulted from depletion and impairment
expense of $12.8 million during 2001 compared to $2.3 during 2000. The
significant increase in depletion and impairment expense resulted from a
significant decrease in energy prices at December 31, 2001 compared to December
31, 2000. Additionally, we recorded a $0.6 million of impairment expense related
to the fixed assets of Pinnacle. Lastly, depreciation and depletion related to
the Pedco acquisition increased $0.3 million during 2001 compared to 2000. We
acquired Pedco on September 1, 2000.
Interest expense. Interest expense decreased $1.2 million in 2001 to $5.8
million, a 17% decrease compared to 2000. Primarily, the decrease is
attributable to an increase in capitalized interest during 2001 compared to
2000. We recorded $2.3 million of capitalized interest during 2001 compared to
$1.3 million during 2000. Primarily, capitalized interest relates to our
development project in the Washakie Basin.
Warren financed the acquisition of $6.9 million and $11.6 million of oil
and gas properties during 2001 and 2000, respectively. Warren had approximately
$54 million in debentures outstanding at December 31, 1999. During 2000, Warren
issued approximately $15 million of additional debentures and converted
approximately $10 million of debentures into common shares, resulting in an
outstanding debenture balance of approximately $59 million at December 31, 2000.
During 2001, Warren redeemed approximately $0.9 million in debentures resulting
in an outstanding balance of $58.1 million at December 31, 2001.
Remarketing Obligation. Remarketing obligation expense of $3.3 million was
recorded in 2001 based on pricing at March 15, 2002. No remarketing expense was
recorded in 2000. As stated above, the determination of whether a repurchase
liability exists is based upon estimates of future net cash flows from reserve
studies prepared by petroleum engineers compared to the potential repurchase of
drilling program units. Significant decreases in natural gas and oil prices at
December 31, 2001 lowered the estimated future cash flows when compared to
future potential repurchase obligations. As a result, a remarketing liability
and a remarketing obligation expense of $3.3 million was recorded in 2001.
Year Ended December 31, 2000 Compared to Year Ended December 31, 1999
Turnkey contract activities. Turnkey contract revenue increased $8.6
million in 2000 to $34.0 million, a 34% increase compared to such revenues in
1999. Additionally, turnkey contract expense increased $4.7 million in 2000 to
$22.8 million, a 26% increase compared to the level of such costs in 1999. These
increases resulted from an increase in drilling and completion activities on
behalf of the drilling programs during 2000 compared to 1999. The level of
drilling activity is affected by the amount of funds raised from our drilling
programs in the prior periods. We raised $40.9 million from drilling programs
during 1999, compared to $20.6 million raised during 1998.
37
Gross profit from turnkey contract revenue and expense was $11.1 million,
or 33%. This compared to gross profit of $7.3 million, or 29%. The increase in
percentage gross profit in 2000 resulted from turnkey revenue related to two
drilling programs with no gross profit limitation. The gross profit we earned
relating to these two drilling programs was $3.3 million, or 51.7%.
Natural gas and oil sales and costs from marketing activities. Natural gas
and oil sales from marketing activities did not commence until January 1, 2000.
There were no such sales during 1999. The gross profit from marketing activities
for the year ended December 31, 2000, was a $0.4 million loss, due primarily to
a hedging loss of $1.6 million.
Well services activities. Well services revenue increased by $1.7 million
in 2000 to $4.3 million, a 65% increase compared to 1999. Well services expense
increased $1.8 million in 2000 to $3.2 million, a 134% increase compared to
1999. This increase resulted from a significant change in the customer base.
During 2000, our drilling subsidiary customer base was 95% unaffiliated third
parties and 5% affiliated drilling programs. During 1999, the customer base was
51% unaffiliated third parties and 49% affiliated drilling programs. As a
result, well services revenue and expense related to affiliated drilling
programs was eliminated through consolidation entries.
Interest and other income. Interest income increased $0.8 million in 2000
to $2.5 million, a 50% increase compared to such income in 1999. Primarily, the
increase is attributable to a higher average cash and cash equivalent balance
during 2000 than in 1999.
Net gain (loss) on investments. Net gain on investments was $0.6 million
for 2000. Net loss on investments was $1.1 million for 1999. Primarily,
investments represent zero coupon U.S. treasury bonds held in our inventory.
Primarily, fluctuations in net gain or loss on investments result from changes
in interest rates.
General and Administrative. General and administrative expenses increased
$1.9 million in 2000 to $6.4 million, a 43% increase compared to 1999.
Primarily, this increase resulted from an increase in certain pre-production and
post-production expenses paid by us for the benefit of our drilling programs.
Such expenses were $3.6 million and $2.1 million in 2000 and 1999, respectively.
Additionally, this increase resulted from increased commissions of $0.7 million
paid to broker dealers selling a higher amount of drilling programs and
debentures during 2000 as compared to amounts sold in 1999. Additionally, Pedco
was acquired on September 1, 2000, with general and administrative expenses
relating to Pedco totaling $0.2 million during 2000.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense decreased $6.1 million in 2000 to $3.1 million, a 67%
decrease compared to 1999. Primarily, depreciation, depletion and amortization
was lower in 2000 due to impairment expense totaling $7.8 million during 1999
compared to $1.9 million during 2000.
Interest expense. Interest expense increased $1.2 million in 2000 to $7.0
million, a 20% increase compared to 1999. Additionally, we recorded $1.3 million
of capitalized interest during 2000 and no capitalized interest in 1999.
Primarily, the increase is attributable to a higher average debenture balance
during 2000 compared to 1999. The average debenture balance was $56.6 million
during 2000 compared to $41.7 million during 1999. Additionally, interest
expense related to escrowed cash in drilling programs increased during 2000
compared to 1999. We raised $46.5 million from our drilling programs during 2000
compared to $40.9 million raised in 1999.
Year Ended December 31, 1999 Compared to Year Ended December 31, 1998
Turnkey contract activities. Turnkey contract revenue increased by $1.2
million in 1999 to $25.4 million, a 5% increase compared to the level of such
revenue in 1998. Turnkey contract expense decreased $2.2 million in 1999 to
$18.1 million, an 11% decrease compared to such costs in 1998. These nominal
fluctuations resulted from relatively flat drilling and completion activities on
behalf of our drilling programs when comparing the level of 1999 activities to
1998 activities. Gross profit from turnkey contract revenue and expense was $7.3
million or 29% in 1999. This compares to gross profit of $3.8 million or 16% in
1998. The increase in gross profit percentage during 1999 resulted from $3.2
million of intangible drilling costs recorded in 1998 that did not reduce our
turnkey obligation. This resulted from a change in estimated costs to complete
certain wells. As a result, no turnkey revenue was recognized relating to these
turnkey expenses.
38
Well services revenue. The acquisition of a controlling interest in our
well services company did not occur until January 1, 1999.
Interest and other income. Interest income decreased by $0.8 million in
1999 to $1.6 million, a 33% decrease compared to levels in 1998. Primarily, the
decrease is attributable to a lower average balance of investments in U.S.
treasury bonds-available for sale during 1999 compared to 1998. The average
balance of U.S. treasury bonds-available for sale was $8.7 million during 1999
compared to $17.5 million during 1998. The significant decrease in the average
balance of U.S. treasury bonds-available for sale resulted from the release to
us during December 1998 of U.S. treasury bonds from escrowed accounts by our
drilling programs and debenture holders.
Net gain (loss) on investments. Net loss on investments was $1.1 million
for 1999. Net gain on investments was $5.5 million for 1998. Primarily,
investments represent zero coupon U.S. treasury bonds held in our inventory. The
significant gain recorded in 1998 resulted from the release to us during
December 1998 of $76.6 million face amount of U.S. treasury bonds-available for
sale with a fair market value of $29.1 million. During December 1998, these U.S.
treasury bonds were released from an escrowed account for the drilling programs
and debenture holders. This transaction resulted in a $4.7 million realized and
unrealized gain on investments in December 1998.
General and Administrative. General and administrative expenses increased
$0.6 million in 1999 to $4.5 million, a 14% increase compared to levels in 1998.
Primarily, this resulted from an increase in certain pre and post-production
expenses paid by us for the benefit of our drilling programs. Such expenses were
$2.1 million and $1.1 million in 1999 and 1998, respectively. This increase was
offset by a decrease in commissions and exchange offer expenses. Such expenses
were $1.2 million paid to broker dealers in 1999 compared to $1.6 million in
1998.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased $1.0 million in 1999 to $9.2 million, a 13%
increase compared to 1998. This increase resulted from increases in depletion of
oil and gas properties of $0.5 million and from depreciation of $0.5 million
relating to our drilling subsidiary which was acquired during 1999. The majority
of the balance represented impairment expense totaling $7.8 million in 1999 and
1998.
Interest expense. Interest expense increased by $1.1 million in 1999 to
$5.8 million, a 24% increase compared to 1998. Primarily, this increase is
attributable to a higher average debenture balance during 1999 as compared to
the balance in 1998. The average debenture balance was $45.8 million during 1999
compared to $35.5 million during 1998.
Item 7A: Quantitative and Qualitative Disclosures About Market Risk
Commodity Risk. Our major market risk exposure is the commodity pricing
applicable to our natural gas and oil production. Realized commodity prices
received for our production are primarily driven by the prevailing worldwide
price for crude oil and spot prices applicable to natural gas. The effects of
price volatility are discussed in the above "Risk Factors" and volatility is
expected to continue. Below is a description of the financial instruments we
have used to reduce our exposure to commodity price risk. Since March 31, 2001,
we have not employed any commodity hedges, derivatives or embedded derivatives,
although we may do so in the future.
During periods through March 31, 2001, we entered into participating
collars to hedge natural gas production through March 31, 2001. Below is a
summary of the collar arrangements from May 1, 2000 to March 31, 2001. The
participating collars were designated as hedges, and realized losses were
recognized in marketing revenues when the associated production occurred.
We hedged approximately 180,000 Mcf per month for eleven months with a
floor price of $2.50 per Mcf and a ceiling price of $3.55 per Mcf. These
participating collars closed with our recording a loss of approximately $2.1
million or $1.21 per Mcf produced for the eleven months referred to above.
39
Our adoption of SFAS No. 133, as amended, is discussed in Note A to our
consolidated financial statements.
Interest Rate Risk. Warren holds investments in U.S. treasury
bonds-available for sale, which represent securities held in escrow accounts on
behalf of the drilling programs and purchasers of certain debentures.
Additionally, Warren holds U.S. treasury bonds-trading securities, which
predominantly represent U.S. treasury bonds released from escrow accounts. The
fair market value of these securities will generally increase if the federal
discount rate decreases and decrease if the federal discount rate increases. All
of our convertible debt has fixed interest rates, so consequently we are not
exposed to cash flow or fair value risk from market interest rate changes on
this debt.
Financial Instruments & Debt Maturities. Our financial instruments consist
of cash and cash equivalents, U.S. treasury bonds, accounts receivable, hedging
contracts and other long term liabilities. The carrying amounts of cash and cash
equivalents, U.S. treasury bonds, accounts receivables and accounts payable
approximate fair value due to the highly liquid nature of these short-term
instruments. The fair value of our convertible debt approximates face value.
Inflation and Changes in Prices
The general level of inflation affects our costs. Salaries and other
general and administrative expenses are impacted by inflationary trends and the
supply and demand of qualified professionals and professional services.
Inflation and price fluctuations affect the costs associated with exploring for
and producing natural gas and oil, which have a material impact on our financial
performance.
Income Taxes
We follow the provisions of SFAS No. 109, "Accounting for Income Taxes,"
which provides for recognition of a deferred tax liability or asset for
deductible temporary timing differences, operating loss carryforwards, statutory
depletion carryforwards and tax credit carryforwards net of a valuation
allowance. The temporary differences consist primarily of depreciation,
depletion, and amortization of intangible drilling costs and our investment
basis in oil and gas partnerships.
As of December 31, 2001, we had a net operating loss carryforward of
approximately $38 million and no alternative minimum tax credit carry forward.
Our net operating loss carryforwards expire in 2012 and subsequent years.
RISK FACTORS
You should carefully consider the risks described below in evaluating our
business. Please keep these risks in mind when reading this annual report, any
of our other public filings or any of our press releases, including any
forward-looking statements appearing in this annual report. See "Forward-Looking
Statements." If the events described in any of the following risks actually
occur, our business, financial condition or results of operations would likely
suffer materially.
40
Risks Related to Our Business
Reserve estimates depend on many assumptions, the material adverse inaccuracy of
which will materially reduce the quantities and present value of our reserves.
This annual report contains estimates of our proved natural gas and oil
reserves and the estimated future net revenues from these reserves. These
estimates are based upon various assumptions, including assumptions relating to
natural gas and oil prices, drilling and operating expenses, capital
expenditures, ownership and title, taxes and the availability of funds. The
process of estimating natural gas and oil reserves is complex. It requires
interpretations of available geological, geophysical, engineering and economic
data for each reservoir. Therefore, these estimates are inherently imprecise.
Further, potential for future reserve revisions, either upward or downward, is
significantly greater than normal because most of our reserves are undeveloped.
Actual natural gas and oil prices, future production, revenues, operating
expenses, taxes, development expenditures and quantities of recoverable natural
gas reserves will most likely vary from those estimated. Any significant
variance could materially affect the estimated quantities and present value of
future net revenues set forth in this registration statement. A reduction in
natural gas and oil prices, for example, would not only reduce the value of
proved reserves, but probably would also reduce the amount of natural gas and
oil that could be economically produced, thereby reducing the quantity of
reserves. We may adjust estimates of proved reserves to reflect production
history, results of exploration and development, prevailing natural gas prices
and other factors, many of which are beyond our control.
As of December 31, 2001, approximately 97% of our estimated net proved
reserves were undeveloped. Undeveloped reserves, by their nature, are less
certain. Recovery of undeveloped reserves requires significant capital
expenditures and successful drilling operations. The reserve data assumes that
we will make significant capital expenditures to develop our reserves. Although
we have prepared estimates of our natural gas and oil reserves and the costs
associated with these reserves in accordance with industry standards, we cannot
assure you that the estimated costs are accurate, that development will occur as
scheduled or that the actual results will be as estimated. We may not be able to
raise the capital we need to develop these proved reserves. Most of these proved
reserves are located in the Wilmington Field in the Los Angeles Basin in
California where drilling activities have been suspended since late 1999.
Further delays or an unfavorable resolution of our dispute with our joint
venture partner in this field could result in a downward revision of our proved
reserves. See, "Item 3-Legal Proceedings."
You should not assume that the present value of future net revenues
referred to in this registration statement is the current market value of our
estimated natural gas and oil reserves. In accordance with SEC requirements, the
estimated discounted future net cash flows from proved reserves are generally
based on prices and costs as of the date of the estimate. Actual future prices
and costs may be materially higher or lower than the prices and costs as of the
date of the estimate. Any change in consumption by natural gas and oil
purchasers or in governmental regulations or taxation will also affect actual
future net cash flows. The timing of both the production and the expenses from
the development and production of our natural gas and oil properties will affect
the timing of actual future net cash flows from proved reserves and their
present value. In addition, the 10% discount factor, which is required by the
SEC to be used in calculating discounted future net cash flows for reporting
purposes, is not necessarily the most appropriate discount factor nor does it
reflect discount factors used in the marketplace for purchase and sale of oil
and gas properties. Conditions in the oil and gas industry and oil and gas
prices will affect whether the 10% discount factor accurately reflects the
market value of our estimated reserves.
41
We may be unable to continue to obtain needed financing on satisfactory terms to
successfully continue operations and grow.
Our future growth depends on our ability to make large capital expenditures
for the exploration and development of our natural gas and oil properties and to
acquire additional properties. We have projected these capital expenditures to
be approximately $22.5 million for 2002 and $34.0 million for 2003.
Historically, we have financed our capital expenditures primarily through the
drilling programs that participate in the exploration, drilling and development
of the projects, and to a lesser extent through debt financing. We intend to
continue financing these capital expenditures through drilling programs, the
issuance of debt and equity securities, cash flow from operations or a
combination of these methods. Future cash flows and the availability of
financing will be subject to a number of variables, such as:
o the success of our coalbed methane project in the Washakie
Basin;
o our success in locating and producing new reserves;
o the level of production from existing wells; and
o prices of natural gas and oil.
Additional financing sources may be required in the future to fund our
developmental and exploratory drilling. Issuing equity securities to satisfy our
financing requirements could cause substantial dilution to our existing
stockholders. Debt financing could lead to:
o a substantial portion of our operating cash flow being
dedicated to the payment of principal and interest;
o our being more vulnerable to competitive pressures and
economic downturns; and
o restrictions on our operations.
We incurred a net loss of $21.1 million during 2001. As of December 31,
2001, current liabilities exceeded current assets by $8.9 million and total
liabilities exceeded total assets by $6.4 million. Such loss and working capital
deficiency may materially adversely affect our ability to obtain financing.
Financing may not be available in the future under existing or new financing
arrangements, or we may not be able to obtain necessary financing on acceptable
terms, if at all. If sufficient capital resources are not available, we may be
forced to curtail our drilling, acquisition and other activities or be forced to
sell some of our assets on an untimely or unfavorable basis, which would have an
adverse affect on our financial condition and operating results.
Our future growth depends heavily on development of properties in the Washakie
Basin in which we own interests.
Our future growth plans rely heavily on establishing significant production
and reserves in the Washakie Basin. Proved reserves cannot be attributed to the
Washakie Basin until production begins. Currently, there are no producing wells
in this basin. We cannot be sure, however, that our planned projects in the
Washakie Basin will lead to significant production or that we will be able to
drill productive wells at anticipated finding and development costs due
primarily to financing and environmental uncertainties. Any reduction in our
drilling and development plans for the Washakie Basin could result in our
failure to replace or add reserves and materially adversely affect our financial
condition and results of operations.
An inability to obtain financing at acceptable rates could prevent us from
developing the Washakie Basin. Furthermore, environmental restrictions in this
area could prevent us from developing this acreage as planned. The BLM has begun
preparation of an EIS, which involves a series of scientific studies, surveys
and public hearings and formulation of a plan for drilling and production in the
Washakie Basin. This study is currently targeted for completion in the second
quarter of 2003. Our current drilling in this basin, along with our projected
drilling in 2002, is being conducted under an interim drilling policy of the
BLM, under which up to a total of 200 wells can be drilled in this basin, 165 of
which have been allocated to us. If public opposition to continued drilling in
this basin or other regulatory complications occur, the environmental impact
statement may not be completed during 2003, or could cause the BLM to severely
restrict or prohibit drilling on a more permanent basis. This could delay or
halt our drilling activities or the construction of ancillary facilities
necessary for production, which would prevent us from developing our property
interests in the Washakie Basin as planned. We cannot predict the future timing
or outcome of the environmental impact statement. Delays could severely limit
our operations there or make them uneconomic. This could impede our growth, as
this is the area in which we intend to undertake significant activity in order
to increase our production and reserves.
42
If we are unable to settle our disagreements with our joint venture partner in
the Wilmington Field, the value of our interest there or realization of that
value could be significantly diminished or delayed.
A majority, approximately 94%, of the estimated present value of our proved
reserves at December 31, 2001 are attributable to our interests in the
Wilmington Field near Los Angeles, California. Our operations in this field to
date have been governed by a joint venture agreement and the purchase and sale
agreement with Magness Petroleum Company, which requires a substantial degree of
coordination and cooperation with Magness. Our business relationship with
Magness has been characterized by significant discord and litigation, and no
drilling or development operations have taken place in this field since November
1999. See "Item 3--Legal Proceedings." The ultimate outcome of this litigation,
which is continuing, could affect our ownership interest in the Wilmington Field
or its value. Continued delays in conducting drilling operations in the
Wilmington Field due to litigation with Magness is likely to affect the
realization of the value of our interests in that field because most of our
proved reserves in this field are undeveloped and require further drilling to
become producing reserves. We believe that any subsequent findings will not have
a significant adverse effect on our financial position or operations.
Defects in the title to any of our natural gas and oil interests could result in
the loss of some of our oil and natural gas properties or portions thereof or
liability for losses resulting from defects in the assignment of leasehold
rights.
We obtain interests in natural gas and oil properties with varying degrees
of warranty of title such as general, special quitclaim or without any warranty.
We acquired our interest in the Wilmington Field from an independent operator
who acquired the interest directly from Exxon Corporation with no warranty of
title at all and no representation as to the percentage working interest or net
revenue interest being transferred. We have acquired no title opinion as to the
interests we own in that field, which may ultimately prove to be less than the
interests we believe we own. Losses in this field may result from title defects
or from ownership of a lesser interest than we assume we acquired or from the
assignment of leasehold rights by us to our drilling programs. In other
instances, title opinions may not be obtained if in our discretion it would be
uneconomical or impractical to do so. This increases the possible risk of loss
and could result in total loss of properties purchased. Furthermore, in certain
instances we may determine to purchase properties even though certain technical
title defects exist if we believe it to be an acceptable risk under the
circumstances.
The marketability of our production is dependent upon factors over which we have
no control.
The marketability of our production depends in part upon the availability,
proximity and capacity of pipelines, natural gas gathering systems and
processing facilities. This dependence is heightened in our coalbed methane
operations where this infrastructure is less developed than in our traditional
oil and gas operations. For example, there is no existing pipeline in the
southern portion of the Washakie Basin. Therefore, if drilling results are
positive in the entire length of the Washakie Basin, an entirely new gathering
system would need to be built to handle the potential volume of gas produced at
a cost of approximately $10.0 million, which would likely require Warren to seek
the assistance of a substantial pipeline company to finance and construct such a
system. In our traditional oil and gas operations, we generally only have to tie
in to existing pipelines at a cost of less than $250,000, which can be completed
in a number of weeks.
Any significant change in market factors affecting these infrastructure
facilities could adversely impact our ability to deliver the natural gas and oil
we produce to market in an efficient manner, or its price and, in some cases, we
may be required to shut-in wells, at least temporarily, for lack of a market or
because of the inadequacy or unavailability of transportation facilities. We
deliver natural gas and oil through gathering systems and pipelines that we do
not own. These facilities may not be available to us in the future. Our ability
to produce and market natural gas and oil is affected and also may be harmed by:
43
o the lack of pipeline transmission facilities or carrying
capacity;
o federal and state regulation of natural gas and oil
production;
o federal and state transportation, tax and energy policies;
o changes in supply and demand; and
o general economic conditions.
Leverage materially affects our operations.
As of December 31, 2001, our long-term debt was approximately $58 million,
substantially all of which consists of debentures we have issued from time to
time with due dates ranging from August 31, 2002 through December 31, 2022. At
December 31, 2001, the ratio of our debt to equity was negative and at the same
date, the ratio of our debt to total assets was 0.61 to 1.0. At August 31, 2002,
approximately $600,000 of debentures become due, with the next series of
debentures not becoming due until year-end 2007. Additionally, we are required
to make sinking fund payments on $45.7 million principal amount of our
outstanding debentures, with sinking fund payments of $3.2 million by the end of
2002 and $3.4 million by the end of 2003. We are also contingently obligated to
repurchase 10% of our outstanding bonds annually. See the next risk factor
below. Although we believe we can meet these requirements through December 31,
2002, we may not have sufficient funds to make repayments or sinking fund
payments throughout all future maturities.
Our level of debt affects our operations in several important ways,
including the following:
o a large portion of our net cash flow from operations has
been used to pay interest on borrowings;
o the covenants contained in the agreements governing our debt
limit our ability to borrow additional funds or to dispose
of assets;
o the covenants contained in the agreements governing our debt
may affect our flexibility in planning for and reacting to
changes in business conditions;
o a high level of debt may impair our ability to obtain
additional financing in the future for working capital,
capital expenditures, acquisitions, general corporate or
other purposes; and
o our leveraged financial position may make us more vulnerable
to economic downturns and may limit our ability to withstand
competitive pressures.
In addition, we may significantly alter our capitalization in order to make
future acquisitions or develop our properties. These changes in capitalization
may significantly increase our level of debt. A higher level of debt increases
the risk that we may default on our debt obligations. Our ability to meet debt
obligations and to reduce our level of debt depends on our future performance.
If we are unable to repay our debt at maturity out of cash on hand, we
could attempt to refinance the debt or repay the debt with the proceeds of an
equity offering. We may not be able to generate sufficient cash flow to pay the
interest or principal when due on our debt. We may be unable to sell public debt
or equity securities or do so on acceptable terms to pay or refinance the debt.
Factors that will affect our ability to raise cash through an offering of our
capital stock or a refinancing of our debt include financial market conditions
and our market value and operations performance at the time of the offering or
other financing. Any such offering or refinancing may not be successfully
completed.
44
Our substantial contingent obligations to repurchase 10% of our outstanding
bonds annually and to repurchase drilling program interests could strain our
financial resources and adversely affect our future financial condition.
Holders of our $58 million of outstanding convertible debentures and
sinking fund debentures are entitled each year to tender up to 10% of the
original aggregate face amount of each series of debentures for repurchase by us
at their face amount. Up to $4.4 million can be tendered in 2002 and $6.2
million in 2003.
Furthermore, as of December 31, 2001, under the terms of 13 of our drilling
programs formed before 1998, investors have the right to require us to
repurchase their interests in each program for a formula price either seven
years from the date of a partnership's formation, or between the 15th and 25th
anniversary of their formation. As of December 31, 2001, our potential
repurchase obligations which mature between 2002 and 2007 for such programs
approximate up to $45.2 million and for those maturing in 2008 or beyond
approximate up to $3.3 million. For the drilling programs formed before 1998,
the repurchase price is the amount of an investor's original capital
contribution reduced by the greater of:
o cash distributions made to the investor through the
repurchase date, or
o 10% for every $1.00 by which the then current oil price is
below $13.00 per Bbl, adjusted by CPI changes since the
program's formation.
Furthermore, as of December 31, 2001, under the terms of 7 of our drilling
programs formed during and after 1998, investors have the right to require us to
repurchase their interests in each program for a formula price either seven
years from the date of a partnership's formation, or between the 15th and 25th
anniversary of their formation. As of December 31, 2001, our potential
repurchase obligations which mature between 2002 and 2007 for such programs
approximate up to $47.0 million and for those maturing in 2008 or beyond
approximate up to $55.0 million. For the drilling programs formed in 1998 and
thereafter, the repurchase price is the amount of an investor's original capital
contribution reduced by the greater of:
o cash distributions made to the investor through the
repurchase date, or
o 10% for every $1.00 by which the then current oil price is
below $13.00 per Bbl, adjusted by
o CPI changes since the program's formation.
However, under no circumstances will the repurchase price for interests in
programs formed in 1998 and thereafter exceed the present value of the program's
future net revenues from proved reserves.
As of December 31, 2001, we have made aggregate cash distributions to
investors in the drilling programs of approximately $49.2 million. A portion of
our repurchase obligations is secured by $1.6 million market value of treasury
securities held by an independent trustee.
A reduction in production or oil and/or gas prices, which prices have
fallen since year-end 2000, could result in our recording liabilities for our
repurchase obligations and might result in our having to repurchase certain
drilling program interests if tendered by investors. At December 31, 2001,
original capital contributions of program investors exceeded cash distributions
made to that date by $1.0 million in programs whose repurchase right mature in
2002, by $4.4 million for programs whose rights mature in 2003 and by $16.7
million for programs whose rights mature in 2004. Depending upon the amount of
cash distributions to investors in our programs prior to the repurchase
obligation dates and the number of investors who tender their interests for
repurchase as their tender rights become available, a significant amount of
funds may be required for such repurchases, which could put a strain upon our
financial resources and otherwise affect our ability to execute upon our
business plan.
45
We may face significantly increasing water disposal costs in our coalbed methane
drilling operations.
The DEQ has restrictive regulations applying to the surface disposal of
water produced from our coalbed methane drilling operations. We typically obtain
permits to use surface discharge methods to dispose of water when the
groundwater produced from the coal seams will not exceed surface discharge
permit limitations. Surface disposal options have volumetric limitations and
require an extensive third-party water sampling and laboratory analysis program
to ensure compliance with state permit standards. Alternative methods to surface
disposal of water are more expensive. These alternatives include installing and
operating treatment facilities or drilling disposal wells to re-inject the
produced water into the underground rock formations adjacent to the coal seams
or lower sandstone horizons. When we are unable to obtain the appropriate
permits for surface disposal or applicable laws or regulations require water to
be disposed of in an alternative manner, the costs to dispose produced water
significantly increases. For example, the approximate cost to dispose of
produced water on the surface is $0.01 per barrel, into temporary reservoirs is
$0.04 per barrel and into water disposal wells is $0.10 per barrel. These costs
could have a material adverse effect on some of our operations in this area,
including potentially rendering future production and development in these
affected areas uneconomic.
Based on our experience with coalbed methane gas production in the Powder
River Basin, we believe that permits for surface discharge of produced water in
that basin as well as the Washakie Basin will become more and more difficult to
obtain. Furthermore, the state of Montana, in which some of our interests in the
Powder River Basin are located, has recently indicated that it does not intend
to allow surface discharge of produced water. Therefore, we will have to use
injection wells at all of our Montana operations. In Wyoming, produced water is
currently injected at three wells and we have obtained permits to drill six more
of these underground injection wells. We expect the costs to dispose of produced
water to continue to increase and may increase significantly.
If we pursue acquisitions and are unsuccessful at either completing the
acquisitions or if completed, realizing benefits, we may suffer losses.
We may pursue acquisitions of businesses or assets of businesses. These
businesses may operate in areas or markets in which we may not have any
experience. There is intense competition for acquisition opportunities in our
industry. Competition for acquisitions may increase the cost of, or cause us to
refrain from, completing acquisitions. Completion of acquisitions is dependent
upon, among other things, our ability to obtain debt and equity financing and,
in some cases, regulatory approvals. The acquisition of properties that are
substantially different in operating or geologic characteristics or geographic
locations from our existing properties, with which we have less experience,
could change the nature of our operations and business. We may issue stock that
would dilute our current stockholders' percentage ownership in connection with
an acquisition. We have limited experience in acquisition activities and may
have to devote substantial time and resources to complete any potential
acquisitions. In addition, if adequate funds are not available to us on
reasonable terms, we may be unable to take advantage of acquisition
opportunities.
If the attention of our management team is diverted toward pursuing
acquisitions and integrating any acquired business, they will have less time to
devote to managing current operations and developing new operations relating to
current assets. Achieving the expected benefits from any acquisition will depend
in part on the integration of operations, business cultures and personnel in a
timely and efficient manner to minimize the risk that the acquisition will
result in the loss of key employees and to minimize the diversion of the
attention of management. Any completed acquisition or failure to successfully
integrate a newly acquired business could result in the loss of our investment,
which could be substantial. Moreover, even successful acquisitions may involve
investment related expenses and amortization of acquired assets that could
adversely affect our operating results.
46
Our coalbed methane operations could be adversely affected by abnormally poor
weather conditions.
Our coalbed methane operations are conducted in areas subject to extreme
weather conditions and often in difficult terrain. Primarily in the winter and
spring, our operations are often curtailed because of cold, snow and wet
conditions. Unusually severe weather could further curtail these operations,
including drilling of new wells or production from existing wells, and depending
on the severity of the weather, could have a material adverse effect on our
financial condition and results of operations.
As general partner of limited partnerships and co-venturer in joint ventures, we
are liable for various obligations of those partnerships and joint ventures.
We currently serve as the managing general partner of 20 limited
partnerships and participate in four joint ventures as a result of our
sponsorship of drilling programs. As general partner or co-venturer, we are
contingently liable for the obligations of the partnerships or joint ventures,
as applicable, including responsibility for their day-to-day operations, and
liabilities which cannot be repaid from partnership or venture assets, insurance
proceeds or indemnification by others. In the future, we might be exposed to
litigation in connection with partnership or joint venture activities, or find
it necessary to advance funds on behalf of certain partnerships or joint
ventures to protect the value of the natural gas and oil properties by drilling
wells to produce undeveloped reserves or to pay lease operating expenses in
excess of production. These activities may adversely affect our financial
condition. See "Items 1 and 2-Business and Properties-Drilling Programs."
Our role as general partner of limited partnerships and co-venturer in joint
ventures may result in conflicts of interest, which may not be resolved in the
best interests of Warren or its stockholders.
Our role as general partner of limited partnerships and co-venturer in the
joint ventures may result in conflicts of interest between the interests of
those entities and our stockholders. For example, we plan to continue
contributing natural gas and oil wells to the various drilling programs we have
sponsored. The allocation of those wells to the drilling programs may give rise
to a conflict of interest between our interests and the interests of the
partners or co-venturers in our drilling programs. The resolution of these
conflicts may not always be in our best interests.
The loss of our chief executive officer or other key management and technical
personnel or our inability to attract and retain experienced technical personnel
could adversely affect our ability to operate.
We depend to a large extent on the efforts and continued employment of
Norman F. Swanton, our chief executive officer and chairman, James C. Johnson,
Jr., our executive vice president, Timothy A. Larkin, a senior vice president
and our chief financial officer, and other key management and technical
personnel. The loss of the services of Messrs. Swanton, Johnson, Larkin or other
key management and technical personnel could adversely affect our business
operations. We maintain key person life insurance on Messrs. Swanton, Johnson
and Larkin but not on other key management and technical personnel.
The success of our development, exploration and production activities
depends, in part, on our ability to attract and retain experienced petroleum
engineers, geologists and other key personnel. From time to time, competition
for experienced engineers and geologists is intense. If we cannot retain these
personnel or attract additional experienced personnel, our ability to compete in
the geographic regions in which we conduct our operations could be harmed.
Hedging activities may result in losses or limit our potential gains.
While we have not had any hedging arrangements in place to reduce our
exposure to fluctuations in the prices of natural gas and oil since March 31,
2001, we may enter into long-term gas contracts and hedging arrangements in the
future. These hedging arrangements would expose us to risk of financial loss if
certain events were to occur, including the following:
47
o our production is lower than expected;
o the difference between the underlying price in the hedging
agreement and actual prices received is higher or lower than
expected;
o the other parties to the hedging contracts fail to perform
their contract obligations; or
o a sudden unexpected event materially impacts natural gas or
oil prices.
In addition, these hedging arrangements may limit the benefit we would
receive from increases in oil or natural gas prices. Furthermore, if we choose
not to engage in hedging arrangements in the future, we may be more adversely
affected by changes in natural gas and oil prices than other competitors who
engage in hedging arrangements. The hedging arrangements we entered into prior
to March 31, 2001 resulted in substantial financial losses to us. We cannot
guarantee the success of any long-term gas contracts or hedging arrangements we
may enter into in the future.
We are subject to litigation risks that may not be covered by insurance.
In the ordinary course of business, we become subject to various claims and
litigation. The material litigation we are currently involved in is summarized
in "Item 3-Legal Proceedings." We maintain insurance to cover potential losses
and we are subject to various self-retentions and deductibles under our
insurance. It is possible, however, that judgments could be rendered against us
that exceed policy limits or, in cases in which we could be uninsured, beyond
the amount that we currently anticipate incurring for such matters.
RISKS RELATING TO THE OIL AND GAS INDUSTRY
Natural gas and oil prices fluctuate widely and a decrease in natural gas or oil
prices will adversely affect our financial results.
Our revenues, operating results and future rate of growth are substantially
dependent upon the prevailing prices of, and demand for, natural gas and oil.
Declines in the prices of, or demand for, natural gas and oil may adversely
affect our financial condition, liquidity, ability to finance planned capital
expenditures and results of operations. Lower natural gas and oil prices may
also reduce the amount of natural gas and oil that we can produce economically.
Historically, natural gas and oil prices and markets have been volatile, and
they are likely to continue to be volatile in the future. A decrease in natural
gas or oil prices will not only reduce revenues and profits, but will also
reduce the quantities of reserves that are commercially recoverable and may
result in charges to earnings for impairment of the value of these assets. If
natural gas or oil prices decline significantly for extended periods of time in
the future, we might not be able to generate enough cash flow from operations to
meet our obligations and make planned capital expenditures. Natural gas and oil
prices are subject to wide fluctuations in response to relatively minor changes
in the supply of and demand for natural gas and oil, market uncertainty and a
variety of additional factors that are beyond our control. NYMEX pricing for
natural gas ranged from $2.13 to $10.10 per MCF during 2000 and from $1.91 to
$9.82 per MCF during 2001. NYMEX pricing for oil ranged from $23.70 to $37.80
per Bbl during 2000 and from $17.45 to $32.19 per Bbl during 2001. Among the
factors that can cause this fluctuation are:
o domestic and worldwide supplies of natural gas and oil;
o market expectations about future prices;
o the availability of pipeline capacity;
o political conditions in natural gas and oil producing
regions;
o overall economic conditions;
o domestic and foreign governmental regulations and taxes;
o the price and availability of alternative fuels;
o weather conditions; or
o levels of production, and other activities of OPEC members
and other oil and natural gas producing nations.
48
We may not be able to replace, maintain or expand our reserves.
In general, production from natural gas and oil properties declines over
time as reserves are depleted, with the rate of decline depending on reservoir
characteristics. If we are not successful in our exploration, development and
enhancement activities or in acquiring properties containing proved reserves,
our proved reserves will decline as reserves are produced. Our future natural
gas and oil production is highly dependent upon our ability to economically
find, develop or acquire reserves in commercial quantities.
To the extent cash flow from operations is reduced, either by a decrease in
prevailing prices for natural gas and oil or an increase in finding and
development costs, and external sources of capital become limited or
unavailable, our ability to make the necessary capital investment to maintain or
expand our asset base of natural gas and oil reserves would be impaired. Even
with sufficient available capital, our future exploration and development
activities may not result in additional proved reserves and we may not be able
to drill productive wells at acceptable costs.
Oil and gas exploration and development is a high-risk activity.
Our future success depends largely on the success of our exploratory and
development drilling activities, which involve numerous risks, including the
risk that we will not find any commercially productive natural gas or oil
reservoirs. The cost of drilling, completing and operating wells is often
uncertain, and a number of factors can delay or prevent drilling operations,
including:
o unexpected drilling conditions;
o pressure or geologic irregularities in formations;
o equipment failures or accidents;
o pipeline and processing interruptions or unavailability;
o production allocations;
o adverse weather conditions;
o lack of market demand;
o government regulations;
o shortages or delays in the availability of drilling rigs and
the delivery of equipment; and
o force majeure.
Our future drilling activities may not be successful. Our drilling success
rate overall and within a particular area could decline. We could incur losses
by drilling unproductive wells. Also, we may not be able to obtain any options
or lease rights in potential drilling locations. Although we have identified
numerous potential drilling locations, we cannot be sure that we will ever drill
them or that we will produce natural gas or oil from them or from any other
potential drilling locations. Shut-in wells, curtailed production and other
production interruptions may negatively impact our business and result in
decreased revenues.
Competition in the oil and gas industry is intense, and many of our competitors
have greater financial, technological and other resources than we do.
We operate in the highly competitive areas of oil and gas exploration,
development and acquisition with a substantial number of other companies. We
face intense competition from independent, technology-driven companies as well
as from both major and other independent oil and gas companies in each of the
following areas:
o acquiring desirable producing properties or new leases for
future exploration;
49
o marketing our natural gas and oil production;
o integrating new technologies; and
o acquiring the equipment and expertise necessary to develop
and operate our properties.
Many of our competitors have financial, managerial, technological and other
resources substantially greater than ours. These companies may be able to pay
more for exploratory prospects and productive oil and gas properties and may be
able to define, evaluate, bid for and purchase a greater number of properties
and prospects than our financial or human resources permit. To the extent our
competitors are able to pay more for properties than we are, we will be at a
competitive disadvantage. Further, many of our competitors may enjoy
technological advantages and may be able to implement new technologies more
rapidly than we can. Our ability to explore for natural gas and oil prospects
and to acquire additional properties in the future will depend upon our ability
to successfully conduct operations, implement advanced technologies, evaluate
and select suitable properties and consummate transactions in this highly
competitive environment.
We are subject to complex laws and regulations, including environmental
regulations, that can adversely affect the cost, manner or feasibility of doing
business.
Exploration for and exploitation, production and sale of oil and gas in the
United States is subject to extensive federal, state and local laws and
regulations, including complex tax laws and environmental laws and regulations.
Failure to comply with these laws and regulations may result in the suspension
or termination of our operations and subject us to administrative, civil and
criminal penalties. Compliance costs are significant. Further, these laws and
regulations, particularly in the Rocky Mountain region, could change in ways
that substantially increase our costs and associated liabilities. We cannot be
certain that existing laws or regulations, as currently interpreted or
reinterpreted in the future, or future laws or regulations will not harm our
business, results of operations and financial condition. Matters subject to
regulation include:
o water discharge permits for drilling operations;
o drilling permits;
o drilling bonds;
o spacing of wells;
o unitization and pooling of properties;
o air quality;
o rights of way;
o environmental protection;
o reports concerning operations; and
o taxation.
Under these laws and regulations, we could be liable for:
o personal injuries;
o property damage;
o oil spills;
o discharge of hazardous materials;
o well reclamation costs;
o remediation and clean-up costs; and
o other environmental damages.
See "Items 1 and 2-Business and Properties-Government Regulation" for a more
detailed discussion of laws affecting our operations.
50
Shortages of rigs, equipment, supplies, and personnel may restrict our
operations from time to time.
If domestic drilling activity increases, particularly in the fields in
which we operate, a general shortage of drilling and completion rigs, field
equipment and qualified personnel could develop. These shortages could be
intense. If shortages do occur, the costs and delivery times of rigs, equipment
and personnel could be substantially greater than in previous years. From time
to time, these costs have sharply increased and could do so again. The demand
for and wage rates of qualified drilling rig crews generally rise in response to
the increasing number of active rigs in service and could increase sharply in
the event of a shortage. Shortages of drilling and completion rigs, field
equipment or qualified personnel could delay, restrict or curtail our
exploration and development operations, which could in turn harm our operating
results.
We do not insure against all potential operating risks and loss. We could be
seriously harmed by unexpected liabilities.
Our operations are subject to hazards and risks inherent in drilling for,
producing and transporting natural gas and any of these risks can cause
substantial losses resulting from:
o injury or loss of life;
o damage to and destruction of property, natural resources and
equipment;
o pollution and other environmental damage;
o regulatory investigations and penalties;
o suspension of our operations; and
o repair and remediation costs.
As protection against operating hazards, we maintain insurance coverage
against some, but not all, potential losses. However, losses could occur for
uninsurable or uninsured risks, or in amounts in excess of existing insurance
coverage. The occurrence of an event that is not fully covered by insurance
could harm our financial condition and results of operations. In addition,
pollution and environmental risks generally are not fully insurable.
RISKS RELATED TO OWNERSHIP OF OUR COMMON STOCK
Our inability to obtain waivers or releases of preemptive rights from some of
our current and former stockholders in connection with previous issuances of
securities may subject us to liability for damages.
Because we were incorporated in New York before February 1998 and our
certificate of incorporation does not deny shareholders preemptive rights, our
shareholders have preemptive rights in connection with certain issuances of our
securities, unless certain exceptions applied. Generally, if applicable,
preemptive rights entitle a shareholder to subscribe to a proportionate part of
a new issue of stock, securities convertible into stock or rights to acquire
stock. On numerous occasions between 1992 and 2000, we issued common stock,
warrants and convertible bonds. We may not have informed our shareholders
regarding their preemptive rights under New York law, if not exempt or otherwise
waived, relating to these offerings.
We have obtained written waivers or releases from shareholders who,
collectively, represented a majority of the outstanding shares as of December
31, 2000, and owned shares for many years before then. We have not determined
whether or not we will seek additional waivers. If we do determine to seek such
waivers, we are uncertain whether or not we will be able to obtain waivers from
a substantial additional number of those persons or entities who owned our stock
at the time of the issuances of securities between 1992 and 2000.
A shareholder who has not waived his or her preemptive rights with respect
to our offering of securities that were not otherwise exempt may have a right to
bring an action for damages against us. If claims are made and are successful,
damages could be assessed against us. Our financial condition could be
materially adversely affected if any such assessment involves substantial
damages.
51
Our failure to register our common stock when the number of our shareholders
exceeded 500 exposes us to potential liability under the securities laws.
Because the number of our shareholders for purposes of Section 12(g) of the
Securities Exchange Act of 1934 exceeded 500 as of December 31, 1999, we were
required to register our shares of common stock pursuant to Section 12(g) in the
beginning of 2000. We did not become aware of the fact that our shareholders
exceeded 500 for purposes of Section 12(g) until June 2001. We filed our
registration statement on Form 10 to register our common stock pursuant to
Section 12(g) with the Securities and Exchange Commission on October 26, 2001
that became effective on December 25, 2001. It is possible that administrative
proceedings or civil lawsuits could be brought against us, and our financial
condition could be materially affected, if any such proceeding or lawsuit were
successful and resulted in an award of substantial damages.
No public trading market exists for our common stock.
There is no public trading market for our common stock and there can be no
assurance that a trading market will ever develop. We cannot predict nor control
the extent to which a trading market will develop or how liquid such a market
may become. Shares of our common stock may only be resold if they are registered
with the SEC or if they are sold pursuant to an exemption from registration.
The number of shares eligible for future sale or which have registration rights
could adversely affect any future market that develops for our common stock.
If a public market for our shares should develop, sales of substantial
amounts of our common stock in such a public market or the perception that a
large number of shares are available for sale could depress any market price for
our common stock. As of December 31, 2001, there were approximately 17,537,579
shares of common stock outstanding and 7,009,939 shares of common stock issuable
upon the exercise of outstanding options and conversion of our convertible debt.
Additionally, the compensation committee had approved the grant of 4,415,613
options pursuant to the 2000 Equity Plan for Employees of Pedco, 2001 Stock
Incentive Plan and the 2001 Key Employee Stock Incentive Plan, which plans are
subject to shareholder approval. Pursuant to Rule 144 under the Securities Act,
commencing March 26, 2002, which was 90 days following the effectiveness of our
Form 10 registration statement, up to approximately 9,666,547 shares of our
common stock can be sold under Rule 144 and 7,871,032 shares including 6,045,949
shares held by "affiliates" could be resold subject to the volume limitations of
Rule 144. Further, pursuant to Rule 144, commencing March 26, 2002, all holders
of our common stock issuable upon conversion of existing convertible debt are
eligible to sell such shares, and some of them may also have rights, subject to
some conditions including the consent of any underwriter, to include their
shares in any registration statements that we file to register our shares under
the Securities Act for ourselves or other stockholders. If our stockholders sell
significant amounts of common stock on any public market which develops or
exercise their registration rights and sell a large number of shares, the price
of our common stock could be negatively affected. If we were to include shares
held by those holders in a registration statement pursuant to the exercise of
their registration rights, those sales could impair our ability to raise needed
capital by depressing the price at which we could sell our common stock or
impede such an offering altogether.
Control by our officers and directors stockholders will limit your ability to
influence the outcome of matters requiring stockholder approval and could
discourage our potential acquisition by third parties.
Our executive officers and directors beneficially own, in the aggregate,
approximately 38% of our outstanding common stock. These stockholders, if acting
together, would be able to influence significantly all matters requiring
approval by our stockholders, including the election of our board of directors
and the approval of mergers or other business combination transactions. This
concentration of ownership could have the effect of delaying or preventing a
change in our control or otherwise discourage a potential acquirer from
attempting to obtain control of us, which in turn could have an adverse effect
on the market price of our common stock or prevent our stockholders from
realizing a premium over the market price for their shares of our common stock.
52
Item 8: Financial Statements and Supplementary Data
See Independent Accountant's Report and Audited Financial Statements at
Item 14 for financial statements.
Item 9: Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
PART III
Item 10: Directors and Executive Officers of the Registrant.
Executive Officers, Directors and certain Significant Employees
Our executive officers, directors and certain significant employees and their
ages and positions are set forth below:
Name Age Position
Norman F. Swanton 63 President, Chairman of the Board and Chief Executive Officer
James C. Johnson, Jr. 47 Executive Vice President and President of Pedco
Gregory S. Johnson 42 Senior Vice President and Executive Vice President of Pedco
Timothy A. Larkin 39 Senior Vice President and Chief Financial Officer
David E. Fleming 47 Senior Vice President and General Counsel
Jack B. King 57 Vice President and National Director of Sales and Marketing
Dominick D'Alleva 50 Secretary and Director
Anthony L. Coelho (2) 59 Director
Lloyd G. Davies (1) (2) 65 Director
Victor E. Millar 66 Director
Marshall Miller (1) (2) 51 Director
Thomas G. Noonan (1) 63 Director
Michael R. Quinlan 57 Director
James A. Thompson 48 Director
Ellis G. Vickers 45 Vice President and Associate General Counsel and Senior Vice President and
General Counsel of Pedco
Bret D. Cook 40 Senior Vice President - Engineering and Operations of Pedco
Kenneth A. Gobble 42 Vice President - Rocky Mountain Region
Michael R. Burch 50 Vice President and Land Manager of Pedco
- ---------------------
(1) Members of the Compensation Committee.
(2) Members of the Audit Committee.
Norman F. Swanton. Mr. Swanton is and has been our President, Chairman of
the Board and Chief Executive Officer since Warren Resources, Inc. was founded
in June 1990. Mr. Swanton currently serves on the board of directors for
Resource Capital Group, Inc., a public company with its principal business in
real estate. From October 1986 to 1990, he served as an independent financial
advisor, arranging debt restructuring, new credit facilities, leveraged buy-out
financing, debt-for-equity exchanges, equity financing, reorganization
consulting and providing other financial services. From 1972 to 1985, he served
as Chairman of the Board, President and Chief Executive Officer of Swanton
Corporation, a publicly held company engaged in investment banking, securities
brokerage, insurance premium financing, securities industry consulting and
energy operations; Chairman of the Board and founder of NFS Services, Inc., a
corporation engaged in providing credit, operations and regulatory consulting;
Chairman of the Board of Swanton, Shoenberg Hieber, Inc., a New York Stock
Exchange member firm; Chairman of the Board of Swanton Swartwood Hess, Inc., a
NASD member firm; and President and founder of Low Sulphur Fuel Company, a
marine terminal residual fuel oil blending operation combined with crude
oil-for-product exchange activities on behalf of West Coast utility companies.
From 1961 to 1972, he served as an executive officer for Glore, Forgan, Staats,
Inc. and a divisional controller for Hayden Stone, Inc. which were New York
Stock Exchange member securities and underwriting firms. He also served as a
principal consultant to the Trust Fund of the New York Stock Exchange serving as
its representative in the liquidation of several former New York Stock Exchange
member firms. Mr. Swanton received his Bachelor of Arts Degree with honors in
History and Political Science from Long Island University in 1962 and attended
Bernard Baruch Graduate School of Business in a graduate degree program in
Accountancy and Finance from 1963 to 1966. He is the brother-in-law of Thomas G.
Noonan.
53
James C. Johnson, Jr. Mr. Johnson has served as our Executive Vice
President since September 2000 and as President of Pedco since March 1998. From
1978 to 1998, he served as Vice President of Pedco. He has participated in
drilling over 100 horizontal wells located in New Mexico, North Dakota, Wyoming,
Missouri, Michigan, Texas and California. Additionally, he has supervised field
drilling operations for more than 200 vertical wells. Mr. Johnson received his
Bachelor of Arts degree in business administration from the University of New
Mexico in 1977. He is the brother of Gregory S. Johnson.
Gregory S. Johnson. Mr. Johnson has served as our Senior Vice President
since September 2000 and as Executive Vice President of Pedco since 1998. Mr.
Johnson is in charge of field operations and supervises all on-site horizontal
and directional drilling and well engineering. From 1989 to 1998, Mr. Johnson
was President of Pedco Swabbing. He has been actively engaged in a broad range
of natural gas and oil drilling and completion operations for the past 18 years.
Mr. Johnson attended the University of New Mexico from 1978 to 1979 and the New
Mexico Technology Institute from 1981 to 1984, majoring in Petroleum
Engineering. Mr. Johnson is the brother of James C. Johnson, Jr.
Timothy A. Larkin. Mr. Larkin has served as our Senior Vice President and
Chief Financial Officer since January 1995. From 1991 to 1994, he served as
Accounting Manager of Palmeri Fund Administrators, Inc., an administrative
services company providing investment, administrative and accounting advisory
support to over 50,000 limited partners in investment funds primarily sponsored
by Merrill Lynch and Oppenheimer & Co. Inc. From 1985 to 1991, he was employed
in the audit department of Deloitte & Touche, LLP, an international public
accounting firm, attaining the level of audit manager. Mr. Larkin received his
bachelor's degree in Accounting from Villanova University in 1985.
David E. Fleming. Mr. Fleming joined Warren in July 2001 as a Senior Vice
President and General Counsel. From January 1999 to June 2001, he was a partner
with the law firm of Cummings & Lockwood, where he practiced corporate law. For
the five years prior thereto, he practiced corporate law at Epstein, Becker &
Green, P.C., New York, New York, where he was a member of the firm. Mr. Fleming
received a Bachelor of Arts degree from Cornell University in 1976 and a Juris
Doctor, Cum Laude, from the University of Maryland School of Law in 1980. He is
admitted to practice law in the States of New York, Connecticut and Maryland.
Jack B. King. Mr. King has served as our Vice President and our National
Director of Sales and Marketing for drilling programs and our other private
placements since April 1997. He is also our Western Marketing representative
based in Tustin, California. From 1995 to April 1997, he served as a marketing
director for Icon Capital, an equipment leasing syndicator. He received his
Bachelor of Arts degree in Psychology from Drury University in Springfield,
Missouri in 1966 and holds various securities and insurance licenses.
Dominick D'Alleva. Mr. D'Alleva has been our Secretary and a director since
June 1992. Additionally, from 1995 to the present, he has been a principal with
DND Realty, LLC, a privately owned New York limited liability company involved
in the acquisition and financing of real estate. From 1986 to 1995, he was
engaged in residential New York City real estate for his own account and as
general counsel to various real estate acquisition firms, where he negotiated
contracts for the acquisition and financing of commercial real estate. From 1983
to 1985, he served as Executive Vice President, Director and General Counsel of
Swanton Corporation, which engaged in energy, retail and financial services
businesses. From 1980 to 1983 he was Associate Counsel of Damson Oil
Corporation. From 1977 to 1980 he was an associate with Simpson, Thatcher &
Bartlett specializing in securities and corporate law. Mr. D'Alleva received a
Bachelor of Arts degree Summa Cum Laude from Fordham University in 1974 and
earned his Juris Doctor degree with honors from Yale University in 1977. Mr.
D'Alleva will devote only so much of his time as is reasonably required to
perform his duties as our Secretary.
Anthony L. Coelho. Congressman Coelho joined our Board as an independent
director in May 2001 and serves on the audit committee of the Board. From
December 2000 to the present, Mr. Coelho has devoted his time to serving on the
boards of directors listed below and as an independent consultant and adviser.
From 1998 through November 2000, he served as the General Chairman for the U.S.
Presidential campaign of Vice President Al Gore. From 1995 to 1998, he was
Chairman and Chief Executive Officer of ETC w/tci, Inc, an education and
training technology company in Washington, D.C. and from 1990 to 1995, he served
as President and CEO of Wertheim Schroeder Investment Services, Inc. From 1978
to 1989, he served five terms in the U.S. Congress, representing the State of
California as a member of the U.S. House of Representatives. During his
congressional terms, he served as Democratic Majority Whip from 1987 to 1989 and
54
authored the Americans with Disabilities Act. Congressman Coelho was also
appointed chairman of the President's Committee on the Employment of People with
Disabilities by President Clinton. Congressman Coelho has served on a number of
corporate boards, including AutoLend Group, Kaleidoscope Network, Inc., LoanNet,
LLC, Pinnacle Global Group, Inc. and as chairman of ICF Kaiser International,
Inc. He currently serves on the boards of ColumbusNewport, LLC, Cadiz, Inc.,
Cyberonics, Inc., DeFrancesco & Sons, Inc., Kistler Aerospace Corporation,
Ripplewood Holdings, LLC, Service Corporation International, a publicly traded
company, and MangoSoft, Inc. Congressman Coelho earned a Bachelor of Arts degree
in Political Science from Loyola Marymount University in 1964.
Lloyd G. Davies. Mr. Davies joined the board of directors in July 2001 and
serves on the audit committee and compensation committee of the Board.. For the
past seven years Mr. Davies has been retired. From 1992 through 1994, Mr. Davies
was the Assistant Division Manager for the Western U.S. area for Texaco. Prior
to that, from 1990 through 1992, Mr. Davies was the Manager and Director of
Operations for Texaco's Far East Operations Division. During those years, he
also served on several of Texaco's subsidiaries' board of directors in the Far
East. Mr. Davies received a Bachelor of Science Degree in Petroleum Engineering
from the University of Oklahoma in 1958. In 1966, he received a Master of
Science Degree in Petroleum Engineering with a Minor in Math from the University
of Texas.
Victor E. Millar. Mr. Millar joined the Board as an independent director in
January 1998. Since 1998, he has been Chairman of ColumbusNewport, an
international consulting and venture capital organization based in Washington
D.C. From 1995 through 1998, he was Executive Vice President of AT&T and CEO of
AT&T Solutions, a $1 billion consulting subsidiary of AT&T. Mr. Millar has also
served as CEO of Saatchi & Saatchi Consulting and CEO of Unisys Worldwide
Information Services. Additionally, he served as the Managing Partner of
Andersen Consulting worldwide. Mr. Millar earned his bachelor's degree in
business in 1957 and his MBA in 1958 from the University of California at
Berkeley.
Marshall Miller. Mr. Miller joined the Board as an independent director in
February 1998 and serves on the audit committee and compensation committee of
the Board. Mr. Miller was an Executive Vice President of Wells Fargo Bank in San
Francisco until retiring in 2000. For the past 17 years, Mr. Miller served in
various senior management capacities with several financial institutions
including Fair, Isaac Companies, Providian Financial Corporation and Wells Fargo
Bank and specialized in advanced computer systems for credit risk management.
Mr. Miller received a Bachelor of Arts Degree in Mathematics from the University
of California at Berkley and a Masters of Science Degree from Stanford
University in 1976.
Thomas G. Noonan. Mr. Noonan joined the Board as a director in November
1997 and serves on the compensation committee of the Board. For the past 17
years, he has served as Manager of Quality Assurance for Mars Inc., an
international food and candy company. From 1961 to 1979, he was a microbiologist
for the Environmental Department of the State of New York. Mr. Noonan received a
Bachelor of Science degree from Fordham University in New York in 1959. He is
the brother-in-law of Mr. Swanton.
Michael R. Quinlan. Mr. Quinlan joined the Board as a director in January
2002. From 1963 to the present Mr. Quinlan has been employed by the McDonald's
Corporation. In 1979, Mr. Quinlan was appointed to the board of directors of
McDonald's and served as the Chairman of the Board and Chief Executive Officer
from 1990 to 1998. From 1998 to 1999, he served as Chairman of the Board of
McDonald's Corporation. From 1987 to 1990, he served as the President and Chief
Executive Officer. Currently he serves as the Chairman of the Executive
Committee. Mr. Quinlan is chairman of the board of trustees of both Ronald
McDonald House Charities and Loyola University Chicago. Additinally, he is a
member of the board of trustees of Loyola University Health System. He is also
on the board of directors of Dun and Bradstreet Corporation and the May
Department Stores Company. Mr. Quinlan earned a Bachelor of Science degree in
1967 and a Master's of Business Administration from Loyola University Chicago in
1970. He has been awarded Honorary Doctors of Law Degrees from Loyola University
Chicago, Elmhurst College and Illinois Benedictine College.
James A. Thompson. Mr. Thompson joined the Board as an independent director
in 1997. For the past 13 years he has served as President of the Thompson Group
Inc., a NASD Broker-Dealer firm located in White Plains, New York. From 1977 to
1985, he was associated with the New York Life Insurance Company specializing in
insurance products and estate planning. While with the New York Life Insurance
Company, he was a five-year member of the Million-Dollar Round Table. Mr.
Thompson received a Bachelor of Science degree from Union College, Schenectady,
New York in 1976. He also received a Chartered Life Underwriting designation in
1981 and a Chartered Financial Consultant designation in 1983 from The American
College.
55
Ellis G. Vickers. Mr. Vickers is our Vice President and Associate General
Counsel and is the Senior Vice President and General Counsel of Pedco. He has
served in these positions since September 2001. From 1995 through December 2001,
Mr. Vickers practiced law with the New Mexico based law firm of Bozarth &
Vickers. He focused his practice on corporate, securities, oil and gas, real
estate and partnership law and is a New Mexico Board of Legal Specialization
Recognized Specialist in Oil and Gas Natural Resources. Mr. Vickers resigned
from his law firm partnership to become full-time at Pedco commencing January 1,
2002. Mr. Vickers received his Bachelor of Science degree in Political Science,
Summa Cum Laude, from Eastern New Mexico University in 1979 and a Juris Doctor
from the University of New Mexico in 1982. He is admitted to practice law in the
states of New Mexico and Texas.
Bret Cook. Mr. Cook has served as Senior Vice President - Engineering and
Operations for Pedco since 1996. Mr. Cook was responsible for drilling
horizontal wells in numerous challenging formations and environments at the
major on-shore natural gas and oil basins throughout the U.S. Mr. Cook received
his Bachelor of Science in Petroleum Engineering in 1985 and Master of Science
in Petroleum Engineering in 1993 from New Mexico Institute of Mining and
Technology.
Ken Gobble. Mr. Gobble is Vice President - Rocky Mountain Region for Pedco.
Prior to joining Pedco in 1996, Mr. Gobble had extensive experience with major
service companies including Schlumberger Well Services. Additionally, Mr. Gobble
has extensive experience in numerous advanced applications for natural gas and
oil drilling operations including logging-while-drilling, wire-line, gamma ray,
3-D seismic, horizontal drilling and coalbed methane development. Mr. Gobble
received his Bachelor of Science Degree in Petroleum Engineering and a Bachelor
of Science Degree in Mathematics from New Mexico Institute of Mining and
Technology in 1986.
Michael R. Burch. Mr. Burch is Vice President and Land Manager of Pedco and
is responsible for land and lease administration. Prior to joining Pedco in
1998, Mr. Burch had twenty years of experience with Yates Petroleum Company and
other independent energy companies in negotiating, managing and administrating
oil and gas lease acquisitions. Mr. Burch attended New Mexico Military
Institute, Florence State University where he majored in business and has
attended numerous seminars covering environmental and other legal land issues.
Committees of the Board
The board of directors has established the following standing committees:
audit, nominating and compensation committees.
Audit Committee. The audit committee is comprised entirely of non-employee
directors. The audit committee reviews the preparation of and the scope of the
audit of our annual consolidated financial statements, reviews drafts of such
statements, makes recommendations as to the engagement and fees of the
independent auditors, and monitors the functioning of our accounting and
internal control systems by meeting with representatives of management and the
independent auditors. This committee has direct access to the independent
auditors and counsel to Warren and performs such other duties relating to the
maintenance of the proper books of account and records of Warren and other
matters as the board of directors may assign from time to time. We intend to
maintain an audit committee consisting of at least three independent directors.
Independent directors are persons who are, among other things, neither officers
nor employees of Warren or its subsidiaries or any other person who has a
relationship with any person or entity which, in the opinion of the board of
directors, would interfere with the exercise of independent judgment in carrying
out the responsibilities of a director. The Audit Committee consists of Messrs.
Miller, Congressman Coelho and Mr. Davies. Mr. Miller currently acts as chairman
of the audit committee.
Compensation Committee. The compensation committee consists of Messrs.
Davies, Miller and Noonan. Mr. Noonan will be the chairman of the committee. The
compensation committee has sole authority to administer our stock option plans.
The compensation committee also reviews and makes recommendations regarding the
compensation levels of the company's executive officers.
56
Meetings of the Board of Directors
During 2001, the board of directors met three times. At least 75% of the
directors attended each meeting.
Compensation of Directors
Directors who are also employees of Warren receive no additional
compensation for their services as directors. Directors who are not employees of
Warren receive $1,000 for each meeting of the board of directors or committees
of the board of directors which they attend, and are reimbursed for travel
expenses and other out-of-pocket costs incurred in connection with the
attendance at such meetings. Until Warren becomes a publicly traded company,
each director receives:
o options to purchase 25,000 shares of our common stock
exercisable at the then current fair market price for a
period of five years upon becoming a member of the board;
and
o options to purchase 10,000 shares of our common stock for
each year of service thereafter, exercisable at the then
current fair market price for a period of five years.
After Warren becomes a publicly traded company, each non-employee director shall
receive:
o an annual retainer fee of $10,000;
o options to purchase 10,000 shares of our common stock
exercisable at the then current fair market price for a
period of five years, upon becoming a member of the board;
and
o options to purchase 5,000 shares of our common stock for
each year of service thereafter, exercisable at the then
current fair market price for a period of five years.
Compensation Committee Interlocks and Insider Participation
None of the members of our compensation committee are currently or have
been at any time since our founding, an officer or employee of Warren. No member
of our compensation committee serves as a member of the board of directors or
compensation committee of any entity that has one or more executive officers
serving as a member of our board of directors or compensation committee.
Item 11: Executive Compensation.
The following table sets forth the total compensation earned by our chief
executive officer and each of the four most highly compensated other executive
officers who received annual compensation in excess of $100,000 for the year
ended December 31, 2001. We refer to these officers as our named executive
officers. The compensation set forth in the table below for the fiscal years
ended December 31, 2001, 2000 and 1999 does not include medical, group life or
other benefits which are available to all of our salaried employees, and
perquisites and other benefits, securities or property which do not exceed the
lesser of $50,000 or 10% of the person's salary and bonus shown in the table.
57
Summary Compensation Table
Annual Compensation Long-Term Compensation Awards
--------------------------------------- -----------------------------
Securities
Other Annual Underlying All Other
Name and Principal Position Year Salary Bonus(1) Compensation(2) Options Compensation
- ------------------------------- ----- --------- -------- -------------- ---------- --------------
Norman F. Swanton, 2001 $375,000 $220,000 $18,814 600,000(3) -0-
Chief Executive Officer and 2000 150,000 375,000 -0- -0- -0-
Chairman of the Board 1999 146,154 200,000 -0- -0- -0-
James C. Johnson, Jr., 2001 $200,000 $ 33,300 $ 1,700 -0- -0-
Executive Vice President 2000 113,333 300,000 -0- 400,000 -0-
and President of Pedco 1999 90,000 36,000 -0- -0- -0-
Timothy A. Larkin, 2001 $185,000 $ 92,500 $ 819 676,875(3) -0-
Senior Vice President and 2000 155,000 134,333 -0- -0- -0-
Chief Financial Officer 1999 140,000 140,000 -0- -0- -0-
Gregory S. Johnson, 2001 $185,000 $ 30,708 -0- -0- -0-
Senior Vice President and 2000 110,000 300,000 -0- 400,000 -0-
Vice President of Pedco 1999 90,000 36,000 -0- -0- -0-
Jack B. King, 2001 $200,000 $ -0- -0- 380,630(3) -0-
Vice President and Director 2000 150,000 346,186 -0- -0- -0-
of National Sales and 1999 125,000 222,643 -0- -0- -0-
Marketing
(1) Bonus amounts reported for 2001, 2000 and 1999 include bonuses earned in
the reported year and actually paid in the subsequent year.
(2) Amounts reflect insurance premiums paid by the company during the covered
fiscal year with respect to life insurance for the benefit of the named
executive officer or his designee.
(3) Includes stock option grants in 2001, which were approved by the Board of
Directors on September 6, 2001, subject to shareholder approval at the next
meeting of shareholders.
Option Grants in Last Fiscal Year
The following stock options to purchase shares of our common stock were
granted to the named executive officers during the fiscal year ended December
31, 2001.
Individual Grants
---------------------------------------------------
Percent of Potential Realizable
Total Value at Assumed Annual
Number of Options Rate of Stock Price
Securities Granted to Appreciation for Option
Underlying Employees Term(2)
Options in Fiscal Exercise Expiration ------------------------
Granted Year Price(1) Date 5% 10%
---------- ---------- -------- ---------- ---------- ----------
Norman F. Swanton 600,000 22.5% $10.00 09/05/06 $1,657,689 $3,663,060
James C. Johnson, Jr. -0- - - - -
Gregory S. Johnson -0- - - - -
Timothy A. Larkin 676,875 25.4% $10.00 09/05/06 $1,870,081 $4,132,390
Jack B. King 380,630 14.3% $10.00 09/05/06 $1,050,538 $2,325,649
- -----------------------
(1) The exercise price per share of each option was determined to be equal to
the fair market value per share of the underlying stock on the date of
grant, as estimated by management.
(2) The potential realizable value shown is calculated based on the term of the
option at the time of grant. Stock price appreciation of 5% and 10% is
assumed pursuant to the rules and regulations of the SEC and does not
represent our prediction of our stock price performance. The potential
realizable values at 5% and 10% appreciation are calculated by assuming
that the exercise price on the date of grant appreciates at the indicated
rate for the entire term of the option and that the option is exercised at
the exercise price and sold on the last day of its term at the appreciated
price.
58
Employment Agreements
We entered into an employment agreement on July 1, 2001 with Mr. Norman F.
Swanton, our Chairman and Chief Executive Officer, that provides for a salary of
$375,000 per year, guaranteed annual bonus compensation equal to 50% of his
annual base salary, participation in our standard insurance plans for our
executives, and participation in our other incentive compensation programs at
the discretion of the board of directors. The employment agreement also provides
that all stock options held by Mr. Swanton are subject to accelerated vesting in
the event of his termination without cause or in the event of a change of
control. Under his employment agreement, Mr. Swanton is entitled to receive
stock options to purchase 600,000 shares of common stock at the exercise price
of $10.00 per share for a period expiring five years from date of issuance. The
options to purchase common stock vest at the rate of 50% upon issuance, 25% one
year after the date of the grant and 25% two years after the date of the grant.
If Mr. Swanton's employment is terminated without cause, Mr. Swanton is entitled
to termination compensation equal to the greater of two years annual base
salary, plus the bonus amount paid in the preceding fiscal year, or all of the
base salary for the remainder of the employment term, plus the preceding year's
bonus compensation. Mr. Swanton's employment agreement automatically renews on
each anniversary of the effective date after the initial three year employment
term, for an additional one year unless we notify Mr. Swanton in writing 90 days
prior to such anniversary that we will not be renewing his employment agreement.
We entered into an employment agreement on July 1, 2001 with Mr. Timothy A.
Larkin, our Senior Vice President and Chief Financial Officer, that provides for
a salary of $185,000 per year, guaranteed annual bonus compensation equal to 50%
of his annual base salary, participation in our standard insurance plans for our
executives, and participation in our other incentive compensation programs at
the discretion of the board of directors. The employment agreement also provides
that all stock options held by Mr. Larkin are subject to accelerated vesting in
the event of his termination without cause or in the event of a change of
control. Under his employment agreement, Mr. Larkin is entitled to receive stock
options to purchase 676,875 shares of common stock at the exercise price of
$10.00 per share for a period expiring five years from date of issuance. All of
these stock options will vest immediately. If Mr. Larkin's employment is
terminated without cause, Mr. Larkin is entitled to termination compensation
equal to the greater of two years annual base salary, plus the bonus amount paid
in the preceding fiscal year, or all of the base salary for the remainder of the
employment term, plus the preceding year's bonus compensation. Mr. Larkin's
employment agreement automatically renews on each anniversary of the effective
date after the initial three year employment term, for an additional one year
unless we notify Mr. Larkin in writing 90 days prior to such anniversary that we
will not be renewing his employment agreement.
In connection with our acquisition of Pedco, we entered into employment
agreements on September 14, 2000 with Messrs. James C. Johnson, Jr. and Gregory
S. Johnson effective through August 31, 2003. Jim Johnson is paid a base salary
of $200,000 a year and serves as our Executive Vice President and as President
of Pedco. Greg Johnson is paid a base salary of $185,000 a year and serves as
our Senior Vice President and Vice President of Pedco. Pursuant to these
agreements, the base compensation may be increased on an annual basis. These
agreements also provide for an annual bonus, up to 100% of base compensation, to
be determined in the sole discretion of the board of directors. In addition,
each officer was awarded 400,000 options to purchase shares of our common stock
at an exercise price of $4.00 per share. Of these 400,000 options, 200,000
options vested immediately, with 100,000 options vested at September 1, 2001 and
100,000 will vest at September 1, 2002. The agreements also provide for
participation in the benefit plan generally available to our senior executives,
four weeks paid vacation, and business expense reimbursement. Pursuant to the
agreements, we can terminate their employment with or without cause. Each
agreement automatically terminates upon the death or disability of the
respective officer. Upon termination, Messrs. Johnson and Johnson are entitled
to receive all compensation and benefits through the date of termination. If
terminated without cause or as a result of death or disability, the officers
will receive severance pay in an amount equal to the greater of the balance of
his remaining and unpaid base compensation due under the employment agreement,
or his annual base compensation less all required withholdings. If terminated
with or without cause, the officers can maintain all unvested options provided
by the equity incentive plan or, at their option, sell them back to us.
59
We entered into an employment agreement on June 25, 2001 with Mr. David E.
Fleming, our Senior Vice President and General Counsel, that provides for a
salary of $210,000 per year, guaranteed annual bonus compensation equal to 50%
of his annual base salary, participation in our standard insurance plans for our
executives, and participation in our other incentive compensation programs at
the discretion of the board of directors. The employment agreement is for an
initial three-year term and also provides that all stock options held by Mr.
Fleming are subject to accelerated vesting in the event of his termination
without cause or in the event of a change of control. Under his employment
agreement, Mr. Fleming is entitled to receive stock options to purchase 150,000
shares of common stock at the exercise price of $10.00 per share for a period
expiring five years from date of issuance. The options to purchase common stock
vest at the rate of 50% upon issuance, 25% one year after the date of the grant
and 25% two years after the date of the grant. If Mr. Fleming's employment is
terminated without cause, Mr. Fleming is entitled to termination compensation
equal to the greater of two years annual base salary, plus the bonus amount paid
in the preceding fiscal year, or all of the base salary for the remainder of the
employment term, plus the preceding year's bonus compensation. Mr. Fleming's
employment agreement automatically renews on each anniversary of the effective
date after the initial three year employment term, for an additional one year
unless we notify Mr. Fleming in writing 90 days prior to such anniversary that
we will not be renewing his employment agreement.
We entered into an employment agreement on May 2, 2001 with Mr. Jack B.
King, our Vice President and National Sales Director, that provides for a salary
of $200,000 per year, participation in our standard insurance plans for our
executives, and participation in our other incentive compensation programs at
the discretion of the board of directors. The employment contract also provides
for an incentive cash compensation plan for 2001 which consists of the
following: an override of 0.3% of drilling funds raised nationally over the
entire wholesaler network; an additional override for the first two years of
0.25% of drilling funds raised nationally by the wholesaler network for all new
broker dealers Mr. King personally adds to the wholesaler network; and a
percentage of the drilling funds raised in Mr. King's territory based on a
sliding scale equal to 1.00% of $0-$7.5 million raised, 1.50% of $7.5 million to
$15 million raised, and 2.00% if the amount raised is greater than $15 million.
Mr. King is also entitled to a budget of 1.7% of all drilling funds raised
nationally by the wholesaler network for agreed marketing expenses. If the total
expenses for 2001, net of reimbursements, are less than 1.7% of the drilling
funds raised nationally, the difference will be added to Mr. King's incentive
compensation. The term of Mr. King's employment contract ends on December 31,
2001.
Employee Benefit Plans
2000 Equity Incentive Plan for Employees of Petroleum Development Corporation
Introduction. Our 2000 Equity Incentive Plan for Employees of Pedco was
adopted by the board in September 2000 and was amended by the board in September
2001, and is subject to approval by our shareholders. Any awards granted before
shareholder approval of the plan are subject to, and may not be exercised or
realized before, approval of the plan by the shareholders. The plan is
administered by our compensation committee.
Share Reserve. 1,975,000 shares of common stock have been authorized for
issuance under the plan. In addition, no participant in the plan may be granted
stock options and direct stock issuances for more than 750,000 shares of common
stock in total per calendar year.
60
Awards. The plan provides for the following types of awards:
o eligible individuals in the employ of, or rendering services to,
Pedco and its subsidiaries may be granted options to purchase
shares of common stock at an exercise price determined by the
compensation committee;
o eligible individuals may be issued shares of common stock that
may be subject to certain restrictions and conditions directly
through the purchase of shares at a price determined by the
compensation committee.
Plan Features. The plan will include the following features:
o eligible participants under the plan are employees, consultants
and directors of Pedco and its subsidiaries.
o the plan sets forth various restrictions upon the exercise of
awards. The compensation committee has the discretion to alter
any restrictions or conditions upon any awards.
o the exercise price for any options granted under the plan may be
paid in cash, by certified or cashier's check or, if acceptable
to the compensation committee, in property valued at fair market
value, by delivery of a promissory note, or in currently owned
shares of common stock valued at fair market value on the last
business day prior to the date of exercise. An option may, in the
discretion of the compensation committee, be exercised through a
sale or loan program with a broker acceptable to the compensation
committee without any cash outlay by the optionee.
o grants of restricted stock awards can be made to participants.
Restricted stock awards may be subject to certain restrictions,
vesting requirements or other conditions, including the
attainment of performance goals.
o if a participant's employment is terminated for any reason other
than cause, including death or disability, any vested options
held by the participant will remain exercisable for a specified
period of time after the termination. If a participant's
employment is terminated for cause, all outstanding options held
by the participant will expire immediately. If a participant's
employment is terminated for any reason other than cause, any
unvested restricted stock awards will generally be forfeited
unless the compensation committee provides otherwise. If a
participant's employment is terminated for cause, all restricted
stock awards will be forfeited. Warren may require the return of
any dividends previously paid on the restricted stock and, in all
events, will repay to the participant (or the participant's
estate) any amounts paid for the restricted stock awards.
Change in Control. In the event that Warren or Pedco is acquired by merger,
consolidation, asset sale or equity sale, outstanding options will be assumed,
or equivalent options will be issued by the successor corporation. If the
successor corporation refuses to assume or substitute the options, the
compensation committee may accelerate the participants' rights to exercise for a
limited period of time after which the options would terminate. With respect to
restricted stock awards, the compensation committee could also elect to
terminate any vested awards in exchange for cash payments.
61
Recapitalization or Reorganization. In the event of a recapitalization or
reorganization of Warren or of Pedco that does not constitute a
change-in-control as described above, a participant will be entitled to receive,
upon exercising an option, that which the participant would have received had
the participant exercised prior to the recapitalization or reorganization.
Amendment. The board may amend or modify the 2000 Plan at any time, pending
any required shareholder approval. The 2000 Plan will terminate no later than
September 1, 2010.
As of December 31, 2001, nonqualified stock options to purchase 1,770,000
shares of our common stock were granted to eligible persons pursuant to this
plan at exercise prices of $4.00 and $10.00 per share, subject to the approval
of this plan by our shareholders. None of these options has been exercised.
Unexercised options to purchase 929,250 shares are vested as of December 31,
2001, and the balance of the options will vest over the next three years. The
shares that may be issued pursuant to the exercise of an option awarded under
this plan have not been registered under the Securities Act of 1933.
2001 Stock Incentive Plan
Introduction. Our 2001 Stock Incentive Plan was adopted by the board in
September 2001 and is subject to approval by our shareholders. Any awards
granted before shareholder approval of the plan are subject to, and may not be
exercised or realized, before approval of the plan by the shareholders. The plan
will be administered by our compensation committee.
Share Reserve. A total of 2,500,000 shares of our common stock have been
authorized for issuance of options under the plan. In addition, no participant
in the plan may be granted stock options, separately exercisable stock
appreciation rights, direct stock issuances and stock units for more than
750,000 shares of our common stock in total per calendar year.
Programs. The plan is divided into three separate programs:
o an option grant program under which eligible individuals may be
granted options to purchase shares of common stock at an exercise
price determined by the compensation committee;
o a stock appreciation rights program under which eligible
individuals may be granted rights to receive payments equal to
the fair market value of shares of common stock to which the
right is subject on the date of exercise over the fair market
value of such shares of common stock on the date of grant; and
o a stock issuance program under which eligible individuals may be
issued shares of common stock directly through the purchase of
shares at a price determined by the compensation committee, or
units representing such shares.
Plan Features. The plan includes the following features:
o eligible individuals under the plan are employees, consultants
and directors of Warren and our subsidiaries.
o the plan sets forth various restrictions upon the exercise of
awards. Our compensation committee has the discretion to
accelerate the vesting or exercisability of options under certain
events.
o the exercise price for any options granted under the plan may be
paid in cash or, if acceptable to the compensation committee, in
currently owned shares of common stock valued at fair market
value on the exercise date. The option may, in the discretion of
the compensation committee, be exercised through a sale or loan
program with a broker acceptable to the compensation committee
without any cash payment by the option holder.
62
o deferred compensation stock options may be issued under the stock
option program. These options will provide a means by which
compensation payments can be deferred to future dates, with the
number of shares of common stock subject to a deferred
compensation stock option being determined by the compensation
committee in accordance with a formula where the number of shares
subject to the option is equal to the amount of compensation to
be deferred divided by the excess of the fair market value of the
common stock at the time of exercise over the exercise price of
the option.
o stock appreciation rights may be separately issued entitling a
participant to receive an amount equal to the excess of the fair
market value of the shares of common stock subject to such right
on the date of exercise over the fair market value of such shares
on the date of grant. Payment to a participant may be made in:
cash, shares of common stock, a deferred compensation option, or
any combination of the above, as the compensation committee shall
determine.
o outright grants of stock awards, as well as grants of restricted
stock awards and restricted stock units can be made to
participants. In order for a participant to vest in an award of
either restricted stock or a restricted stock unit, the
participant must generally provide services for a continuous
period of not less than two years. A participant shall be
entitled to receive payment for a restricted stock unit in an
amount equal to aggregate fair market value of the units covered
by the award at the end of the applicable vesting restriction
period, which payment can be made in: cash, shares of common
stock, deferred compensation stock options, or any combination of
the above, as the compensation committee shall determine.
o if a participant's employment is terminated for any reason,
including death and disability, any vested awards held by the
participant will remain exercisable for a specified period of
time after the termination. If a participant retires, but
continues or begins to serve as a director, the participant may
continue to hold any awards granted under the original terms
thereof.
Change in Control. The plan includes change in control provisions which may
result in the accelerated vesting of outstanding option grants and stock
issuances:
o In the event that Warren is acquired by merger or asset sale or
there is an acquisition of more than fifty percent of the capital
stock of Warren by an individual, entity or group, the vesting
schedule of each outstanding award will be, except to the extent
specifically provided to the contrary in the instrument
evidencing the award, or any other agreement between a
participant and us, accelerated in part so that one-half of the
number of shares subject to such award shall become immediately
exercisable or realizable and the remaining one-half of such
number of shares shall continue to be exercisable or realizable
in accordance with the original vesting schedule.
63
o In the event there is a merger of Warren, or an exchange of
shares for cash, securities or other property in connection with
an exchange transaction, which does not constitute a
change-in-control as described above, the board shall provide
that all outstanding options will be assumed or equivalent
options substituted by the acquiring or succeeding corporation.
With respect to all other awards, the board will determine the
effect the transaction will have on such awards at the time the
transaction takes place.
Amendment. The board may amend or modify the 2001 Plan at any time, pending
any required shareholder approval. The 2001 Plan will terminate no later than
September 5, 2011.
As of December 31, 2001, non-qualified stock options to purchase 1,143,738
shares of our common stock have been granted to eligible persons pursuant to
this plan at exercise prices of $10.00 per share, subject to the approval of
this plan by our shareholders. None of these options has been exercised. The
shares that may be issued pursuant to the exercise of an option awarded under
this plan have not been registered under the Securities Act of 1933.
2001 Key Employee Stock Incentive Plan
Our 2001 Key Employee Stock Incentive Plan was adopted by the board on
September 6, 2001, and is subject to approval by our shareholders. A total of
2,500,000 shares of our common stock have been authorized for issuance under
this plan. In addition, no participant in the plan may be granted stock options,
separately exercisable stock appreciated rights or direct stock issuances for
more than 750,000 shares of common stock in total per calendar year. This plan
will be administered by our compensation committee. The plan is modeled after
the 2001 Employee Stock Incentive Plan and its terms are substantially similar
except that participants eligible to be granted awards under the plan will be
limited to our key employees.
As of December 31, 2001, non-qualified stock options to purchase 1,501,875
shares of our common stock have been granted to eligible persons at exercise
prices of $10.00 per share pursuant to this plan, subject to the approval of
this plan by our shareholders. None of these options have been exercised.
Unexercised options to purchase 1,089,375 shares vested as of December 31, 2001,
and the balance of the options will vest over the next three years. The shares
that may be issued pursuant to the exercise of an option awarded by this plan
have not been registered under the Securities Act of 1933.
Related Matters
A private investigation by the SEC involving events which occurred in the
mid to late 1970's was concluded by settlement between Swanton Corporation and
certain affiliates, including Mr. Swanton, and the SEC in 1981. As a result of
the settlement, Mr. Swanton and Swanton Corporation, without admitting or
denying any of the allegations, consented to the entry of a final judgment
enjoining them from violations of anti-fraud, periodic reporting and beneficial
ownership provisions of the Exchange Act of 1934 and agreed to engage a Special
Review Person to determine whether there had been any improper use of corporate
funds. The Special Review Person found that, although there was no wrongdoing on
the part of Mr. Swanton, $20,400 received by him from an unaffiliated debtor
should have been paid to Swanton Corporation. Mr. Swanton thereafter paid the
$20,400 to Swanton Corporation.
Item 12: Securities Ownership of Certain Beneficial Owners and Management.
The following table sets forth information regarding the beneficial
ownership of our common stock as of March 29, 2002 by:
o each of our directors;
o our chief executive officer;
o our four most highly compensated executive officers other
than our chief executive officer; and
o all directors and executive officers as a group.
64
As of March 29, 2002, we do not know of any other person to own beneficially
more than 5% of our common stock.
Unless otherwise indicated, each person named in the table has sole voting
power and investment power, or shares this power with his or her spouse, with
respect to all shares of our common stock listed as owned by such person. The
table includes all shares beneficially owned by each stockholder, which includes
any shares as to which the individual has sole or shared voting power or
investment power and any shares which the individual has the right to acquire
within 60 days of March 29, 2002 through the exercise of any stock option or
other right.
Shares of Common Stock Percent of
Name of Beneficial Owner Beneficially Owned Ownership
- ------------------------------------------------ ----------------------- -----------
Norman F. Swanton(1) (2) 2,504,733 14.3%
James C. Johnson, Jr. (3) 1,152,500 6.6%
Gregory S. Johnson(3) 1,002,500 5.7%
Timothy A. Larkin(2) 50,000 *
David E. Fleming(2) 10,000 *
Jack B. King(4) 17,707 *
Dominick D'Alleva(4) 45,521 *
Anthony L. Coelho(4) -0- -0-
Lloyd G. Davies(4) -0- -0-
Victor E. Millar(4) 269,501 1.5%
Marshall Miller(4) 739,000 4.2%
Thomas G. Noonan(4) (5) 744,333 4.2%
James A. Thompson(4) 32,154 *
Michael R. Quinlan(4) 78,000 *
All directors and executive officers as a group (14 persons)(2) (4) 6,645,949 37.9%
- -------------------
* Less than 1% of the outstanding common stock.
(1) Does not include 368,000 shares of common stock owned by the Swanton Family
Trust and 368,000 shares of common stock owned by the Virginia Trust of
Eire, as to which Mr. Noonan and his wife are the trustees. The nieces and
nephews of Mr. Swanton are the sole beneficiaries of these trusts. Mrs.
Noonan is Mr. Swanton's sister. Includes 25,000 shares owned by a
charitable foundation for which Mr. Swanton is a trustee.
(2) Does not include stock options exercisable at $10.00 per share for a period
of five years approved by the compensation committee of the board of
directors on September 6, 2001, which grant shall become effective upon
approval of the 2001 Key Employee Stock Incentive Plan by the shareholders
as follows: 600,000 for Norman F. Swanton; 676,875 for Timothy A. Larkin;
and 150,000 for David E. Fleming.
(3) Includes the following shares of common stock issuable upon exercise of
options that are currently exercisable or exercisable within 60 days of
September 30, 2001: 300,000 for James C. Johnson, Jr.; and 300,000 for
Gregory S. Johnson.
(4) Does not include stock options exercisable at $10.00 per share for a period
of five years approved by the compensation committee of the board of
directors on September 6, 2001 which grant shall become effective upon
approval of the 2001 Stock Incentive Plan by the shareholders as follows:
10,000 for Thomas Noonan; 10,000 for Dominick D'Alleva; 10,000 for Victor
Millar; 10,000 for Marshall Miller; 10,000 for James Thompson; 25,000 for
Anthony Coelho; 25,000 for Lloyd Davies; 25,000 for Michael Quinlan; and
380,631 for Jack King.
(5) Includes 368,000 shares of common stock owned by the Swanton Family Trust
and 368,000 shares of common stock owned by the Virginia Trust of Eire. Mr.
Noonan and his wife are the trustees of these trusts. The nieces and
nephews of Mr. Swanton are the sole beneficiaries of these trusts. Mr.
Noonan disclaims beneficial ownership of the shares of common stock held by
the Swanton Family Trust and the Virginia Trust of Eire.
65
Item 13: Certain Relationships and Related Transactions.
Acquisition of Pedco
On September 1, 2000, we purchased all of the outstanding shares of stock
of Pedco and a mortgage held by Pedco and Pedco's shareholders, then valued at
$117,228, from Pedco's shareholders in exchange for a total of 1,600,000 shares
of our common stock valued on that date at $4.00 per share. At that time, Mr.
James Johnson, Jr. and Mr. Gregory Johnson were the sole shareholders of Pedco.
As part of this transaction, each of them executed an employment agreement with
Warren and received options to purchase 400,000 shares of our common stock at an
exercise price of $4.00 per share. See "Item 11-Executive Compensation-Employee
Benefit Plans." Between January 1 and the date of the acquisition, we paid
$16,685,000 to Pedco pursuant to joint venture agreements and operating
agreements related to property acquisition, equipment and operational services
they performed for us and our drilling programs during that time. See "Items 1
and 2--Business and Properties-Drilling Programs" for more information about
Pedco and our drilling programs.
Officer and Director Participation in our Drilling Programs
Our officers and directors own, in the aggregate, limited partnership
interests valued at $2,788,333 at the time of purchase in 15 of our drilling
programs. Mr. Swanton owns $528,333 of interests in twelve programs. Mr. King
owns $310,000 of interests in three programs. Mr. Millar owns $260,000 of
interests in three programs. Mr. Quinlan owns $2,100,000 of interests in five
programs, including a 16.67% interest one program. Mr. Thompson owns $25,000 of
interests in one program. Other than Mr. Quinlan's interest in one drilling
program, no officer or director owns greater than a 10% interest in any
particular drilling program.
Retention of ColumbusNewport
On January 2, 2001, we retained the services of ColumbusNewport, a venture
capital and consulting services firm for the purpose of providing us with
strategic business and consulting services. Mr. Millar is the Chairman of the
Board and owner of approximately 21% of ColumbusNewport. Mr. Coelho is a member
of the board of directors of ColumbusNewport. We paid ColumbusNewport $11,660 in
fees during 2000 and $392,606 during 2001.
The Thompson Group
Since December 1994, we have employed the services of The Thompson Group,
Inc., a broker-dealer firm and member of the NASD to assist us in the sale of
our drilling programs and private placement of bonds. Mr. Thompson, one of our
directors, is the principal of The Thompson Group. In 1999, we paid The Thompson
Group $322,965 in commissions, $283,613 in 2000 and $22,000 in 2001. Currently,
we have no outstanding balance payable to The Thompson Group.
Indebtedness of Management
During 2000, Mr. Swanton, our Chairman of the Board and Chief Executive
Officer, was indebted to us for approximately $172,000, including accrued
interest at a rate of 7.0% per annum. These debts were paid in full on June 22,
2001. Mr. Swanton was indebted to us for a maximum amount of $67,000, including
accrued interest at a rate of 7% per annum in 1998 and a maximum amount of
$68,000, including accrued interest at a rate of 7% per annum in 1999. The loans
were ratified by our board of directors.
66
PART IV
Item 14: Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) (1) Financial Statements
Form 10-K
Pages
---------
Report of Independent Public Accountants F-2
Consolidated Balance Sheets, December 31, 2001 and 2000 F-3
Consolidated Statements of Operations for the Years Ended
December 31, 2001, 2000 and 1999 F-4
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 2001, 2000 and 1999 F-5
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2001, 2000 and 1999 F-6
Notes to Consolidated Financial Statements, F-8
December 31, 2001, 2000 and 1999
(a)(2) All other schedules have been omitted because the required information is
inappliacble or is shown in the Notes to the Consolidated Financial Statements.
(a)(3) Exhibits required to be filed by Item 601 of Regulation S-K.
Exhibit
No. Description
- ------ __________________________________
2.1* Stock Exchange Agreement, dated September 1, 2000, by and among the Registrant, Petroleum Development
Corporation, James C. Johnson, Jr. and Gregory S. Johnson.
3.1* Certificate of Incorporation of Registrant dated June 11, 1990
3.2* Amendment to Certificate of Incorporation of Registrant dated November 15, 1990
3.3* Amendment to Certificate of Incorporation of Registrant dated November 4, 1992
3.4* Amendment to Certificate of Incorporation of Registrant dated September 3, 1996
3.5* Bylaws of the Registrant, dated June 12, 1990
4.1* Form of Stock Certificate for Common Stock
4.2* Indenture between the Registrant and Continental Stock Transfer and Trust Company, as Trustee, dated
December 1, 2000 regarding 12% debentures due December 31, 2007
4.3* Form of Bond Certificate for 12% debentures due December 31, 2007
4.4* Indenture between the Registrant and Continental Stock Transfer
and Trust Company, as Trustee, dated February 1, 1999 regarding
13.02% debentures due December 31, 2010 and December 31, 2015
4.5* Form of Bond Certificate for 13.02% debentures due December 31, 2010
4.6* Form of Bond Certificate for 13.02% debentures due December 31, 2015
4.7* Form of Class A Warrant
4.8* Form of Class B Warrant
4.9* Form of Class C Warrant
4.10* Form of Class D Warrant
10.1* 2000 Equity Incentive Plan for Pedco Subsidiary
10.2* Amendment to 2000 Stock Incentive Plan for Pedco Subsidiary
10.3* 2001 Stock Incentive Plan
10.4* 2001 Key Employee Stock Incentive Plan
10.5* Employment Agreement dated January 1, 2001, between the Registrant and Norman F. Swanton
10.6* Employment Agreement dated January 1, 2001, between the Registrant and Timothy A. Larkin
10.7* Employment Agreement dated September 14, 2000, between the Registrant and James C. Johnson, Jr.
10.8* Employment Agreement dated September 14, 2000, between the Registrant and Gregory S. Johnson
10.9* Employment Agreement dated May 7, 2001, between the Registrant and Jack B. King
10.10* Employment Agreement dated June 25, 2001, between the Registrant and David E. Fleming
10.11* Form of Indemnification Agreement
10.12* Joint Venture Agreement dated May 24, 1999, by and between Warren Resources of California, Inc., Warren
Development Corp., Pedco and Magness Petroleum Company
67
Exhibit
No. Description
- ------ __________________________________
10.13** Crude Oil Sale and Purchase Contract dated November 7, 1996, between Huntway Refining Company and
Magness Petroleum Company
10.14* May 11, 2000 Agreement to Amend the Price and Term Clauses of the Crude Oil Sale and Purchase Contract
dated November 7, 1996, between Huntway Refining Company and Magness Petroleum Company
10.15* Gas Purchase Agreement dated January 28, 2000, by and between Western Gas Resources, Inc. and Big Basin
Petroleum, LLC
10.16* December 20, 2000 Letter of Agreement to Amend the Gas Purchase Contract dated January 28, 2000, between
Western Gas Resources Inc. and Petroleum Development Corp., as successor in interest to Big Basin
Petroleum, LLC
10.17* Gas Purchase and Sales Contract dated April 1, 2000, between the Registrant and Tenaska Marketing
Ventures
10.18* Form of Partnership Production Marketing Agreement
11+ Statements regarding Computation of Per Share Earnings (included in Item 14)
23.1 + Consent of Williamson Petroleum Consultants, Inc.
- -------------------------
*Incorporated by reference to the Company's Registration Statement on Form 10,
Commission File No. 000-33275, filed on October 26, 2001.
**Incorporated by reference to the Company's Amendment No. 1 to Registration
Statement on Form 10/A, Commission File No. 000-33275, filed on March 6, 2002.
+ Filed herewith.
(b) Reports on Form 8-K
On December 26, 2001, the Company filed a Current Report on Form 8-K to
disclose that the registration statement on Form 10 originally filed on October
26, 2001 became automatically effective December 25, 2001 pursuant to Section
12(g) of the Securities Exchange Act of 1934. However, the review and comment
process by the Securities and Exchange Commission was not completed as of that
date. Accordingly, because the Company would file an amended Form 10 in response
to the SEC's comments, the Form 10 as filed on October 26, 2001 was subject to
substantial revision, the inclusion of financial information and statements for
the quarter ended September 30, 2001, the revision of prior period financial
statements, changes in the reserve information and valuations and updated
disclosures regarding the Company.
68
SIGNATURES
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 authorized.
WARREN RESOURCES INC.
By /s/ Norman F. Swanton President, Chief
----------------------- Executve Officer,
Norman F. Swanton Director and Chairman
By /s/ Timothy A. Larkin Senior Vice President,
----------------------- Chief Financial Officer
Timothy A. Larkin and Principal Accounting
Officer
Dated: April 15, 2002
Pursuant to the requirements of the Securities and Exchange Act of 1934,
this Report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title (Principal Function) Date
/s/ Norman F. Swanton
-------------------------------- President, Chief Executive April 15, 2002
Norman F. Swanton Officer, Director and Chairman
/s/ Timothy A. Larkin Senior Vice President, Chief
-------------------------------- Financial Officer and April 15, 2002
Timothy A. Larkin Principal Accounting Officer
/s/ Anthony Coelho
-------------------------------- Director April 15, 2002
Anthony Coelho
/s/ Lloyd Davies
-------------------------------- Director April 15, 2002
Lloyd Davies
/s/ Dominick D'Alleva
-------------------------------- Director April 15, 2002
Dominick D'Alleva
/s/ Victor Millar
-------------------------------- Director April 15, 2002
Victor Millar
/s/ Marshall Miller
-------------------------------- Director April 15, 2002
Marshall Miller
/s/ Thomas Noonan
-------------------------------- Director April 15, 2002
Thomas Noonan
/s/ Michael R. Quinlan
-------------------------------- Director April 15, 2002
Michael R. Quinlan
/s/ James Thompson
-------------------------------- Director April 15, 2002
James Thompson
69
INDEX TO FINANCIAL STATEMENTS
Page
----
Report of Independent Certified Public Accountants F-2
Consolidated Balance Sheets as of December 31, 2001 and 2000 F-3
Consolidated Statements of Operations for the years ended
December 31, 2001, 2000 and 1999 F-4
Consolidated Statement of Stockholders' Equity (Deficit)for
the years ended December 31, 2001, 2000 and 1999 F-5
Consolidated Statements of Cash Flows for the years ended
December 31, 2001, 2000 and 1999 F-6
Notes to Consolidated Financial Statements F-8
F-1
Report of Independent Certified Public Accountants
--------------------------------------------------
Board of Directors
Warren Resources Inc.
We have audited the accompanying consolidated balance sheets of Warren Resources
Inc. and Subsidiaries as of December 31, 2001 and 2000, and the related
consolidated statements of operations, stockholders' equity (deficit) and cash
flows for each of the three years in the period ended December 31, 2001. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. 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 Warren Resources
Inc. and Subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001 in conformity with accounting principles generally accepted in
the United States of America.
As discussed in Note A to the consolidated financial statements, effective
January 1, 2001 the Company changed its method of accounting for derivative
instruments and hedging activities.
GRANT THORNTON LLP
Oklahoma City, Oklahoma
March 8, 2002
F-2
Warren Resources Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
December 31,
ASSETS 2001 2000
------------- --------------
CURRENT ASSETS
Cash and cash equivalents $ 22,923,605 $ 58,969,552
Accounts receivable - trade 5,543,326 5,819,049
Accounts receivable from affiliated partnerships 801,661 779,921
Investments in U.S. Treasury bonds - trading securities - 103,857
Other investments - trading securities 205,989 337,659
Restricted investments in U.S. Treasury bonds - available for sale, at
fair value (amortized cost of $1,142,637 in 2001 and $540,652 in 2000) 1,187,123 592,719
Other current assets 1,294,986 1,965,834
Assets held for sale 3,757,900 -
------------ -------------
Total current assets 35,714,590 68,568,591
OTHER ASSETS
Oil and gas properties - at cost, based on successful efforts method of
accounting, net of accumulated depletion and amortization 39,974,798 35,930,025
Property and equipment - at cost, net 891,304 5,529,388
Restricted investments in U.S. Treasury bonds - available for sale, at
fair value (amortized cost of $7,399,989 in 2001 and $7,037,660 in 2000) 7,791,555 7,778,953
Deferred bond offering costs, net of accumulated amortization of $2,535,160
in 2001 and $2,115,711 in 2000 3,905,908 4,348,038
Goodwill 3,430,246 3,922,868
Other assets 3,191,813 2,571,035
------------ -------------
59,185,624 60,080,307
------------ -------------
$ 94,900,214 $ 128,648,898
============ =============
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES
Current maturities of debentures $ 4,747,370 $ 3,598,350
Current maturities of other long-term liabilities 392,721 1,371,846
Accounts payable and accrued expenses 6,511,137 7,762,772
Deferred income - turnkey drilling contracts with affiliated partnerships 32,943,586 45,563,281
------------ -------------
Total current liabilities 44,594,814 58,296,249
LONG-TERM LIABILITIES
Debentures, less current portion 53,391,330 55,055,150
Other long-term liabilities, less current portion 29,191 421,911
Contingent repurchase obligation 3,318,993 -
------------ -------------
56,739,514 55,477,061
STOCKHOLDERS' EQUITY (DEFICIT)
Common stock - $.001 par value; authorized, 20,000,000 shares; issued
17,537,579 shares in 2001 and 17,528,261 shares in 2000 17,538 17,528
Additional paid-in capital 52,197,669 52,187,679
Accumulated deficit (58,903,571) (37,829,979)
Accumulated other comprehensive income, net of applicable income taxes
of $171,792 in 2001 and $293,000 in 2000 264,260 500,360
------------ -------------
(6,424,104) 14,875,588
Less common stock in Treasury - at cost; 4,563 shares in 2001 and
none in 2000 10,010 -
------------ -------------
(6,434,114) 14,875,588
------------ -------------
$ 94,900,214 $ 128,648,898
============ =============
The accompanying notes are an integral part of these statements.
F-3
CONSOLIDATED STATEMENTS OF OPERATIONS
Year ended December 31,
2001 2000 1999
----------- ----------- ------------
REVENUES
Turnkey contracts with affiliated partnerships $ 30,102,946 $33,984,960 $ 25,405,838
Oil and gas sales from marketing activities 14,866,954 15,420,917 -
Well services, 12% with affiliated partnerships in 2001 5,574,335 4,297,414 2,611,226
Oil and gas sales 948,270 200,330 68,054
Net gain (loss) on investments (10,337) 587,349 (1,103,648)
Interest and other income 1,977,082 2,457,146 1,641,629
------------ ----------- ------------
53,459,250 56,948,116 28,623,099
EXPENSES
Turnkey contracts 25,953,340 22,783,248 18,126,223
Cost of marketed oil and gas purchased from affiliated partnerships 15,298,842 15,800,258 -
Well services 3,519,085 3,167,550 1,351,341
Production and exploration 567,756 355,347 42,681
Depreciation, depletion and amortization 14,462,119 3,065,460 9,197,683
General and administrative 5,484,773 6,416,043 4,491,078
Interest 5,776,234 6,967,850 5,791,321
Contingent repurchase obligation 3,318,993 - -
------------ ----------- ------------
74,381,142 58,555,756 39,000,327
------------ ----------- ------------
Loss before provision for income taxes (20,921,892) (1,607,640) (10,377,228)
PROVISION FOR INCOME TAXES
Deferred income tax expense (benefit) 151,700 (412,000) 702,000
------------ ----------- ------------
NET LOSS $(21,073,592) $ (1,195,640) $(11,079,228)
============ ============ ============
BASIC AND DILUTED LOSS PER SHARE $ (1.20) $ (.10) $ (1.00)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 17,532,882 12,461,814 11,115,522
The accompanying notes are an integral part of these statements.
F-4
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (DEFICIT)
Years ended December 31, 2001, 2000 and 1999
Accumulated Total
Common stock Additional other stockholder's
-------------------- Paid-in Accumulated Comprehensive Treasury equity
Shares Amount capital deficit income (loss) Stock (deficit)
---------- -------- ----------- ------------ ------------- -------- ----------
Balance at January 1, 1999 11,085,750 $ 11,086 $20,766,876 $(25,555,111) $ 993,186 $ - $ (3,783,963)
Repurchase of common stock (7,500) (8) (27,592) - - - (27,600)
Shares issued from exercise of Class C
warrants 41,000 41 204,959 - - - 205,000
Shares issued from exercise of Class B exchange
warrants 2,789 3 661 - - - 664
Shares issued from exercise of Class C exchange
warrants 938 1 4,503 - - - 4,504
Shares issued from exercise of Class D warrants 563 1 4,501 - - - 4,502
Issuance of Class C warrants - - 15,520 - - - 15,520
Sale of common stock from offering 337,648 338 1,255,705 - - - 1,256,043
Conversion to common stock from convertible
debentures 6,250 6 24,994 - - - 25,000
Conversion from common stock to convertible
debentures (12,500) (13) (49,987) - - - (50,000)
Warrants issued to nonemployees - - 8,828 - - - 8,828
Comprehensive loss
Net loss - - - (11,079,228) - - (11,079,228)
Other comprehensive loss
Net change in unrealized loss on investment
securities available for sale, net of
applicable income taxes - - - - (1,197,644) - (1,197,644)
------------
Total comprehensive loss ---------- -------- ----------- ------------ ------------ -------- (12,276,872)
------------
Balance at December 31, 1999 11,454,938 11,455 22,208,968 (36,634,339) (204,458) - (14,618,374)
Issuance of common stock 33,343 33 100,374 - - - 100,407
Repurchase of common stock (35,250) (35) (106,965) - - - (107,000)
Shares issued from exercise of Class B
warrants 909,178 909 1,652,080 - - - 1,652,989
Shares issued from exercise of Class C
warrants 1,020,689 1,021 3,320,606 - - - 3,321,627
Shares issued from exercise of Class D
warrants 1,178,709 1,179 8,858,961 - - - 8,860,140
Conversion to common stock from convertible
debentures 1,366,654 1,366 9,455,359 - - - 9,456,725
Acquisition of Petroleum Development
Corporation ("Pedco") 1,600,000 1,600 6,398,400 - - - 6,400,000
Extension of expiration period for Class B
warrants - - 139,399 - - - 139,399
Issuance of warrants - - 160,497 - - - 160,497
Comprehensive loss
Net loss - - - (1,195,640) - - (1,195,640)
Other comprehensive income
Net change in unrealized gain on
investment securities available for
sale, net of applicable income taxes - - - - 704,818 - 704,818
------------
Total comprehensive loss (490,822)
---------- -------- ----------- ------------ ------------ -------- ------------
Balance at December 31, 2000 17,528,261 17,528 52,187,679 (37,829,979) 500,360 - 14,875,588
Conversion to common stock from convertible
debentures 9,318 10 9,990 - - - 10,000
Purchase of Treasury stock - - - - - (10,010) (10,010)
Comprehensive loss
Net loss - - - (21,073,592) - - (21,073,592)
Other comprehensive loss
Cumulative effect of change in
accounting principle - - - - (1,449,930) - (1,449,930)
Reclassification adjustment for derivative
losses - - - - 1,449,930 - 1,449,930
Net change in unrealized gain on
investment securities available for
sale, net of an applicable income taxes - - - - (236,100) - (236,100)
------------
Total comprehensive loss (21,309,692)
---------- --------- ----------- ------------ ------------ -------- ------------
Balance at December 31, 2001 17,537,579 $ 17,538 $52,197,669 $(58,903,571) $ 264,260 $(10,010) $ (6,434,114)
========== ========= =========== ============ ============ ======== ============
The accompanying notes are an integral part of this statement.
F-5
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended December 31,
2001 2000 1999
------------ ------------ ------------
Cash flows from operating activities
Net loss $(21,073,592) $ (1,195,640) $(11,079,228)
Adjustments to reconcile net loss to net cash provided by operating
activities
Accretion of discount on available-for-sale debt securities (473,080) (502,017) (703,736)
Amortization and write-off of deferred bond offering costs 442,130 380,365 276,983
Gain on sale of U.S. Treasury bonds - available for sale (21,019) (541,722) (750,811)
Depreciation, depletion and amortization 14,462,119 3,065,460 9,197,683
Expense on issuance of warrants - 299,896 87,863
Common stock issued for services - 172,444 -
Deferred tax expense (benefit) 151,700 (412,000) 702,000
Change in assets and liabilities
Decrease in trading securities 235,527 2,642,565 8,824,823
(Increase) decrease in accounts receivable - trade 275,723 (3,564,306) (705,303)
Increase in accounts receivable from affiliated partnerships (21,740) (358,724) (209,941)
Decrease in restricted cash - - 1,741,723
(Increase) decrease in other assets 862,956 (961,253) (24,788)
Increase (decrease) in accounts payable and accrued expenses (1,251,636) 1,151,061 (4,356,848)
Increase (decrease) in deferred income from affiliated partnerships (12,619,695) 10,482,609 14,690,458
Increase (decrease) in contingent repurchase obligation to affiliated 3,318,993 - (1,188,844)
partnerships ------------ ------------ ------------
Net cash provided by (used in) operating activities (15,711,614) 10,658,738 16,502,034
Cash flows from investing activities
Purchases of U.S. Treasury bonds - available for sale (1,264,058) (4,584,677) (1,431,248)
Purchases of oil and gas properties (16,944,421) (20,957,501) (22,300,079)
Purchases of property and equipment (189,666) (28,227) (428,168)
Cash acquired from Pedco on acquisition - 629,896 -
Proceeds from U.S. Treasury bonds - available for sale 763,353 5,928,078 2,619,792
------------ ------------ ------------
Net cash used in investing activities (17,634,792) (19,012,431) (21,539,703)
Cash flows from financing activities
Proceeds from issuance of long-term debt - 15,390,000 16,886,000
Payments on long-term debt (1,876,645) (999,301) (169,373)
Proceeds from issuance of common stock - 13,762,717 1,486,233
Deferred bond offering costs - (1,345,270) (1,449,455)
Deferred offering costs (812,886) - -
Repurchase of common stock (10,010) (107,000) (27,600)
------------ ------------ ------------
Net cash provided by (used in) financing activities (2,699,541) 26,701,146 16,725,805
------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS (36,045,947) 18,347,453 11,688,136
Cash and cash equivalents at beginning of year 58,969,552 40,622,099 28,933,963
------------ ------------ ------------
Cash and cash equivalents at end of year $ 22,923,605 $ 58,969,552 $ 40,622,099
============ ============ ============
The accompanying notes are an integral part of these statements.
F-6
CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
Year ended December 31,
2001 2000 1999
------------ ------------ ------------
Supplemental disclosure of cash flow information
Cash paid for interest, net of amount capitalized $ 5,275,100 $ 6,386,551 $ 5,381,556
Cash paid for income taxes - - 33,000
Noncash investing and financing activities
Conversion to common stock from convertible securities 10,000 9,456,725 25,000
Conversion from common stock to convertible securities - - 50,000
During 2000, the Company acquired Pedco in exchange for 1,600,000 shares of
common stock (note J). In conjunction with the acquisition, assets were acquired
and liabilities were assumed as follows:
Estimated fair value of assets acquired, including cash and cash equivalents
of $629,896 $ 7,710,418
Liabilities assumed (1,310,418)
------------
Estimated fair value of common stock $ 6,400,000
============
During 1999, the Company acquired an additional 50% interest in a 25% owned
investee by the assumption of liabilities as follows:
Assets acquired $ 2,266,700
Cash paid -
-------------
Liabilities assumed $ 2,266,700
=============
The accompanying notes are an integral part of these statements.
F-7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
NOTE A - ORGANIZATION AND ACCOUNTING POLICIES
Nature of Operations
Warren Resources Inc. (the "Company"), a New York corporation, was formed
on June 12, 1990 for the purpose of acquiring and developing oil and gas
properties. Primarily, these properties are located in New Mexico, Texas,
Wyoming, Montana, North Dakota, Oklahoma, Michigan and California. In
addition, the Company serves as the managing general partner (the "MGP") to
affiliated partnerships and joint ventures. Also, the Company, through its
wholly owned subsidiaries, provides turnkey contract drilling services to
affiliated partnerships and joint ventures, well services including
engineering, maintenance, operations and well completion, recompletion and
workovers through nine workover/recompletion rigs and, commencing in 2000,
gas marketing and transportation services.
Management Plans
The Company has incurred a net loss of approximately $21,100,000 during
2001. At December 31, 2001, current liabilities exceeded current assets by
approximately $8,800,000 and total liabilities exceeded total assets by
approximately $6,400,000.
The 2001 net loss includes approximately $15,200,000 of non-cash charges
including oil and gas properties and drilling rig impairments and
recognition of a liability related to the Company's contingent obligation
to purchase partnership interests. The oil and gas impairment and
contingent repurchase obligation were measured using March 15, 2002 oil and
gas prices, which were significantly below prior year prices. During 2001,
the Company raised $18.1 million for its drilling programs compared to
$46.5 million and $40.9 million in 2000 and 1999, respectively. As a
result, the Company's turnkey revenue and total gross profit in 2002 will
be less than in 2001 and 2000 and the number of the Company's oil and gas
properties developed through partnership arrangements will be reduced.
In order to improve operations and liquidity and meet its cash flow needs,
the Company has or intends to do the following:
o Sold Pinnacle, the Company's work-over drilling rig subsidiary
for $4.2 million in February 2002 (see Notes C and R).
o Sell interests in some of our undeveloped oil and gas leases. The
Company is currently in extended negotiations for several sales
of a portion of our oil and gas interests which it is anticipated
will be closed in 2002. Although there are no definitive
agreements, the Company has received offers to buy certain of its
undeveloped oil and gas leases that have significantly
appreciated when compared to their original cost.
o Raise additional capital through the sale of preferred stock and
common stock.
o Obtain a credit facility based in part on the value of our proven
reserves.
o Continue privately placed drilling programs, which based on prior
experience management anticipates raising approximately $30
million in 2002.
F-8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE A - ORGANIZATION AND ACCOUNTING POLICIES - CONTINUED
Management Plans - Continued
o Generate turnkey profit and operating cash flow from our turnkey
drilling contracts equal to approximately 25% of the total amount
of turnkey price.
o Reduce fixed overhead expenses and primarily conduct development
drilling operations in the Company's two main target areas,
coalbed methane properties in Wyoming and oil formations in the
Wilmington field in California.
As a result of these plans, management belives that it will generate
sufficient cash flows to meet its current obligations in 2002.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company,
its wholly owned subsidiaries, Warren Development Corp., Warren Drilling
Corp., Petroleum Development Corporation ("Pedco") and CJS Pinnacle
Petroleum Services, LLC ("Pinnacle"). All significant intercompany accounts
and transactions have been eliminated in consolidation.
The Company conducts the majority of its oil and gas operations through
joint ventures and partnerships. The Company enters into joint venture
agreements with limited partnerships whereby the Company assigns a 75%
(before payout) working interest in an oil and gas lease to a limited
partnership while retaining a 25% (before payout) working interest. This
ownership interest is an undivided interest in the mineral rights and each
owner is responsible for its designated well expenditures. In exchange for
the 75% working interest, the limited partners pay intangible drilling
costs and, if a well is successful, the Company pays completion costs,
including lease and well equipment. The Company has a 25% interest in the
joint venture before payout and receives an additional reversionary 15%
interest once payout occurs. The Company also has a 10% interest in the
partnership revenue and expenses which increases to 25% once payout occurs.
Payout is achieved once the limited partners in a particular program
receive distributions equal to 100% of their original investment.
Distributions received by the participants are determined by the revenues
generated from the wells in each of the various programs less any
applicable lease operating expenses. Therefore, once payout is achieved,
the Company has a total interest of 55% in the net revenue generated from
all wells assigned to a particular program. The Company has subordinated
substantially all its general partner and joint venture rights to
production for 1998 and earlier partnerships until payout and its general
partner's interest in 1999 and later partnerships until payout. The Company
proportionately consolidates its share of the costs incurred on undivided
working interest of affiliated partnerships and joint ventures in the
accompanying consolidated financial statements. The Company primarily
incurs lease acquisition costs and completion costs, including lease and
well equipment, on wells developed in these partnerships and joint
ventures. All significant intercompany accounts and transactions have been
eliminated.
F-9
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE A - ORGANIZATION AND ACCOUNTING POLICIES - CONTINUED
Oil and Gas Properties
The Company uses the successful efforts method of accounting for oil and
gas properties. Under this methodology, costs incurred to acquire mineral
interests in oil and gas properties, to drill and equip exploratory wells
that find proved reserves and to drill and equip development wells are
capitalized. Costs to drill exploratory wells that do not find proved
reserves, geological and geophysical costs and costs of carrying and
retaining unproved properties are expensed.
Unproved oil and gas properties that are individually significant are
periodically assessed for impairment of value and a loss is recognized at
the time of impairment by providing an impairment allowance. Other unproved
properties are amortized based on the Company's experience of successful
drilling and historical lease expirations.
Capitalized costs of producing oil and gas properties are depleted by the
units-of-production method on a field-by-field basis. Lease costs are
depleted using total proved reserves while lease equipment and intangible
development costs are depleted using proved developed reserves. The
Company's proved properties are evaluated on a field-by-field basis for
impairment. An impairment loss is indicated whenever net capitalized costs
exceed expected future net cash flow based on engineering estimates. In
this circumstance, the Company recognizes an impairment loss for the amount
by which the carrying value of the properties exceeds the estimated fair
value (based on discounted cash flow).
On the sale or retirement of a complete unit of a proved property, the cost
and related accumulated depletion and amortization are eliminated from the
property accounts, and the resultant gain or loss is recognized. On the
retirement or sale of a partial unit of proved property, the cost is
charged to accumulated depletion and amortization with a resulting gain or
loss recognized in earnings.
On the sale of an entire interest in an unproved property, a gain or loss
on the sale is recognized, taking into consideration the amount of any
recorded impairment if the property had been assessed individually. If a
partial interest in an unproved property is sold, the amount received is
treated as a reduction of the cost of the interest retained.
Investment in CJS Pinnacle Petroleum Services, LLC
Pinnacle was formed in 1997 and at that time the Company obtained a 25%
interest through its initial capital contribution of $500 and a 9% loan to
Pinnacle of $1,800,000. The Company accounted for its 25% investment using
the equity method. On January 1, 1999, the Company acquired an additional
50% interest in Pinnacle by the assumption of liabilities of approximately
$2,267,000. Pinnacle operates as a drilling services company and is
incorporated in the state of Texas. Effective September 1, 2000, with the
acquisition of Pedco, Pinnacle became a 100% owned subsidiary (Note J). On
February 14, 2002, the Company completed the sale of substantially all of
the assets of Pinnacle (Notes C and R).
F-10
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE A - ORGANIZATION AND ACCOUNTING POLICIES - CONTINUED
Revenue Recognition
The Company enters into agreements with affiliated partnerships to drill
wells to completion for a fixed price. The Company, in turn, enters into
drilling contracts primarily with unrelated parties to drill wells on a day
work basis. Therefore, if problems are encountered on a well, the cost of
that well will increase and gross profit will decrease and could result in
a loss on the well. The Company recognizes revenue from the turnkey
drilling agreements on the percentage-of-completion method based on total
costs incurred to total estimated costs to complete. When estimates of
revenues and expenses indicate a loss, the total estimated loss is accrued.
Oil and gas sales result from undivided interests held by the Company in
various oil and gas properties. Sales of natural gas and oil produced are
recognized when delivered to or picked up by the purchaser. Oil and gas
sales from marketing activities result from sales by the Company of oil and
gas produced by affiliated joint ventures and partnerships and are
recognized when delivered to purchasers. Drilling rig revenues generated
from the Company's day rate drilling contracts, included in well services
revenue, are recognized as services are performed.
Cash and Cash Equivalents
The Company considers all highly liquid investments with maturities of
three months or less when acquired to be cash equivalents. The Company
maintains its cash and cash equivalents in bank deposit accounts which
exceed federally insured limits. At December 31, 2001, the Company had
approximately 82% of its cash and cash equivalents with one financial
institution. The Company has not experienced any losses in such accounts
and believes it is not exposed to any significant credit risk on cash and
cash equivalents.
Accounts Receivable
Accounts receivable include amounts due from affiliated partnerships and
joint ventures for advances and expenditures made by the Company on behalf
of such entities, as well as trade receivables. The Company reviews
accounts and notes receivable for collectibility and provides allowances on
specific accounts when the Company believes the collection is doubtful.
The Company grants credit to purchasers of oil and gas and owners of
managed properties, substantially all of whom are located in California,
Wyoming, New Mexico and Texas.
Investments
The Company classifies its debt and equity securities into two categories:
trading securities and available-for-sale securities. Trading securities,
classified as current assets, are recorded at fair value with net
unrealized gains or losses included in the determination of net earnings.
Available-for-sale securities are measured at fair value, with net
unrealized gains and losses excluded from net earnings and reported as
other comprehensive income (loss). Realized gains and losses are determined
on the basis of specific identification of the securities.
F-11
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE A - ORGANIZATION AND ACCOUNTING POLICIES - CONTINUED
Deferred Bond Offering Costs
Costs incurred in connection with the issuance of long-term debt are
capitalized and amortized over the term of the related debt using the
effective interest rate method.
Contingent Repurchase Obligation
The Company's contingent repurchase obligation represents the present
value of the Company's potential future obligation to affiliated
partnerships under repurchase agreements (Note G) based upon the excess of
the formula price for repurchase over the discounted present value of each
partnership's estimated future net revenues from its oil and gas properties
as determined by independent petroleum engineers.
Income Taxes
Deferred income taxes are recognized for the tax consequences in future
years of differences between the tax basis of assets and liabilities and
their financial reporting amounts based on enacted tax laws and statutory
rates applicable to the period in which the differences are expected to
affect taxable income. Valuation allowances are established when, in
management's opinion, it is more likely than not that a portion or all of
the deferred tax assets will not be realized.
Use of Estimates
In preparing financial statements, generally accepted accounting principles
require management to make estimates and assumptions in determining 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 revenues and expenses during the reporting period.
Actual results could differ from those estimates.
Gas Imbalances
The Company follows the sales method of accounting for gas imbalances. A
liability is recorded when the Company's excess takes of natural gas
volumes exceed its estimated remaining recoverable reserves. No receivables
are recorded for those wells where the Company has taken less than its
ownership share of gas production. The Company has no significant gas
imbalances.
Capitalized Interest
Interest of approximately $2,300,000 and $1,300,000 was capitalized during
the years ended December 31, 2001 and 2000, respectively, relating to a
major coal-bed methane development project that was not being currently
depreciated, depleted or amortized and on which exploration activities were
in progress during 2001 and 2000.
F-12
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE A - ORGANIZATION AND ACCOUNTING POLICIES - CONTINUED
Hedging Activities
During the year ended December 31, 2000, the Company entered into gas price
swaps to manage its exposure to gas price volatility for marketed gas. The
hedging instruments are usually placed with counterparties that the Company
believes are minimal credit risks. The gas reference prices upon which the
price hedging instruments are based reflect various market indices that
have a high degree of historical correlation with actual prices received by
the Company.
The Company accounted for its hedging instruments using the deferral method
of accounting through December 31, 2000. Under this method, realized gains
and losses from the Company's price risk management activities are
recognized in gas revenues when the associated sale occurs and the
resulting cash flows are reported as cash flows from operating activities.
Gains and losses on hedging contracts that are closed before the hedged
production occurs are deferred until the production month originally
hedged. In the event of a loss of correlation between changes in oil and
gas reference prices under a hedging instrument and actual oil and gas
prices, a gain or loss is recognized currently to the extent the hedging
instrument has not offset changes in actual oil and gas prices. For the
years ended December 31, 2001 and 2000, the Company hedged approximately
3,000 dekatherms of natural gas per day for the months April 2000 through
March 2001 based on the Inside FERC Index price and fixed floor and ceiling
prices of $2.50 and $3.55, respectively. For the years ended December 31,
2001 and 2000, the Company incurred losses on its hedging contracts of
approximately $509,000 and $1,600,000, respectively, which are reflected as
a reduction of gas sales from marketing activities.
The Company adopted the provisions under Statement of Financial Accounting
Standards ("SFAS") No. 133, Accounting for Derivative Instruments and
Hedging Activities, as amended, in the first quarter of its year ended
December 31, 2001. In accordance with the transition provisions of SFAS No.
133, the Company recorded a net-of-tax-cumulative-effect-type adjustment of
approximately $1,450,000 in accumulated other comprehensive loss to
recognize at fair value all derivatives that are designated as cash flow
hedging financial instruments. The Company's hedging agreements expired in
March 2001.
Accounting For Long-Lived Assets
The Company reviews property and equipment, certain identifiable intangible
assets and any goodwill relating to those assets for impairment whenever
circumstances and situations change, indicating that the carrying amounts
may not be recoverable.
Stock Based Compensation
The Company accounts for stock based employee awards using the intrinsic
value method. Stock based awards to nonemployees are accounted for under
the fair value method.
F-13
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE A - ORGANIZATION AND ACCOUNTING POLICIES - CONTINUED
Property and Equipment
Property and equipment are stated at cost and are depreciated using the
straight-line method over the estimated useful lives of the assets, ranging
from three through 25 years. Major classes of property and equipment
consisted of the following at December 31:
2001 2000
----------- ----------
Drilling rigs and equipment $1,054,006 $5,967,950
Automobiles and trucks 40,055 563,198
Furniture and fixtures 144,867 198,465
Land and buildings 137,535 512,238
Office equipment 89,856 64,011
----------- -----------
1,466,319 7,305,862
Less accumulated depreciation and amortization 575,015 1,776,474
----------- -----------
$ 891,304 $ 5,529,388
=========== ===========
Earnings (Loss) Per Common Share
Basic earnings (loss) per common share is computed by dividing the net
earnings (loss) by the weighted average number of common shares outstanding
for the period. Diluted earnings (loss) per share is based on the
assumption that stock options and warrants are converted into common shares
using the treasury stock method and convertible bonds and debentures are
converted using the if-converted method. Conversion or exercise is not
assumed if the results are antidilutive.
Potential common shares relating to options, warrants and convertible bonds
and debentures excluded from the computations of diluted earnings (loss)
per share because they are antidilutive are as follows:
Year ended December 31,
-----------------------------------------------
2001 2000 1999
-------------- -------------- -----------
Class B Warrants - - 1,632,219
Class B Warrants - Exchange - - 53,274
Class C Warrants - - 1,357,610
Class C Warrants - Exchange - - 498,123
Class D Warrants - - 1,039,193
Class D Warrants - Exchange - - 410,172
Employee stock options 1,770,000 1,642,000 -
Convertible bonds and debentures 6,216,022 6,531,880 7,950,967
F-14
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE A - ORGANIZATION AND ACCOUNTING POLICIES - CONTINUED
Earnings (Loss) Per Common Share - Continued
Class B, C and D Warrants have a weighted average exercise price of $4.50,
$6.00 and $10.00, respectively, for all periods presented. The average
weighted exercise price of Class B, C and D Exchange Warrants is $3.60,
$4.80 and $8.00, respectively, for all periods presented.
Employee stock options have a weighted average exercise price of $4.52 and
$4.00 for the years ended December 31, 2001 and 2000, respectively.
The Convertible Bonds and Debentures may be converted from the date of
issuance until maturity at 100% of principal amount into common stock of
the Company at prices ranging from approximately $4.50 to $50.00 (Note D).
Recent Accounting Pronouncements
On July 20, 2001, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other
Intangible Assets. SFAS No. 141 is effective for all business combinations
completed after June 30, 2001. SFAS No. 142 is effective for fiscal years
beginning after December 15, 2001; however, certain provisions of SFAS No.
142 apply to goodwill and other intangible assets acquired between July 1,
2001 and the effective date of SFAS No. 142.
Major provisions of SFAS Nos. 141 and 142 and their effective dates for the
Company are as follows:
o All business combinations initiated after June 30, 2001 must use
the purchase method of accounting. The pooling of interest method
of accounting is prohibited, except for transactions initiated
before July 1, 2001.
o Intangible assets acquired in a business combination must be
recorded separately from goodwill if they arise from contractual
or other legal rights or are separable from the acquired entity
and can be sold, transferred, rented or exchanged, either
individually or as part of a related contract, asset or
liability.
o Goodwill, as well as intangible assets with indefinite lives,
acquired after June 30, 2001, will not be amortized. Effective
January 1, 2002, all previously recognized goodwill and
intangible assets with indefinite lives will no longer be subject
to amortization.
o Effective January 1, 2002, goodwill and intangible assets with
indefinite lives will be tested for impairment annually and
whenever there is an impairment indicator.
o All acquired goodwill must be assigned to reporting units for
purposes of impairment testing and segment reporting.
F-15
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE A - ORGANIZATION AND ACCOUNTING POLICIES - CONTINUED
Recent Accounting Pronouncements - Continued
The Company will continue to amortize goodwill recognized prior to July 1,
2001 under its current method until January 1, 2002, at which time annual
and quarterly goodwill amortization of approximately $270,000 and $67,500
will no longer be recognized. By December 31, 2002, the Company will have
completed a transitional fair value determination based on an impairment
test of goodwill as of January 1, 2002. Impairment losses, if any,
resulting from the transitional testing will be recognized in the quarter
ended March 31, 2002 as a cumulative effect of a change in accounting
principle.
In June 2001, FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations, and in August 2001, issued SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets. SFAS No. 143 requires entities
to record the fair value of a liability for an asset retirement obligation
in the period in which it is incurred and a corresponding increase in the
carrying amount of the related long-lived asset. Subsequently, the asset
retirement cost should be allocated to expense using a systematic and
rational method. SFAS No. 143 is effective for fiscal years beginning after
June 15, 2002. SFAS No. 144 addresses financial accounting and reporting
for the impairment of long-lived assets and for long-lived assets to be
disposed of. It supersedes, with exceptions, SFAS No. 121, Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of, and is effective for fiscal years beginning after December 15,
2001. The Company is currently assessing the impact of SFAS Nos. 143 and
144. However, at this time, the Company does not believe the impact of
these statements will be material to its consolidated financial position or
results of operations.
NOTE B - INVESTMENTS
The amortized cost, unrealized gains and losses and fair values of the
Company's available-for-sale securities held are summarized as follows:
December 31,
-----------------------------
2001 2000
-------------- -----------
U.S. Treasury Bonds, stripped of interest, maturing 2002 through 2023,
aggregate par value of $19,107,000 and $18,879,000, respectively
Amortized cost $8,542,626 $7,578,312
Gross unrealized gains 464,517 793,360
Gross unrealized losses (28,465) -
---------- ----------
Estimated fair value $8,978,678 $8,371,672
========== ==========
F-16
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE B - INVESTMENTS - CONTINUED
During 2001, 2000 and 1999, the Company recognized approximately $(3,100),
$39,000 and $(1,869,000), respectively, of unrealized gains (losses) on its
trading securities and $21,000, $549,000 and $765,000, respectively, of
realized gains from its investments in trading and available-for-sale
securities. During 2001, 2000 and 1999, the Company recognized realized
gains of approximately $21,000, $542,000 and $751,000, respectively,
resulting from the release of such securities due to cash distributions to
investors of affiliated partnerships made from proceeds from sales of oil
and gas and the release of the Company's obligation related to securing its
commitment under certain repurchase agreements (Notes G and I). Gross gains
recognized in earnings attributable to transfers of available-for-sale
securities to trading securities were $21,019, $541,722 and $771,264 in
2001, 2000 and 1999, respectively. Gross losses recognized in earnings
attributable to transfers of available-for-sale securities to trading
securities was $20,453 in 1999.
The amortized cost and estimated fair values of available-for-sale
securities, by contractual maturity, at December 31, 2001 are shown below.
Amortized Estimated
cost fair value
---------- ----------
Due within one year $ 484,278 $ 498,320
Due after five years through ten years 3,912,434 4,091,937
Due after ten years 4,145,914 4,388,421
---------- ----------
Total $8,542,626 $8,978,678
========== ==========
NOTE C - ASSETS HELD FOR SALE
During 2001, the Company initiated a plan to dispose of substantially all
assets of Pinnacle which was completed on February 14, 2002 (Note R). In
connection with the plan of disposal, the Company determined that the
carrying value of Pinnacle's assets exceeded their fair values.
Accordingly, an impairment expense of approximately $825,000, which is
included as part of depreciation, depletion and amortization, and
represents the excess of the carrying value of $4,568,000 over the fair
value of $3,743,000, has been charged to operations in 2001. The fair value
is based on the net selling price of the completed transaction.
Carrying
value Fair value
---------- ----------
Goodwill $ 223,042 $ -
Property and equipment 4,345,156 3,742,941
---------- ----------
$4,568,198 $3,742,941
========== ==========
F-17
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE D - LONG-TERM DEBT
Debentures consist of the following at December 31:
2001 2000
----------- -----------
Secured Convertible Debentures, due August 31, 2002, bearing interest at
12%, due in semiannual payments. As of December 31, 2001 and 2000,
collateralized by $455,000 and $505,000, respectively, principal amount of
zero coupon U.S. Treasury Bonds due August 15, 2002. $ 470,000 $ 505,000
Sinking Fund Convertible Debentures, due August 31, 2002, bearing interest
at 12%, due in semiannual payments. Annual Sinking Fund payments, equal to
11.1% of total outstanding principal, commenced August 31, 1994. 55,000 55,000
Sinking Fund Debentures, due December 31, 2007, bearing interest at 12%,
due in monthly payments. Annual Sinking Fund payments, based on 20% of
total outstanding principal, commencing on December 31, 2002. 15,390,000 15,390,000
Secured Convertible Debentures, due December 31, 2009, bearing interest at
12%, due in monthly payments. As of December 31, 2001 and 2000, principal
collateralized by $840,000 each year, principal amount of zero coupon U.S.
Treasury Bonds due November 15, 2009. 840,000 840,000
Secured Convertible Bonds, due December 31, 2010, bearing interest at 12%,
due in monthly payments. As of December 31, 2001 and 2000, principal
collateralized by $1,740,000 and $1,765,000, respectively, principal amount
of zero coupon U.S. Treasury Bonds due November 15, 2010. 1,740,000 1,765,000
Sinking Fund Convertible Debentures, due December 31, 2010, bearing
interest at 13.02%, due in monthly payments. Annual Sinking Fund payments,
based on 8.33% of total outstanding principal, commenced on December 31,
1999. 15,095,200 15,215,000
Sinking Fund Convertible Debentures, due December 31, 2015, bearing
interest at 13.02%, due in monthly payments. Annual Sinking Fund payments,
based on 5.88% of total outstanding principal, commenced on December 31,
1999. 12,737,500 12,977,500
Secured Convertible Bonds, due December 31, 2016, bearing interest at 12%,
due in monthly payments. As of December 31, 2001 and 2000, principal
collateralized by $1,580,000 and $1,625,000, respectively, principal amount
of zero coupon U.S. Treasury Bonds due November 15, 2016. 1,580,000 1,625,000
F-18
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE D - LONG-TERM DEBT - CONTINUED
2001 2000
----------- -----------
Sinking Fund Convertible Debentures, due December 31, 2017, bearing
interest at 12%, due in monthly payments. Annual Sinking Fund payments,
based on 5.56% of total outstanding principal, commenced on December 31,
1999. 7,215,000 7,225,000
Secured Convertible Bonds, due December 31, 2020, bearing interest at 12%,
due in monthly payments. As of December 31, 2001 and 2000, principal
collateralized by $1,780,000 and $1,770,000, respectively, principal amount
of zero coupon U.S. Treasury Bonds due November 15, 2020. 1,780,000 1,770,000
Secured Convertible Bonds, due December 31, 2022, bearing interest at 12%,
due in monthly payments. As of December 31, 2001 and 2000, principal
collateralized by $1,236,000 and $1,286,000, respectively, principal amount
of zero coupon U.S. Treasury Bonds due November 15, 2022. 1,236,000 1,286,000
----------- -----------
58,138,700 58,653,500
Less current maturities 4,747,370 3,598,350
----------- -----------
Long-term portion $53,391,330 $55,055,150
=========== ===========
Other long-term debt consists of the following at December 31:
2001 2000
----------- -----------
Deferred payment related to an acquisition of oil leases; paid in full
during 2001 $ - $ 1,000,000
Note payable with monthly payments of $31,757, maturing January 2003.
Payments include interest accruing at a rate of 10.25%, per annum,
collateralized by equipment. 374,321 698,747
Other miscellaneous long-term debt 47,591 95,010
----------- -----------
421,912 1,793,757
Less current maturities 392,721 1,371,846
----------- -----------
Long-term portion $ 29,191 $ 421,911
=========== ===========
During 2000, the Company issued $15,390,000 12% Sinking Fund Debentures,
due December 31, 2007. The Company also issued 400 Class D Warrants to
purchase common stock of the Company at $10.00 per share with each $50,000
of face value. Brokers also received 200 of the same Class D Warrants for
each $50,000 of face value as well as broker commissions. The fair value of
the Class D Warrants of approximately $40,000 has been recognized as debt
issue costs.
F-19
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE D - LONG-TERM DEBT - CONTINUED
The Convertible Bonds and Debentures may be converted from the date of
issuance until maturity at 100% of principal amount into common stock of
the Company at prices ranging from approximately $4.50 to $50.00. In 2001,
a debenture holder converted $10,000 principal amounts of a note into
approximately 1,300 shares of common stock. Additionally, the Company
issued approximately 8,000 shares of common stock to certain exchange bond
holders. During 2000, debenture holders converted $10,250,000 principal
amounts of notes into approximately 1,367,000 shares of common stock.
Con-versions of debt would increase the numbers of shares outstanding at
December 31 as follows:
2001 Outstanding Per Share
---- Maturity principal conversion Common shares
date amount price if converted
----------------- ------------- ---------- -------------
Secured Convertible 12% Bond August 31, 2002 $ 470,000 $ 4.50 104,444
Sinking Fund 12% Bond August 31, 2002 55,000 4.50 12,222
Secured Convertible 12% Bond December 31, 2009 840,000 7.00 120,000
Secured Convertible 12% Bond December 31, 2010 1,740,000 7.00 248,571
Sinking Fund 13.02% Bond December 31, 2010 15,095,200 5.00 3,019,040
Sinking Fund 13.02% Bond December 31, 2015 12,737,500 8.00 1,592,188
Secured Convertible 12% Bond December 31, 2016 1,580,000 7.00 225,714
Sinking Fund 12% Bond December 31, 2017 7,215,000 10.00 721,500
Secured Convertible 12% Bond December 31, 2020 1,780,000 17.50 101,714
Secured Convertible 12% Bond December 31, 2022 1,236,000 17.50 70,629
Sinking Fund 12% Bond December 31, 2007 15,390,000 - -
------------- -------------
$ 58,138,700 6,216,022
============= =============
2000 Outstanding Per Share
---- Maturity principal conversion Common shares
date amount price if converted
----------------- ------------- ---------- -------------
Secured Convertible 12% Bond August 31, 2002 $ 505,000 $ 4.50 112,222
Sinking Fund 12% Bond August 31, 2002 55,000 4.50 12,222
Secured Convertible 12% Bond December 31, 2009 840,000 7.00 120,000
Secured Convertible 12% Bond December 31, 2010 1,765,000 7.00 252,143
Sinking Fund 13.02% Bond December 31, 2010 15,215,000 5.00 3,043,000
Sinking Fund 13.02% Bond December 31, 2015 12,977,500 8.00 1,622,188
Secured Convertible 12% Bond December 31, 2016 1,625,000 7.00 232,143
Sinking Fund 12% Bond December 31, 2017 7,225,000 7.50 963,333
Secured Convertible 12% Bond December 31, 2020 1,770,000 17.50 101,143
Secured Convertible 12% Bond December 31, 2022 1,286,000 17.50 73,486
Sinking Fund 12% Bond December 31, 2007 15,390,000 - -
------------- -------------
$ 58,653,500 6,531,880
============= =============
F-20
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE D - LONG-TERM DEBT - CONTINUED
1999 Outstanding Per Share
---- Maturity principal conversion Common shares
date amount price if converted
----------------- ------------- ---------- -------------
Secured Convertible 12% Bond August 31, 2002 $ 520,000 $ 4.50 115,556
Sinking Fund 12% Bond August 31, 2002 115,000 4.50 25,556
Secured Convertible 12% Bond December 31, 2009 1,735,000 6.00 289,167
Secured Convertible 12% Bond December 31, 2010 2,375,000 6.00 395,833
Sinking Fund 13.02% Bond December 31, 2010 13,043,000 5.00 2,608,600
Sinking Fund 13.02% Bond December 31, 2015 11,797,500 8.00 1,474,688
Secured Convertible 12% Bond December 31, 2016 2,325,000 6.00 387,500
Sinking Fund 12% Bond December 31, 2017 17,500,000 7.50 2,333,333
Secured Convertible 12% Bond December 31, 2020 2,815,000 15.00 187,667
Secured Convertible 12% Bond December 31, 2022 1,996,000 15.00 133,067
------------- -------------
$ 54,221,500 7,950,967
============= =============
Effective January 2, 1996, and each year thereafter, the holders of the
Secured and Sinking Fund Convertible Debentures due August 31, 2002 may
tender to the Company up to 10% of the aggregate debentures originally
issued.
Effective January 1, 1998, and each year thereafter, the holders of the
Secured Convertible Debentures due December 31, 2009, 2010 and 2016 may
tender to the Company up to 10% of the aggregate debentures issued.
Effective January 1, 2000 and January 1, 2001, and each year thereafter,
the holders of the Secured Convertible Debentures due December 31, 2020 and
December 31, 2022, respectively, may tender to the Company up to 10% of the
aggregate debentures issued. Holders of the Sinking Fund Convertible
Debentures due December 31, 2010, 2015 and 2017 may tender to the Company
up to 10% of the aggregate debentures issued effective January 1, 2000,
January 1, 2001 and January 1, 2001, respectively. Effective January 1,
2002, and each year thereafter, the holders of the Sinking Fund Debentures
due December 31, 2007 may tender to the Company up to 10% of the aggregate
debentures originally issued.
F-21
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE D - LONG-TERM DEBT - CONTINUED
The estimated principal that can be tendered by the Secured Convertible and
Sinking Fund Debenture holders, including contractual maturities, is as
follows:
Fiscal year ending December 31
2002 $ 4,747,370
2003 5,761,370
2004 5,761,370
2005 5,761,370
2006 5,761,370
Thereafter 30,345,850
------------
$ 58,138,700
Annual sinking fund requirements are as follows:
Fiscal year ending December 31
2002 $ 3,220,352
2003 3,416,436
2004 3,615,131
2005 3,838,362
2006 4,069,352
Thereafter 15,893,738
------------
$ 34,053,371
NOTE E - STOCKHOLDERS' EQUITY
On September 6, 2001, the Board of Directors approved the issuance of
2,520,613 stock options to officers and employees under certain plans
subject to shareholder approval. At December 31, 2001, these plans have not
been approved.
In September 2000, the Company adopted an employee stock option plan for
certain employees with a maximum of 1,975,000 shares which may be issued
and granted a total of 1,642,000 options exercisable at $4.00 per share.
During 2001, the Company issued and granted a total of 153,000 options
under the plan. The options are exercisable at a price not less than the
fair market of the stock at the date of grant, have an exercisable period
of five years and generally vest 25% after one year, 50% after two years
and the final 25% three years after the date of grant. A total of 1,050,000
options granted in 2000 to certain of the employees vest 50% upon grant and
25% each on the second and third anniversaries of the date of grant.
Accordingly, no compensation has been recognized for these options in the
consolidated financial statements and the fair value compensation is
included in the pro forma amounts below.
On September 30, 2000, the Company extended the expiration of Class B and C
Warrants from September 30, 2000 to December 31, 2000 and recognized an
expense of approximately $139,000 due to the change in fair value of the
extended warrants. In May 2000, the Company issued 29,000 shares of common
stock to two former employees in exchange for exercise of employee
warrants. As part of severance arrangements, in a cashless exercise one
employee exchanged 60,000 warrants for 24,000 shares of common stock.
Compensation expense of $96,000 was recognized as a result of this
exercise. The second employee exercised 5,000 warrants at the exercise
price of $3.68 per share.
F-22
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE E - STOCKHOLDERS' EQUITY - CONTINUED
The Company's Class B Warrants, which expired on December 31, 2000, enabled
the holders to purchase shares of c ommon stock at an exercise price of
between $2.50 and $4.50 per share, subject to certain antidilution
provisions. The Company's Class C Warrants, which expired on December 31,
2000, enabled the holders to purchase shares of common stock at an exercise
price of between $4.00 and $6.00 per share, subject to certain antidilution
provisions. The Company's Class D Warrants, which expired on December 31,
2000, enabled the holders to purchase shares of common stock at an exercise
price of between $10.00 and $20.00 per share, subject to certain
antidilution provisions. The affiliated partnerships, certain brokers,
employees and others held the warrants.
On December 31, 1998, certain Class B, C and D Warrants were modified under
the terms of the Exchange Offer (Note J). The Company's Class B, Class C
and Class D Warrants as modified (the Exchange Warrants) had an exercise
price of $3.60, $4.80 and $8.00, respectively. All Exchange Warrants
expired December 31, 2000.
The Company uses the intrinsic value method to account for its employee
warrant and option plans in which compensation is recognized only when the
fair value of the underlying stock exceeds the exercise price of the
warrant or option at the date of grant. The exercise price of all warrants
or options equaled or exceeded market price of the stock at the date of
grant. Accordingly, no compensation cost has been recognized for the
warrants and options issued. Had compensation cost been determined based on
the fair value of the warrants and options at the grant dates, the
Company's net earnings (loss) would have been adjusted to the pro forma
amounts for the years ended as indicated below.
2001 2000 1999
------------ ----------- ------------
Net loss
As reported $(21,073,592) $(1,195,640) $(11,079,228)
Pro forma $(21,360,468) $(1,366,787) $(11,081,618)
The fair value of each grant is estimated on the date of grant using the
Black-Scholes options-pricing model with the following weighted-average
assumptions used for grants in 2001, 2000 and 1999, respectively: No
expected dividends, expected volatility of 28%, 24% and 24%, risk-free
interest rate of 3.64%, 5.85% and 6% and expected lives of 3 years for
incentive options issued in 2001 and .4 and 1.5 years for warrants and 3
years for incentive options issued in 2000. The volatility assumptions were
developed using a peer group of similar energy companies.
The Black-Scholes options valuation model was developed for use in
estimating the fair value of traded warrants 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 warrants
have characteristics significantly different from those of traded warrants,
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 warrants.
F-23
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE E - STOCKHOLDERS' EQUITY - CONTINUED
A summary of the status of the Company's warrants and options issued to
employees as of December 31, 2001, 2000 and 1999 and changes during the
years ended on those dates is presented below for employees. All warrants
are exercisable at the award date. Class B, C and D Warrants have weighted
average exercise prices of $4.50, $6.00 and $10.00, respectively, for all
periods presented.
Class B Class C Class D Incentive
Warrants Warrants Warrants Options
--------- -------- -------- ----------
Warrants outstanding - January 1, 1999 109,950 320,267 - -
Issued - 15,000 - -
--------- --------- --------- -----------
Warrants outstanding - December 31, 1999 109,950 335,267 - -
Issued - 273,158 251,059 1,642,000
Exercised - (29,700) (10) -
Expired (109,950) (578,725) (251,049) -
--------- --------- --------- -----------
Warrants and options outstanding - December 31, 2000 - - - 1,642,000
Issued - - - 153,000
Exercised - - - -
Expired - - - -
Forfeited - - - (25,000)
--------- --------- --------- -----------
Warrants and options outstanding - December 31, 2001 - - - 1,770,000
========= ========= ========= ===========
Weighted average fair value of warrants granted during 1999 $ - $ .16 $ - N/A
Weighted average fair value of options granted during 2000 $ - $ - $ - $ .56
Weighted average fair value of options granted during 2001 $ - $ - $ - $ .73
Options exercisable at December 31, 2001 N/A N/A N/A 929,500
Weighted average exercise price of options N/A N/A N/A $ 4.52
F-24
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE E - STOCKHOLDERS' EQUITY - CONTINUED
A summary of the status of the Company's Warrants issued to nonemployees,
which expired on December 31, 2000 and the changes during the years ended
December 31, 2000 and 1999 are presented below. The average weighted
exercise price of Class B, C and D warrants is $4.50, $6.00 and $10.00,
respectively. The average weighted exercise price of Class B, C and D
Exchange Warrants is $3.60, $4.80 and $8.00, respectively.
Class B Class C Class D
Warrants Warrants Warrants
---------- ---------- ----------
Warrants outstanding - January 1, 1999 1,523,769 1,074,377 589,483
Issued - 12,916 573,745
Exercised - (41,000) -
Modified as Exchange Warrants (1,500) (23,950) (124,035)
---------- ---------- ----------
Warrants outstanding - December 31, 1999 1,522,269 1,022,343 1,039,193
Issued 26,559 215,036 649,604
Exercised (863,821) (625,996) (869,900)
Modified as Exchange Warrants (550) (16,859) (11,532)
Expired (684,457) (594,524) (807,365)
---------- ----------- ----------
Warrants outstanding - December 31, 2000 - - -
========== =========== ==========
Weighted average fair value of warrants granted in 1999 N/A $ .16 $ -
Weighted average fair value of warrants granted in 2000 $ 1.20 $ - $ .22
F-25
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE E - STOCKHOLDERS' EQUITY - CONTINUED
Class B Class C Class D
Exchange Exchange Exchange
Warrants Warrants Warrants
---------- ---------- ----------
Warrants outstanding - January 1, 1999 54,188 469,111 255,609
Issued 1,875 29,950 155,126
Exercised (2,789) (938) (563)
---------- ---------- ----------
Warrants outstanding - December 31, 1999 53,274 498,123 410,172
Issued 688 21,086 14,492
Exercised (45,357) (393,993) (308,799)
Modified as Exchange Warrants (8,605) (125,216) (115,865)
---------- ---------- ----------
Warrants outstanding - December 31, 2000 - - -
========== ========== ==========
Weighted average fair value of exchange warrants granted in 1999 $ .74 $ .20 $ -
Weighted average fair value of exchange warrants granted in 2000 $ .52 $ .04 $ -
F-26
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE F - INCOME TAXES
The Company and its subsidiaries file a consolidated income tax return.
The Company's effective income tax rate differed from the federal statutory
rate as follows:
2001 2000 1999
------------- ---------- -----------
Income taxes at federal statutory rate $ (7,113,443) $(546,598) $(3,528,258)
Change in valuation allowance 11,560,422 (5,297) 4,902,072
Nondeductible expenses 264,101 120,798 42,136
State income taxes at statutory rate (1,255,314) (96,458) (622,634)
Adjustment of estimated income tax provision of
prior year (3,312,841) 121,294 (137,939)
Other 8,775 (5,739) 46,623
------------- --------- -----------
$ 151,700 $(412,000) $ 702,000
============= ========= ===========
The components of the net deferred tax asset are as follows as of December
31:
2001 2000
----------- ------------
Deferred tax assets
Net operating loss carryforward $15,176,559 $ 8,815,005
Organization costs 87,659 304,650
Oil and gas properties and tangible equipment 6,086,792 4,450,248
Contingent repurchase obligation 1,406,542 -
Other 471,623 196,200
----------- ------------
23,229,175 13,766,103
Less valuation allowance 22,142,772 10,582,350
----------- ------------
Total deferred tax assets 1,086,403 3,183,753
----------- ------------
Deferred tax liabilities
Capitalized intangible assets 930,628 923,369
Tangible equipment - 1,840,445
Net unrealized gain on investments 155,775 311,240
Other - 108,699
----------- ------------
Total deferred tax liabilities 1,086,403 3,183,753
----------- ------------
Net deferred tax asset $ - $ -
=========== ============
The valuation allowance increased (decreased) $11,560,422, $(5,297) and
$4,902,072 for the years ended December 31, 2001, 2000 and 1999,
respectively.
F-27
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE F - INCOME TAXES - CONTINUED
A valuation allowance for deferred tax assets is required when it is more
likely than not that some portion or all of the deferred tax assets will
not be realized. The ultimate realization of this deferred tax asset
depends on the Company's ability to generate sufficient taxable income in
the future. Manage-ment believes it is more likely than not that the
net deferred tax asset will not be realized by future operating results.
At December 31, 2001, the Company had net operating loss carryforwards for
federal income tax purposes of approximately $38,000,000 which begin to
expire in 2012.
NOTE G - COMMITMENTS AND CONTINGENCIES
General Commitments
The Company has entered into various commitments and operating agreements
related to development and production of certain oil and gas properties. It
is management's belief that such commitments, as stated below, will be met
without significant adverse impact to the Company's financial position or
results of operations.
Oil and Gas Partnerships
The Company is the managing general partner in various oil and gas
partnerships. Accordingly, the Company is unconditionally liable for
liabilities which may be incurred by such partnerships. Additionally, the
Company has indemnified various working interest (general) partners of
affiliated partnerships against any liability which may be incurred in
connection with the partnerships, in excess of such partner's interest, in
the undistributed net assets of the partnership and insurance proceeds
thereof. The partnerships have no liabilities except accounts payable to
the Company for lease operating and administrative expenses.
In connection with the release of Treasury securities held for drilling
programs formed between 1994 and 1998, the Company undertook to contribute
additional oil and gas leases to these partnerships on a "best efforts"
basis. The values of the properties to be contributed may vary, at the sole
discretion of the Company, from zero up to 50% of the value of the U.S.
Treasury Bonds released by the partnerships.
The Company has a gas purchase contract with Western Gas related to its
Piper Federal lease. The contract is for the purchase of a minimum of 2,500
Mcf of gas per day at the wellhead. The contract commences on February 1,
2001 and expires on February 1, 2005. If the Company fails to deliver 2,500
Mcf of gas per day, Western Gas may charge the Company a deficiency fee.
The deficiency fee is defined as the amount of deficient Mcf times 90%
(amount below 2,500 Mcf times 90%) times the deficiency rate of $0.42 per
Mcf representing gathering, compression and transportation charges. During
2001, the Company was in compliance with the purchase contract.
F-28
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE G - COMMITMENTS AND CONTINGENCIES - CONTINUED
Oil and Gas Partnerships - continued
The Company has a gas purchase contract with Western Gas related to its
Haight Less lease. The contract is for the purchase of a minimum of 550 Mcf
of gas per day at the wellhead. Since approximately 1998, the contract has
been extended on a year-by-year basis. If the Company fails to deliver 550
Mcf of gas per day, Western Gas reduces the sales price by a nominal
amount. During 2001, the Company was in compliance with the purchase
contract.
The Company has a transportation contract with Williston Basin Interstate
("WBI") related to its LX Bar lease. If the Company fails to deliver the
stated amount of gas per day, WBI may charge the Company a transportation
fee. The transportation fee is defined as the amount of deficient Mcf times
the transportation rate of approximately $0.43 per Mcf. During 2001, the
Company paid a transportation fee of approximately $172,000.
Repurchase Agreements
Under certain repurchase agreements, the investor partners in certain
affiliated partnerships have a right to have their interests purchased by a
repurchase agent. Such purchase price is calculated at a formula price and
is payable in seven to 25 years from the date of admission to the
partnership. For certain affiliated partnerships formed prior to 1998, the
maximum purchase price for all such interests was fully secured at maturity
by zero coupon U.S. Treasury Bonds held by an independent trust company.
The face amounts of such securities are released to the Company when equal
amounts of cash distributions are made to investors. At December 31, 2001
and 2000, the face amounts of U.S. Treasury Bonds securing the Company's
obligation under such repurchase agreements were $4,603,000 and $5,722,000,
respectively, and the market value of these U.S. Treasury Bonds was
approximately $1,589,409 and $2,028,000, respectively. Under certain other
repurchase agreements, the investor partners have a right to have their
interests purchased by a repurchase agent under the same formula price
seven years from the date of the original partnership investment. The
repurchase agent's performance is unconditionally guaranteed by the
Company.
Harbor View Horizons Corp. ("Harbor View") is a financial services company
that served as a remarketing agent for the limited partnerships formed in
1994 and 1995 under a remarketing agreement, wherein Harbor View agreed to
accept tenders from investor partners who desired to sell their interest
and withdraw from the partnerships at a designated future date that was
typically 15 to 22 years from the date of formation of the partnerships. To
assure Harbor View's ability to perform, the Company placed zero coupon
U.S. Treasury Bonds in an escrow account with Chase Manhattan Bank, N.A.
Harbor View was not affiliated with the limited partnerships or the
Company. Commencing in 1996, the partnerships ceased using Harbor View as a
remarketing agent. Instead, the remarketing feature was replaced with a
"buy-sell" clause or agreement directly with the Company contained within
the respective limited partnership agreements. Subsequent to 1995, the
Company made investments in Harbor View through loans to it for other
finance activities unrelated to the remarketing agreements.
In determining the amount of the contingent repurchase obligation, the
present value of the obligation is computed based on the excess of the
formula purchase price over the estimated discounted present value of
future net revenues of proved developed and undeveloped reserves of each
partnership, net of future capital costs and the Company's working
interest. The partnerships' proved undeveloped leases must be drilled by
F-29
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE G - COMMITMENTS AND CONTINGENCIES - CONTINUED
Repurchase Agreements - Continued
the Company using funds from an outside party or from the Company to
provide future revenues which satisfy the contingent repurchase obligation.
The Company has estimated that these wells will require approximately
$26,800,000 of development costs in partnerships in 2002 and 2003 for
drilling and completing these wells. These development costs, the
partnerships' future net revenues and the contingent repurchase obligation
are based on reserve studies of independent petroleum engineers and actual
amounts may differ from the estimates. Based upon this calculation using
prices at March 15, 2002 the Company recorded a contingent repurchase
obligation of $3,318,993 at December 31, 2001. A similar analysis has been
performed in all prior years.
Included in other current assets in the accompanying consolidated financial
statements at December 31, 2001 and 2000 are amounts due from the Company's
repurchase agent of approximately $325,000 and $1,557,000, respectively,
related to short-term, noninterest-bearing loans.
Trust Indenture Agreements
Under certain Trust Indenture Agreements, the Company has purchased zero
coupon U.S. Treasury Bonds to secure repayment of the outstanding principal
amount of debentures outstanding when due at maturity. At December 31, 2001
and 2000, the face amounts of U.S. Treasury Bonds securing the Company's
obligation under the Trust Indenture Agreements were $14,504,000 and
$13,157,000, respectively, and the market values of these U.S. Treasury
Bonds were approximately $7,386,000 and $6,344,000, respectively.
Leases
In July 1997, the Company entered into an office lease in New York City,
which commenced October 1997 and expires in March 2008. The lease can be
canceled by the Company after five years subject to a cancellation fee of
approximately $120,000. On June 1, 2000, Pedco entered into an office lease
in Albuquerque, New Mexico expiring May 31, 2003. On January 22, 2000,
Pedco entered into an office lease in Gillette, Wyoming expiring February
28, 2001 with an option to renew on a yearly basis. This lease was renewed
in 2001. On November 1, 2000, Pinnacle entered into an office lease in
Artesia, New Mexico, expiring on November 1, 2001 with an option to renew
on a yearly basis.
Future minimum annual rental payments, which are subject to escalation and
include utility charges as of December 31, 2001, are as follows:
Year ending December 31
2002 $ 229,677
2003 182,350
2004 155,686
2005 155,686
2006 155,686
Thereafter 194,607
-----------
$ 1,073,692
===========
Rent expense under these leases was approximately $281,000, $243,000 and
$152,000 for the years ended December 31, 2001, 2000 and 1999,
respectively.
F-30
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE G - COMMITMENTS AND CONTINGENCIES - CONTINUED
Litigation
The Company is a party to various matters of litigation arising in the
normal course of business. Management believes that the ultimate outcome of
the matters will not have a material effect on the Company's financial
condition or results of operations.
NOTE H - EMPLOYEE BENEFIT PLANS
The Company has a retirement plan covering substantially all qualified
corporate employees under section 401(k) of the Internal Revenue Code.
Under the plan, participants may contribute up to 22% of their compensation
to their plan accounts. The Company contributed for each participant a
matching contribution equal to 50% of the participant's contribution to a
maximum of 6% of each employee's annual compensation. The Company may also
make discretionary contributions. The Company's expenses under the plan
were approximately $92,000, $35,000 and $25,000 for the years ended
December 31, 2001, 2000 and 1999, respectively.
NOTE I - RELATED PARTY TRANSACTIONS
Affiliated Partnerships
The Company contributed mineral rights with an agreed-upon fair value of
$361,115 and $2,950,645 during 2001 and 2000, respectively, to affiliated
partnerships in exchange for a 10% interest in these partnerships. The
mineral rights remain at cost in the Company's property accounts.
Affiliated partnerships paid $14,443,250, $44,479,750 and $40,791,020 to
the Company during 2001, 2000 and 1999, respectively, under fixed price
turnkey drilling contracts. At December 31, 2001 and 2000, accounts
receivable from affiliated partnerships were approximately $802,000 and
$780,000, respectively, relating primarily to administrative costs paid by
the Company on behalf of the partnerships.
The Company purchased lease and well equipment and certain leasehold
interests at estimated fair value from affiliated partnerships during the
years ended December 31, 2001, 2000 and 1999 for approximately $75,000,
$355,000 and $131,000, respectively. During the years ended December 31,
2001, 2000 and 1999, the Company expensed lease operating expenses of
approximately $1,329,000, $3,234,000 and $2,030,000, respectively, for
affiliated partnerships which were recorded in general and administrative
expenses as marketing cost.
F-31
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE I - RELATED PARTY TRANSACTIONS - CONTINUED
Joint Venture Agreements
Prior to September 1, 2000, the Company and Pedco each owned, net of
third-party interests, a 50% interest in the Pedco Group, a joint venture
formed for the purpose of participating in the horizontal drilling and
re-completing of existing oil wells. Subsequent to the acquisition of
Pedco, the Company owns 100% of the Pedco Group.
The Pedco Group is party to separate joint venture agreements with the
affiliated partnerships. The agreements form a joint venture between the
Pedco Group and each partnership for the purpose of participating in the
drilling and re-completing of oil wells. Under the terms of the agreements,
property acquisition and capital equipment costs are borne by the Pedco
Group. Generally, intangible drilling and development costs are borne by
the partnerships. Additionally, the Company issued warrants to buy shares
of the Company's common stock to these partnerships as a capital
contribution and to certain brokers who sell these limited partners'
interests as additional commissions. The fair value of these warrants are
recognized as either reductions of turnkey revenue (partnership warrants)
or marketing expense (broker warrants) based on the fair value of the
warrant issued (Note D) and increases to paid-in capital. Charges to
operations for these warrants were approximately $120,000 and $3,000
for the years ended December 31, 2000 and 1999, respectively.
Under the terms of the joint venture agreement, the affiliated partnerships
have an initial 75% interest in the aggregate net profits of the
properties. Once the partnerships have received distributions equal to the
payments under the turnkey contract, the Pedco Group will receive an
additional reversionary interest of 15% and the partnerships' interest will
be reduced to 60%.
The partnerships are parties to a standard form of operating agreement with
Pedco (the "Operator") pursuant to which the Operator will be responsible
for the operation of the wells. Also, the Operator is engaged to supervise
all drilling and re-completion of wells, on behalf of all working
interests, and has full control of all operations of the wells as covered
under the operating agreement. Each partnership pays the Operator its pro
rata share of monthly operating expenses.
In May 1999, the Company entered into an agreement with Magness Petroleum
Company ("Magness") to form a joint venture for the purpose of
participating in the horizontal drilling and re-completing of existing oil
wells and the drilling of new oil wells within the Wilmington Oil Field in
Los Angeles County, California.
F-32
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE I - RELATED PARTY TRANSACTIONS - CONTINUED
Joint Venture Agreements - Continued
On or about September 28, 1999, Magness filed suit against Warren Resources
Inc., alleging claims for breach of written contract, breach of oral
contract, dissolution of joint venture, accounting and declaratory relief.
Upon defendants' motion, the case was sent to arbitration. As part of the
arbitration, the defendants asserted cross-claims against Magness for
breach of written contract, gross negligence, breach of fiduciary duty and
actual and constructive fraud. Shortly before the arbitration commenced,
Magness amended its complaint to add certain fraud claims against
defendants. In February 2001, the arbitrator rendered his opinion, finding
that Magness had breached the joint venture agreement at issue and that the
defendants had not breached the joint venture agreement. Additionally, the
arbitrator found there was no fraud or damages on either side, that the
joint venture agreement should remain in force and that the Company should
recover approximately $320,000 of charges from Magness which was collected
during 2001. Magness has initiated new arbitration in August 2001, seeking
dissolution of the joint venture and has sought court action to change to a
different arbitrating organization for dispute resolution. The Company has
filed a court action to compel Magness to submit disputes to the original
arbitrating organization to which the parties agreed. The Company believes
that any subsequent arbitration findings will not have a significant
adverse effect on the Company's financial position or operations.
Amounts Due From Officer
At December 31, 2000, amounts due from the President and Chief Executive
Officer amounted to approximately $172,000 inclusive of accrued interest at
7%. Such amounts were due on demand.
NOTE J - EXCHANGE OFFERS
On October 15, 1998, the partnerships initially solicited votes (the
"Partnership Exchange Offers") of all Investor Partners in certain limited
partnerships formed prior to 1998 to modify the Repurchase Agreement to
release to the Company the escrowed long-term zero coupon U.S. Treasury
Bonds which secured the financial performance of the Repurchase Agent to
buy back partnership units at a formula price. In exchange for the release
of the U.S. Treasury Bonds, the Company offered a number of investment
enhancements in favor of the Investor Partners. The enhancements for
Investor Partners accepting the Partnership Exchange Offer included (a) a
reduction in the earliest date when an Investor Partner may exercise under
the Repurchase Agreement to seven years from the year of investment from 15
to25 years (Note G), (b) a modification of the Investor Warrants to
increase by 25% the number of shares of common stock of the Company that an
Investor Partner may purchase in any public offering of the Company's stock
(the "Exchange Warrants"), (c) a reduction by 20% to 46% of the exercise
price per share of the Exchange Warrants with no further price increases in
the exercise prices for the term of the Exchange Warrants, and (d) an
undertaking to register the shares reserved for issuance under the Exchange
Warrants in any public offering of the Company's common stock. Effective
December 31, 1998, in conjunction with these oil and gas exchange offers,
the Company assigned certain oil and gas properties to the partnerships.
As a result, the Company charged to expense oil and gas properties with a
value of approximately $786,000 which were contributed to these
partnerships. In conjunction with the change in warrant terms, the Company
recognized an expense and an increase to paid-in capital of approximately
$203,000. A small number of investors did not accept the exchange until
1999, which resulted in an expense and an increase to paid-in capital of
approximately $6,000 for the year ended December 31, 1999.
Additionally, on December 1, 1998, the Company solicited votes (the "Bond
Exchange Offer") of all outstanding bond holders to exchange their
Debentures or Bonds due at maturities ranging from 2002 to 2022 (the "Old
Bonds") for new 13.02% Sinking Fund Convertible Bonds due 2010 and 2015
(the "New Bonds"). Upon acceptance of the Bond Exchange Offer, the Old
Bonds were retired and the U.S. Treasury Bonds securing the repayment of
principal amounts outstanding under the Old Bonds were released to the
Company. The Bond Exchange Offer contained a number of investment
enhancements to the bond holders accepting the Bond Exchange Offer,
including (a) an increase in the interest rate on the New Bonds to 13.02%
per year, (b) a reduction in the conversion price of the New Bonds into
common stock of the Company with no further increase in conversion price
for the full remaining term of the New Bonds, and (c) an undertaking to
register the shares reserved for issuance under the New Bonds in any public
offering of the Company's common stock. The Bond Exchange Offer was
completely voluntary for each bond holder.
F-33
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE J - EXCHANGE OFFERS - CONTINUED
As of December 31, 2001 and 2000, cumulatively $66,164,000 and $65,050,000,
respectively, face amounts of U.S. Treasury Bonds were released to the
Company under the terms of the Partnership Exchange Offer. Also, as of
December 31, 2001 and 2000, cumulatively $24,638,000 and $24,638,000,
respectively, face amounts of U.S. Treasury Bonds were released to the
Company under the terms of the Bond Exchange Offer. As a result of the Bond
Exchange Offer, certain bonds were considered retired. Costs associated
with this exchange resulted in a $1,000 and $75,000 charge to operations
for the years ended December 31, 2000 and 1999, respectively, for the
write-off of deferred bond issuance costs for the two bond series
considered extinguished and current period issue costs for the bond series
not meeting the criteria for extinguishment. As a result of these releases,
the Company recognized a substantial portion of its approximate $(10,000),
$587,000 and $(1,103,600) realized and unrealized gains (losses) on
securities for the years ended December 31, 2001, 2000 and 1999,
respectively.
NOTE K - FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments and does not purport to represent
the aggregate net fair value of the Company.
Cash and Cash Equivalents. The balance sheet carrying amounts of cash and
cash equivalents approximate fair values of such assets.
U.S Treasury Bonds - Trading Securities and Available-For-Sale. The fair
values are based upon quoted market prices for those or similar
investments.
Convertible Debentures. Fair values of fixed rate convertible debentures
were calculated using interest rates in effect as of year end for similar
instruments with the other terms unchanged.
Other Long-Term Liabilities. The carrying amount approximates fair value
due to the short duration to maturity.
Contingent Repurchase Obligation. The balance sheet carrying amounts of the
contingent repurchase obligation approximate fair value of such liability.
2001 2000
----------------------------- --------------------------
Fair Carrying Fair Carrying
value amount value amount
------------ ------------ ----------- -----------
Financial assets
Cash and cash equivalents $ 22,923,605 $ 22,923,605 $ 58,969,552 $ 58,969,552
U.S. Treasury bonds and other
investments - trading securities 205,989 205,989 441,516 441,516
U.S. Treasury bonds - available-for-sale 8,978,678 8,978,678 8,371,672 8,371,672
Financial liabilities
Fixed rate debentures (62,463,469) (58,138,700) (59,080,546) (58,653,500)
Other long-term liabilities (421,912) 421,912 (1,792,663) (1,793,757)
Hedging contracts - - (1,450,000) -
Contingent repurchase obligation (3,318,993) (3,318,903) - -
=========== =========== ============ ===========
NOTE L - ACQUISITION OF BUSINESS
On September 1, 2000, the Company acquired Pedco for 1,600,000 shares of
its common stock valued at $4.00 per share by an independent party. Pedco
has been the contract operator for the majority of the Company's wells in
New Mexico, Texas and Wyoming and owned a 25% interest in the Company's
consolidated subsidiary, Pinnacle. The Company accounted for the
acquisition as a purchase transaction and costs in excess of net assets
acquired of approximately $3,765,000 will be amortized over its estimated
life of 15 years. The fair value of receivables and investments were based
upon their net realizable values and the value of the investment in
Pinnacle was based upon a bona fide offer of purchase of Pinnacle from an
unrelated party. Property and equipment values were estimated by field
personnel. Goodwill predominately relates to the acquired technical,
engineering and operating personnel of Pedco.
F-34
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE L - ACQUISITION OF BUSINESS - CONTINUED
The estimated fair market values of the assets acquired and liabilities
assumed in the acquisition of Pedco are as follows:
Estimated fair value of assets acquired
Cash $ 629,896
Receivables 1,571,546
Investments 131,478
Property and equipment 14,446
Investment in Pinnacle 1,503,798
Goodwill 3,764,903
Other 94,351
-----------
Total fair value of assets 7,710,418
Liabilities assumed
Accounts payable 1,310,418
-----------
Estimated fair value of acquisition $ 6,400,000
===========
The following summarizes pro forma unaudited results of operations for the
years ended December 31, 1999 and 2000 as if the acquisition had been
consummated immediately prior to January 1, 1999 and 2000. These pro forma
results are not necessarily indicative of future results.
Pro Forma (unaudited)
----------------------------
Year ended December 31,
2000 1999
----------- ------------
Revenues $57,861,658 $ 28,984,768
=========== ============
Net loss $ (996,746) $(11,232,068)
=========== ============
Loss per share
Basic and diluted $ (.07) $ (.88)
The operations of Pedco are included in the accompanying consolidated
financial statements subsequent to the acquisition.
F-35
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE L - ACQUISITION OF BUSINESS - CONTINUED
On January 1, 1999, Warren acquired a 50% interest in Pinnacle in addition
to its 25% interest acquired in the formation of Pinnacle. Pinnacle is
consolidated with the Company subsequent to its acquisition of the
additional interest. The estimated fair market value of the assets acquired
and liabilities assumed in the 1999 acquisition are as follows:
Estimated fair value of assets acquired
Cash $ 11,063
Receivables 64,918
Property and equipment 1,912,718
Goodwill 278,490
------------
Total fair value of assets $ 2,267,189
============
Liabilities assumed
Accounts payable $ 353,737
Loan secured by equipment 628,502
Note to the Company 1,284,950
------------
Total fair value of liabilities $ 2,267,189
============
The Company accounted for the acquisition of Pinnacle on January 1, 1999 as
a purchase transaction and recorded $278,490 in goodwill, which is
amortized over its estimated life of 15 years. On February 14, 2002, the
Company completed the sale of substantially all assets of Pinnacle (Notes C
and R).
NOTE M - CHANGE IN ESTIMATED LIVES
After review and study of its preventative maintenance program and
operating policies by the Company, effective January 1, 2000, the estimated
lives of its drilling rigs and related drilling equipment were changed from
60 months to 180 months. This change was made to more closely approximate
the estimated remaining useful lives of each asset. The effect of this
change was to decrease net loss by approximately $264,000 for the year
ended December 31, 2000 or $.02 per share, basic and diluted.
F-36
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE N - OIL AND GAS INFORMATION
Costs related to the oil and gas activities of the Company were incurred as
follows for the years ended December 31:
2001 2000 1999
------------ ----------- ------------
Property acquisition - unproved $ 6,912,000 $15,918,470 $ 7,325,697
Property acquisition - proved - 1,191,595 2,092,506
Exploration costs 3,763,417 999,873 5,441,735
Development costs 6,269,004 2,847,563 7,440,141
------------ ----------- ------------
$ 16,944,421 $20,957,501 $ 22,300,079
============ =========== ============
Of the above development costs incurred for the years ended December 31,
2001, 2000 and 1999, the amounts of approximately $390,000, $59,000 and
$1,038,000, respectively, were incurred to develop proved undeveloped
properties from the prior year.
During the years ended December 31, 2001, 2000 and 1999, exploration costs
of approximately $282,000, $340,000 and $35,000, respectively, were
expensed.
The Company had the following aggregate capitalized costs relating to the
Company's oil and gas activities at December 31:
2001 2000
----------- -----------
Unproved oil and gas properties $67,171,193 $53,990,189
Proved oil and gas properties 19,188,469 15,425,052
----------- -----------
86,359,662 69,415,241
Less accumulated depreciation, depletion and amortization 46,384,864 33,485,216
----------- -----------
$39,974,798 $35,930,025
=========== ===========
The following table sets forth the Company's results of operations from oil
and natural gas producing activities for the years ended December 31:
2001 2000 1999
------------ ------------ -----------
Revenues $ 948,270 $ 200,330 $ 68,054
Production costs (285,980) (14,634) (7,562)
Exploration costs (281,776) (340,713) (35,119)
Depreciation, depletion and amortization (12,899,648) (2,476,036) (8,730,369)
------------ ------------ -----------
Loss from oil and gas producing activities $(12,519,134) $ (2,631,053) $(8,704,369)
============ ============ ===========
F-37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE N - OIL AND GAS INFORMATION - CONTINUED
In the presentation above, no deduction has been made for indirect costs
such as corporate overhead or interest expense. No income taxes are
reflected above due to the Company's tax loss carryforwards. Additionally,
production costs reported above excludes the amount that the Company pays
on behalf of the affiliated partnerships and is reimbursed.
Depreciation, depletion and amortization expense was $12,899,648,
$2,476,036 and $8,730,369 or $258, $52 and $230 per equivalent Mcf of
production for the years ended December 31, 2001, 2000 and 1999,
respectively. These amounts include impairment expenses of $11,112,516,
$2,102,624 and $7,841,743 for the years ended December 31, 2001, 2000 and
1999, respectively, which was based on prices at March 15, 2002 and
December 31, 2000 and 1999, respectively.
NOTE O - OIL AND GAS RESERVE DATA (UNAUDITED)
The following estimates of proved reserve quantities and related
standardized measure of discounted net cash flows are estimates only, and
do not purport to reflect realizable values or fair market values of the
Company's reserves. 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, these estimates are expected to change as future information
becomes available. All of the Company's reserves are located in the United
States.
Proved reserves are estimated reserves of crude oil (including condensate
and natural gas liquids) and natural gas that geological and engineering
data demonstrate with reasonable certainty to be recoverable in future
years from known reservoirs under existing economic and operating
conditions. Proved developed reserves are those expected to be recovered
through existing wells, equipment and operating methods.
The standardized measure of discounted future net cash flows is computed by
applying year-end prices of oil and gas (with consideration of price
changes only to the extent provided by contractual arrangements) to the
estimated future production of proved oil and gas reserves, less estimated
future expenditures (based on year-end costs) to be incurred in developing
and producing the proved reserves, less estimated future income tax
expenses (based on year-end statutory tax rates, with consideration of
future tax rates already legislated) to be incurred on pretax net cash
flows less tax basis of the properties and available credits, and assuming
continuation of existing economic conditions. The estimated future net cash
flows are then discounted using a rate of 10% per year to reflect the
estimated timing of the future cash flows.
F-38
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE O - OIL AND GAS RESERVE DATA (UNAUDITED) - CONTINUED
The following summaries of changes in reserves and standardized measure of
discounted future net cash flows were prepared from estimates of proved
reserves developed by independent petroleum engineers.
Summary of Changes in Proved Reserves
Year ended December
----------------------------------------------------------------
31, 2001 2000 1999
------------------- ------------------ -----------------
Bbls Mcf Bbls Mcf Bbls Mcf
------- -------- -------- ------- ------ ------
(Amounts in thousands)
Proved reserves
Beginning of year 11,770 11,516 10,389 4,993 8,768 1,726
Purchase of reserves in place - - - 1,540 984 -
Discoveries and extensions 4 947 19 1,734 79 3,138
Revisions of previous estimates (3,293) (9,936) 1,365 3,279 562 143
Production (3) (32) (3) (30) (4) (14)
------- -------- ------- ------- ------ ------
End of year 8,478 2,495 11,770 11,516 10,389 4,993
======= ======== ======= ======= ====== ======
Proved developed reserves
Beginning of year 243 8,034 240 2,174 10 284
End of year 8 1,648 243 8,034 240 2,174
Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
December 31,
-----------------------------------------
2001 2000 1999
--------- --------- --------
(Amounts in thousands)
Future cash inflows $122,032 $337,921 $220,714
Future production costs and taxes (25,676) (56,671) (23,257)
Future development costs (31,556) (33,848) (14,500)
Future income tax expenses (4,749) (66,233) (49,595)
--------- -------- --------
Net future cash flows 60,051 181,169 133,362
Discounted at 10% for estimated timing of cash flows (40,539) (92,073) (73,159)
-------- -------- --------
Standardized measure of discounted future net cash flows $ 19,512 $ 89,096 $ 60,203
========= ========= =-=======
F-39
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE O - OIL AND GAS RESERVE DATA (UNAUDITED) - CONTINUED
Changes in Standardized Measure of Discounted Future Net Cash Flows
Related to Proved Oil and Gas Reserves
Year ended December 31,
-----------------------------------------
2001 2000 1999
--------- --------- ---------
(Amounts in thousands)
Sales, net of production costs and taxes $ (662) $ (200) $ (68)
Discoveries and extensions 272 5,393 1,413
Purchases of reserves in place - 4,537 7,897
Changes in prices and production costs (42,613) 6,103 41,356
Revisions of quantity estimates (15,976) 22,214 4,602
Net changes in development costs 2,823 (12,071) 3,676
Interest factor - accretion of discount 11,783 7,975 2,218
Net change in income taxes 27,762 (9,177) (15,457)
Changes in production rates (timing) and other (52,973) 4,119 (3,511)
--------- --------- ---------
Net increase (decrease) (69,584) 28,893 42,126
Balance at beginning of year 89,096 60,203 18,077
--------- --------- ---------
Balance at end of year $ 19,512 $ 89,096 $ 60,203
========= ========= =========
Estimated future net cash flows represent an estimate of future net
revenues from the production of proved reserves using current sales prices,
along with estimates of the operating costs, production taxes and future
development and abandonment costs (less salvage value) necessary to produce
such reserves. The average prices used at December 31, 2001, 2000 and 1999
were $13.87, $20.37 and $20.50 per Bbl and $1.76, $8.53 and $1.54 per Mcf,
respectively. No deduction has been made for depreciation, depletion or any
indirect costs such as general corporate overhead or interest expense.
Operating costs and production taxes are estimated based on current costs
with respect to producing oil and natural gas properties. Future
development costs are based on the best estimate of such costs assuming
current economic and operating conditions. The future cash flows estimated
to be spent to develop the Company's portion of proved undeveloped
properties in the years ended December 31, 2002, 2003 and 2004 are
$926,000, $627,000 and $383,000, respectively.
Income tax expense is computed based on applying the appropriate statutory
tax rate to the excess of future cash inflows less future production and
development costs over the current tax basis of the properties involved,
less applicable carryforwards, for both regular and alternative minimum
tax.
The future net revenue information assumes no escalation of costs or
prices, except for oil and natural gas sales made under terms of contracts
which include fixed and determinable escalation. Future costs and prices
could significantly vary from current amounts and, accordingly, revisions
in the future could be significant.
F-40
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE P - QUARTERLY INFORMATION (UNAUDITED)
Summarized quarterly financial data for the years ended December 31, 2001
and 2000 are as follows:
2001
--------------------------------------------------------------------------------
Quarter Year
------------------------------------------------------------- ------------
First Second Third Fourth
----------- ----------- ----------- ------------
Revenues $11,057,663 $14,641,153 $14,757,521 $ 13,002,913 $ 53,459,250
Gross profit (loss) 341,499 1,240,828 1,202,611 (14,412,568) (11,627,630)
Net loss (1,185,559) (858,508) (497,193) (18,532,332) (21,073,592)
Loss per share
Basic and diluted $ (.07) $ (.05) $ (.03) $ (1.06) $ (1.20)
2000
--------------------------------------------------------------------------------
Quarter Year
------------------------------------------------------------- ------------
First Second Third Fourth
----------- ----------- ----------- ------------
Revenues $11,841,330 $12,548,119 $15,488,659 $17,070,008 $56,948,116
Gross profit 736,252 746,693 1,955,136 2,320,401 5,758,482
Net loss (269,451) (679,429) (52,875) (193,885) (1,195,640)
Loss per share
Basic and diluted $ (.02) $ (.06) $ - $ (.01) $ (.10)
Quarterly and year-to-date computations of per share amounts are made
independently. Therefore, the sum of quarterly per share amounts may not agree
with per share amounts for the year.
During the fourth quarter of 2001, the Company had the following significant
adjustments:
o Entered into an agreement to sell substantially all assets of Pinnacle
that resulted in an impairment of approximately $825,000 (see Notes C
and R).
o Recorded a contingent repurchase obligation of approximately
$3,300,000 (see Note G).
o Recognized impairment on oil and gas properties of approximately
$11,100,000 as a result of the net capitalized costs exceeding the
expected future net cash flow based on engineering estimates (see Note
N).
o Recorded a charge to operations of approximately $1,905,000 to write
off deferred stock offering costs that management believes will be
duplicated in 2002 in finalizing an anticipated stock offering.
The effect of these adjustments was to increase the net loss by approximately
$17,130,000 or $(.98) per basic and diluted share for the quarter and year ended
December 31, 2001.
F-41
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE Q - SEGMENT INFORMATION
The Company's operating activities can be divided into four major segments:
turnkey contracts, oil and gas marketing, oil and gas exploration and
production operations and well services. The Company drills oil and natural
gas wells for Company-sponsored drilling partnerships and retains an
interest in each well. The Company also markets natural gas for affiliated
partnerships. The Company charges Company-sponsored partnerships and other
third parties competitive industry rates for well operations and gas
gathering. Segment information for the years ended December 31 is as
follows:
2001 2000 1999
------------ ------------- ------------
Revenues from external customers
Turnkey contracts $ 30,102,946 $ 33,984,960 $ 25,405,838
Oil and gas marketing 14,866,954 15,420,917 -
Oil and gas operations 948,270 200,330 68,054
Well services 5,574,335 4,297,414 2,611,226
Other 1,966,745 3,044,495 537,981
------------ ------------- ------------
Total $ 53,459,250 $ 56,948,116 $ 28,623,099
============ ============= ============
Intersegment revenue
Well services $ 983,910 $ 226,179 $ 2,261,462
Other 228,857 235,598 267,176
------------ ------------- ------------
Total $ 1,212,767 $ 461,777 $ 2,528,638
============ ============= ============
Interest revenue
Turnkey contracts $ 23,003 $ 309,275 $ 23,904
Oil and gas marketing - - -
Oil and gas operations 81,001 8,260 -
Well services 17,183 - 18,458
Other 2,084,752 2,375,209 1,866,443
Intersegment elimination (228,857) (235,598) (267,176)
------------ ------------- ------------
Total $ 1,977,082 $ 2,457,146 $ 1,641,629
============ ============= ============
Consolidated revenues
Total segment revenue $ 52,476,415 $ 54,129,800 $ 30,346,580
Other 2,195,602 3,280,093 805,157
Intersegment elimination (1,212,767) (461,777) (2,528,638)
------------ ------------- ------------
Total $ 53,459,250 $ 56,948,116 $ 28,623,099
============ ============= ============
F-42
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE Q - SEGMENT INFORMATION - CONTINUED
2001 2000 1999
------------ ------------- ------------
Interest expense
Turnkey contracts $ 116,933 $ 478,832 $ 109,340
Oil and gas marketing - - -
Oil and gas operations - - -
Well services 292,515 335,111 399,959
Other 5,595,643 6,389,505 5,549,198
Elimination of intersegment (228,857) (235,598) (267,176)
------------ ------------- ------------
Total $ 5,776,234 $ 6,967,850 $ 5,791,321
============ ============= ============
Depreciation, depletion and amortization
Turnkey contracts $ 100,450 $ 89,301 $ 28,286
Oil and gas marketing - - -
Oil and gas operations 12,899,648 2,476,036 8,730,369
Well services 961,253 362,682 409,570
Other 500,768 137,441 29,458
------------ ------------- ------------
Total $ 14,462,119 $ 3,065,460 $ 9,197,683
============ ============= ============
Operating loss
Turnkey contracts $ 2,458,217 $ 11,218,926 $ 7,303,547
Oil and gas marketing (431,888) (379,341) -
Oil and gas operations (12,438,133) (2,622,793) (8,704,996)
Well services 2,367,993 915,717 845,253
Other (12,878,081) (10,740,149) (9,821,032)
------------ ------------- ------------
Total $(20,921,892) $ (1,607,640) $(10,377,228)
============ ============= ============
Assets
Turnkey contracts $ 33,592,593 $ 49,587,787 $ 38,793,726
Oil and gas marketing 192,642 192,642 -
Oil and gas operations 45,080,072 37,621,395 12,720,938
Well services 4,471,379 4,364,664 4,262,794
Other 11,563,528 36,882,410 26,366,553
------------ ------------- ------------
Total $ 94,900,214 $ 128,648,898 $ 82,144,011
============ ============= ============
F-43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE Q - SEGMENT INFORMATION - CONTINUED
2001 2000 1999
------------ ------------- ------------
Capital expenditures
Turnkey contracts $ 42,616 $ - $ 345,977
Oil and gas marketing - 192,642 -
Oil and gas operations 16,955,738 20,764,859 22,300,079
Well services 92,315 5,253 66,468
Other 43,418 22,974 15,723
------------ ------------- ------------
Total $ 17,134,087 $ 20,985,728 $ 22,728,247
============ ============= ============
NOTE R - SUBSEQUENT EVENTS
On February 14, 2002, the Company completed the sale of substantially all
of the assets of Pinnacle, which consists of the workover/recompletion rig
portion of the Company's well services business, for a purchase price of
$4.2 million to Basic Energy Services, Inc. ("Basic Energy"). Under the
purchase agreement dated as of December 31, 2001, Basic Energy paid the
Company $3.7 million in cash at the closing and $500,000 in contract
drilling services credits issued by Basic Energy, which may be utilized by
the Company over a three-year period with a maximum of $25,000 in any
month. Additionally, the Company entered into a non-compete agreement with
Basic Energy.
F-44
INDEX TO EXHIBITS
Exhibit
No. Description
- ------- -----------------------------------
2.1* Stock Exchange Agreement, dated September 1, 2000, by and among the Registrant, Petroleum Development
Corporation, James C. Johnson, Jr. and Gregory S. Johnson.
3.1* Certificate of Incorporation of Registrant dated June 11, 1990
3.2* Amendment to Certificate of Incorporation of Registrant dated November 15, 1990
3.3* Amendment to Certificate of Incorporation of Registrant dated November 4, 1992
3.4* Amendment to Certificate of Incorporation of Registrant dated September 3, 1996
3.5* Bylaws of the Registrant, dated June 12, 1990
4.1* Form of Stock Certificate for Common Stock
4.2* Indenture between the Registrant and Continental Stock Transfer and Trust Company, as Trustee, dated
December 1, 2000 regarding 12% debentures due December 31, 2007
4.3* Form of Bond Certificate for 12% debentures due December 31, 2007
4.4* Indenture between the Registrant and Continental Stock Transfer
and Trust Company, as Trustee, dated February 1, 1999 regarding
13.02% debentures due December 31, 2010 and December 31, 2015
4.5* Form of Bond Certificate for 13.02% debentures due December 31, 2010
4.6* Form of Bond Certificate for 13.02% debentures due December 31, 2015
4.7* Form of Class A Warrant
4.8* Form of Class B Warrant
4.9* Form of Class C Warrant
4.10* Form of Class D Warrant
10.1* 2000 Equity Incentive Plan for Pedco Subsidiary
10.2* Amendment to 2000 Stock Incentive Plan for Pedco Subsidiary
10.3* 2001 Stock Incentive Plan
10.4* 2001 Key Employee Stock Incentive Plan
10.5* Employment Agreement dated January 1, 2001, between the Registrant and Norman F. Swanton
10.6* Employment Agreement dated January 1, 2001, between the Registrant and Timothy A. Larkin
10.7* Employment Agreement dated September 14, 2000, between the Registrant and James C. Johnson, Jr.
10.8* Employment Agreement dated September 14, 2000, between the Registrant and Gregory S. Johnson
10.9* Employment Agreement dated May 7, 2001, between the Registrant and Jack B. King
10.10* Employment Agreement dated June 25, 2001, between the Registrant and David E. Fleming
10.11* Form of Indemnification Agreement
10.12* Joint Venture Agreement dated May 24, 1999, by and between Warren Resources of California, Inc., Warren
Development Corp., Pedco and Magness Petroleum Company
10.13** Crude Oil Sale and Purchase Contract dated November 7, 1996, between Huntway Refining Company and
Magness Petroleum Company
10.14* May 11, 2000 Agreement to Amend the Price and Term Clauses of the Crude Oil Sale and Purchase Contract
dated November 7, 1996, between Huntway Refining Company and Magness Petroleum Company
10.15* Gas Purchase Agreement dated January 28, 2000, by and between Western Gas Resources, Inc. and Big Basin
Petroleum, LLC
10.16* December 20, 2000 Letter of Agreement to Amend the Gas Purchase Contract dated January 28, 2000, between
Western Gas Resources Inc. and Petroleum Development Corp., as successor in interest to Big Basin
Petroleum, LLC
10.17* Gas Purchase and Sales Contract dated April 1, 2000, between the Registrant and Tenaska Marketing
Ventures
10.18* Form of Partnership Production Marketing Agreement
11+ Statements regarding Computation of Per Share Earnings (included in Item 14)
21.1* Subsidiaries of the Registrant
23.1+ Consent of Williamson Petroleum Consultants, Inc.
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*Incorporated by reference to the Company's Registration Statement on Form 10,
Commission File No. 000-33275, filed on October 26, 2001.
**Incorporated by reference to the Company's Amendment No. 1 to Registration
Statement on Form 10/A, Commission File No. 000-33275, filed on March 6, 2002.
+ Filed herewith.
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