CIBC 2012 ENERGY CONFERENCECORPORATE PRESENTATION

APRIL 2012

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DISCLAIMER

Certain information regarding RMP Energy Inc. (“RMP”) (the “Company”) contained within this corporate presentation may constitute forward-looking statements within the meaning of applicable securities laws. Forward-looking statements include internal estimates and forecasts and may also include estimates, plans, expectations, opinions, forecasts, projections, indications, targets, guidance or other similar statements that are not statements of fact. The forward-looking statements contained within this corporate presentation are based on Management’s assessments of future plans that involve geological, engineering, operational and financial estimates or expectations of future production, reserves, capital expenditures, well project economics, cash flow and earnings. Although the Company believes that such estimates or expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. A number of risks and uncertainties that may or may not be within the control of the Company may cause these results to vary materially from those predicted herein and the reader and/or viewer is therefore cautioned that such information is speculative in nature. Please refer to the Risk Factors outlined in RMP’s Annual Information Form for the year ended December 31, 2010, which is available on the System for Electronic Document Analysis and Retrieval (“SEDAR”). The disclosed and presented net present value of future net revenue or cash flows attributable to the Company’s reserves are stated without provision for interest costs and general and administrative costs, but after providing for estimated royalties, production/operating and transportation costs, future development costs, other income, and well abandonment costs. It should not be assumed that the undiscounted or discounted net present value of future net revenue or cash flows attributable to the Company’s reserves, as estimated or evaluated by the Company or their independent qualified reserves evaluators, represents the fair market value of those reserves. Actual reserves may be greater than or less than the estimates provided herein.

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DISCLAIMER

The well economics provided in this presentation are based on the average historical estimates of reserves for wells drilled in the respective areas in which RMP has an interest and there is no certainty that future wells will have similar economics. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. Finding and development costs have been prepared in accordance with National Instrument 51-101. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

The estimates of original oil in place ("OOIP") and original gas in place ("OGIP") with respect to the Montney Growth Fairway in this presentation are estimates prepared by the Alberta Energy Resources Conservation Board. Such estimates have been provided to highlight the resource potential in the Montney Growth Fairway in which RMP has an interest. RMP cannot confirm whether such estimates have been prepared by a qualified reserves evaluator or whether such estimates have been prepared in accordance with the Canadian Oil and Gas Evaluation Handbook.

Reserves and production data are commonly stated in barrels of oil equivalent (“BOE”) using a six to one conversion ratio when converting thousands of cubic feet of natural gas (“MCF”) to barrels of oil (“BBL”) and a one to one conversion ratio for natural gas liquids (“NGLs”). Such conversion may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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FORMATION OF COMPANY

Formed May 11, 2011 with the combination of Orleans Energy Ltd. and RMP Energy Ltd.

Trading Symbol RMP.TO

Shares Outstanding96.7 million

Options 8.2 million

Warrants2.9 million

Directors’ & Officers’ ownership (fully diluted) 12%

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COMPANY

Significant Waskahigan and Ante Creek light oil development opportunity• Near-term focus

Excellent natural gas resource potential

Strong balance sheet• Line of credit of $80 million• Drawn $45 million (as of March 31, 2012)

Large tax pool balance• $305 million of tax pools

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MANAGEMENT TRACK RECORD

Senior management team has worked together for over 20 years

Successfully grown and managed companies from 1,000 boe/d to 120,000 boe/d

Team has invested over $5.0 billion in WCSB since 1992

Team is a proven value creator throughout commodity price cycles

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2012 FORECAST

2011 Actual 2012 Budget % Change

E&D Capital Spending $ 100 million $ 75 million (25)

Production:

Annual Avg. (boe/d) 3,472 5,000-5,500 44-58

December 2011(boe/d) 5,000

Cash Flow $ 24.4 million $ 55-$ 65 million 125-166

Per basic share $ 0.30 $ 0.57 - $ 0.67 90-123

Assumptions:

Crude Oil ($WTI/bbl) $ 95.05 $ 94.00 (1)

Natural Gas ($AECO/GJ) $ 3.50 $ 3.00 (14)

Net Debt $ 49.1 million $60 - $70 million 22-43

Line of Credit $ 80 million $ 80 million -

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RESERVES SUMMARY

Total proved plus probable oil and gas reserves increased to 22.68 million boe, 36% increase over the 16.68 million boe at Dec. 31, 2010

Total crude oil reserves increased by 814% to 9.41 million bbls from 1.03 million bbls (proved plus probable)

2011 F&D costs of $23.34/boe, prior to natural gas revisions (proved plus probable)

Replaced 573% of 2011 annual production on a proved plus probable basis and 405% on a proved basis, net of revisions

Year-end net asset value of $3.93 per share (discounted 8%) and $3.47 per share (discounted 10%) (fully diluted)

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Light oil exploration and development• Waskahigan• Ante Creek• Big Muddy

Natural gas potential• Kaybob• Pine Creek• Ricinus

CORE AREAS

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MONTNEY OIL FAIRWAY

Significant land position in the Montney oil fairway

Estimated 416 Mstb OOIP* on RMP acreage

59.6 net (63.25 gross) Montney sections in fairway; 94% working interest

215 locations

Significant low risk development inventory

* Internal estimates combined with independent engineering.

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WASKAHIGANMONTNEY OIL

Top tier light oil play in WCSB

Large accumulation: initial resource study of oil estimate 264 Mstb OOIP with potential to significantly grow

Three years of low risk infill drilling inventory (40+ locations)• Up to 130 additional locations with step out drilling

High netbacks ~$50/boe; low operating costs ~$5/boe

Exceptional economics

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WASKAHIGANMONTNEY OIL

51.25 gross sections (47.6 net) 93% W.I.

Drilled wells: 22

Open Range, Harvest and Athabasca Oil locations have significantly de-risked the northern and eastern part of property and increased development program.

Recent land acquisition significantly increases exposure to play.

Potential for up to 170 additional locations.

Pool details• Avg. OOIP/Section: 8,000 MBOE• 40o API Light Oil• GOR: 2,500 scf/bbl

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WASKAHIGANMONTNEY OIL

Development

Over 40 locations in licensing process

130+ incremental locations in full development scenario

Pad drilling configuration will significantly reduce surface access and tie-in costs

Infrastructure is in place for 2012 drilling program. 10 pads are built and pipelines are in the ground

Evaluating smaller fracs to reduce costs

Optimizing production infrastructure

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WASKAHIGANMONTNEY OIL

Oil Battery

Design capacity:• 2,500 bbl/d oil• 10 mmcf/d natural gas• $18.5 million for battery and gathering

line

Has significantly reduced transportation and operating costs

Water disposal permit to inject approved• $100,000 per month savings

Expansion:• Future capacity ~ 6,000 bbls/day• Oil expansion ~ $4 million

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WASKAHIGANMONTNEY OIL

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WASKAHIGANMONTNEY OIL

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WASKAHIGANMONTNEY OIL

Capital Costs ($000): Single Well Economics: (C$3.5/GJ and US$95/bbl WTI)

Drill 2,100 High Oil Rec. Ave. Oil Rec. Low Oil Rec.Complete 2,100Equip & Tie-in 700 NPV (10% BT $000) 5,400 3,650 2,050Total 4,900 IRR (% BT) 110 50 25

F&D ($/BOE) 17.00 21.63 22.60Recycle Ratio 3.4 3.1 2.6

0

100

200

300

400

500

600

700

800

900

1,000

0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000

Daily Oil Production, Barrels per Day

Cumulative Oil Production, Barrels

Waskahigan Oil Recovery Type Curves

133 mbbl 178 mbbl 223 mbbl 05‐25 04‐36 03‐23 09‐35

Type Curve Oil Gas Totalmstb mmcf mboe

High Oil Recovery         233 424 294Ave Oil Recovery          178 333                 234Low Oil Recovery          133                  514                 219

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ANTE CREEKMONTNEY OIL

Development

6 sections 100% W.I.

Extension of Ante Creek oil pool

Drilled 4-35 well:• Tested 1,900 boe/d, 1,620 bbl/d• 85% oil (38˚ API)

On-stream Q4 2012

Significant resource:• ~ $4 million per well • 23 potential locations• 280,000 boe (proved plus probable)• 130% rate of return

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CONCLUSION

Strong production growth through oil development at Waskahigan and Ante Creek

• Focus on costs

Tremendous natural gas potential at:

• Kaybob

• Pine Creek

• Ricinus

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APPENDIX

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DIRECTORS

Craig Stewart Executive Chairman of RMP Energy Inc.

Doug Baker Independent Businessman

John Brussa Partner, Burnet Duckworth & Palmer LLP

John Ferguson President and CEO of RMP Energy Inc.

Andrew Hogg President and CEO of Coda Petroleum Inc.

Jim Saunders President and CEO of Twin Butte Energy Ltd.

Lloyd Swift Independent Businessman

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MANAGEMENT TEAM

Craig Stewart Executive Chairman

John Ferguson President and CEO

Dean Bernhard Vice President, Finance and CFO

Brent DesBrisay Vice President, Geosciences

Jon Grimwood Vice President, Exploration

Ross MacDonald Vice President, Engineering

Bruce McFarlane Vice President, Business Development

Derek Riddell Vice President, Operations

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PINE CREEKWILRICH NATURAL GAS

6.25 net sections, 56% W.I.

Wilrich development

5 wells currently producing from Wilrich, 1 well drilled in 2012 (40% W.I.; Peyto operated)

Currently producing ~ 700 boe/d

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KAYBOB MONTNEY NATURAL GAS

28 sections 92% W.I.

Significant low risk gas inventory

60 locations; 90 BCF

Infrastructure is established; quick tie-in and onstream projects

Industry is still very active in area; i.e TQN, TET, CLT

Very attractive play when gas prices recover

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RICINUSLIQUID RICH NATURAL GAS

52 sections, 64% W.I.

“Deep Basin” stratigraphy provides a “resource style” area

Reviewing 3-D seismic

Potential zones:• Cardium• Viking• Glauconite• Ellerslie• Cadomin

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BIG MUDDYBAKKEN OIL PROSPECT

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RESERVES SUMMARY

December 31, 2011 Reserves Summary (1) (Company interest before royalties)

  Natural Gas Light Crude Oil NGLs Oil Equivalent

(Columns may not add due to rounding) (Bcf) (Mbbls) (Mbbls) (Mboe) (6:1)

Proved developed producing 29.295 1,596.7 532.1 7,011.3

Proved developed non-producing 0.561 207.4 1.5 302.5

Proved undeveloped 21.395 3,232.2 285.8 7,083.8

Total Proved 51.252 5,036.3 819.4 14,397.6

Probable 21.904 4,370.2 258.3 8,279.3

Total Proved plus Probable

Commodity Weighting

73.156

54%

9,406.5

41%

1,077.7

5%

22,676.9

Note (1) Estimated using InSite’s forecast prices and costs as of December 31, 2011.

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NET PRESENT VALUE SUMMARY

December 31, 2011 Net Present Value Summary (Company interest before royalties)

(Columns may not add due to rounding)

Discount factor:0% 8% 10% 15% 20%

Proved developed producing $ 214,478 $ 150,980 $ 141,124 $ 122,094 $ 108,423

Proved developed non-producing 12,534 7,876 7,191 5,908 5,021

Proved undeveloped 193,905 71,779 56,073 28,506 11,113

Total Proved 420,917 230,636 204,388 156,508 124,557

Probable 342,428 132,241 109,017 70,402 47,435

Total Proved plus Probable $ 763,345 $ 362,877 $ 313,405 $ 226,910 $ 171,991

Note (1) Estimated using InSite’s forecast prices and costs as of December 31, 2011.

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F&D COSTS

F&D Costs

(amounts in $000s except reserve units and unit costs)Fiscal 2011

Proved Proved + Probable

Exploration and development expenditures $ 86,596 $ 86,596

Waskahigan oil battery and gathering lines infrastructure 18,531 18,531

Net land dispositions (5,163) (5,163)

Capitalized general and administrative and office costs 1,037 1,037

Total finding and development expenditures $ 101,001 $ 101,001

Future development cost - ending period 149,734 239,855

Less: Future development cost - beginning period (81,953) (97,573)

All-in total, including change in future development cost $ 168,782 $ 243,283

Reserve additions - excluding acquisitions / dispositions and natural gas technical revisions (Mboe)

6,683.9 11,737.6

Natural gas technical revisions - (Mboe) (1,523.5) (4,483.0)

Net reserve additions - including revisions (Mboe) 5,160.4 7,254.6

F&D Costs - excluding natural gas technical revisions ($/boe) $ 28.81 $ 23.34F&D Costs - including natural gas technical revisions ($/boe) $ 32.71 $ 33.53

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FOURTH QUARTER 2011 FINANCIAL RESULTS

Three Months ended December 31,

(thousands except share data) 2011 2010 % Change

Cash flow from operations $ 11,558 $ 7,134 62

Per share – basic and diluted $ 0.12 $ 0.11 9

Net Income (loss) $ (70,980) $ 20,153 -

Net debt – period end $ 49,087 $ 8,449 481

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FOURTH QUARTER 2011 OPERATING RESULTS

Three months ended December 31,

(6:1 oil equivalent conversion) 2011 2010 % Change

E&D Capital Spending ($ thousands) $ 42,157 $ (25,546) -

Average Daily Production:

Crude Oil & NGLS(bbls/d) 1,496 856 75

Natural Gas (mcf/d) 19,337 15,278 27

Oil Equivalent (boe/d) 4,719 3,402 39

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FISCAL 2011 FINANCIAL RESULTS

Year ended December 31,

(thousands except share data) 2011 2010 % Change

Cash flow from operations $ 49,511 $ 47,770 4

Per share – basic and diluted $ 0.30 $ 0.41 (27)

Net Income (loss) $ (74,974) $ 20,001 -

Net debt – period end $ 49,087 $ 8,449 481

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FISCAL 2011 OPERATING RESULTS

Year ended December 31,

(6:1 oil equivalent conversion) 2011 2010 % Change

E&D Capital Spending ($ thousands) $ 99,964 $ 15,874 530

Average Daily Production:

Crude Oil & NGLS(bbls/d) 877 681 29

Natural Gas (mcf/d) 15,568 18,321 (15)

Oil Equivalent (boe/d) 3,472 3,734 (7)