1. business and industrial
2. energy
3. natural gas

Full Cycle Profitable Growth
CORPORATE PRESENTATION
TSX: BXE
JULY 2015
NYSE: BXE
Advisories
FORWARD LOOKING STATEMENTS: In the interest of providing Bellatrix’s shareholders and potential investors with information regarding Bellatrix, including management’s assessment of Bellatrix’s future plans and operations, certain statements made by the presenter and contained in these presentation
materials (collectively, this “presentation”) are forward looking statements or information within the meaning of applicable securities legislation, collectively referred to herein as “forward looking statements”. The forward-looking statements contained in this presentation speak only as of the date of this
presentation and are expressly qualified by this cautionary statement. Forward looking statements in this presentation include, but are not limited to: management's intended strategy, including its intent to focus on per share profitability, to be a low cost finder and operator, and to target accretive tuck-in
acquisitions, to adopt leading technological advancements, to produce industry leading well results, to secure and grow processing capacity to up to 80,000 boe/d, and to maintain a strong balance sheet and financial flexibility; management’s forecasted 2015 operating metrics, including capital, production and
operating costs per boe; management’s presentation of hedges as a percentage of forecasted volumes; management’s assessment that Bellatrix is a low cost operator and has top quartile 3 year average finding, development and acquisition (“FD&A”) costs; management’s expectations regarding the
Mannville/Spirit River and Cardium areas; management’s estimates of payouts and the internal rate of return (“IRR”) of its wells; management’s assessment that Bellatrix’s profit margin improves when processing Spirit River well production through its proposed deep cut gas plant; the impact of strategic
infrastructure on revenues, operating costs and netbacks, and forecasted liquid recoveries from Bellatrix’s proposed deep cut gas plant; the timing of completion, costs of commissioning and capacities of Bellatrix’s proposed deep cut gas plant; management's assessment of future plans and operations; drilling
plans and the timing thereof; commodity price risk management strategies; estimated average and exit production rates and the oil and liquids percentage of such production; estimates of commodity prices and exchange rates; and drilling inventory and costs and time to develop. Certain statements may
constitute financial outlooks under applicable securities laws and were approved by management on March 11, 2015. Forward-looking statements necessarily involve risks, including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and
transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated
benefits of acquisitions, actual results from wells to be drilled may not be similar to the results from previous wells drilled or the expected type curves, and delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources. Events or
circumstances may cause actual results to differ materially from those predicted, as a result of the risk factors set out and other known and unknown risks, uncertainties, and other factors, many of which are beyond the control of Bellatrix. In addition, forward-looking statements or information are based on a
number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect and which have been used to develop such statements and information in order to provide shareholders with a more complete perspective on Bellatrix's future operations.
Such information may prove to be incorrect and readers are cautioned that the information may not be appropriate for other purposes. Although Bellatrix believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forwardlooking statements because Bellatrix can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the
economic and political environment in which Bellatrix operates; the timely receipt of any required regulatory approvals; the ability of Bellatrix to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which Bellatrix has an
interest in to operate the field in a safe, efficient and effective manner; the ability of Bellatrix to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development of exploration; the timing and costs of
pipeline, storage and facility construction and expansion and the ability of Bellatrix to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Bellatrix
operates; and the ability of Bellatrix to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. As a consequence, actual results may differ materially from those anticipated in the forward-looking
statements. Additional information on these and other factors that could affect Bellatrix's operations and financial results are included in reports on file with Canadian securities regulatory authorities and the U.S. Securities Exchange Commission ("SEC") and may be accessed through the SEDAR website
(www.sedar.com), through the SEC website (www.sec.gov), and at Bellatrix's website (www.bellatrixexploration.com). Furthermore, the forward-looking statements contained herein are made as at the date hereof and Bellatrix does not undertake any obligation to update publicly or to revise any of the included
forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.
NON-GAAP MEASURES: This presentation may contain certain non-GAAP measures, including the term “cash flow” which is a non-GAAP measure defined as cash from operating activities excluding net change in other assets and liabilities, net change in non-cash working capital and cash tax on sale of assets. This
and any other non-GAAP measures used in this presentation are intended to provide shareholders and potential investors with additional information regarding Bellatrix’s liquidity and its ability to generate funds to finance its operations.
FD&A COSTS: This presentation includes calculations of FD&A costs for the year ended December 31, 2014. National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") requires that written disclosure of finding and development costs to be calculated in accordance with Section 5.15
of NI 51-101 which does not include the reserves additions associated with acquisitions or the costs of acquisitions in the calculation. The calculations of FD&A in this presentation include the reserves additions associated with acquisitions and the costs of acquisitions as Bellatrix believes that including the effect
of acquisitions provides useful information to investors. FD&A costs for the year ended December 31, 2014, 2013 and 2012 are $13.22/boe, $9.67/boe and $6.95/boe on a proved plus probable basis, respectively, and the average FD&A for the last three completed years is $10.05/ proved plus probable boe. The
finding and developments costs calculated in accordance with Section 5.15 of NI 51-101 for the years ended December 31, 2014, 2013 and 2012 are $18.56/proved boe ($23.80/proved plus probable boe, $10.67/proved boe ($9.65/proved plus probable boe) and $11.73/proved boe ($7.31/proved plus probable
boe), respectively, and the average finding and development costs for the last three completed years is $13.45/proved boe ($11.69/proved plus probable boe). 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 reserve additions for that year.
BOE PRESENTATION: The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 mcf/ 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner
tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. All boe
conversions in this presentation are derived from converting gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil.
INITIAL PRODUCTION RATES: Initial production rates disclosed herein may not be indicative of long-term performance or ultimate recovery. Such rates are not determinative of the future production rates of such wells and do not reflect how the production from such wells will decline thereafter. While
encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for Bellatrix. A pressure transient analysis or well test interpretation has not been carried out in respect of all wells. Accordingly, Bellatrix cautions that the test results should be considered to be
preliminary.
ESTIMATED ULTIMATE RECOVERY (EUR): In this presentation, estimated ultimate recovery represents the estimated ultimate recovery associated with the type curves presented which are based on the assumptions used by Sproule Associates Limited to estimate Bellatrix's proved plus probable reserves per well
as evaluated effective December 31, 2014 based on forecast prices and costs. There is no certainty that such Bellatrix will ultimately recover such volumes from the wells it drills.
ANALOGOUS INFORMATION: Certain information in this presentation may constitute "analogous information" as defined in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”), including, but not limited to, the reservoir data, production rates of industry wells, cumulative
production information, and economics information relating to the areas in which Bellatrix has an interest. Such information has been obtained from government sources, regulatory agencies or other industry participants. Management of Bellatrix believes the information is relevant as it helps to define the
reservoir characteristics and the reserves and production potential in which Bellatrix holds an interest. Such information has not been prepared in accordance with NI 51-101. Bellatrix is also unable to confirm that the analogous information was prepared by a qualified reserves evaluator or auditor. Such
information is not an estimate of the resources attributable to lands held or to be held by Bellatrix and there is no certainty that the reservoir data, resource estimates, production and decline rates and economics information for the lands held by Bellatrix will be similar to the information presented herein. The
reader is cautioned that the data relied upon by Bellatrix may be in error and/or may prove not be analogous to the lands be held by Bellatrix.
CURRENCY: All dollar amounts in this presentation are Canadian dollars unless otherwise identified.
DRILLING LOCATIONS: This presentation discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are sometimes collectively referred to as “booked locations”, are derived from Bellatrix’s most recent
independent reserves evaluation and account for drilling locations that have associated proved + probable reserves or probable-only reserves, as applicable. Unbooked locations are internal estimates based on Bellatrix’s acreage outside of evaluated areas and an assumption as to the number of wells that can be
drilled per section based on industry practice and internal review. Unbooked locations have not been risked, and do not have attributed reserves or resources.
RESERVES INFORMATION: Unless indicated otherwise, reserve estimates and related future net revenue and other reserves information is derived from Bellatrix’s independent reserve report prepared by Sproule Associates Limited as at December 31, 2014 using forecast prices and costs. Land acreage
information is as available at December 31, 2014.
FINANCIAL INFORMATION: Unless otherwise stated, financial information is based upon Bellatrix’s 2014 audited consolidated financial statements for the years ended December 31, 2014 and 2013.
2
Bellatrix Core Values
Focus on per
share profitability
Technically strong
• Track record of
production, reserve &
cash flow growth
• Early stage adoption of
leading technological
advancements
• Low cost finder
and operator
• Strong well results and
performance; low natural
gas supply cost
• Accretive tuck-in
acquisition strategy
3
• Drill bit driven
growth
Strategic direction
& vision
Flexible financial
position
• 20+ years drilling
inventory
• Balance sheet
preservation through
commodity cycle
• Secured firm service
processing & gas plant
construction
• Total net processing
capacity estimated at
80,000 boe/d with
Phase 2 of gas plant
Shareholder value creation
• JV strategy including
promoted external
capital
• Strategic long term
infrastructure asset
value
Corporate Profile
MARKET SUMMARY
Ticker Symbol
TSX / NYSE: BXE
Average Daily Volume1
Canada: 1.8 million / U.S.: 0.7 million
Shares Outstanding
192.0 million basic / 202.7 million diluted
Market Capitalization2
$612 million
Net Debt (Q1/2015)
$696 million
Enterprise Value2
$1.31 billion
2015 Average Production
43,000 to 44,000 boe/d
Natural Gas Weighting
67%
1
2
4
Three month average at June 24, 2015
Calculated using June 24, 2015 share price (C$3.19/share)
Doing More with Less in 2015
2015 FORECAST
2014 ACTUAL
2015/2014
CHANGE
$200
$504
-60%
Infrastructure ($MM)
$70
$188
-63%
Drilling & Completions ($MM)
$120
$298
-60%
Other ($MM) 1
$10
$18
-44%
Net Capital Budget ($MM)
Average Production
Low range (boe/d)
43,000
38,065
+13%
High range (boe/d)
44,000
38,065
+16%
67%
67%
0%
$8.25
$8.64
-5%
Natural gas weighting (%)
Operating costs ($/boe)2
other spending includes land, geological, and geophysical costs
Operating costs before net processing revenue/fees
Net capital spending excludes acquisition and divestiture activity which totaled $176 million and $10 million respectively in 2014
1
2
5
Commodity Price Risk Management
90%
OIL HEDGES
60%
AECO swap $C/Mcf
$2.93 $2.93
% of total forecast oil & condi volumes
% of total forecast 2015 gas volumes
100%
NATURAL GAS HEDGES
AECO Basis swap
80%
70%
60%
50%
$2.95
$3.38 $3.38 $3.38 $3.38
40%
$3.38 $3.38 $3.38 $3.38
30%
20%
10%
0%
•
•
•
50 MMcf/d @ C$2.95/Mcf (Apr-Dec 2015)
106.7 MMcf/d @ C$2.92/Mcf (Apr-Oct 2015)
44.3 MMcf/d @ C$3.38/Mcf (2016 & 2017)
C$70.34
C$70.34
C$70.34
Q2/15
Q3/15
Q4/15
40%
30%
20%
10%
0%
Q2/15 Q3/15 Q4/15 Q1/16 Q2/16 Q3/16 Q4/16 Q1/17 Q2/17 Q3/17 Q4/17
AECO fixed price swap contracts:
50%
Canadian dollar WTI crude oil hedges:
•
3,000 bbl/d @ C$70.34/bbl (Apr-Dec 2015)
AECO basis swaps
•
•
6
~35 MMcf/d @ US$0.70/Mcf (2016)
~16 MMcf/d @ US$0.70/Mcf (2017)
Note: Percent of total forecast volumes based on mid-point of full year average 2015 production guidance (43,500 boe/d)
Natural gas hedges have been converted from $/GJ to $/Mcf based on an assumed average corporate heat content of 40.8 Mj/m3 in 2015 and 40.0 Mj/m3 in 2016 & 2017. Oil hedges are
Canadian dollar WTI equivalent. All hedges are denominated in Canadian dollars unless otherwise noted.
Track Record of Production and
Reserves Growth
HISTORICAL PRODUCTION
38,065
80
70
12,469
50
21,829
16,686
30
5,717
25,596
20
4,540
15,340
33%
140
103.7
100
80
42.4
41.8
24.8 28%
29%
38%
40%
124.1
0.6
36%
0.4
55.2
37%
0.2
2013
2014
2010
45% CAGR total corporate production
23% CAGR production per share
CAGR – Compounded Annual Growth Rate
Basic weighted average shares
2011
2012
2013
P+P
0
2012
0.0
Proved
0
0
7
37%
67.4
60
20
0.8
36%
120
40
1.0
161.4
160
P+P
2011
10
211.5
180
Proved
2010
10,969
200
P+P
5,969
7,414
37%
Proved
2,550
1.2
220
P+P
8,519
6,489
1.4
240
Proved
10,000
40
250.1
P+P
11,954
60
Reserves per share (right side)
260
Proved
Production (boe/d)
30,000
Oil and Liquids
2014
56% CAGR P+P reserves
32% CAGR P+P reserves per share
Reserves per year end share (boe/share)
40,000
20,000
Natural Gas
Production per share (right side)
Reserves (MMboe)
Oil and Liquids
Production per avg. share (boe/000's shares)
Natural Gas
HISTORICAL RESERVES
Track Record of Cash Flow
and Earnings Growth
$300
$175
$1.60
Operating Funds Flow
FFO Per Share
$271
$250
$200
$1.00
$0.80
$150
$143
$100
$0.60
$111
$94
$50
$0.40
$53
$0
2010
2011
2012
2013
2 2010 –
$100
$0.60
$75
$0.45
$72
$50
$0.30
$25
$0.15
$18
$0
$0.00
($50)
CAGR calculated beginning in 2011 given negative values in 2010
2012 Earnings reflect reported earnings before certain non-cash items
Basic weighted average shares
1
$0.90
$0.75
($25)
2014
$163
EPS
$125
$0.20
50% CAGR operating funds flow
27% CAGR funds flow per share
8
Earnings ($ millions)
$1.20
$1.05
Earnings
$150
$1.40
Funds Flow Per Share
Operating Funds Flow ($ millions)
EARNINGS
$22
$0.00
$(28)
-$0.15
-$0.30
2010
2011
2012
2013
2014
107% CAGR net earnings1,2
71% CAGR earnings per share1,2
Earnings Per Share
OPERATING FUNDS FLOW
NAV of $1.7 Billion or $9.01 Per Basic Share
2P NAVPS BUILD-UP1
$14.00
$12.00
$1.31
$3.67
$10.00
Value ($ per basic share)
($3.32)
$8.00
$2.50
$6.00
$4.00
$9.01
$4.86
$2.00
$0.00
PDP (2)
$932MM
1P (2)
$479MM
2P (2)
Undev land +
seismic (3) (4)
$709MM
$251MM
Net debt (5)
($638MM)
Based on 191.95 million common shares outstanding as at December 31, 2014.
As evaluated by Sproule as at December 31, 2014 based on forecast prices and costs before income tax.
3 As estimated by Bellatrix as at December 31, 2014 based on 385,397 net acres of undeveloped land at an average price of $584.53 per acre.
4 Based on 26.1% of $99.8 million replacement value based on seismic costs to buy data at an average of $1,500/km for 2D and $14,500/km2 for 3D.
5 2014 year end net debt.
1
2
9
2P NAV
$1,729MM
Peer Group Comparison
OPERATING COSTS/ BOE1
$16.00
2P FD&A (INCLUDING FDC)2
$22.00
$20.00
$14.00
$18.00
$12.00
$16.00
$14.00
$10.00
$12.00
$8.00
$10.00
$6.00
$8.00
$6.00
$4.00
$4.00
$2.00
$2.00
$0.00
$0.00
BXE
Low cost operator
BXE
Top quartile 3 year average FD&A costs
Source: Public disclosure or calculated where unavailable
Note: Peer set includes select Canadian listed companies with gas weighting >50% and with an enterprise value between ~$1bn and ~$10bn
1 As at December 31, 2014 (2014 average costs)
2 3-yr average FD&A costs 2012-2014 (including future development capital)
10
Top Quartile Historical Results
PEER LEADING RESULTS
200%
179%
166%
160%
80%
120%
Peers
106%
BXE
120%
CASH FLOW PER SHARE GROWTH (2010-2014)1,2
31%
40%
14%
8%
0%
(0%)
(40%)
(10%)
(22%)
(80%)
200%
160%
(58%)
153%
149%
145%
PRODUCTION PER SHARE GROWTH (2010-2014)2
Peers
118%
BXE
120%
80%
40%
40%
35%
15%
5%
0%
(12%)
(40%)
(14%)
(80%)
(58%)
500%
P+P RESERVES PER SHARE GROWTH (2010-2014)3
400%
778%
3235%
200%
BXE
300%
100%
Peers
299%
141%
113%
98%
70%
43%
24%
5%
0%
(100%)
11
(4%)
Note: Peer group includes companies with gas weighting >50% and enterprise value between ~$1bn and ~$10bn, excluding those not in existence for the entire 2010-2014 period
1 Cash flow per share is a Non-GAAP Measure. See “Non-GAAP Measures” in the Advisories section of this presentation
2 Per share growth from 2010 to 2014 (based on weighted average fully diluted shares outstanding)
3 Per share growth from January 1, 2010 to December 31, 2014 (based on basic shares outstanding)
Concentrated Land Base
WEST CENTRAL ALBERTA
FERRIER
STRACHAN
Production1 (% of total):
74%
Production1 (% of total):
8%
Land2 (net acres):
75,333
Land2 (net acres):
50,750
P+P net locations:
178
P+P net locations:
33
Unbooked net locations:
549
Unbooked net locations:
40
WILLESDEN GREEN
HARMATTAN
Production1 (% of total):
4%
Production1 (% of total):
8%
Land2 (net acres):
22,879
Land2 (net acres):
100,393
P+P net locations:
18
P+P net locations:
46
Unbooked net locations:
122
Unbooked net locations:
156
GREATER PEMBINA
OTHER
Production1 (% of total):
3%
Production1 (% of total):
3%
Land2 (net acres):
40,521
Land2 (net acres):
393,770
P+P net locations:
30
P+P net locations:
17
Unbooked net locations:
167
Unbooked net locations:
254
1
2
Reflects % of year end 2014 exit corporate volumes
Net acreage as at December 31, 2014
12
Significant Drilling Inventory
NET ACREAGE1
Net dev.
sections
Net undev.
sections
Ferrier
59
Willesden Green
NET DRILLING LOCATIONS2
Total
Proved
locations
Probable
locations
Unbooked
locations
Total
locations
59
118
137
41
549
727
28
8
36
12
6
122
140
Greater Pembina
53
10
63
23
7
167
197
Strachan
23
56
79
22
11
40
73
Harmattan
52
105
157
28
18
156
202
Other
251
365
615
9
8
254
271
Total
466
603
1,068
231
91
1,288
1,610
Area
1:
2:
As at December 31, 2014
Numbers may not add due to rounding
13
Spirit River Liquids Rich Gas
BXE Land Sections
287 Gross1
162 Net1
BXE Net Drilling Inventory
44 proved
15 probable
339 unbooked
398 total
Spirit River Resource Play Summary
Regional Stacked Mannville Channels
deposited in broad valleys
>110 BXE and industry Notikewin / Falher /
Wilrich gas wells in greater area
2 mile Hz produced an estimated 5.0 Bcf gas
with 166 mbbls liquids in first year
Spirit River (Notikewin/Falher/Wilrich)
provides significant upside for Bellatrix
1
Greater Pembina including Angle Strachan but excluding Angle Harmattan & Davey
14
FERRIER CORE SPIRIT RIVER PLAY
Spirit River Geology Summary
Broad, thick, extensive sand rich valleys in Notikewin,
Falher and Wilrich members
Average thickness 25-40m
2 to 3 stacked channels per section
2-6 wells per pad
3 wells per zone to fully develop a section
+/- 2400 m depth
Currently drilling 1 mile laterals: 3 megabores drilled
17 frac stages / well
34 fracs in a 2 mile megabore
Porosity 6-18%; permeability 1-3 mD
Peak IP rates at 4.0 to 25.0 MMcf/d
Open and closed fracture systems evident in rock core
and to a lesser degree in rock cuttings
15
Low Supply Cost
Bellatrix Spirit River wells compare favorably with other top plays across the
Western Canadian Sedimentary Basin
70%
5.0
4.5
4.0
3.5
3.0
2.5
2.0
1.5
1.0
0.5
0.0
60%
40%
30%
20%
10%
Payout
Average payout
Comparative chart of payback and IRR rates across WCSB resource plays
Source: Canaccord Genuity Research. Uses Canaccord price deck: Approximately US$55/bbl WTI in 2015 and US$62/bbl WTI in 2016.
AECO at C$3.25/Mcf ($3.04/GJ) in 2015 and C$3.75/Mcf ($3.50/GJ) in 2016
16
IRR
Lloydminster
Glauc/Ellerslie
Shaunavon
Waskahigan Montney
Tower Oil
Banff (Michichi)
Ante Creek Montney
Edson Cardium
Cardium
NEBC Montney
Kakwa Montney
Valhalla Doig
Edson Bluesky
Torquay
Deep Basin Lower Cret.
Dawson Montney
Bakken
0%
IRR (%)
50%
BXE Spirit River
Payout (years)
PAYOUT & IRR PLAY COMPARISON
Industry Leader in Spirit River Development
COMPARATIVE 2014 NOTIKEWIN & FALHER COST & EFFICIENCY METRICS
Days to complete
10
5
0
BXE
$6.0
$5.0
BXE
Industry
Reported costs
7.0
Completion cost
$4.0
$3.0
$2.0
4.0
3.0
2.0
1.0
$0.0
0.0
17
IP90 Gas rate
5.0
$1.0
BXE
Industry
6.0
Drill cost
IP90 (MMcf/d)
Well costs ($ millions)
$7.0
Number of completion days
Industry
Source: Canadian Discovery Frac Database
BXE
Industry
3.0
Average days per stage
2.5
2.0
1.5
1.0
0.5
0.0
BXE
$10,000
Capital efficiency ($/boepd)
Number of stages
15
40
35
30
25
20
15
10
5
0
Days per completion stage
Frac stages
20
Industry
IP90 Capital efficiency
$8,000
$6,000
$4,000
$2,000
$0
BXE
Industry
Spirit River Type Curves
7.4 BCF TYPE CURVE
1,421 Mboe / 20% oil + liq.
IP30
1,887 boe/d (11.3 MMcfe/d)
Capex
IRR
BT NPV10
Payout
Half Cycle
Full Cycle
$4.7 MM
$5.8 MM
206%
131%
$12.0 MM
$11.4MM
0.7 years
0.9 years
5.2 BCF TYPE CURVE
EUR
1,008 Mboe / 20% oil + liq.
IP30
1,280 boe/d (7.7 MMcfe/d)
Capex
IRR
Half Cycle
Full Cycle
$4.7 MM
$5.8 MM
96%
62%
BT NPV10
$7.1 MM
$6.4 MM
Payout
1.1 years
1.5 years
PRICING ASSUMPTION
(C$/GJ)
2015
2016
2017+
$3.00
$3.50
Escalated at 2%
7.4 Bcf Type Curve
1,800
Average Production (boe/d)
EUR
SPIRIT RIVER TYPE CURVES
2,000
1,600
1,400
1,200
1,000
800
600
400
200
0
1
3
5
7
9
11
13
15 17 19 21
Producing Months
23
25
27
29
31
33
IRR SENSITIVITIES
>500%
7.4 Bcf Type Curve
400%
5.2 Bcf Type Curve
300%
200%
100%
0%
C$2/GJ
18
5.2 Bcf Type Curve
C$3/GJ
C$4/GJ
C$5/GJ
Note: Type Curves are generated from March 2011 – June 2014, Bellatrix operated, Notikewin and Falher B wells and represent P50 and P20 performance curves from actual results
Full cycle economics include an average $1.06 million per well for facilities, land and seismic related costs
IRR above 500% cannot be determined accurately and is presented by common convention as “>500%”
Spirit River All-In Profitability
Full cycle F&D costs
Full cycle F&D costs
$/Mcfe
($1.11)
Cash costs
$/Mcfe
($1.57)
Sales price
$/Mcfe
$4.15
Profit
Profit margin
$/Mcfe
$1.47
%
35%
Profit Margin improves to $2.48/Mcfe or 50%
when identical stream processed through BXE
deep-cut plant post July 2015
1
2
Operating costs assume $0.56/Mcf for natural gas and $7.50/bbl for oil
Sales prices assume AECO at $3/Mcf, ethane @ $10/bbl, propane @ $20/bbl, butane @ $35/bbl and condensate @ $60/bbl
19
Drill
Complete
Equip & tie-in
Half cycle costs
Land/seismic/facilities
Full cycle costs
$2.1MM
$1.7MM
$0.8MM
$4.7MM
$1.1MM
$5.8MM
EUR (low type curve)
5.2Bcfe
Full cycle F&D
$1.11/Mcfe
Cash costs
Royalties (est @ 8%)
Operating costs 1
Transport
G&A
Interest
Total costs
$0.33/Mcfe
$0.61/Mcfe
$0.15/Mcfe
$0.25/Mcfe
$0.23/Mcfe
$1.57/Mcfe
Sales price2
Total sales price
$4.15/Mcfe
Cardium Light Oil Resource Play
BXE Cardium Sections
494 Gross
334 Net
Edson
BXE Net Drilling Inventory
157 proved
50 probable
348 unbooked
555 total
Pembina
Ferrier
Lease Operate Expense < $9.00/boe
Cardium Resource Play Summary
Largest accumulation of light oil in the WCSB
Approximately 20,000 square miles
Approximately 1.9 Billion bbls produced to date
Currently producing 140,000 bbl/d & 1.0 Bcf/d
Cardium remains a key focus
area for Bellatrix
20
Strachan
Harmattan
Proven Innovative Development
The leading Cardium driller since 2013
APPLYING CUTTING EDGE EXPLOITATION TECHNIQUES
Horizontal well placement and applying
cutting edge exploitation techniques
results in top-tier well results compared
to industry
DRIVES INDUSTRY LEADING RESULTS
IP90
330
well count
290
boe/d
270
250
230
210
190
170
ARX
Baccalieu
PWT
Regent
BTE
JOY
WCP
TOG
TVE
BNE
VET
LTS
BXE
150
Well count
100
90
80
70
60
50
40
30
20
10
0
310
Comparative chart of IP90 production rates for horizontal wells drilled 2013+ in greater Pembina/Ferrier/Willesden Green areas
Source: National Bank Financial Inc. Research
21
Cardium Type Curves
EUR
454 Mboe / 41% oil + liq.
IP30
650 boe/d
Capex
IRR
Half Cycle
Full Cycle
$3.9 MM
$5.0 MM
49%
30%
BT NPV10
$4.3 MM
$3.2 MM
Payout
1.9 years
3.0 years
Average Production (boe/d)
CARDIUM OIL WEIGHTED TYPE
CARDIUM TYPE CURVES
700
CURVE1
Cardium Oil Weighted
500
400
300
200
100
0
1
3
5
FERRIER GAS TYPE CURVE1
EUR
576 Mboe / 20% oil + liq.
IP30
609 boe/d
Half Cycle
Full Cycle
$3.9 MM
$5.0 MM
33%
26%
BT NPV10
$2.6 MM
$0.6 MM
Payout
2.7 years
4.3 years
Capex
IRR
140%
120%
100%
80%
60%
40%
20%
0%
7
9
11
13
15 17 19 21
Producing Months
23
25
27
29
31
33
35
IRR SENSITIVITIES
Cardium Oil Weighted Type Curve
Ferrier Gas Type Curve
Gas C$2/GJ /
Oil $50/bbl
22
Ferrier Gas
600
Gas C$3/GJ /
Oil $65/bbl
Gas C$4/GJ /
Oil $80/bbl
Gas C$5/GJ /
Oil $95/bbl
Cardium Oil Weighted Type Curve is generated from analysis of all producing oil reserve assignments from Sproule at year-end 2014 and is the P-mean performance well from this distribution as
evaluated by Sproule. Ferrier Gas Type Curve is generated from all producing Ferrier Cardium gas wells and represents P50 performance curve from actual results
Full cycle economics include an average $1.06 million per well for facilities, land and seismic related costs
1: Economics run using an average of the forecast prices published by Sproule Associates Ltd., GLJ Petroleum Consultants Ltd., and McDaniel & Associates Consultants Ltd. As at January 1, 2015
WTI @ US$64.17/bbl, Edm Par @ $67.89/bbl, and AECO @ C$3.38/MMBtu in 2015
Cardium (P-Mean Type Curve) Provides Long-Term
Low Risk Optionality At Higher Oil Prices
Base case (US$70/bbl WTI)
Full cycle F&D costs
Full cycle F&D costs
$/boe
($10.81)
($10.81)
($10.81)
($10.81)
($10.81)
($10.81)
Cash costs
$/boe
($15.27)
($15.77)
($16.26)
($16.75)
($17.24)
($17.73)
Drill
Complete
Equip & tie-in
Half cycle costs
Land/seismic/facilities
Full cycle costs
Sales price
$/boe
$24.12
$28.21
$32.30
$36.39
$40.49
$44.58
EUR (oil type curve)
454 mboes
Profit
$/boe
($1.97)
$1.63
$5.23
$8.83
$12.43
$16.03
Full cycle F&D
$10.81/boe
%
-8%
6%
16%
24%
31%
36%
US$40/bbl US$50/bbl US$60/bbl US$70/bbl US$80/bbl US$90/bbl
C$44/bbl C$57/bbl C$69/bbl C$82/bbl C$94/bbl C$107/bbl
WTI
Edm Par
Profit margin
$2.00MM
$1.50MM
$0.35MM
$3.85MM
$1.06MM
$4.91MM
Cash costs
Royalties (est @ 12%)
Operating costs 1
Transport
G&A
Interest
Total costs
$4.37/boe
$8.50/boe
$1.00/boe
$1.50/boe
$1.38/boe
$16.75/boe
Sales price2
1 Historical
LOE average ~$8.50/boe for Cardium
Sales prices assume AECO at $3/Mcf, light oil @ Edm Par less $5/bbl, ethane @ 15% Edm Par, propane @ 40% Edm Par,
butane @ 60% Edm Par, condensate @ 100% Edm Par
3 Sensitivities include flat $0.80 USD/CAD exchange and Edm Par at C$WTI less $6/bbl
2
23
Total sales price
$36.39/boe
Early Stage Adoption of Leading
Technological Advancements
24
2009
2010
Enhanced recovery using
horizontal wells and
multistage
frac technology
Increased recoveries and
reduced per well costs
2011
2012
Began to transfer
technology know-how to
the Cardium Play with
horizontal slick water frac
technology
Introduced technical
understanding to drill the
middle of the Cardium
zone to unlock full
potential
2012
2013
Drilled a 2 mile horizontal
well that produced 5 Bcf
gas plus liquids in its first
year
Improved drilling
efficiencies
2014
2015
Early adopter of Zipper
frac techniques in
Cardium and Spirit River
Testing ceramic
proppant to enhance
productivity
Greater Ferrier Area Infrastructure Overview
GREATER FERRIER EXISTING
INFRASTRUCTURE ACCESS:
Infrastructure gives Bellatrix control of
production and growth
Working interest or operatorship in
2 major gas processing facilities
4 compressor stations
3 oil batteries
BELLATRIX O’CHIESE NEESOHPAWGANU’CK DEEP-CUT
GAS PLANT:
Phase I - 110 MMcf/d sales capacity (in
service May 2015, cost +/- $90MM)
Phase II - 110 MMcf/d sales capacity
(in service 2017, cost +/- $97MM)
•
C3+ Recovery 99%
•
C4+ Recovery 100%
Strategic advantage from
owned infrastructure –
lowered costs and
guaranteed access
25
GREATER FERRIER AREA STRATEGIC INFRASTRUCTURE
Growing Firm Capacity Within Core Areas
TOTAL BELLATRIX GROSS PROCESSING CAPACITY – GREATER FERRIER
BXE Phase 2 deep
cut incremental
110 MMcf/d
400
300
Bellatrix net
processing
capability
expected to
increase by
~75% through
Q4/2016
BXE Phase 1 deep
cut 110 MMcf/d
500
13-05 booster
compression &
Twin Rivers
pipeline project
Twin
Rivers
pipeline
expansion
Total
processing
capacity net to
Bellatrix
estimated at
~80,000 boe/d
in 2017
200
100
0
Q4 - 2017
Q3 - 2017
BXE Deepcut
Q2 - 2017
Q1 - 2017
Q4 - 2016
BXE Non Op Capacity
Q3 - 2016
Q2 - 2016
Q1 - 2016
Q4 - 2015
Blaze Capacity
Q3 - 2015
Q2 - 2015
26
Q1 - 2015
Third Party Total Capacity
Q4 - 2014
Q3 - 2014
Q2 - 2014
Q1 - 2014
Total Gross Raw Gas Processing Capacity (MMcf/d)
600
Total Firm Capacity
Bellatrix Facility NGL Yield Uplift
Bellatrix Deep Cut Facilities (Phase I & II)
Raw Gas (MMcf/d)
Shrinkage
Sales Gas (MMcf/d)
NGL Yields1
1
2
245
10%
220
Current Third Party
Facilities Bbl/MMcf
Bellatrix Facilities
Bbl/MMcf
Combined Facilities(2)
Bbl/MMcf
Ethane (C2)
4
22
13
Propane (C3)
10
28
18
Butane (C4)
6
9
8
Condensate (C5+)
25
28
27
Total NGL’s
45
87
66
Yields assume a current and future mix of Cardium, Notikewin & Falher wells
Combined facilities assumes 50% of Bellatrix gas processed through existing third party facilities,
and 50% processed through the Bellatrix deep cut facility
27
Strategic Infrastructure Enhances Netbacks
THIRD PARTY FACILITIES(1)
Yield
Price
Bbl/MMcf
Sales
Dry Gas
$3.00/Mcf
-
Ethane
$10.00/bbl
Propane
Butane
Revenue
BELLATRIX FACILITIES(1)
Yield
$000s
Bbl/MMcf
Sales
232 MMcf/d(3)
$696.0
-
4
980 bbl/d
$9.8
$20.00/bbl
10
2,450 bbl/d
$35.00/bbl
6
Condensate $60.00/bbl
Revenue
COMBINED FACILITIES(2)
Yield
Revenue
$000s
Bbl/MMcf
Sales
220 MMcf/d(3)
$660.0
-
227 MMcf/d(3)
$681.0
22
5,390 bbl/d
$53.9
13
3,185 bbl/d
$31.9
$49.0
28
6,860 bbl/d
$137.2
18
4,410 bbl/d
$88.2
1,470 bbl/d
$51.5
9
2,205 bbl/d
$77.2
8
1,960 bbl/d
$68.6
25
6,125 bbl/d
$367.5
28
6,860 bbl/d
$411.6
27
6,615 bbl/d
$396.9
Revenue
Total
$1,174
Total
$1,340
Total
$1,267
per Mcfe
$4.79
per Mcfe
$5.47
per Mcfe
$5.17
per Mcf
($0.56)
per Mcf
($0.20)
per Mcf
($0.38)
Op Costs
$000s
OPERATING COST PROFILE
Pre Plant
$8.64/boe
Gas Plant I - 2015
$7.60/boe
Gas Plant II - 2017
$7.20/boe
BXE-owned facilities result in a 14% revenue increase and 64% decrease in op. costs
Based on 245 MMcf/d gas going into facility
Combined facilities assumes 50% of Bellatrix gas processed through existing third party facilities, and 50% processed through the Bellatrix deep cut facility
3 ~10% shrinkage on 245 MMcf/d through BXE facility, 5% shrinkage through third party facility, and 7.5% shrinkage through third party and BXE facility
1
2
28
Financial Position
2015 A YEAR OF BALANCE SHEET PRESERVATION
•
Up to $200 million CAPEX budget with flexibility to adjust second half 2015 spending plans
•
•
Further capital reductions or transactions possible to reduce debt further
Bank covenants are calculated on trailing four quarter basis, relaxed covenants announced March 11, 2015
•
US$250 million senior unsecured notes issuance closed May 21, 2015
STRATEGIC VALUE IN INFRASTRUCTURE ASSETS
• 60% owner and operator of Bellatrix O’Chiese Nees-Ohpawganu’ck deep-cut gas plant
•
•
Phase 1: 110 MMcf/d
Phase 2: incremental 110 MMcf/d
•
Working interest owner in two other major gas processing facilities
•
11 compressor sites with 64,600 compression horse power and 392 MMcf/d gas compression capacity
•
Five major oil batteries with over 12,000 bbl/d oil processing capacity
•
Over 330 kilometers of gathering and product transfer pipelines
Infrastructure supports growth to 80,000 boe/d net with Phase 2 of BXE deep-cut gas plant
29
Differentiated Joint Venture Strategy
Bellatrix has entered into a series of Joint Venture (JV) transactions providing
up to $700 million in development cost funding
This clearly differentiated strategy provides significant benefits:
Accelerates development potential of our multi-billion dollar inventory of projects
Non-dilutive mechanism of capital cost funding
Improved capital efficiency of drilling program irrespective of well productivity
Enhances internal rate of return (IRR) of drilling projects given front end loaded
promoted capital
Insulates against weakening commodity prices given higher return expectations
and improved efficiency metrics
30
Joint Ventures & Strategic Partnerships
JOINT VENTURES
Grafton JV (GJV) –
$305 MM
• Effective Date: July 1, 2013
• Wells: 72 net wells
• BXE / Partner Contribution:
$55 MM / $250 MM
• Ferrier, Brazeau
Troika JV (TJV) –
$240 MM
STRATEGIC PARTNERSHIPS
CNOR JV - $500 MM
(Grafton managed co.)
Daewoo/Devonian JV –
$200 MM
• Effective Date: January 1,
• Effective Date: September
• Wells: 63 gross wells
• BXE / Partner Contribution:
• Funds expected to be spent
• Effective Date: July 1, 2013
• Wells: 70 gross wells
• BXE / Partner Contribution:
• 3 JVs with 5 year Terms
• Dates of March 1, 2011,
• Ferrier, Willesden Green
• 50/50 go-forward
• Drill commitments of 3, 10
2013
$120 MM / $120 MM
• Ferrier
29, 2014
from 2016-2018
• BXE / Partner Contribution:
$250 MM / $250 MM
• Development plans/areas
to be determined by
management committee
JV Partner earning terms:
JV Partner earning terms:
JV Partner earning terms:
• Pay 82% to earn 54%
• Pay 50% to earn 35%
• Pay 50% to earn 33%
• Reversion to 33% after
• Reverting to 25% after
• Payout: $250MM + 8% IRR
• One time election to
• Payout: $120 MM + 15%
• Payout: $250MM + 8% IRR
• Convert to 10.67% gross
before payout
payout
convert 33% WI to 17.5%
gross overriding royalty on
pre-JV BXE working interest
31
before payout
payout
IRR
before payout
overriding royalty on preJV BXE working interest
• Pro-rata terms match GJV
$100 MM / $100 MM
O’Chiese Partnership
December 1, 2011, and
January 1, 2013
and 2 wells per year
• 52 sections of total land
across partnership
Compelling Investment Opportunity
 Experienced management team
 Industry leading well results
 Low cost operator and finder
 A large inventory of high rate of return drilling locations
 Unfettered growth potential with firm processing
capacity
 Differentiated JV strategy and access to capital
32
Appendix: Additional Long
Term Opportunities
Lower Mannville: Liquids-rich Gas Play
Drill locations identified across
three play types
GR
Porosity
31 horizontal Ellerslie wells drilled
by Angle/BXE at Harmattan to date
Net Drilling Inventory:
12 proved
15 probable
77 unbooked
104 total
Liquids-rich gas plays
Liquids yields up to 205 bbl/MMcf
(sales) in the Harmattan area
34
Schematic Log
Duvernay Unconventional Resource
BXE Land Sections
130 Gross1
129 Net1
BXE Net Drilling Inventory
415 unbooked
+95 Duvernay wells licensed in Greater
Ferrier and Edson
18 wells currently on production
BXE 09-24 HZ highest recorded IP90 at
3.7 MMcf/d; 0.75 Bcf cumulative since
brought on production
Reported offset NGL yields of
70-150 Bbls/MMcf
Highly over-pressured at 15.8 kPa/m
1
Excludes Davey. Davey is an additional 80 gross (80 net) sections
35
Duvernay provides significant option
value for Bellatrix
Second White Specks: Tight Oil Resource
Laterally continuous fairway: >6,000 sq miles
Thick: 75-225m
Over-pressured: 9-14KPA/m
Thermally mature for oil: Tmax 435-455ºC
High Organic Content (TOC): 1.5-4wt%
Existing vertical production
15 industry HZ’s drilled
12 with published oil/condensate production
Gross: 308 sections net
Net: 247 sections net
On-going technical work
36
Belly River: Regional Oil & Gas Play
Significant oil production in the Basal Belly River from extensive marine shoreface
deposits
Gas & oil production from lower to upper Belly River fluvial channel deposits
37
Rock Creek: Willesden Green
Laterally extensive tight
marine sandstone
10 horizontal well inventory
33 BXE gross sections
55% average BXE WI
Numerous vertical
industry producers
38
Core Area
Corporate Information
BOARD OF DIRECTORS
OFFICERS
Raymond G. Smith, P.Eng.
President & CEO
Doug N. Baker, FCA
Edward J. Brown, C.A.
Executive Vice President,
Finance & CFO
W.C. (Mickey) Dunn
Chairman
Murray L. Cobbe
BANKERS
National Bank of Canada
Alberta Treasury Branches
HSBC Bank Canada
Canadian Imperial Bank of Commerce
The Bank of Nova Scotia
Bank of Montreal
The Toronto Dominion Bank
Union Bank, Canada Branch
Wells Fargo Bank N.A., Canadian Branch
Corporation Canada
John H. Cuthbertson, QC
Brent A. Eshleman, P.Eng.
Executive Vice President & COO
Melvin M. Hawkrigg,
BA, FCA, LLD (Hon.)
Charles R. Kraus, Esq.
Vice President, General Counsel
& Corporate Secretary
EVALUATION ENGINEERS
Sproule Associates Limited
Steve G. Toth, CFA
Vice President, Investor Relations
REGISTRAR & TRANSFER AGENT
Computershare Trust Company of Canada
Robert A. Johnson, P.Geol.
Daniel Lewis, B.S.
Keith E. Macdonald, CA
Steven J. Pully, CPA, CFA
Raymond G. Smith, P. Eng.
Murray B. Todd, B.Sc., P. Eng.
Keith S. Turnbull, B.Sc., CA
39
AUDITORS
KPMG LLP
EXCHANGE LISTING
The Toronto Stock Exchange - BXE
The New York Stock Exchange - BXE
1920, 800 – 5th Avenue SW
Calgary, Alberta Canada T2P 3T6
Tel: (403) 266-8670
Fax: (403) 264-8163
www.bellatrixexploration.com