RAM Energy Resources, Inc. APRIL Oil and Gas Investment Symposium TM

2 Disclosure Statement This 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.

TM 3 Creating Shareholder value since 1987 Creating Shareholder value since 1987  Proven value creation through both acquisitions and drillbit Stable cash flow base from long-lived reserves Stable cash flow base from long-lived reserves  Year-end 2006 proved reserves of 18.5 MMBOE or 111 Bcfe  2006 production: 1.3 MMBOE or 7.8 Bcfe  R/P ratio 14 years Large inventory of growth opportunities Large inventory of growth opportunities  228 PUD locations, a three year inventory  Accelerating development on 27,700 gross (6,800 net) acre position in Barnett Shale  Testing initial wells of a 15,000 net acre Wolfcamp Shale exploration play exploration play  6,600 net acres in Woodford/Barnett Shale play in West Texas Summary of Investment Considerations

TM 4 Compelling valuation vs. peers Compelling valuation vs. peers  Significant discount to peers based on reserves and cash flows  Substantial discount to net asset value calculated by analysts High degree of operating control High degree of operating control Significant management and technical experience Significant management and technical experience Management’s substantial ownership of RAM stock supports alignment with shareholder interest Management’s substantial ownership of RAM stock supports alignment with shareholder interest Summary of Investment Considerations

TM 5 (1)PV-10 value calculated using year-end 2006 reserve volumes and prices at March 30, 2007 of $64.00/Bbl for oil, $7.55/ MMBtu for natural gas and $39.68/Bbl for NGL (2)As of 12/31/06 (3)Based on fully diluted shares outstanding Company Overview Operations Proved Reserves (12/31/06)18.5 MMBOE % Crude & NGL70% % Developed71% PV-10 Value - At year end 2006 $270 MM - At 3/30/2007 $330 MM % of PV-10 Value Operated91% 2006 Financial Results (2) Oil and Natural Gas Sales$68.0 MM EBITDA$33.4 MM Operating Income$23.3 MM Net Income$5.0 MM Net Income Per Share (3) $0.20 IDFieldProved Reserves (MMBOE) 1Electra / Burkburnett9.8 2Boonsville2.9 3North Texas Barnett Shale0.9 4Secondary Producing Fields4.9 AWoodford / Barnett ShalesN / A BWolfcamp FormationN / A (1)

TM 6 93% Drilling Success Rate Remains High (2) Excluding wells in progress (1) Gross wells drilled (1) 2006 Total Wells Drilled Producers Dry Holes Drilling or Completing Total Success Ratio % (2) (1) 4

TM 7 Property Summary Producing Properties Exploration Projects (1)

TM 8 Financial Liquidity Analysis Cash Plus: Total Credit Line Less: Outstanding Credit RAM completed its offering of 7.5 million shares in February adding substantially to liquidity. RAM’s borrowing base was reaffirmed at $140 million at regularly scheduled semi-annual redetermination (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 $140 million provides expanded financial flexibility for growth Liquidity Actual ($millions) Financial Liquidity (2) 12/31/06 3/31/07 Estimated ($millions) (1) 65.7

TM 9 $30.3 Million Electra / Burkburnett $9.7 MM Boonsville $1.6 MM Egan, Vinegarone, and Other $4.2 MM West Texas Woodford / Barnett Shale $0.5 MM Wolfcamp Formation $7.4 MM Capitalized G & G Cost $2.9 MM Proved Drilling Cap ExNon-Proved Drilling Cap ExNon-Drilling Cap Ex 2007E Capital Expenditure Detail $4.0 MM North Texas Barnett Shale

TM % WI ownership & operational control Includes assets that help maintain drilling schedule and control costs: gas plant, gathering system, one drilling rig, five workover rigs, and a supply company (1) At 12/31/06 Wichita and Wilbarger Counties, Texas 4Q06 production of MBOE from 536 producers 79 wells drilled in 2006, establishing 64 new PUD locations 200 identified PUD drilling locations (1) with a projected D&C of $5.82 per BOE Electra / Burkburnett

TM 11 Average well statistics:  Drill & complete$128,000  EUR22,000 BOE  Economic life20 years  IRR per > 100%  IRR per > 100% PUD inventory sufficient to maintain or increase production over the next several years, thereby sustaining RAM’s stable cash flow base 2007E Capital expenditures for Electra / Burkburnett budgeted for $9.7 million (38% of total capital expenditure budget) Forecast of Electra/Burkburnett Production (1) Production (MBoe) Electra / Burkburnett Production and Capital Expenditures Based on estimate of proved reserves and associated capital spending at 12/31/06. (1)

TM 12 Jack and Wise Counties, TexasJack and Wise Counties, Texas 4Q06 production of over 44.1 MBOE from 88 producers4Q06 production of over 44.1 MBOE from 88 producers 20 identified drilling locations20 identified drilling locations  Avg. D&C cost: $625,000  Avg. EUR:115,000 BOE 25 miles of gas gathering system25 miles of gas gathering system Proved reserves of 2,862 MBOE (1)Proved reserves of 2,862 MBOE (1) Capital expenditure budget of $1.6 million in 2007Capital expenditure budget of $1.6 million in 2007 Producing wells hold Barnett Shale rightsProducing wells hold Barnett Shale rights Boonsville (1) As of December 31, 2006

TM 13 Jack and Wise Counties, Texas 27,700 gross/6,800 net acres All acreage is “held by production” 90% of acreage is in Core area 325 potential horizontal drilling locations on 80-acre spacing 9 gross producing wells existing Project inventory/near-intermediate term upside potential;  1 gross well completing – TL Dickenson 1H  1 gross well currently drilling Ashe C-1H  5 PUD locations  19 probable seismic locations  9 possible seismic locations  35 total additional locations identified to date RAM’s Barnett Shale operating area Barnett Shale Core Tier 1 Tier 2

TM 14 Approximately 23,500 gross acres (5,600 net) – RAM WI=24% More than 290 potential drilling locations on 80-acre spacing One producing well – Ashe 1H completed in March 2006 No PUD locations booked to date 27 square miles of 3-D seismic   Additional 60 square miles planned for 2007   Ongoing seismic review supports 11 additional drilling locations to date Year-to-date RAM has proposed its first three wells to EOG; EOG has consented to drill all three wells   EOG has spud the Ashe C 1H well, the first well proposed by RAM in 2007 Right to propose wells   If EOG declines to participate, RAM can drill wells on a non-consent basis Barnett Shale (EOG Area) Ashe 1H Well Planned 2007 Acquired 2006 Seismic Ashe 1H Ashe C 1-H Ashe C 1-H Well

TM 15 Approximately 3,500 gross acres (1,200 net) – RAM WI=36% More than 35 potential drilling locations on 80-acre spacing 7 producing wells to date 1 well drilled and awaiting completion 5 PUD locations booked to date 8 square miles of 3-D seismic   Ongoing seismic review supports 8 additional drilling locations to date Continuous drilling clause in the participation agreement   Devon must drill a well 120 days after the completion of the previous well Barnett Shale (Devon Area) Additional Locations PDP - (Rawle 4H, Rawle A 1H, Burress Unit 1H, Burress Unit 2H, Etta Burress 1H, PUD - (Etta Burress 2-H, Etta Burress 3H, Burress Unit 3H, North of Paradise 2H, Fitzgerald 5-2H) North of Paradise 1H, Fitzgerald 5H, TL Dickenson 1H - PDNP)

TM 16 6 wells drilled to date Average initial production = 1,921 MCFEPD Average EUR = 1.9 Bcfe Average well cost = $1.7 MM Finding cost = $0.90 / Mcfe Barnett Shale (Devon Area) Rawle / Burress Lease Well Name Completion Date Initial Production (MCFEPD) Rawle No. 4HFeb ,302 Rawle A No. 1HMar ,124 Burress No. 1HNov ,384 Burress No. 2HFeb ,239 Etta Burress No. 1 TL Dickenson 1H Sept Awaiting Completion 1,558 TBD (1) Composite of industry horizontal wells in Barnett Shale adjusted for RAM’s Rawle/Burress well performance (1)

TM 17 Southwest Texas Potential high-impact exploration RAM has leased & optioned 15,000 net acres 100% working interest Current status of activity on two vertical test wells drilled in 4Q06   Stimulation of two zones in well A and one zone in well B complete   Recently installed pumping units to aid in recovery of frac fluids   Testing underway Wolfcamp Fairway

TM 18 EV / Proved Reserves (BOE) (1) (3) (4) EV as % of PV-10 (2) (3) (4) Attractive 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 4/12/07

TM 19 EV / LTM Daily Production (BOEPD) (1) (2) (3) (4) EV / LTM EBITDA (3) (4) Attractive 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 4/12/07

TM 20 Attractive Valuation vs. Peers 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 4/12/07 (3)RAM shares outstanding adjusted to reflect offering of common stock 2/8/07 (4) Ferris Baker Watts, Gilford, Jefferies, Johnson Rice, RBC Average Net Asset Value (NAV) per share range published by analysts: $6.06 (4) At current price level, RAME sells at 28% discount to analysts’ calculated NAV per share.

TM 21 Stable cash flow base Compelling valuation vs. peers Significant management and technical experience Balanced oil & natural gas exposure Large inventory of growth opportunities High degree of operating control Proven value creation through both acquisitions and drillbit Management’s substantial ownership of RAM stock supports alignment with shareholder interest Summary of Investment Considerations

RAM Energy Resources, Inc. TM

23 APPENDIX

TM 24 ($ millions) Percent Change Net Revenue55,39970,24427% Operating Expenses41,51146,99013% Operating Income13,88823,25467% Net Interest Expense12,53916,74134% Net Income 5435,048830% Per Share Income % Summary Financials – 2006 VS 2005 (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 Resources at the time of the merger. (1)

TM 25 Production Volumes and Expenses

TM 26 Production Volumes and Expenses (1) Production for the year ended December 31, 2006 is impacted by exercise of reversionary interest in September (1)

TM 27 Net Realized Prices Before/After Derivatives

TM 28 Net Realized Prices Before/After Derivatives

TM 29 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.

TM 30 Cash Flow Reconciliation of cash flow from operations (a non-GAAP measure) to GAAP cash flow from operating activities (in thousands) Fourth Quarter Ended December 31

TM 31 Year Ended December 31 (in thousands) (in thousands) Cash Flow Reconciliation of cash flow from operations (a non-GAAP measure) to GAAP cash flow from operating activities

TM 32 (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 prices at March 30, 2007 of $64.00/Bbl for oil, $7.55/ MMBtu for natural gas and $39.68/Bbl for NGL Year-end proved reserves18.5 MMBOE Oil – 59%10.8 MMBbls NGL – 11% 2.1 MMBbls Natural gas – 30%33.2 Bcf Proved developed reserves13.1 MMBOE Proved developed reserves as percent of total 71% 2006 year-end prices Oil $58.74 Bbl NGL $36.51 Bbl Natural gas $5.51 MMBtu 2006 PV-10 $270 Million 2006 standardized measure $180 Million PV-10 value – using current pricing $330 Million 2006 Reserves (2) (1) (3)

TM 33 (1) From continuing operations 2006 Production Replacement and 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%

TM 34 Derivative Positions (1) As of March 31, 2007 (2) Natural gas Secondary Floors covering 4Q ’07 cover only the month of October. (1)

TM 35 Barnett Shale (EOG Area) Joint 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 and Complete, $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 EOG Operates Allocation of costs by working interest