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, 1999

[ ]   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. N/A

           As  of March 26, 2000, there were 2,727,000 shares  of
the  registrant's  $.01 par value Common Stock outstanding.   The
Common Stock is privately held by affiliates of the registrant.

          Documents incorporated by reference:  None
                        RAM ENERGY, INC.
<PAGE>
                   Annual Report on Form 10-K
              for the Year Ended December 31, 1999

                       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 the 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. ("RAM Energy" and, together with its
subsidiaries, the "Company") is an independent oil and gas
company engaged in the acquisition, development, exploration and
production of oil and gas properties primarily in the Mid-
Continent Area and in the Permian Basin. At December 31, 1999,
the Company's estimated net proved reserves were 101.8 Bcf of
natural gas and 3.6 MMBbls of oil, or 123.4 Bcfe, with a PV-10
Value of approximately $93 million and a reserve life of
approximately 12 years. As of such date, the Company operated 535
wells, a 181-mile oil and gas gathering system and a saltwater
disposal operation. The Company's interests in the wells it
operates represented approximately 69% of its PV-10 Value at
December 31, 1999. The Company has grown principally through
producing property acquisitions, acquiring approximately $242
million of oil and gas properties since inception, including its
acquisition of Carlton Resources, Inc. (the "Carlton
Acquisition") which was consummated on February 24, 1998 and the
Ricks Acquisition described under "Recent Events."

From 1989 to November 1996, the Company primarily developed and
operated oil and gas properties owned jointly by RAM Energy and
an institutional limited partnership (the "Partnership"). During
that eight-year period, the Company drilled 225 oil and gas wells
with a 95% success rate, which is not necessarily indicative of
its future drilling success rate. The Partnership distributed a
substantial portion of the net cash flows from these properties
to its partners and the Company did not invest significantly in
its asset base.

In November 1996, RAM Energy acquired the limited partner's
interest in the Partnership and subsequently liquidated the
Partnership and distributed all of its oil and gas properties and
other assets to RAM Energy (the "Partnership Acquisition"). The
Company then adopted its current strategy of aggressively
managing its existing properties and seeking acquisitions and
exploration opportunities to grow its revenues, production and
cash flow. From December 1, 1996 to December 31, 1999, the
Company drilled 94 oil and gas wells, all but six of which were
successfully completed. The Company does not have information
with respect to Carlton's drilling success rates. As a result of
increasing emphasis on exploration, drilling results may differ
from the Company's historical drilling success rate. The Company
has identified approximately 179 development and exploitation
opportunities on its properties. These opportunities are located
primarily in intermediate depth, normally pressured reservoirs
and generally involve moderate drilling and completion costs.

Forward-Looking Statements

The description of the Company's plans set forth herein,
including planned capital expenditures and acquisitions, are
forward-looking statements made pursuant to the safe harbor
provisions of the Private Securities Litigation Reform Act of
1995.  These plans involve a number or risks and uncertainties.
Important factors that could cause actual capital expenditures,
acquisitions activity or the Company's performance to differ
materially from the plans include, without limitation, prices
received for its oil and gas production, the Company's ability to
satisfy the financial covenants of its outstanding debt and to
raise additional capital; the Company's ability to manage its
growth successfully and to compete effectively in its oil and gas
business against competitors with greater financial, technical,
marketing and other resources; and adverse regulatory changes.
Readers are cautioned not to place undue reliance on these
forward-looking statements which speak only as of the date
hereof.  The Company undertakes no obligation to update or revise
these forward-looking statements to reflect events or
circumstances after the date hereof including, without
limitation, changes in the Company's business strategy or planned
capital expenditures, or to reflect the occurrence of
unanticipated events.

Strategy

The Company's primary goal is to increase reserves, production
and operating cash flow through the acquisition, development and
exploration of oil and gas properties. Key elements of the
Company's growth strategy include the following:

Expand Core Areas.  Approximately 87% of the Company's PV-10
Value as of December 31, 1999, is in the Mid-Continent Area and
the Permian Basin, and, in these areas, the Company operates a
high percentage of the wells in which it owns interests. The
Company believes that its geographic concentration and operating
control within these core areas provide it with focused,
efficient operations. The Company plans to continue to pursue
acquisitions and exploration opportunities within its core areas
but will evaluate opportunities elsewhere that could result in
the establishment of new core areas.

Complete Selective Oil and Gas Acquisitions.  The Company seeks
to acquire producing oil and gas properties that provide
opportunities for reserve additions and increased cash flow
through operating improvements, production enhancement and
additional development and exploratory drilling. The Company
believes these criteria are met in regions that are characterized
by long histories of production and multiple producing oil and
gas horizons, such as the Mid-Continent Area and the Permian
Basin. As part of its growth strategy, the Company intends to
evaluate acquisitions in other regions where it can add producing
properties, undeveloped acreage and personnel to establish
concentrated operations and economies of scale.

Develop and Exploit Existing Oil and Gas Properties.  The Company
has identified approximately 179 infill drilling, recompletion,
enhanced recovery and workover opportunities on its properties,
and plans to pursue these relatively lower-risk development
activities, as well as selective exploration activities.

Continue Emphasis on Exploration Prospect Development.  In its
efforts to build an exploration prospect inventory, the Company
continues its acquisition of 2-D and 3-D seismic data on approved
prospect lead areas located primarily in the Mid-Continent and
Permian Basin Areas.  Where practicable, the Company utilizes its
2-D data sets to high-grade its prospect lead areas and then,
utilizing 3-D seismic, confirms the continuity of the Prospect
for subsequent drilling.  The Company currently employs three
exploration geologists, one exploration landman and has project
specific consulting relationships with two geophysicists.  In
addition, the Company actively seeks and evaluates exploration
opportunities in the major exploration basins of the onshore U.S.

Recent Events

The Carlton Acquisition.  On February 24, 1998, the Company
acquired Carlton Resources, Inc. ("Carlton") for $41.6 million
(after certain purchase price adjustments), and on April 17,
1998, Carlton was merged into the Company. With the Carlton
Acquisition, the Company acquired interests in 360 (348 at
December 31, 1999) producing oil and gas wells, primarily
located in the Carmen Field in the Mid-Continent Area and
other fields in the Mid-Continent Area, the Permian Basin
and other oil and gas producing regions. At December 31, 1999
the Company operated 185 of these wells. The Carlton Acquisition
added approximately 27.1 Bcfe of estimated net proved reserves
to the Company's reserve base, as of December 31, 1999 (net of 2.1
and 1.8 Bcfe of production for the years 1998 and 1999, respectively,
since the date of acquisition. The properties acquired in the
Carlton Acquisition include an attractive combination of
established, long-life production, development and exploratory
drilling opportunities, with over 50 identified projects, and
have an estimated reserve life of approximately 13 years.

As part of the Carlton Acquisition, the Company acquired, and
currently owns and operates, the Carmen System, a [181-mile] oil
and gas gathering system and a saltwater disposal operation in
the Carmen Field of the Mid-Continent Area. The Carmen System
purchases, transports and markets oil and gas production and
disposes of produced water from properties owned by the Company
and other oil and gas companies. The Company operates 133 of the
205 producing oil and gas wells currently dedicated to the Carmen
System. Since the Carlton Acquisition, the Company has connected
seven additional wells (five of which were drilled by the
Company) to the Carmen System.

The Carmen System purchases oil and gas at the lease and
transports the production, with associated saltwater, to a
collection and separation facility operated by the Company. From
this point, the natural gas is delivered to a processing and
compression facility operated by Continental Gas, Inc. After
processing, gas volumes are returned to the Company and sold into
a variety of delivery points. Oil purchasing and gathering,
saltwater gathering 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 the Company's
saltwater disposal well.

Notes Offering.  On February 24, 1998, RAM Energy completed an
offering of $115.0 million of 11-1/2% Senior Notes due 2008 (the
"Notes"), and received net proceeds of $108.3 million.  During
the fourth quarter of 1998 the Company purchased $7.04 million
face amount of the Notes, which were subsequently cancelled.  The
Indenture relating to the Notes contains certain covenants,
including, but not limited to, covenants that limit:

o    incurrence of additional indebtedness and issuances of
     disqualified capital stock,

o    restricted payments,

o    dividends and other payments affecting subsidiaries,

o    transactions with affiliates and outside directors fees,

o    asset sales,

o    liens,

o    lines of business,

o    merger, sale or consolidation, and

o    non-refundable acquisition deposits.

The Indenture also contains covenants regarding the designation
of Unrestricted Subsidiaries (as defined in the Indenture),
ownership of Subsidiary Guarantors (as defined in the Indenture)
and issuance of reports.  See "Description of Indebtedness -
Notes."

Ricks Acquisition.  On August 17, 1998, the Company completed a
$6.5 million acquisition of a one-half interest in certain proved
undeveloped oil and gas properties of Ricks Exploration, Inc.
("Ricks") located in south Texas (the "Ricks Acquisition").

Concurrent with the Ricks Acquisition, the Company completed a
$2.0 million investment in RVC Energy, Inc. ("RVC") in exchange
for 49.5% of RVC's voting common stock and certain shares of
RVC's non-voting common stock. RVC is an unrestricted affiliate
of the Company.

Concurrent with the Ricks Acquisition, RVC acquired all of Rick's
interest in the proved developed producing oil and gas properties
in the same field and the remaining one-half interest in the
proved undeveloped properties for $14.6 million.  On August 31,
1998, RVC acquired all of the outstanding common stock of Comet
Petroleum, Inc. ("Comet") for $27.8 million cash.  RVC funded
both acquisitions with equity contributed by its stockholders and
borrowings under its credit facility which are non-recourse to
its stockholders, including the Company.

The Company was designated as the operator of all oil and gas
properties acquired from Ricks and a majority of the Comet
properties formerly operated by Comet and its affiliates; the
Company receives overhead reimbursements and a management fee
from RVC and Comet.

During 1999 RVC's cash flows were insufficient to cover its debt
service costs and its lender declared its credit facility in
default and requested that RVC's properties be sold in satisfaction
of its indebtedness.  Accordingly, RAM reduced its remaining
investment in RVC to $0 as of December 31, 1999.

Production Payment. On September 28, 1999 the Company entered
into a volumetric production payment agreement with a unit of
Duke Energy Corporation ("Duke"), pursuant to which the Company
will deliver to Duke 2.8 Bcf of natural gas produced from certain
of the Company's properties over a 5-year period.  Consideration
received by the Company was $5.0 million.

Exploration Program. The Company continues to emphasize the
development of its exploration program as a means of finding and
developing new reserve additions.  Consistent with this strategy,
the Company has recently completed its acquisition and
interpretation of 3-D seismic data covering interests in 2
exploration prospects and intends to drill or participate in the
drilling of a well on each such prospect later this year.  The
first of these prospects was the result of a Company-operated 35
mile 3-D seismic acquisition program in northwestern Oklahoma.
The Company will own 50% of this prospect and operate the drilling
of all wells drilled by the participant group. The second prospect
is located in south Texas and the Company will own a 7.5% non-operated
working interest in this prospect.

Net Production, Unit Prices and Costs

The following table presents certain information with respect to
oil and gas production, prices and costs attributable to all oil
and gas properties owned by the Partnership and the Company for
the periods shown:

<TABLE>
<CAPTION>
                                         Year Ended December 31,
                                         -----------------------
                                         1997      1998     1999
                                         ----      ----     ----
<S>                                     <C>      <C>      <C>
  Operating Data:
    Production volumes:
      Natural gas (MMcf)                 6,686    8,795    8,283
      Oil and condensate (MBbls)           467      520      362
      Total (MMcfe)                      9,487   11,916   10,456
    Average realized prices(1):
      Natural gas (per Mcf)              $2.36    $2.24    $2.08
      Oil and condensate (per Bbl)       17.08    11.81    16.13
      Per Mcfe                            2.50     2.17     2.21
    Expenses (per Mcfe):
      Lease operating (including
       production taxes)                  0.71     0.72     0.75
      Depreciation and amortization       0.92     1.15     1.24
      General and administrative          0.47     0.30     0.42
______________
</TABLE>

 (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."

Producing Wells

The following table sets forth the number of productive wells in
which the Company owned an interest as of December 31, 1999:

                                        Gross         Net
                                        -----         ---
              Natural gas                 873         207
              Oil                       1,181         240
                                        -----         ---
                Total                   2,054         447
                                        =====         ===

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.

Acreage

The following table sets forth the Company's developed and
undeveloped gross and net leasehold acreage as of December 31,
1999:

<TABLE>
<CAPTION>
                                  Gross                 Net
                                  -----                 ---
              <S>                <C>                  <C>
              Developed          233,739              81,233
              Undeveloped         39,298               8,772
                                 -------              ------
                Total            273,037              90,005
                                 =======              ======
</TABLE>

Approximately 81% of the Company's net acreage was located in the
Mid-Continent Area and Permian Basin as of December 31, 1999.
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 oil and gas, 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, the Company drilled the following
wells.

<TABLE>
<CAPTION>
                            1997              1998               1999
                            ----              ----               ----
                       Gross     Net     Gross      Net     Gross      Net
                       -----     ---     -----      ---     -----      ---
<S>                    <C>       <C>     <C>       <C>      <C>        <C>
Development wells:
  Productive              29     5.6        53     16.1        19      2.4
  Non-productive                             4      1.5
                          --     ---        --     ----        --      ---
    Total                 29     5.6        57     17.6        19      2.4
                          ==     ===        ==     ====        ==      ===
</TABLE>

Oil and Gas Marketing and Hedging

The Company's oil and gas production is sold primarily under
market sensitive or spot price contracts. Until the third quarter
of 1998 the Company sold substantially all of its casinghead gas
to purchasers under varying percentage-of-proceeds contracts. By
the terms of these contracts, the Company received a fixed
percentage of the resale price received by the purchaser for
sales of natural gas and natural gas liquids recovered after
gathering and processing the Company's gas. The Company received
between 84% and 100% of the proceeds from natural gas sales and
from 40% to 100% of the proceeds from natural gas liquids sales
received by the purchasers of the Company's production when the
products were resold. The natural gas and natural gas liquids
were sold primarily based on spot market prices. The revenues
received by the Company from the sale of natural gas liquids are
included in crude oil sales. During 1998, the Company converted
some of these percentage of proceeds contracts to "keep whole"
contracts wherein the Btu content of the natural gas liquids is
added to the natural gas proceeds.  During the year ended
December 31, 1999, two purchasers accounted for approximately
52% of the Company's crude oil and natural gas sales and one
customer accounted for approximately 80% of gathering system
revenue.  The Company believes that there are numerous other
companies available to purchase the Company's crude oil and
natural gas and that the loss of any or all of these purchasers
would not materially affect the Company's ability to sell crude
oil and natural gas.

Periodically the Company utilizes various hedging strategies to
manage the price received for a portion of its future oil and gas
production. The Company does not establish hedges in excess of
its 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 the Company
pays the hedging partner and below which the Company is paid by
the hedging partner. These contracts allow the Company to predict
with greater certainty the effective oil and gas prices to be
received for its production and benefit the Company when market
prices are less than the fixed prices under its hedging
contracts. However, the Company will not benefit from market
prices that are higher than the fixed prices in such contracts
for its hedged production. At December 31, 1999, the Company had
hedging contracts in place covering 15,100 MMbtu per day
(approximately 55% of its estimated gas production for 2000) for
January through October 2000 at an average price of $2.42 per
Mmbtu.  For the year ended December 31, 1999 the Company's
hedging strategies reduced realized gas prices by $0.044 per Mcf.
See "Management's Discussion and Analysis of Financial Condition
and Results of Operations General."

The Company has only limited involvement with derivative
financial instruments, as defined in SFAS No. 119 "Disclosure
About Derivative Financial Instruments and Fair Value of
Financial Instruments" and does not use them for trading
purposes. The Company's objective is to hedge a portion of its
exposure to price volatility from producing oil and gas. These
arrangements expose the Company to credit risk of its
counterparties and to basis risk.

Employees

As of December 31, 1999, the Company had 70 employees, 25 of whom
were administrative, accounting or financial personnel and 45 of
whom were technical and operations personnel. The Company's
future success will depend partially on its ability to attract,
retain and motivate qualified personnel. The Company is not a
party to any collective bargaining agreements and has not
experienced any strikes or work stoppages. The Company considers
its relations with its employees to be satisfactory.

Competition

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

Item 2   Properties

Principal Oil and Gas Properties and Oil and Gas Reserves

The Company's oil and gas properties located in the Mid-Continent
Area and the Permian Basin comprised approximately 59% and 28%,
respectively, of the Company's PV-10 Value as of December 31,
1999. These regions are large, well established oil and gas
producing basins with activities dating from the early 1900s and
are characterized by numerous known producing horizons ranging
from shallow oil and gas production to deep gas reservoirs. The
Company owns interests in numerous properties which provide
opportunities to increase reserves and production through
additional development, recompletions, enhanced recovery methods
and the use of 3-D seismic technology. The Company's interests in
the wells it operates represented approximately 69% of its PV-10
Value at December 31, 1999.  Substantially all of the Company's
oil and gas properties are mortgaged to secure the Company's
obligations under an Amended and Restated Loan and Security
Agreement dated as of December 27, 1999, among RAM Energy, Inc.,
as Borrower, the Lenders (as described therein) and Foothill
Capital Corporation as Agent for the Lenders.

The following table provides information for the Company's major
fields as of December 31, 1999.

     Net Proved Reserves for Principal Oil and Gas Properties

<TABLE>
<CAPTION>
                                                       Gas       % of Total
                                  Oil       Gas     Equivalent      PV-10
    Area                        (MBbl)     (MMcf)     (MMcfe)       Value
    ----                        ------     ------     -------       -----
<S>                             <C>       <C>        <C>           <C>
    Mid-Continent                1,679     66,433     76,509        59.0
    Permian Basin                1,649     22,262     32,154        27.5
    Gulf Coast                     104     12,174     12,799        11.0
    Other                          175        895      1,939         2.5
                                 -----    -------    -------       -----
      Total net proved reserves  3,607    101,764    123,401       100.0
                                 =====    =======    =======       =====
</TABLE>

Mid-Continent Area.  In the Mid-Continent Area, the Company owns
interests in 1,363 wells and operates 440 of those wells.  During
1999 the Company participated in the successful drilling and
completion of 9 wells.  The wells drilled in 1999 were all
natural gas wells, primarily production from the Red Fork, Prue,
Skinner and Mississippi formations, ranging in depth from 6,000
to 13,000 feet.  Future development plans include the drilling of
82 additional infill locations and 19 recompletions.

Permian Area.  In the Permian Area, the Company owns interests in
597 wells and operates 91 of those wells.  During 1999, the Company
drilled and completed a 9,200 foot Strawn gas well in Val Verde
County, Texas. Future development plans in this area include the
drilling of 18 additional infill wells and 1 recompletion.

Gulf Coast Area.  In the Gulf Coast Area, the Company owns
interests in 59 wells and operates 40 of those wells.  Principal
Company activity in this area focused upon a field located in
Acadia Parish, Louisiana, where the Company completed the
reprocessing of 3-D seismic data and successfully conducted
recompletion operations in existing wells.  Subsequent engineering
study in this area has resulted in the identification of 18
additional recompletion candidates for future exploitation
ranging in depth from 9,000 to 11,000 feet.

Oil and Gas Reserves

The following table summarizes the estimates of the Company's
historical net proved reserves and the related present values of
such reserves at the dates shown. The reserve and present value
data for the Company's oil and gas properties as of December 31,
1997, 1998 and 1999 were prepared by Garb Grubbs Harris &
Associates (formerly Forrest A. Garb & Associates, Inc. ("Garb &
Associates").

<TABLE>
<CAPTION>
                                                 December 31,
                                        --------------------------------
                                        1997         1998           1999
                                        ----         ----           ----
<S>
Reserve Data:                         <C>          <C>            <C>
   Proved developed reserves:
     Natural gas (MMcf)                 56,516      77,035         68,134
     Oil and condensate (MBbls)          2,436       2,760          2,901
     Total (MMcfe)                      71,132      93,595         85,541
   PV-10 Value (in thousands) (1)      $80,208     $71,021        $76,100
   Proved reserves:
     Natural gas (MMcf)                 81,912     109,894        101,764
     Oil and condensate (MBbls)          3,367       3,653          3,606
     Total (MMcfe)                     102,114     131,812        123,401
   PV-10 Value (in thousands) (1)     $104,560     $84,615        $92,611

   $/Mcf                                 $2.81       $2.12          $2.07
   $/Bbl                                 16.17        8.95          22.76
_______________
</TABLE>

(1)       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 including the effects
          of hedging activities. In accordance with applicable
          requirements of the Securities and Exchange Commission
          (the "Commission"), estimates of the Company's proved
          reserves and future net revenues are made using oil and
          gas sales prices estimated to be in effect as of the
          date of such reserve estimates and are held constant
          throughout the life of the properties (except to the
          extent a contract specifically provides for
          escalation). The prices used in calculating PV-10 Value
          as of December 31, 1999 were $2.07 per Mcf of natural
          gas and $22.76 per Bbl of oil, compared to prices used
          as of December 31, 1998 of $2.12 per Mcf of natural gas
          and $8.95 per Bbl of oil.

Estimated quantities of proved reserves and future net revenues
therefrom are affected by oil and gas prices, which have
fluctuated widely in recent years. There are numerous
uncertainties inherent in estimating oil and gas 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 oil and gas 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
the Company, may vary. In addition, estimates of reserves are
subject to revisions based upon actual production, results of
future development and exploration activities, prevailing oil and
gas prices, operating costs and other factors, which revisions
may be material. The PV-10 Value of the Company's proved oil and
gas reserves does not necessarily represent the current or fair
market value of such proved reserves, and the 10% discount factor
required by the Commission may not reflect current interest
rates, the Company's cost of capital or any risks associated with
the development and production of the Company's proved oil and
gas reserves.

In general, the volume of production from oil and gas properties
declines as reserves are depleted. Except to the extent the
Company acquires properties containing proved reserves or
conducts successful exploitation and development activities, the
proved reserves of the Company will decline as reserves are
produced. The Company's future oil and gas production is,
therefore, highly dependent upon its level of success in finding
or acquiring additional reserves.

Title to Properties

The Company believes it has satisfactory title to its properties
in accordance with standards generally accepted in the oil and
gas industry. As is customary in the oil and gas industry, the
Company makes only a cursory review of title to farmout acreage
and to undeveloped oil and gas 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, the Company,
rather than the seller of the undeveloped property, is typically
responsible to cure any such title defects at its expense. If the
Company were unable to remedy or cure any title defect of a
nature such that it would not be prudent to commence drilling
operations on the property, the Company could suffer a loss of
its entire investment in the property. The Company has obtained
title opinions on substantially all of its producing properties.
Prior to completing an acquisition of producing oil and gas
leases, the Company performs a title review on a material portion
of the leases. The Company's oil and gas properties are subject
to customary royalty interests, liens for current taxes and other
burdens that the Company believes do not materially interfere
with the use of or affect the value of such properties.

Facilities

The Company's principal executive and operating offices are
located at Suite 650, Meridian Tower, 5100 E. Skelly Drive,
Tulsa, Oklahoma 74135. The Company's finance and accounting
offices, along with the office of the Chairman, are located at
Suite 130, One Benham Place, 9400 N. Broadway Extension, Oklahoma
City, Oklahoma 73114. The Company leases all of its significant
facilities. The Company believes that its facilities are adequate
for its current needs.

Regulation

General.  Various aspects of the Company's oil and gas 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. 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 (the "NGA") and
the Natural Gas Policy Act of 1978 (the "NGPA"). 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. Deregulation of wellhead
sales in the natural gas industry began with the enactment of the
NGPA in 1978. In 1989, Congress enacted the Natural Gas Wellhead
Decontrol Act (the "Decontrol Act"). The Decontrol Act removed
all remaining NGA and NGPA price and nonprice controls affecting
wellhead sales of natural gas effective January 1, 1993.

Regulation of Sales and Transportation of Natural Gas.  The
Company's 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.
In recent years, the FERC has undertaken various initiatives to
increase competition within the natural gas industry. As a result
of initiatives like FERC Order No. 636, issued in April 1992, the
interstate natural gas transportation and marketing system has
been substantially restructured to remove various barriers and
practices that historically limited non-pipeline natural gas
sellers, including producers, from effectively competing with
interstate pipelines for sales to local distribution companies
and large industrial and commercial customers. The most
significant provisions of Order No. 636 require that interstate
pipelines provide firm and interruptible transportation service
on an open access basis that is equal for all natural gas
suppliers. In many instances, the results of Order No. 636 and
related initiatives have been to substantially reduce or
eliminate the interstate pipelines' traditional role as
wholesalers of natural gas in favor of providing only storage and
transportation services. While the United States Court of Appeals
has upheld most of Order No. 636, certain related FERC orders,
including the individual pipeline restructuring proceedings, are
still subject to judicial review and may be reversed or remanded
in whole or in part. While the outcome of these proceedings
cannot be predicted with certainty, the Company does not believe
that it will be affected materially differently than its
competitors.

The FERC has also announced several important transportation-
related policy statements and proposed rule changes, including a
statement of policy and a request for comments concerning
alternatives to its traditional cost-of-service ratemaking
methodology to establish the rates interstate pipelines may
charge for their services. A number of pipelines have obtained
FERC authorization to charge negotiated rates as one such
alternative. Both the policy statement and individual pipeline
negotiated rate authorizations are currently subject to appeal
before the U.S. Court of Appeals for the D.C. Circuit. In
February 1997, the FERC announced a broad inquiry into issues
facing the natural gas industry to assist the FERC in
establishing regulatory goals and priorities in the post-Order
No. 636 environment. Moreover, the FERC has refined the criteria
used to distinguish non-jurisdictional gathering from
jurisdictional transportation. 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 the Company only
indirectly, they are intended to further enhance competition in
natural gas markets. The Company cannot predict what further
action the FERC or state regulators will take on these matters,
however, the Company does not believe that it will be affected by
any action taken materially differently than 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.  Sales of crude oil,
condensate and gas liquids by the Company are not currently
regulated and are made at market prices. The price the Company
receives from the sale of these products may be affected by the
cost of transporting the products to market.

Environmental.  Extensive federal, state and local laws
regulating the discharge of materials into the environment or
otherwise relating to the protection of the environment affect
the Company's oil and gas operations. Numerous governmental
departments issue rules and regulations to implement and enforce
such laws, which are often difficult and costly to comply with
and which carry substantial civil and even criminal penalties for
failure to comply. Some laws, rules and regulations relating to
protection of the environment may, in certain circumstances,
impose strict liability for environmental contamination,
rendering a person or entity liable for environmental damages and
cleanup costs without regard to negligence or fault on the part
of such person or entity. Other laws, rules and regulations may
restrict the rate of oil and gas production below the rate that
would otherwise exist or even prohibit exploration and production
activities in sensitive areas. In addition, state laws often
require various forms of remedial action to prevent pollution,
such as closure of inactive pits and plugging of abandoned wells.
The regulatory burden on the oil and gas industry increases the
Company's cost of doing business and consequently affects the
Company's profitability. The Company believes that it is in
substantial compliance with current applicable environmental laws
and regulations and that continued compliance with existing
requirements will not have a material adverse impact on the
Company's operations. However, environmental laws and regulations
have been subject to frequent changes over the years, and the
imposition of more stringent requirements could have a material
adverse effect upon the capital expenditures or competitive
position of the Company.

The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA") imposes liability, without regard to
fault or the legality of the original act, on certain classes of
persons that are considered to be responsible for the release of
a "hazardous substance" into the environment. These persons
include the current or former owner or operator of the disposal
site or sites where the release occurred and companies that
disposed or arranged for the disposal of hazardous substances at
the disposal site. Under CERCLA such persons may be subject to
joint and several liability for the costs of investigating and
cleaning up hazardous substances that have been released into the
environment, for damages to natural resources and for the costs
of certain health studies. Comparable state statutes also impose
liability on the owner or operator of a property for remediation
of environmental contamination existing on such property. In
addition, companies that incur liability frequently confront
third party claims because it is not uncommon for neighboring
landowners and other third parties to file claims for personal
injury and property damage allegedly caused by hazardous
substances or other pollutants released into the environment from
a polluted site.

The Company currently owns or leases, and has in the past owned
or leased, numerous properties that have been used for the
exploration and production of oil and gas and for other uses
associated with the oil and gas industry. Although the Company
has followed operating and disposal practices that it considered
appropriate under applicable laws and regulations, hydrocarbons
or other wastes may have been disposed of or released on or under
the properties owned or leased by the Company or on or under
other locations where such wastes were taken for disposal. In
addition, the Company owns or leases properties that have been
operated by third parties in the past. The Company could incur
liability under CERCLA or comparable state statutes for
contamination caused by wastes it generated or for contamination
existing on properties it owns or leases, even if the
contamination was caused by the waste disposal practices of the
prior owners or operators of the properties.

The Federal Solid Waste Disposal Act, as amended by the Resource
Conservation and Recovery Act of 1976 ("RCRA"), regulates the
generation, transportation, storage, treatment and disposal of
hazardous wastes and can require cleanup of hazardous waste
disposal sites. RCRA currently excludes drilling fluids, produced
waters and other wastes associated with the exploration,
development or production of oil and gas from regulation as
"hazardous waste." A similar exemption is contained in many of
the state counterparts to RCRA. Disposal of such non-hazardous
oil and gas exploration, development and production wastes
usually is regulated by state law. Other wastes handled at
exploration and production sites or used in the course of
providing well services may not fall within this exclusion.
Moreover, stricter standards for waste handling and disposal may
be imposed on the oil and gas industry in the future. From time
to time legislation has been proposed in Congress that would
revoke or alter the current exclusion of exploration, development
and production wastes from the RCRA definition of "hazardous
wastes" thereby potentially subjecting such wastes to more
stringent handling and disposal requirements. If such legislation
were enacted, or if changes to applicable state regulations
required the wastes to be managed as hazardous wastes, it could
have a significant impact on the operating costs of the Company,
as well as the oil and gas industry in general.

The Company's operations are also subject to the Clean Air Act
(the "CAA") and comparable state and local requirements.
Amendments to the CAA were adopted in 1990 and contain provisions
that may result in the gradual imposition of certain pollution
control requirements with respect to air emissions from
operations of the Company. The Company may be required to incur
certain capital expenditures in the next several years for air
pollution control equipment in connection with obtaining and
maintaining operating permits and approvals for air emissions.
However, the Company believes its operations will not be
materially adversely affected by any such requirements, and the
requirements are not expected to be any more burdensome to the
Company than to other similarly situated companies involved in
oil and gas exploration and production activities or well
servicing activities.

The Federal Water Pollution Control Act of 1972 (the "FWPCA")
imposes restrictions and strict controls regarding the discharge
of wastes, including produced waters and other oil and gas
wastes, into navigable waters. These controls have become more
stringent over the years, and it is probable that additional
restrictions will be imposed in the future. Permits must be
obtained to discharge pollutants into state and federal waters.
The FWPCA provides for civil, criminal and administrative
penalties for unauthorized discharges of oil and other hazardous
substances and imposes substantial potential liability for the
costs of removal or remediation. State laws governing discharges
to water also provide varying civil, criminal and administrative
penalties and impose liabilities in the case of a discharge of
petroleum or its derivatives, or other hazardous substances, into
state waters. In addition, the Environmental Protection Agency
has promulgated regulations that require many oil and gas
production sites, as well as other facilities, to obtain permits
to discharge storm water runoff. The Company believes that
compliance with existing requirements under the FWPCA and
comparable state statutes will not have a material adverse effect
on the Company's financial condition or results of operations.

The Company maintains insurance against "sudden and accidental"
occurrences which may cover some, but not all, of the risks
described above. Most significantly, the insurance maintained by
the Company may not cover the risks described above which occur
over a sustained period of time. Further, there can be no
assurance that such insurance will continue to be available to
cover all such costs or that such insurance will be available at
premium levels that justify its purchase. The occurrence of a
significant event not fully insured or indemnified against could
have a material adverse effect on the Company's financial
condition and results of operations.

Regulation of Oil and Gas Exploration and Production.
Exploration and production operations of the Company 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 unitization 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
the Company's properties.

Item 3   Legal Proceedings

From time to time, the Company is party to litigation or other
legal proceedings that it considers to be a part of the ordinary
course of its business.  The Company is not involved in any legal
proceedings, nor is it a party to any pending or threatened
claims, that could reasonably be expected to have a material
adverse effect on its financial condition or results of
operations.

Item 4   Submission of Matters to a Vote of Security Holders

None.

                            PART II

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

There is no established trading market for the Company's Common
Stock.  As of March 26, 2000, there were four record holders of
the Company's Common Stock. The Company sold no equity securities
during the years ended December 31, 1998 and 1999 except that on
July 1, 1998 the Company 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 the Company's Common Stock at an
exercise price of $7.33 per share over a three year period.  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. The Company relied on the exemption
from registration provided by Regulation D.

Item 6    Selected Financial Data

The following table sets forth certain historical consolidated
financial data with respect to each of the five years ended
December 31, 1999 which have been derived from the Company's and
its Predecessor's 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.

Company Historical Financial Information
and Other Financial Data

<TABLE>
<CAPTION>
                                          Year Ended December 31,
                                -------------------------------------------
                                1995     1996      1997      1998      1999
                                 (in thousands except for ratios and per
                                         share and per unit data)
<S>                           <C>      <C>      <C>       <C>       <C>
Operating Statement Data:
Revenues:
  Oil and gas revenue           $166   $3,275   $23,737   $25,839   $23,085
  Gathering systems                -        -         -     6,123     9,198
  Management fees              1,606    1,482         -         -         -
  Operator overhead fees       1,686    1,343         -         -         -
  Consulting fees                163      153         -         -         -
  Other                           84      567        79       354       827
                              ------   ------   -------   -------   -------
    Total revenues             3,705    6,820    23,816    32,316    33,110
Expenses:
  Lease operating costs
   (including production taxes)   77      827     6,769     8,633     7,793
  Gathering System purchases       -        -         -     4,220     6,621
  Gathering systems                -        -         -       496       414
  Depreciation and amortization  353      990     8,692    13,713    12,964
  General and administrative   3,364    4,164     4,467     3,517     4,437
                              ------   ------   -------   -------   -------
    Total expenses             3,794    5,981    19,928    30,579    32,229
                              ------   ------   -------   -------   -------
  Operating income (loss)        (89)     839     3,888     1,737       881
  Other income (expense):
    Interest expense             (18)    (541)   (5,159)  (13,197)  (14,623)
    Interest income               73       29        83       356       169
    Equity in income of a
     partnership                   -       71         -         -         -
    Equity in loss of affiliate    -        -         -      (693)   (1,307)
    Minority interest in a
     partnership                 (23)      10         -         -         -
                              ------   ------   -------   -------   -------
  Income (loss) before income
   Taxes and extraordinary item  (57)     408    (1,188)  (11,797)  (14,880)
  Income tax benefit               -        -         -    (4,200)   (5,650)
                              ------   ------   -------   -------   -------
  Income (loss) before
   extraordinary item            (57)     408    (1,188)   (7,597)   (9,230)
  Extraordinary item               -        -         -     1,140         -
                              ------   ------   -------   -------   -------
  Net income (loss)             ($57)    $408   ($1,188)  ($6,457)  ($9,230)
                              ======   ======   =======   =======   =======
Per Share Amounts:
  Income(loss) before
   extraordinary item         ($0.02)   $0.15    ($0.44)   ($2.78)   ($3.38)
  Extraordinary item           $0.00    $0.00     $0.00     $0.42     $0.00
                              ------   ------   -------   -------   -------
Net income(loss)              ($0.02)   $0.15    ($0.44)   ($2.37)   ($3.38)
                              ======   ======   =======   =======   =======
Weighted average common
 shares outstanding (in
 thousands)                    2,727    2,727     2,727     2,727     2,727
                              ======   ======   =======   =======   =======
</TABLE>

<TABLE>
<CAPTION>
                                           Year Ended December 31,
                               --------------------------------------------
                               1995      1996      1997      1998      1999
                               ----      ----      ----      ----      ----
                                  (in thousands except for ratios and per
                                          share and per unit data)
<S>                          <C>      <C>        <C>      <C>       <C>
Balance Sheet Data:
------------------
  Cash and cash equivalents    $524    $1,607    $1,248    $8,603    $1,875
  Net property and equipment    995    54,738    50,574   134,274   122,687

  Total assets                6,485    71,410    69,727   156,451   135,797
  Long-term debt, including
   current portion               49    62,984    62,225   131,739   129,253
  Stockholders' deficit      (1,729)   (1,321)   (3,983)  (10,440)  (19,670)

Other Financial Data:
--------------------
  Cash flow from operating
   activities                 ($233)      $70    $8,722    $9,533   ($5,968)
  Cash flow from investing
   activities                    (8)  (59,071)   (8,202)  (66,607)   (2,269)
  Cash flow from financing
   activities                  (662)   60,084      (879)   64,429     1,509
  Capital expenditures          335       250    17,985    18,361     5,403
  Adjusted EBITDA (1)           314     1,939    12,663    15,806    14,014
  Interest coverage ratio (2) 17.44      3.58      2.45      1.20      0.96
</TABLE>

<TABLE>
Partnership Historical Financial
Information and Other Financial Data
<CAPTION>
                                                  11 Months
                                 Year Ended         Ended
                                December 31,     November 30,
                                   1995            1996(3)
                                ------------     ------------
                               (in thousands, except for ratios
                                      and per unit data)
<S>                              <C>               <C>
Income Statement Data:
---------------------
Operating revenues:
  Oil and gas                    $21,802           $23,456
  Other                              139                 7
                                 -------           -------
    Total operating revenues      21,941            23,463
Operating expenses:
  Oil and gas production           9,902             7,609
  Depreciation and amortization    9,808             5,114
  Management fees                  1,606             1,482
  Operator overhead fees           1,686             1,343
  General and administrative         502               378
                                 -------           -------
    Total operating expense       23,504            15,926
                                 -------           -------
  Operating income (loss)         (1,563)            7,537
  Other income (expense):
    Interest expense                (809)             (564)
    Interest income                   59               114
                                 -------           -------
  Net income (loss)              ($2,313)           $7,087
                                 =======           =======
</TABLE>

<TABLE>
<CAPTION>
                                                  11 Months
                                   Year Ended       Ended
                                  December 31,   November 30,
                                     1995          1996(3)
                                  ------------   ------------
                                (in thousands, except for ratios
                                        and per unit data)
<S>                               <C>            <C>
Balance Sheet Data:
------------------
  Cash and cash equivalents         $1,266          $1,102
  Net property and equipment        49,601          46,198
  Total assets                      57,208         115,611
  Long-term debt, including
   current portion                  10,000          62,800
  Total partners' equity            43,166          48,120

Other Financial Data:
--------------------
  Cash flow from operating
   activities                        7,478          10,837
  Cash flow from investing
   activities                       (5,273)         (1,621)
  Cash flow from financing
   activities                       (1,295)         (9,380)
  Capital expenditures               5,380           3,310
  Adjusted EBITDA(1)                 8,304          12,765
  Interest coverage ratio (2)        10.26           22.63
</TABLE>

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

(2)       Interest coverage ratio is calculated by dividing
          Adjusted EBITDA by interest expense.

(3)       RAM Energy acquired the limited partner's interest in
          the Partnership on November 30, 1996.Prior to December
          1996, RAM Energy conducted drilling and development
          activities on behalf of and as the managing general
          partner of a partnership, and the data presented below
          was not meaningful for the Company.  In November 1996,
          RAM Energy acquired the limited partner's interest in
          the partnership.  In February 1998, the Company
          acquired Carlton Resources Corporation.  These
          transactions affect the comparability of the historical
          operating data for the periods and is not necessarily
          indicative of the Company's future performance.

<TABLE>
<CAPTION>
                                Partnership             RAM Energy
                            ------------------- ----------------------------
                              Year    11 Months
                              Ended     Ended
                            December  November     Year Ended December 31,
                               31,        30,   ----------------------------
Operating Data                1995       1996   1996    1997    1998    1999
                              ----       ----   ----    ----    ----    ----
<S>                         <C>         <C>    <C>     <C>    <C>     <C>
Production volumes(2):
  Natural gas (MMcf)         8,747      6,714    632   6,686   8,795   8,283
  Oil and condensate (MBbls)   621        533     53     467     520     362
  Total (MMcfe)             12,476      9,914    941   9,486  11,916  10,456
Average realized prices(2):
  Natural gas (MMcf)         $1.44      $2.04  $3.42   $2.36   $2.24   $2.08
  Oil and condensate (MBbls) 14.81      18.25  21.58   17.08   11.81   16.13
  Total (Mmcfs)               1.75       2.37   3.48    2.50    2.17    2.21
Expense (per Mcfe):
  Lease operating (including
   production (taxes)         0.79       0.77   0.88    0.71    0.72    0.75
  Depreciation and
   amortization               0.79       0.52   1.05    0.92    1.15    1.24
  General and
   administrative(3)          0.30       0.32   1.26    0.47    0.30    0.42
</TABLE>

(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."

(2)       Reflects changes in reporting of natural gas liquids as
          oil rather than natural gas as reported previously.

(3)       For the Partnership, includes management fees and
          operator overhead fees charged to the Partnership by
          RAM Energy during 1994, 1995 and the 1996 periods.

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

General

The Company is an independent oil and gas company engaged in the
acquisition, development and production of oil and gas properties
primarily in the Mid-Continent Area and the Permian Basin.  The
Company also operates gathering and disposal systems in Oklahoma.

From 1989 to November 1996, the Company primarily developed and
operated oil and gas properties owned jointly by RAM Energy and
the Partnership.  In November 1996 RAM Energy acquired the
limited partner's interest in the Partnership and subsequently
liquidated the Partnership and  distributed all of its oil and
gas properties and other assets to RAM Energy.

In late February 1998, the Company consummated the Carlton
Acquisition, in an acquisition of stock accounted for as a
purchase, for approximately $41.6 million after certain
adjustments. With the acquisition of Carlton, the Company
acquired estimated net proved reserves of approximately 31 Bcfe
located in the Mid-Continent Area and Permian Basin, as well as
an oil and gas gathering system and salt water disposal facility
located in Oklahoma (the "Carmen System").  The results of
operations discussed below include the operations acquired as
part of the Carlton Acquisition since March 1, 1998.

The Carmen System transports gas in one transportation line and
liquids in the form of salt water and oil in a separate
transportation line.  Fees are based on various contracts at both
fixed prices per unit of volume, and percentage of sales proceeds
for gas.  The system serves both the Company and third parties,
but reported revenues are those derived from third parties only.

The Carlton Acquisition was financed by the public issuance of
$115.0 million in Senior Notes due 2008 (the "Notes Offering").
Net proceeds of the Notes Offering were used to purchase Carlton,
to repay existing debt, and for working capital.

On August 17, 1998, the Company completed the Ricks Acquisition
for $6.5 million.  The Company acquired 14.2 Bcfe of proved
undeveloped reserves and undeveloped leasehold in this
transaction.

Concurrent with the Ricks Acquisition, RAM invested $2.0 million
in RVC, in exchange for 49.5% of RVC's voting common stock and
certain shares of non-voting common stock.  RVC is an
unrestricted affiliate of RAM and is accounted for under the
equity method.

Concurrent with the Ricks Acquisition, RVC acquired the remaining
one-half interest in the proved undeveloped properties of Ricks
and all of Ricks' interest in the proved developed producing oil
and gas properties in the same field for $14.6 million cash.  On
August 31, 1998, RVC acquired all of the outstanding common stock
of Comet for $27.8 million in cash.  RVC funded both acquisitions
with equity contributed by its stockholders and borrowings under
its credit facility which are non-recourse to its stockholders,
including the Company.

During 1999 RVC's cash flows were insufficient to cover its debt
service costs and its lender declared its credit facility in
default and requested that RVC's properties be sold in satisfaction
of its indebtedness.  Accordingly, RAM reduced its remaining
investment in RVC to $0 at December 31, 1999.

The Company's revenue, profitability and cash flow are
substantially dependent upon prevailing prices for oil and gas
and the volumes of oil and gas it produces.  In addition, the
Company's proved reserves and oil and gas production will decline
as oil and gas are produced unless the Company is successful in
acquiring producing properties or conducts successful exploration
and development drilling activities.

At December 31, 1999, the Company had hedging contracts in place
covering 15,100 MMbtu per day (approximately 55% of its estimated
gas production for 2000) for January through October 2000 at an
average price of $2.42 per Mmbtu. For the year ended December 31,
1999 the Company's hedging strategies reduced realized gas prices
by $0.044 per Mcf. For the year ended December 31, 1998 the
Company's hedging strategies added $0.28 per Mcf to gas prices
realized.

Historically, the Company has added reserves primarily through
acquisitions and development.  In 1997 the Company incurred $17.6
million in acquisition and development costs.  In 1998 the
Company expended $18.0 million for development projects and
certain exploration activities, exclusive of acquisitions.  Also
during 1998, the Company expended $41.6 million for the Carlton
Acquisition, $6.5 million for the Ricks Acquisition and invested
$2.0 million in RVC. The Company made no acquisitions during 1999
and expended $4.5 million for development projects and certain
exploration activities.  The Company intends to continue to
pursue attractive oil and gas acquisitions, and development and
exploration opportunities.

The Company uses the full cost method of accounting for its
investment in oil and gas properties.  Under the full cost method
of accounting, all costs of acquisition, exploration and
development of oil and gas reserves are capitalized into a "full
cost pool" as incurred, and properties 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 oil and gas prices that are not offset by other
factors could result in a write-down for impairment of the
carrying value of oil and gas properties.  Once incurred, a write-
down of oil and gas properties is not reversible at a later date,
even if oil or gas prices increase.

Results of Operations

Year Ended December 31, 1999 Compared to Year Ended December 31, 1998

Operating Revenues.  Operating revenues increased by $0.8
million, or 3% for the year ended December 31, 1999 compared to
the same period in 1998. The following table summarizes oil and
gas production volumes, average sales prices and period to period
comparisons, including the effect on oil and gas operating
revenues, for the periods indicated:

<TABLE>
<CAPTION>
                                                     Year ended
                                                1999 Compared to 1998
                           December 31,    --------------------------------
                           ------------    % Increase   Operating Revenue
                           1998    1999    (Decrease)   Increase (decrease)
                           ----    ----    ----------   -------------------
                                                       (Dollars in thousands)
<S>                      <C>      <C>       <C>               <C>
Production volumes:
  Natural gas (Mmcf)      8,795    8,283     ( 5.8)%            (1,146)
  Oil (Mbbls)               520      362     (30.4)%            (1,865)
Average sale prices:
  Natural gas (per Mcf)   $2.24    $2.08     ( 7.1)%            (1,309)
  Oil (per Bbl)          $11.81   $16.13      36.6 %             1,563
</TABLE>

Oil and gas revenues were lower during 1999 compared to 1998 as a
result of a 12% decrease in production partially offset by a 2%
increase in realized prices, both on an Mcfe basis. Most of the
decrease in production was due to property sales during the
second quarter of 1999.  Average daily production was 28.6 MMcfe
in 1999 compared to 32.6 MMcfe for 1998.  Natural gas production
decreased by 6% and oil production decreased by 30% for the
comparable periods.  The average realized sales price for natural
gas was $2.08 per Mcf for 1999, compared to $2.24 per Mcf for
1998.  The average realized oil price for 1999 was $16.13 per
Bbl, compared to $11.81 per Bbl for 1998, a 37% increase.

Oil and Gas Production Expense.  Oil and gas production expense
decreased by $0.8 million, or 10%, for the year ended December
31, 1999, compared to the same period in 1998.   The decrease in
expense was due primarily to the property sales during the second
quarter of 1999. The oil and gas production expense was $.75 per
Mcfe for 1999, an increase from $.72 per Mcfe compared to 1998,
or a 4% increase on an Mcfe basis.

Gathering System.  The Carmen System is obligated to deliver
10,000 MMbtu's per day at the tail-gate of the system, and
purchases outside gas to satisfy that obligation. Revenue from
this source was $9.2 million for 1999.  During 1999, outside
purchases were $6.6 million and system operating costs were $0.4
million.

Depreciation and Amortization ("D&A") Expense.   Depreciation and
amortization expense decreased by $0.7 million, or 5% for 1999
compared to 1998, and was $1.24 per Mcfe for 1999, an increase of
$0.09, or 8% compared to the $1.15 per Mcfe for 1998. For oil and
gas D&A only, the results were $.92 per Mcfe for 1999 compared
with $.93 per Mcfe for 1998.

G & A Expense.  General and administrative expense increased $.9
million, or 26%, in 1999 compared with $3.5 million in 1998.  The
increase is due primarily to costs associated with managing RVC,
for which the Company was reimbursed $0.6 million in management
fees during 1999.

Interest Expense.  Interest expense increased $1.4 million to
$14.6 million for 1999 compared to $13.2 million for 1998.  This
increase was attributable to higher average outstanding
indebtedness and higher effective interest rates during 1999.
The Company's Notes were outstanding for only 10 months of 1998.

Income Taxes.  In connection with the Carlton Acquisition, the
Company 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 such date, the Company's existing net
operating loss carryforwards and the provision or credit for
income taxes had been offset by valuation allowances.  Such net
liability results in the Company providing for income taxes or
credits after the date of the Carlton Acquisition.

Equity in Loss of Affiliate.  During 1999 the Company wrote-off
its remaining investment in RVC of $1.3 million.

Extraordinary Item.  During 1998, the Company purchased $7.0
million of its 11-1/2% Senior Notes due 2008.  The purchase price
for the Notes was $4.8 million and after adjustments for
proportionate offering costs, accrued interest and tax effects,
resulted in a gain of $1.1 million.

Net Loss.  Due to the factors described above, the Company's net
loss increased by $2.7 million, from a net loss of $6.5 million
in 1998 to a net loss of $9.2 million in 1999.

Year Ended December 31, 1998 Compared to Year Ended December 31,
1997

Operating Revenues.  Operating revenues increased by  $8.5
million, or 36% for the year ended December 31, 1998 compared to
the same period in 1997, with $6.1 million of the increase due to
the inclusion in 1998 of the operations of Carlton's gathering
system.  The following table summarizes oil and gas production
volumes, average sales prices and period to period comparisons,
including the effect on oil and gas operating revenues, for the
periods indicated:

<TABLE>
<CAPTION>
                            Year ended         1998 Compared to 1997
                           December 31,    --------------------------------
                           ------------    % Increase   Operating Revenue
                           1997    1998    (Decrease)   Increase (decrease)
                           ----    ----    ----------   -------------------
                                                       (Dollars in thousands)
<S>                      <C>      <C>       <C>               <C>
Production volumes:
  Natural gas (Mmcf)      6,686    8,795      31.5 %            4,968
  Oil (Mbbls)               467      520      11.5 %              914
Average sale prices:
  Natural gas (per Mcf)   $2.36    $2.24     ( 5.0)%           (1,031)
 Oil (per Bbl)           $17.10   $11.81     (30.9)%           (2,749)
</TABLE>

Oil and gas revenues were higher during 1998 compared to 1997 as
a result of a 26% increase in production partially offset by a
13% decrease in realized prices, both on an Mcfe basis. Most of
the increase in production was due to the addition of Carlton's
operations following its acquisition by the Company in February
1998.  Average daily production was 32.6 MMcfe in 1998 compared
to 26.0 MMcfe for 1997.  Natural gas production increased by 32%
and oil production increased by 12% for the comparable periods.
The average realized sales price for natural gas was $2.24 per
Mcf for 1998, compared to $2.36 per Mcf for 1997.  The average
realized oil price for 1998 was $11.81 per Bbl, compared to
$17.10 per Bbl for 1997, a 31% decrease.

Oil and Gas Production Expense.  Oil and gas production expense
increased by $1.9 million, or 28%, for the year ended December
31, 1998, compared to the same period in 1997.   The increase in
expense was due primarily to the addition of Carlton's operations
following its acquisition by the Company in February 1998. The
oil and gas production expense was $.72 per Mcfe for 1998, an
increase from $.71 per Mcfe compared to 1997.

Gathering System.  The Carmen System is obligated to deliver
10,000 MMbtu's per day at the tail-gate of the system, and
purchases outside gas to satisfy that obligation. Revenue from
this source was $6.1 million for 1998.  During 1998, outside
purchases were $4.2 million and system operating costs were $0.5
million.

Depreciation and Amortization ("D&A") Expense.   Depreciation and
amortization expense increased by $5.0 million, or 58% for 1998
compared to 1997, and was $1.15 per Mcfe for 1998, an increase of
$0.23, or 26% compared to the $0.92 per Mcfe for 1997.  This
increase is due primarily to the inclusion of Carlton's
operations in 1998, including the depreciation of the Carmen
System.  For oil and gas D&A only, the results were $.93 per Mcfe
for 1998 compared with $.86 per Mcfe for 1997, an 8% increase.

G & A Expense.  General and administrative expense decreased $.9
million, or 21%, in 1998 compared with $4.5 million in 1997.  The
decrease is due primarily to operator overhead fee reimbursements
received from unrelated interests attributable to Carlton for
1998, and the capitalization of certain geological and
geophysical costs related to the Company's increased exploration
efforts in 1998.Interest Expense.  Interest expense increased
$8.0 million to $13.2 million for 1998 compared to $5.2 million
for 1997.  This increase was attributable to higher average
outstanding indebtedness and higher effective interest rates
during 1998, resulting both from the Notes Offering and
additional bank borrowings during 1998.

Income Taxes.  In connection with the Carlton Acquisition, the
Company 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 such date, the Company's existing net
operating loss carryforwards and the provision or credit for
income taxes had been offset by valuation allowances.  Such net
liability results in the Company providing for income taxes or
credits after the date of the Carlton Acquisition.

Equity in Loss of Affiliate.  This represents the Company's 49.5%
equity interest in the loss of its affiliate RVC Energy, Inc.

Extraordinary Item.  During 1998, the Company purchased $7.0
million of its 11-1/2% Senior Notes due 2008.  The purchase price
for the Notes was $4.8 million and after adjustments for
proportionate offering costs, accrued interest and tax effects,
resulted in a gain of $1.1 million.

Net Loss.  Due to the factors described above, the Company's net
loss increased by $5.3 million, from a net loss of $1.2 million
in 1997 to a net loss of $6.5 million in 1998.

Use of Estimates

The preparation of financial statements in conformity with
generally accepted accounting principles requires management
to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent
assets and liabilities at the date of the 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

At December 31, 1999 the Company had cash and cash equivalents of
$1.9 million, and $2.9 million available under the Credit
Facility discussed below.

At December 31, 1999 the Company had $129.4 million ($130.6
million after giving effect to applicable original issue
discount) of indebtedness outstanding.  This indebtedness
consisted primarily of $108.0 million of Senior Notes due 2008
issued in February 1998 (before giving effect to unamortized
original issue discount of $1.3 million) and $22.5 million of
advances obtained under the Credit Facility discussed below.  Net
proceeds of the Notes Offering were used to repay existing debt,
fund the Carlton Acquisition, and for working capital.  Pursuant
to the Indenture governing the Senior Notes, the Company may
incur up to $30.0 million in Permitted Indebtedness (as defined).
Subject to certain limitations in the Indenture, the Company may
incur additional indebtedness, including additional indebtedness
under the Credit Facility.  See "-Credit Facility."

Funding for the Company's business activities has historically
been provided by operating cash flow and reserve-based bank
borrowings.  The Company regularly engages in discussions
relating to potential acquisitions of oil and gas properties or
companies engaged in the oil and gas business.  Any future
acquisitions may require additional debt or equity financing
which will be dependent upon financing arrangements, if any,
available at the time.

Credit Facility. On December 27, 1999 the Company refinanced its
senior secured credit facility (the "Credit Facility") with
Foothill Capital Corporation, a Wells Fargo company.  The
refinancing was preceeded on December 22 by the Company and its
prior lenders, Union Bank of California, N.A. and Den norske
Bank, ASA, executing an amendment to the then-existing credit
facility to restore the commitment to $30.0 million and increase
the borrowing base to $25.0 million, which amount was fully
advanced.  The refinancing was effected by Foothill purchasing
from Union and Den norske the Company's outstanding $25.0 million
indebtedness, together with all rights under the mortgages,
security agreements and other loan documents previously executed
in connection therewith.

The Company and Foothill have entered into an Amended and
Restated Loan and Security Agreement which provides for up to
$30.0 million of revolving credit, subject to borrowing base
restrictions and applicable limitations under the indenture
governing the Company's $108.0 million senior notes due 2008.
The initial term of the facility is three years and the interest
rate is prime plus 2%.  Indebtedness under the Credit Facility
is secured by substantially all of the Company's oil and gas
properties and other assets.

The amount of credit available at any time under the Credit
Facility may not exceed the borrowing base which is subject to
redetermination at least semi-annually.  The borrowing base at
December 31, 1999 was $25.4 million.  The Credit Facility
contains customary covenants which, among other things, require
periodic financial and reserve reporting and limit the Company's
incurrence of indebtedness, liens, dividends, loans, mergers,
transactions with affiliates, investments and sales of assets.

Cash Flows from Operating Activities.  For the year ended
December 31, 1999 cash flows from operating activities were a
negative $6.0 million compared to $9.5 million for 1998, due to
an increase of $2.8 million net loss for 1999 and decreases in
accounts receivable and accounts payable for 1999 compared to
increases in these categories for 1998.

Cash Flow from Investing Activities.  For the year ended December
31, 1999 net cash used by investing activities was $2.3
million, including $4.5 million for oil and gas property
additions, offset by property sales proceeds of $2.9 million.
For the year ended December 31, 1998 net cash used in the
Company's investing activities was $66.6 million, including $41.6
million for the Carlton Acquisition, $6.5 million for the Ricks
Acquisition, $18.0 million for oil and gas well drilling
activities, and a $2.0 million investment in RVC offset by $2.1
million of property sales. The Company's budget for capital
expenditures in 2000 will approximate $5.0 million provided
current oil and gas prices realized are maintained.

Year 2000 Issues

During 1999 the Company completed modifications and testing of
its main-frame application software to ensure its Year 2000
compliance, at an approximate cost of $100,000.

To date, no failures of these modifications has come to the
Company's attention, nor has the Year 2000 readiness of others
with which the Company does business affected the Company in any
way.

Item 7A   Quantitative and Qualitative Disclosures about Market
          Risk

The carrying amounts reported in the balance sheets for cash and
cash equivalents, trade receivables and payables, installment
notes and capital leases, and variable rate long-term debt
approximate their fair values. The carrying value of the Senior
Notes exceeded the fair value at December 31, 1998 and 1999 by
approximately $37.4 million and $62.1 million, respectively,
based on quoted market prices.

Item 8    Financial Statements and Supplementary Data

                        RAM Energy, Inc.

                Consolidated Financial Statements

          Years ended December 31, 1997, 1998 and 1999


                            Contents

Report of Independent Auditors
Consolidated Financial Statements

Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Stockholders' Deficiency
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements

<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, 1998 and 1999, and the
related consolidated statements of operations, stockholders'
deficiency, and cash flows for each of the three years in the
period ended December 31, 1999. 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, 1998 and
1999, and the consolidated results of its operations and its cash
flows for each of the three years in the period ended December
31, 1999, in conformity with accounting principles generally
accepted in the United States.



                                           ERNST & YOUNG LLP

Oklahoma City, Oklahoma
March 29, 2000
<PAGE>
                         RAM Energy, Inc.
<TABLE>
                    Consolidated Balance Sheets
                      (Dollars in Thousands)
<CAPTION>
                                                         December 31,
                                                        1998      1999
                                                        --------------
<S>                                                  <C>       <C>
Assets
Current assets (Note 5):
  Cash and cash equivalents                          $  8,603  $  1,875
  Accounts receivable:
    Oil and gas sales                                   3,387     3,587
    Joint interest operations, net of allowance
     for doubtful accounts of $358 in 1998 and
     $459 in 1999                                       2,117     1,164
    Related parties                                       147       219
    Other                                                 115        16
  Prepaid expenses and deposits                           431       361
                                                     ------------------
Total current assets                                   14,800     7,222

Properties and equipment, at cost (Notes 1, 5 and 13):
  Oil and gas properties and equipment, based on
   full cost accounting                               119,697   119,227
  Gathering and disposal systems                       39,184    39,623
  Other property and equipment                          3,781     3,940
                                                    ------------------
                                                      162,662   162,790
  Less accumulated amortization and depreciation       28,388    40,103
                                                     ------------------
Net properties and equipment                          134,274   122,687

Investment in RVC Energy, Inc. (Note 2)                 1,307         -

Other assets:
  Deferred loan costs, net of accumulated
   amortization of $715 in 1998 and $1,042 in 1999        955     1,578
  Deferred offering costs, net of accumulated
   amortization of $395 in 1998 and $865 in 1999
   (Note 5)                                             4,307     3,837
  Other                                                   808       473
                                                     ------------------
Total assets                                         $156,451  $135,797
                                                     ==================
Liabilities and stockholders' deficiency
Current liabilities:
  Accounts payable:
    Trade                                            $  6,230  $  1,372
    Oil and gas proceeds due others                     4,378     4,539
    Related party                                         826       217
  Accrued liabilities:
    Compensation                                          320       122
    Interest                                            4,942     4,707
    Other                                                  65         -
  Gas balancing liability                                   -       639
  Long-term debt due within one year (Note 5)             109       103
                                                     ------------------
Total current liabilities                              16,870    11,699

Gas balancing liability not expected to be
 settled within one year                                  735     2,509
Long-term debt due after one year (Note 5)            131,630   129,253
Deferred income taxes                                  17,056    11,406
Commitments and contingencies (Notes 5, 7 and 11)         600       600

Stockholders' deficiency (Note 9):
  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                                 (10,483)  (19,713)
                                                     ------------------
Stockholders' deficiency                              (10,440)  (19,670)
                                                     ------------------
Total liabilities and stockholders' deficiency       $156,451  $135,797
                                                     ==================
</TABLE>
See accompanying notes.
<PAGE>

                         RAM Energy, Inc.
<TABLE>
               Consolidated Statements of Operations
               (In Thousands, Except Share Amounts)
<CAPTION>
                                               Year ended December 31,
                                          1997          1998          1999
                                          --------------------------------
<S>                                  <C>           <C>           <C>
Operating revenues:
  Oil and gas sales                  $   23,737    $   25,839    $   23,085
  Gathering system                            -         6,123         9,198
  Other (Note 4)                             79           354           827
                                     --------------------------------------
Total operating revenues                 23,816        32,316        33,110

Operating expenses:
  Oil and gas production expenses         6,769         8,633         7,793
  Gathering system purchases                  -         4,220         6,621
  Gathering system operations                 -           496           414
  Amortization and depreciation           8,692        13,713        12,964
  General and administrative, overhead
   and other expenses, net of
   operator's overhead fees               4,467         3,517         4,437
                                     --------------------------------------
Total operating expenses                 19,928        30,579        32,229
                                     --------------------------------------
Operating income                          3,888         1,737           881

Other income (expense):
  Interest expense                       (5,159)      (13,197)      (14,623)
  Interest income                            83           356           169
  Equity in loss of RVC Energy, Inc.
   (Note 2)                                   -          (693)       (1,307)
                                     --------------------------------------
Loss before income taxes and
 extraordinary item                      (1,188)      (11,797)      (14,880)

Income tax benefit-deferred (Note 10)         -        (4,200)       (5,650)
                                     --------------------------------------
Loss before extraordinary item           (1,188)       (7,597)       (9,230)

Extraordinary gain on repurchase of
 debt, net of income taxes of $700            -         1,140             -
                                     --------------------------------------
Net loss                               $ (1,188)     $ (6,457)     $ (9,230)
                                     ======================================

Per share amounts-basic and diluted:
  Loss before extraordinary item          $(.44)       $(2.79)       $(3.38)
  Extraordinary item                          -           .42             -
                                     --------------------------------------
Net loss                                  $(.44)       $(2.37)       $(3.38)
                                     ======================================
Weighted average shares outstanding   2,727,000     2,727,000     2,727,000
                                     ======================================
</TABLE>
See accompanying notes.

                             RAM Energy, Inc.
<TABLE>
            Consolidated Statements of Stockholders' Deficiency
                              (In Thousands)
<CAPTION>
                                                                      Stock-
                              Preferred Common  Paid-In  Accumulated holders'
                                Stock   Stock   Capital    Deficit  Deficiency
                              ------------------------------------------------
<S>                             <C>     <C>     <C>      <C>        <C>
Balance at December 31, 1996    $  1    $  23   $ 1,493  $ (2,838)  $ (1,321)
Preferred stock redemption        (1)       -    (1,473)        -     (1,474)
Revision of par value
 of common stock                   -        4        (4)        -          -
Net loss                           -        -         -    (1,188)    (1,188)
                                --------------------------------------------
Balance at December 31, 1997       -       27        16    (4,026)    (3,983)
Net loss                           -        -         -    (6,457)    (6,457)
                                --------------------------------------------
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)
                                ============================================
</TABLE>
See accompanying notes.
<PAGE>

                         RAM Energy, Inc.
<TABLE>
               Consolidated Statements of Cash Flows
                          (In Thousands)
<CAPTION>
                                               Year ended December 31,
                                             1997       1998       1999
                                          ------------------------------
<S>                                       <C>        <C>        <C>
Cash flows from operating activities
------------------------------------
Net loss                                  $ (1,188)  $ (6,457)  $ (9,230)
Adjustments to reconcile net loss to
 net cash provided (used) by
 operating activities:
  Amortization of Senior Notes
   discount included in interest expense         -        126        157
  Amortization and depreciation:
    Oil and gas properties and equipment     8,134     11,113      9,578
    Gathering and disposal systems               -      1,625      1,950
    Senior Notes fees                            -        395        470
    Credit facility fees                       350        358        327
    Other property and equipment               208        222        549
  Provision for doubtful accounts
   receivable and other                         91         30        116
  Extraordinary gain on retirement of debt, net  -     (1,140)         -
  Equity in loss of RVC Energy, Inc.             -        693      1,307
  Deferred income taxes, net                     -     (4,200)    (5,650)
  Cash provided (used) by changes in
   operating assets and liabilities,
   net of amounts resulting from acquisitions:
    Prepaid expenses and deposits                -        730         70
    Accounts receivable                        797        383        664
    Accounts payable                         1,430      1,525     (5,306)
    Accrued liabilities                       (646)     4,157       (498)
    Gas balancing liability                   (454)       (27)      (472)
                                          ------------------------------
Total adjustments                            9,910     15,990      3,262
                                          ------------------------------
Net cash provided (used) by
 operating activities                        8,722      9,533     (5,968)

Cash flows from investing activities
------------------------------------
Payment for acquisition of Carlton
 Resources Corporation,
 net of cash acquired                            -    (41,611)         -
Payment for acquisition of Ricks properties      -     (6,500)         -
Payment for investment in RVC Energy, Inc.       -     (2,000)         -
Payments for oil and gas properties
 and equipment                             (17,642)   (17,972)    (4,485)
Proceeds from sales of oil and gas
 properties and equipment                    9,764      2,068      2,903
Payments for other property and equipment     (343)      (389)      (283)
Proceeds from sales of other
 property and equipment                         19          -         26
Payments for gathering and disposal systems      -       (184)      (438)
Payment for other assets                         -       (263)      (197)
Proceeds from sales of other assets              -        244        205
                                          ------------------------------
Net cash used by investing activities       (8,202)   (66,607)    (2,269)

Cash flows from financing activities
------------------------------------
Principal payments on long-term debt       (10,510)   (62,132)    (8,045)
Proceeds from borrowings on long-term debt   9,751     25,129      5,504
Proceeds from volumetric production
 payment                                         -          -      5,000
Proceeds from Senior Notes Offering,
 net of discount                                 -    113,328          -
Payment for repurchase of Senior Notes           -     (4,791)         -
Payments for Preferred Stock Redemptions:
  Company Series A and B                         -     (1,474)         -
  Carlton Redeemable                             -       (600)         -
Payments of deferred offering costs              -     (5,008)         -
Payments for loan origination fees            (120)       (23)      (950)
                                          ------------------------------
Net cash provided (used) by
 financing activities                         (879)    64,429      1,509
                                          ------------------------------
Increase (decrease) in cash and cash
 equivalents                                  (359)     7,355     (6,728)

Cash and cash equivalents at
 beginning of year                           1,607      1,248      8,603
                                          ------------------------------
Cash and cash equivalents at end of year  $  1,248   $  8,603   $  1,875
                                          ==============================
Disclosure of noncash investing and
 financing activities
-----------------------------------
Deferred loan and offering costs
 included in accounts payable and
 other liabilities                        $    734   $     -    $      -
                                          ==============================

Preferred stock redemption included
 in accrued liabilities                   $  1,474   $     -    $      -
                                          ==============================

Exchange of Partnership interest for
 receivable from sister corporation,
 net of minority interest                 $    611   $     -    $      -
                                          ==============================
</TABLE>
See accompanying notes.
<PAGE>

                        RAM Energy, Inc.

           Notes to Consolidated Financial Statements

                   December 31, 1998 and 1999


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 oil and gas industry with activities
including the drilling, completion and operation of oil and gas
wells. The Company conducts the majority of its operations in the
states of Oklahoma, Texas and New Mexico. Additionally, the
Company owns and operates an oil and gas gathering system and a
saltwater disposal operation in north central Oklahoma (the
"Gathering System"). The Gathering System purchases, transports
and markets oil and gas production and disposes of salt water
from properties owned by the Company and other oil and gas
companies.

Principles of Consolidation

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

Properties and Equipment

The Company follows the full cost method of accounting for oil
and gas operations. Under this method, all productive and
nonproductive costs incurred in connection with the acquisition,
exploration and development of oil and gas reserves are
capitalized. No gains or losses are recognized upon the sale or
other disposition of oil and gas 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 11, 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 should 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 two years.

Under the full cost method, the net book value of oil and natural
gas properties, less related deferred income taxes, may not
exceed the estimated after-tax future net revenues from proved
oil and natural gas 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 have been prepared by an
independent petroleum engineer.

The discounted future net revenues at December 31, 1999 include
approximately $28.9 million related to undeveloped and
nonproducing properties on which estimated capital expenditures
of approximately $25.4 million will be required to develop and
produce the reserves. Such amounts have been considered in the
calculation of the ceiling amount at December 31, 1999. The
funding for these projects is expected by the Company to be
provided from cash flows from operations and borrowings under its
credit facility (Note 5).

The Company has capitalized internal costs of none, $785,492 and
$599,628 for the years ended December 31, 1997, 1998 and 1999,
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
Gathering System on a quarterly basis, or when events occur which
indicate an impairment in value may exist. Impairment is recorded
if the book value of the Gathering System is in excess of the
expected future cash flows from the Gathering System. Accumulated
depreciation related to the Gathering System is $1,625,000 and
$3,575,000 at December 31, 1998 and 1999, 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, 1998 and 1999 is
$3,011,000 and $3,270,000, respectively.

Amortization and Depreciation

Amortization of oil and gas properties and equipment is computed
based on the unit-of-production method using total proved
reserves. Depreciation of gas gathering and disposal facilities
is computed on a straight-line method over twenty years.
Depreciation on other equipment is computed based on the double
declining balance method over the estimated useful lives of the
assets which range from three to ten years. Amortization of
leasehold improvements is computed 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.

Oil and Gas Sales and Gas Imbalances

The Company follows the entitlement method in accounting for oil
and gas sales, recognizing 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. Prior to 1999, the Company recorded acquired
properties net of any existing gas imbalances.

Effective October 1, 1999, the Company changed its accounting
presentation for acquired imbalances to present such net
imbalances with gas balancing liabilities in its Balance Sheet.
The net overproduced position related to these acquired
imbalances was 1.8 billion cubic feet at such date. The effect of
the change in accounting presentation resulted in a $2,885,000
increase to the net gas balancing liability with a like increase
to oil and gas properties and equipment. Such change did not have
an effect on the accumulated deficit at October 1, 1999 or on the
net loss reported for the year ended December 31, 1999.

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 oil and gas to various customers and
participates with other parties in the drilling, completion and
operation of oil and gas wells. Joint interest and oil and gas
sales receivables related to these operations are generally
unsecured. In 1999, approximately 53% of total revenues were to
two customers (49% to three customers in 1998), with sales to
each comprising 29% and 24% (19%, 16% and 14% in 1998) of total
revenues. For the years ended December 31, 1997, 1998 and 1999,
the provisions for doubtful accounts receivable were
approximately $91,000, $30,000 and $116,000, respectively, while
charge-offs of the allowance in those years were approximately
$23,000, $111,000 and $15,000, respectively. The Company has
established joint interest operations accounts receivable
allowances which management believes are adequate for
uncollectible amounts at December 31, 1998 and 1999.

Use of Estimates

The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of 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 capital leases, and variable rate long-term debt
approximate their fair values. The carrying value of interest
rate swap agreements at December 31, 1998 exceeded the fair value
by approximately $419,000, representing the amount the Company
would be required to pay to terminate the contracts at such date.
There were no interest rate swap agreements outstanding at
December 31, 1999. The carrying value of the Senior Notes
exceeded the fair value at December 31, 1998 and 1999 by
approximately $37.4 million and $62.1 million, respectively,
based on quoted market prices.

Hedging Activities

The Company attempts to reduce its exposure to unfavorable
changes in natural gas prices by utilizing fixed-price physical
delivery contracts, basis swaps and options. The Company also
enters into interest rate swap contracts to reduce its exposure
to interest rate fluctuations. Gains and losses from transactions
designated as hedges are deferred and recognized in income in the
periods for which the underlying commodity or interest rate was
hedged. The effectiveness of the hedge is measured by a
correlation of changes in the fair value of the hedging
instruments with changes in the value of the hedged item. If high
correlation ceases to exist, hedge accounting will be terminated
and gains or losses are recognized in the period of the change.

Earnings Per Common Share

Basic earnings per share is calculated using income available to
common shareowners divided by the weighted average number of
common shares outstanding during the year. As the Company had no
common stock equivalents in any of the periods presented, diluted
earnings per share and basic earnings per share are the same.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 133, "Accounting
for Derivative Instruments and Hedging Activities," which is
required to be adopted in years beginning after June 15, 2000.
The Company expects to adopt the new statement effective January
1, 2001. The statement requires the Company to recognize all
derivatives on the balance sheet at fair value. Derivatives that
are not designated or not effective as hedges must be adjusted to
fair value through income. If the derivative is a hedge,
depending on the nature of the hedge, changes in the fair value
of the derivative will either be offset against the change in
fair value of the hedged assets, liabilities, or firm commitments
through earnings or recognized in other comprehensive income
until the hedged item is recognized in earnings. The ineffective
portion of a derivative's change in fair value will immediately
be recognized in earnings. The Company has not yet determined
what the effects of adoption of this statement will be on the
earnings and financial position of the Company.

2. Acquisitions

On February 24, 1998, the Company acquired Carlton Resources
Corporation ("Carlton") in a stock acquisition accounted for as a
purchase, for approximately $41.6 million, net of defined working
capital adjustments of $1,000,000. The operations of Carlton are
included in the accompanying consolidated financial statements
beginning March 1, 1998. The allocation of the purchase price to
the assets and liabilities acquired was as follows (in thousands):

         Properties and equipment:
         Oil and gas properties              $24,400
         Pipeline gathering systems           39,000
                                             -------
                                              63,400
         Other assets and liabilities, net    (1,244)
         Deferred income tax liability       (20,556)
                                             -------
         Purchase price                      $41,600
                                             =======

The following unaudited pro forma results of operations gives
effect to the acquisition as if consummated on January 1, 1997.
The data reflects adjustments of the historical Carlton results
for depreciation and amortization of the property and equipment
acquired, adjustments of expenses resulting from contractual
requirements of the acquisition agreement and incremental
interest expense relating to the sale in February 1998 of the
Company's Senior Notes (Note 5) used to finance the purchase and
repay existing debt. The pro forma adjustments are based upon
available information and assumptions that management of the
Company believes are reasonable. The pro forma results of
operations data does not purport to represent the results of
operations which would have occurred had such transaction been
consummated on January 1, 1997 or the Company's results of
operations for any future date or period.

                                             Pro Forma (Unaudited)
                                             ---------------------
                                             Year ended December 31,
                                                1997       1998
                                             -----------------------
                                                (In Thousands,
                                           Except Per Share Amounts)

         Total operating revenues            $40,188   $34,458

         Net loss                            $(4,598)  $(7,180)

         Net loss per common share           $ (1.69)   $(2.63)


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
is an unrestricted affiliate of the Company accounted for under
the equity method of accounting. RVC has experienced recurring
losses since its inception and at December 31, 1999 was in
default under its credit facility. Accordingly, 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.

On August 17, 1998, the Company completed a $6.5 million
acquisition of certain proved undeveloped oil and gas properties
located in south Texas from Rick's Exploration, Inc.

The Company's acquisition of the Ricks properties and investment
in RVC were funded through borrowings under the Company's Credit
Facility (Note 5).

3. 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 will 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. Proceeds of the
Production Payment were $5.0 million and were recorded as a
reduction of oil and gas properties and equipment. Of the
proceeds, $4.5 million was used by the Company to reduce the
outstanding principal balance under its credit facility (Note 5).

4. Related Party Transactions

Since its formation the Company has acted as manager of RVC and
owned the operating rights of RVC's oil and gas properties. The
Company has received monthly management fees of $50,000 and
overhead reimbursements from RVC. During 1998 and 1999, the
Company received $225,000 and $600,000, respectively, in
management fees as well as $101,000 and $309,000, 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 oil
and gas properties resulting in cash proceeds of $1.7 million.

5. Long-Term Debt

Long-term debt at December 31, consists of the following:

                                             December 31,
                                            1998       1999
                                            ---------------
                                            (In Thousands)

    11-1/2% Senior Notes Due 2008 (A)    $ 106,517  $ 106,674
    Revolving note payable (B)              25,000     22,500
    Installment loan agreements                222        182
                                         --------------------
                                           131,739    129,356
    Less amount due within one year            109        103
                                         --------------------
                                         $ 131,630  $ 129,253
                                         ====================

(A)  In February 1998, the Company completed the sale of $115
     million of 11-1/2% Senior Notes ("Notes") Due 2008 in a
     public offering ("Offering"). The proceeds, net of offering
     costs of $5,008,720 and discount of $1,672,100 were used
     principally to pay the outstanding balance under its
     existing Credit Facility ("Credit Facility") and to acquire
     Carlton (Note 2).

     The 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 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.

     During the fourth quarter of 1998, the Company recognized an
     extraordinary after-tax gain (net of unamortized deferred
     offering and original issue discount costs and income taxes)
     of $1,140,698 or $.42 per share as a result of the
     repurchase of $7,040,000 face amount of the Notes. The Notes
     were purchased at 64% of the face amount, with accrued
     interest to the date of repurchase. The Company utilized
     borrowings under its revolving Credit Facility to purchase
     the Notes. In February 2000, the Company canceled the
     repurchased Notes.

     At December 31, 1998 and 1999, the unamortized issue
     discount associated with the Notes totaled $1,443,246 and
     $1,285,801, respectively.

(B)  From February 1998 to December 1999, the Credit Facility
     bore interest on a sliding scale based on the ratio of the
     aggregate amount outstanding to the borrowing base of $25
     million. The applicable rate could, at the Company's option,
     be based either on the Eurodollar rate or the creditor's
     base rate, with the rates ranging from the Eurodollar rate
     plus 1.375% to 2.0% or the creditor's base rate plus 0.0% to
     0.5%. On December 27, 1999, Foothill Capital Corporation
     ("Foothill") purchased the Credit Facility, assuming all
     rights and obligations, at which time the facility was
     amended and restated.

     The Credit Facility, as amended and restated, provides for a
     three year, $30 million revolving commitment. The amount of
     credit available at any time under the amended and restated
     Credit Facility may not exceed the borrowing base, which is
     $25.4 million at December 31, 1999, and will be redetermined
     monthly. Advances under the amended and restated Credit
     Facility bear interest, payable monthly, at the Foothill
     reference rate plus 2.0% per annum, but no less than 8% per
     annum. The interest rate on outstanding borrowings at
     December 31, 1999 was 10.5%.

     The Company is required to pay a commitment fee equal to .5%
     per annum on the amount by which the borrowing base exceeds
     the aggregate amount outstanding under the Foothill Credit
     Facility. Amounts outstanding under the Foothill Credit
     Facility are secured by essentially all current and future
     assets of the Company and its subsidiaries.

     The Credit Facility contains customary covenants which,
     among other things, require periodic financial and reserve
     reporting and limit the Company's incurrence of
     indebtedness, liens, dividends, loans, mergers, transactions
     with affiliates, investments and sales of assets, and
     require the Company to maintain certain financial ratios.

The amount of required principal payments for the next five years
and thereafter as of December 31, 1999 are as follows:
2000-$103,000; 2001-$45,000; 2002-$22.5 million; 2003-$0;
2004-$0; thereafter-$108 million.

Interest paid in the years ended December 31, 1997, 1998 and 1999
totaled $5,163,996, $8,508,010 and $14,700,992, respectively.

6. Subsidiary Guarantors

The Company's Senior Notes are 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 summarized financial information of the
Subsidiary Guarantors after their acquisition or formation in
1998. Full financial statements of the Subsidiary Guarantors are
not presented because management believes they are not material
to the investors. 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.

                                            December 31,
                                          1998       1999
                                          ---------------
                                          (In Thousands)
    Balance Sheet Data:
    Current assets                      $  2,878   $  1,355
    Property and equipment, net         $ 68,276   $ 69,837
    Other assets                        $    363   $     96
    Current liabilities                 $  1,912   $    277
    Deferred income tax liabilities     $ 20,556   $ 20,320


                                        Year ended December 31,
                                            1998       1999
                                            ---------------
                                           (In Thousands)
    Operating Data:
    Operating revenues                  $ 10,997    $ 13,994
    Operating expenses                     8,376      11,656
                                        --------------------
    Operating income                    $  2,621    $  2,338
                                        ====================

Amounts presented related to operations have been limited to
operating information as the Company has not allocated
administrative, interest charges or income taxes to its
subsidiaries. Amounts presented related to liabilities do not
reflect debt and related accrued interest payable, unamortized
debt issue cost, and unamortized issue discount as the debt and
related balances are reflected at the Company level.

7. Operating Leases

The Company leases office space, equipment and vehicles under
noncancelable operating lease agreements which expire at various
dates through 2001. The leases provide that the Company pay
insurance, taxes and maintenance related to the leased assets.
Rent expense of $308,799, $429,025 and $449,402 was incurred
under operating leases in the years ended December 31, 1997, 1998
and 1999, respectively.

Future minimum lease payments for operating leases at December
31, 1999 are as follows (in thousands):

              2000                                  $  534
              2001                                     177
                                                    ------
                                                    $  711
                                                    ======

Future minimum sublease receipts due under noncancelable
subleases as of December 31, 1999 are as follows (in thousands):

              2000                                  $  120
              2001                                      80
                                                    ------
                                                    $  200
                                                    ======

8. 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 $10,000 in 1999.   Employer
contributions to the plan are discretionary. Company
contributions to the plan in 1997, 1998 and 1999 were $88,000,
$100,000 and none, respectively.

9. Capital Stock

Common Stock

Pursuant to a Special Retainer Agreement effective July 1,  1998,
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  vest  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.
Consequently, no compensation expense related to the grant has
been recognized in the 1998 and 1999 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, 1999.

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.

In connection with a change in capital structure in 1997,  the
Company called for redemption in November 1997 and December 1997,
respectively, of the previously outstanding Series A and Series B
noncumulative preferred shares for $10 per share or a total  of
$1,473,660. Such redemptions were completed by February 1998.

10. 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,
1998 and 1999 are as follows:
<TABLE>
<CAPTION>
                                                            1998        1999
                                                            ----------------
                                                             (In Thousands)
<S>                                                      <C>         <C>
Deferred tax assets
Financial charges which are deferred for tax purposes    $    127    $     47
Minimum and investment tax credit carryforwards               372         372
Net operating loss carryforwards                            8,846      13,399
                                                         --------------------
  Deferred tax assets                                       9,345      13,818

Deferred tax liabilities
Intangible drilling costs capitalized for financial
 purposes and expensed for tax purposes                     6,179       5,966
Financial bases in excess of tax bases on net assets of
 Carlton acquired                                          20,222      19,258
                                                         --------------------
  Deferred tax liabilities                                 26,401      25,224
                                                         --------------------
Net deferred income tax liabilities                      $ 17,056    $ 11,406
                                                         ====================
</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 is as follows:

<TABLE>
<CAPTION>
                                              Year ended December 31,
                                             1997        1998      1999
                                             --------------------------
                                                    (In Thousands)
<S>                                         <C>       <C>       <C>
Income tax benefit at statutory rate        $(404)    $(4,129)  $(5,194)
State income taxes                            (48)       (353)     (445)
Other                                          11         282       (11)
Change in valuation allowance recognized      441           -         -
                                            ---------------------------
Income tax benefit-deferred                 $   -     $(4,200)  $(5,650)
                                            ===========================
</TABLE>

At December 31, 1999, the Company has federal income tax net
operating loss carryforwards of approximately $35 million which
begin expiring in 2002.

11. Commitments and Contingencies

In 1996, the Company's predecessor sold an oil and gas 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 severance agreements for two senior
officers and directors of the Company. These agreements provide
for severance benefits to be paid upon involuntary separation as
a result of actions taken by the Company or its successors.
Benefits under the agreements are principally based upon length
of service to the Company. The covered officers and directors are
not entitled to these separation benefits upon voluntary
separation, including retirement. At December 31, 1999, the
severance benefits under these agreements were approximately $1.6
million. A provision for these benefits would not be made unless
an involuntary termination was probable.

The Company is involved in legal proceedings and litigation
arising 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.

12. Fixed Price Contracts

The Company periodically enters into fixed price physical
delivery contracts basis swaps and options to reduce its exposure
to unfavorable changes in natural gas prices which are subject to
significant and often volatile fluctuation. These contracts allow
the Company to predict with greater certainty the effective gas
prices to be received from its hedged production. At December 31,
1999, the Company had contracts to deliver 4,120,000 MMbtu at an
average price of $2.42 in 2000.

13. Oil and Gas Producing Activities

Capitalized costs relating to crude oil and gas producing
activities and related accumulated depreciation and amortization
are summarized as follows:

<TABLE>
<CAPTION>
                                                      December 31,
                                                     1998       1999
                                                     ---------------
                                                     (In Thousands)
<S>                                                <C>        <C>
    Proved crude oil and natural gas properties    $119,697   $119,227
    Accumulated depreciation and amortization       (23,752)   (33,329)
                                                   -------------------
                                                   $ 95,945   $ 85,898
                                                   ===================
</TABLE>

Costs incurred in oil and gas producing activities are as
follows:

<TABLE>
<CAPTION>
                                             Year ended December 31,
                                           1997       1998        1999
                                           ---------------------------
                                        (In Thousands, Except Per Mcfe)
<S>                                     <C>         <C>         <C>
    Acquisition of proved properties    $ 12,169    $ 30,907    $      -
    Development costs                      6,085      17,972       4,485
    Amortization rate per equivalent Mcf    $.86        $.93        $.92
</TABLE>

14. Supplementary Oil and Gas Reserve Information (Unaudited)

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

The Company retains independent engineering firms to provide year-
end estimates of the Company's future net recoverable oil, gas,
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
oil and gas, including condensate and natural gas liquids, are
summarized as follows:

<TABLE>
<CAPTION>
                                          Crude Oil   Natural Gas
                                         (Thousand     (Million
                                          Barrels)    Cubic Feet)
                                         ------------------------
<S>                                       <C>         <C>
December 31, 1996                           4,282      82,885

Extensions and discoveries                    403      16,596
Sales of reserves in place                   (813)     (6,502)
Purchases of reserves in place                355       7,593
Revisions of previous estimates              (393)    (11,974)
Production                                   (467)     (6,686)
                                          -------------------
December 31, 1997                           3,367      81,912

Extensions and discoveries                    238       8,706
Sales of reserves in place                   (155)     (4,530)
Purchases of reserves in place                771      36,983
Revisions of previous estimates               (48)     (4,382)
Production                                   (520)     (8,795)
                                          -------------------
December 31, 1998                           3,653     109,894

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

Proved developed reserves:
December 31, 1996                           3,511      62,319
December 31, 1997                           2,436      56,516
December 31, 1998                           2,760      77,035
December 31, 1999                           2,901      68,134
</TABLE>

The following is a summary of a standardized measure of
discounted net cash flows related to the Company's proved oil and
gas reserves. For these calculations, estimated future cash flows
from estimated future production of proved reserves were computed
using crude oil and natural gas 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 crude oil and
natural gas reserves, less the tax basis of the properties
involved.

The Company cautions against using this data to determine the
fair value of its oil and gas properties. To obtain the best
estimate of fair value of the oil and gas 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 crude oil and natural gas reserves are
summarized as follows:

<TABLE>
<CAPTION>
                                                   December 31,
                                            1997       1998       1999
                                            --------------------------
                                                  (In Thousands)
<S>                                      <C>        <C>        <C>
Future cash inflows                      $ 284,955  $ 266,000  $ 293,097
Future production and development costs   (102,877)  (105,544)  (113,272)
Future income tax expenses                 (43,757)   (20,704)   (26,450)
                                         ---------  ---------  ---------
Future net cash flows                      138,321    139,752    153,375

10% annual discount for estimated
 timing of cash flows                      (58,883)   (66,061)   (74,387)
                                         -------------------------------
Standardized measure of discounted
 future net cash flows                   $  79,438  $  73,691  $  78,988
                                         ===============================
</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 ended December 31, 1999:

<TABLE>
<CAPTION>
                                               1997       1998      1999
                                               -------------------------
                                                    (In Thousands)
<S>                                         <C>        <C>        <C>
Discounted future net cash flows at
beginning of year                           $112,656   $ 79,438   $ 73,691

Changes during the year:
  Sales and transfers of crude oil
   and natural gas produced, net of
   production costs                          (16,968)   (17,206)   (15,292)
  Net changes in prices and production costs (47,943)   (37,978)    23,037
  Extensions and discoveries, less
   related costs                              15,139      3,757      7,181
  Development costs incurred and revisions     2,340     16,065      2,717
  Sales of reserves in place                 (12,857)    (2,762)    (6,366)
  Purchases of reserves in place              11,307     24,583          -
  Revisions of previous quantity estimates   (16,670)    (5,917)    (7,535)
  Net change in income taxes                  23,137     14,212     (2,705)
  Accretion of discount                       16,092      7,943      7,369
  Other                                       (6,795)    (8,444)    (3,109)
                                            ------------------------------
  Net change                                 (33,218)    (5,747)     5,297
                                            ------------------------------
Discounted future net cash flows at
 end of year                                $ 79,438   $ 73,691   $ 78,988
                                            ==============================
</TABLE>

Prices used in computing these calculations of future cash flows
from estimated future production of proved reserves were $16.17,
$8.95 and $22.76 per barrel of crude oil at December 31, 1997,
1998 and 1999, respectively, and $2.81, $2.12 and $2.07 per
thousand cubic feet of natural gas at December 31, 1997, 1998 and
1999, respectively.

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

          Not applicable.

                            PART III

Item 10   Directors and Executive Officers of the Registrant

          The following table sets forth names, ages and titles
of the directors and executive officers of the Company.

     Name                   Age        Position
     ----                   ---        --------

William W. Talley II, Ph.D.  57   Chairman of the Board of Directors

Larry E. Lee                 51   President and Chief Executive Officer and
                                  Director

M. Helen Bennett(1)(2)       52   Director

Gerald R. Marshall(1)(2)     66   Director

John M. Reardon(1)(2)        58   Director

Larry G. Rampey              55   Senior Vice President - Operations

John M. Longmire             57   Senior Vice President and Chief Financial
                                  Officer, Treasurer and Secretary

Drake N. Smiley              52   Senior Vice President - Land, Legal and
                                  Business Development
________________

(1)       Member of the Compensation Committee.

(2)       Member of the Audit Committee.

William W. Talley II, Ph.D. has been Chairman of the Board and a
director of the Company since its incorporation 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 President and a director of the Company
since its incorporation in 1987. Mr. Lee served as its 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.

M. Helen Bennett has been a director of the Company since 1992
and was a Vice President of the Company from December 1996 until
November 30, 1997. Mrs. Bennett has been a limited partner of
Goldman, Sachs & Co., an investment banking firm, since May 1992.
From 1980 until 1986, Mrs. Bennett served in several executive
capacities with Time, Incorporated, including as General Manager
of Fortune magazine from 1984 to 1986. From 1973 until 1980, she
was employed by McKinsey & Company.

Gerald R. Marshall became a director of the Company 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 of the Company in December 1997
and served as an adviser to the Company's 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.

Larry G. Rampey became a Senior Vice President of the Company in
December 1997 and had been a Vice President of the Company 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.

John M. Longmire became a Senior Vice President of the Company in
December 1997 and had been a Vice President of the Company since
1994. Mr. Longmire has been Chief Financial Officer, Treasurer
and Secretary of the Company since August 1994 and was its
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.

Drake N. Smiley became a Senior Vice President of the Company in
December 1997 and had been a Vice President of the Company since
February 1997. Mr. Smiley was Vice President - Land and Legal of
the Company from 1989 to 1994. From 1994 until he rejoined the
Company 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.

The 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 Company's executive officers serve at the
discretion of the Board of Directors. The terms of Mrs. Bennett
and Mr. Reardon will expire in 2000, Dr. Talley's term will
expire in 2001, and the terms of Mr. Lee and Mr. Marshall will
expire in 2002.

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, Mr. Lee and Mrs. Bennett collectively own a majority
of the stock and constitute the Board of Directors of Oklahoma
Double R Corporation, a Delaware corporation ("ODRC").  Dr. Talley
and Mr. Lee are the senior executive officers of ODRC.  ODRC was
special general partner of the Partnership and upon dissolution of
the Partnership in 1997, all of ODRC's interest in the properties
of the Partnership was distributed to RAM Energy in partial
satisfaction of outstanding indebtedness from ODRC to RAM Energy.
ODRC has 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 currently is pending.

Item 11  Executive Compensation

The following table sets forth for 1998 the cash compensation of
(i) the Company's chief executive officer and (ii) each other
person who was an executive officer as of December 31, 1998
(together with the Company's chief executive officer, the "Named
Executive Officers").  As described below, the Company has a
severance agreement with Dr. Talley and an employment agreement
with Mr. Lee.  See "Employment and Severance Agreements."

<TABLE>
Summary Compensation Table
<CAPTION>
                                                            Under-      All
                                                   Annual   lying      Other
                              Annual Compensation  Compen- Options    Compen-
                            ----------------------  sation (# of       sation
Name and Principal Position Year   Salary    Bonus    (1) Shares)(2)  ($) (3)
--------------------------- ----   ------    -----  ----- ----------  -------
<S>                         <C>   <C>       <C>      <C>    <C>      <C>
William W. Talley II, Ph.D. 1999  $240,000  $150,000                  $    -
Chairman of the Board(4)    1998   240,000   150,000     -     -       7,296
                            1997   540,860    81,470                   7,296

Larry E. Lee                1999   295,000   300,000                       -
President and Chief         1998   295,000   300,000     -     -       7,296
 Executive Officer(5)       1997   540,860    98,455                   7,296

M. Helen Bennett            1999    30,000         -                       0
Vice President(6)           1998    30,000         -     -     -           0
                            1997   372,660    46,897                       0

Larry G. Rampey             1999   155,000    50,000           -           -
Senior Vice President       1998   150,000    50,000     -             6,900
                            1997   130,000    15,416                   6,900

John M. Longmire            1999   145,000    50,000                       -
Senior Vice President,      1998   140,000    60,000     -     -       7,296
 Chief Financial Officer,   1997   120,000    15,000                   6,930
 Treasurer and Secretary

Drake M. Smiley             1999   140,000    50,000                       -
Senior Vice President       1998   130,000    40,000     -     -           -
                            1997    97,519     9,584                  39,142
_______________
</TABLE>

(1)       Personal benefits provided by the Company 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 Mr. Smiley, the amounts specified represent
          matching contributions made by the Company to the
          account of the executive officer under the Company's
          401(k) Profit Sharing Plan. The amount specified for
          Mr. Smiley represents relocation expenses paid by the
          Company.

(4)       Dr. Talley was Chief Executive Officer until October
          31, 1997. Director fees of $180,860 in 1997 are
          included as salary.

(5)       Mr. Lee was appointed Chief Executive Officer effective
          November 1, 1997.  Director fees $180,860 in 1997 are
          included as salary.

(6)       Mrs. Bennett was Vice President until November 30,
          1997. Director fees of $168,660 in 1997 and $30,000 in
          1998 and 1999 are included as salary.

Directors' Compensation

Dr. Talley and Mr. Lee received $180,860 in 1997, and Mrs.
Bennett received $168,660 in 1997 for serving as directors.
Beginning in 1998 the annual fee to be paid to each non-employee
director was $24,000 plus $1,000 for each meeting attended, with
a maximum of 6 meetings per year. Directors who are also
employees of the Company will not receive annual directors' fees.
Directors are also reimbursed for travel and other expenses.

Compensation Committee Interlocks and Insider Participation

The Compensation Committee of the Board of Directors of the
Company determines the compensation of the Company's executive
officers.  During fiscal year 1999, the members of the
Compensation Committee were M. Helen Bennett, Gerald R. Marshall
and John M. Reardon, all of whom are members of the Company's
Board of Directors.

Employment and Severance Agreements

The Company is a party to a Special Severance Agreement with Dr.
Talley which continues until Dr. Talley ceases to be Chairman of
the Board of the Company. During the existence of this agreement,
Dr. Talley will receive an annual base salary of at least
$240,000 and a bonus as determined by the Board. The term of the
agreement ends upon Dr. Talley's death, disability or voluntary
resignation, and may be terminated by the Company for cause. Upon
Dr. Talley's death, his representatives or, upon his disability,
Dr. Talley, will receive accrued but unpaid salary, bonus and
benefits, a pro rata share of any bonus paid for the 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 Dr.
Talley's disability, he will continue to be entitled to receive
benefits for the remainder of the agreement. If Dr. Talley ceases
to be Chairman of the Board 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.

The Company has an employment agreement with Mr. Lee for an
initial term expiring in December 2000, subject to annual
extensions of one year, at an annual salary of at least $295,000
and an annual bonus to be determined by the Board. Under this
agreement, Mr. Lee's employment may be terminated by the Company
for death or disability, or for cause, and by Mr. Lee for good
reason. 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.

The Company has employment and severance agreements with Messrs.
Longmire, Rampey and Smiley. Each of these agreements expires
December 31, 2000.  Under the terms of each agreement, the
officer's employment may be terminated by the Company at any time
for good cause, or for any other reason upon two weeks prior
notice, subject to certain severance payments.

Stock Incentive Plan

The Company's 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 employees of the Company, and any present or
future parent or subsidiary, and directors of the Company to
exert maximum efforts toward the success and growth of the
Company and to attract and retain experienced individuals who by
their position, ability and diligence are able to make important
contributions to the Company's success. The Plan is administered
by the Compensation Committee of the Board of Directors; 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 classes of stock of the Company (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 Company 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 will be 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 the liquidation or dissolution of the
Company or the merger or consolidation of the Company or sale of
all or substantially all of the Company's 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 of new options therefor. Unexercised outstanding
options will terminate upon the consummation of the dissolution
or liquidation of the Company or such merger, consolidation or
sale of assets.

The Plan may be terminated or amended by the 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, the Company's 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 the
          Company or its stockholders,

o         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 the rights of the Company or its stockholders, in
appropriate circumstances, to seek equitable remedies such as
injunctive or other forms of non-monetary relief. Such remedies
may not be effective in all cases.

The Certificate and the Bylaws provide that the Company shall
indemnify all of its directors and officers to the full extent
permitted by the Delaware General Corporation Law. Under such
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 such director or officer acted in good faith and in a
manner he reasonably believed to be in or not opposed to the best
interest of the Company. The Certificate, 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, the Bylaws, any agreement,
vote of stockholders or disinterested directors or otherwise.

The Company has entered into indemnity agreements with each of
its directors and executive officers. Under each indemnity
agreement, the Company 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 a
          director and/or officer of the Company or an affiliate
          or

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 an officer, director, employee or agent of
          the Company or an affiliate or is or was serving at the
          request of the Company as a director, officer, employee
          or agent of another corporation, partnership, joint
          venture, trust or other enterprise.

o         The payments which the Company 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. The Company also intends to provide
          liability insurance for each of its 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 the Common Stock as of December 31, 1999
by:

o         each director of the Company who owns Common Stock,

o         each Named Executive Officer who owns Common Stock,

o         each person known or believed by the Company to own
          beneficially 5% or more of the Common Stock, and

o         all directors and executive officers as a group, and as
          adjusted to give effect to the Offering.

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)           675,000          24.75%
9400 N. Broadway Extension
Oklahoma City, Oklahoma 73114

Larry E. Lee (1)(2)                             675,000          24.75
5100 E. Skelly Drive
Suite 650
Tulsa, Oklahoma 74135

M. Helen Bennett (1)(4)                         675,000          24.75
3333 Hagen Road
Napa, California 94558

William S. Price                                702,000          25.74
2002 East 46th Street
Tulsa, Oklahoma 74105

All executive officers and directors          2,025,000          74.26
  as a group (8 persons)
_______________
</TABLE>

(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.

(4)       Such shares are held in a trust as to which Mrs.
          Bennett has sole voting and dispositive power.

Item 13   Certain Relationships and Related Transactions

The Company completed the redemption of all of its 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, Mrs. Bennett and Mr. Price 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.

From May through November 1997, the Company employed William S.
Price, a principal stockholder of the Company, as a consultant to
assist it in identifying acquisition opportunities. Mr. Price
received $15,000 per month, or an aggregate of $105,000, pursuant
to this consulting agreement.

                            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, 1998 and
          1999.

          Consolidated Statements of Operations of the Company
          for the years ended December 31, 1997, 1998 and 1999.

          Consolidated Statements of Stockholders' Deficiency for
          the years ended December 31, 1997, 1998, and 1999.

          Consolidated Statements of Cash Flows of the Company
          for the years ended December 31, 1997, 1998 and 1999.

          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 RCP 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)

10.15     Amended and Restated Loan 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 (the
          "Amended and Restated Loan Agreement") (3)

10.16     Employment and Severance Agreement by and between John
          M. Longmire and the Company dated December 13, 1999 (3)

10.16.1   Employment and Severance Agreement by and between Larry
          G. Rampey and the Company dated December 13, 1999 (3)

10.16.2   Employment and Severance Agreement by and between Drake
          N. Smiley and the Company dated December 13, 1999 (3)

21        Subsidiaries of the Company (3)

27        Financial Data Schedule (3)

_______________

*         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 herewith.

     (b)  No report on Form 8-K was filed by RAM Energy, Inc.
          during the quarter ended December 31, 1999.
<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 30, 2000                     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.

Signatures                       Title                       Date
----------                       -----                       ----
WILLIAM W. TALLEY, II, PH.D.
William W. Talley, II, Ph.D. Chairman of the Board         March 30, 2000

LARRY E. LEE
Larry E. Lee                 President and Chief Executive March 30, 2000
                             Officer (principal executive
                             officer)

JOHN M. LONGMIRE
John M. Longmire             Senior Vice President and     March 30, 2000
                             Chief Financial Officer
                             (principal financial officer
                             and principal accounting
                             officer), Treasurer and
                             Secretary

M. HELEN BENNETT
M. Helen Bennett             Director                       March 30, 2000

GERALD R. MARSHALL
Gerald R. Marshall           Director                       March 30, 2000

JOHN M. REARDON
John M. Reardon              Director                       March 30, 2000


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
          RCP 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   Filed herewith electronically
          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    Filed herewith electronically
          Agreement by and between
          John M. Longmire and the
          Company dated December 13,
          1999

10.16.1   Employment and Severance    Filed herewith electronically
          Agreement by and between
          Larry G. Rampey and the
          Company dated December 13,
          1999

10.16.2   Employment and Severance    Filed herewith electronically
          Agreement by and between
          Drake N. Smiley and the
          Company dated December 13,
          1999

21        Subsidiaries of the Company Filed herewith electronically

27        Financial Data Schedule     Filed herewith electronically