RAM Energy Resources, Inc.

APRIL 2007

Fourth Quarter and Year-End 2006 Review

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

Call AgendaCall Agenda

• Fourth quarter results and year-end summaryFourth quarter results and year-end summary

• Year-end reserves, production replacement and Year-end reserves, production replacement and finding costfinding cost

• Balance sheet/liquidityBalance sheet/liquidity

• 2007E capital budget2007E capital budget

• Operational updateOperational update

• Attractive valuationAttractive valuation

4

Highlights2006 Highlights

•Oil and gas sales rose 3% to $68.0 million;

•Operating income increased to $23.3 million, or 67%, compared to 13.9 million in 2005;

•Net income rose to $5.0 million vs. $543,000 in 2005;

•Cash flow from operations, a non-GAAP measure, was $18.1 million vs. $23.0 million in 2005.

•Average daily production was 3,533 BOE vs. 3,848 BOE in 2005;

4Q 2006 Highlights

•RAM reports income of $1.1 million or $0.03 a share;

•Cash flow from operations (a non-GAAP measure) was $3.2 million vs. $5.4 million in fourth quarter 2005;

5

Highlights4Q 2006 Highlights

•Fourth quarter production of 317,000 BOE was negatively impacted by weather

related curtailments. Curtailments also impacted 1Q07, however, daily production

is estimated to have averaged approximately 3,500 BOE, or a total for the quarter

of 315,000 BOE;

•Capital spending of $6.6 million in the quarter raises the total for the year to $28.1

million, over 100% above spending of $13.5 million in 2005.

Current Quarter Highlights

•RAM’s borrowing base was reaffirmed at $140 million by the company’s

commercial lenders at the regularly scheduled semi-annual redetermination;

•RAM completed its offering of 7.5 million shares of common stock in February,

adding substantially to liquidity. Adjusted for RAM’s recent offering liquidity at

3/31/07 is estimated at $68 million;

6

Highlights

Current Quarter Highlights

•In its Wolfcamp Shale exploration play, the company drilled two vertical wells

which are currently undergoing fracture stimulation and testing;

•In February, RAM proposed its third Barnett Shale well of 2007 to EOG; Devon’s

first well of 2007 in jointly held Barnett Shale acreage has been drilled and is

awaiting completion.

7

93%

Drilling Success Rate

(2) Excluding wells in progress

(1) Gross wells drilled

(1)2006

Total Wells Drilled1987- 2006

Producers

Dry Holes

Drilling or Completing

Total

Success Ratio

80 512

41

88

92 561

95%(2)

(1)

4

8

(1) RAM realized prices at year-end 2006 used in the calculation of PV-10

(2) Pre-tax

(3) PV-10 value calculated using year-end 2006 reserve volumes and price realizations at March 30, 2007

Year-end proved reserves 18.5 MMBOE

Oil – 59% 10.8 MMBbls

NGL – 11% 2.1 MMBbls

Natural gas – 30% 33.2 Bcf

Proved developed reserves 13.1 MMBOE

Proved developed reserves as

percent of total 71%

2006 year-end prices

Oil $58.74 Bbl

NGL $36.51 Bbls

Natural gas $5.51 MMBtu

2006 PV-10 $270 Million

2006 standardized measure $179.7 Million

PV-10 value – using current pricing $330 Million

2006 Reserves2006 Reserves

(2)

(1)

(3)

9

(1) From continuing operations

20062006 Production Replacement Production Replacement and Finding Costand Finding Cost

(1)

2006 production 1.3 MMBOE

Reserve additions from extensions/

discoveries, net revisions and

acquisitions 946 MBOE

2006 all-sources finding cost $27.18/BOE

Three-year ended 2006 average all-

sources finding cost $ 8.15/BOE

2006 production replacement 73%

Three-year ended 2006 average

production replacement rate 437%

10

Electra / Burkburnett Boonsville

Barnett Shale Other Total

Proved Reserves (MBOE) 9,788 2,862 882 4,920 18,452Percent proved developed 61% 69% 6% 86% 71%Percent crude 96% 5% 4% 25% 70%

PV-10 Value (in $MM) (2) $172.7 $26.6 $12.1 $58.6 $270.0

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 12/31/06

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)

11

$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

12

• Financial Liquidity AnalysisFinancial Liquidity Analysis

CashCashPlus: Total Credit LinePlus: Total Credit LineLess: Outstanding CreditLess: Outstanding Credit (103.0)

(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)

(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

43.7Financial LiquidityFinancial Liquidity

(2)

12/31/06 3/31/07 Estimated($millions)

140.0 31.0 (1)

68.0

13

• 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 12/31/06

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

• 4Q06 production of 170.2 MBOE from 4Q06 production of 170.2 MBOE from 536 producers536 producers

• 79 wells drilled in 200679 wells drilled in 2006

• 200 identified PUD drilling locations200 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

14

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 12/31/06.

(1)

15

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

• 4Q06 production of over 44.1 4Q06 production of over 44.1 MBOE from 88 producers MBOE 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 2,862 Proved reserves of 2,862 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, 2006

16

• 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

17

• 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 three RAM has proposed its first three wells to EOG; EOG has wells to EOG; EOG has consented to drill the first two consented to drill the first two well; expected to respond to third well; expected to respond to third proposal by mid-Aprilproposal by mid-April

• 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

18

• 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, TL Dickenson 1H - PDNP)North of Paradise 1H, Fitzgerald 5H, TL Dickenson 1H - PDNP)

19

• 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)

20

• 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

21

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 3/28/07

$31.07

$16.12$17.04

$48.39

$26.84 $27.89 $26.84

$15.23

$0.00

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

ARD

CRZOCW

EI

TXCO

PLLL

Mea

n

Med

ian

RAME

104%

236%200%

236%

294%

110%

276%

87%

0%

100%

200%

300%

400%

22

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) Production based on companies 2006 Annual 10K(3) RAM EV adjusted to reflect offering of common stock 2/8/07(4) Share prices as of close 3/28/07

15.9x 17.2x

9.9x 9.5x

15.7x13.6x

15.7x

8.4x

0.0x

5.0x

10.0x

15.0x

20.0x $253,035

$203,441

$54,288

$125,106

$169,534$161,081 $169,534

$85,763 $79,530

$0

$100,000

$200,000

$300,000

ARD

CRZOCW

EI

TXCOPLLL

Mea

n

Med

ian

Harold

Mea

nRAM

E

23

Attractive Valuation vs. Peers

0.86x

4.27x

1.25x

2.92x 3.13x

2.49x2.92x

1.06x

0.00x

1.00x

2.00x

3.00x

4.00x

5.00x

Price / NAV (1) (2) (3)

(1) Represents proved reserves and PV-10 value as of most recent SEC filing of reserves

(2) Share prices as of close 3/28/07(3) RAM EV adjusted to reflect offering of common stock 2/8/07

24

• 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

RAM Energy Resources, Inc.

27

($’($’ millions)millions) Percent Percent 20052005 2006 2006 Change Change

Net RevenueNet Revenue 55,39955,399 70,24470,244 27%27%

Operating ExpensesOperating Expenses 41,51141,511 46,99046,990 13%13%

Operating IncomeOperating Income 13,88813,888 23,25423,254 67%67%

Net Interest ExpenseNet Interest Expense 12,53912,539 16,74116,741 34%34%

Net IncomeNet Income 543 543 5,0485,048 830%830%

Per Share IncomePer Share Income .07 .07 0.21 0.21 186%186%

Summary Financials – 2006 VS 2005Summary Financials – 2006 VS 2005

(1) At year-end 2005 RAM Energy, Inc. was a private company. In May 2006, RAM Energy merged with (1) At year-end 2005 RAM Energy, Inc. was a private company. In May 2006, RAM Energy merged with

Tremisis, a public “blank check” company. The combined entity changed its name to RAM Energy Tremisis, a public “blank check” company. The combined entity changed its name to RAM Energy

Resources at the time of the merger.Resources at the time of the merger.

(1)

28

Production Volumes and Expenses

Fourth Quarter Ended December 31 Percent

2005 2006 Change(in thousands, except per unit amounts)

Production volumes:Oil and condensate (MBbls) 193 176 (8.9)Natural gas liquids (MBbls) 42 40 (4.8)Natural gas (MMcf) 571 603 5.6 Total (Mboe) 331 317 (4.2)

Expenses (dollars per BOE):Oil and natural gas production taxes 2.60 2.53 (2.7)Oil and natural gas production expenses 14.03 15.91 13.4General and administrative 7.02 9.30 32.5Interest (excluding amortization) 11.61 12.10 4.2

Total (per BOE) 35.26 39.84 13.0

29

Production Volumes and Expenses

(1) Production for the year ended December 31, 2006 is impacted by exercise ofreversionary interest in September 2005.

Year Ended December 31 Percent2005 2006 Change

(in thousands, except per unit amounts)

Production volumes:Oil and condensate (MBbls) 787 752 (4)

Natural gas liquids (MBbls) (1) 170 143 (16)Natural gas (MMcf) 2,681 2,365 (12) Total (Mboe) 1,405 1,290 (8)

Expenses (dollars per BOE):

Oil and natural gas production taxes 2.36 2.58 24Oil and natural gas production expenses 11.46 14.16 18General and administrative 6.13 7.21 38Interest (excluding amortization) 8.98 12.40 26 Total (per BOE) 28.93 36.35 26

30

Net Realized Prices Before/After Derivatives

Percent 2005 2006 Change

(dollars per unit of production)

Average realized prices (before effects of derivatives):

Oil and condensate (per Bbl) 55.37 58.09 4.9Natural gas liquids (per Bbl) 39.75 36.35 (8.6)Natural gas (per Mcf) 6.82 5.42 (20.5) Total per BOE 48.23 47.21 2.1

Effect of contract premiums and settlement of derivatives contracts:

Oil and condensate (per Bbl) (4.01) (0.12) 97.0Natural gas liquids (per Bbl) - - -Natural gas (per Mcf) (2.95) 0.23 107.8 Total per BOE (8.78) 0.37 104.2

Average realized prices (after effects of derivatives):

Oil and condensate (per Bbl) 51.36 57.97 12.9 Natural gas liquids (per Bbl) 39.75 36.35 (8.6)Natural gas (per Mcf) 3.87 5.64 45.7 Total per BOE 39.48 47.57 20.5

Fourth Quarter Ended December 31

31

Net Realized Prices Before/After Derivatives

Percent2005 2006 Change

Average realized prices (before effects of derivatives):

Oil and condensate (per Bbl) 53.75 63.82 19Natural gas liquids (per Bbl) 36.33 40.33 11Natural gas (per Mcf) 6.61 6.02 (9) Total per BOE 47.16 52.74 12

Effect of contract premiums and settlement of derivatives contracts:

Oil and condensate (per Bbl) (3.30) (5.78) 75Natural gas liquids (per Bbl) - - -Natural gas (per Mcf) (1.04) (0.13) (88) Total per BOE (3.84) (3.61) (6)

Average realized prices (after effects of derivatives):

Oil and condensate (per Bbl) 50.45 58.04 15Natural gas liquids (per Bbl) 36.33 40.33 11Natural gas (per Mcf) 5.57 5.89 6 Total per BOE 43.31 49.13 13

Year Ended December 31

(dollars per unit of production)

32

Fourth Quarter ResultsFourth Quarter Results

4Q06 4Q05 4Q06 4Q05 4Q06 4Q05 4Q06 4Q054Q06 4Q05 4Q06 4Q05 4Q06 4Q05 4Q06 4Q05

$4.20$4.20

Net Income Net Income (Loss) (Loss)

(1) Cash flow is a non-GAAP measure. See appendix for a reconciliation of this non-GAAP measure to the corresponding (1) Cash flow is a non-GAAP measure. See appendix for a reconciliation of this non-GAAP measure to the corresponding

GAAP amount. GAAP amount.

($ In Millions)($ In Millions)

(1)(1)Non-GAAPNon-GAAPOil & Natural Oil & Natural Gas SalesGas Sales Cash Flow From Cash Flow From

Operations Operations

$18.1$18.1

$0.03$0.03

$0.54$0.54

Net Income Net Income Per SharePer Share

$1.05$1.05

$15.0$15.0

$5.4$5.4

$3.2$3.2

33

2006 Results2006 Results

2006 2005 2006 2005 2006 2005 2006 20052006 2005 2006 2005 2006 2005 2006 2005

$0.5$0.5

Net Income Net Income

(1) Cash flow is a non-GAAP measure. See appendix for a reconciliation of this non-GAAP measure to the corresponding (1) Cash flow is a non-GAAP measure. See appendix for a reconciliation of this non-GAAP measure to the corresponding

GAAP amount. GAAP amount.

($ In Millions)($ In Millions)(1)(1)Non-GAAPNon-GAAPOil & Natural Oil & Natural

Gas SalesGas Sales Cash Flow From Cash Flow From Operations Operations

$66.24$66.24 $0.20$0.20

NMNM

Net Income Net Income Per SharePer Share

$5.05$5.05$68.02$68.02$23.0$23.0

$18.1$18.1

(2)(2)

(2) At year end 2005, RAM Energy was a privately held company with 2,354 weighted average fully diluted shares outstanding. In 2006 RAM became a (2) At year end 2005, RAM Energy was a privately held company with 2,354 weighted average fully diluted shares outstanding. In 2006 RAM became a

publicly traded company and had 25.0 weighted average fully diluted shares outstanding at year end. In February 2007 RAM completed a public publicly traded company and had 25.0 weighted average fully diluted shares outstanding at year end. In February 2007 RAM completed a public

offering of 7.5 million shares of common stock. . offering of 7.5 million shares of common stock. .

Up 3%Up 3% Up 910%Up 910% Up 21%Up 21%

34

Non-GAAP Financial Measure

Cash flow, a non-GAAP measure, represents cash provided by operating activities before the impact of discontinued operations, changes in working capital items related to operating activities, and further adjusted for unrealized gains or losses on derivative transactions This non-GAAP measure is presented because management believes it is a useful adjunct to cash provided by operating activities under accounting principles generally accepted in the United States (GAAP). This non-GAAP cash flow measure is widely accepted as a financial indicator of an oil and gas company’s ability to generate cash which is used to internally fund exploration and development activities and to service debt. This non-GAAP measure is not a measure of financial performance under GAAP and should not be considered as an alternative to cash provided (used) by operating, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity.

35

Cash FlowReconciliation of cash flow from operations (a non-GAAP measure)

to GAAP cash flow from operating activities

2006 2005(in thousands) (in thousands)

Cash flow from operations (a non-GAAP measure) $3,167 $5,355Plus: working capital changes 2,042 2,388Less: deferred income taxes on share-based compensation classified as financing activities (34) -Net cash provided by operating activities per condensed consolidated statements of cash flow 5,243 7,743

Cash flow from operations (a non-GAAP measure) $3,167 $5,355Less: realized (losses) on derivatives 116 (3,293)Less: unrealized gains (losses) on derivatives per condensed consolidated statements of cash flow 365 8,211Cash flow from operations (a non-GAAP measure) excluding realized and unrealized gains (losses) on derivatives 2,686 437

Fourth Quarter Ended December 31

36

Year Ended December 31

(in thousands)2006 2005

(in thousands)

Cash flow from operations (a non-GAAP measure) $18,144 $22,999Plus: working capital changes 11,516 (4,640)Less: deferred income taxes on share-based compensation classified as financing activities (877) -Net cash provided by operating activities per condensed consolidated statements of cash flow 30,537 18,359

Cash flow from operations (a non-GAAP measure) $18,144 $22,999Less: realized (losses) on derivatives (4,650) (5,393)Less: unrealized gains (losses) on derivatives per condensed consolidated statements of cash flow 6,239 (6,302)Cash flow from operations (a non-GAAP measure) excluding realized and unrealized gains (losses) on derivatives 16,555 34,694

Cash FlowReconciliation of cash flow from operations (a non-GAAP measure)

to GAAP cash flow from operating activities

37

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 cover March through December, Natural gas floors/ceilings 2007 cover April through December. Natural gas Secondary floors for 2007 cover 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.

Secondary Floors Secondary Floors

Floors CeilingsCrude Oil (Bbls) Natural Gas (Mmbtu)

Floors Ceilings

As of February 28, 2007

38

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