APRIL 2012
CIBC 2012 ENERGY CONFERENCE
CORPORATE PRESENTATION
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.
2
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.
3
FORMATION OF COMPANY
Formed May 11, 2011 with the combination of Orleans Energy Ltd. and RMP
Energy Ltd.
Trading Symbol
RMP.TO
Shares Outstanding
96.7 million
Options
8.2 million
Warrants
2.9 million
Directors’ & Officers’ ownership (fully diluted)
12%
4
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
5
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 $5.0 billion in WCSB since 1992
Team is a proven value creator throughout commodity price cycles
6
2012 FORECAST
E&D Capital Spending
Production:
Annual Avg. (boe/d)
December 2011(boe/d)
Cash Flow
Per basic share
Assumptions:
Crude Oil ($WTI/bbl)
Natural Gas ($AECO/GJ)
Net Debt
Line of Credit
2011 Actual
2012 Budget
% Change
$ 100 million
$ 75 million
(25)
3,472
5,000
5,000-5,500
44-58
$ 24.4 million
$ 0.30
$ 55-$ 65 million
$ 0.57 - $ 0.67
125-166
90-123
$ 95.05
$ 3.50
$ 94.00
$ 3.00
(1)
(14)
$ 49.1 million
$60 - $70 million
22-43
$ 80 million
$ 80 million
7
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)
8
CORE AREAS
Light oil exploration and development
•
Waskahigan
•
Ante Creek
•
Big Muddy
Natural gas potential
•
Kaybob
•
Pine Creek
•
Ricinus
9
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.
10
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
11
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
• 40o API Light Oil
• GOR: 2,500 scf/bbl
12
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
13
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
14
WASKAHIGAN
MONTNEY OIL
15
WASKAHIGAN
MONTNEY OIL
16
WASKAHIGAN
MONTNEY OIL
17
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
18
CONCLUSION
Strong production growth through oil development at Waskahigan and Ante
Creek
• Focus on costs
Tremendous natural gas potential at:
•
Kaybob
•
Pine Creek
•
Ricinus
19
APPENDIX
20
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
21
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
22
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
23
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
24
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
25
BIG MUDDY
BAKKEN OIL PROSPECT
26
RESERVES SUMMARY
December 31, 2011 Reserves Summary (1) (Company interest before royalties)
Natural Gas
(Bcf)
Light Crude Oil
(Mbbls)
NGLs
(Mbbls)
Oil Equivalent
(Mboe) (6:1)
29.295
1,596.7
532.1
7,011.3
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
73.156
9,406.5
1,077.7
22,676.9
54%
41%
5%
(Columns may not add due to rounding)
Proved developed producing
Proved developed non-producing
Commodity Weighting
Note (1) Estimated using InSite’s forecast prices and costs as of December 31, 2011.
27
NET PRESENT VALUE SUMMARY
December 31, 2011 Net Present Value Summary (Company interest before royalties)
(Columns may not add due to rounding)
0%
8%
10%
15%
20%
$ 214,478
$ 150,980
$ 141,124
$ 122,094
$ 108,423
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
$ 763,345
$ 362,877
$ 313,405
$ 226,910
$ 171,991
Discount factor:
Proved developed producing
Proved developed non-producing
Total Proved plus Probable
Note (1) Estimated using InSite’s forecast prices and costs as of December 31, 2011.
28
F&D COSTS
F&D Costs
(amounts in $000s except reserve units and unit costs)
Fiscal 2011
Proved
Proved + Probable
$ 86,596
$ 86,596
Waskahigan oil battery and gathering lines infrastructure
18,531
18,531
Net land dispositions
(5,163)
(5,163)
1,037
1,037
$ 101,001
$ 101,001
Future development cost - ending period
149,734
239,855
Less: Future development cost - beginning period
(81,953)
(97,573)
$ 168,782
$ 243,283
6,683.9
11,737.6
(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 ($/boe)
F&D Costs - including natural gas technical revisions ($/boe)
$ 28.81
$ 32.71
$ 23.34
$ 33.53
Exploration and development expenditures
Capitalized general and administrative and office costs
Total finding and development expenditures
All-in total, including change in future development cost
Reserve additions - excluding acquisitions / dispositions and natural gas
technical revisions (Mboe)
Natural gas technical revisions - (Mboe)
29
FOURTH QUARTER 2011
FINANCIAL RESULTS
Three Months ended December 31,
2011
2010
% Change
Cash flow from operations
$ 11,558
$ 7,134
62
Per share – basic and diluted
$
(thousands except share data)
Net Income (loss)
Net debt – period end
0.12
$
0.11
9
$ (70,980)
$ 20,153
-
$ 49,087
$ 8,449
481
30
FOURTH QUARTER 2011
OPERATING RESULTS
Three months ended December 31,
(6:1 oil equivalent conversion)
E&D Capital Spending ($ thousands)
2011
2010
% Change
$ 42,157
$ (25,546)
-
1,496
856
75
19,337
15,278
27
4,719
3,402
39
Average Daily Production:
Crude Oil & NGLS(bbls/d)
Natural Gas (mcf/d)
Oil Equivalent (boe/d)
31
FISCAL 2011
FINANCIAL RESULTS
Year ended December 31,
2011
2010
% Change
Cash flow from operations
$ 49,511
$ 47,770
4
Per share – basic and diluted
$
$
(thousands except share data)
Net Income (loss)
Net debt – period end
0.30
0.41
(27)
$ (74,974)
$ 20,001
-
$ 49,087
$ 8,449
481
32
FISCAL 2011
OPERATING RESULTS
Year ended December 31,
(6:1 oil equivalent conversion)
E&D Capital Spending ($ thousands)
2011
2010
% Change
$ 99,964
$ 15,874
530
877
681
29
15,568
18,321
(15)
3,472
3,734
(7)
Average Daily Production:
Crude Oil & NGLS(bbls/d)
Natural Gas (mcf/d)
Oil Equivalent (boe/d)
33