UNITED STATES 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

[ ]  Transition  Report  pursuant to Section 13 or 15(d) of the Securities Act
     of 1934

                          Commission File No. 333-42641

                                RAM ENERGY, INC.
             (Exact name of registrant as specified in its charter)

          Delaware                                        52-1535102
(State or other jurisdiction of                        (I.R.S. Employer
incorporation or organization)                        Identification No.)

   5100 East Skelly Drive, Suite 650
             Tulsa, Oklahoma                                74135
(Address of principal executive offices)                  (Zip Code)

       Registrant's telephone number, including area code: (918) 663-2800

        Securities registered pursuant to Section 12(b) of the Act: None

        Securities registered pursuant to Section 12(g) of the Act: None

     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  amendments  to
this Form 10-K. _____

     As of March  31,  2002,  there  were  outstanding  2,727,000  shares of the
registrant's  common  stock,  $.01 par  value per  share.  The  common  stock is
privately held by affiliates of the registrant.

     Documents incorporated by reference: None
<PAGE>

                                RAM ENERGY, INC.

                           Annual Report on Form 10-K
                      for the Year Ended December 31, 2001

                                Table of Contents

          Item Number Page

                                     PART I

1    Business. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2    Properties. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3    Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4    Submission of Matters to a Vote of Security Holders . . . . . . . . . . .

                                     PART II

5    Market for Registrant's Common Equity and Related Matters   . . . . . . .
6    Selected Financial Data   . . . . . . . . . . . . . . . . . . . . . . . .
7    Management's Discussion and Analysis of Financial Condition and
         Results of Operations   . . . . . . . . . . . . . . . . . . . . . . .
7A   Quantitative and Qualitative Disclosure About Market Risk   . . . . . . .
8    Financial Statements and Supplementary Data   . . . . . . . . . . . . . .
9    Changes in and Disagreements with Accountants on Accounting
         And Financial Disclosure  . . . . . . . . . . . . . . . . . . . . . .

                                    PART III

10   Directors and Executive Officers of Registrant  . . . . . . . . . . . . .
11   Executive Compensation  . . . . . . . . . . . . . . . . . . . . . . . . .
12   Security Ownership of Certain Beneficial Owners and Management  . . . . .
13   Certain Relationships and Related Transactions  . . . . . . . . . . . . .

                                     PART IV

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

                                  ATTACHMENT I

8    Audited Financial Statements . . . . . . . . . . . . . . . . . . . .Last
<PAGE>
                                     PART I

Item 1   Business

General

RAM Energy,  Inc. is an independent,  natural gas-focused company engaged in the
exploration  and  production of natural gas and oil properties and the ownership
and  operation of a natural gas and oil pipeline  system in northwest  Oklahoma.
Our core  operating  areas are the Permian Basin,  Gulf Coast and  Mid-Continent
regions, where we have been active since 1987. Our management team has extensive
technical and operating  expertise in all areas of our  geographic  focus.  From
1989 to November 1996, we primarily  developed and operated  natural gas and oil
properties  owned jointly with a limited  partnership in which we and one of our
affiliates were the general partners and an institutional  investor was the sole
limited  partner.  We  acquired  all of the  partnership's  natural  gas and oil
properties  and other assets in November  1996. In February 1998, as part of our
acquisition  of  Carlton  Resources,  Inc.,  we  acquired  natural  gas  and oil
properties and a natural gas and oil pipeline. In 1999, we expanded our strategy
to include exploration activities. Effective December 1, 2001, we sold to Carmen
Acquisition  Corp.  a  substantial  number of our  producing  and  non-producing
natural gas and oil  properties  located in  Oklahoma,  Texas and New Mexico for
$76.0 million.  The sale involved  approximately 86 Bcfe of proved reserves,  of
which  approximately  27 Bcfe were  undeveloped  reserves.  This  sale  included
substantially  all of our natural gas and oil  properties  in the Deep  Anadarko
Basin of  southwest  Oklahoma  and  northwest  Texas and the  Anadarko  Shelf of
western Oklahoma and the Texas  panhandle,  and a portion of our natural gas and
oil  properties  in the Permian  Basin area of west Texas and  southeastern  New
Mexico.  As a result of this sale,  we have changed the focus of our business to
accelerate our  exploration  program and expand our natural gas and oil pipeline
system.  This report  includes our drilling  results and production  information
with respect to our interests in the natural gas and oil properties that we sold
to Carmen Acquisition until the effective date of sale.

At December 31, 2001, our estimated net proved reserves were 46.9 Bcfe, of which
76% were natural gas, with a PV-10 Value of  approximately  $40.5 million before
income taxes. Our proved developed reserves comprised 67% of our total reserves,
and our reserve life for total proved  reserves was  approximately  16 years. At
December 31, 2001, we operated 127 wells, representing  approximately 60% of our
PV-10 Value. In addition to our proved  reserves,  our wholly owned  subsidiary,
Great  Plains   Pipeline   Company   (formerly  known  as  Magic  Circle  Energy
Corporation),  owns and operates a 182-mile  natural gas and oil pipeline system
and saltwater disposal operation located in the Anadarko Shelf area in Oklahoma.
Our pipeline system generated approximately $2.9 million of cash flow from third
parties during 2001.

Through our Great Plains pipeline system, we purchase natural gas and oil at the
well  head  and  transport  the  production,  with  associated  saltwater,  to a
collection and separation facility that we operate. From this point, the natural
gas is delivered to a processing and  compression  facility  operated by a third
party operator. After processing, gas volumes are returned to us and sold into a
variety of delivery points.  Oil purchasing and saltwater  disposal  comprise an
integrated  operation  whereby oil and  saltwater  are gathered at the lease and
subsequently  measured and transported to a central facility through the liquids
gathering  line.  Upon  separation,  the oil is aggregated and sold at a central
sales point to a number of crude purchasers,  and the saltwater is disposed into
our saltwater disposal well.

Until 1998,  we had grown  principally  through our  acquisitions  of  producing
properties and the further  development of these  acquired  properties.  We have
acquired  approximately  $242.0 million of natural gas and oil properties  since
1989. Since 1998, we have grown primarily  through  drilling of new wells.  From
1989 through  December 31, 2001, we drilled or  participated  in the drilling of
359  natural  gas and  oil  wells  with a 92%  success  rate.  Since  1996,  our
historical  average  finding  cost  from  all  sources  has been $ 0.79 per Mcfe
including  revisions  of  previous   estimates.   While  we  believe  there  are
substantial additional acquisition,  development and exploitation  opportunities
in our core  areas,  we  intend  to give  greater  emphasis  to our  exploration
activities,  including the acquisition of 2-D and 3-D seismic data, the internal
generation of exploratory  prospects and  participation in exploratory  drilling
prospects generated by industry partners.

In 2001,  we drilled 17 wells with a success  ratio of 82%. In addition,  during
2001 we increased our proved reserves by 3.0 Bcfe, including revisions.  For the
year ended December 31, 2001, we had EBITDA of $14.7 million, or $1.99 per Mcfe,
excluding  the gain  from our sale of natural gas and oil  properties  to Carmen
Acquisition  Corp.  Also in 2001,  we acquired  leasehold  acreage on internally
generated exploration  prospects.  We currently have identified four exploration
prospects on which we have  acquired  leasehold  acreage and intend to drill all
four of these prospects in 2002.

We participated in 5 exploration projects in 2001; of these 3 were successful, 1
was a dry hole and 1 is still being  evaluated.  We intend to participate in the
drilling of at least 4 new exploration projects in 2002.

Forward-Looking Statements

This  document  contains  forward-looking  statements  under the  meaning of the
federal  securities  laws.  All statements  other than  statements of historical
facts are based on, or express, our expectations about future events,  including
statements regarding such matters as:

-   the drilling of wells;
-   the development of proved undeveloped reserves;
-   the amount, nature and timing of other capital expenditures;
-   the timing and amount of future production;
-   future cash flow and liquidity;
-   future operating costs and other expenses;
-   future oil and gas prices;
-   budgets; and
-   future property acquisitions.

There are many factors  that could cause our  forward-looking  statements  to be
incorrect, including the effect of economic conditions generally, the results of
financing efforts, oil and gas price volatility,  market demand, and other risks
normally  associated  with the business of oil and gas drilling,  production and
marketing. Our forward-looking  statements speak only as of the date made and we
make no commitment to update these statements to reflect events or circumstances
that may occur after this date.

Strategy

Our  primary  goal is to enhance  stockholder  value by finding  and  developing
natural gas and oil  reserves,  increasing  the value of our natural gas and oil
pipeline  system and  reducing  our  indebtedness.  Key elements of our strategy
include the following:

     o    Exploration  Project   Development.   We  are  strongly  committed  to
          increasing  our emphasis on  exploration.  We intend to participate in
          the drilling of at least 4 new  exploration  projects in 2002. We will
          continue to acquire,  review and analyze 2D and 3D seismic  data,  and
          our experienced  technical staff will continue to generate exploratory
          projects and evaluate opportunities proposed by third parties.

     o    Expand Our Natural Gas and Oil Pipeline System. We will seek to expand
          our Great Plains  pipeline  system by connecting  additional  wells to
          increase the volume of natural gas and oil flowing through the system.
          We have  identified  a number of  natural  gas wells  scheduled  to be
          drilled this year and a large number of existing  wells in our area of
          service that we have targeted for  connection to our pipeline  system.
          We believe that our pipeline's ability to transport oil and saltwater,
          in  addition  to natural  gas,  gives us a  competitive  edge over the
          pipelines that move only natural gas.

     o    Develop and Exploit Existing  Natural Gas and Oil Properties.  We have
          identified   numerous  infill  drilling,   recompletion  and  workover
          opportunities  on our  properties  through  year-end  2003. We plan to
          selectively pursue these relatively lower-risk development activities.

     o    Complete  Selective Natural Gas and Oil  Acquisitions.  The members of
          our staff have many years of experience  in acquiring  and  exploiting
          natural gas and oil properties in our core areas.  Where feasible,  we
          will seek additional  acquisitions  of producing  properties that will
          provide us with opportunities for reserve additions and increased cash
          flow  through  operating  improvements,   production  enhancement  and
          additional development and exploratory drilling.

Our Strengths:

     o    Natural gas focus. At year-end 2001,  approximately  76% of our proved
          reserves  were natural gas. We will  continue our focus on natural gas
          properties and prospects. We believe that the economics of natural gas
          are more favorable than oil.

     o    Strong  management and technical  staff.  Our management and technical
          staff  possess  many years of  experience  in the  natural gas and oil
          industry, substantially all of which has been focused on operations in
          our two core areas.  We believe  that the  knowledge,  experience  and
          expertise of our staff will continue to support our efforts to enhance
          stockholder value.

     o    Drilling  success rate. Since 1989, we have drilled or participated in
          the drilling of 359 natural gas and oil wells with a 92% success rate,
          most of which were development wells in our core areas. Because of our
          increased  emphasis on exploration,  in future periods,  we expect our
          overall success rate to decline.

     o    Great Plains  pipeline  system.  Our Great Plains pipeline system is a
          182-mile  natural gas and oil pipeline  system and saltwater  disposal
          operation.  As the owner and  operator  of this  system,  we  purchase
          production  from  third  parties  at  the  wellhead,   transport  that
          production  through our system and sell it at a price in excess of our
          cost.  Our  ownership  of this  system  provides us with an asset that
          generates cash flow irrespective of fluctuations in prices for natural
          gas and oil.

     o    Operating  control.  We  currently  are the  operator  of  wells  that
          represent 61% of our PV-10 Value,  which allows us to control  capital
          allocation and expenses,  and the timing of additional development and
          exploitation of our producing properties.

Recent Events

Sale to  Carmen  Acquisition.  Effective  December  1,  2001,  we sold to Carmen
Acquisition  Corp., a subsidiary of Chesapeake  Energy  Corporation,  all of our
producing  and  non-producing  natural  gas and  oil  properties  located  in 17
counties in Oklahoma,  Texas and New Mexico.  The base  purchase  price of $76.0
million was paid 85% in cash and 15% by the  surrender  of  approximately  $11.1
million principal amount of our 11 1/2% senior notes due 2008. The sale included
approximately  86 Bcfe of proved  reserves  as of  December  1, 2001,  including
approximately 27 Bcfe of undeveloped  reserves.  At the time of the sale, Carmen
Acquisition owned 49.5% of our outstanding common stock.  Immediately  following
the sale, Carmen Acquisition sold all of our common stock owned by it to our two
principal  shareholders,  Larry E. Lee and  William W. Talley II. As a result of
this sale, Messrs. Lee and Talley own all of our outstanding common stock.

At the closing,  $7.5 million of the purchase  price was  deposited in escrow to
secure  post-closing  claims  for  title  and  environmental  defects  and other
matters.  As of March 31, 2002, we have received  approximately $3.0 million out
of the escrow account. Under the terms of the Asset Purchase Agreement governing
the sale,  the final date for  reconciling  claims against the escrow account is
April 3, 2002.

Our properties  sold to Carmen  Acquisition  included all of the properties that
were subject to volumetric  production payment in favor of a unit of Duke Energy
Corporation, and Carmen Acquisition assumed all obligations under the production
payment from and after the effective date of the sale.

Proceeds of the sale to Carmen Acquisition,  net of transaction costs, were used
to fully  repay  our  senior  secured  credit  facility  with  Foothill  Capital
Corporation  and to obtain a release of all mortgages  and other liens  securing
that facility,  to reduce our working capital deficit and to provide  additional
capital to fund our exploration and development activities.

     Summary Historical and Pro Forma Consolidated Financial and Other Data

The following table sets forth:

     o    certain  historical  consolidated  financial and other data for us for
          the year ended December 31, 2001; and

     o    certain pro forma financial and other data for the year ended December
          31, 2001.

We derived our summary historical consolidated financial data for the year ended
December 31, 2001 from our audited  consolidated  financial  statements included
elsewhere in this report. The pro forma results of operations for the year ended
December  31,  2001 give pro forma  effect to our sale of certain of our natural
gas and oil  properties  to Carmen  Acquisition  Corp.  as if such sale had been
completed  and the  proceeds  from such sale had been  applied  as of January 1,
2001.

The  summary  pro  forma  consolidated  financial  data are  based on  currently
available  information  and  assumptions  that we believe  are  reasonable.  The
summary pro forma  consolidated  financial data do not purport to represent what
our results of operations would have been if the pro forma transactions had been
completed  on the dates and for the periods  indicated,  nor do they  purport to
indicate our future results of operations. You should read the summary pro forma
consolidated financial data in conjunction with "Selected Consolidated Financial
and Other Data,"  "Management's  Discussion and Analysis of Financial  Condition
and Results of Operations," and the financial  statements and related notes that
we include elsewhere in this report.

                      (This space left blank intentionally)

<PAGE>
<TABLE>
<CAPTION>
                                                   Year Ended December 31, 2001
                                                   ----------------------------
                                                        Actual       Pro Forma
                                                        ------       ---------
Operating Statement Data:           (in thousands, except for per share amounts)
<S>                                                  <C>            <C>

Operating Revenues:
  Natural gas and oil sales                          $    25,404    $    10,900
  Pipeline system (1)                                     15,602         19,117
  Other                                                      210            210
                                                     -----------    -----------
         Total operating revenues                         41,216         30,227
Operating Expenses:
  Natural gas and oil production taxes                     2,755            872
  Natural gas and oil production expense                   5,975          2,910
  Pipeline system (1)                                     12,716         16,231
  Amortization and depreciation                            9,766          5,087
  Contract termination and severance payments              1,104             --
  General and administrative (2)                           4,061          5,173
                                                     -----------    -----------
         Total operating expenses                         36,377         30,273
                                                     -----------    -----------
  Operating income (loss)                                  4,839            (46)
Other income (expense)
  Gain on sales of natural gas and oil properties         17,320             --
  Interest expense (3)                                   (14,514)       (10,827)
  Interest income (4)                                        104            104
                                                     -----------    -----------
Income (loss) before income
    taxes and extraordinary items                          7,749        (10,769)
  Income tax (benefit)                                     2,900         (5,075)
                                                     -----------    -----------
Income (loss) before extraordinary items                   4,849         (5,694)
  Extraordinary items (net of applicable taxes)           (1,098)            --
                                                     -----------    -----------
Net income (loss)                                    $     3,751    $    (5,694)
                                                     ===========    ===========
Net Income (loss) per share - basic and diluted
  Income (loss)  before extraordinary items          $      1.78    $     (2.09)
                                                     ===========    ===========
  Extraordinary items                                $     (0.40)            --
                                                     ===========    ===========
Net income  (loss)                                   $      1.38    $     (2.09)
                                                     ===========    ===========
Weighted average shares outstanding                    2,727,000      2,727,000
</TABLE>

                      (This space left blank intentionally)
<PAGE>
<TABLE>
<CAPTION>
                                             Year Ended December 31, 2001
                                        -------------------------------------
Operating Data:                             Actual                  Pro Forma
                                            ------                  ---------
<S>                                         <C>                      <C>
Production volumes:
  Natural gas (MMcf)                         5,817                    1,396
  Oil and condensate (MBbls)                   261                      160
  Total (MMcfe)                              7,388                    2,359
Average realized prices: (5)
  Natural gas (per Mcf)                      $3.28                    $4.98
  Oil and condensate (per Bbl)              $24.09                   $24.57
  Per Mcfe                                   $3.44                    $4.62
Expenses (per Mcfe):
  Natural gas  and oil production taxes      $0.37                    $0.37
  Natural gas and oil production             $0.81                    $1.23
     expense
  Amortization and                           $1.32                    $2.16
     depreciation
  General and administrative                 $0.55                    $2.19

---------------
<FN>
(1)  Prior to sale of natural gas and oil  properties  owned by us and connected
     to the pipeline system,  inter-company purchases from these properties were
     eliminated  from both the revenues and costs of the  pipeline  system,  and
     reported as natural gas and oil sales.  The  increases in revenue and costs
     of the pipeline system shown in the Pro Forma column are the result of this
     inter-company elimination not being required.

(2)  The change in General and Administrative  expenses is the result of reduced
     costs due to staff  reductions of $528,000,  and increased costs due to the
     loss of Overhead  Income from third parties that is recorded as a reduction
     of General and Administrative expense.

(3)  The  change  in   interest   expense  is  the  result  of  the  receipt  of
     approximately  $11.1  million  of  11-1/2%  Senior  Notes  due 2008 and the
     pay-off of the Credit Facility in the approximate amount of $25.4 million.

(4)  Gives no effect to additional  interest  income on pro forma beginning cash
     balance of $27.0 million.

(5)  Reflects the actual realized prices received by the Company,  including the
     results of the Company's hedging activities.  See "Management's  Discussion
     and Analysis of Financial Condition and Results of Operations."
</FN>
</TABLE>

Reorganization  of  Certain  Subsidiaries.  In  connection  with the sale of our
properties  to  Carmen  Acquisition,   we  dissolved  the  wholly-owned  limited
partnership  that owned our  pipeline  system and certain of our natural gas and
oil  properties.  All of the oil and gas  properties  that had been owned by the
dissolved  limited  partnership  and its  partners  were  either  sold to Carmen
Acquisition or distributed to RAM Energy. The pipeline system was distributed to
and is now owned by and  operated  as the sole  asset of our  subsidiary,  Great
Plains Pipeline Company.

Net Production, Unit Prices and Costs

The following table presents certain information with respect to our natural gas
and oil  production,  prices and costs  attributable  to all natural gas and oil
properties  owned by us for the periods shown.  Average  realized prices reflect
the actual realized prices received by us,  including the results of our hedging
activities.

<TABLE>
<CAPTION>
                                                       Year Ended December 31,
                                                       -----------------------
     Operating Data:                              1999           2000            2001
                                                  ----           ----            ----
<S>                                             <C>            <C>             <C>
     Production volumes:
                 Natural gas (MMcf)              8,283          6,661           5,817
                 Oil and condensate (MBbls)        362            295             262
                 Total (MMcfe)                  10,456          8,430           7,388
     Average realized prices: (1)
                 Natural gas (per Mcf)           $2.08          $2.64           $3.28
                 Oil and condensate (per Bbl)    16.13          27.38           24.09
                 Per Mcfe                         2.21           3.04            3.44
     Expenses (per Mcfe):
                 Natural gas and oil
                      production taxes            0.19           0.33            0.37
                 Natural gas and oil
                      production expense          0.56           0.59            0.81
                 Amortization and
                      depreciation                1.24           1.20            1.32
                 General and administrative       0.42           0.40            0.55

---------------
<FN>
(1)  Reflects the actual realized prices received by the Company,  including the
     results of the Company's hedging activities.  See "Management's  Discussion
     and Analysis of Financial Condition and Results of Operations."
</FN>
</TABLE>

Producing Wells

The following table sets forth the number of productive  wells in which we owned
an interest as of December 31, 2001. Productive wells consist of producing wells
and  wells  capable  of  production,   including  gas  wells  awaiting  pipeline
connections and oil wells awaiting  connection to production  facilities.  Wells
that are completed in more than one producing horizon are counted as one well.

<TABLE>
<CAPTION>
                                       Gross            Net
                                       -----            ---
<S>                                     <C>             <C>
     Natural gas                        108              29
     Oil                                752             137
                                        ---             ---
              Total                     860             166
                                        ===             ===
</TABLE>

Acreage

The  following  table sets forth our  developed  and  undeveloped  gross and net
leasehold acreage as of December 31, 2001:

<TABLE>
<CAPTION>
                                      Gross             Net
                                      -----             ---
<S>                                  <C>              <C>
     Developed                       59,268           17,392
     Undeveloped                     44,298           12,177
                                    -------           ------
            Total                   103,566           29,569
                                    =======           ======
</TABLE>

Approximately  85% of our net  acreage  was  located  in our  core  areas  as of
December 31, 2001. Our undeveloped  acreage includes leased acres on which wells
have not been drilled or  completed to a point that would permit the  production
of  commercial  quantities of natural gas and oil , regardless of whether or not
such acreage is held by production or contains proved reserves.  A gross acre is
an acre in which an  interest  is owned.  A net acre is deemed to exist when the
sum of fractional  ownership  interests in gross acres equals one. The number of
net acres is the sum of the fractional interests owned in gross acres.

Drilling Activities

During the  periods  indicated,  we  drilled or  participated  in  drilling  the
following wells.

<TABLE>
<CAPTION>
                                1999             2000                2001
                        ----------------   -----------------   ----------------
<S>                     <C>      <C>       <C>       <C>       <C>      <C>
Development wells:       Gross      Net      Gross     Net      Gross     Net
                        -------  -------   --------  -------   -------  -------
      Productive            19     2.40         20     4.30        11     1.91
      Non-productive        --       --          1      .02         2     0.37
Exploratory wells:
      Productive            --       --          1      .19         2      .93
      Non-productive        --       --          7     2.24         2     1.19
                        -------  -------   --------  -------   -------  -------
             Total          19     2.40         29     6.75        17     4.40
                        =======  =======   ========  =======   =======  =======
</TABLE>

Natural Gas and Oil Marketing and Hedging

Our natural gas and oil production is sold primarily  under market  sensitive or
spot price contracts.  The revenues  received by us from the sale of natural gas
liquids are included in crude oil sales.  We utilize  "keep whole"  contracts in
which the Btu  content of the  natural  gas  liquids is added to the natural gas
proceeds.  During the year ended December 31, 2001, three  purchasers  accounted
for  approximately  69% of our  natural  gas and  oil  sales  and  one  customer
accounted for approximately 79% of our pipeline system revenue. We believe there
are numerous other companies available to purchase our crude oil and natural gas
and that the loss of any or all of these purchasers would not materially  affect
our ability to sell crude oil and natural gas.

To reduce  exposure to fluctuations in natural gas and oil prices and to achieve
more predictable cash flow, we periodically  utilize various hedging  strategies
to manage the price  received  for a portion of our future  natural  gas and oil
production. We have not established hedges in excess of our expected production.
These strategies  customarily involve contracts for specified monthly volumes at
prices  determined  with  reference  to the natural  gas futures  market or swap
arrangements  that  establish  an  index-related  price  above  which we pay the
hedging  partner  and  below  which we are paid by the  hedging  partner.  These
contracts allow us to predict with greater  certainty the effective  natural gas
and oil prices to be  received  for our  production  and  benefit us when market
prices are less than the fixed prices under our hedging contracts.  However,  we
will not  benefit  from market  prices that are higher than the fixed  prices in
these  contracts  for our hedged  production.  At December 31,  2001,  we had no
hedging  contracts in place.  For the year ended  December 31, 2001, our hedging
strategies covered natural gas only and reduced our realized gas prices by $0.47
per Mcf.

We have only limited  involvement  with  derivative  financial  instruments,  as
defined  in  Statement  of  Financial  Accounting  Standards,  or SFAS,  No. 133
"Accounting for Derivative  Instruments  and Hedging  Activities" and do not use
them for trading  purposes.  Our objective is to hedge a portion of our exposure
to price  volatility  from  producing  natural gas and oil.  These  arrangements
expose us to credit risk of our counterparties and to basis risk.

Recent Accounting Pronouncements

A description of recent accounting  pronouncements is contained in the footnotes
to the audited consolidated financial statements.

Employees

As of December 31, 2001, we had 39 employees,  six of whom were  administrative,
accounting or financial  personnel and 33 of whom were  technical and operations
personnel.  Our future success will depend  partially on our ability to attract,
retain and motivate  qualified  personnel.  We are not a party to any collective
bargaining  agreement and we have not experienced any strikes or work stoppages.
We consider our relations with our employees to be satisfactory.

Competition

The  natural  gas and oil  industry  is highly  competitive.  We compete for the
acquisition  of natural gas and oil  properties,  primarily  on the basis of the
price to be paid for such properties, with numerous entities including major oil
companies,  other  independent  natural  gas and  oil  concerns  and  individual
producers and operators.  Many of these  competitors are large, well established
companies and have  financial  and other  resources  substantially  greater than
ours.  Our ability to acquire  additional  natural gas and oil properties and to
discover  reserves in the future  will  depend upon our ability to evaluate  and
select  suitable   properties  and  to  consummate   transactions  in  a  highly
competitive environment.

Item 2   Properties

Principal Natural Gas and Oil Properties and Reserves

We own and  operate  numerous  natural gas and oil  properties,  with our proved
reserves  being located  primarily in two core areas:  the Permian Basin of west
Texas and southeastern New Mexico and the Gulf Coast Area of southern  Louisiana
and  Mississippi.  Our  natural gas and oil  properties  located in our two core
areas represented approximately 76% of our PV-10 Value as of December 31, 2001.

At December 31, 2001, we operated 127  productive  wells and owned  non-operated
interests  in 733  productive  wells.  Our  interests  in the  wells we  operate
represented approximately 61% of our PV-10 Value at December 31, 2001.

In the following table, we present information regarding our natural gas and oil
reserves, including reserves in our two core areas, as of December 31, 2001.

<TABLE>
            Net Proved Reserves for Principal Oil and Gas Properties
<CAPTION>
                                                         Gas         % of Total
                               Oil         Gas         Equivalent       PV-10
     Area                    (MBbls)      (MMcf)         (Mmcfe)        Value
     ----                    -------      ------         -------      ------
<S>                            <C>        <C>            <C>           <C>
     Permian Basin             1220       17,870         25,192         50.0%
     Gulf Coast                  62       10,468         10,837         25.7
     Other                      620        7,151         10,872         24.3
                              -----       ------         ------        -----
     Total proved reserves    1,902       35,488         46,900        100.0%
                              =====       ======         ======        =====
</TABLE>

Permian  Basin.   Our  properties  in  the  Permian  Basin  area  accounted  for
approximately  50% of our PV-10 Value at December  31, 2001.  The Permian  Basin
area is located in West Texas and Southeastern New Mexico. In this core area, we
own an interest in 41 natural gas and oil  producing  wells which we operate and
525  natural gas and oil  producing  wells  operated by others.  During the year
ended December 31, 2001, we successfully drilled or participated in the drilling
of one gross  natural gas and oil well in this core area.  In  addition,  during
2001 we successfully recompleted three wells in this core area. During 2001, our
total net daily  production  from the Permian Basin area averaged  approximately
3,178 Mcfe. The majority of our production in this core area is from the Canyon,
Delaware  and Strawn  formations,  from depths of 5,000 feet to 8,000 feet.  Our
principal  fields  in the  Permian  Basin  area  are the SCB and the  Vinegarone
Fields.  We have identified 25 workover and  recompletion  opportunities,  along
with 24 infill drilling locations and three exploratory prospects in the Permian
Basin area.  At December 31, 2001,  approximately  83% of the PV-10 Value of our
proved, undeveloped reserves were in the Permian Basin area.

Gulf Coast.  Our properties in the Gulf Coast area  accounted for  approximately
26% of our PV-10 Value at December 31,  2001.  The Gulf Coast area is located in
south  Louisiana  and  Mississippi.  In this core  area,  we own and  operate an
interest in 30 natural gas and oil producing  wells. We also own interests in 15
natural gas and oil producing  wells  operated by others.  During the year ended
December 31, 2001, we participated in the drilling of one successful natural gas
well in this core area.  During 2001,  our total net daily  production  from the
Gulf  Coast  area  averaged  approximately  1,390  Mcfe.  The  majority  of  our
production  in this core area is from the Camerina and  Margunilina  formations,
from depths of 9,000 feet to 11,000 feet. Our principal  field in the Gulf Coast
area is the  Egan  Field.  We  have  identified  16  workover  and  recompletion
opportunities,  no  infill  drilling  locations  and one  potential  exploratory
prospect in the Gulf Coast area.  At December 31, 2001,  none of the PV-10 Value
of our proved, undeveloped reserves were in the Gulf Cost area For 2001, we have
scheduled the  recompletion  of four wells,  and the drilling of one exploratory
well in the Gulf Coast area.

Natural Gas and Oil Reserves

The  following  table  summarizes  the  estimates of our  historical  net proved
reserves and the related present values of such reserves at the dates shown. The
reserve and present  value data for our  natural  gas and oil  properties  as of
December  31,  1999,  2000  and  2001  were  prepared  by Garb  Grubbs  Harris &
Associates (formerly Forrest A. Garb & Associates, Inc.).

In the following  table,  PV-10 Value  represents the present value of estimated
future net revenues  before income tax discounted at 10%, using prices in effect
at the end of the  respective  periods  presented  and  excluding the effects of
hedging activities. In accordance with applicable requirements of the Securities
and  Exchange  Commission,  estimates  of our  proved  reserves  and  future net
revenues  are  made  using  applicable  location  differentials  from  published
year-end spot natural gas and oil sales prices and are held constant  throughout
the  life of the  properties  (except  to the  extent  a  contract  specifically
provides for escalation).  The spot prices used in calculating PV-10 Value as of
December  31,  2001 were $2.72 per Mcf of natural gas and $19.78 per Bbl of oil,
compared to spot prices used as of December 31, 2000 of $9.98 per Mcf of natural
gas and  $23.75  per Bbl of oil.  The  prices at which we sell  natural  gas are
determined on the first day of each month for the entire month.

Estimated  quantities of proved  reserves and future net revenues  therefrom are
affected by natural gas and oil prices,  which have fluctuated  widely in recent
years. There are numerous  uncertainties  inherent in estimating natural gas and
oil reserves and their values,  including many factors beyond the control of the
producer.  The reserve data set forth in this report  represent only  estimates.
Reservoir  engineering  is  a  subjective  process  of  estimating   underground
accumulations of natural gas and oil that cannot be measured in an exact manner.
The  accuracy of any reserve  estimate is a function of the quality of available
data and of engineering and geological interpretation and judgment. As a result,
estimates  of  different  engineers,  including  those used by us, may vary.  In
addition,  estimates  of  reserves  are subject to  revisions  based upon actual
production, results of future development and exploration activities, prevailing
natural gas and oil prices,  operating costs and other factors,  which revisions
may be material. The PV-10 Value of our proved natural gas and oil reserves does
not  necessarily  represent  the  current or fair  market  value of such  proved
reserves,  and the 10% discount  factor  required by the Securities and Exchange
Commission may not reflect current  interest  rates,  our cost of capital or any
risks  associated  with the development and production of our proved natural gas
and oil reserves.

In  general,  the  volume of  production  from  natural  gas and oil  properties
declines  as  reserves  are  depleted.  Except  to the  extent  that we  acquire
properties  containing  proved  reserves or conduct  successful  exploration and
development  activities,  our  proved  reserves  will  decline as  reserves  are
produced.  Our future  natural  gas and oil  production  is,  therefore,  highly
dependent upon our level of success in finding or acquiring additional reserves.

<TABLE>
<CAPTION>
     Reserve Data:                                            December 31,
                                         --------------------------------------------
                                             1999              2000              2001
                                             ----              ----              ----
<S>                                      <C>               <C>               <C>
     Proved developed reserves:
        Natural gas (MMcf)                 68,134            83,018            22,089
        Oil & condensate (MBbls)            2,901             3,158             1,556
           Total (MMcfe)                   85,541           101,967            31,427
        PV-10 Value (in thousands)       $ 76,100          $341,459          $ 30,297
     Proved reserves:
       Natural gas (MMcf)                 101,764           117,919            35,488
       Oil & condensate (MBbls)             3,606             3,891             1,902
          Total (MMcfe)                   123,401           141,264            46,900
       PV-10 Value (in thousands)        $ 92,611          $470,556          $ 40,491
       Spot $/Mcf                        $   2.07          $   9.98          $   2.72
       Spot $/Bbl                        $  22.76          $  23.75          $  19.78
</TABLE>

Title to Properties

We believe we have  satisfactory  title to our  properties  in  accordance  with
standards  generally  accepted  in the  natural  gas  and  oil  industry.  As is
customary in the natural gas and oil industry,  we make only a cursory review of
title to farmout  acreage  and to  undeveloped  natural  gas and oil leases upon
execution of any contracts.  Prior to the commencement of drilling operations, a
title  examination  is conducted and curative work is performed  with respect to
significant  defects.  To the  extent  title  opinions  or other  investigations
reflect title defects,  we, rather than the seller of the undeveloped  property,
are typically  responsible to cure any such title defects at our expense.  If we
were  unable to remedy or cure any title  defect of a nature  such that it would
not be prudent for us to commence drilling operations on the property,  we could
suffer a loss of our entire  investment in the property.  We have obtained title
opinions on substantially all of our producing  properties.  Prior to completing
an  acquisition  of  producing  natural gas and oil  leases,  we perform a title
review on a material  portion of the leases.  Our natural gas and oil properties
are subject to customary  royalty  interests,  liens for current taxes and other
burdens that we believe do not  materially  interfere  with the use of or affect
the value of such properties.

Facilities

Our executive and operating  offices are located at Suite 650,  Meridian  Tower,
5100 E. Skelly Drive,  Tulsa,  Oklahoma  74135.  We lease all of our significant
facilities. We believe that our facilities are adequate for our current needs.

Regulation

General.  Various  aspects of our natural gas and oil  operations are subject to
extensive and continually changing regulation,  as legislation affecting the oil
and gas industry is under constant  review for amendment or expansion.  Numerous
departments and agencies,  both federal and state,  are authorized by statute to
issue,  and have  issued,  rules and  regulations  binding  upon the oil and gas
industry and its individual members.

Regulation  of Sales and  Transportation  of Natural  Gas.  The  Federal  Energy
Regulatory  Commission (the "FERC")  regulates the  transportation  and sale for
resale of natural gas in interstate  commerce pursuant to the Natural Gas Act of
1938 and the Natural Gas Policy Act of 1978. In the past, the federal government
has  regulated  the  prices at which oil and gas could be sold.  While  sales by
producers of natural gas and all sales of crude oil,  condensate and natural gas
liquids can currently be made at  uncontrolled  market  prices,  Congress  could
reenact price  controls in the future.  Our sales of natural gas are affected by
the  availability,  terms  and cost of  transportation.  The price and terms for
access to  pipeline  transportation  are  subject to  extensive  regulation  and
proposed  regulation  designed  to increase  competition  within the natural gas
industry,  to remove various  barriers and practices that  historically  limited
nonpipeline natural gas sellers, including producers, from effectively competing
with interstate  pipelines for sales to local  distribution  companies and large
industrial  and  commercial  customers  and to  establish  the rates  interstate
pipelines may charge for their  services.  Similarly,  the Oklahoma  Corporation
Commission and the Texas  Railroad  Commission  have been  reviewing  changes to
their regulations  governing  transportation  and gathering services provided by
intrastate pipelines and gatherers.  While the changes being considered by these
federal and state regulators would affect us only indirectly,  they are intended
to further  enhance  competition in natural gas markets.  We cannot predict what
further action the FERC or state regulators will take on these matters, however,
we do not  believe  that  any  actions  taken  will  have an  effect  materially
different than the effect on other natural gas producers with which it competes.

Additional  proposals and proceedings that might affect the natural gas industry
are pending before  Congress,  the FERC, state  commissions and the courts.  The
natural gas industry  historically has been very heavily  regulated;  therefore,
there is no  assurance  that the less  stringent  regulatory  approach  recently
pursued by the FERC and Congress will continue.

Oil Price Controls and Transportation  Rates. Our sales of crude oil, condensate
and gas liquids are not currently  regulated and are made at market prices.  The
price we receive from the sale of these  products may be affected by the cost of
transporting the products to market.

Environmental.  Our natural  gas and oil  operations  are  subject to  pervasive
federal,  state,  and local laws and  regulations  concerning the protection and
preservation of the environment  (e.g.,  ambient air, and surface and subsurface
soils and waters), human health, worker safety, natural resources, and wildlife.
These laws and regulations  affect virtually every aspect of our natural gas and
oil  operations,   including  its  exploration  for,  and  production,  storage,
treatment,  and  transportation  of,  hydrocarbons  and the  disposal  of wastes
generated  in  connection  with those  activities.  These  laws and  regulations
increase our costs of planning, designing, drilling, installing,  operating, and
abandoning  oil and gas  wells and  appurtenant  properties,  such as  gathering
systems, pipelines, and storage, treatment and salt water disposal facilities.

We  have  expended  and  will  continue  to  expend  significant  financial  and
managerial   resources  to  comply  with  applicable   environmental   laws  and
regulations, including permitting requirements. Our failure to comply with these
laws and regulations can subject us to substantial civil and criminal penalties,
claims for injury to persons and damage to properties and natural resources, and
clean-up and other remedial obligations.  Although we believe that the operation
of our properties  generally  complies with  applicable  environmental  laws and
regulations,  the  risks of  incurring  substantial  costs and  liabilities  are
inherent  in the  operation  of  natural  gas  and  oil  wells  and  appurtenant
properties.  We  could  also be  subject  to  liabilities  related  to the  past
operations  conducted by others at properties now owned by us, without regard to
any wrongful or negligent conduct by us.

We cannot predict what effect future  environmental  legislation  and regulation
will have upon our  natural gas and oil  operations.  The  possible  legislative
reclassification  of certain  wastes  generated in  connection  with oil and gas
operations  as  "hazardous  wastes"  would  have  a  significant  impact  on our
operating  costs , as well as the oil and gas  industry in general.  The cost of
compliance with more stringent  environmental laws and regulations,  or the more
vigorous  administration  and enforcement of those laws and  regulations,  could
result in material  expenditures by us to remove,  acquire,  modify, and install
equipment, store and dispose of wastes, remediate facilities,  employ additional
personnel,  and  implement  systems  to ensure  compliance  with  those laws and
regulations.  These  accumulative  expenditures  could have a  material  adverse
effect upon our profitability and future capital expenditures.

Regulation of Natural Gas and Oil Exploration  and  Production.  Our exploration
and  production  operations  are subject to various  types of  regulation at the
federal,  state and local levels. Such regulations include requiring permits and
drilling bonds for the drilling of wells,  regulating the location of wells, the
method of drilling  and casing  wells,  and the surface use and  restoration  of
properties  upon which wells are  drilled.  Many  states  also have  statutes or
regulations  addressing  conservation  matters,  including  provisions  for  the
utilization or pooling of oil and gas properties,  the  establishment of maximum
rates of  production  from oil and gas  wells  and the  regulation  of  spacing,
plugging and  abandonment  of such wells.  Some state statutes limit the rate at
which oil and gas can be produced from our properties.

Item 3  Legal Proceedings

From time to time, we are party to litigation or other legal proceedings that we
consider  to be a part  of the  ordinary  course  of our  business.  We are  not
involved  in any  legal  proceedings,  nor  are we a  party  to any  pending  or
threatened claims,  that could reasonably be expected to have a material adverse
effect on our financial condition or results of operations.

Item 4  Submission of Matters to a Vote of Security Holders

By written consent in lieu of meeting dated December 12, 2001, our  shareholders
re-elected  Dr.  William W. Talley II as a Class I Director  for a term of three
years and ratified the appointment of Ernst & Young as the Company's independent
auditors for 2001.

                                     PART II

Item 5  Market for Registrant's Common Equity and Related Stockholder Matters

There is no  established  trading  market for our common stock.  As of March 31,
2002,  there were two record  holders  of the  common  stock.  We sold no equity
securities  during the three years ended  December 31, 2001.  On July 1, 1998 we
granted to a person who was  neither a  director,  officer  nor  employee of the
Company options to purchase an aggregate of 50,000 shares of our common stock at
an  exercise  price of $7.33 per  share.  The  person to whom the  options  were
granted is an  "accredited  investor"  as that term is defined in  Regulation  D
promulgated   under  the  Securities  Act.  We  relied  on  the  exemption  from
registration provided by Regulation D.

Item 6  Selected Financial Data

The following tables set forth certain of our historical  consolidated financial
data with  respect to each of the five years ended  December 31, 2001 which have
been derived from our audited consolidated financial statements.  The historical
consolidated  financial  data  should  be  read  in  conjunction  with  Item  7.
Management's  Discussion  and  Analysis of  Financial  Condition  and Results of
Operations and the audited  consolidated  financial statements and related notes
thereto included in Item 8.

We define EBITDA as earnings before interest income,  interest  expense,  income
taxes,  depreciation  and  amortization,   writedown  of  related  oil  and  gas
properties and equipment,  extraordinary items and equity in loss of affiliates.
EBITDA  is not a  measure  of cash  flow as  determined  by  generally  accepted
accounting principles.  EBITDA should not be considered as an alternative to, or
more  meaningful  than, net income or cash flow as determined in accordance with
generally  accepted  accounting  principals  or as an  indicator  of a company's
operating performance or liquidity.  We believe that EBITDA is a widely followed
measure of  operating  performance  and may also be used by investors to measure
our ability to meet future debt service requirements, if any.

In February 1998, we acquired Carlton Resources.  Effective December 1, 2001, we
sold to Carmen Acquisition Corp., a subsidiary of Chesapeake Energy Corporation,
all of our producing and non-producing natural gas and oil properties located in
17 counties in Oklahoma,  Texas and New Mexico.  These  transactions  affect the
comparability  of the historical  operating data for the period and the data are
not necessarily indicative of our future performance.

                      (This space left blank intentionally)
<PAGE>

<TABLE>
<CAPTION>
                                                                          Year Ended December 31,
                                                       --------------------------------------------------------
                                                         1997        1998        1999        2000        2001
                                                         ----        ----        ----        ----        ----
Operating Statement Data:                                    (in thousands, except for per share amounts)
<S>                                                    <C>         <C>         <C>         <C>         <C>
Operating Revenues:
      Oil and gas sales                                $ 23,737    $ 25,839    $ 23,085    $ 25,641    $ 25,404
      Pipeline system                                         -       6,123       9,198      14,100      15,602
      Other                                                  79         354         827         294         210
                                                       --------    --------    --------    --------    --------
              Total operating revenues                   23,816      32,316      33,110      40,035      41,216
Operating Expenses:
      Natural gas and oil production taxes                1,713       2,026       1,967       2,762       2,755
      Natural gas and oil production expense              5,056       6,607       5,826       4,994       5,975
      Pipeline system                                         -       4,716       7,035      10,851      12,716
      Amortization and depreciation                       8,692      13,713      12,964      10,091       9,766
      Contract termination and severance                      -           -           -       1,221       1,401
      General and administrative                          4,467       3,517       4,437       3,353       4,061
                                                       --------    --------    --------    --------    --------
              Total operating expenses                   19,928      30,579      32,229      33,272      36,377
      Operating income                                    3,888       1,737         881       6,763       4,839
Other income (expense):
      Gain on sale of natural gas and oil properties          -           -           -           -      17,320
      Interest expense                                   (5,159)    (13,197)    (14,623)    (15,455)    (14,514)
      Interest income                                        83         356         169         148         104
      Equity in loss of affiliate                             -        (693)     (1,307)          -
                                                       --------    --------    --------    --------    --------
Income (loss) before income
              taxes and extraordinary items              (1,188)    (11,797)    (14,880)    ( 8,544)      7,749
      Income tax provision (benefit)                          -      (4,200)     (5,650)     (3,200)      2,900
                                                       --------    --------    --------    --------    --------
Income (loss) before extraordinary items                 (1,188)     (7,597)     (9,230)     (5,344)      4,849
      Extraordinary items                                     -       1,140           -         916      (1,098)
                                                       --------    --------    --------    --------    --------
Net income (loss)                                      $ (1,188)   $ (6,457)   $ (9,230)   $ (4,428)   $  3,751
                                                       ========    ========    ========    ========    ========
Per Share Amounts:
      Income(loss) before extraordinary items          $  (0.44)   $  (2.79)   $  (3.38)   $  (1.96)   $   1.78
      Extraordinary items                                     -        0.42           -        0.34       (0.40)
                                                       --------    --------    --------    --------    --------
      Net income(loss)                                 $  (0.44)   $  (2.37)   $  (3.38)   $  (1.62)   $   1.38
                                                       ========    ========    ========    ========    ========
Weighted average common shares
      outstanding (in thousands)                          2,727       2,727       2,727       2,727       2,727
                                                       ========    ========    ========    ========    ========
</TABLE>

<PAGE>
<TABLE>
<CAPTION>
                                                                         Year Ended December 31,
                                                  ------------------------------------------------------------
                                                     1997         1998         1999         2000         2001
                                                     ----         ----         ----         ----         ----
                                                                   (in thousands, except for ratios)
<S>                                               <C>          <C>          <C>          <C>          <C>
Balance Sheet Data:
        Cash and cash equivalents                 $   1,248    $   8,603    $   1,875    $     917    $  19,874
        Net property and equipment                   60,574      134,274      122,687      118,909       65,478

        Total assets                                 69,727      156,451      135,797      132,836       98,322
        Long-term debt, including
              current portion                        62,225      131,789      129,356      127,580       91,400
        Stockholders' deficit                        (3,983)     (10,440)     (19,670)     (24,098)     (20,347)

Other Financial Data:

              EBITDA                              $  12,580    $  15,450    $  13,845    $  16,854    $  32,029
              Interest expense                       (5,159)     (13,197)     (14,623)     (15,455)     (14,514)
              Working capital changes and other       1,301        7,280       (5,190)       4,549      (16,700)
                                                  ---------    ---------    ---------    ---------    ---------
        Cash flows from:
              Operating activities                $   8,722    $   9,533    $  (5,968)   $   5,948    $   2,240
              Investing activities                   (8,202)     (66,607)      (2,269)      (4,845)      44,520
              Financing activities                     (879)      64,429        1,509       (2,061)     (27,803)

        Capital expenditures:
              Acquisitions                               --       48,111           --           --           --
              Investments                                --        2,000           --           --           --
              Development drilling                   17,642       17,972        3,625        4,464        8,844
              Exploration                                --           --          860        2,421        2,200
              Pipeline system                            --          184          438           54          136
              Other                                     343          652          480          826          169
                                                  ---------    ---------    ---------    ---------    ---------
                      Total capital expenditures     17,985       68,919        5.403        7,765       11,349
</TABLE>

<TABLE>
<CAPTION>
    Operating Data:                                                         Year Ended December 31,
                                                        -------------------------------------------------------------
                                                             1997         1998         1999         2000         2001
                                                        ---------    ---------    ---------    ---------    ---------
                                                        <C>          <C>          <C>          <C>          <C>
    Production volumes:
               Natural gas (MMcf)                           6,686        8,795        8,283        6,661        5,817
               Oil and condensate (MBbls)                     467          520          362          295          262
               Total (MMcfe)                                9,486       11,916       10,456        8,430        7,388
    Average realized prices (1):
               Natural gas (per Mcf)                    $    2.36    $    2.24    $    2.08    $    2.64    $    3.28
               Oil and condensate (per Bbl)                 17.08        11.81        16.13        27.37        24.09
               Per Mcfe                                      2.50         2.17         2.21         3.04         3.44
    Expenses (per Mcfe):
               Natural gas and oil production taxes          0.18         0.17         0.19         0.33         0.37
               Natural gas and oil production expense        0.53         0.55         0.56         0.59         0.81
               Amortization and depreciation                 0.92         1.15         1.24         1.20         1.32
               General and administrative                    0.47         0.30         0.42         0.40         0.55
---------------
<FN>
(1)  Reflects the actual realized prices received by the Company,  including the
     results of the Company's hedging activities.  See "Management's  Discussion
     and Analysis of Financial Condition and Results of Operations."
</FN>
</TABLE>

<TABLE>
Selected Quarterly Financial Data (unaudited) (in thousands, except for per share amounts)
<CAPTION>
Three Months Ended                                March 31,   June 30,  September 30, December 31,
                                                  ---------   --------  ------------- ------------
Year Ended December 31, 2001
<S>                                               <C>         <C>         <C>         <C>
Operating revenues                                $ 15,766    $ 11,705    $  8,248    $  5,497
Operating income (loss)                              5,570       2,441         719      (3,891)
Net income (loss) before extraordinary items         1,221        (767)     (1,900)      6,295
Net income (loss) per share - basic and diluted
     before extraordinary items                   $   0.45    $  (0.28)   $  (0.70)   $   2.31
Net income (loss)                                 $  1,221    $   (767)   $ (1,900)   $  5,197

Year Ended December 31, 2000

Operating revenues                                $  9,014    $  9,436    $  9,933    $ 11,652
Operating income                                       946       1,838       2,126       1,853
Net income (loss) before extraordinary items        (1,753)     (1,170)     (1,150)     (1,271)
Net income (loss) per share - basic and diluted
     before extraordinary items                   $  (0.64)   $  (0.43)   $  (0.42)   $  (0.47)
Net income (loss)                                   (1,753)     (1,170)       (234)     (1,271)
</TABLE>

Item 7  Management's Discussion and Analysis of Financial  Condition and Results
        of Operations

General

We  are  an  independent  oil  and  gas  Company  engaged  in  the  acquisition,
exploration  and development of oil and gas properties and the production of oil
and gas. Our oil and gas properties  are located  primarily in the Permian Basin
of west Texas and New Mexico,  and on-shore  Louisiana and Mississippi.  We also
operate  a  natural  gas and oil  pipeline  and salt  water  disposal  system in
Oklahoma.

Historically,  we have added reserves  mainly through  acquisitions of producing
properties and the further  development and  exploitation  of these  properties.
Beginning in 1999, we initiated an emphasis on exploration activities, including
the  acquisition  of 2-D and 3-D seismic  data and the  internal  generation  of
exploratory  prospects.  We continue to generate exploratory  prospects with our
in-house  exploration staff and evaluate exploratory  opportunities  proposed by
third parties.  We intend to continue  pursuing  attractive  natural gas and oil
acquisitions,  as  well  as  development  activities  and  exploratory  drilling
opportunities.  Any  future  acquisitions  or  major  development  will  require
additional  financing  which will be dependent upon financing  arrangements,  if
any, available at the time.

In February 1998, we acquired Carlton Resources for approximately $41.6 million.
In this acquisition we acquired proved reserves and a 182-mile pipeline system.

In 1998, in connection with our purchase for $6.5 million of a one-half interest
in certain proved  undeveloped  natural gas and oil  properties,  we made a $2.0
million  investment  in RVC Energy,  Inc. RVC Energy then acquired the remaining
one-half  interest in the same  proved  undeveloped  properties  in which we had
acquired  interests,  as well as other  producing  properties  and the  stock of
another oil and gas company.  We were  designated as the operator of most of the
properties  owned  directly or indirectly by RVC Energy.  In 1999,  RVC Energy's
properties were sold to satisfy its indebtedness, and we wrote off our remaining
$1.3 million investment in RVC.

Effective  December  1, 2001,  we sold 86 Bcfe of our proved  reserves to Carmen
Acquisition  Corp.,  an affiliate of Chesapeake  Energy  Corporation,  for $76.0
million in a combination of cash and a surrender of approximately  $11.1 million
principal  amount of our 11 1/2% senior notes due 2008. The natural gas reserves
that we sold  included  certain  reserves  that  were  subject  to a  volumetric
production  payment in favor of Duke Energy.  All our obligations to Duke Energy
under the volumetric  production payment were assumed by Carmen Acquisition . We
used a portion  of the net  proceeds  from the sale to fully  repay  our  senior
secured credit facility.

Critical Accounting Policies

Our revenue,  profitability  and cash flow are directly  impacted by  prevailing
prices  for  natural  gas  and oil and the  volumes  of  natural  gas and oil we
produce.  In addition,  our proved reserves and the rates of our natural gas and
oil  production  will decline as natural gas and oil are produced  unless we are
successful in acquiring additional producing properties or conducting successful
exploration  and  development  drilling  activities.  The  Company  follows  the
entitlements method of accounting for natural gas and oil sales.

We periodically  utilize various hedging strategies to manage the price received
for a portion of our future  natural gas and oil  production.  These  strategies
customarily involve contracts for specified monthly volumes at prices determined
with  reference  to the  natural gas futures  market or swap  arrangements  that
establish  an  index-related  price above  which we pay the hedging  partner and
below  which we are paid by the hedging  partner.  These  contracts  allow us to
predict with greater  certainty the  effective  natural gas and oil prices to be
received for our  production and benefit us when market prices are less than the
fixed  prices  under our hedging  contracts.  However,  we will not benefit from
market  prices that are higher than the fixed prices in these  contracts for our
hedged  production.  At December 31, 2001, we had no hedging contracts in place.
For the year ended December 31, 2001, our hedging strategies covered natural gas
only and reduced our realized gas prices by $0.47 per Mcf.

We use the full cost method of accounting  for our investment in natural gas and
oil  properties.  Under the full cost method of accounting,  all of our costs of
acquisition,  exploration  and  development  of natural gas and oil reserves are
capitalized into a "full cost pool" as incurred,  and costs included in the pool
are amortized and charged to operations  using the future  recoverable  units of
production  method  based on the ratio of  current  production  to total  proved
reserves,  computed  based on current  prices and  costs.  Significant  downward
revisions  of quantity  estimates or declines in natural gas and oil prices that
are not offset by other factors  could result in a writedown  for  impairment of
the  carrying  value of our natural gas and oil  properties.  Once  incurred,  a
writedown of natural gas and oil  properties is not  reversible at a later date,
even  if our  quantity  estimates  or  natural  gas or oil  prices  subsequently
increase.

Results of Operations

Year Ended December 31, 2001 Compared to Year Ended December 31, 2000

Operating Revenues.  Our operating revenues increased by $1.2 million, or 3% for
the year  ended  December  31,  2001  compared  to the same  period in 2000.  An
increase of $1.5  million in the  revenues  of our  gathering  system  primarily
accounts for the increase in 2001 compared to 2000.

Natural Gas and Oil Sales.  The following  table  summarizes our natural gas and
oil production  volumes,  average sales prices and period to period comparisons,
including  the effect on our oil and gas  operating  revenues,  for the  periods
indicated:

<TABLE>
<CAPTION>
                                  Year ended
                                 December 31,
                                --------------    % Increase
                                2000      2001    (Decrease)
                                ----      ----    ----------
<S>                           <C>       <C>       <C>
Natural gas and oil sales     $25,641   $25,404   (  1.0) %
    (in thousands)
Production volumes:
      Natural gas (MMcf)        6,661     5,817   ( 12.7) %
      Oil (MBbls)                 295       262   ( 11.1) %
Average sale prices:
      Natural gas (per Mcf)   $  2.64   $  3.28     24.4  %
      Oil (per Bbl)             27.38     24.09   ( 12.0) %
</TABLE>

Our oil and gas sales were lower  during 2001  compared to 2000 as a result of a
13% increase in realized prices, offset by a 12% decrease in production, both on
an Mcfe basis.  Our average daily  production was 20.2 MMcfe in 2001 compared to
23.0  MMcfe  for 2000.  Our  natural  gas  production  decreased  by 13% and oil
production  decreased by 11% for the comparable  periods. We realized an average
sales price for natural gas of $3.28 per Mcf for 2001, compared to $2.64 per Mcf
for 2000, an increase of 24%. Our average  realized sales price for oil for 2001
was $24.09 per Bbl, compared to $27.38 per Bbl for 2000, a 12% decrease.

Our natural gas sales are computed net of gains or losses from fixed-price swaps
for physical  deliveries during the reporting period. Our natural gas sales were
reduced  by $2.7  million  (or $0.47 per Mcf) from  these  transactions  in 2001
compared to $6.1 million in decreases (or $0.92 per Mcf) for 2000.

Pipeline  System.  Our pipeline  system  revenue was $15.6  million for the year
ended December 31, 2001, compared to $14.1 million for 2000, an increase of $1.5
million, or 11%.

We are  obligated  to deliver  10,000  Mmbtu's  per day at the  tailgate  of the
system,  and we  purchase  natural  gas from  wells  connected  to the system to
satisfy that obligation. In addition, we purchase and re-sell oil and dispose of
salt water.

Our third party purchases and system  operating costs were $12.7 million for the
year of 2001,  compared to $10.9  million for 2000, an increase of $1.9 million,
or 17%.

Volumes of gas,  oil, and water  disposed  were  unchanged  for 2001 compared to
2000;  higher prices  account for the increases in both revenues and costs.  The
operating margin of the system  decreased  $363,000 (or 11%) to $2.9 million for
the year 2001  compared to $3.2  million for the year 2000.

Natural gas and Oil Production  Taxes.  Our natural gas and oil production taxes
were the same amount for the year ended December 31, 2001,  compared to the year
of 2000. On an Mcfe basis, our natural gas and oil production taxes increased to
$0.37 per Mcfe for the year  2001,  compared  to $0.33 for the year  2000.  This
increase was caused by prior year adjustments submitted by outside operators and
a provision for  non-collectibility  of production tax credits recorded in prior
years.

Natural Gas and Oil  Production  Expense.  Our  natural  gas and oil  production
expense decreased by $1.0 million, or 20%, for the year ended December 31, 2001,
compared to the same period in 2000. Our natural gas and oil production  expense
was $0.81 per Mcfe for 2001,  a 37%  increase  from $0.59 per Mcfe  compared  to
2000.  This  increase  was  due  to  increased  costs  to  maintain  production,
settlement of prior years' charges from outside  operators,  and plugging of two
salt water  disposal  wells during the year 2001 compared to costs  incurred for
the year 2000.

Amortization and Depreciation Expense. Our amortization and depreciation expense
decreased by $325,000,  or 3% for 2001 compared to 2000,  and was $1.32 per Mcfe
for 2001,  an increase of $0.17,  or 10%  compared to the $1.20 per Mcfe for the
year 2000.

Contract Termination and Severance.  As a result of the expiration of employment
agreements  with our three  senior  vice-presidents,  we  recorded  $730,000  in
contract  terminations.  Due the sale of a substantial number of our natural gas
and oil  properties,  we  reduced  our office  staff and  recorded  $374,000  in
severance  pay  relating  to these  terminations.  During  2000,  we closed  our
Oklahoma  City  accounting  office and our  Midland,  Texas  operations  office.
Severance  pay and other  costs  incidental  to these  office  closings  totaled
$337,000.  In December  2000, we terminated  the  severance  agreement  with the
Chairman  of the Board and entered  into a new  employment  agreement  with him.
Total benefits paid in connection with the contract termination were $884,000.

General and  Administrative  Expense.  Our general  and  administrative  expense
increased to $4.1 million, an increase of $708,000, or 21% in 2001 compared with
$3.4  million  in 2000.  This  increase  is due  primarily  bonuses  paid to our
executive officers during 2001.

Gain on Sale of Natural Gas and Oil Properties.  The gain on the sale of natural
gas and oil properties is comprised of the purchase price of $76.0 million, less
costs of sale allocated  from the full-cost  pool of $56.6  million,  less other
costs and purchase price adjustments of $2.1 million.

Interest Expense.  Our interest expense decreased  $941,000 to $14.5 million for
2001  compared to $15.5  million for 2000.  During  2001,  we had lower  average
outstanding  indebtedness on our senior notes due to our receiving approximately
$11.1  million of our 11 1/2% senior  notes with the sale of natural gas and oil
properties.  On our credit  facility,  interest  expense  decreased due to lower
average outstanding  balances as the facility was fully repaid in December 2001,
and lower effective interest rates.

Income Taxes. In connection  with our acquisition of Carlton  Resources in early
1998,  we  recorded  deferred  income tax  liabilities  related to the excess of
financial  bases of net assets acquired  (principally  properties and equipment)
over their respective bases for income tax purposes.  Prior to this acquisition,
we offset our existing net  operating  loss  carryforwards  and the provision or
credit for income taxes by valuation allowances. Our net liability is the result
of our providing  for income taxes or credits after the date of our  acquisition
of Carlton Resources.

Extraordinary  Items.  In  conjunction  with the  sales of  natural  gas and oil
properties,  the buyer surrendered  approximately $11.1 million principal amount
of our 11 1/2% senior notes, and with the cash proceeds we retired our revolving
credit facility. Extraordinary items for 2001 includes a proportionate write-off
of deferred  offering  costs and  original  issue  discount on the senior  notes
surrendered,  all remaining  deferred loan costs  associated  with our revolving
credit  facility,  along with a prepayment  penalty  associated  with the credit
facility,  which after tax effects,  totaled $1.1 million loss.  During 2000, we
purchased  $5.0 million  principal  amount of our senior notes for $3.3 million.
After  adjustments for  proportionate  offering costs,  accrued interest and tax
effects, we reported a gain of $916,000.

Net Loss. Due to the factors  described above, we had net income of $3.8 million
in 2001, compared to a net loss of $4.4 million in 2000.

Year Ended December 31, 2000 Compared to Year Ended December 31, 1999

Operating Revenues. Our operating revenues increased by $6.9 million, or 21% for
the year ended December 31, 2000 compared to the same period in 1999.

Natural Gas and Oil Sales:  The following  table  summarizes our natural gas and
oil production  volumes,  average sales prices and period to period comparisons,
including  the effect on our oil and gas  operating  revenues,  for the  periods
indicated:

<TABLE>
<CAPTION>
                                  Year ended
                                 December 31,
                              -----------------   % Increase
                                1999      2000    (Decrease)
                                ----      ----    ----------
<S>                           <C>       <C>        <C>
Natural gas and oil sales     $23,085   $25,641    11.1  %
    (in thousands)
Production volumes:
    Natural gas (MMcf)          8,283     6,661   (19.6) %
    Oil (MBbls)                   362       295   (18.6) %
Average sale prices:
    Natural gas (per Mcf)     $  2.08   $  2.64    26.7  %
    Oil (per Bbl)               16.13     27.38    69.7  %
</TABLE>

Our  natural gas and oil sales were  higher  during  2000  compared to 1999 as a
result of a 38% increase in realized prices,  partially offset by a 19% decrease
in  production,   both  on  an  Mcfe  basis.  Of  the  decrease  in  production,
approximately  28% was due to the production  payment we entered into at the end
of September, 1999, with 785 MMcf delivered for the year of 2000 compared to 208
MMcf  delivered in the last quarter of 1999.  Our average daily  production  was
23.1 MMcfe in 2000 compared to 28.6 MMcfe for 1999.  Our natural gas  production
decreased by 20% and oil production decreased by 19% for the comparable periods.
We  realized  an average  sales price for natural gas of $2.64 per Mcf for 2000,
compared to $2.08 per Mcf for 1999,  an increase  of 27%.  Our average  realized
sales price for oil for 2000 was $27.38 per Bbl,  compared to $16.13 per Bbl for
1999, a 70% increase.

Our natural gas sales are computed net of gains or losses from fixed-price swaps
for physical  deliveries during the reporting period. Our natural gas sales were
reduced  by $6.1  million  (or $0.92 per Mcf) from  these  transactions  in 2000
compared to $362,000 in decreases (or $0.04 per Mcf) for 1999.

Pipeline  System.  Our pipeline  system  revenue was $14.1  million for the year
ended December 31, 2000,  compared to $9.2 million for 1999, an increase of $4.9
million, or 53%.

We are  obligated  to deliver  10,000  Mmbtu's  per day at the  tailgate  of the
system,  and we  purchase  natural  gas from  wells  connected  to the system to
satisfy that obligation. In addition, we purchase and re-sell oil and dispose of
salt water.

Our third party purchases and system  operating costs were $10.9 million for the
year of 2000, compared to $7.0 million for 1999, an increase of $3.8 million, or
54%.

Volumes of gas,  oil,  and water  disposed  were  virtually  unchanged  for 2000
compared to 1999;  higher prices  account for the increases in both revenues and
costs.  The operating  margin of the system  increased  $1.0 million (or 45%) to
$3.2 million for the year 2000 compared to $2.2 million for the year 1999.

Natural Gas and Oil Production Taxes. Our oil and gas production taxes increased
by $795,000,  or 40%, for the year ended December 31, 2000, compared to the same
period in 1999.  This  increase was due entirely to higher  wellhead oil and gas
revenue during 2000 compared to 1999.

Natural  Gas and Oil  Production  Expense.  Our oil and gas  production  expense
decreased by $832,000, or 14%, for the year ended December 31, 2000, compared to
the same period in 1999. Our oil and gas  production  expense was $0.59 per Mcfe
for 2000,  a 5% increase  from $0.56 per Mcfe  compared to 1999,  due to reduced
production volumes in 2000 compared to 1999.

Amortization and Depreciation Expense. Our depreciation and amortization expense
decreased by $2.9 million,  or 22% for 2000 compared to 1999,  and was $1.20 per
Mcfe for 2000,  a decrease  of $0.04,  or 3%  compared to the $1.24 per Mcfe for
1999. Our oil and gas amortization  expense was $0.82 per Mcfe for 2000 compared
with  $0.92  per  Mcfe for  1999,  an 11%  decrease,  due to  increased  reserve
quantities at the end of 2000 compared to the end of 1999.

Contract Termination and Severance.  During the first quarter of 2000, we closed
our Oklahoma City accounting  office and our Midland,  Texas operations  office.
Severance  pay and other  costs  incidental  to these  office  closings  totaled
$337,000.  In December  2000, we terminated  the  severance  agreement  with the
Chairman  of the Board and entered  into a new  employment  agreement  with him.
Total  benefits to be paid in  connection  with the  contract  termination  were
$884,000.

General and  Administrative  Expense.  Our general  and  administrative  expense
decreased to $3.3 million,  a decrease of $1.1 million,  or 24% in 2000 compared
with $4.4 million in 1999. This decrease is due primarily to the office closings
described  above,  and decreased costs of managing RVC Energy, a partially owned
unrestricted affiliate, for which we received $600,000 in management fees during
1999.

Interest Expense.  Our interest expense increased  $832,000 to $15.5 million for
2000  compared to $14.6  million for 1999.  During  2000,  we had lower  average
outstanding indebtedness on our senior notes due to our purchase of $5.0 million
principal  amount  of  senior  notes  during  August,  2000,  offset  by  higher
outstanding  balances  and  higher  effective  interest  rates  under our credit
facility.

Equity in Loss of Affiliate.  During 1999 we wrote off our remaining  investment
of $1.3 million in RVC Energy.

Income Taxes. In connection  with our acquisition of Carlton  Resources in early
1998,  we  recorded  deferred  income tax  liabilities  related to the excess of
financial  bases of net assets acquired  (principally  properties and equipment)
over their respective bases for income tax purposes.  Prior to this acquisition,
we offset our existing net  operating  loss  carryforwards  and the provision or
credit for income taxes by valuation allowances. Our net liability is the result
of our providing  for income taxes or credits after the date of our  acquisition
of Carlton Resources.

Extraordinary  Item.  During 2000, we purchased $5.0 million principal amount of
our senior notes for $3.3 million.  After adjustments for proportionate offering
costs, accrued interest and tax effects, we reported a gain of $916,000.

Net Loss.  Due to the factors  described  above,  our net loss decreased by $4.8
million,  from a net loss of $9.2  million in 1999 to a net loss of $4.4 million
in 2000.

Use of Estimates

The preparation of financial  statements in conformity  with generally  accepted
accounting   principles   requires  that  our  management   make  estimates  and
assumptions  that  affect the  reported  amounts of assets and  liabilities  and
disclosure of contingent  assets and liabilities at the date of the consolidated
financial  statements and the reported  amounts of revenues and expenses  during
the reporting period. Actual results could differ from those estimates.

Liquidity and Capital Resources

As of December 31, 2001, we had cash and cash equivalents of $19.9 million,  and
in  conjunction  with the sales of  natural  gas and oil  properties  previously
discussed, $6.1 million in an escrowed cash account discussed further below.

As of December 31, 2001,  we had $91.1  million  ($92.0  million  excluding  the
original issue  discount) of  indebtedness  outstanding  evidenced by our senior
notes  due 2008  issued in  February  1998.  Under  the  terms of the  indenture
governing  our  outstanding  senior  notes,  we currently  may incur up to $30.0
million in permitted  indebtedness in addition to the  indebtedness  outstanding
under our senior notes.

Historically,  we have funded our business  activities  with operating cash flow
and  reserve-based  bank borrowings.  From time to time we engage in discussions
relating  to  potential  acquisitions  of  natural  gas  and oil  properties  or
companies  engaged  in the  natural  gas and oil  business.  We have no  present
agreement,   commitment   or   understanding   with   respect  to  any  material
acquisitions.  Any future  acquisitions  may require  that we obtain  additional
financing that will depend upon financing arrangements, if any, available at the
time.

Sale to  Carmen  Acquisition.  Effective  December  1,  2001,  we sold to Carmen
Acquisition  Corp., a subsidiary of Chesapeake  Energy  Corporation,  all of our
producing and  non-producing  oil and gas  properties  located in 17 counties in
Oklahoma,  Texas and New Mexico.  The base purchase price of $76 million (before
customary closing and post-closing  adjustments) was paid 85% in cash and 15% by
the  surrender of  approximately  $11.1  principal  amount of our 11 1/2% senior
notes due 2008, valued at par. The sale included approximately 86 Bcfe of proved
reserves as of December 1, 2001, including  approximately 27 Bcfe of undeveloped
reserves.  At the  time of the  sale,  Carmen  Acquisition  owned  49.5%  of our
outstanding  common stock.  Immediately  following the sale, Carmen  Acquisition
sold all of our common stock owned by it to our two major shareholders, Larry E.
Lee and William W. Talley II. As a result of this sale,  Messrs.  Lee and Talley
currently own all of our outstanding common stock.

At the closing,  $7.5 million of the purchase  price (85% in cash and 15% in our
senior  notes) was deposited in escrow to secure  post-closing  claims for title
and  environmental  defects and other  matters.  As of March 31,  2002,  we have
received approximately $3.0 million (85% in cash and 15% in senior notes) out of
the escrow account.  Under the terms of the Asset Purchase  Agreement  governing
the sale,  the final date for  reconciling  claims against the escrow account is
April 3, 2002.

Our properties  sold to Carmen  Acquisition  included all of the properties that
were subject to volumetric  production payment in favor of a unit of Duke Energy
Corporation.  As  part  of  the  sale,  Carmen  Acquisition  assumed  all of our
obligations  under the  production  payment from and after the effective date of
the sale.

We used the  proceeds  of our sale to  Carmen  Acquisition,  net of  transaction
costs, to fully repay our senior secured credit  facility with Foothill  Capital
Corporation  and to obtain a release of all mortgages  and other liens  securing
that facility,  to reduce our working capital deficit and to provide  additional
capital to fund our exploration and development activities.

Credit Facility. In December 1999, we obtained a $30.0 million,  senior secured,
revolving  credit  facility from  Foothill  Capital  Corporation,  a Wells Fargo
company. In December 2001 we used a portion of the proceeds from our sale of gas
and oil properties to Carmen Acquisition to fully pay all sums outstanding under
our credit  facility,  and such credit  facility  was  terminated  and all liens
securing the facility were released.

Senior Notes. We have outstanding  $92.0 million  aggregate  principal amount of
senior  notes,  which  mature in February  2008.  The notes were issued under an
indenture  with United States Trust  Company of New York, as Trustee.  The notes
bear  interest  at an  annual  rate of 11 1/2%,  payable  semi-annually  on each
February 15 and August 15.

Production Payment.  In September 1999, we entered into a volumetric  production
payment agreement with a unit of Duke Energy  Corporation,  pursuant to which we
will deliver to Duke Energy 2.8 Bcf of natural gas produced  from certain of our
properties over a 5-year period.  We received $5.0 million of  consideration  in
this  transaction.  In  connection  with our sale of oil and gas  properties  to
Carmen Acquisition in December 2001, Carmen Acquisition  assumed our obligations
under the Duke Energy production payment.

Cash Flows from Operating  Activities.  Our cash flows from operating activities
are  comprised  of three  main  items:  net  income or  (loss),  adjustments  to
reconcile net loss to cash provided  (used) before  changes in working  capital,
and changes in working  capital.  For the year ended  December 31, 2001, our net
income was $8.2 million more than the $4.4 million net loss of 2000. Adjustments
(primarily  non-cash items such as depreciation  and  amortization  and deferred
income  taxes) were $(3.6) million for the year of 2001 compared to $6.1 million
for 2000, a decrease of $9.6 million.  Working capital changes for the year 2001
used cash of $2.0 million  compared with cash provided of $4.2 million for 2000.
Decreases  in  accounts  receivable,  accounts  payable  and natural gas and oil
proceed due others caused this change.  For the year ended December 31, 2001, in
total,  our cash flows from operating  activities  provided $2.2 million in cash
compared to $5.9 million provided in 2000.

Cash Flow from Investing  Activities.  For the year ended December 31, 2001, our
net cash provided by investing  activities  was $44.5 million,  including  $55.9
million from sales of natural gas and oil property  sales to Carmen  Acquisition
Corp.,  offset by natural gas and oil property  additions of $11.0 million.  For
the year ended December 31, 2000, our net cash used in investing  activities was
$4.8 million,  including $2.8 million of property sales,  offset by $6.9 million
for natural gas and oil property additions.  Our budget for capital expenditures
in 2002 is  approximately  $7.0  million  provided  current  oil and gas  prices
realized are maintained.

Item 7A   Quantitative and Qualitative Disclosures about Market Risk

The  carrying  amounts  reported  in  our  balance  sheets  for  cash  and  cash
equivalents, trade receivables and payables, installment notes and variable rate
long-term debt approximate  their fair values.  The carrying value of our senior
notes exceeded  their fair value at December 31, 2000 and 2001 by  approximately
$23.2 million and $23.9 million, respectively, based on quoted market prices.

Interest Rate Risk

We are exposed to changes in interest  rates.  Changes in interest  rates affect
the interest earned on our cash and cash  equivalents and the interest rate paid
on  borrowings.  Under  our  current  policies,  we do  not  use  interest  rate
derivative instruments to manage exposure to interest rate changes.

Commodity Price Risk

Our revenues, profitability and future growth depend substantially on prevailing
prices  for  natural  gas and oil.  Prices  also  affect the amount of cash flow
available  for  capital  expenditures  and  our  ability  to  borrow  and  raise
additional  capital.  Lower prices may also reduce the amount of natural gas and
oil that we can economically  produce. We currently sell most of our natural gas
and oil production under price sensitive or market price contracts.

To reduce  exposure to fluctuations in natural gas and oil prices and to achieve
more predictable cash flow, we periodically  utilize various hedging  strategies
to manage the price  received  for a portion of our future  natural  gas and oil
production. We have not established hedges in excess of our expected production.
These strategies  customarily involve contracts for specified monthly volumes at
prices  determined  with  reference  to the natural  gas futures  market or swap
arrangements  that  establish  an  index-related  price  above  which we pay the
hedging  partner  and  below  which we are paid by the  hedging  partner.  These
contracts allow us to predict with greater  certainty the effective  natural gas
and oil prices to be  received  for our  production  and  benefit us when market
prices are less than the fixed prices under our hedging contracts.  However,  we
will not  benefit  from market  prices that are higher than the fixed  prices in
these  contracts  for our hedged  production.  At December 31,  2001,  we had no
hedging  contracts  in place.  For year ended  December  31,  2001,  our hedging
strategies reduced our realized gas prices by $0.47 per Mcf.

Item 8  Financial Statements and Supplementary Data

                See last section of this report

Item 9  Changes and Disagreements  with  Accountants on Accounting and Financial
        Disclosure

               Not applicable.

                      (This space left blank intentionally)

<PAGE>
                                    PART III

Item 10   Directors and Executive Officers of the Registrant

The  following  table sets forth  names,  ages and titles of our  directors  and
executive officers of RAM Energy, Inc.

<TABLE>
<CAPTION>
            Name                       Age               Position
            ----                       ---               --------
<S>                                    <C>      <C>
   William W. Talley II, Ph.D. (1)      59      Chairman of the Board of Directors

   Larry E. Lee                         53      President and Chief Executive Officer and Director

   Gerald R. Marshall (1)(2)            68      Director

   John M. Reardon (1)(2)               60      Director

   John M. Longmire                     59      Senior Vice President and Chief Financial Officer,
                                                Treasurer and Secretary

   Larry G. Rampey                      57      Senior Vice President - Operations

   Drake N. Smiley                      54      Senior Vice President - Land, Legal and Business
                                                Development
---------------

<FN>
(1)  Member of the Compensation Committee.

(2)  Member of the Audit Committee.
</FN>
</TABLE>

William W. Talley II,  Ph.D.  has been our  Chairman of the Board and a director
since we were  incorporated in 1987 and was Chief Executive Officer from 1987 to
1989 and from 1992 to October  31,  1997.  Dr.  Talley  served as the Society of
Petroleum Engineers' Distinguished Lecturer on natural gas marketing and pricing
in 1987  and  1988  and was  Vice  President  and  director  of the  Independent
Petroleum  Association  of America in 1987. Dr. Talley has been an officer and a
principal  of the RAM Group,  Ltd.,  an energy and  management-consulting  firm,
since 1974. He is a registered professional engineer.

Larry E. Lee has been our President and a director since we were incorporated in
1987.  Mr. Lee served as our Chief  Executive  Officer from 1989 to 1992 and has
served in such  capacity  since  November  1,  1997.  Mr. Lee is a member of the
Oklahoma  Independent  Petroleum  Association and of the  Independent  Petroleum
Association  of America.  He served as a director of the  Independent  Petroleum
Association  of America  from 1990 to 1992.  Mr.  Lee has been an officer  and a
principal of the RAM Group, Ltd. since 1984.

Gerald R. Marshall  became a director in December 1997.  Since October 1996, Mr.
Marshall has served as Vice  Chairman of the Midland  Group,  an  Oklahoma-based
financial services organization. Since December 1993, Mr. Marshall has served as
President and Chief Executive  Officer of Midland Asset Management Co., an asset
management  and financial  consulting  firm. He has served as Chairman and Chief
Executive Officer of RAM Management  Associates,  Inc., a management  contractor
for the Resolution Trust Corporation, since March 1990.

John M. Reardon  became a director in December  1997 and served as an adviser to
our Board of Directors  from August 1994 until  December  1997.  Mr. Reardon has
been President and Chief  Executive  Officer of Valencia Bank & Trust  (formerly
Valencia National Bank), of Santa Clarita,  California,  since August 1994. From
1991 to August 1994,  he was Senior Vice  President of RAMCO Oil & Gas,  Inc., a
former subsidiary of the Company,  and of RAM Management  Associates,  Inc. From
1987 to 1991, Mr. Reardon was a Senior Vice President of Wells Fargo Bank.

John M. Longmire  became a Senior Vice President in December 1997 and had been a
Vice  President  of the Company  since  1994.  Mr.  Longmire  has been our Chief
Financial  Officer,  Treasurer  and  Secretary  since  August  1994  and was our
Controller  from 1990 to February 1994.  Previously,  he held various  financial
management  positions with Texas International  Company,  Amarex, Inc. and Union
Oil Company of California. Mr. Longmire is a Certified Public Accountant.

Larry G. Rampey  became a Senior Vice  President in December 1997 and had been a
Vice President  since 1989.  From 1972 to 1989, Mr. Rampey held the positions of
Vice  President  of  International   Operations,   Vice  President  of  Domestic
Operations and staff engineer for Reading & Bates Petroleum Co.

Drake N. Smiley  became a Senior Vice  President in December 1997 and had been a
Vice President since February 1997. Mr. Smiley was our Vice President - Land and
Legal from 1989 to 1994.  From 1994 until he  rejoined  us in 1997,  Mr.  Smiley
served as Vice President - Land of Continental  Resources,  Inc., an independent
oil and gas  company.  From 1980 to 1989,  he was  employed  by  Reading & Bates
Petroleum  Co.,  serving  as  Manager  of Land.  Mr.  Smiley  is a member of the
Oklahoma and Tulsa County Bar Associations.

Our directors are divided into three classes,  with each class having as equal a
number of directors as  practicable.  The  directors  are elected on a staggered
basis for  three-year  terms.  One class stands for  re-election  at each annual
meeting of  stockholders.  The terms of Mr. Lee and Mr.  Marshall will expire in
2002 and the term of Mr.  Reardon will expire in 2003.  Dr.  Talley's  term will
expire in 2004.  Our executive  officers serve at the discretion of the Board of
Directors.

Dr. Talley and Mr. Lee beneficially own and were formerly  executive officers of
Jobs for St. Landry Parish,  Inc., d/b/a Standard  Fittings  Company  ("Standard
Fittings"), a manufacturer of pipe fittings.  Standard Fittings filed a petition
pursuant to Chapter 11 of the U.S.  Bankruptcy  Code in January 1997 in the U.S.
Bankruptcy  Court  for  the  Western  District  of  Louisiana.  The  Chapter  11
proceeding was dismissed in June 1997.

Dr. Talley and Mr. Lee collectively  owned 49.5% of the outstanding common stock
and  served  on the Board of  Directors  of  Oklahoma  Double R  Corporation,  a
Delaware corporation ("ODRC").  Dr. Talley and Mr. Lee were the senior executive
officers of ODRC. ODRC was special  general partner of a limited  partnership in
which an  institutional  investor was the sole limited  partner.  We managed the
limited partnership.  Upon dissolution of the partnership in 1997, all of ODRC's
interest in the properties of the  partnership  was distributed to us in partial
satisfaction  of  outstanding  indebtedness  from ODRC to us.  ODRC had no other
assets.  During  1999,  ODRC filed a petition  pursuant to Chapter 7 of the U.S.
Bankruptcy  Code in the  U.S.  Bankruptcy  Court  for the  Western  District  of
Oklahoma, which proceeding was fully administered and concluded in 2001.

Item 11  Executive Compensation

The following table sets forth for the years indicated the cash  compensation of
our chief executive  officer and each of our other four most highly  compensated
executive officers as of December 31, 2001.

<TABLE>
<CAPTION>
                                                                           Other  Under-      All
Summary Compensation Table                                                Annual  lying      Other
                                             Annual Compensation         Compen- Options    Compen-
                                            ---------------------        sation   (# of     sation
Name and Principal Position              Year    Salary      Bonus       (1)    Shares)(2) ($)(3)(4)
---------------------------              ----    ------      -----       ------ ---------- ---------
<S>                                      <C>    <C>        <C>           <C>    <C>        <C>
William W. Talley II, Ph.D               2001   $ 65,000   $150,000          -         -   $ 10,500
Chairman of the Board(4)                 2000    240,000          -          -         -    888,332
                                         1999    240,000    150,000          -         -          -

Larry E. Lee                             2001    321,550    300,000          -         -     10,500
         (5)                                                112,500
President and Chief Executive Officer    2000    295,000          -          -         -      4,486
                                         1999    295,000    300,000          -         -          -

Larry G. Rampey                          2001    164,300     70,000          -         -    264,936
Senior Vice President                    2000    155,000          -          -         -      4,486
                                         1999    155,000     50,000          -         -          -

John M. Longmire                         2001    153,700     50,000          -         -    235,713
Senior Vice President, Chief Financial   2000    145,000          -          -         -      4,486
   Officer, Treasurer and Secretary      1999    145,000     50,000          -         -          -

Drake N. Smiley                          2001    153,700     60,000          -         -    231,813
Senior Vice President                    2000    140,000          -          -         -      4,486
                                         1999    140,000     50,000          -         -          -
---------------
<FN>

(1)  Personal  benefits  provided  by us did not exceed the lesser of $50,000 or
     10% of total annual salary and bonus for any named  executive  officer.  No
     other annual compensation was paid.

(2)  No options have been granted to, or are  outstanding and held by, the named
     executive officers.

(3)  Except for Dr.  Talley,  the amounts  specified for the year 2000 represent
     matching  contributions  made by us to the account of the executive officer
     under our 401(k) Profit Sharing Plan.

(4)  Includes for Dr. Talley $4,486 and $10,500 matching  contribution under our
     401(k) Profit Sharing Plan for the years 2000 and 2001,  respectively,  and
     $883,846  for the year  2000 in  conjunction  with  termination  by us of a
     severance  agreement with him. (See "Employment and Severance  Agreements,"
     below.)

     Includes for Mr.  Rampey  $10,500  matching  contribution  under our 401(k)
     Profit  Sharing  Plan and $254,436  for the year 2001 in  conjunction  with
     termination by us of a severance  agreement with him. (See  "Employment and
     Severance Agreements," below.)

     Includes for Mr. Longmire  $10,500 matching  contribution  under our 401(k)
     Profit  Sharing  Plan and $225,213  for the year 2001 in  conjunction  with
     termination by us of a severance  agreement with him. (See  "Employment and
     Severance Agreements," below.)

     Includes  for Mr.  Smiley  $6,600  matching  contribution  under our 401(k)
     Profit  Sharing  Plan and $225,213  for the year 2001 in  conjunction  with
     termination by us of a severance  agreement with him. (See  "Employment and
     Severance Agreements," below.)

(5)  Mr. Lee was paid a bonus of $112,500 in 2001 for services provided to us in
     2000.
</FN>
</TABLE>

Directors' Compensation

We pay our  non-employee  directors and Dr. Talley an annual fee of $24,000 plus
$1,000 for each meeting  attended,  with a maximum of six meetings per year. Mr.
Lee,  as our  President  and  Chief  Executive  Officer,  does not  receive  any
director's fee. We reimburse all of our directors for travel and other expenses.

Compensation Committee, Interlocks and Insider Participation

The Compensation Committee of our board of directors determines the compensation
of our  executive  officers.  During  2001,  the  members  of  the  Compensation
Committee  were Gerald R. Marshall and John M. Reardon,  all of whom are members
of our board of directors.  In addition,  one of our former directors,  M. Helen
Bennett, resigned as a member of our Compensation Committee, effective March 30,
2001. In August 2001, Dr. Talley became a member of our Compensation Committee.

Employment and Severance Agreements

We have an employment  agreement  with Mr. Lee effective  January 1, 2002 for an
initial term expiring on December 31, 2004,  subject to annual extensions of one
year,  at an annual  salary of $321,550 and an annual bonus to be  determined by
the Board. Under this agreement, Mr. Lee's employment may be terminated by us or
Mr. Lee at any time.  Upon Mr. Lee's  death,  his  representatives  or, upon his
disability, Mr. Lee, will receive accrued but unpaid salary, bonus and benefits,
a pro rata  share of any bonus  paid for the  immediately  preceding  year,  one
year's  salary and an amount  equal to the highest  bonus paid to him during the
term of the agreement. In the event of Mr. Lee's disability, he will continue to
be entitled to receive  benefits for the remainder of the agreement.  If Mr. Lee
ceases to be an employee other than by reason of death, disability, for cause or
by  voluntary  resignation,  he is  entitled  to receive  his accrued but unpaid
salary and  benefits,  an amount equal to a pro rata share of any bonus paid for
the  immediately  preceding  year,  plus an amount equal to three times his base
salary.

We have an  employment  agreement  with Dr.  Talley  under  which he  serves  as
Chairman  of the Board of  Directors  of the  Company at a salary of $65,000 per
year, plus a fee of $1,000 per board meeting up to a maximum of six meetings per
year.  This agreement may be terminated by Dr. Talley or by us at any time. Upon
termination  of this  employment  agreement,  we have no  obligation to make any
severance  payment to Dr. Talley.  The  employment  agreement  became  effective
January 1, 2001, upon termination of the special severance  agreement between us
and Dr.  Talley  that had been in  existence  since  December  1997.  Under that
special severance  agreement,  Dr. Talley received a base salary of $240,000 per
year,  plus any  annual  bonus  awarded by the Board.  Upon  termination  of the
special severance agreement,  we agreed to pay Dr. Talley the severance benefits
provided in the special severance agreement, totaling $884,000, all of which was
treated as an  expense in our  consolidated  financial  statements  for the year
ended  December 31, 2000. The sum of $164,000 was paid in December 2000, and the
remaining $720,000 was paid during 2001.

We had employment and severance  agreements  with Messrs.  Longmire,  Rampey and
Smiley.  Each of these agreements  expired December 31, 2001. As a result of the
expiration of these agreements,  we incurred  non-removal payment obligations to
Messrs.  Longmire,  Rampey  and  Smiley  of  $225,213,  $254,436  and  $225,213,
respectively. These amounts were paid in January, 2002.

Stock Incentive Plan

Our 1998 Stock Incentive Plan (the "Plan")  authorizes the grant of nonqualified
stock options,  incentive stock options and restricted stock awards to employees
and  non-employee  directors.  The  purpose of the Plan is to create  incentives
designed to motivate our employees and directors to exert maximum efforts toward
our success and growth, and to attract and retain experienced individuals who by
their position,  ability and diligence are able to make important  contributions
to our success. The Plan is administered by our Compensation Committee; however,
awards under the Plan to members of the  Compensation  Committee are made by the
full Board (whether the Compensation Committee or the Board, the "Committee").

The maximum  number of shares of common stock for which  options and  restricted
stock awards may be granted under the Plan is 550,000,  subject to adjustment in
the event of any stock dividend, stock split, recapitalization or reorganization
or  certain  business  combinations.  Shares  subject to  previously  expired or
terminated  options  or other  forfeited  awards  which  did not  result  in the
issuance of shares become  available again for awards under the Plan. The shares
to be  issued  under the Plan may be newly  issued  shares,  treasury  shares or
shares acquired privately or by open-market purchases.  The number of shares and
other terms of each grant are  determined  by the  Committee;  provided that the
shares  subject  to stock  options  granted  under  the Plan and the  shares  of
restricted  stock awarded under the Plan in any year to any  participant may not
exceed an aggregate of 25,000.  Awards under the Plan may, in the  discretion of
the  Committee,  provide  for  immediate  vesting  upon a change of control  (as
defined in the Plan).

The price  payable upon the exercise of both  incentive and  nonqualified  stock
options may not be less than 100% of the fair market  value of the common  stock
at the time of grant or, in the case of an incentive  stock option granted to an
employee  owning stock  possessing  more than 10% of the total  combined  voting
power of all of our  classes  of stock (a "10%  Shareholder"),  110% of the fair
market value of the common stock on the date of grant.  Incentive  stock options
may be  granted  only to  employees,  and the  aggregate  exercise  price of all
incentive stock options under all plans becoming  exercisable for the first time
by an employee  during any calendar  year may not exceed  $100,000.  Each option
granted under the Plan will expire on the date specified by the Committee,  but,
with respect to incentive  stock options,  not more than ten years from the date
of grant or, in the case of a 10% Shareholder, not more than five years from the
date of grant.  Unless the  Committee  otherwise  provides,  a stock option will
terminate  three months (one year in the event of an  optionee's  disability  or
three  years  in  the  event  of  an  optionee's  death)  after  the  optionee's
termination of employment or termination  as a director.  In no event,  however,
will an option be exercisable  after its expiration  date. The Committee has the
power to accelerate  the vesting of options not  exercisable  on the  optionee's
termination  date. The exercise price of an option granted under the Plan may be
paid in cash,  shares of common  stock  having a fair market  value equal to the
exercise  price  (either  shares then owned by the optionee or to be issued upon
exercise of the option) or a combination of cash and common stock.  In addition,
an optionee may utilize a broker to effect a contemporaneous  sale of sufficient
shares  subject  to the  option  to pay the  exercise  price  by  following  the
procedure set forth in the Plan.

Restricted  stock  awards are  subject to such terms,  conditions,  restrictions
and/or limitations as the Committee deems appropriate including, but not limited
to,  restrictions on transferability  and continued  employment (or service as a
director in the case of non-employee directors).

Outstanding  options become  nonforfeitable  and exercisable in full immediately
prior to our liquidation, dissolution, merger, consolidation, or the sale of all
or substantially  all of our assets if provision is not made in such transaction
for the assumption by the acquiror of outstanding unvested options granted under
the Plan or the substitution for new options.  Unexercised  outstanding  options
will terminate upon the  consummation of our dissolution,  liquidation,  merger,
consolidation or sale of assets.

The Plan may be  terminated  or amended by our Board of  Directors  at any time,
subject to  stockholder  approval  in the case of  amendments  to  increase  the
aggregate  number of shares of  common  stock  subject  to the Plan or to permit
options with below-market  exercise prices. If not earlier terminated,  the Plan
expires in 2008.

No stock options or restricted stock awards have yet been granted to officers or
directors under the Plan.

Officer and Director Liability

As permitted by the  provisions  of the Delaware  General  Corporation  Law, our
certificate of incorporation,  eliminates in certain  circumstances the monetary
liability of directors  of the Company for a breach of their  fiduciary  duty as
directors. These provisions do not eliminate the liability of a director for:

     o    a breach of the director's duty of loyalty to us or our  stockholders,
          acts or  omissions  by a director  not in good faith or which  involve
          intentional misconduct or a knowing violation of law,

     o    liability   arising  under   Section  174  of  the  Delaware   General
          Corporation Law (relating to the declaration of dividends and purchase
          or  redemption  of  shares  in  violation  of  the  Delaware   General
          Corporation Law) or

     o    any transaction from which the director  derived an improper  personal
          benefit.

In addition,  these  provisions do not eliminate the liability of a director for
violations of federal  securities  law, nor do they limit our rights or those of
our stockholders, in appropriate circumstances,  to seek equitable remedies such
as injunctive or other forms of non-monetary  relief.  These remedies may not be
effective in all cases.

Our certificate of incorporation  and bylaws provide that we shall indemnify all
of our  directors  and  officers to the full extent  permitted  by the  Delaware
General Corporation Law. Under these provisions, any director or officer, who in
his capacity as such,  is made or  threatened  to be made a party to any suit or
proceeding, may be indemnified if the Board of Directors determines the director
or officer acted in good faith and in a manner he  reasonably  believed to be in
or not opposed to our best interest.  The certificate of  incorporation,  bylaws
and  the   Delaware   General   Corporation   Law  further   provide  that  such
indemnification  is not exclusive of any other rights to which such  individuals
may be entitled under the certificate of incorporation,  bylaws,  any agreement,
vote of stockholders or disinterested directors or otherwise.

We entered into  indemnity  agreements  with each of our directors and executive
officers.  Under  each  indemnity  agreement,  we  will  pay  on  behalf  of the
indemnitee, and the indemnitee's executors, administrators and heirs, any amount
which he or she is or becomes legally obligated to pay because of:

     o    any claim or claims from time to time  threatened  or made against him
          or her by any  person  because  of any act or  omission  or neglect or
          breach of duty,  including any actual or alleged error or misstatement
          or  misleading  statement,  which he or she  commits or suffers  while
          acting in his or her capacity as our director and/or officer of one of
          our affiliates.

     o    being  a  party,  or  being  threatened  to be  made a  party,  to any
          threatened,  pending  or  contemplated  action,  suit  or  proceeding,
          whether civil, criminal, administrative or investigative, by reason of
          the fact that he or she is or was our officer,  director,  employee or
          agent or one of our  affiliates or is or was serving at our request as
          a  director,  officer,  employee  or  agent  of  another  corporation,
          partnership, joint venture, trust or other enterprise.

The  payments  which we will be  obligated  to make  pursuant to such  indemnity
agreement include damages, charges, judgments, fines, penalties, settlements and
court costs, costs of investigation and costs of defense of legal,  equitable or
criminal  actions,  claims or proceedings  and appeals  therefrom,  and costs of
attachment,  supersedeas, bail, surety or other bonds. We also intend to provide
liability insurance for each of our directors and executive officers.

Item 12   Security Ownership of Certain Beneficial Owners and Management

The following  table sets forth  certain  information  regarding the  beneficial
ownership of our common stock as of December 31, 2001 by:

     o    each of our directors who own common stock,

     o    each of our Named Executive Officers who own common stock,

     o    each person known or believed by us to own  beneficially 5% or more of
          our common stock, and

     o    all directors and executive officers as a group.

Unless otherwise  indicated,  each person has sole voting and dispositive  power
with respect to such shares.

<TABLE>
<CAPTION>
                                                  Shares of
                                                    Common         Ownership
     Name of Beneficial Owner                        Stock         Percentage
     ------------------------                        -----         ----------
<S>                                               <C>                  <C>
     William W. Talley II, Ph.D. (1)(2)(3)        1,363,500             50%
     9400 N. Broadway Extension
     Oklahoma City, Oklahoma 73114

     Larry E. Lee (1)(2)                          1,363,500             50%
     5100 E. Skelly Drive Suite 650
     Tulsa, Oklahoma 74135
                                                  ---------            ---
     All executive officers and directors         2,727,000            100%
     as a group (8 persons)
                                                  =========            ===
---------------
<FN>

(1)  Director

(2)  Named Executive Officer

(3)  Such shares are held in a trust as to which Dr.  Talley has sole voting and
     dispositive power.
</FN>
</TABLE>

Item 13  Certain Relationships and Related Transactions

We completed the  redemption of all of our Series B Preferred  Stock in February
1998.  The Series B  Preferred  Stock was issued in 1987 and 1988 for $10.00 per
share. Dr. Talley, Mr. Lee, one of our former directors,  Mrs. Bennett,  and one
other  person  beneficially  owned  in  equal  amounts  all  of the  issued  and
outstanding  shares of Series B Preferred  Stock.  The redemption price for each
share of Series B Preferred Stock was $10.00 per share, resulting in the payment
of $174,130 to each holder, for an aggregate redemption price of $696,520.

                                     PART IV

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

(a)(1)  The following financial statements of RAM Energy, Inc. are included in
        Item 8:

        Report of Independent Auditors

        Consolidated Balance Sheets as of December 31, 2000 and 2001.

        Consolidated Statements of Operations of the Company for the
        years ended December 31, 1999, 2000, and 2001.

        Consolidated Statements of Stockholders' Deficiency for the
        years ended December 31, 1999, 2000, and 2001.

        Consolidated Statements of Cash Flows of the Company for the years
        ended December 31, 1999, 2000, and 2001.

        Notes to Consolidated Financial Statements

   (2)  Not applicable

   (3)  Exhibits

Exhibit
No.           Description of Exhibit
-------       ----------------------

3.1           Company's Amended and Restated Certificate of Incorporation (1)

3.2           Company's Amended and Restated Bylaws (1)

4.1           Indenture dated as of February 24, 1998 among the Company, as
              issuer, RB Operating Company and RLP Gulf States, L.L.C., as
              Subsidiary Guarantors, and United States Trust Company of
              New York, as trustee (1)

4.2           Form of 11-1/2% Senior Notes due 2008 (included in Exhibit 4.1)
              (1)

4.3           Supplemental Indenture entered into February 24, 1998 by the
              Registrant, the Subsidiary Guarantors, the Additional Guarantors
              and United States Trust Company of New York, as Trustee (2)

10.4          RAM Energy 1998 Stock Incentive Plan* (1)

10.5          Special Severance Agreement by and between William W. Talley II
              and the Company dated as of December 1, 1997* (1)

10.6          Employment Agreement by and between Larry E. Lee and the Company
              dated as of December 1, 1997* (1)

10.8          Form of the Company's Indemnity Agreement* (1)

10.6.1.1      Amendment of Employment Agreement by and between Larry E. Lee and
              the Company (3)

10.17         Employment Agreement by and between William W. Talley II and the
              Company dated January 1, 2001 (3)

10.18         Employment and Severance Agreement by and between John M. Longmire
              and the Company dated December 1, 2000 (3)

10.19         Employment and Severance Agreement by and between Larry G. Rampey
              and the Company dated December 1, 2000 (3)

10.20         Employment and Severance Agreement by and between Drake N. Smiley
              and the Company dated December 1, 2000 (3)

21            Subsidiaries of the Company (3)

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

X        Management contract or compensatory plan or arrangement.

(1)      Filed as an exhibit to the Company's Registration Statement on Form
         S-4 (No. 333-42641) and incorporated by reference herein.

(2)      Filed as an exhibit to the Company's Current Report on Form 8-K filed
         on March 10, 1998, as the exhibit number 4.2.

(3)      Filed as an exhibit to the Company's Annual Report on Form 10-K filed
         on April 2, 2001 and incorporated by reference herein.


(b)      During the quarter ended December 31, 2001 the Registrant filed the
         following reports on 8-K:

         Date of Report         Items Covered
         --------------         -------------

         November 27, 2001      Item 5.  Other Material Events

         December 6, 2001       Item 2.  Acquisition or Disposition of Assets
<PAGE>
                                  ATTACHMENT I








CONSOLIDATED FINANCIAL STATEMENTS
RAM Energy, Inc.
Years ended December 31, 1999, 2000, and 2001



<PAGE>


                                RAM Energy, Inc.

                        Consolidated Financial Statements


                  Years ended December 31, 1999, 2000, and 2001




                                    Contents

Report of Independent Auditors..........................................F-1

Consolidated Audited Financial Statements

Consolidated Balance Sheets.............................................F-2
Consolidated Statements of Operations...................................F-3
Consolidated Statements of Stockholders' Deficiency.....................F-4
Consolidated Statements of Cash Flows...................................F-5
Notes to Consolidated Audited Financial Statements......................F-7

<PAGE>

                         Report of Independent Auditors

The Board of Directors
RAM Energy, Inc.

We have audited the accompanying consolidated balance sheets of RAM Energy, Inc.
as of December 31, 2000 and 2001,  and the related  consolidated  statements  of
operations, stockholders' deficiency, 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. 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 financial  statements  referred to above present fairly, in
all material respects,  the consolidated  financial position of RAM Energy, Inc.
at December 31, 2000 and 2001,  and the  consolidated  results of its operations
and its 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.

As discussed in Note 1 of the notes to the  consolidated  financial  statements,
effective January 1, 2001, the Company adopted Statement of Financial Accounting
Standards No. 133, Accounting for Derivative Instruments and Hedging Activities.

                                        ERNST & YOUNG LLP
Tulsa, Oklahoma
March 22, 2002

<PAGE>
<TABLE>
                                   RAM Energy, Inc.

                             Consolidated Balance Sheets
                                (Dollars in Thousands)
<CAPTION>
                                                                     December 31
                                                                   2000      2001
                                                                   ----      ----
<S>                                                              <C>        <C>
Assets
Current assets:
   Cash and cash equivalents                                     $    917   $ 19,874
   Accounts receivable:
      Escrow cash (Note 3)                                              -      6,375
      Natural gas and oil sales                                     5,316      1,921
      Joint interest operations, net of allowance
        for doubtful accounts of $532 in 2000 and $532 in 2001
                                                                    1,691      1,243
      Related parties                                                 207          -
      Other                                                           381         47
   Prepaid expenses and deposits                                      423        626
                                                                 --------   --------
Total current assets                                                8,935     30,086

Properties and equipment at cost (Note 15):
   Natural gas and oil properties and equipment, based
     on full cost accounting                                      124,026     49,449
   Pipeline system                                                 39,677     39,813
   Other property and equipment                                     4,294      4,497
                                                                 --------   --------
                                                                  167,997     93,759
   Less accumulated amortization and depreciation                  49,088     28,281
                                                                 --------   --------
Net properties and equipment                                      118,909     65,478

Other assets:
   Deferred loan costs, net of accumulated amortization
     of $1,583 in 2000                                              1,084          -
   Deferred offering costs, net of accumulated amortization
     of $1,281 in 2000 and $1,539 in 2001 (Note 6)                  3,203      2,462
   Other                                                              705        296
                                                                 --------   --------
Total assets                                                     $132,836   $ 98,322
                                                                 ========   ========

Liabilities and Stockholders' Deficiency
Current liabilities:
   Accounts payable:
      Trade                                                      $  4,369   $  4,115
      Natural gas and oil proceeds due others                       5,842      4,186
      Related parties                                                   -         76
   Accrued liabilities:
      Compensation                                                    876      1,048
      Interest                                                      4,493      3,988
      Other                                                           228         27
   Gas balancing liability                                            639         41
   Long-term debt due within one year (Note 6)                        154        135
                                                                 --------   --------
Total current liabilities                                          16,601     13,616

Gas balancing liability and other not expected
  to be settled within one year                                     3,539      2,194
Long-term debt due after one year (Note 6)                        127,426     91,265
Deferred income taxes                                               8,768     10,994
Commitments and contingencies (Notes 6, 8, and 13)                    600        600

Stockholders' deficiency (Note 10):
   Preferred stock, $.01 par value; authorized--
     5,000,000 shares; issued and outstanding--none                     -          -
   Common stock, $.01 par value; authorized--
     15,000,000 shares; issued and outstanding--
     2,727,000 shares                                                  27         27
   Paid-in capital                                                     16         16
   Accumulated deficit                                            (24,141)   (20,390)
                                                                 --------   --------
Stockholders' deficiency                                          (24,098)   (20,347)
                                                                 --------   --------
Total liabilities and stockholders' deficiency                   $132,836   $ 98,322
                                                                 ========   ========
</TABLE>

See accompanying notes.

<TABLE>
                                            RAM Energy, Inc.

                                 Consolidated Statements of Operations
                                  (In Thousands, Except Share Amounts)
<CAPTION>
                                                                        Year ended December 31
                                                                 1999           2000            2001
                                                                 ----           ----            ----
<S>                                                          <C>            <C>            <C>
Operating revenues:
   Natural gas and oil sales                                 $    23,085    $    25,641    $    25,404
   Pipeline system                                                 9,198         14,100         15,602
   Other (Note 5)                                                    827            294            210
                                                             -----------    -----------    -----------
Total operating revenues                                          33,110         40,035         41,216

Operating expenses:
   Natural gas and oil production taxes                            1,967          2,762          2,755
   Natural gas and oil production expenses                         5,826          4,994          5,975
   Pipeline purchases                                              6,621         10,362         12,227
   Pipeline operations                                               414            489            489
   Amortization and depreciation                                  12,964         10,091          9,766
   Contract termination and severance payments                         -          1,221          1,104
   General and administrative, overhead and other expenses,
      net of operator's overhead fees (Note 5)                     4,437          3,353          4,061
                                                             -----------    -----------    -----------
Total operating expenses                                          32,229         33,272         36,377
                                                             -----------    -----------    -----------
Operating income                                                     881          6,763          4,839

Other income (expense):
   Gain on sale of natural gas and oil properties (Note 3)             -              -         17,320
   Interest expense                                              (14,623)       (15,455)       (14,514)
   Interest income                                                   169            148            104
   Equity in loss of RVC Energy, Inc. (Note 2)                    (1,307)             -              -
                                                             -----------    -----------    -----------
Income (loss) before income taxes and extraordinary items        (14,880)        (8,544)         7,749

Income tax provision (benefit) (Note 11)                          (5,650)        (3,200)         2,900
                                                             -----------    -----------    -----------
Income (loss) before extraordinary items                          (9,230)        (5,344)         4,849
                                                             ===========    ===========    ===========

Extraordinary gain (loss) on acquisition of debt, net of income
   tax provision (benefit) of $562 in 2000 and ($674) in 2001          -            916         (1,098)
                                                             -----------    -----------    -----------
Net income (loss)                                            $    (9,230)   $    (4,428)   $     3,751
                                                             ===========    ===========    ===========

Per share amounts--basic and diluted:
   Income (loss) before extraordinary items                  $     (3.38)   $     (1.96)   $      1.78
   Extraordinary gain (loss)                                           -            .34           (.40)
                                                             -----------    -----------    -----------
Net income (loss)                                            $     (3.38)   $     (1.62)   $      1.38
                                                             ===========    ===========    ===========

Weighted average shares outstanding                            2,727,000      2,727,000      2,727,000
                                                             ===========    ===========    ===========
</TABLE>

See accompanying notes.

<TABLE>
                                                          RAM Energy, Inc.

                                         Consolidated Statements of Stockholders' Deficiency
                                                           (In Thousands)
<CAPTION>
                                                                                                        Accumulated
                                                                                                          Other           Total
                                                Preferred     Common      Paid-In    Accumulated       Comprehensive   Stockholders'
                                                   Stock       Stock      Capital      Deficit         Income(Loss)     Deficiency
                                               -----------   ---------   ---------   --------------    -------------   ------------
<S>                                            <C>          <C>           <C>         <C>              <C>           <C>
Balance at December 31, 1998                   $      -     $     27      $     16    $  (10,483)      $        -    $  (10,440)

   Net loss                                           -            -             -        (9,230)               -        (9,230)
                                               --------     --------      --------    ----------       ----------    ----------
Balance at December 31, 1999                          -           27            16       (19,713)               -       (19,670)

   Net loss                                           -            -             -        (4,428)               -        (4,428)
                                               --------     --------      --------    ----------       ----------    ----------
Balance at December 31, 2000                          -           27            16       (24,141)               -       (24,098)

Comprehensive income:
   Net income                                         -            -             -         3,751                -         3,751

   Transition adjustment upon adoption of
   SFAS No. 133 at January 1, 2001, net of
   income tax benefit of $2,816                       -            -             -             -           (4,596)       (4,596)

   Change in the value of derivative
   contracts, net of income taxes of $1,787           -            -             -             -            2,916         2,916

   Reclassification adjustments contract
   settlements, net of income taxes of $1,030         -            -             -             -            1,680         1,680
                                                                                                                     ----------
Total comprehensive income                                                                                                3,751
                                               --------     --------      --------    ----------       ----------    ----------
Balance at December 31, 2001                   $      -     $     27      $     16    $  (20,390)      $        -    $  (20,347)
                                               ========     ========      ========    ==========       ==========    ==========
</TABLE>

See accompanying notes.

<TABLE>
                                                     RAM Energy, Inc.

                                          Consolidated Statements of Cash Flows
                                                      (In Thousands)
<CAPTION>
                                                                                              Year ended December 31
                                                                                           1999        2000        2001
                                                                                           ----        ----        ----
<S>                                                                                     <C>         <C>         <C>
Operating Activities
Net income (loss)                                                                       $ (9,230)   $ (4,428)   $  3,751
Adjustments to reconcile net income (loss) to net cash provided by (used in)
   operating activities:
      Amortization of Senior Notes discount included in interest expense                     157         157         148
      Amortization and depreciation:
         Natural gas and oil properties and equipment                                      9,578       6,861       6,534
         Pipeline system                                                                   1,950       1,950       2,044
         Deferred offering costs                                                             470         470         443
         Deferred loan costs                                                                 327         541         497
         Other property and equipment                                                        549         269         248
      Provision for doubtful accounts receivable and other                                   116          60           -
      Gain on sale of natural gas and oil properties                                           -           -     (17,320)
      Gain on sale of other property and equipment                                             -         (23)       (103)
      Extraordinary (gain) loss on retirement of debt, net                                     -        (916)      1,098
      Equity in loss of RVC Energy, Inc.                                                   1,307           -           -
      Deferred income taxes, net                                                          (5,650)     (3,200)      2,900
      Cash provided by (used in) changes in operating assets and liabilities:
            Prepaid expenses and deposits                                                     70         (62)       (274)
            Accounts receivable                                                              664      (2,667)      4,352
            Accounts payable                                                              (5,306)      5,593      (3,600)
            Accrued liabilities                                                             (498)      2,221       1,940
            Gas balancing liability                                                         (472)       (878)       (418)
                                                                                        --------    --------    --------
Total adjustments                                                                          3,262      10,376      (1,511)
                                                                                        --------    --------    --------
Net cash provided by (used in) operating activities                                       (5,968)      5,948       2,240

Investing Activities
Payments for natural gas and oil properties and equipment                                 (4,485)     (6,885)    (11,044)
Cash proceeds from sale of natural gas and oil properties to Carmen Acquisition
   Corp., net of transaction costs                                                             -           -      55,869
Proceeds from sales of other natural gas and oil properties and equipment                  2,903       2,752          92
Payments for other property and equipment                                                   (283)       (454)       (271)
Proceeds from sales of other property and equipment                                           26          27          10
Payments for pipeline system                                                                (438)        (54)       (136)
Payment for other assets                                                                    (197)       (372)          -
Proceeds from sales of other assets                                                          205         141           -
                                                                                        --------    --------    --------
Net cash provided by (used in) investing activities                                       (2,269)     (4,845)     44,520

Financing Activities
Payments on long-term debt                                                                (8,045)     (4,942)    (28,862)
Proceeds from borrowings on long-term debt                                                 5,504       6,231       1,059
Proceeds from volumetric production payment                                                5,000           -           -
Payments for purchase of Senior Notes                                                          -      (3,303)          -
Payments for loan origination fees                                                          (950)        (47)          -
                                                                                        --------    --------    --------
Net cash provided by (used in) financing activities                                        1,509      (2,061)    (27,803)
                                                                                        --------    --------    --------
Increase (decrease) in cash and cash equivalents                                          (6,728)       (958)     18,957

Cash and cash equivalents at beginning of year                                             8,603       1,875         917
                                                                                        --------    --------    --------
Cash and cash equivalents at end of year                                                $  1,875    $    917    $ 19,874
                                                                                        ========    ========    ========

Disclosure of Noncash Investing and Financing Activities
Accrued interest added to principal balance of Foothill
   credit facility                                                                      $      -    $  1,722    $  2,474
                                                                                        ========    ========    ========

Senior Notes received from Chesapeake Energy Corporation as partial consideration in
   the sale of certain natural gas and oil properties (Note 3)                          $      -    $      -    $ 11,099
                                                                                        ========    ========    ========
</TABLE>

See accompanying notes.
<PAGE>

                                RAM Energy, Inc.

                   Notes to Consolidated Financial Statements

                           December 31, 2000 and 2001

1.   Summary of  Significant  Accounting  Policies,  Organization,  and Basis of
     Financial Statements

Nature of Operations and Organization

RAM Energy,  Inc. (the Company) operates  exclusively in the upstream segment of
the natural gas and oil industry with activities including drilling,  completion
and operation of natural gas and oil wells. The Company conducts the majority of
its operations in the states of Oklahoma,  Texas, and New Mexico.  Additionally,
the  Company  owns and  operates  a natural  gas and oil  pipeline  system and a
saltwater  disposal  operation in north central Oklahoma (the pipeline  system).
The  pipeline  system  purchases,  transports  and  markets  natural gas and oil
production and disposes of salt water from  properties  owned by the Company and
other  natural gas and oil  companies.  On December 1, 2001,  the Company sold a
substantial portion of its natural gas and oil properties (see Note 3).

Principles of Consolidation

The consolidated  financial  statements  include the accounts of the Company and
its wholly owned subsidiaries.  All significant  intercompany  transactions have
been eliminated.

Properties and Equipment

The Company  follows the full cost method of accounting  for natural gas and oil
operations.  Under this method, all productive and nonproductive  costs incurred
in connection with the  acquisition,  exploration and development of natural gas
and oil reserves are  capitalized.  No gains or losses are  recognized  upon the
sale  or  other  disposition  of  natural  gas  and  oil  properties  except  in
transactions  which  would  substantially  alter  the  amortization  base of the
capitalized costs.

With the exception of the plugging and abandonment  obligation further described
in Note  13,  the  Company  does  not  believe  that  future  costs  related  to
dismantlement, site restoration, and abandonment costs, net of estimated salvage
values, will have a significant effect on its results of operations or financial
position  because the salvage  value of  equipment  and  related  facilities  is
expected to approximate  or exceed any future  expenditures  for  dismantlement,
restoration,  or abandonment.  The Company has not incurred any net expenditures
for costs of this nature during the last three years.

Under  the  full  cost  method,  the  net  book  value  of  natural  gas and oil
properties,  less related  deferred  income taxes,  may not exceed the estimated
after-tax  future net  revenues  from  proved  natural  gas and oil  properties,
discounted  at 10% per year (the ceiling  limitation).  In arriving at estimated
future net revenues,  estimated lease  operating  expenses,  development  costs,
abandonment  costs,  and  certain  production-related  and ad valorem  taxes are
deducted. In calculating future net revenues,  prices and costs in effect at the
time of the calculation are held constant indefinitely, except for changes which
are fixed and determinable by existing contracts. The net book value is compared
to the ceiling  limitation on a quarterly and yearly basis. The excess,  if any,
of the net book value above the ceiling  limitation is charged to expense in the
period in which it occurs and is not subsequently reinstated.  Reserve estimates
used in  determining  estimated  future net  revenues  have been  prepared by an
independent petroleum engineer.

The discounted future net revenues at December 31, 2001,  include  approximately
$20  million  related  to  undeveloped  and  nonproducing  properties  on  which
estimated  discounted capital expenditures of approximately $8.4 million will be
required to develop and produce the reserves.  The funding for these projects is
expected by the Company to be provided from existing available cash, future cash
flows from  operations and from proceeds  received from property sales (see Note
3).

The Company has  capitalized  internal costs of $600,000,  $613,000 and $657,000
for the years ended  December  31,  1999,  2000,  and 2001,  respectively.  Such
capitalized costs include salaries and related benefits of individuals  directly
involved in the Company's  acquisition,  exploration and development  activities
based on the percentage of their time devoted to such activities.

The Company assesses the recoverability of the book value of the pipeline system
on a quarterly basis, or when events occur which indicate an impairment in value
may exist. Impairment is recorded for the excess of the book value over the fair
value of the  pipeline  system if the book  value of the  pipeline  system is in
excess of the expected future cash flows from the pipeline  system.  Accumulated
depreciation  related to the pipeline  system is  $5,525,000  and  $7,569,000 at
December 31, 2000 and 2001, respectively.

Other property and equipment consists principally of furniture and equipment and
leasehold  improvements.  Other  property and equipment and related  accumulated
amortization  and depreciation are relieved upon retirement or sale and the gain
or loss is included in operations.  Renewals and  replacements  which extend the
useful  life of  property  and  equipment  are  treated  as  capital  additions.
Accumulated  amortization  and  depreciation  of other property and equipment at
December 31, 2000 and 2001, is $3,445,000 and $3,443,000, respectively.

Amortization and Depreciation

Amortization  of natural gas and oil  properties and equipment is computed based
on the  unit-of-production  method using total proved reserves.  Depreciation of
pipeline  system is  computed  on a  straight-line  method  over  twenty  years.
Depreciation on other equipment is computed based on an accelerated  method over
the  estimated  useful  lives of the assets which range from three to ten years.
Amortization of leasehold  improvements  is computed based on the  straight-line
method over the term of the  associated  lease.  Amortization  of deferred  loan
origination  and debt  issuance  costs is  computed  based on the  straight-line
method over the term of the related debt.

Natural Gas and Oil Sales and Gas Imbalances

The Company  follows the  entitlements  method of accounting for natural gas and
oil sales,  recognizing  only its net share of all production  sold as revenues.
Any amount received in excess of or less than the Company's  revenue interest is
recorded in the net gas balancing liability.  At December 31, 2000 and 2001, the
Company's  net  overproduced   position  was  1,483,000  mcf  and  167,000  mcf,
respectively,   with  an  associated   liability  of  $2,178,000  and  $235,000,
respectively.  Charges for gathering and  transportation are included in natural
gas and oil production expenses.

Cash Equivalents

All highly liquid  unrestricted  investments  with a maturity of three months or
less when purchased are considered to be cash equivalents.

Credit and Market Risk

The Company sells natural gas and oil to various customers and participates with
other parties in the drilling,  completion  and operation of natural gas and oil
wells. Joint interest and natural gas and oil sales receivables related to these
operations are generally unsecured. In 2001, approximately 74% of total revenues
were to four  customers  (68% to four customers in 2000 and 53% to two customers
in 1999),  with sales to each  comprising 34%, 17%, 12%, and 11% (30%, 15%, 12%,
and 11% in 2000 and 29% and 24% in 1999) of total revenues.  For the years ended
December  31,  1999,  2000,  and 2001,  the  provisions  for  doubtful  accounts
receivable were approximately $116,000,  $60,000, and none, respectively,  while
charge-offs of the allowance in those years were  approximately  $15,000,  none,
and none,  respectively.  The Company has established joint interest  operations
accounts  receivable  allowances  which  management  believes  are  adequate for
uncollectible amounts at December 31, 2000 and 2001.

Use of Estimates

The preparation of financial statements in conformity with accounting principles
generally  accepted in the United States  requires  management to make estimates
and assumptions  that affect the reported  amounts of assets and liabilities and
disclosure of  contingent  assets and  liabilities  at the date of the financial
statements  and the  reported  amounts  of  revenues  and  expenses  during  the
reporting period. Actual results could differ from those estimates.

Fair Value of Financial Instruments

The  carrying  amounts  reported  in  the  balance  sheets  for  cash  and  cash
equivalents, trade receivables and payables, installment notes and variable rate
long-term debt approximate  their fair values.  The carrying value of the Senior
Notes  exceeded the fair value at December 31, 2000 and 2001,  by  approximately
$23.2 million and $23.9 million, respectively, based on quoted market prices.

Accounting Policy for Derivatives

On January 1, 2001, the Company  adopted  Financial  Accounting  Standards Board
Statement No. 133, Accounting for Derivative Instruments and Hedging Activities,
as amended,  (SFAS No. 133).  SFAS No. 133 requires  companies to recognize  all
derivative  instruments  as either  assets or  liabilities  in the  statement of
financial  position at fair value.  The accounting for changes in the fair value
of a  derivative  depends on the intended use of the  derivative  and  resulting
designation.  The  Company  formally  documents  its  hedging  relationships  at
inception of the hedge,  however  redesignation  is permitted.  For  derivatives
designated as cash flow hedges and meeting the effectiveness  guidelines of SFAS
No. 133,  changes in fair value are  recognized  in other  comprehensive  income
until the hedged item is recognized in earnings. Hedge effectiveness is measured
at  least  quarterly  based  on  relative  changes  in fair  value  between  the
derivative contract and hedged item during the period of hedge designation.  The
ineffective  portion  of a  derivative's  change  in fair  value  is  recognized
currently in earnings.  Forecasted transactions designated as the hedged item in
a cash flow hedge are regularly  evaluated to assess whether they continue to be
probable of occurring,  and if the forecasted  transaction is no longer probable
of  occurring,  any gain or loss  deferred in  accumulated  other  comprehensive
income is recognized  in earnings  currently.  All of the  Company's  derivative
contracts have been designated as cash flow hedges.

The adoption of SFAS No. 133 on January 1, 2001, resulted in a pre-tax reduction
to  accumulated  other  comprehensive  income  of  $7.4  million  ($4.6  million
after-tax)  as a result of losses  indicated on the  Company's  cash flow hedges
based on the  Company's  derivative  positions  and market  prices at January 1,
2001.

Earnings Per Common Share

Basic  earnings  per share is computed by  dividing  net income by the  weighted
average number of common shares outstanding for the period. Diluted earnings per
share reflects the potential dilution that could occur if dilutive stock options
and warrants were  exercised,  calculated  using the treasury stock method.  The
outstanding  stock  options  (see Note 10) were not  considered  in the  diluted
earnings per share calculations for 1999, 2000, and 2001, as the effect would be
antidilutive.  As a result,  basic  earnings per share and diluted  earnings per
share are the same.

Recently Issued Accounting Pronouncements

In June 2001, the Financial  Accounting  Standards Board (FASB) issued Statement
of Financial  Accounting Standards (SFAS) No. 141, Business  Combinations.  SFAS
No. 141 addresses financial accounting and reporting for business  combinations.
SFAS No. 141 is effective for all business combinations initiated after June 30,
2001, and for all business combinations  accounted for under the purchase method
initiated  before but completed  after June 30, 2001. In addition,  in June 2001
the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets. SFAS No. 142
addresses  financial  accounting  and reporting for acquired  goodwill and other
intangible  assets.  SFAS No. 142 is effective for fiscal years  beginning after
December 15, 2001, and applies to all goodwill and other intangibles  recognized
in the financial statements at that date. The adoption of these standards is not
expected  to have an impact  on the  Company's  current  financial  position  or
results of operations.  However, any business  combinations  initiated from this
point forward will be impacted by these two standards.

In August 2001, the FASB issued SFAS No. 143,  Accounting  for Asset  Retirement
Obligations,  and in October  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 No. 143 and No. 144;  however,  at this time does not believe the impact
of these  standards  will be material to the  Company's  financial  condition or
results of operations.

2.   Investment in RVC Energy, Inc.

In August 1998, RVC Energy, Inc. (RVC), a Delaware corporation,  was formed and,
concurrent  with the  formation,  the Company  invested  $2.0  million in RVC in
exchange  for 49.5% of RVC's  voting  common  stock and all of RVC's  non-voting
common stock.  RVC was an  unrestricted  affiliate of the Company  accounted for
under the equity  method of  accounting.  The Company  recognized  an impairment
charge of  approximately  $200,000 in 1999 to reduce its recorded  investment in
RVC to $0 at December  31,  1999.  As of December  31,  2000,  RVC had  divested
substantially  all  assets  such that the  Company is not  expecting  any future
recovery of this investment.

3.   Property Sales

In a transaction that closed December 4, 2001,  effective  December 1, 2001, the
Company sold to Carmen Acquisition Corp.  (Carmen), a wholly owned subsidiary of
Chesapeake  Energy  Corporation,  all of Company's  producing and  non-producing
natural gas and oil  properties  located in seventeen  counties in the states of
Oklahoma,  Texas, and New Mexico.  Such properties  contained proved reserves of
approximately 85.8 billion cubic feet of natural gas equivalent.  The base sales
price  of $76  million  (before  the  settlement  of the  net  overproduced  gas
balancing  status of the properties for $2.0 million and customary  post-closing
adjustments)  was comprised of  approximately  85% cash and 15% in the Company's
11.5% Senior Notes due 2008 valued at par. At December 31, 2001,  $6,375,000  of
cash and  $1,125,000 of the Company's  Senior Notes were being held in an escrow
account pending  determination  of any post-closing  adjustments.  Subsequent to
December 31, 2001, Carmen identified potential post-closing  adjustments related
to title  defects as well as other issues  related to certain  remaining  unpaid
obligations of the Company,  on the sold  properties.  Management of the Company
believes that all material  title and  environmental  defects will be cured such
that no material adjustments will be made to the escrow amounts. The Company has
accrued  liabilities  recorded at December  31, 2001 for the unpaid  obligations
identified by Carmen.  Management  expects to receive the escrow  amounts during
April 2002. The sale of these properties, which represented approximately 66% of
the Company's proved reserves,  significantly  altered the relationship  between
capital costs and proved reserves. As a result, the Company recognized a gain of
approximately  $17.3 million,  net of transaction  costs of  approximately  $1.1
million,  on the sale under full cost  accounting.  At the time of the  closing,
Carmen  Acquisition Corp. was the owner of 49.5% of the outstanding common stock
of the Company.  Immediately following the closing,  Carmen Acquisition sold all
of its stock in the Company directly to the Company's remaining stockholders and
their affiliates.

As allowed by the provisions of the indenture  under which the Company's  Senior
Notes were issued,  the Company utilized $28.8 million of the proceeds to pay in
full the amounts  outstanding  under the credit  facility with Foothill  Capital
Corporation (see Note 6). The indenture requires that the remaining net proceeds
of $16.4  million,  net of  estimated  tax effects of the  transaction  of $16.2
million before  consideration  of tax attributes  unrelated to the sale, be used
within  365  days  either  for  additional  capital   expenditures  or  for  the
acquisition  of natural  gas and oil  assets.  To the  extent  that the net cash
proceeds  that are not applied for such  expenditures  by the end of the 365-day
period,  such  amounts are defined as excess  cash under the  indenture.  In the
event that such  excess  cash  exceeds $10  million,  the  Company  must make an
irrevocable and unconditional offer to the holders of the Company's Senior Notes
to purchase  the maximum  amount of the Senior  Notes which could be acquired by
the  application  of the excess  cash at a purchase  price  equal to 100% of the
principal  amount  of  the  Senior  Notes.   Based  on  the  Company's   capital
expenditures  budget for 2002, the excess cash balance at the end of the 365-day
period is  expected to be below $10  million  such that no Senior  Notes will be
required to be purchased.

4.   Volumetric Production Payment

On  September  28,  1999,  the Company  entered  into a  nonrecourse  volumetric
production   payment  agreement  (the  Production   Payment)  with  Duke  Energy
Corporation  (Duke),  pursuant to which the  Company was  required to deliver to
Duke 2.8  billion  cubic  feet of  natural  gas  produced  from  certain  of the
Company's  properties over a five-year  period.  Such volumes have been excluded
from the  Company's  proved  reserves at December  31, 1999 and 2000.  Effective
December  1, 2001,  the  Company's  remaining  obligation  under the  Production
Payment was assigned to Carmen  Acquisition  Corp. in  connection  with the sale
discussed in Note 3.

5.   Related Party Transactions

Since its formation, the Company acted as manager of RVC and owned the operating
rights of RVC's natural gas and oil  properties.  The Company  received  monthly
management  fees of  $50,000  and  overhead  reimbursements  from  RVC  from its
inception through March 2000 at which time RVC had divested substantially all of
its assets.  During 1999 and 2000, the Company  received  $600,000 and $150,000,
respectively, in management fees as well as $309,000 and $43,000,  respectively,
in overhead  reimbursements  from RVC.  Management  fees are  reflected in other
income  while  overhead  reimbursements  have been  netted  against  general and
administrative   expenses  in  the  accompanying   consolidated   statements  of
operations.  In February 2000, the Company sold the operating  rights of certain
RVC natural gas and oil  properties  resulting in cash proceeds of $1.7 million.
Such proceeds have been recorded as a reduction in the carrying value of natural
gas and oil properties.

6.   Long-Term Debt

Long-term debt at December 31 consists of the following:
<TABLE>
<CAPTION>
                                                        2000       2001
                                                        ----       ----
                                                       (In Thousands)

<S>                                                  <C>        <C>
11-1/2% Senior Notes Due 2008, net of discount (A)   $101,887   $ 91,036
Credit facility (B)                                    25,367          -
Installment loan agreements                               326        364
                                                     --------   --------
                                                      127,580     91,400
Less amount due within one year                           154        135
                                                     --------   --------
                                                     $127,426   $ 92,165
                                                     ========   ========
</TABLE>


(A)  In February 1998,  the Company  completed the sale of $115 million of 11.5%
     Senior Notes Due 2008 in a public  offering of which $92.0  million  remain
     outstanding  at December  31, 2001.  The Senior Notes are senior  unsecured
     obligations  of the Company and are redeemable at the option of the Company
     in whole or in part,  at any time on or after  February 15, 2005, at prices
     ranging from 111.50% to 103.84% of face amount to their scheduled  maturity
     in 2008.

     The  indenture  under which the Senior  Notes are issued  contains  certain
     covenants,  including  covenants  that limit (i)  incurrences of additional
     indebtedness and issuances of disqualified  capital stock,  (ii) restricted
     payments,  (iii) dividends and other payments affecting subsidiaries,  (iv)
     transactions with affiliates and outside  directors' fees, (v) asset sales,
     (vi) liens, (vii) lines of business,  (viii) merger,  sale or consolidation
     and (ix) non-refundable acquisition deposits.

     In August 2000, the Company recognized an extraordinary after-tax gain (net
     of  unamortized  deferred  offering and original  issue  discount costs and
     income  taxes) of $916,000 or $.34 per share as a result of the purchase of
     an  additional  $5.0  million face amount of the Senior  Notes.  The Senior
     Notes were  purchased  at 66% of face amount and have been  canceled by the
     Company.  The  Company  utilized  borrowings  under  its  revolving  credit
     agreement to purchase the Senior Notes.

     In December 2001, the Company  recognized an  extraordinary  after-tax loss
     (net of unamortized deferred offering and original issue discount costs) of
     $247,000  or $.09 per  share as a result  of the  retirement  of the  $11.0
     million of Senior Notes received from Chesapeake  Energy  Corporation  (see
     Note 3).

     At December 31, 2000 and 2001, the  unamortized  issue discount  associated
     with the Notes totaled $1,073,000 and $825,795, respectively.

(B)  In  connection  with the sale of natural gas and oil  properties  to Carmen
     Acquisition  Corp.  (see  Note  3),  the  Company  repaid  the  outstanding
     borrowings  under its credit  facility  with Foothill  Capital  Corporation
     (Foothill)  and  terminated  the  agreement.  As  a  result  of  the  early
     termination of the credit  facility,  the Company was required to pay a fee
     of $785,000 to Foothill.  Such amount,  combined with the unamortized  loan
     origination fees and net of income taxes, resulted in an extraordinary loss
     of $851,000 or $.31 per share.

Subsequent  to year-end,  the Company  purchased a $1.5 million  certificate  of
deposit with BancFirst  which serves as collateral for a three-year $1.5 million
standby letter of credit issued to Carmen  Acquisition Corp., as required by the
provisions of the sales agreement (see Note 3).

The  amount  of  required  principal  payments  for  the  next  five  years  and
thereafter,   as  of  December   31,  2001,   are  as  follows:   2002-$135,000;
2003-$229,000; 2004-$-; 2005-$-; 2006-$-; thereafter-$92.0 million.

Interest  paid in the years ended  December  31,  1999,  2000,  and 2001 totaled
$14,701,000, $13,946,000 and $12,545,000, respectively.

7.   Subsidiary Guarantors

The Company's Senior Notes are fully and unconditionally guaranteed, jointly and
severally,  on a senior  unsecured  basis,  by all of the Company's  current and
future subsidiaries (the Subsidiary Guarantors).  The following table sets forth
condensed consolidating financial information of the Subsidiary Guarantors after
their  acquisition or formation in 1998.  There are currently no restrictions on
the ability of the Subsidiary Guarantors to transfer funds to the Company in the
form of cash dividends, loans or advances.

The following  represents  the condensed  consolidating  balance  sheets for the
Company and its subsidiaries for the years ended December 31, 2000 and 2001:

<TABLE>
<CAPTION>
                                                                                                            Total
                                                                                Subsidiary  Consolidating Consolidated
                                                                     Parent     Guarantors   Adjustments   Amounts
                                                                     ------     ----------   -----------   -------
<S>                                                                <C>          <C>          <C>          <C>
December 31, 2000
Current assets                                                     $   8,080    $   6,279    $  (5,424)   $   8,935
Property and equipment, net                                           56,443       62,466            -      118,909
Investment in subsidiary                                              40,972            -      (40,972)           -
Other assets                                                           4,576          416            -        4,992
                                                                   ---------    ---------    ---------    ---------
Total assets                                                       $ 110,071    $  69,161    $ (46,396)   $ 132,836
                                                                   =========    =========    =========    =========

Current liabilities                                                $  14,393    $   7,632    $  (5,424)   $  16,601
Long-term debt                                                       127,426            -            -      127,426
Other non-current liabilities                                          4,139            -            -        4,139
Deferred income taxes                                                (11,789)      20,557            -        8,768
                                                                   ---------    ---------    ---------    ---------
Total liabilities                                                    134,169       28,189       (5,424)     156,934

Stockholders' equity (deficiency)                                    (24,098)      40,972      (40,972)     (24,098)
                                                                   ---------    ---------    ---------    ---------
Total liabilities and stockholders' equity (deficiency)            $ 110,071    $  69,161    $ (46,396)   $ 132,836
                                                                   =========    =========    =========    =========

December 31, 2001
Current assets                                                     $  27,381    $  16,455    $ (13,750)   $  30,086
Property and equipment, net                                            9,691       55,787            -       65,478
Investment in subsidiary                                              46,412            -      (46,412)           -
Other assets                                                           2,422          336            -        2,758
                                                                   ---------    ---------    ---------    ---------
Total assets                                                       $  85,096    $  72,578    $ (60,162)   $  98,322
                                                                   =========    =========    =========    =========

Current liabilities                                                $  23,389    $   3,977    $ (13,750)   $  13,616
Long-term debt                                                        91,222           43            -       91,265
Other non-current liabilities                                          2,794            -            -        2,794
Deferred income taxes                                                (11,152)      22,146            -       10,994
                                                                   ---------    ---------    ---------    ---------
Total liabilities                                                    106,253       26,166      (13,750)     118,669

Stockholders' equity (deficiency)                                    (20,347)      46,412      (46,412)     (20,347)
                                                                   ---------    ---------    ---------    ---------
Total liabilities and stockholders' equity (deficiency)
                                                                   $  85,096    $  72,578    $ (60,162)   $  98,322
                                                                   =========    =========    =========    =========
</TABLE>


The following  represents the condensed  consolidating  statements of operations
and statements of cash flows for the Company and its  subsidiaries for the years
ended December 31, 1999, 2000, and 2001:

<TABLE>
<CAPTION>
                                                                                                      Total
                                                                          Subsidiary Consolidating Consolidated
                                                                Parent    Guarantors  Adjustments    Amounts
                                                                ------    ----------  -----------    -------
<S>                                                            <C>         <C>         <C>         <C>
Year ended December 31, 1999
Operating revenues                                             $ 18,694    $ 14,416    $      -    $ 33,110
Operating expenses                                               18,257      13,972           -      32,229
                                                               --------    --------    --------    --------
Operating income                                                    437         444           -         881
Other income (expense)                                          (15,317)         43        (487)    (15,761)
                                                               --------    --------    --------    --------
Income (loss) before income taxes                               (14,880)        487        (487)    (14,880)
Income taxes                                                     (5,650)          -           -      (5,650)
                                                               --------    --------    --------    --------
Net Income (loss)                                              $ (9,230)   $    487    $   (487)   $ (9,230)
                                                               ========    ========    ========    ========

Cash flows provided by (used in) operating activities          $ (9,788)   $  3,820    $      -    $ (5,968)
Cash flows provided by (used in) investing activities               816      (3,085)          -      (2,269)
Cash flows provided by (used in) financing activities             3,473      (1,964)          -       1,509
                                                               --------    --------    --------    --------
Increase (decrease) in cash and cash equivalents                 (5,499)     (1,229)          -      (6,728)
Cash and cash equivalents at beginning of year                    7,347       1,256           -       8,603
                                                               --------    --------    --------    --------
Cash and cash equivalents at end of year                       $  1,848    $     27    $      -    $  1,875
                                                               ========    ========    ========    ========
</TABLE>

<TABLE>
<CAPTION>
                                                                                                      Total
                                                                          Subsidiary Consolidating Consolidated
                                                                Parent    Guarantors  Adjustments    Amounts
                                                                ------    ----------  -----------    -------
<S>                                                            <C>         <C>         <C>         <C>

Year ended December 31, 2000
Operating revenues                                             $ 19,786    $ 20,249    $      -    $ 40,035
Operating expenses                                               16,562      16,710           -      33,272
                                                               --------    --------    --------    --------
Operating income                                                  3,224       3,539           -       6,763
Other income (expense)                                          (11,768)         65      (3,604)    (15,307)
                                                               --------    --------    --------    --------
Income (loss) before income taxes and extraordinary item         (8,544)      3,604      (3,604)     (8,544)
Income taxes                                                     (3,200)          -           -      (3,200)
                                                               --------    --------    --------    --------
Income (loss) before extraordinary item                          (5,344)      3,604      (3,604)     (5,344)
Extraordinary item, net                                             916           -           -         916
                                                               --------    --------    --------    --------
Net income (loss)                                              $ (4,428)   $  3,604    $ (3,604)   $ (4,428)
                                                               ========    ========    ========    ========

Cash flows provided by (used in) operating activities          $ (4,225)   $ 10,173    $      -    $  5,948
Cash flows provided by (used in) investing activities            (3,109)     (1,736)          -      (4,845)
Cash flows provided by (used in) financing activities             5,855      (7,916)          -      (2,061)
                                                               --------    --------    --------    --------
Increase (decrease) in cash and cash equivalents                 (1,479)        521           -        (958)
Cash and cash equivalents at beginning of year                    1,848          27           -       1,875
                                                               --------    --------    --------    --------
Cash and cash equivalents at end of year
                                                               $    369    $    548    $      -    $    917
                                                               ========    ========    ========    ========
</TABLE>

<TABLE>
<CAPTION>
                                                                                                      Total
                                                                          Subsidiary Consolidating Consolidated
                                                                Parent    Guarantors  Adjustments    Amounts
                                                                ------    ----------  -----------    -------
<S>                                                            <C>         <C>         <C>         <C>
Year ended December 31, 2001
Operating revenues                                             $ 23,098    $ 23,558    $ (5,440)   $ 41,216
Operating expenses                                               18,210      18,167           -      36,377
                                                               --------    --------    --------    --------
Operating income                                                  4,888       5,391      (5,440)      4,839
Other income (expense)                                            2,861          49           -       2,910
                                                               --------    --------    --------    --------
Income (loss) before income taxes and extraordinary item          7,749       5,440      (5,440)      7,749
Income taxes                                                      2,900           -           -       2,900
                                                               --------    --------    --------    --------
Income (loss) before extraordinary item                           4,849       5,440      (5,440)      4,849
Extraordinary gain (loss), net                                   (1,098)          -           -      (1,098)
                                                               --------    --------    --------    --------
Net income (loss)                                              $  3,751    $  5,440    $ (5,440)    $ 3,751
                                                               ========    ========    ========    ========

Cash flows provided by (used in) operating activities          $  1,055    $  1,185    $      -     $ 2,240
Cash flows provided by (used in) investing activities            26,768      17,752           -      44,520
Cash flows provided by (used in) financing activities           (21,362)     (6,441)          -     (27,803)
                                                               --------    --------    --------    --------
Increase (decrease) in cash and cash equivalents                  6,461      12,496           -      18,957
Cash and cash equivalents at beginning of year                      369         548           -         917
                                                               --------    --------    --------    --------
Cash and cash equivalents at end of year                       $  6,830    $ 13,044    $      -    $ 19,874
                                                               ========    ========    ========    ========
</TABLE>


The  Company has not  allocated  any  portion of its  long-term  debt or related
accounts,  including accrued interest payable,  unamortized debt issue costs and
unamortized issue discount to its subsidiaries. In addition, the Company has not
allocated general and administrative expenses,  interest charges or income taxes
to its subsidiaries.  Accordingly, the above condensed consolidating information
is not intended to present the Company's subsidiaries on a stand-alone basis.

8.   Operating Leases

The Company leases office space under a noncancelable  operating lease agreement
that  expires on December  31,  2006.  Future  minimum  lease  payments for this
operating lease at December 31, 2001, are as follows:

                       2002           $   157,000
                       2003               160,000
                       2004               163,000
                       2005               166,000
                       2006               168,000
                                      -----------
                                      $   814,000
                                      ===========

Rent expense of $449,000,  $324,000  and $254,000 was incurred  under  operating
leases in the years ended December 31, 1999, 2000, and 2001, respectively.

9.   Defined Contribution Plan

The  Company  sponsors a 401(k)  defined  contribution  plan for the  benefit of
substantially all employees. The plan allows eligible employees to contribute up
to 17.5% of their annual compensation,  not to exceed  approximately  $10,500 in
2001.   Employer   contributions   to  the  plan  are   discretionary.   Company
contributions  to the plan in 1999,  2000,  and 2001  were  none,  $80,000,  and
$341,000, respectively.

10.  Capital Stock

Common Stock

Pursuant to a Special Retainer Agreement effective July 1, 1998, as amended, the
Board of  Directors  granted an outside  counsel  an option to  purchase  50,000
shares of the Company's common stock.  Pursuant to the terms of the Stock Option
Agreement, 16,666 shares vested on August 1, 1998, 1999, and 2000, respectively,
or become fully vested upon  occurrence  of certain  specified  events,  and are
exercisable  through June 30, 2008. On March 5, 1999, the Board of Directors set
the exercise price at $7.33, an amount which  management  believes  approximates
the per common  share  value of the Company at the grant date and  December  31,
1998 and 1999 and August 1, 2000. Consequently,  no compensation expense related
to the grant has been recognized in the statements of operations.

Additionally,  the Board of Directors approved the 1998 Stock Incentive Plan and
reserved  550,000 shares of Common Stock which may be granted under the plan. No
grants have been made at December 31, 2001.

Preferred Stock

The Company has an authorized  class of Preferred Stock  consisting of 5,000,000
shares,  none of which are issued and  outstanding.  The Board of  Directors  is
authorized,  subject  to any  limitations  prescribed  by law,  without  further
stockholder  approval, to issue shares of Preferred Stock from time to time. The
Board of Directors  may designate  one or more series of Preferred  Stock.  Each
such series of Preferred  Stock shall have such number of shares,  designations,
preferences,  voting powers,  qualifications  and special or relative  rights or
privileges as shall be determined by the Board of Directors,  which may include,
among  others,  dividend  rights,  voting  rights,  redemption  and sinking fund
provisions, liquidation preferences and conversion rights.

11.  Income Taxes

Deferred  income  taxes of the Company  reflect the net tax effects of temporary
differences between the carrying amounts of assets and liabilities for financial
reporting  purposes  and the amounts used for income tax  purposes.  Significant
components of the Company's  deferred tax assets and  liabilities as of December
31 are as follows:

<TABLE>
<CAPTION>
                                                                 2000                  2001
                                                            --------------        -------------
                                                                      (In Thousands)
<S>                                                         <C>                   <C>
Deferred Tax Assets
Financial charges which are deferred for tax purposes       $         333         $         326
Minimum and investment tax credit carryforwards                       122                   122
Net operating loss carryforwards                                   16,397                 1,357
                                                            -------------         -------------
   Deferred tax assets                                             16,852                 1,805

Deferred Tax Liabilities
Intangible drilling costs capitalized for financial
  purposes and expensed for tax purposes
                                                                    7,053                 2,362
Financial bases in excess of tax bases primarily on
  properties and equipment                                         18,567                10,437
                                                            -------------         -------------
      Deferred tax liabilities                                     25,620                12,799
                                                            -------------         -------------
Net deferred income tax liabilities                         $       8,768         $      10,994
                                                            =============         =============
</TABLE>


The  reconciliation  of income taxes computed at the U.S. Federal  statutory tax
rates to the Company's  income tax benefit based on loss before income taxes and
extraordinary item for the years ended December 31 is as follows:

<TABLE>
<CAPTION>
                                           1999               2000             2001
                                        ---------          ---------        ---------
                                                          (In Thousands)
<S>                                     <C>                <C>              <C>
Income tax benefit at statutory rate    $ (5,194)          $ (2,990)        $  2,712
State income taxes                          (445)              (256)             232
Other                                        (11)                46              (44)
                                        --------------------------------------------
Income tax benefit--deferred            $ (5,650)          $ (3,200)        $  2,900
                                        ============================================
</TABLE>

At December  31, 2001,  the Company has federal  income tax net  operating  loss
carryforwards of approximately $3.5 million which begin expiring in 2006.

12.  Contract Termination and Severance Payments

In 2000,  the Company  closed its Oklahoma City  accounting  and Midland,  Texas
operations offices and outsourced its accounting  function as well as elected to
terminate its Special Severance  Agreement with the Chairman of the Board and to
execute a new  Employment  Contract  with him. A total charge of  $1,221,000  is
reflected in the consolidated statement of operations, consisting of $230,000 in
severance payments to affected employees, $107,000 related to the termination of
certain  operating lease contracts and $884,000 in connection with the severance
agreement termination.

In December 2001,  following the sale of certain  natural gas and oil properties
to Carmen Acquisition Corp. (see Note 3), the Company reduced its work force and
elected to terminate  employment  contracts with certain senior  officers of the
Company.  A total charge of  approximately  $1,104,000 has been reflected in the
consolidated  statements  of  operations.  Such  charge  consists of $374,000 in
severance  payments made to affected  employees during 2001 and $730,000 related
to the  termination of the employment  contracts with the senior  officers.  The
amounts  owed to the  senior  offices  were  included  accrued  compensation  at
December 31, 2001 and were paid in 2002.

13.  Commitments and Contingencies

In 1996, the Company's  predecessor sold an natural gas and oil property located
in Louisiana state waters in Plaquemines  Parish.  The property included several
uneconomical  wells for which the Company estimated the plugging and abandonment
(P&A) obligation to be approximately $1,020,000. The purchaser provided a letter
of credit and a bond totaling $420,000 to ensure funding of a portion of the P&A
obligation.  The P&A  obligation  would  revert to the  Company in the event the
purchaser  does not  complete  the  required  P&A  activities.  As a result,  in
connection  with  the  sale the  Company  recorded  a  contingent  liability  of
$600,000, which is included in the accompanying consolidated balance sheets.

The Company has  established a severance  agreement for the President and CEO of
the Company.  This  agreement  provides for  severance  benefits to be paid upon
involuntary  separation  as a result  of  actions  taken by the  Company  or its
successors.  At December 31, 2001,  the severance  benefits under this agreement
were  approximately  $1.0 million.  A provision for these  benefits would not be
made unless an involuntary termination was probable.

Pursuant to a Special Retainer Agreement effective July 1, 1998, as amended, the
Company is obligated  to pay an outside  counsel  approximately  $308,700 in the
event that the  agreement is  terminated  by reason of  expiration  of term,  by
counsel for good  reason,  by reason of change in control,  or by the Company at
will. A provision  for the payment would not be made unless  termination  of the
agreement was probable.

The Company is currently  involved in litigation with the  Commissioners  of the
Land Office (CLO) over alleged  improper  royalty  payments made to the State on
gas  purchased by the  Company's  pipeline  system.  The Company  purchased  the
pipeline  system from  Carlton  Resources  Corporation  (Carlton)  in 1998.  The
alleged improper payments occurred  primarily prior to the time that the Company
owned the pipeline system.  The amount of damages claimed by the CLO is believed
to  approximate  $600,000.  The  Company  has  denied  all  of  the  substantive
allegations  made by the CLO and plans to  vigorously  defend the case.  No loss
accrual has been reflected in the financial  statements at December 31, 2001, as
management  does not  believe  that a loss is  probable.  In the event  that the
Company is  unsuccessful  in  defending  the  allegations  made by the CLO,  the
Company  believes  that the former  stockholders  of Carlton and a former  joint
venture partner of Carlton are contractually  obligated to indemnify the Company
for all material  amounts  assessed  against the Company,  including  legal fees
incurred.

The Company is also involved in legal proceedings and litigation in the ordinary
course of business.  In the opinion of  management,  the outcome of such matters
will not have a material adverse effect on the Company's  financial  position or
results of operations.

14.  Hedging Strategy

During 1999, 2000, and 2001, the Company utilized a cash flow hedging program to
reduce its  exposure  to  unfavorable  changes in  natural  gas prices  that are
subject to significant and often volatile  fluctuation.  Under this program, the
Company hedges  portions of its  forecasted  natural gas production by utilizing
fixed-price  natural gas swap contracts.  Under the swap contracts,  the Company
receives a fixed  price for  natural  gas and pays a floating  price  (generally
NYMEX  futures  prices) to a  counterparty.  When market  prices for natural gas
decline,  the  decline  in the  value  of the  cash  flows  from  the  Company's
forecasted  natural gas production  designated as being hedged is  substantially
offset by gains in the value of the fixed price swap contracts. Conversely, when
market  prices  increase,  the  increase in the value of the cash flows from the
Company's  forecasted  natural  gas  production  designated  as being  hedged is
substantially offset by losses in the value of the fixed price swap contracts.

As of December  31,  2001,  the Company had no  contracts  in place to hedge the
price received for its future  forecasted  natural gas production,  however such
contracts may be utilized in the future.

15.  Natural Gas and Oil Producing Activities

Capitalized  costs  relating to natural  gas and oil  producing  activities  and
related accumulated  depreciation and amortization at December 31 are summarized
as follows:

<TABLE>
<CAPTION>
                                                2000                  2001
                                             ---------             ---------
                                                      (In Thousands)
<S>                                          <C>                   <C>
Proved natural gas and oil properties        $ 124,026             $  49,449
Accumulated depreciation and amortization      (40,118)              (17,269)
                                             ---------             ---------
                                             $  83,908             $  32,180
                                             =========             =========
</TABLE>

Costs  incurred in natural gas and oil producing  activities for the years ended
December 31 are as follows:

<TABLE>
<CAPTION>
                                            1999       2000        2001
                                         --------    --------    --------
                                          (In Thousands, Except Per Mcfe)
<S>                                      <C>         <C>         <C>
Acquisition of proved properties         $     -     $     -     $     -
Development costs                        $ 3,625     $ 4,464     $ 8,844
Exploration costs                        $   860     $ 2,421     $ 2,200
Amortization rate per equivalent Mcf     $   .92     $   .82     $   .88
</TABLE>

16.  Supplementary Natural Gas and Oil Reserve Information (Unaudited)

The Company has interests in natural gas and oil properties that are principally
located in Oklahoma,  Texas,  and New Mexico.  The Company does not own or lease
any natural gas and oil properties outside the United States.

The Company retains independent  engineering firms to provide year-end estimates
of the  Company's  future net  recoverable  natural  gas,  oil,  and natural gas
liquids  reserves.  Estimated  proved net  recoverable  reserves  as shown below
include  only  those   quantities  that  can  be  expected  to  be  commercially
recoverable  at prices  and costs in effect at the  balance  sheet  dates  under
existing  regulatory  practices  and with  conventional  equipment and operating
methods.

Proved developed reserves represent only those reserves expected to be recovered
through  existing  wells.  Proved  undeveloped  reserves  include those reserves
expected to be recovered  from new wells on undrilled  acreage or from  existing
wells on which a relatively major expenditure is required for recompletion.

Net quantities of proved developed and undeveloped reserves of natural gas and
oil, including condensate and natural gas liquids, are summarized as follows:

<TABLE>
<CAPTION>

                                          Natural Gas           Crude Oil
                                     (Million Cubic Feet)   (Thousand Barrels)
                                    ---------------------   ------------------

<S>                                       <C>                  <C>
December 31, 1998                         109,894               3,653

Extensions and discoveries                  4,942                 318
Sales of reserves in place                 (4,481)               (226)
Purchases of reserves in place                  -                   -
Revisions of previous estimates              (308)                224
Production                                 (8,283)               (362)
                                       -----------------    -----------------
December 31, 1999                         101,764               3,607

Extensions and discoveries                  9,751                 124
Sales of reserves in place                   (781)                (74)
Purchases of reserves in place                  -                   -
Revisions of previous estimates            13,216                 529
Production                                 (6,661)               (295)
                                       -----------------    -----------------
December 31, 2000                         117,289               3,891

Extensions and discoveries                 10,265                 218
Sales of reserves in place                (77,511)             (1,375)
Purchases of reserves in place                  -                   -
Revisions of previous estimates            (8,738)               (571)
Production                                 (5,817)               (261)
                                       -----------------    -----------------
December 31, 2001                          35,488               1,902
                                       =================    =================

Proved developed reserves:
   December 31, 1998                       77,035               2,760
   December 31, 1999                       68,134               2,901
   December 31, 2000                       83,018               3,158
   December 31, 2001                       22,088               1,556

</TABLE>

The  following is a summary of a  standardized  measure of  discounted  net cash
flows related to the Company's  proved  natural gas and oil reserves.  For these
calculations,  estimated future cash flows from estimated  future  production of
proved  reserves were computed using natural gas and oil prices as of the end of
the period presented.  Future  development and production costs  attributable to
the proved  reserves were  estimated  assuming that  existing  conditions  would
continue  over the economic  lives of the  individual  leases and costs were not
escalated for the future.  Estimated  future income tax expenses were calculated
by applying  future  statutory  tax rates (based on the current tax law adjusted
for permanent  differences  and tax credits) to the estimated  future pretax net
cash flows related to proved natural gas and oil reserves, less the tax basis of
the properties involved.

The Company  cautions against using this data to determine the fair value of its
natural gas and oil properties. To obtain the best estimate of fair value of the
natural gas and oil properties, forecasts of future economic conditions, varying
discount rates, and consideration of other than proved reserves would have to be
incorporated   into  the  calculation.   In  addition,   there  are  significant
uncertainties  inherent  in  estimating  quantities  of proved  reserves  and in
projecting rates of production that impair the usefulness of the data.

The standardized  measure of discounted future net cash flows relating to proved
natural gas and oil reserves at December 31 are summarized as follows:

<TABLE>
<CAPTION>
                                                  1999           2000           2001
                                              ----------    -----------     ----------
                                                           (In Thousands)
<S>                                           <C>            <C>            <C>
Future cash inflows                           $  293,097     $1,165,721     $  134,145
Future production and development costs         (113,272)      (225,655)       (51,767)
Future income tax expenses                       (26,450)      (331,920)       (19,239)
                                              ----------     ----------     ----------
Future net cash flows                            153,375        608,146         63,139

10% annual discount for estimated timing
  of cash flows                                  (74,387)      (302,701)       (30,119)
                                              ----------     ----------     ----------
Standardized measure of discounted future
  net cash flows                              $   78,988     $  305,445     $   33,020
                                              ==========     ==========     ==========
</TABLE>

The following are the principal sources of change in the standardized measure of
discounted  future net cash flows of the  Company for each of the three years in
the period ended December 31, 2001:

<TABLE>
<CAPTION>
                                                     1999            2000            2001
                                                   --------      ----------      ----------
                                                                   (In Thousands)
<S>                                                <C>           <C>             <C>
Discounted future net cash flows at beginning
   of year                                         $ 73,691      $   78,988      $  305,445

Changes during the year:
   Sales and transfers of natural gas and oil
     produced, net of production costs              (15,292)        (18,005)        (16,734)
   Net changes in prices and production costs        23,037         299,158        (390,453)
   Extensions and discoveries, less related costs     7,181          41,147           4,961
   Development costs incurred and revisions           2,717           2,174             568
   Sales of reserves in place                        (6,366)           (916)        (64,419)
   Purchases of reserves in place                         -               -               -
   Revisions of previous quantity estimates          (7,535)         55,822          (5,216)
   Net change in income taxes                        (2,705)       (151,488)        157,640
   Accretion of discount                              8,462           9,261          47,055
   Other                                             (4,202)        (10,696)         (5,827)
                                                   --------      ----------       ---------
   Net change                                         5,297         226,457        (272,425)
                                                   --------      ----------       ---------
Discounted future net cash flows at end of year    $ 78,988      $  305,445       $  33,020
                                                   ========      ==========       =========
</TABLE>

Prices used in computing these  calculations of future cash flows from estimated
future production of proved reserves were $22.76,  $23.75, and $19.78 per barrel
of oil at December 31, 1999, 2000, and 2001, respectively, and $2.07, $9.98, and
$2.72 per thousand  cubic feet of natural gas at December 31,  1999,  2000,  and
2001, respectively. Such prices do not include the effect of the Company's fixed
price contracts designated as hedges.

<PAGE>
                                   SIGNATURES

Pursuant to the requirements of Section 13 and 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.

March 29, 2002                         RAM ENERGY, INC.

                                       By LARRY E. LEE
                                          Larry E. Lee
                                          President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following  persons on behalf of the  registrant and
in capacities and on the dates indicated.

<TABLE>
<CAPTION>
Signatures                      Title                           Date
-------------------------       ------------------------------  ------------
<S>                             <C>                             <C>
WILLIAM W. TALLEY, II, PH.D.
William W. Talley, II, Ph.D.    Chairman of the Board           March 29, 2002

LARRY E. LEE
Larry E. Lee                    President and Chief Executive   March 29, 2002
                                Officer (principal executive
                                officer)

JOHN M. LONGMIRE
John M. Longmire                Senior Vice President and       March 29, 2002
                                Chief Financial Officer
                                (principal financial officer
                                and principal accounting
                                officer), Treasurer and
                                Secretary

GERALD R. MARSHALL
Gerald R. Marshall              Director                        March 29, 2002

JOHN M. REARDON
John M. Reardon                 Director                        March 29, 2002
</TABLE>


Supplemental  Information to be Furnished With Reports Pursuant to Section 15(d)
of the Act by  Registrants  Which have Not  Registered  Securities  Pursuant  to
Section 12 of the Act.

The  Company  has not sent,  and does not  intend to send,  an annual  report to
security holders covering its last fiscal year, nor has the Company sent a proxy
statement,  form of proxy or other proxy  soliciting  material  to its  security
holders with respect to any annual meeting of security holders.

<PAGE>
                                  EXHIBIT INDEX

Exhibit
No.         Description of Exhibit              Method of Filing
-------     ----------------------              --------------------------------
3.1         Company's Amended and               Incorporated herein by reference
            Restated Certificate of
            Incorporation

3.2         Company's Amended and               Incorporated herein by reference
            Restated Bylaws

4.1         Indenture dated as of               Incorporated herein by reference
            February 24, 1998 among
            the Company, as issuer,
            RB Operating Company and
            RLP Gulf States, L.L.C., as
            Subsidiary Guarantors, and
            United States Trust Company
            of New York, as trustee

4.2         Form of 11-1/2% Senior              Incorporated herein by reference
            Notes due 2008

4.3         Supplemental Indenture              Incorporated herein by reference
            entered into February 24,
            1998 by the Registrant, the
            Subsidiary Guarantors, the
            Additional Guarantors and
            United States Trust Company
            of New York, as Trustee

10.4        RAM Energy 1998 Stock               Incorporated herein by reference
            Incentive Plan

10.5        Special Severance Agreement         Incorporated herein by reference
            by and between William W.
            Talley II and the Company
            dated as of December 1, 1997

10.6        Employment Agreement by and         Incorporated herein by reference
            between Larry E. Lee and
            the Company dated as of
            December 1, 1997

10.8        Form of the Company's               Incorporated herein by reference
            Indemnity Agreement

10.15       Amended and Restated Loan           Incorporated herein by reference
            and Security Agreement by
            and between the Company, as
            Borrower, the Financial
            Institutions named therein
            and Foothill Capital
            Corporation, as Agent,
            dated December 27, 1999

10.16       Employment and Severance            Incorporated herein by reference
            Agreement by and between
            John M. Longmire and the
            Company dated December 13,
            1999

10.16.1     Employment and Severance            Incorporated herein by reference
            Agreement by and between
            Larry G. Rampey and the
            Company dated December 13,
            1999

10.16.2     Employment and Severance            Incorporated herein by reference
            Agreement by and between
            Drake N. Smiley and the
            Company dated December 13,
            1999

10.6.1      Amendment of Employment             Incorporated herein by reference
            Agreement by and between
            Larry E. Lee and the Company

10.17       Employment Agreement by and         Incorporated herein by reference
            between William W. Talley II
            and the Company dated
            January 1, 2001

10.18       Employment and Severance            Incorporated herein by reference
            Agreement by and between
            John M. Longmire and the
            Company dated December 1,
            2000

10.19       Employment and Severance            Incorporated herein by reference
            Agreement by and between
            Larry G. Rampey and the
            Company dated December 1,
            2000

10.20       Employment and Severance            Incorporated herein by reference
            Agreement by and between
            Drake N. Smiley and the
            Company dated December 1,
            2000

21          Subsidiaries of the Company         Filed herewith electronically