reserves - Bonterra Energy Corp.

BONTERRA ENERGY CORP.
MAY 2015
AGM
YIELD GROWTH SUSTAINABILITY
FORWARD LOOKING INFORMATION
Certain statements contained in this Presentation include statements which contain words such as “anticipate”, “could”, “should”, “expect”, “seek”,
“may”, “intend”, “likely”, “will”, “believe” and similar expressions, statements relating to matters that are not historical facts, and such statements of our
beliefs, intentions and expectations about development, results and events which will or may occur in the future, constitute “forward-looking
information” within the meaning of applicable Canadian securities legislation and are based on certain assumptions and analysis made by us derived
from our experience and perceptions. Forward-looking information in this Presentation includes, but is not limited to: expected cash provided by
continuing operations; future capital expenditures, including the amount and nature thereof; oil and natural gas prices and demand; expansion and
other development trends of the oil and gas industry; business strategy and outlook; expansion and growth of our combined business and operations;
and maintenance of existing supplier and partner relationships; supply channels; accounting policies; credit risks; and other such matters. Forwardlooking information in this Presentation also includes, but is not limited to, the timing and amount of future dividend payments by Bonterra.
All such forward-looking information is based on certain assumptions and analyses made by us in light of our experience and perception of historical
trends, current conditions and expected future developments, as well as other factors we believe are appropriate in the circumstances. The risks,
uncertainties, and assumptions are difficult to predict and may affect operations, and may include, without limitation: foreign exchange fluctuations;
equipment and labour shortages and inflationary costs; general economic conditions; industry conditions; changes in applicable environmental,
taxation and other laws and regulations as well as how such laws and regulations are interpreted and enforced; the ability of oil and natural gas
companies to raise capital; the effect of weather conditions on operations and facilities; the existence of operating risks; volatility of oil and natural gas
prices; oil and gas product supply and demand; risks inherent in the ability to generate sufficient cash flow from operations to meet current and future
obligations; increased competition; stock market volatility; opportunities available to or pursued by us; and other factors, many of which are beyond
our control. The foregoing factors are not exhaustive.
Actual results, performance or achievements could differ materially from those expressed in, or implied by, this forward-looking information and,
accordingly, no assurance can be given that any of the events anticipated by the forward-looking information will transpire or occur, or if any of them
do so, what benefits will be derived there from. Except as required by law, Bonterra disclaims any intention or obligation to update or revise any
forward-looking information, whether as a result of new information, future events or otherwise.
The term barrels of oil equivalent (BOE) may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet per
barrel (6mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner
tip and does not represent a value equivalency at the wellhead. All BOE conversions in the report are derived from converting gas to oil in the ratio
mix of six thousand cubic feet of gas to one barrel of oil.
The forward-looking information contained herein is expressly qualified by this cautionary statement.
1
CURRENT SNAPSHOT
CORPORATE PROFILE
Shares outstanding
32.1 million
Market capitalization
$1.22 billion
Insider ownership
12%
Current monthly dividend
$0.15 per share
Current annualized yield(1)
4.8%
Oil and liquids weighting – Q1
71% (6% liquids)
Reserve life index (PDP)
7 years
Reserve life index (1P)
11 years
Reserve life index (2P)
16 years
Tax pools
$580 million
Tax horizon
2016
Net debt to cash flow (at 03/31/2015)
1.2 to 1.0 times
(1) Based on April 29, 2015 price of $37.83
2
FINANCIAL RESULTS
HIGHLIGHTS
Q1
2015
Year
2014
Q1
2014
$22,090
$209,665
$54,414
$0.69
$6.57
$1.73
87%
54%
50%
$0
$39,500
$12,889
$0.60
$3.54
$0.87
Average Daily Production per BOE
12,204
13,195
12,006
Operating costs per BOE
$11.93
$13.89
$13.90
Corporate Netback
$20.78
$45.39
$50.37
($1,935)
$38,761
$23,041
($0.06)
$1.21
$0.73
$38,960 (1)
$155,565
$54,236
$37,633
$53,642
$62,488
$207,217
$154,723
$143,103
(000s except per share amounts)
Funds Flow
Per share – basic
Payout ratio
Cash from other sources
Cash Dividends per share
Net earnings
Per share - basic
Capital expenditures and acquisitions (net of dispositions)
Working capital deficiency
Long-term debt
(1) Includes a deposit of $17,200,000 for a purchase of primarily Pembina Cardium oil and gas assets that closed on April 15, 2015, and increased capital
expenditures from $21,760,000
3
CASH FLOW SENSITIVITIES
Per Annum
Sensitivity
Analysis(1)
(estimate for 2015)
Cash Flow(3)
Cash Flow
Per Share(2)
Change of U.S. $1.00 per barrel of oil and NGLs
$2,880,000
$0.09
Change of Canadian $0.10 per MCF of natural gas
$ 713,000
$0.02
Change of Canadian $0.01 / U.S.$ exchange rate
$1,267,000
$0.04
(1) Based on average yearly production of 12,800 boe per day
(2) Based on estimated weighted average common shares of 32,169,623
4
DIVIDEND HISTORY
$0.40
$0.35
$0.30
$0.30
$0.28
$0.29
$0.26
$0.24
$0.25
$0.21
$0.20
$0.22
$0.18
$0.16
$0.16
$0.14
$0.15
$0.15
$0.12
$0.10
$0.05
$‐
5
INCREASING SHAREHOLDER VALUE
Reserves per Share
Reserves Profile
(boe per share) (Proved plus Probable)
(Proved plus Probable)
29% Natural Gas
71% Oil/NGLs
80,248
74,981
2009 2010 2011 2012 2013 2014
Gross Reserves
(MBOE - Proved plus Probable – year over year growth)
45,032
35,824
Proved
Probable
23,870
14,899
19,711
10.9%
19.3%
21.1%
10.9%
3.2%
14.3%
14.7%
9.9%
4.6%
9.4%
66.5%
7.0%
2001
31,241
81.7%
8,201
16,529
26,476
27,321
39,371 41,149
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
6
INCREASING SHAREHOLDER VALUE
Production per Share
Production Profile
(boe per share)
29% Natural Gas
71% Oil/NGLs
13,195
12,190
2009 2010 2011 2012 2013 2014
Gross Production
(boe per day – year over year growth)
Oil/Liquids
Natural Gas
3,179
3,118
3,194
3,655
4,042
4,218
4,346
4,994
5,628
6,322
6,703
1,766
80.0%
-1.9%
2.4%
14.4%
4.4%
10.6%
3.0%
14.9%
12.7%
12.3%
12.3%
81.3%
4.1%
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
7
PEMBINA CARDIUM
ORIGINAL OIL IN PLACE PER SECTION
0 to 5,000 Mbbl
5,000 to 10,000 Mbbl
10,000 to 20,000 Mbbl
20,000 to 25,000 Mbbl
25,000+ Mbbl
RECOVERY FACTOR
0%
5%
10%
15%
20%
25%
KEY CHARACTERISTICS
• Pembina is the largest conventional oilfield in Canada with large oil in place and low recovery to date.
• The pool is characterized by high oil in place, low recovery factors, long-term stable production, high
quality oil and high netbacks
• Majority of Bonterra’s land position covers areas with high original oil in place and low recovery factors
8
CARDIUM LANDS
LAND
• Average working interest – 76%
• Bonterra operates 88.5% of its total
production
• Reserve life index (Proved) – 11
years
• Reserve life index (P+P) – 16 years
• Reserves (P+P) – 93.3 MBOE
• Land position – 292 gross (201 net)
sections
• Booked locations – 252 gross (230
net) wells
• Total Cardium Locations – 1,137
gross (773 net) wells
9
PEMBINA ACQUISITION
R11
R10
R9
R8
R7
R6
R5W5
DEAL RATIONALE
• Pembina Cardium Tuck-In
T51
T50
• Operational Synergy / Facility
Consolidation
• 1,800 Boe/d
• 86% Oil & NGL’s
T49
• 7% Decline
• Reserves (Proved) – 9,861 MBOE
T48
• Reserves (P+P) – 13,039 MBOE
T47
T46
• Potential Cardium Locations – 244
gross (136 net) wells
• Booked locations – 12 gross (12
net) wells
10
2015 AVERAGE PRODUCTION
Base
Enerplus
2015 Capital ‐ 10 Additional Wells
2015 Capital ‐ On Prod Q1
2015 Capital ‐ Deferred to Q2
16,000
Base Production
9 Gross (7.4 Net) Wells On Prod Q1
Enerplus Acquisition
8 Gross (7.9 Net) Wells Deferred to Q2
10 Gross (9.9 Net) Wells
Year Average
14,000
12,000
BOE/d
10,000
9,973
583
1,254
630
416
12,856
• Assumes a $58M Capital Budget
8,000
• Annual Estimated Production from the Enerplus
acquisition is 1,770 BOE/d; when adjusted for
April 15 closing date it is 1,254 BOE/d
6,000
4,000
• With Enerplus recognized from Jan 1, 2015
production would have been 13,368 BOE/d
2,000
0
Jan‐15
2015 AVERAGE PRODUCTION
ESTIMATE (BOE/D)
• Base production includes downtime estimates
Apr‐15
Jul‐15
Oct‐15
Jan‐16
Apr‐16
Jul‐16
Oct‐16
Month
Note: 2016 Capital expenditures are not included in this chart
11
DEFERRED COMPLETIONS
RATIONAL
Bonterra deferred completions on 8 Gross (7.4 Net) wells from Q1 to Q2 as a result in the drop of
Realized Canadian Oil pricing.
The $20.95/bbl increase in Realized Canadian Oil price from January 2015 to June 2015 estimate
results in incremental revenue of ~$450,000 per well. By deferring the 8 wells from January to
June, Bonterra expects to realize ~$3.6 Million of incremental revenue.
Completion costs have also declined from $1,150,000 per well in January to $600,000 per well in
June. By deferring the 8 wells from January to June, Bonterra expects to realize ~ $4.4 Million of
capital cost savings
Total estimated increase in incremental revenue on deferring completions: $8.0 Million
REALIZED CANADIAN OIL PRICE
WTI (U$)
Diff (U$)
FX
Quality Adjustment
Realized Canadian Oil (CAD)
January (Actual)
$47.33
‐$6.97
$1.21
‐$3.24
$45.60
June (Est.)
$60.00
‐$2.80
$1.22
‐$3.24
$66.55
Month
12
DRILLING INNOVATION
•
•
Transition from intermediate casing design to monobore design
Advances in bit technology
13
COMPLETION INNOVATION
TRANSITION FROM OPEN HOLE TO CASED HOLE
• Increased recovery
• Accurate and even placement of fracs
• Increased number of fracs per well.
• Reduced costs per cemented frac in 2015
Packers
Cemented
2015 Cemented
$100,000
$90,000
$80,000
$/stage
$70,000
$60,000
$50,000
$40,000
$30,000
$20,000
$10,000
$0
10
15
20
25
30
35
40
45
50
# stages
14
PEMBINA CARDIUM DEVELOPMENT
CONVENTIONAL VERTICAL DEVELOPMENT
• 4 vertical wells
• Estimated ultimate oil recovery: 378,000 Bbl
• Recovery factor: 3.2%
8 HZ WELLS* PER SECTION DEVELOPMENT
• Estimated ultimate oil recovery: 1,178,000 Bbl
• Recovery factor: 10.2%
• Number of wells per section on primary is dictated by quality of
the reservoir
* Estimated ultimate oil recovery per horizontal: 100,000 Bbl
SECONDARY AND ENHANCED RECOVERY UPSIDE
• Possible Recovery factor: 20+%
• Number of wells on secondary recovery is dictated by number
of injectors required
• Waterflood pilot commenced in 2014
Section 13-48-6 W5
Estimated Original Oil in Place:
12,000,000 Bbl
15
PEMBINA CARDIUM DEVELOPMENT
SECTION 13-048-06W5
Original Vertical Wells
Horizontal Infill Wells
1,000
100
BOPD
Recovery Factor = 10.3%
10
Recovery Factor = 3.2%
1
Jan‐10
Jan‐15
Jan‐20
Month
16
AVERAGE BNE CARDIUM ECONOMICS
BNE AVERAGE HZ METRICS
300
250
BOE/D
200
Total capital costs per well ($MM)
2.6
2.2
Reserves per well (MBOE)
165
165
IP (1 month) (boe/d)
255
255
IP (12 months) (boe/d)
124
124
Internal rate of return (% BT)
71
122
Payout (years)
1.4
1.0
Recycle ratio
1.8
2.4
150
Price Deck: Sproule 2015 Q1 (WTI: $US65/bbl; GAS: $3.32/MMBTU)
100
50
BNE Avg Hz to Dec 31, 2014
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Month
17
CARDIUM LOCATIONS
Area Name
CYNTHIA
BLUE RAPIDS
KEYSTONE
CARNWOOD
ROSE CREEK
WEST PEMBINA
WILLESDEN GREEN
TOTAL OPERATED
Avg WI%
80.0%
72.7%
97.5%
90.9%
98.3%
96.7%
100.0%
93.4%
Total Inventory
Gross
Net
2.5
2.0
79.5
57.8
152.0
148.2
180.0
163.6
211.5
207.9
118.0
114.1
16.0
16.0
759.5
709.5
Booked Locations
Gross
Net
2.0
1.6
9.0
6.8
105.0
102.3
75.0
71.7
16.0
14.3
17.5
17.4
13.0
13.0
237.5
227.1
TOTAL NON-OPERATED
17.0%
377.5
64.1
15
2.8
GRAND TOTAL
68.0%
1,137.0
773.5
252.5
229.9
BNE 3 YEAR LOCATION BOOKING RATIONAL
• Dividend vs. Growth Co. Strategy
• Allows for year-over-year sustainable reserve growth
• Risk mitigation on reserve write-downs due to pricing effects
18
CURRENT RESERVES
CURRENT RESERVES (INCL. ENERPLUS)
PDP
29,336
61,191
2,425
41,959
Oil (Mbbl)
Sales Gas (Mmcf)
Liquids (Mbbl)
Total (MBOE)
TP
49,007
114,209
4,615
72,656
TPP
62,950
146,830
5,866
93,288
Product Mix
Oil
Gas
Liq
6%
26%
67%
19
RESERVES – INTERNAL ESTIMATE
FULL DEVELOPMENT - INTERNAL ESTIMATED RESERVES
PDP*
30,235
72,830
3,112
45,486
Oil (Mbbl)
Sales Gas (Mmcf)
Liquids (Mbbl)
Total (MBOE)
Op Upside
70,631
286,973
14,166
132,626
Non-Op Upside
5,953
21,127
1,043
10,517
TOTAL
106,819
380,929
18,321
188,628
* BNE internal estimate after updating Sproule Database with production to Feb 2015 & adjusting for well performance.
Internal Est. Reserves
PDP
OP Upside
Non-Op Upside
6%
Product Mix
Oil
Gas
Liq
10%
24%
34%
57%
70%
20
WHY INVEST IN BONTERRA?
QUALIFIED AND
EXPERIENCED
STAFF
SUSTAINABLE
DIVIDEND
CONCENTRATED
ASSET BASE
FOCUS ON PER
SHARE GROWTH
BONTERRA
LARGE INVENTORY
OF HIGH QUALITY
DRILL LOCATIONS
FOCUS ON
TECHNOLOGICAL
INNOVATION
GOOD ACCESS TO
MARKETS
STRONG BALANCE
SHEET
21
CORPORATE INFORMATION
BOARD OF DIRECTORS
G. J. Drummond
G. F. Fink
R. M. Jarock
C. R. Jonsson
R. A. Tourigny
OFFICERS
G. F. Fink, CEO and Chairman of the Board
B. A. Curtis, Vice President, Business Development
A. Neumann, Chief Operating Officer
R. D. Thompson, CFO and Secretary
BANKERS
CIBC, Calgary, Alberta
National Bank of Canada, Calgary, Alberta
J. P. Morgan, Calgary, Alberta
TD Securities, Calgary, Alberta
Alberta Treasury Branch, Calgary, Alberta
HEAD OFFICE
901, 1015 – 4th Street SW
Calgary, AB T2R 1J4
Telephone: 403.262.5307
Fax: 403.265.7488
WEBSITE
REGISTRAR AND TRANSFER AGENT
www.bonterraenergy.com
Olympia Trust Company, Calgary, Alberta
AUDITORS
Deloitte LLP, Calgary, Alberta
SOLICITORS
Borden Ladner Gervais LLP, Calgary, Alberta
22