RAM Energy Resources, Inc. March 2008 TM Fourth Quarter and Year-End 2007 Review

RAM Energy Resources, Inc.

March 2008

TM

Fourth Quarter and Year-End 2007 Review

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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.

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2007 Highlights

• Production rose 10% to 1.4 million barrel equivalents (BOE) of oil and natural gas vs. 1.3 million BOE in 2006.

• Oil and gas sales rose 20% to $81.9 million.

• Operating income, inclusive of substantial non-cash unrealized losses from derivatives, was $10.7 million.

• Cash flow from operations (a non-GAAP measure) was $23.7 million vs. $18.1 million in 2006.

• RAM reported net loss of $1.3 million, which included non-cash unrealized losses from derivatives of $10.1 million (a $6.4 million after tax impact) most of which was incurred in the fourth quarter as a result of the unprecedented rise in the price of oil vs. net income of $5.0 million in 2006 which benefited from unrealized derivative gains.

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Fourth Quarter 2007 Highlights

• Fourth quarter 2007 production volumes grew 37% to 436 MBOE.

- Average daily production in fourth quarter 2007 was 4,739 BOE vs. fourth quarter 2006 level of 3,446 BOE.

• The average realized price of oil, NGLs and natural gas were substantially higher in fourth quarter 2007 vs. fourth quarter 2006.

- Oil up 52.8%- NGL up 63.3%- Natural gas up 17.2%

• Higher production combined with increased product prices drove oil and gas sales to $29.4 million, 96% above last year’s sales.

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Fourth Quarter 2007 Highlights

• RAM reported a net loss of $6.3 million or $0.13 a share, which included non-cash unrealized losses from derivatives of $8.0 million (a $5.0 million after tax impact).

• Cash flow from operations (a non-GAAP measure) in the quarter was $7.6 million vs. $2.3 million in fourth quarter 2006.

• Capital spending of $ 311 million in the quarter raises the total for the year to $345 million.

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December 2007 Highlights Post Ascent Acquisition

• RAM’s consolidated production for December 2007, the first full month of production following the acquisition of Ascent, totaled 203,875 BOE including a contribution of 90,930 BOE production by Ascent.

• December average daily production from the combined entity was 6,577 BOE.

• RAM’s EBITDA for December was $7.5 million.

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• Preliminary 2008 capital spending budget of $80 million targets growth in production and reserves.

• 110,685 total net undeveloped conventional and unconventional acres represent potential opportunities for future growth.

2008 Operating Highlights2008 Operating Highlights

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2008 Growth Projects

• South Texas 2 wells drilled and producing 1 well drilling 1 well completing 6 additional wells to drill

• Barnett Shale activity accelerating- 3 wells awaiting pipeline connection- 1 well awaiting completion- 1 well drilling- 5 wells proposed


• West Virginia Rig contracted to initiate drilling program beginning early second quarter in company’s Devonian Shale play 6 wells permitted 8 additional wells programmed for full year

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• Electra/Burkburnett

Drilling five wells per month with company owned rig

Recompletion program underway

• Fitts/Allen

- 1 well drilled and completing

- 1 well currently drilling

- 10 wells scheduled to be drilled

- 1 new disposal well to be drilled


Production Maintenance ProjectsProduction Maintenance Projects

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Company OverviewCompany Overview- Areas of Operation

= Rig under contract

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2008 Non-Acquisition Capital ExpenditureBudget by Economic Risk

60%

33%

7%

Development (1) Exploitation (2) Exploration (3)

(1) Development: Activity targeting primarily conventional proved undeveloped reserves aimed at conversion to

proved developed producing status.

(2) Exploitation: Activity targeting shale plays known to be hydrocarbon bearing with principal project risk is the

ability to establish commercial development.

(3) Exploration: Activity targeting discovery of reserves from previously untested formations with significant

geological and commercial risk present.

$80 Million

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PUD -

Probable -

Possible -

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South Texas – Growth DriverVicksburg Wilcox

• One well completed prior to year-end 2007

- Garza Hitchcock #12 initial daily flow rate of 1,947 Mcfe

• Three wells drilling/completing

Garza Hitchcock #13 completed with initial daily flow rate of 2,748 Mcfe

Garza Hitchcock #11 spud early February and is completing

Garza Hitchcock #14 spud mid-March

• RAM is operator with 100% Working Interest

• 2008 CAPEX: $19.0 million

6 additional wells planned

Represents 20% of total 2008 CAPEX

• PUD Inventory of 18 locations

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• 27,700 gross (6,800 net) acres located in Core area and all held by production

• 26,267gross (25,393 net) leasehold acres located in Tier 2

• 85 square miles of seismic

• Current Activity;

11 producing wells 4 wells completing/waiting on pipeline

1 well drilling

5 wells proposed

31 future locations

• 2008 CAPEX: $10 million

RAM’s Barnett Shale operating area

Barnett Shale - Growth Driver

Core

Tier 1

Tier 2

Newly acquired acreage

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T.L. Dickenson 1H Producing

Etta Burress 1-H Producing

Burress 1-H Producing

Burress 2-H Producing

Rawle A 1-H Producing

Rawle 4-H Producing

Etta Burress 5-H PUD

Burress Unit 10-H PossT. L. Dickenson A 2-H PUD Prop

T.L. Dickenson A3-H PUD

Raw

le 6H Poss

Rawle 5H PUD

Etta Burress 6-H PUD

Burress Unit 7-H PUD

Burress Unit 3-H PUD

Etta B

urress 4-HE

tta Burress 2-H

Molloy U

.A. "A

" 1-H P

rob Prop

Etta Burress 3-H Prob

Burress 4H PUD

T. L. Dickenson A 4H Prob Prop

T. L. Dickenson A 5H Prob Prop

• Approximately 1,531 gross (551 net) acres

• 6 wells producing

• Etta Burress #2-H and #4-H horizontal wells drilled

Simul-frac completion

Awaiting pipeline connection

• Etta Burress #3-H horizontal well, awaiting completion

• Molloy #1-H horizontal well, spud early March

• Devon has proposed 4 additional horizontal wells

• RAM WI = 36%

• Continuous drilling clause in participation agreement

Barnett Shale (Devon Area) – Growth DriverRawle / Burress Lease

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• Approximately 23,500 gross acres (5,600 net)

• RAM WI = 24%

• RAM has proposed five wells to EOG; EOG has elected to participate and operate all five

• One well awaiting pipeline connection

Dethloff #1-H

• One well pending: Brown 2-H

• 37 square miles of 3-D seismic- Additional 20 square miles planned for 2008

- Ongoing seismic review supports 21 identified locations to date

• Right to propose wells If EOG declines to participate, RAM can drill

wells on a non-consent basis

Barnett Shale (EOG Area) – Growth Driver

Producing

Acquired 2006

Seismic

Ashe 1H

Proposed

Sealy C-1H

Ashe C-1H

Ramsey 1H

Brown 2H

Dethloff 1H

Permitting

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West Virginia – Growth DriverDevonian Shale Play


• Approximately 47,000 gross (45,000 net) leasehold acres


first well to spud early second quarter

6 wells permitted with rig under contract

8 additional wells scheduled for 2008

represents 24% of total 2008 CAPEX

RAM Existing Wells

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West Virginia – Growth DriverDevonian Shale Play

RAM Existing Wells

Cabot Existing Wells

RAM Acreage

Cabot Acreage

RAM owned gathering system

Rig contracted to commence drilling on initial 6 well

program; first well to spud early second quarter.

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• Financial Liquidity Analysis:

Cash

Plus: Available Credit LineLess: Outstanding Credit

Liquidity

Financial Liquidity

(334)

12/31/07

375 6

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• Expanded credit facility to $500 million from previous $300 million

• Increases borrowing availability to $375 million vs. prior $150 million

• Substantial interest expense savings accruing from reductions in LIBOR rates

($millions)

(1) Borrowing base using 6/30/07 mid-year reserve report

(1)

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Attractive Valuation vs. Peers

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

(1) Represents most recent proved reserves and PV-10 value for peers. RAM’s PV-10 value at 12/31/07.(2) Share prices as of close 03/04/08.(3) RAM shares outstanding adjusted to reflect offering of common stock 2/8/07 and additional 18.8 million common shares

issued in the acquisition of Ascent which closed 11/29/07.

0.68x0.88x

2.71x

1.11x 0.99x

1.34x

0.51x

0.00x

1.00x

2.00x

3.00x

4.00x

ARD

BEXP

CRZOPLLL

Mea

n

Med

ian

RAME

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• Large inventory of growth opportunities

• Stable cash flow base

• Oil and NGL rich reserve and production base

• High degree of operating control

• Proven value creation through both acquisitions and drillbit

• Compelling valuation vs. peers

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

Summary of Investment Considerations


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Derivative Positions

(1) As of February 29, 2008

(2) Crude oil floors and ceilings and natural gas floors and ceilings cover March through December 2008. Crude oil bare

floors cover March through December 2008. Crude oil floors and ceilings for 2009 cover the calendar year. Natural gas floors

and ceilings for 2009 cover January through October. Crude oil bare floors cover January through June 2009.

Crude oil secondary floors for 2009 cover January through March. Crude oil floors and ceilings for 2010 cover

January through March.

(1)

per day Price per day Price per day Price per day PriceCollarsQ1 '08 1,500 $65.33 1,500 $82.57 4,000 $8.00 4,000 $16.70Q2' 08 1,500 $65.33 1,500 $83.13 10,000 $7.00 10,000 $10.06Q3 '08 1,500 $65.33 1,500 $84.80 10,000 $7.00 10,000 $11.04Q4 '08 1,500 $65.33 1,500 $83.06 6,022 $7.00 6,022 $12.86

Q1 '09 2,000 $58.50 2,000 $82.63 4,000 $7.00 4,000 $12.40Q2 '09 1,500 $60.00 1,500 $81.07 10,000 $7.00 10,000 $10.01Q3 '09 1,000 $60.00 1,000 $81.22 10,000 $7.00 10,000 $10.23Q4 '09 1,000 $60.00 1,000 $82.50 10,000 $7.00 10,000 $10.33

Q1 '10 500 $60.00 500 $80.00 - - - -

BareFloorsQ1 '08 1,800 $72.32Q2' 08 1,800 $72.32Q3 '08 1,800 $70.00Q4 '08 1,800 $70.00

Q1 '09 1,000 $65.00Q2' 09 1,000 $65.00

SecondaryFloorsQ1 '09 800 $75.00

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

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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 fund debt service costs. 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.

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

to GAAP cash flow from operating activities

Net cash provided by operating activities per condensed Consolidated statements of cash flow $4,308 $4,366Less: working capital changes (3,316) 2,070 Cash flow from operations (a non-GAAP measure) $7,624 $2,296

Cash flow from operations (a non-GAAP measure) $7,624 $2,296Less: realized gains (losses) on derivatives (2,308) 116

Cash flow from operations (a non-GAAP measure) excluding

Realized and unrealized gains (losses) on derivatives $9,932 $2,180

Fourth Quarter ended December 31

(in thousands)2007 2006

(in thousands)

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Year Ended December 31

(in thousands)2007 2006

(in thousands)

Net cash provided by operating activities per condensed Consolidated statements of cash flow $17,042 $29,660Less: working capital changes (6,616) 11,544 Cash flow from operations (a non-GAAP measure) $23,658 $18,116

Cash flow from operations (a non-GAAP measure) $23,658 $18,116Less: realized gains (losses) on derivatives (2,669) (4,650)

Cash flow from operations (a non-GAAP measure) excluding

Realized and unrealized gains (losses) on derivatives $26,327 $22,766

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

to GAAP cash flow from operating activities

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Oil Gas NGL PercentMBBL MMcf MBBL MBOE of total

Reserve Category

Proved Developed producing 12,648 40,504 2,300 21,698 55%

Developed non-producing 904 10,486 265 2,917 7%

Undeveloped 5,992 42,368 1,706 14,760 38%

Total Proved 19,544 93,358 4,271 39,375 100%

Estimates of Proved Reserves

1) Estimate of RAM proved reserves at 12/31/07

____________

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North Texas – Production MaintenanceElectra / Burkburnett

• Average well statistics (1)

- F & D costs $5.91/BOE EUR 22 MBOE Economic life 20 years Working Interest 100% IRR at $53.00/Bbl = 100%

• PUD Inventory of 150 locations Three year drilling inventory at 2008

planned activity level Multiple year inventory of non-PUD

well locations• 2008 CAPEX: $7.5 million

60 wells planned

(1) At 12/31/07

• Proved Reserves of 9.4 MMBOE

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• PUD Inventory of 57 locations


1 well drilled and completing 1 well drilling- 10 wells scheduled to be drilled 1 new disposal well to be drilled Represents 9% of total 2008

CAPEX


PUDInjectors

PDP

57

10 60

Allen Field

Fitts Field

Oklahoma - Production Maintenance

PUD WF

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$80 Million

2008E Non-Acquisition Capital Expenditure Detail

ExplorationExplorationNorth

Texas

North

Texas

$7.5 MM $7.5 MM $19.0 MM $8.5 MM $19.0 MM $5.0 MM$10.0 MM

OklahomaOklahoma South

Texas

South

TexasBarnett

Shale

Barnett

Shale LouisianaLouisianaAppalachianAppalachian Capitalized

G&G

Capitalized

G&G

$3.5 MM

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Company Overview Company Overview Reserves / Production Reserves / Production(1)(1)

1) Using RAM proved reserves at 12/31/07

2) Production mix as of December 2007

Other

P roduc ing

Fields

11%

North

Texas

31%

Barnett

Shale

5%South

Texas

14%

Louisiana

13%

Oklahoma

26%

Louisiana

8%

South

Texas

16%

Other

P roduc ing

Fields

15%

North

Texas

35%

Oklahoma

20%

Barnett

Shale

6%

Percent of Total Reserves by Area / Field(1) Production by Area / Field(2)

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Company Overview Company Overview Reserves / Production Reserves / Production(1)(1)

Hydrocarbon Mix of Reserves (1)

50%

39%

11%

oil

natural gas

NGL's

(1) Using RAM proved reserves at 12/31/07

• Oil and liquids rich reserve base• 67% of production is based on price of oil

Production Mix (1)

34%

15%

52%

Bbls

MCF

NGL

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Company Overview Company Overview Proved Reserves Proved Reserves (1)(1)

PV10 by Reserve Category

57%

8%

35%

PDP

PDNP

PUD

(1) Estimate of RAM proved reserves as of 12/31/07

Percent Total Reserves by Category

55%

7%

38%

PDP

PDNP

PUD

• High ratio of PDP and PDNP component of total reserve and PV-10 value contributes to consistent cash flow

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Drilling Success Rate Remains High

(2) Excluding wells in progress

(1) Gross wells drilled - RAM prior to Acquisition of Ascent

91% 92%

(1)Total Wells Drilled

1987- 2007

Producers

Dry Holes

Drilling or Completing

Total

Success Ratio

69 591

48

3

81 642

(2)

7

5

2007(1)

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Production Volumes and Expenses

Fourth Quarter Ended December 31 Percent

2007 2006 Change

Production volumes:Oil and condensate (MBbls) 225 176 28Natural gas liquids (MBbls) 64 40 59Natural gas (MMcf) 878 603 46 Total (Mboe) 436 317 37

Expenses (dollars per BOE):Oil and natural gas production taxes 4.38 2.53 73Oil and natural gas production expenses 15.39 15.91 (3)Amortization of full-cost pool 16.70 9.71 72General and administrative 10.43 9.30 12

Share - based compensation 0.66 0.28 132Interest (excluding amortization) 18.76 12.10 55

Total (per BOE) 66.32 49.83 33

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Production Volumes and Expenses

Year Ended December 31 Percent2007 2006 Change

Production volumes:Oil and condensate (MBbls) 774 752 3Natural gas liquids (MBbls) 184 143 29Natural gas (MMcf) 2,785 2,365 18 Total (Mboe) 1,422 1,290 10

Expenses (dollars per BOE):

Oil and natural gas production taxes 3.43 2.58 33Oil and natural gas production expenses 15.18 14.16 7Amortization of full cost pool 12.86 9.77 32General and administrative 8.36 7.21 16 Total (per BOE) 39.83 33.72 18

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Net Realized Prices Before/After Derivatives

Percent 2007 2006 Change

(dollars per unit of production)Average realized prices (before effects of derivatives):

Oil and condensate (per Bbl) 88.74 58.09 53Natural gas liquids (per Bbl) 59.37 36.35 63Natural gas (per Mcf) 6.35 5.42 17 Total per BOE 67.40 47.21 43

Effect of contract premiums and settlement of derivatives contracts:

Oil and condensate (per Bbl) (11.44) (0.12) Natural gas liquids (per Bbl) - - Natural gas (per Mcf) 0.30 0.23 Total per BOE (5.30) 0.37

Average realized prices (after effects of derivatives):

Oil and condensate (per Bbl) 77.30 57.97 33 Natural gas liquids (per Bbl) 59.37 36.35 63Natural gas (per Mcf) 6.65 5.64 18 Total per BOE 62.10 47.57 31

Fourth Quarter Ended December 31

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Net Realized Prices Before/After Derivatives

Percent2007 2006 Change

Average realized prices (before effects of derivatives):


Effect of contract premiums and settlement of derivatives contracts:

Oil and condensate (per Bbl) (4.35) (5.78)Natural gas liquids (per Bbl) - -Natural gas (per Mcf) 0.25 (0.13) Total per BOE (1.88) (3.61)

Average realized prices (after effects of derivatives):


Year Ended December 31

(dollars per unit of production)


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Documents

RAM Energy Resources, Inc. March 2008 TM Fourth Quarter and Year-End 2007 Review