RAM Energy Resources, Inc.

March 2007

2

Disclosure StatementThis document contains forward-looking statements within the meaning of Section 27A

of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact, including, without limitation, statements that address estimates of RAM’s proved reserves of oil, gas and natural gas liquids, its derivative positions, the impact of derivatives, exploration activities, capital spending, borrowing availability, financial position, business strategy, management’s objectives, future operations, and industry conditions, are forward-looking statements. Although RAM believes that the expectations reflected in such forward-looking statements are reasonable, RAM can give no assurance that such expectations will prove to be correct. Important factors that could cause actual results to differ materially from RAM’s expectations (“Cautionary Statements”) include, without limitation, the actual quantities of RAM’s oil and natural gas reserves, future production levels, future prices and demand for oil and natural gas, the results of RAM’s future exploration and development activities, future operating, development costs and future acquisitions, the effect of existing and future laws and governmental regulations (including those pertaining to the environment), the continued availability of capital and financing, and the political and economic climate of the United States as well as risk factors listed from time to time in our reports and documents filed with the SEC. All subsequent written and oral forward-looking statements attributable to RAM, or persons acting on RAM’s behalf, are expressly qualified in their entirety by the Cautionary Statements.

3

Company OverviewCompany Overview

Operations

Proved Reserves (12/31/05)Proved Reserves (12/31/05)18.8 MMBOE18.8 MMBOE

% Crude% Crude60%60%

% PUD% PUD30%30%

PV-10 ValuePV-10 Value$345.5 MM$345.5 MM

% of PV-10 Value Operated% of PV-10 Value Operated86%86%

Historical Drilling Success RateHistorical Drilling Success Rate93%93%

Latest Twelve Months Financials(1)

LTM RevenueLTM Revenue

$77.5 MM$77.5 MM

LTM EBITDALTM EBITDA

$33.8 MM$33.8 MM

IDID FieldField Proved Reserves (MMBOE)Proved Reserves (MMBOE)

11 Electra / BurkburnettElectra / Burkburnett 9.89.8

22 BoonsvilleBoonsville 3.03.0

33 EganEgan 1.71.7

44 North Texas Barnett ShaleNorth Texas Barnett Shale 0.40.4

55 VinegaroneVinegarone 1.11.1

AA Woodford / Barnett ShalesWoodford / Barnett Shales N / AN / A

BB Wolfcamp FormationWolfcamp Formation N / AN / A

11

22

33

44

AA

55

BB

11

22

33

44

AA

55

BB

(1) Unaudited; As of 9/30/06

4

• Founded in 1987 by current CEO and a former partnerFounded in 1987 by current CEO and a former partner

• Between 1987 and 2006,Between 1987 and 2006,Engaged in the acquisition, development, exploitation, Engaged in the acquisition, development, exploitation,

exploration, and production of oil & natural gas propertiesexploration, and production of oil & natural gas propertiesCompleted 20 acquisitions for a total amount in excess of $400 Completed 20 acquisitions for a total amount in excess of $400

millionmillionWG Acquisition in 2004 has yielded a 146% IRRWG Acquisition in 2004 has yielded a 146% IRR(1)(1) based on based on

effective acquisition price of $6.42 per BOEeffective acquisition price of $6.42 per BOECompleted multiple divestitures consistent with business Completed multiple divestitures consistent with business

strategy totaling more than $139 millionstrategy totaling more than $139 millionDrilled or participated in the drilling of 561 wells at a success Drilled or participated in the drilling of 561 wells at a success

rate of 93%rate of 93%

• Recent HighlightsRecent HighlightsMay 2006 – Through merger with Tremisis RAM became public May 2006 – Through merger with Tremisis RAM became public

companycompanyFebruary 2007 – Raised $30 million from sale of common stockFebruary 2007 – Raised $30 million from sale of common stock

Company HistoryCompany History

(1) Pre-tax IRR calculated using 12/31/05 PV-10 Value as a terminal value(1) Pre-tax IRR calculated using 12/31/05 PV-10 Value as a terminal value

5

Execution of Business StrategyExecution of Business Strategy

• Develop and exploit existing oil & natural gas propertiesDevelop and exploit existing oil & natural gas properties

• Accelerate North Texas Barnett Shale developmentAccelerate North Texas Barnett Shale development

• Increase emphasis on exploration activityIncrease emphasis on exploration activity

• Complete selective acquisitions and divestituresComplete selective acquisitions and divestitures

6

Electra / Burkburnett Boonsville

Barnett Shale Other Total

Proved Reserves (MBOE) 9,802 3,011 408 5,575 18,796Percent proved developed 61% 69% 6% 86% 70%Percent crude 97% 6% 2% 27% 60%

PV-10 Value (in $MM) (2) $182.9 $43.4 $10.4 $108.8 $345.5

Total net acres 12,190 7,313 6,800 11,945 38,248

(1) On an acreage basis(2) Proved reserves and PV-10 value of proved reserves as of 12/31/05

Principal Exploration ProjectsName Objective Net Acres

Wolfcamp Shale Gas 15,000

West Texas Barnett / Woodford Shale Gas 6,600

Principal Exploration ProjectsName Objective Net Acres

Wolfcamp Shale Gas 15,000

West Texas Barnett / Woodford Shale Gas 6,600

Property SummaryProperty Summary

Producing Properties

Exploration Projects

(1)(1)

7

$30.3 Million$30.3 Million

Electra /

Burkburnett

Electra /

Burkburnett

$9.7 MM

BoonsvilleBoonsville

$1.6 MM

Egan,

Vinegarone,

and Other

Egan,

Vinegarone,

and Other

$4.2 MM

West Texas

Woodford /

Barnett

Shale

West Texas

Woodford /

Barnett

Shale

$0.5 MM

Wolfcamp

Formation

Wolfcamp

Formation

$7.4 MM

Capitalized

G & G Cost

Capitalized

G & G Cost

$2.9 MM

Proved Drilling Cap Ex Non-Proved Drilling Cap Ex Non-Drilling Cap Ex

2007E Capital Expenditure Detail2007E Capital Expenditure Detail

$4.0 MM

North

Texas

Barnett

Shale

8

Growth in Capital ExpendituresGrowth in Capital Expenditures

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

2004 2005 2006 2007E

Cap Ex for Proven Reserves Cap Ex for Unproven Projects

(dollars in millions)

• Pursuant to strategy targeting growth, RAM has steadily increased CAPEX to unproven projects

• CAPEX for 2007 allocates 65 percent for spending on proved reserves and 35 percent for spending on unproven projects

$

9

(1) February 2007 RAM sold 7.5 million shares of common stock at a price of $4.00 per share for gross

proceeds of $30 million or $28.05 million after deducting underwriting discount.

(103.0)

• Financial Liquidity AnalysisFinancial Liquidity Analysis

CashCashPlus: Total Credit LinePlus: Total Credit LineLess: Outstanding CreditLess: Outstanding Credit

• Operational LiquidityOperational Liquidity

LTM Cash Flow from OperationsLTM Cash Flow from Operations2007E Capital Expenditures2007E Capital Expenditures

(2) $300 million Sr. Secured Credit Facility with initial borrowing limit of $140 million

provides expanded financial flexibility for growth

LiquidityLiquidity

Actual($millions)

6.7140.0

29.5(30.3)

43.7Financial LiquidityFinancial Liquidity

(2)

12/31/06Adjusted for

Offering($millions)

140.0 34.8

(103.0)

(1)

71.8

(3)

(3) Last twelve months ended 9/30/06

10

• 100% WI ownership & 100% WI ownership & operational controloperational control

• Includes assets that help Includes assets that help maintain drilling schedule maintain drilling schedule and control costs: gas and control costs: gas plant, gathering system, plant, gathering system, one drilling rig, five one drilling rig, five workover rigs, and a supply workover rigs, and a supply companycompany

(1) At 9/30/06

• Wichita and Wilbarger Counties, TexasWichita and Wilbarger Counties, Texas

• 3Q06 production of 169,730 BOE from 3Q06 production of 169,730 BOE from 503 producers503 producers

• 79 wells drilled in 200679 wells drilled in 2006

• 151 identified PUD drilling locations151 identified PUD drilling locations(1) (1)

with a projected D&C of $5.82 per BOEwith a projected D&C of $5.82 per BOE

Electra / BurkburnettElectra / Burkburnett

11

0

100

200

300

400

500

600

700

800

900

1,000

2006 2007 2008 2009 2010 2011 2012 2013 2014

Year

PDP PUD 2006 PUD 2007 PUD 2008

• Average well statistics:Average well statistics: Drill & completeDrill & complete

$128,000$128,000 EUREUR

22,000 BOE22,000 BOE Economic lifeEconomic life

20 years20 years IRR per well @$60/Bbl > 100%IRR per well @$60/Bbl > 100% IRR per well @$50/Bbl > 100%IRR per well @$50/Bbl > 100%

• PUD inventory sufficient to maintain or PUD inventory sufficient to maintain or increase production over the next increase production over the next several years, thereby sustaining RAM’s several years, thereby sustaining RAM’s stable cash flow basestable cash flow base

• 2007E Capital expenditures for Electra / 2007E Capital expenditures for Electra / Burkburnett budgeted for $9.7 million Burkburnett budgeted for $9.7 million (38% of total capital expenditure budget)(38% of total capital expenditure budget)

Forecast of Electra/Burkburnett

Production (1)

Pro

du

ctio

n (

MB

oe

)

Electra / BurkburnettElectra / BurkburnettProduction and Capital ExpendituresProduction and Capital Expenditures

Electra/Burkburnett Type CurveInital Rate - 30 BOEPD

1

10

100

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36

Months

BO

EP

D

Based on estimate of proved reserves and

associated capital spending at 12/31/05.

(1)

12

• Jack and Wise Counties, TexasJack and Wise Counties, Texas

• 3Q06 production of over 3Q06 production of over 44,160 BOE from 88 producers 44,160 BOE from 88 producers

• 20 identified drilling locations20 identified drilling locations Avg. D&C cost:Avg. D&C cost:

$625,000$625,000 Avg. EUR:Avg. EUR:

115,000 BOE115,000 BOE

• 25 miles of gas gathering 25 miles of gas gathering systemsystem

• Proved reserves of 3,011 Proved reserves of 3,011 MBOEMBOE(1)(1)

• Capital expenditure budget of Capital expenditure budget of $1.6 million in 2007$1.6 million in 2007

• Producing wells hold Barnett Producing wells hold Barnett Shale rightsShale rights

BoonsvilleBoonsville

(1) As of December 31, 2005

13

• Jack and Wise Counties, TexasJack and Wise Counties, Texas

• 27,700 gross acres27,700 gross acres

• 6,800 net acres6,800 net acres

• All acreage is HBPAll acreage is HBP

• 90% of the acreage located in the 90% of the acreage located in the Core areaCore area

• 325 potential horizontal drilling 325 potential horizontal drilling locations on 80-acre spacinglocations on 80-acre spacing

• 9 gross producing wells existing9 gross producing wells existing

• 35 square miles of 3-D seismic 35 square miles of 3-D seismic acquired and interpretedacquired and interpreted Budgeted to add another 60 square Budgeted to add another 60 square

miles during 2007miles during 2007

• Partners are EOG and DevonPartners are EOG and Devon

RAM’s Barnett Shale operating area

Barnett ShaleBarnett Shale

Core

Tier 1

Tier 2

14

• Approximately 23,500 gross acres Approximately 23,500 gross acres (5,600 net) – RAM WI=24%(5,600 net) – RAM WI=24%

• More than 290 potential drilling More than 290 potential drilling locations on 80-acre spacinglocations on 80-acre spacing

• One producing well – Ashe 1H One producing well – Ashe 1H completed in March 2006completed in March 2006

• No PUD locations booked to dateNo PUD locations booked to date• 27 square miles of 3-D seismic27 square miles of 3-D seismic

Additional 60 square miles planned Additional 60 square miles planned for 2007for 2007

Ongoing seismic review supports 11 Ongoing seismic review supports 11 additional drilling locations to dateadditional drilling locations to date

• RAM has proposed its first two RAM has proposed its first two wells to EOG; EOG has wells to EOG; EOG has consented to drill both wellsconsented to drill both wells

• Right to propose wellsRight to propose wells If EOG declines to participate, RAM If EOG declines to participate, RAM

can drill wells on a non-consent can drill wells on a non-consent basisbasis

Barnett Shale (EOG Area)Barnett Shale (EOG Area)

Ashe 1H WellAshe 1H Well

Planned 2007Planned 2007

Acquired 2006Acquired 2006

SeismicSeismic

Ashe 1HAshe 1H

15

Barnett Shale (EOG Area)Barnett Shale (EOG Area)Joint Operating Agreement (JOA) TermsJoint Operating Agreement (JOA) Terms

Any working interest owner may

propose a well

Non-proposing parties have 30 days to elect to participate or

opt for “non-consent”

Participate “Non Consent”

Must spud well within 90 days

Estimated cost to drill andComplete, $3 million (MM) per well

Must spud well within 90 days

Estimated cost to drill and complete, $3 million (MM) per well

EOG=66%

Other=10%

RAM=24%

$2.0MM $0.3MM$0.7MM

EOG=0%

Other=10%

RAM=90%

$0.0MM $0.3MM$2.7MM

(1)

(1) Assumes “other” working interest partners elect to maintain existing working interests totaling approximately 10%

RAM operates or other option

EOGOperates

Allocation of costs by working interest Allocation of costs by working interest

16

• Approximately 3,500 gross acres (1,200 Approximately 3,500 gross acres (1,200 net) – RAM WI=36%net) – RAM WI=36%

• More than 35 potential drilling locations More than 35 potential drilling locations on 80-acre spacing on 80-acre spacing

• 7 producing wells to date7 producing wells to date

• 4 PUD locations booked to date4 PUD locations booked to date

• 8 square miles of 3-D seismic8 square miles of 3-D seismic

Ongoing seismic review supports 8 Ongoing seismic review supports 8 additional drilling locations to dateadditional drilling locations to date

• Continuous drilling clause in the Continuous drilling clause in the participation agreementparticipation agreement

Devon must drill a well 120 days after the Devon must drill a well 120 days after the completion of the previous wellcompletion of the previous well

Barnett Shale (Devon Area)Barnett Shale (Devon Area)

Additional LocationsAdditional Locations

PDP - (Rawle 4H, Rawle A 1H, Burress Unit 1H, Burress Unit 2H, Etta Burress 1H, PDP - (Rawle 4H, Rawle A 1H, Burress Unit 1H, Burress Unit 2H, Etta Burress 1H,

PUD - (Burress Unit 3H, Burress Unit 4H, North of Paradise 2H, Fitzgerald 5-2H)PUD - (Burress Unit 3H, Burress Unit 4H, North of Paradise 2H, Fitzgerald 5-2H)

North of Paradise 1H, Fitzgerald 5H)North of Paradise 1H, Fitzgerald 5H)

17

• 6 wells drilled to date6 wells drilled to date

• Average initial production = 1,921 Average initial production = 1,921 MCFEPDMCFEPD

• Average EUR = 1.9 BcfeAverage EUR = 1.9 Bcfe

• Average well cost = $1.7 MMAverage well cost = $1.7 MM

• Finding cost = $0.90 / McfeFinding cost = $0.90 / Mcfe

Barnett Shale (Devon Area)Barnett Shale (Devon Area)Rawle / Burress LeaseRawle / Burress Lease

Well NameWell NameCompletion Completion

DateDate

Initial Initial Production Production (MCFEPD)(MCFEPD)

Rawle No. 4HRawle No. 4H Feb. 2004Feb. 2004 1,3021,302

Rawle A No. 1HRawle A No. 1H Mar. 2005Mar. 2005 2,1242,124

Burress No. 1HBurress No. 1H Nov. 2005Nov. 2005 2,3842,384

Burress No. 2HBurress No. 2H Feb. 2006Feb. 2006 2,2392,239

Etta Burress No. 1Etta Burress No. 1TL Dickenson 1HTL Dickenson 1H

Sept. 2006Sept. 2006Awaiting Awaiting

CompletionCompletion

1,5581,558TBDTBD

Barnett Shale Type Curve

10

100

1,000

10,000

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36

Months

MC

FE

PD

(1)

Composite of industry horizontal wells in Barnett Shale adjusted for RAM’s Rawle/Burress well performance(1)

18

• Southwest TexasSouthwest Texas

• Potential high-impact Potential high-impact explorationexploration

• RAM has leased & optioned RAM has leased & optioned 15,000 net acres15,000 net acres

• 100% working interest100% working interest

• Two test wells vertically drilledTwo test wells vertically drilled

• Stimulation, recovery of frac Stimulation, recovery of frac fluid and testing underway on fluid and testing underway on two wellstwo wells

• If commercial, significant If commercial, significant potential upside on 80 acre potential upside on 80 acre spacingspacing

Wolfcamp FairwayWolfcamp Fairway

19

• Reeves County, TexasReeves County, Texas

• Exploration play – 84,000 gross Exploration play – 84,000 gross acres (6,600 net)acres (6,600 net)

• Estimated thickness of the Barnett is Estimated thickness of the Barnett is between 400’ – 700’ and the between 400’ – 700’ and the Woodford varies from 200’ – 400’Woodford varies from 200’ – 400’

• Keys to success are horizontal Keys to success are horizontal drilling and fracture stimulationdrilling and fracture stimulation

• Four wells drilled under farmout Four wells drilled under farmout agreementsagreements

• 3-D seismic shot over 10 square 3-D seismic shot over 10 square mile areamile area

Alpine Area

3 wells drilled

J. Cleo Thompson

1 well drilled

Barnett and Woodford ShaleBarnett and Woodford ShaleThompson and Alpine AreasThompson and Alpine Areas

20

EV / Proved Reserves (BOE)(1) (3) (4) EV as % of PV-10(2) (3) (4)

Attractive Valuation vs. PeersAttractive Valuation vs. Peers

(1) Represents proved reserves as of most recent SEC proved reserve filing(2) Represents PV-10 value as of most recent SEC proved reserve filing(3) RAM EV adjusted to reflect offering of common stock 2/8/07(4) Share prices as of close 3/12/07

$14.20

$25.13$30.09

$25.13

$52.56

$21.28

$13.60

$37.89

$0.00

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$70.00

77%

221%189%

221%

318%

63%

248%

94%

0%

100%

200%

300%

400%

21

EV / LTM Daily Production (BOEPD)(1) (2) (3) (4)EV / LTM EBITDA (3) (4)

Attractive Valuation vs. PeersAttractive Valuation vs. Peers

(1) “Herold Mean” are mean results of search of J. S. Herold’s database of industry transactions in the last twelve months of Gulf Coast Onshore, Mid-Continent, and Permian Basin transactions between $25 million and $250 million

(2) Estimated 2006 daily production from research reports(3) RAM EV adjusted to reflect offering of common stock 2/8/07(4) Share prices as of close 3/12/07

7.9x

10.9x11.5x

14.1x

10.2x

5.7x

10.9x

16.4x

0.0x

5.0x

10.0x

15.0x

20.0x

25.0x$221,259

$193,132

$51,255

$134,613

$158,764$151,805

$158,764

$71,399

$0

$50,000

$100,000

$150,000

$200,000

$250,000

ARD

CRZOCW

EI

TXCOPLLL

Mea

n

Med

ian

RAME

22

• Stable cash flow baseStable cash flow base

• Compelling valuation vs. peersCompelling valuation vs. peers

• Significant management and technical experienceSignificant management and technical experience

• Balanced oil & natural gas exposureBalanced oil & natural gas exposure

• Large inventory of growth opportunitiesLarge inventory of growth opportunities

• High degree of operating controlHigh degree of operating control

• Proven value creation through both acquisitions Proven value creation through both acquisitions and drillbitand drillbit

• Management’s substantial ownership of RAM stock supports Management’s substantial ownership of RAM stock supports alignment with shareholder interestalignment with shareholder interest

Summary of Investment ConsiderationsSummary of Investment Considerations

25

Quarterly Results (unaudited)Quarterly Results (unaudited)

($ in thousands) 3 Months Ended LTM EndedDec 31, 2005 Mar 31, 2006 Jun 30, 2006 Sep 30, 2006 Sep 30, 2006

OPERATING REVENUESOil & Natural Gas Sales $18,103 $16,810 $17,973 $18,267 $71,153Realized/Unrealized Gains (Losses) on Derivatives 4,918 1,408 (4,178) 3,878 6,026Other (132) 244 180 42 334

Total Revenues 22,889 18,462 13,975 22,187 77,513

OPERATING EXPENSESOil & Natural Gas Production Taxes 860 810 874 843 3,387Oil & Natural Gas Production Expenses 4,646 4,306 4,607 4,309 17,868Amortization and Depreciation 3,759 3,213 3,311 3,495 13,778Accretion Expense 293 133 132 133 691Share-based Compensation 0 0 2,218 0 2,218General & Administrative, Overhead, and Other Expenses 2,325 1,959 2,088 2,304 8,676

Total Operating Expenses 11,883 10,421 13,230 11,084 46,618

Operating Income 11,006 8,041 745 11,103 30,895

OTHER INCOME (EXPENSE)Interest Expense (3,845) (3,529) (5,778) (3,906) (17,058)Interest Income 34 27 82 129 272

INCOME BEFORE INCOME TAXES 7,195 4,539 (4,951) 7,326 14,109

INCOME TAX PROVISION 3,028 1,725 (1,882) 3,081 5,952

NET INCOME $4,167 $2,814 ($3,069) $4,245 $8,157

EBITDA $6,881 $8,220 $8,837 $9,831 $33,768

($ in thousands) 3 Months Ended LTM EndedDec 31, 2005 Mar 31, 2006 Jun 30, 2006 Sep 30, 2006 Sep 30, 2006

OPERATING REVENUESOil & Natural Gas Sales $18,103 $16,810 $17,973 $18,267 $71,153Realized/Unrealized Gains (Losses) on Derivatives 4,918 1,408 (4,178) 3,878 6,026Other (132) 244 180 42 334

Total Revenues 22,889 18,462 13,975 22,187 77,513

OPERATING EXPENSESOil & Natural Gas Production Taxes 860 810 874 843 3,387Oil & Natural Gas Production Expenses 4,646 4,306 4,607 4,309 17,868Amortization and Depreciation 3,759 3,213 3,311 3,495 13,778Accretion Expense 293 133 132 133 691Share-based Compensation 0 0 2,218 0 2,218General & Administrative, Overhead, and Other Expenses 2,325 1,959 2,088 2,304 8,676

Total Operating Expenses 11,883 10,421 13,230 11,084 46,618

Operating Income 11,006 8,041 745 11,103 30,895

OTHER INCOME (EXPENSE)Interest Expense (3,845) (3,529) (5,778) (3,906) (17,058)Interest Income 34 27 82 129 272

INCOME BEFORE INCOME TAXES 7,195 4,539 (4,951) 7,326 14,109

INCOME TAX PROVISION 3,028 1,725 (1,882) 3,081 5,952

NET INCOME $4,167 $2,814 ($3,069) $4,245 $8,157

EBITDA $6,881 $8,220 $8,837 $9,831 $33,768

27

Derivative Positions

Year per day Price per day Price per day Price per day Price2007 1,500 $52.67 1,500 $73.11 4,000 $7.61 4,000 $11.492008 950 $53.69 950 $86.08 4,000 $6.87 4,000 $13.532009 800 $50.00 800 $65.00 4,000 $7.00 4,000 $12.40

Year Per day Price Per day Price2007 - - 4,000 $12.002008 - - - -2009 800 $75.00 - -

Crude oil floors/ceilings 2007 are for March through December, Natural gas floors/ceilings 2007 are for April through December. Natural gas Secondary floors for 2007 are for April through October,

Crude oil floors/ceilings and Natural gas floors/ceilings 2008 are for calendar year. Crude oil floors/ceilings and Natural gas floors/ceilings 2009 are January through March. Crude oil secondary floors 2009 are January through March.

Crude Oil (Bbls) Natural Gas (Mmbtu)Floors Ceilings

Secondary Floors Secondary Floors

Floors Ceilings

As of February 28, 2007