1. CIBC 2012 ENERGY CONFERENCE CORPORATE PRESENTATION APRIL 2012

2. 2 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.

3. 3 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.

4. 4 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%

5. 5 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

6. 6 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

7. 7 2012 FORECAST 2011 Actual2012 Budget% Change E&D Capital Spending $ 100 million$ 75 million(25) Production: Annual Avg. (boe/d) 3,4725,000-5,50044-58 December 2011 (boe/d) 5,000 Cash Flow$ 24.4 million$ 55-$ 65 million125-166 Per basic share$ 0.30$ 0.57 - $ 0.6790-123 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 - $70 million22-43 Line of Credit$ 80 million$ 80 million-

8. 8 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)

9. 9 Light oil exploration and development Waskahigan Ante Creek Big Muddy Natural gas potential Kaybob Pine Creek Ricinus CORE AREAS

10. 10 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.

11. 11 WASKAHIGAN MONTNEY 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

12. 12 WASKAHIGAN MONTNEY 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 40 o API Light Oil GOR: 2,500 scf/bbl

13. 13 WASKAHIGAN MONTNEY 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

14. 14 WASKAHIGAN MONTNEY 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

15. 15 WASKAHIGAN MONTNEY OIL

16. 16 WASKAHIGAN MONTNEY OIL

17. 17 WASKAHIGAN MONTNEY OIL

18. 18 ANTE CREEK MONTNEY 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

19. 19 CONCLUSION Strong production growth through oil development at Waskahigan and Ante Creek Focus on costs Tremendous natural gas potential at: Kaybob Pine Creek Ricinus

20. 20 APPENDIX

21. 21 DIRECTORS Craig StewartExecutive Chairman of RMP Energy Inc. Doug BakerIndependent Businessman John BrussaPartner, Burnet Duckworth & Palmer LLP John FergusonPresident and CEO of RMP Energy Inc. Andrew HoggPresident and CEO of Coda Petroleum Inc. Jim SaundersPresident and CEO of Twin Butte Energy Ltd. Lloyd SwiftIndependent Businessman

22. 22 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

23. 23 PINE CREEK WILRICH 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

24. 24 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

25. 25 RICINUS LIQUID 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

26. 26 BIG MUDDY BAKKEN OIL PROSPECT

27. 27 RESERVES SUMMARY December 31, 2011 Reserves Summary (1) (Company interest before royalties) Natural GasLight Crude OilNGLsOil Equivalent (Columns may not add due to rounding) (Bcf)(Mbbls) (Mboe) (6:1) Proved developed producing29.2951,596.7532.17,011.3 Proved developed non-producing0.561207.41.5302.5 Proved undeveloped21.3953,232.2285.87,083.8 Total Proved51.2525,036.3819.414,397.6 Probable21.9044,370.2258.38,279.3 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.

28. 28 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-producing12,5347,8767,1915,9085,021 Proved undeveloped193,90571,77956,07328,50611,113 Total Proved 420,917230,636204,388156,508124,557 Probable342,428132,241109,01770,40247,435 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.

29. 29 F&D COSTS F&D Costs (amounts in $000s except reserve units and unit costs) Fiscal 2011 ProvedProved + Probable Exploration and development expenditures$ 86,596 Waskahigan oil battery and gathering lines infrastructure18,531 Net land dispositions(5,163) Capitalized general and administrative and office costs1,037 Total finding and development expenditures$ 101,001 Future development cost - ending period149,734239,855 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) 6,683.911,737.6 Natural gas technical revisions - (Mboe)(1,523.5)(4,483.0) Net reserve additions - including revisions (Mboe)5,160.47,254.6 F&D Costs - excluding natural gas technical revisions ($/boe)$ 28.81$ 23.34 F&D Costs - including natural gas technical revisions ($/boe)$ 32.71$ 33.53

30. 30 FOURTH QUARTER 2011 FINANCIAL RESULTS Three Months ended December 31, (thousands except share data) 20112010% 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$ 8,449481

31. 31 FOURTH QUARTER 2011 OPERATING RESULTS Three months ended December 31, (6:1 oil equivalent conversion) 20112010% Change E&D Capital Spending ($ thousands) $ 42,157$ (25,546)- Average Daily Production: Crude Oil & NGLS (bbls/d) 1,49685675 Natural Gas (mcf/d) 19,33715,27827 Oil Equivalent (boe/d) 4,7193,40239

32. 32 FISCAL 2011 FINANCIAL RESULTS Year ended December 31, (thousands except share data) 20112010% 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$ 8,449481

33. 33 FISCAL 2011 OPERATING RESULTS Year ended December 31, (6:1 oil equivalent conversion) 20112010% Change E&D Capital Spending ($ thousands) $ 99,964$ 15,874530 Average Daily Production: Crude Oil & NGLS (bbls/d) 87768129 Natural Gas (mcf/d) 15,56818,321(15) Oil Equivalent (boe/d) 3,4723,734(7)