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RAM Energy Resources, Inc.

RAM Energy Resources, Inc. Fourth Quarter and Year-End 2006 Review. APRIL 2007. Disclosure Statement.

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RAM Energy Resources, Inc.

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  1. RAM Energy Resources, Inc. Fourth Quarter and Year-End 2006 Review APRIL 2007

  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.

  3. Call Agenda Fourth quarter results and year-end summary Year-end reserves, production replacement and finding cost Balance sheet/liquidity 2007E capital budget Operational update Attractive valuation

  4. Highlights 2006 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. Highlights 4Q 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. Drilling Success Rate Total Wells Drilled 2006 (1) 1987- 2006 (1) 512 Producers 80 41 Dry Holes 4 8 Drilling or Completing 8 561 Total 92 95% Success Ratio 93% (2) (1) Gross wells drilled (2) Excluding wells in progress

  8. 2006 Reserves 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 (1) (2) (3) (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

  9. 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% (1) From continuing operations

  10. Property Summary Producing Properties (1) Exploration Projects

  11. 2007E Capital Expenditure Detail North Texas Barnett Shale Electra / Burkburnett Boonsville Egan, Vinegarone, and Other West Texas Woodford / Barnett Shale Wolfcamp Formation Capitalized G & G Cost $9.7 MM $4.0 MM $1.6 MM $4.2 MM $0.5 MM $7.4 MM $2.9 MM $30.3 Million Proved Drilling Cap Ex Non-Proved Drilling Cap Ex Non-Drilling Cap Ex

  12. Liquidity 12/31/06 3/31/07 Estimated ($millions) • Financial Liquidity Analysis Cash Plus: Total Credit Line Less: Outstanding Credit Actual ($millions) (1) 6.7 31.0 (2) 140.0 140.0 (103.0) (103.0) Financial Liquidity 43.7 68.0 (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. (2) $300 million Sr. Secured Credit Facility with initial borrowing limit of $140 million provides expanded financial flexibility for growth

  13. Electra / Burkburnett • Wichita and Wilbarger Counties, Texas • 4Q06 production of 170.2 MBOE from 536 producers • 79 wells drilled in 2006 • 200 identified PUD drilling locations(1) with a projected D&C of $5.82 per BOE 100% 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

  14. Electra / Burkburnett Production and Capital Expenditures • Average well statistics: • Drill & complete $128,000 • EUR 22,000 BOE • Economic life 20 years • IRR per well @$60/Bbl > 100% • IRR per well @$50/Bbl > 100% Forecast of Electra/Burkburnett Production (1) Production (MBoe) 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) (1) Based on estimate of proved reserves and associated capital spending at 12/31/06.

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

  16. Barnett Shale • Jack and Wise Counties, Texas • 27,700 gross acres • 6,800 net acres • All acreage is HBP • 90% of the acreage located in the Core area • 325 potential horizontal drilling locations on 80-acre spacing • 9 gross producing wells existing • 35 square miles of 3-D seismic acquired and interpreted • Budgeted to add another 60 square miles during 2007 • Partners are EOG and Devon Core Tier 1 Tier 2 RAM’s Barnett Shale operating area

  17. Barnett Shale (EOG Area) Ashe 1H Seismic Acquired 2006 Planned 2007 Ashe 1H Well • 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 • RAM has proposed its first three wells to EOG; EOG has consented to drill the first two well; expected to respond to third proposal by mid-April • Right to propose wells • If EOG declines to participate, RAM can drill wells on a non-consent basis

  18. Barnett Shale (Devon Area) • 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 • 4 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 Additional Locations PDP - (Rawle 4H, Rawle A 1H, Burress Unit 1H, Burress Unit 2H, Etta Burress 1H, North of Paradise 1H, Fitzgerald 5H, TL Dickenson 1H - PDNP) PUD - (Burress Unit 3H, Burress Unit 4H, North of Paradise 2H, Fitzgerald 5-2H)

  19. Barnett Shale (Devon Area) Rawle / Burress Lease • 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 (1) (1) Composite of industry horizontal wells in Barnett Shale adjusted for RAM’s Rawle/Burress well performance

  20. Wolfcamp Fairway • Southwest Texas • Potential high-impact exploration • RAM has leased & optioned 15,000 net acres • 100% working interest • Two test wells vertically drilled • Stimulation, recovery of frac fluid and testing underway on two wells • If commercial, significant potential upside on 80 acre spacing

  21. Attractive Valuation vs. Peers EV as % of PV-10(2) (3) (4) EV / Proved Reserves (BOE)(1)(3) (4) • Represents proved reserves as of most recent SEC proved reserve filing • Represents PV-10 value as of most recent SEC proved reserve filing • RAM EV adjusted to reflect offering of common stock 2/8/07 • Share prices as of close 3/28/07

  22. Attractive Valuation vs. Peers EV / LTM EBITDA (3) (4) EV / LTM Daily Production (BOEPD)(1) (2) (3) (4) • “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 • Production based on companies 2006 Annual 10K • RAM EV adjusted to reflect offering of common stock 2/8/07 • Share prices as of close 3/28/07

  23. Attractive Valuation vs. Peers Price / NAV (1) (2) (3) • Represents proved reserves and PV-10 value as of most recent SEC filing of reserves • Share prices as of close 3/28/07 • RAM EV adjusted to reflect offering of common stock 2/8/07

  24. Summary of Investment Considerations 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

  25. RAM Energy Resources, Inc.

  26. Summary Financials – 2006 VS 2005 ($’millions) Percent 2005 2006 Change Net Revenue 55,399 70,244 27% Operating Expenses 41,511 46,990 13% Operating Income 13,888 23,254 67% Net Interest Expense 12,539 16,741 34% Net Income 543 5,048 830% Per Share Income .07 0.21 186% (1) (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.

  27. Production Volumes and Expenses

  28. Production Volumes and Expenses (1) Production for the year ended December 31, 2006 is impacted by exercise of reversionary interest in September 2005.

  29. Net Realized Prices Before/After Derivatives

  30. Net Realized Prices Before/After Derivatives

  31. Fourth Quarter Results ($ In Millions) (1) Oil & Natural Gas Sales Non-GAAP Net Income (Loss) Net Income Per Share Cash Flow From Operations $5.4 $18.1 $4.20 $0.54 $15.0 $3.2 $1.05 $0.03 4Q06 4Q05 4Q06 4Q05 4Q06 4Q05 4Q06 4Q05 (1) Cash flow is a non-GAAP measure. See appendix for a reconciliation of this non-GAAP measure to the corresponding GAAP amount.

  32. 2006 Results ($ In Millions) (1) Oil & Natural Gas Sales Non-GAAP Net Income Net Income Per Share Cash Flow From Operations (2) $23.0 $68.02 $5.05 $18.1 $0.20 $66.24 $0.5 NM 2006 2005 2006 2005 2006 2005 2006 2005 Up 910% Up 3% Up 21% (1) Cash flow is a non-GAAP measure. See appendix for a reconciliation of this non-GAAP measure to the corresponding GAAP amount. (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 offering of 7.5 million shares of common stock. .

  33. 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.

  34. Cash Flow Reconciliation of cash flow from operations (a non-GAAP measure) to GAAP cash flow from operating activities Fourth Quarter Ended December 31 2006 2005 (in thousands) (in thousands)

  35. Cash Flow Reconciliation of cash flow from operations (a non-GAAP measure) to GAAP cash flow from operating activities Year Ended December 31 2006 2005 (in thousands) (in thousands)

  36. Derivative Positions As of February 28, 2007

  37. 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” EOG Operates RAM operates or other option Must spud well within 90 days Must spud well within 90 days Estimated cost to drill and Complete, $3 million (MM) per well Estimated cost to drill and complete, $3 million (MM) per well Allocation of costs by working interest Allocation of costs by working interest (1) Other =10% RAM =24% EOG =66% RAM =90% Other =10% EOG =0% $2.7MM $0.0MM $0.3MM $0.7MM $2.0MM $0.3MM (1) Assumes “other” working interest partners elect to maintain existing working interests totaling approximately 10%

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