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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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<PAGE>




                              WARREN RESOURCES INC.

                                    FORM 10-K

                                TABLE OF CONTENTS
<TABLE>
<CAPTION>
                 PART I                                                                                     Page
                                                                                                           ----
                 <S>            <C>                                                                        <C>
                 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
</TABLE>


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<PAGE>

                             ----------------------

     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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<PAGE>

     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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<PAGE>

          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


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<PAGE>

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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<PAGE>

     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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<PAGE>

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.


                                       9
<PAGE>

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
<PAGE>

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
<PAGE>

     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
<PAGE>

     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
<PAGE>
<TABLE>
<CAPTION>
                                                                      Year Ended December 31,
                                                                    ---------------------------
                                                                    1999         2000           2001
                                                                    ----         ----           ----
         <S>                                                     <C>            <C>            <C>
         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

</TABLE>
     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
<PAGE>
Productive Wells

     The  following  table sets forth our gross and net  productive  wells as of
December 31, 2001:
<TABLE>
<CAPTION>
                                   Natural Gas Wells                  Oil Wells                        Total
                              -----------------------------    ------------------------     ----------------------------
                                 Gross             Net          Gross          Net            Gross             Net
                              -------------    ------------    ---------    -----------     ----------       -----------
  <S>                         <C>              <C>             <C>          <C>             <C>              <C>
  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
                              =============    ============    =========    ===========     ==========       ===========
</TABLE>
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:
<TABLE>
<CAPTION>
                                                 Year Ended December 31,
                            -----------------------------------------------------------------
                                   1999                   2000                    2001
                            -------------------    --------------------    ------------------
                             Gross       Net
<S>                         <C>         <C>        <C>          <C>        <C>        <C>
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
                            =======     ======     =======      ======     =======    =======
</TABLE>
------------
(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:
<TABLE>
<CAPTION>
                                       Developed                     Undeveloped                       Total
                              -----------------------------    ------------------------     --------------------------
                                 Gross             Net           Gross          Net           Gross             Net
                              -------------    ------------    ----------    ----------     ----------       ---------
  <S>                         <C>              <C>             <C>           <C>            <C>              <C>
  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
                              =============    ============    ==========    ==========     ==========       =========
</TABLE>
(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
<PAGE>

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.
<TABLE>
<CAPTION>
                                                          Years Ended December 31,
                                                      --------------------------------
                                                         1999        2000       2001
                                                      ----------   --------   --------
<S>                                                   <C>          <C>        <C>
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

</TABLE>
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
<PAGE>

     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
<PAGE>

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
<PAGE>
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
<PAGE>

     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.

                                       20
<PAGE>

     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
<PAGE>

     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
<PAGE>

     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
<PAGE>
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
<PAGE>

     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
<PAGE>

     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
<PAGE>

     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
<PAGE>

     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
<PAGE>

     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
<PAGE>
<TABLE>
<CAPTION>
                                                                         Year ended December 31,
                                                 -----------------------------------------------------------------
                                                    1997         1998          1999          2000          2001
                                                 ----------   ----------   -----------   -----------   -----------
                                                           (Amounts in thousands, except share information)
<S>                                              <C>          <C>          <C>           <C>           <C>
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)
</TABLE>
<TABLE>
<CAPTION>
                                                                         Year ended December 31,
                                                 ---------------------------------------------------------------
                                                  1997          1998         1999          2000          2001
                                                 -------      -------      -------       --------      ---------
<S>                                              <C>          <C>          <C>           <C>           <C>
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)
</TABLE>

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
<PAGE>

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
<PAGE>

     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
<PAGE>

     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
<PAGE>

     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.

<TABLE>
<CAPTION>
                                                                            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

<S>                                                  <C>             <C>           <C>           <C>            <C>
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
                                                     -----------     -----------   -----------   -----------    -----------
</TABLE>

     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.
<TABLE>
<CAPTION>
                                                             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

<S>                                                  <C>             <C>           <C>            <C>            <C>
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
                                                     ------------    -----------   ------------   ------------   ------------
</TABLE>

     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
<PAGE>

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
<PAGE>

     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
<PAGE>

     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
<PAGE>

     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
<PAGE>

     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
<PAGE>

     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
<PAGE>


                          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
<PAGE>

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
<PAGE>

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
<PAGE>

               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
<PAGE>


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
<PAGE>

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
<PAGE>

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
<PAGE>

               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
<PAGE>

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
<PAGE>

               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
<PAGE>

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
<PAGE>


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
<PAGE>

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:
<TABLE>
<CAPTION>

Name                                  Age     Position
<S>                                   <C>     <C>
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
</TABLE>
---------------------
(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
<PAGE>

     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
<PAGE>

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
<PAGE>

     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
<PAGE>

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
<PAGE>

<TABLE>
<CAPTION>
                                                   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
-------------------------------   -----     ---------     --------   --------------   ----------     --------------
<S>                               <C>        <C>          <C>         <C>             <C>            <C>
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
</TABLE>

(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.
<TABLE>
<CAPTION>
                                                 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%
                                ----------    ----------    --------    ----------   ----------    ----------
<S>                             <C>           <C>           <C>         <C>          <C>           <C>
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
</TABLE>
-----------------------

(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
<PAGE>

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
<PAGE>

     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
<PAGE>

     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
<PAGE>

     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
<PAGE>

          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
<PAGE>

          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
<PAGE>

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.
<TABLE>
<CAPTION>

                                                                      Shares of Common Stock     Percent of
        Name of Beneficial Owner                                        Beneficially Owned       Ownership
------------------------------------------------                     -----------------------    -----------
<S>                                                                  <C>                        <C>
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%
</TABLE>
-------------------
* 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
<PAGE>

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
<PAGE>
                                     PART IV

Item 14: Exhibits, Financial Statement Schedules and Reports on Form 8-K

(a) (1) Financial Statements
<TABLE>
<CAPTION>
                                                                       Form 10-K
                                                                        Pages
                                                                       ---------
<S>                                                                    <C>

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
</TABLE>
(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.
<TABLE>
<CAPTION>
Exhibit
  No.              Description
------        __________________________________
<S>           <C>
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
</TABLE>


                                       67
<PAGE>

<TABLE>
<CAPTION>
Exhibit
  No.              Description
------        __________________________________
<S>           <C>

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.

-------------------------
</TABLE>
*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
<PAGE>

                                   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.
<TABLE>
<CAPTION>


                                      Signature                  Title (Principal Function)         Date
                         <S>                                   <C>                               <C>
                                 /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
</TABLE>



                                       69
<PAGE>

                          INDEX TO FINANCIAL STATEMENTS


<TABLE>
<CAPTION>
                                                                          Page
                                                                          ----
<S>                                                                       <C>
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
</TABLE>


                                      F-1
<PAGE>



               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
<PAGE>



                     Warren Resources Inc. and Subsidiaries


                           CONSOLIDATED BALANCE SHEETS

                                  December 31,
<TABLE>
<CAPTION>


                                    ASSETS                                                       2001            2000
                                                                                            -------------   --------------
<S>                                                                                          <C>            <C>
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
</TABLE>
<TABLE>
<CAPTION>
                                                                                             ============   =============

         LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
<S>                                                                                          <C>            <C>
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
                                                                                             ============   =============
</TABLE>

        The accompanying notes are an integral part of these statements.



                                      F-3
<PAGE>



                      CONSOLIDATED STATEMENTS OF OPERATIONS

                             Year ended December 31,
<TABLE>
<CAPTION>


                                                                                   2001            2000          1999
                                                                                -----------    -----------   ------------
<S>                                                                            <C>             <C>           <C>
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
</TABLE>



        The accompanying notes are an integral part of these statements.

                                       F-4

<PAGE>
            CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (DEFICIT)

                  Years ended December 31, 2001, 2000 and 1999
<TABLE>
<CAPTION>
                                                                                              Accumulated                Total
                                                     Common stock     Additional                  other               stockholder's
                                                --------------------  Paid-in    Accumulated  Comprehensive Treasury    equity
                                                 Shares     Amount     capital      deficit   income (loss)  Stock     (deficit)
                                                ----------  -------- ----------- ------------ ------------- --------   ----------
<S>                                             <C>         <C>      <C>         <C>           <C>          <C>        <C>
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)
                                                ========== ========= =========== ============  ============ ========   ============
</TABLE>
         The accompanying notes are an integral part of this statement.

                                      F-5
<PAGE>



                      CONSOLIDATED STATEMENTS OF CASH FLOWS

                             Year ended December 31,
<TABLE>
<CAPTION>
                                                                                    2001              2000               1999
                                                                                ------------       ------------     ------------
<S>                                                                             <C>                <C>              <C>
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
                                                                                ============       ============     ============

</TABLE>

        The accompanying notes are an integral part of these statements.

                                       F-6
<PAGE>


                CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED

                             Year ended December 31,
<TABLE>
<CAPTION>
                                                                                    2001              2000               1999
                                                                                ------------       ------------     ------------
<S>                                                                             <C>                <C>              <C>
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
                                                                                                                  =============
</TABLE>




        The accompanying notes are an integral part of these statements.

                                       F-7
<PAGE>



                   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
<PAGE>



             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
<PAGE>
             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
<PAGE>

             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
<PAGE>

             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
<PAGE>
             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
<PAGE>

             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:
<TABLE>
<CAPTION>

                                                                                            2001              2000
                                                                                         -----------       ----------
       <S>                                                                               <C>               <C>
       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
                                                                                        ===========       ===========
</TABLE>

     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:
<TABLE>
<CAPTION>

                                                                                     Year ended December 31,
                                                                       -----------------------------------------------
                                                                            2001              2000            1999
                                                                       --------------    --------------    -----------
       <S>                                                             <C>               <C>               <C>
       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

</TABLE>


                                      F-14
<PAGE>

             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
<PAGE>



             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:
<TABLE>
<CAPTION>

                                                                                                  December 31,
                                                                                         -----------------------------
                                                                                              2001              2000
                                                                                         --------------    -----------
       <S>                                                                               <C>               <C>
       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
                                                                                         ==========        ==========
</TABLE>



                                      F-16
<PAGE>

             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.
<TABLE>
<CAPTION>


                                                                                          Amortized       Estimated
                                                                                             cost         fair value
                                                                                         ----------       ----------
       <S>                                                                               <C>              <C>
       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
                                                                                         ==========       ==========
</TABLE>

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.

<TABLE>
<CAPTION>

                                                                                          Carrying
                                                                                            value       Fair value
                                                                                         ----------     ----------
       <S>                                                                               <C>            <C>
       Goodwill                                                                          $  223,042     $        -
       Property and equipment                                                             4,345,156      3,742,941
                                                                                         ----------     ----------

                                                                                         $4,568,198     $3,742,941
                                                                                         ==========     ==========
</TABLE>

                                      F-17
<PAGE>

             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:
<TABLE>
<CAPTION>

                                                                                             2001              2000
                                                                                         -----------       -----------
     <S>                                                                                 <C>               <C>
     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

</TABLE>


                                      F-18
<PAGE>



             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

                        December 31, 2001, 2000 and 1999


NOTE D - LONG-TERM DEBT - CONTINUED
<TABLE>
<CAPTION>

                                                                                             2001              2000
                                                                                         -----------       -----------
     <S>                                                                                 <C>               <C>
     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
                                                                                         ===========       ===========
</TABLE>

    Other long-term debt consists of the following at December 31:
<TABLE>
<CAPTION>

                                                                                             2001              2000
                                                                                         -----------       -----------
     <S>                                                                                 <C>               <C>


     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
                                                                                         ===========       ===========
</TABLE>

     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
<PAGE>

             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:
<TABLE>
<CAPTION>


             2001                                                       Outstanding      Per Share
             ----                                    Maturity            principal      conversion       Common shares
                                                      date                amount           price         if converted
                                                -----------------       -------------   ----------       -------------
    <S>                                         <C>                     <C>             <C>              <C>
    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
                                                                        =============                    =============
</TABLE>
<TABLE>
<CAPTION>

             2000                                                       Outstanding      Per Share
             ----                                    Maturity            principal      conversion       Common shares
                                                      date                amount           price         if converted
                                                -----------------       -------------   ----------       -------------
    <S>                                         <C>                     <C>             <C>              <C>
    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
                                                                        =============                    =============
</TABLE>


                                      F-20
<PAGE>



             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

                        December 31, 2001, 2000 and 1999


NOTE D - LONG-TERM DEBT - CONTINUED
<TABLE>
<CAPTION>

             1999                                                       Outstanding      Per Share
             ----                                    Maturity            principal      conversion       Common shares
                                                      date                amount           price         if converted
                                                -----------------       -------------   ----------       -------------
    <S>                                         <C>                     <C>             <C>              <C>
    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
                                                                        =============                    =============
</TABLE>

     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
<PAGE>



             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:
<TABLE>
<CAPTION>

                     Fiscal year ending December 31
                         <S>                                                           <C>

                         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
</TABLE>
    Annual sinking fund requirements are as follows:
<TABLE>
<CAPTION>

                     Fiscal year ending December 31
                         <S>                                                           <C>

                         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
</TABLE>

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
<PAGE>

             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.
<TABLE>
<CAPTION>
                                                                      2001            2000           1999
                                                                  ------------    -----------     ------------
       <S>                                                        <C>             <C>             <C>
       Net loss
           As reported                                            $(21,073,592)   $(1,195,640)    $(11,079,228)
           Pro forma                                              $(21,360,468)   $(1,366,787)    $(11,081,618)
</TABLE>

     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
<PAGE>

             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.
<TABLE>
<CAPTION>


                                                                         Class B      Class C     Class D     Incentive
                                                                         Warrants     Warrants    Warrants      Options
                                                                        ---------     --------    --------    ----------
       <S>                                                              <C>          <C>         <C>         <C>

       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
</TABLE>


                                      F-24
<PAGE>

             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.
<TABLE>
<CAPTION>
                                                                               Class B         Class C       Class D
                                                                              Warrants        Warrants      Warrants
                                                                             ----------      ----------    ----------
       <S>                                                                   <C>             <C>           <C>
       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
</TABLE>


                                      F-25
<PAGE>



             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

                        December 31, 2001, 2000 and 1999


NOTE E - STOCKHOLDERS' EQUITY - CONTINUED
<TABLE>
<CAPTION>
                                                                               Class B         Class C       Class D
                                                                              Exchange        Exchange      Exchange
                                                                              Warrants        Warrants      Warrants
                                                                             ----------      ----------    ----------
       <S>                                                                   <C>             <C>           <C>
       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     $        -
</TABLE>

                                      F-26
<PAGE>



             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:
<TABLE>
<CAPTION>

                                                                            2001           2000          1999
                                                                       -------------   ----------   -----------
       <S>                                                             <C>             <C>          <C>
       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
                                                                       =============   =========    ===========
</TABLE>

     The  components of the net deferred tax asset are as follows as of December
     31:
<TABLE>
<CAPTION>

                                                                                             2001         2000
                                                                                       -----------   ------------
       <S>                                                                             <C>           <C>
       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                                                          $         -   $          -
                                                                                       ===========   ============
</TABLE>

     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
<PAGE>



             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
<PAGE>



             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
<PAGE>



             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:
<TABLE>
<CAPTION>
                     Year ending December 31
                     <S>                                 <C>
                         2002                            $   229,677
                         2003                                182,350
                         2004                                155,686
                         2005                                155,686
                         2006                                155,686
                         Thereafter                          194,607
                                                         -----------
                                                         $ 1,073,692
                                                         ===========
</TABLE>
     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
<PAGE>



             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
<PAGE>



             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
<PAGE>
             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
<PAGE>

             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.

<TABLE>
<CAPTION>
                                                                           2001                     2000
                                                         -----------------------------    --------------------------
                                                            Fair            Carrying           Fair       Carrying
                                                            value            amount            value        amount
                                                         ------------     ------------    -----------   -----------
       <S>                                               <C>              <C>             <C>           <C>
       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)              -             -
                                                          ===========      ===========    ============   ===========
</TABLE>

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
<PAGE>

             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:
<TABLE>
<CAPTION>
       Estimated fair value of assets acquired
       <S>                                                       <C>

           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
                                                                 ===========
</TABLE>

     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.
<TABLE>
<CAPTION>
                                                                                           Pro Forma (unaudited)
                                                                                      ----------------------------
                                                                                         Year ended December 31,
                                                                                         2000               1999
                                                                                      -----------     ------------
       <S>                                                                            <C>             <C>
       Revenues                                                                       $57,861,658     $ 28,984,768
                                                                                      ===========     ============

       Net loss                                                                       $  (996,746)    $(11,232,068)
                                                                                      ===========     ============
       Loss per share
           Basic and diluted                                                          $      (.07)    $       (.88)
</TABLE>


     The  operations  of Pedco are  included  in the  accompanying  consolidated
     financial statements subsequent to the acquisition.



                                      F-35
<PAGE>



             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:
<TABLE>
<CAPTION>

       Estimated fair value of assets acquired
           <S>                                               <C>

           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
                                                             ============
</TABLE>

     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
<PAGE>



             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:
<TABLE>
<CAPTION>

                                                                         2001             2000          1999
                                                                    ------------      -----------   ------------
       <S>                                                          <C>               <C>           <C>
       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
                                                                    ============      ===========   ============
</TABLE>

     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:
<TABLE>
<CAPTION>

                                                                                          2001               2000
                                                                                      -----------        -----------
       <S>                                                                            <C>                <C>
       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
                                                                                      ===========        ===========
</TABLE>

     The following table sets forth the Company's results of operations from oil
     and natural gas producing activities for the years ended December 31:
<TABLE>
<CAPTION>
                                                                          2001               2000           1999
                                                                    ------------        ------------     -----------
       <S>                                                          <C>                 <C>              <C>
       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)
                                                                    ============        ============     ===========
</TABLE>


                                      F-37
<PAGE>



             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
<PAGE>



             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.
<TABLE>
<CAPTION>

                      Summary of Changes in Proved Reserves

                                                                          Year ended December
                                                      ----------------------------------------------------------------
31,                                                            2001                 2000                   1999
                                                      -------------------    ------------------      -----------------
                                                         Bbls       Mcf        Bbls       Mcf         Bbls       Mcf
                                                      -------    --------    --------   -------      ------     ------
                                                                            (Amounts in thousands)
       <S>                                            <C>        <C>         <C>        <C>          <C>        <C>
       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
</TABLE>


            Standardized Measure of Discounted Future Net Cash Flows
                     Relating to Proved Oil and Gas Reserves
<TABLE>
<CAPTION>

                                                                                              December  31,
                                                                              -----------------------------------------
                                                                                 2001            2000            1999
                                                                              ---------       ---------        --------
                                                                                         (Amounts in thousands)
      <S>                                                                      <C>             <C>             <C>
       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
                                                                               =========       =========       =-=======
</TABLE>



                                      F-39
<PAGE>



             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
<TABLE>
<CAPTION>


                                                                                           Year ended December 31,
                                                                              -----------------------------------------
                                                                                  2001            2000          1999
                                                                              ---------       ---------       ---------
                                                                                             (Amounts in thousands)
       <S>                                                                    <C>             <C>             <C>
       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
                                                                              =========       =========       =========
</TABLE>

     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
<PAGE>



             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:
<TABLE>
<CAPTION>

                                                                                 2001
                                        --------------------------------------------------------------------------------
                                                                   Quarter                                   Year
                                        -------------------------------------------------------------    ------------
                                           First             Second           Third         Fourth
                                        -----------      -----------      -----------    ------------
       <S>                              <C>              <C>              <C>            <C>             <C>

       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)

</TABLE>

<TABLE>
<CAPTION>
                                                                                   2000
                                          --------------------------------------------------------------------------------
                                                                     Quarter                                   Year
                                          -------------------------------------------------------------    ------------
                                             First             Second           Third         Fourth
                                          -----------      -----------      -----------    ------------
       <S>                                <C>              <C>              <C>            <C>             <C>
       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)
</TABLE>


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
<PAGE>



             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:
<TABLE>
<CAPTION>

                                                                       2001                 2000               1999
                                                                   ------------        -------------       ------------
       <S>                                                         <C>                 <C>                 <C>
       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
                                                                   ============        =============       ============
</TABLE>


                                      F-42
<PAGE>



             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

                        December 31, 2001, 2000 and 1999


NOTE Q - SEGMENT INFORMATION - CONTINUED

<TABLE>
<CAPTION>

                                                                       2001                 2000               1999
                                                                   ------------        -------------       ------------
       <S>                                                         <C>                 <C>                 <C>
       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
                                                                   ============        =============       ============

</TABLE>


                                      F-43
<PAGE>



             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

                        December 31, 2001, 2000 and 1999


NOTE Q - SEGMENT INFORMATION - CONTINUED

<TABLE>
<CAPTION>

                                                                       2001                 2000               1999
                                                                   ------------        -------------       ------------
       <S>                                                         <C>                 <C>                 <C>
       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
                                                                   ============        =============       ============
</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>
                                INDEX TO EXHIBITS
Exhibit
  No.              Description
-------       -----------------------------------
<S>           <C>
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.

</TABLE>
-------------------------

*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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