RAM Energy Resources, Inc.

APRIL 2007

2007 Oil and Gas Investment Symposium

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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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• Creating Shareholder value since 1987Creating Shareholder value since 1987Proven value creation through both acquisitions and drillbitProven value creation through both acquisitions and drillbit

• Stable cash flow base from long-lived Stable cash flow base from long-lived reservesreserves

Year-end 2006 proved reserves of 18.5 MMBOE or 111 BcfeYear-end 2006 proved reserves of 18.5 MMBOE or 111 Bcfe2006 production: 1.3 MMBOE or 7.8 Bcfe2006 production: 1.3 MMBOE or 7.8 BcfeR/P ratio 14 yearsR/P ratio 14 years

• Large inventory of growth opportunitiesLarge inventory of growth opportunities228 PUD locations, a three year inventory228 PUD locations, a three year inventory

Accelerating development on 27,700 gross (6,800 net) acre Accelerating development on 27,700 gross (6,800 net) acre position in Barnett Shaleposition in Barnett Shale

Testing initial wells of a 15,000 net acre Wolfcamp Shale Testing initial wells of a 15,000 net acre Wolfcamp Shale exploration playexploration play6,600 net acres in Woodford/Barnett Shale play in West Texas6,600 net acres in Woodford/Barnett Shale play in West Texas

Summary of Investment ConsiderationsSummary of Investment Considerations

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• Compelling valuation vs. peersCompelling valuation vs. peers

Significant discount to peers based on reserves and cash flowsSignificant discount to peers based on reserves and cash flows

Substantial discount to net asset value calculated by analystsSubstantial discount to net asset value calculated by analysts

• High degree of operating controlHigh degree of operating control

• Significant management and technical Significant management and technical experienceexperience

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

Summary of Investment ConsiderationsSummary of Investment Considerations

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(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

ID Field Proved Reserves (MMBOE)

1 Electra / Burkburnett 9.8

2 Boonsville 2.9

3 North Texas Barnett Shale 0.9

4 Secondary Producing Fields 4.9

A Woodford / Barnett Shales N / A

B Wolfcamp Formation N / A

(1)

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93%

Drilling Success Rate Remains High

(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)

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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 & NGL 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)

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• Financial Liquidity Analysis

CashPlus: Total Credit LineLess: 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)

6.7140.0

43.7Financial Liquidity

(2)

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

140.0 28.7 (1)

65.7

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$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 Detail

$4.0 MM

North

Texas

Barnett

Shale

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• 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

• Wichita and Wilbarger Counties, Texas

• 4Q06 production of 170.2 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

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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: Drill & complete

$128,000 EUR

22,000 BOE Economic life

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

Pro

du

ctio

n (

MB

oe

)

Electra / BurkburnettProduction 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)

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• 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

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• 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 dateRAM’s Barnett Shale operating area

Barnett Shale

Core

Tier 1

Tier 2

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• 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

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• 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)

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• 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 NameCompletion

Date

Initial Production (MCFEPD)

Rawle No. 4H Feb. 2004 1,302

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

Burress No. 1H Nov. 2005 2,384

Burress No. 2H Feb. 2006 2,239

Etta Burress No. 1TL Dickenson 1H

Sept. 2006Awaiting

Completion

1,558TBD

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)

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• 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

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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

$32.60

$16.18$16.63

$50.90

$28.18 $28.90 $28.18

$14.99

$0.00

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

ARD

CRZO

CWEI

TXCOPLLL

Mea

n

Med

ian

RAME

102%

248%208%

248%

309%

110%

290%

85%

0%

100%

200%

300%

400%

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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

15.5x 18.0x

10.0x 10.0x

16.4x14.0x

15.5x

8.3x

0.0x

5.0x

10.0x

15.0x

20.0x

ARD

CRZOCW

EI

TXCOPLLL

Mea

n

Med

ian

RAME

$247,013

$213,458

$54,491

$131,583

$178,027$164,914 $178,027

$85,763 $78,249

$0

$100,000

$200,000

$300,000

ARD

CRZOCW

EI

TXCOPLLL

Mea

n

Med

ian

Harold

Mea

n

RAME

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Attractive Valuation vs. Peers

0.84x

4.52x

1.26x

3.07x3.32x

2.60x3.07x

1.04x

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 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.

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• 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.

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($ 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%

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)

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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

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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) 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

Production Volumes and Expenses

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

(1)

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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

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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)

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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 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.

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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

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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

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(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 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 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)

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(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%

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Derivative Positions

(1) As of March 31, 2007

(2) Natural gas Secondary Floors covering 4Q ’07 cover only the month of October.

Per day Price Per day Price Per day Price Per day PriceCollarsQ2 '07 1,500 $52.67 1,500 $73.92 4,000 $7.50 4,000 $10.00Q3 '07 1,500 $52.67 1,500 $72.58 4,000 $7.50 4,000 $10.00Q4 '07 1,500 $52.67 1,500 $72.58 4,000 $7.83 4,000 $14.44

Q1 '08 1,000 $52.00 1,000 $85.80 4,000 $8.00 4,000 $16.70Q2' 08 1,000 $52.00 1,000 $86.64 4,000 $7.00 4,000 $10.30Q3 '08 1,000 $56.00 1,000 $86.68 4,000 $6.50 4,000 $12.75Q4 '08 800 $55.00 800 $85.00 4,000 $6.00 4,000 $14.35

Q1 '09 800 $50.00 800 $65.00 4,000 $7.00 4,000 $12.40

SecondaryFloorsQ2 '07 - - - - 4,000 $12.00 - - Q3 '07 - - - - 4,000 $12.00 - -

Q4 '07 (2)

- - - - 4,000 $12.00 - -

Q1 '09 800 $75.00 - - - - - -

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

(1)

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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