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NOVEMBER 15 & 16, 2011. FirstEnergy Capital Corp. 2011 FirstEnergy Conference. Corporate Presentation. dISCLAIMER.

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firstenergy capital corp 2011 firstenergy conference
NOVEMBER 15 & 16, 2011

FirstEnergy Capital Corp.

2011 FirstEnergy Conference

Corporate Presentation

disclaimer
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.

disclaimer1
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.

formation of company
Formation of company
  • Formed May 11, 2011 with the combination of Orleans Energy Ltd. and RMP Energy Ltd.
  • Trading Symbol RMP.TO
    • Shares Outstanding 96.3 million
      • Options 8.3 million
      • Warrants 2.9 million
      • Directors’ & Officers’ ownership (fully diluted) 12%
company
COMPANY
  • Created a very focused, well-managed and high quality junior producer
  • Significant Waskahigan light oil development opportunity
    • Near-term focus
    • Excellent natural gas resource potential
      • Strong balance sheet
      • Large tax pool balance
directors
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

management team
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

management track record
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
2011 forecast
2011 forecast
  • Capital Spending $ 100 million
    • Production
          • Annual Avg. 3,300 boe/d
          • December 20115,000 boe/d (40% Oil and NGLs)
      • Cash Flow $ 22 million
core areas
Core areas
  • Oil exploration and development
    • Waskahigan
    • Ante Creek
    • Big Muddy
  • Natural Gas potential
    • Kaybob
    • Pine Creek
    • Resthaven/Bilbo
    • Ricinus
montney oil fairway
MONTNEY Oil FAIRWAY
  • Significant land position in the Montney oil fairway
  • Large Montney oil accumulations in this region
  • Active area for:
  • Montney
  • Nordegg
  • Duvernay

Waskahigan resource potential: OOIP: 264 Mstb

OGIP: 194 BCF

Total: 296 Mboe

waskahigan montney oil
WaskahiganMontney Oil
  • Top tier light oil play in WCSB
  • Large accumulation: resource study estimate 264 Mstb OOIP
  • Three years of low risk infill drilling inventory (33 locations)
    • Up to 100 additional locations with step out drilling
  • 100% owned and operated facility, commissioned and on-stream end of October 2011
    • Capacity: 2500 bbl/d oil & 10 mmcf/d gas
    • Readily expandable to double capacity
  • High netbacks >$60/boe; low operating costs <$7/boe
  • Large unbooked resource
  • Exceptional economics
waskahigan montney oil1
WaskahiganMontney Oil
  • 39 net sections 100% W.I.
  • Drilled wells: 15
  • 2 more wells drilled in 2011
    • Completions will commence in new year
  • HTE and ASOC locations have the potential to significantly de-risk the northern part of property and increase development program.
  • Potential for up to 100 additional locations.
  • Pool details
    • Avg. OOIP/Section: 8,000 MBOE
    • 40o API Light Oil
    • GOR: 2,500 scf/bbl
waskahigan montney oil2
WaskahiganMontney Oil

Development

  • 32 locations in licensing process
  • 100+ 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. 9 pads are built and pipelines are in the ground.
waskahigan montney oil3
WaskahiganMontney Oil

Oil Battery

  • Design capacity
  • 2500 bbl/d oil
  • 10 mmcf/d natural gas
  • $16 million capital
  • Will significantly reduce transportation and operating costs
  • Expansion
  • Battery has been designed to be expanded
  • Capacity can be doubled
ante creek montney oil
ANTE CREEKMontney Oil
  • 5 sections 100% W.I.
  • Extension of Ante Creek oil pool
  • Significant activity in area with positive results by HTE, POU, CNQ, ARX
  • Currently surveyed location with drilling to start this winter
  • Success will result in multi-well program
pine creek wilrich natural gas
Pine CreekWilrich Natural Gas
  • 6.25 net sections, 56% W.I.
  • Wilrich HZ development
  • 4 wells currently producing from Wilrich, 1 more well anticipated by year end (40% W.I.; Peyto operated)
  • Currently producing ~ 750 boe/d
resthaven bilbo liquid rich natural gas
Resthaven/bilboLiquid Rich Natural Gas
  • Large land base in multi-zoned, gas-charged area
  • Montney gas exploration has driven recent activity
  • Significant investment in HZ Montney drilling by competitors
  • Results will dictate RMP’s pace of development
  • Secondary targets include Nikanassinand Halfway
kaybob montney natural gas
KaybobMontney Natural Gas
  • 28 sections 92% W.I.
  • Significant low risk gas inventory
  • 60 locations; 90 BCF
  • Infrastructure is established; quick tie-in and onstreamprojects
  • Industry is still very active in area; i.e TQN, TET, CLT
  • Very attractive play when gas prices recover
conclusion
conclusion
  • Strong production growth through oil development at Waskahigan
  • Exposure to oil exploration at Ante Creek and Big Muddy
    • Tremendous natural gas potential at:
      • Kaybob
      • Pine Creek
      • Ricinus
      • Resthaven/Bilbo
ricinus liquid rich natural gas
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
third quarter 2011 financial results
THIRD Quarter 2011 financial results

Nine months ended September 30,

(thousands except share data) 2011 2010 % Change

Cash flow from operations $ 12,848 $ 19,784 (35)

Per share – basic and diluted $ 0.17 $ 0.30 (43)

Net Income (loss) $ (3,994) $ (152) -

Net debt – period end $ 37,822 $ 46,305 (18)

third quarter 2011 operating results
THIRD Quarter 2011 operating results

Nine months ended September 30,

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

E&D Capital Spending ($ thousands) $ 68,476 $ 41,420 65

Average Daily Production:

Crude Oil & NGLS(bbls/d) 668 621 8

Natural Gas (mcf/d) 14,297 19,347 (26)

Oil Equivalent (boe/d) 3,051 3,846 (21)

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