Z4’iay

THIS IS EXHIBIT “11”
referred to in the Affidavit of
Glen C. Schmidt
Sworn before me this
Z4’iay of March, 2015
NOTARY PUBLIC/COMMISSIONER FOR
OATHS IN AND FOR THE PROVINCE
OF ALBERTA
LEGAL CAL:1 1810773.1
Page:
ofl4I
LARICINA ENERGY LTD.
RESERVES AND RESOURCE
ASSESSMENT AND EVALUATION OF
SALESM
Effective December 31, 2014
1143197
L9 GLJ
Petroleum
Consultants
Page:2ofl4
SALESKI
TABLE OF CONTENTS
Page
COVERING LETTER
3
INDEPENDENT PETROLEUM CONSULTANTS’ CONSENT
5
SALESKI
6
RESOURCE AND RESERVES DEFINITIONS
12$
PRODUCT PRICE AND MARKET FORECASTS
133
APPENDIX I
Certificates of Qualification
137
Fhnry 142a15 I34322
LLj GLJ
Petroleum
Consultants
Pafle: 3 of 141
II
(‘ I I Petroteum
3 I_i) Consultants
JTESC.,
P.
Executive Vice President & COO
Officers I Vice Presidents:
Caralyn P. Bennett, P. Eng.
Tim R. Freeborn, R Eng.
Leonard L. Herchen, P. Eng.
Myron]. Hladyshevsky, R Eng.
Todd]. Ikeda, P. Eng.
Bryan M. ba, P. Big.
Mark bobin, P. Geol,
]ohn E. Keith, P. Eng.
February 13, 2015
Project 1143197
Mr. Barry Jackson
Chairman of Reserves Committee
Laricina Energy Ltd.
800, 4251st Street SE
Calgary, Alberta T2P 3L8
Dear Chairman:
Re:
Saleski Evaluation
Effective December 31, 2014
GLJ Petroleum Consultants (GLJ) has completed an independent reserves and resource assessment and
evaluation of the Saleski property of Laricina Energy Ltd. (the “Company”). The effective date of this
evaluation is December 31, 2014. All heavy oil volumes reported herein refer to bitumen.
This report has been prepared for the Company for the purpose of annual disclosure and other financial
requirements. This evaluation has been prepared in accordance with reserves definitions, standards and
procedures contained in the Canadian Oil and Gas Evaluation Handbook.
hi the course of the evaluation, the Company provided GLJ personnel with basic information which included
land data, well infonnation, geological information, reservoir studies, estimates of on-stream dates, contract
information, current hydrocarbon product prices, operating cost data, capital budget forecasts, fmancial data and
future operating plans. Other engineering, geological or economic data required to conduct the evaluation and
upon which this report is based, were obtained from public records, other operators and from GLJ nonconfidential files.
Estimates of reserves and resources and projections of production were generally prepared using well
information and production data available from public sources to approximately December 31, 2014. The
Company provided land, accounting data and other technical information not available in the public domain
to approximately December 31, 2014. In certain instances, the Company also provided recent engineering,
geological and other information up to December 31, 2014. The Company has confirmed that, to the best of its
knowledge, all information provided to GLJ is correct and complete as of the effective date.
The evaluation was conducted on the basis of the current GLJ Price Forecast which is summarized in the
Product Price and Market Forecasts section of this report.
4100, 400
-
3rd Avenue SW., Calgary, Alberta, Canada T2P 4H2
(403) 266-9500
Fax (403) 262-1855
GLJPC.com
Page: 4 at 141
GLJ
Petroleum Consultants
It is trusted that this evaluation meets your current requirements. Should you have any questions regarding this
analysis, please contact the undersigned.
Yours very truly,
GLJ PETROLEUM CONSULTANTS LTD.
Caralyn P. Bennett, P. Eng.
Vice President
CPB/jem
Attachments
Pane: 5 of I4
INDEPENDENT PETROLEUM CONSULTANTS’ CONSENT
The undersigned firm of Independent Petroleum Consultants of Calgary, Alberta, Canada has
prepared an independent evaluation of the Laricina Energy Ltd. (the “Company”) Saleski oil sands
property and hereby gives consent to the use of its name and to the said estimates. The effective date
of the evaluation is December 31, 2014.
In the course of the evaluation, the Company provided GU Petroleum Consultants Ltd. personnel with basic
information which included land data, well information, geological information, reservoir studies, estimates of
on-stream dates, contract information, current hydrocarbon product prices, operating cost data, capital budget
forecasts, financial data and future operating plans. Other engineering, geological or economic data required to
conduct the evaluation and upon which this report is based, were obtained from public records, other operators
and from GLJ Petroleum Consultants Ltd. nonconfidential files. The Company has provided a representation
letter confirming that all information provided to GLJ Petroleum Consultants Ltd. is correct and complete to
the best of its knowledge. Procedures recommended in the Canadian Oil and Gas Evaluation (COGE)
Handbook to verify certain interests and financial information were applied in this evaluation. In applying
these procedures and tests, nothing came to GLJ Petroleum Consultants Ltd.’s attention that would suggest
that information provided by the Company was not complete and accurate. GLJ Petroleum Consultants Ltd.
reserves the right to review all calculations referred to or included in this report and to revise the estimates in
light of erroneous data supplied or information existing but not made available which becomes known
subsequent to the preparation of this report.
The accuracy of any reserves, resources and production estimate is a function of the quality and quantity of
available data and of engineering interpretation and judgment. While reserves, resources and production
estimates presented herein are considered reasonable, the estimates should be accepted with the understanding
that reservoir performance subsequent to the date of the estimate may justify revision, either upward or
downward.
Revenue projections presented in this report are based in part on forecasts of market prices, currency exchange
rates, inflation, market demand and government policy which are subject to many uncertainties and may, in
future, differ materially from the forecasts utilized herein. Present values of revenues documented in this
report do not necessarily represent the fair market value of the reserves and resources evaluated herein.
PERMIT TO PRACTICE
GLJ PETROLEUM CONSULTANTS LTD.
Signature:
Date:
Febwary 13, 2015
PERMIT NUMBER: P 2066
The Association of Professional Engineers
and Geoscientists of Alberta
LJ GLJ
Petroleum
Consultants
Page: 6 of WI
LARICINA ENERGY LTD.
SALESKI
Effective December 31, 2014
Prepared by
Peter G. Moore, P. Geol.
Angie Wong, P. Eng.
L
Petroleum
GLJ Consultants
Page: 7 of 141
SALESM
TABLE OF CONTENTS
Page
SUMMARY
Summary of Reserves and Values
Summary of Resources and Values
Forecast Gross Lease Total Oil Production
Forecast Gross Lease Total Oil Production
Reserves and Present Value Summary
Resources and Present Value Summary
9
10
11
12
13
14
LAND
Summary of Well Interests and Burdens
15
DISCUSSION
General
Performance Review
Background
Project Status
Geology
Reserves
Resources
Production and Development forecast
Economic Analysis
16
18
23
27
30
35
44
49
52
MAPS
Map 1
Map 2
Map 3
Map 4
Map 5
Map 6
Land Map
Structure Map
Net Bitumen Pay
Net Bitumen Pay
Net Bitumen Pay
Net Bitumen Pay
55
56
57
58
59
60
PLOTS
Plot 1
Plot 2
Plot 3
Plot 4
Plot 5
Plot 6
Plot 7
Pilot Steam Injection Time Coord Plot
lC Steam Injection Time Coord Plot
1D Steam Injection Time Coord Plot
2C Steam Injection Time Coord Plot
2D Steam Injection Time Coord Plot
3D Steam Injection Time Coord Plot
Saleski Reserve Area Type Well Plots
61
62
63
64
65
66
67
Well List and Production Summary
Volumetric Parameters Summary Bitumen Initially In Place
Volumetric Parameters Summary Reserves
Volumetric Parameters Summary Contingent Resources
Type Well Forecasts
Production & Development Forecast Probable Undeveloped Reserves
Production & Development Forecast Probable + Possible Undeveloped
Reserves
68
69
70
71
72
82
84
TABLES
Table 1
Table 2
Table 2.1
Table 2.2
Table 3
Table 4
Table 4.1
-
-
-
-
Grosmont C
Grosmont D
Upper Ireton
Nisku
-
-
-
-
-
-
-
-
-
-
-
-
Febnaay 14,2015 1442:22
LI GLJ
Petroleum
Consultants
Page: 8 of 141
TABLE OF CONTENTS
Page
TABLES
Table 4.2
Table 4.3
Table 5a
Table 55
86
Production & Development Forecast 2P Reserves + Best Est. Cont.
Resources
Production & Development Forecast 3P Reserves + High Est. Cont.
Resources
Bitumen Netback Pricing Reserves
Bitumen Netback Pricing Resources
-
8$
-
90
91
-
-
ECONOMIC FORECASTS
Probable Undeveloped
Probable Plus Possible Undeveloped
Best Estimate Contingent Resources
High Estimate Contingent Resources
92
96
100
104
APPENDIX I
Combined Reserves and Resources
10$
APPENDIX II
Additional Information
122
Febeacry 142015 14:43:22
L
GLJ Petroleum
Consultants
Page: 9 of 141
Company:
Property:
Reserve Class:
Development Class:
Pricing:
Effective Date:
Laricina Energy Ltd.
Saleski
Various
Classifications
GU (2015-01)
December31, 2014
Summary of Reserves and Values
Probable
Plus
Possible
Undeveloped
Probable
Undeveloped
-
MARKETABLE RESERVES
Bitumen (Mbbl)
Gross Lease
Total Company Interest
NetAflerRoyalty
Oil Equivalent (Mboe)
Gross Lease
Total Company Interest
NetAflerRoyalty
BEFORE TAX PRESENT VALUE (MMS)
0%
5%
8%
10%
12%
15%
20%
FIRST 6 YEARS BEFORE TAX CASH FLOW (MM$)
2015
2016
2017
2018
2019
2020
BOE factors;
HVY OIL
CONO
1.0
1.0
RES GAS 6.0
SLN GAS 6.0
PROPANE I .0
BUTANE 1.0
166,941
100,165
$3,813
177,369
106,422
85,111
166,941
100,165
83,813
177,369
106,422
85,111
2,549
516
185
69
-4
-71
-126
3,350
771
344
194
98
8
-69
-44
-143
-141
-49
21
77
-44
-143
-137
-19
47
82
ETHANE 1.0
SULPHUR 0.0
Ra, Dote: Febroasy 04, 2013 1431:42
1143197
Class (E2,E2N2), GU (2015-01), psum
februaty 04,2015 14:32:04
L
Petroleum
GLJ Consultants
Page: lId 141
Company:
Property:
Resource Class:
Development Class:
Pricing:
Effective Date:
Laricina Energy Ltd.
Saleski
Various
Classifications
GLJ (2015-01)
December31, 2014
Summary of Resources and Values
High
Estimate
Contingent
Resources
Best
Estimate
Contingent
Resources
Low
Estimate
Contingent
Resources
MARKETABLE RESOURCES
Bitumen (Mbbl)
Gross Lease
Total Company Interest
Net Afier Royalty
OiL Equivalent (Mboe)
Gross Lease
Total Company Interest
NetAfier Royalty
BEFORE TAX PRESENT VALUE (MM$)
0%
5%
8%
10%
12%
15%
20%
FIRST 6 YEARS BEFORE TAX CASH FLOW (MM$)
2015
2016
2017
2018
2019
2020
BOE Factors:
I-IVY OIL
CONG
1.0
1.0
RES GAS 6.0
SLN GAS 6.0
PROPANE 1.0
BUTANE 1.0
0
0
0
2,484,549
1,490,729
1,207,664
4,068,798
2,441,279
1,920, 181
0
0
0
2,484,549
1,490,729
1,207,664
4,068,798
2,441,279
1,920,181
0
0
0
0
0
0
0
39,773
10,787
4,973
2,917
1,649
591
-104
73,580
21,539
10,642
6,682
4,181
2,016
467
0
0
0
0
0
0
-4
1
5
3
14
-50
-3
3
7
3
0
-38
ElI-lANE 1.0
SULPHUR 0.0
Ron lInt,: Febronry 04, 2015 14:31:43
1143197
Class (CR1 ,CR2,CR3), GLJ (2015-01), psum
February 04, 2015 14:32:00
LJ GLJ
Petroleum
Consultants
o
•0
.0
.0
0
0
o
Company:
Property:
—
:
—
-
—
I
t
————-—————r
:
= =
CU (2015-01)
Legend
-
-
-
—
-
E2: Probable Undeveloped
E2N2: Probable Plus Possible Undeveloped
December 3t, 2014
————————-1—————1-——
:
Gross Lease Total Oil
Effective Date:
Pricing:
Forecast Production
C
Year
(J
Petroleum
Consultants
Gross Lease Total Oil
1143197/I’ebO4,20l5
15 1617 15 19 2021 2223 242526 27 28 29 3031 3233 34 35 3637 38 39 4041 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64
—‘
—
Laricina Energy Ltd.
Saleski
Page: 12 of 141
cc
-
CD
CD
CD
-
ç..
000000[
_
OOOO
OOOOO
(pIlqq)noleioj.
OOO
1143197
Class (E2,02N2), GU (2515-01), ps
0
Probable Plus Possible Undevelopei
SalenkiTotal
Gas
MMcf
177,369
166,941
Oil
Mbbl
NGL
Mbbl
0
0
0
0
Gas
MMcf
0
0
106,422
100,165
Oil
Mbbl
NGL
Mbbl
0
0
0
0
Sulphur
MIt
Company Interest Reserves
Gas
MMcf
0
0
$5,111
83.813
Oil
Mbbl
NGL
Mbbl
0
0
0
0
Sulphur
MIt
3,350
2,549
0%
Reserve Class:
Development Class:
Pricing:
Effective Date:
Net Interest Reserves
Reserves and Present Value Summary
Sulphur
MIt
Gross Lease Reserves
0
Entity Description
Luricina Energy Ltd.
Saleski
Probable Undeveloped
SaleskiTotal
Company:
Property:
771
516
5%
344
185
8%
69
194
10%
8
-71
L[J GLJ
98
-4
15%
-69
-126
20%
Petroleum
Consultants
Pebmoy 15. 2015 0t:36t6
12%
Before Income Tax
Discounted Present Value (IVIMS)
Various
Classifications
GLJ (2015-01)
December 31, 2014
-s
0
OS
Entity Description
Laricin Energy Ltd.
Saleski
1143197
Saleski Total
Class (CR2,CR3), flU (2015-01). rpv
High Estimate contingent Resources
Saleski Total
Best Estimate Contingent Resources
Company:
Property:
Gas
Bcf
0
0
4,069
2,485
Oil
MMbbl
NGL
MMbbl
-
0
0
0
0
Sulphur
MMIt
Gross Lease Resources
Bet
Gas
0
0
2,441
1,491
Oil
MMbbl
NGL
MMbbl
0
0
-
0
0
Sulphur
MMlt
Company Interest Resources
Bet
Gas
0
0
1,920
1,208
Oil
IvilvibbI
NGL
MMbbl
0
0
0
0
Sulphur
MMIt
Net Inlerest Resources
Resources and Present Value Summary
73,580
39,773
0%
Resource Class:
Development Class:
Pricing:
Effective Date:
21,539
10,787
5%
-
10,642
4,973
8%
6,682
2,917
10%
2,016
591
15%
467
-104
20%
LGJ GLJ
Petroleum
Consultants
Febrawy 10, 2015 08:3559
4,181
1,649
12%
Betore Income Tax
Discounted Pent Value 1M$)
Various
Classifications
CU (2015-01)
December 31, 2014
Entity Description
Luricina Energy Ltd.
Salcski
1143197
00.000
IWO
%
APO
¾
-
Working Interest
High Estimate Contingent Resources, GU (2015-01), mt
Glossary
AB: Alberta
APOBPO interests unless otherwise specified
CR Crown Royalty
HVY: Heavy
NCONV: Non-Conventional
Saleski
Saleski Total
Company:
Property:
Rem P0
(000’s)
-
Type
EPO
%
-
APO
¾
Royalty Interest
-
Rem P0
(000’s)
-
Summary of Well Interests and Burdens
AB CR NCONV HVY
Lessor
Royalty
Resource Class:
Development Class:
Pricing:
Effective Date:
Type
BPO
%
Petroleum
Consultants
February 04,2015 4:32:07
Rem P0
(000’s)
LJ GLJ
-
APO
¾
Other Royalty Burdens
Contingent Resources
High Estimate
GLJ (2015-01)
December 31,2014
Page: 16 of 141
GENERAL
GLJ Petroleum Consultants Ltd. (GLJ) was commissioned to evaluate reserves and resources within
Laricina Energy Ltd.’s (the Company) Saleski property located in Townships 084 and 085, Ranges
19 and 20 W4M, approximately 80 miles west of Fort McMurray, Alberta, at the edge of the
Athabasca Bitumen Deposit, as illustrated on Map 1. The Company holds a 60 percent working
interest subject to Crown royalties. A summary of well interests and burdens is presented in the
land section of the report. All heavy oil volumes reported herein refer to bittunen.
The Company received approval (Approval No. 11337)111 July 2009 from the Alberta Energy
Regulator (AER) for a 1,800 bopd pilot project utilizing the $AGD process. The Pilot commenced
first steam in December 2010 and is currently producing bitumen from the Grosmont C and D
reservoirs. The Pilot originally was testing steam assisted gravity drainage (SAGD) but has since
switched to a low pressure cyclic operation. Operations are similar to cyclic steam stimulation
(CSS), used commercially in the Cold Lake region of Alberta, with modifications where
appropriate, for the carbonate reservoir at Saleski. The Company is currently planning to use CSS
to develop the remainder of the lease.
There are five CSS wells/well pairs in the pilot with two well pairs in the Grosmont C and three
wells/well pairs in the Grosmont D reservoir. The Pilot has produced 449 bopcd and ISOR
(instantaneous steam oil ratio) of 4.5 during 2014. The Pilot CSOR (cumulative steam oil ratio) is
7.2.
The Company submitted a commercial development application to AER and Alberta
Environment (AENV) in December 2010 to seek approval to construct and add 10,700 bopd of
bitumen capacity to the project. This was later amended in October 2012 to change the recovery
process from SAGD to the cyclic process, currently being utilized in the Saleski Pilot, as the
exploitation method in both the Grosmont C and D. Approval for Phase 1 (Approval No. 12087)
was granted by the AER in 2013.
A breakdown of bitumen initially-in-place (BlIP), reserves and resources assignments is provided
in Tables 2 through 2.2. Canadian Oil and Gas Evaluation Handbook (COGEH) criteria were
used in assessing the reserves and resources categories and assessing the uncertainty in the
estimates.
Considering the successful Pilot results, a portion of the recoverable volumes within Phase 1
approved project area with 3D seismic have been classified as probable and possible undeveloped
LII GLJ
Consultants
Page: l7of 141
reserves; the remaining recoverable volumes have been classified as contingent resources. The
reserves lands are directly adjacent and analogous to the Pilot area as shown on the appended land
map. Outside the reserves lands, economic contingent resources have been assessed with
reclassification of these volumes to reserves contingent upon further reservoir studies, delineation
drilling, facility design, preparation of firm development plans, regulatory applications and
company approvals. Certain lands within the property are not direct geological analogues to the
Pilot lands and therefore future reserve assignments are also contingent on additional piloting of
CS$ technology. There is no certainty that it will be commercially viable to produce any portion
of the contingent resources.
L1J GLJ
Petroleum
Consultants
Page: 8of 141
PERFORMANCE REVIEW
The Saleski Pilot is developed with five operating CSS wells/well pairs and Performance to date
is illustrated in the Plots section of this report. The tables below summarized the performance of
the pilot and individual wells.
Suirimary of Pilot performance:
Time
Dec. 2010
Yearly Oil
Volume
(Mbbl)
-
Yearly Steam
Volume
(Mbbl)
7.7
ISOR
(for the
year)
CSOR
(since Dec.
2010)
-
-
Operation
Wells
IC and 1D
SAGD
2011
45.1
13.1
lCandlD
SAGD
141.7
581.7
1036.9
12.9
2012
7.3
8.7
IC, ID, 2C
and 2D
2013
142.7
1191.4
8.3
8.6
IC, ID,2C
and 2D
SAGD initially
then
transitioned to
CSS
CSS
2014
164.0
740.6
4.5
7.2
IC, 1D, 2C, 2D
and 3D
Total
493.5
3558.2
CSS
7.2
-
Summary of Individual Well/Well Pair Performance:
Well
First
Steam
Cumulative
Oil Volume
Since First
Steam
(Mbbl)
Cumulative
Steam
Volume Since
First Steam
(Mbbl)
Oil
(bopcd
in 2014)
CSOR
(Dec
2013)
CSOR
(Dec
2014)
Comment
Operation
1D
Dec
2010
114.6
626.2
105.7
7.8
5.5
80Dm long.
Initial well pair.
IC
Jan
2011
161.3
1258.0
98.2
8.3
7.8
800mlong.
Initial well pair.
2D
Aug
2012
17.0
27.2
59.0
30.3
800 m long.
Initial well pair
but only using
the top well.
Limited steam
injection.
515.7
L
SAGD
initially and
transitioned
toCSSin
2012
SAGD
initially and
transitioned
to CSS in
2012
CSS
Petroleum
GLJ Consultants
Page; 9o1141
Well
First
Steam
Cumulative
Oil Volume
Since First
Steam
(Mbbl)
Cumulative
Steam
Volume Since
First Steam
(MbbI)
Oil
(bopcd
in 2014)
CSOR
(Dec
2013)
CSOR
(Dec
2014)
6.3
5.5
2C
May
2102
176.3
963.8
151.7
3D
May
2014
24.3
194.5
99.0
-
8.0
Comment
Operation
450mlong.
Drilled
balanced.
Additional well
pair.
800 m long.
Drilled
balanced.
Additional
single well.
CSS
CSS
The Pilot originally operated via the SAGD recovery process with moderate success in 1D and
1 C. In 2012, the Company transitioned the wells into cyclic operation and since that time, there
has been a notable increase in oil production. The Pilot has demonstrated that a low pressure CSS
process, where steam is injected and bitumen produced successively from the same well, is a
technically viable recovery process with wells placed at the base of the Grosmont C and D units.
The well pairs 1D, 1 C and 2C are currently operating in cycles with the original SAGD producer
acting as injection and producer. The SAGD injectors were used until end of 2013 to increase
steam injection rate into the reservoir and reduce injection time.
The Company drilled 2C in 2012 as a 450 metre well pair, approximately one half of the
proposed commercial length. 2C was drilled at balanced pressure to reduce cuttings/fluid losses
and acid stimulated immediately after drilling. The well is operated with CS S and during 2014, it
produced 152 bopcd. 2C currently has the best performance in the Pilot in terms of CSOR and
production per metre of horizontal wellbore length.
The performance of 2D has been hampered by the availability of steam as the Company has
focused steaming on other wells. In 2014, 3D was drilled balanced and acid stimulated
immediately after drilling. This well was first steamed in May 2014 and the early production is 99
bopcd; 3D is still in early stages of operation.
Sateski Pilot Prodttction Mechanisms
—
The Company has
since transitioning
the goal of steam
wells. In the CSS
been operating the wells as a low pressure cyclic steam operations (LP-CSS)
from SAGD testing in 2011. Similar to all thermal in-situ production methods,
injection is to lower the bitumen viscosity, allowing flow to the production
operations in the Cold Lake area of north-eastern Alberta, steam is injected
L
GLJ Petroleum
Consultants
pae:2OorI4
above fracture pressure, to increase injectivity and enhance vertical permeability. Due to the high
injectivity of the Grosmont reservoir, suitable injection rates can be achieved with injection
pressures below the fracture pressure of the reservoir. The main drive mechanisms include gravity
drainage and thermal expansion. Laboratory tests have shown that imbibition can occur at high
temperatures (greater than 150°C) resulting in altered wettability and enhanced drainage from the
matrix. Longer term production testing will be needed to confirm this production mechanism.
A useful plot for comparing CSS projects is the recovery factor versus pore volume injected as
shown for the Pilot wells on the following plot. Injection and production from the $AGD testing
has been excluded from the plot. As of December 31, 2014, 2C has recovered approximately 22
percent of BlIP over five cycles.
Saleski Pilot Recovery Factorvs Pore Volume Steam Injection
-
50%
t-__-
45%
-
-__
-
-
40%
35%
30%
0
EL
Cl Cyclic Only
25%
-
—C2
20%
-
15%
I
5
10%
Cyclic Only
—02
—03
J
1E
0
0.2
0.4
0.6
0.8
1
1.2
1.4
1.6
1.8
2
Pate Volume Injected
As of the effective date, the Pilot remains active and continues to investigate operational factors
and depletion mechanisms including the extent and significance of communication across the
marl (limey sandstone) separating the Grosmont C and D and the viability of solvent co-injection.
There has been evidence of localized temperature and pressure communication across the marl
separating the Grosmont C and D, indicating that the upper unit is being affected by heating from
L
GLJ Petroleum
Consultants
Page:2( otI4l
below. Data continues to be collected to better assess the degree and extent of this
communication.
Production data to date has shown that the Saleski Grosmont reservoir appears to act as a dual
permeability system and that the Grosmont C and D have material differences in their production
performance. The best early time production has come from the Grosmont C reservoir which has
lower porosity, compared to the Grosmont D; a higher percentage of the Grosmont C porosity is
contained within the vug and fracture network. Fracture characterization work, completed by the
Company, indicates that fracture and vuggy porosity makes up approximately 45 percent of the
total porosity in the Grosmont C and 18 percent in the Grosmont D.
GLJ estimates from Pilot inj ectivity and production rates, that the effective permeability in the
Grosmont C is on the order of 8 Darcies. Bitumen from the vugs and fracture network is likely to
have been the primary contributor to production in the early cycles, whereas bitumen from the
matrix is likely to be contributing to production in the most recent cycles. It is expected that long
term production will be dominated by matrix drainage.
As the cycles have progressed, 4D seismic was utilized to show the area of the reservoir that has
been heated in the Grosmont C. 4D seismic, taken in February 2014, shows the heated areas
surrounding the PlC and P2C wells.
Using material balance calculations, it can be shown that the BlIP from the heated fracture and
vug network is insufficient to account for production to date; therefore, to date, at least a portion
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of the matrix has been drained from the Grosmont C wells. This matrix drainage is supported by
laboratory (steam soak) tests performed by the Company, as well as historical results from the
Buffalo Creek Pilot. Ongoing production will continue to reduce the uncertainty in the relative
contribution of bitumen recovery from the matrix.
Grosmont D productivity to date has been lower than for the Grosmont C. A larger percentage of
the Grosmont D net pay is contained within unconsolidated dolomite (matrix porosity) compared
to the Grosmont C, resulting in lower effective permeability. From injectivity and production
performance, GLI estimates that effective vertical permeability in the Grosmont D is on the order
of 1.5 Darcies. Average porosity in the Grosmont D is approximately 33 percent higher than in
the Grosmont C, resulting in higher BlIP and larger recoverable resources.
GLJ expects production from the Grosmont D to be influenced less by the fractures and vugs and
more by the matrix. Therefore, the Grosmont D production rate will be lower than the Grosmont
C; however the larger resource in place is expected sustain long term production rates. Results
from the Pilot have demonstrated some heat scavenging benefits from the Grosmont C.
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BACKGROUND
The development horizon at Saleski is the heavily karsted and highly brecciated Grosmont
dolomite. The property falls on the regional Grosmont platform, identified by the Energy
Resources Conservation Board (ERCB, 5T98_2013) as containing 406 billion barrels of bitumen
resource, comparable in scale to the world’s largest producing oil field, the Saudi Arabian
Ghawar carbonate.
Through the mid-l970’s to mid-l980’s, Unocal Canada Limited, Canadian Superior Energy Inc.
and Alberta Oil Sands Technology and Research Authority (AOSTRA) conducted a number of
vertical well Pilot schemes to evaluate the formation’s recovery potential with various processes.
The high costs related to the remote access, in combination with mixed results due to various
operational and completion issues of the day, resulted in a suspension of the program with the
weakened oil price regime of the mid-1980’s.
The suite of eight Pilot tests were dominated by CS$ evaluations ranging through in-situ
combustion, pattern steam drive and foam divertants on what are now Husky Energy lands,
several townships north of the Company’s lease. Limited success was achieved where Pilot
steaming operations were compromised with communicating gas and water stringers, formation
pressures proved suboptimal for in-situ combustion, and the high bitumen viscosity proved not
amenable to a steam drive process, as consistent within the Athabasca oil sands.
Among the Pilot tests, the Buffalo Creek C$S Pilot (BC Pilot) at the lO-05-088-19W4 vertical
well was the most successful. Intermittently operated in the Grosmont C from 1979 to 1986, the
well produced 101,036 bbls over 12 steaming cycles. Analysis of the BC Pilot is limited by
operational constraints, such as insufficient surface tankage to hold oil production volumes
leading to periodic production shut-ins, as well as boiler limitations compromising steam quality
to below 80 percent and related equipment breakdown. Nevertheless, the BC Pilot produced peak
oil rates of 440 bblld, with a best cycle steam oil ratio (SOR) of 3.6 on cycle four. The calendar
day oil rate (CDOR) for cycle four was 77 bbl/d. Over approximately five years of production,
the CDOR was 55 bbl/d with a cumulative SOR (CSOR) near six. There was a final steaming
cycle with no subsequent production cycle that was not included in this summary.
The BC Pilot demonstrated high steam injectivity at contained pressures (below 4 mPa), extended
bitumen mobilization through production cycles over several months and an overall performance
favourable to early CSS tests within the Athabasca oil sands. A 10 metre offsetting vertical well
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Petroleum
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core drilled approximately 20 years following the BC Pilot operation demonstrated extended
depletion within the rock matrix, with residual oil saturations (Sor) below 20 percent over
intervals where initial oil saturations (Soi) had exceeded 90 percent. The Sor was shown to
decrease even in low porosity rock, supporting the application of a 9 percent porosity cutoff when
estimating net pay.
The plot below shows the core from the original 10-05 wells compared to the new well drilled,
post steaming operations, 10 metres away. The right half of the plot shows the areas of reduced
oil saturation.
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It should be noted that there have been numerous technological advancements in horizontal
drilling, completion and CSS technology during the intervening 25 to 30 years since the BC Pilot.
Sateski Pilot Operations
The Saleski property is several miles down structure from the eastern gas reservoirs within a
fairway that has a maximum thickness, reaching up to 50 metres, of preserved bitumen-saturated
reservoir within the Grosmont pay. The Company originally received approval to construct and
operate a Pilot project in 2009. The Pilot was originally designed for 1,800 bopd production and
to demonstrate the viability of applying SAGD technology within the Grosmont including a plan
to transition to a solvent cyclic SAGD process. Through 2012 the wells transitioned to a cyclic
process which required minimal modifications to the facility.
The Pilot currently consists of five horizontal well/well pairs and seven observation wells. Three
800 metre long well pairs (rig released in 2010), one 450 metre long (rig released in early 2012)
injector/producer well pair, and one single 800 metre long well (rig released in 2014) have been
drilled northwards from a central pad at 90 metre lateral spacing. The horizontal wells are offset
(within 5 to 10 metres) by vertical observation wells along the length of the horizontal wells with
one additional observation well between the two sets of well pairs.
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Components
Central Processing Facility
Details
-
-
-
-
Well Pad
-
-
Water Source and Disposal
-
-
Support Facilities
-
-
Conventional diluent treating and solvent recovery
systems
Two 50 MMBtu/hr OTSGs
The second OTSG was installed in Q4 of 2011 and was
fully operational in Qi 2012
FWKO and Treater
Four SAGD well pairs and one single well currently
drilled.
Two pairs at the base of the Grosmont C, two pairs at
the base of the Grosmont D. One single well in the
Grosmont D.
Six water source wells are available to the Pilot
Three disposal wells are available to the Pilot
Access corridor, borrow pits, camp site, associated
pipelines and a storm water retention pond
Trucks are used to transport product diluted bitumen to
market
The Pilot, designed for 1800 bopd of production capacity, has been operating since December
2010 with first oil produced in March 2011. Over the first four months of operations, two 800
metre long well pairs were brought on stream, one in the Grosmont C (P1 C) and one in the
Grosmont D (P 1D). During the first year of the Pilot, a series of field experiments were
undertaken to assess thermal performance in the warm-up phase, injector-producer
communication along the length of the well pairs, the feasibility of bull-heading steam injection
versus steam circulation and other production and injection optimization strategies. The early
Pilot results were hampered by limited availability of steam for injection as well as a number of
equipment failures, ultimately resulting in obtaining limited performance data from the Grosmont
D during the first year of operation. In the latter half of 2011, a facility steam expansion was
added and both producers in the Grosmont C and D were chemically stimulated to reduce near
welibore pressure differentials with marked improvements in production performance.
Considering Pilot results through late 2011, operations were transitioned to CSS in 2012.
Additionally, in early 2012, P2C (450 metre long), was drilled at balanced pressure, completed
without a liner and acid stimulated prior to commencing start-up operations. In Aug 2012, the
Company started steaming 2D which was drilled before the start of the Pilot. A single well, P3D
(800 metre long), was drilled at balanced pressure, completed with liner and acid stimulated prior
to commencing operation in May 2014. To date, the Pilot has produced in excess of 493 Mbbl of
bitumen.
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PROJECT STATUS
Saleski Project Development Status
December, 2014
—
Pilot
Project Component
Operation
Status
Pilot Started Year-end
2010
.
Marketing/Sales
Crude sales ongoing for Pilot.
Production trucked to various pipeline
and rail connected terminals.
.
Regular consultation meetings with
regional stakeholders.
No objections or letters of concern.
Stakeholder Consultation
Ongoing
Steam Addition
Complete
Horizontal Wells
Observation Wells
Production underway at Pilot. Wells
have been transitioned to cyclic
production. Solvent injection
commenced into well P1 C during
September 2012.
.
Ongoing
.
Comments
Complete
Complete
Second OTSG installed during Q4 of
2011, fully operational in Q1 2012,
An additional C well pair (2C) was
drilled in Qi 2012. 1C, 1D, 2C and 3D
have been in cyclical operation since
Sept 2012.
A sidetrack to the original P1 C well was
drilled successfully at the end of 2013.
Added an additional horizontal producer
well in the Grosmont D, P3D in the first
half of 2014 with first production
achieved in June 2014.
Seven observation wells equipped with
temperature and pressure sensors are
currently monitoring performance of the
Pilot.
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Sateski Phase 1 Project
—
10,700 bopd
Resource Delineation
Water Source
Waste Disposal
Power supply
Fuel Gas Supply
Sales / Diluent Pipelines
Comments
Status
Project Component
Currently 46 delineation
wells over 67 sections,
including 6 wells per
section in the initial
development area.
167 km 2D seismic, 1.1
km2 of 3D in the Pilot
area and acquired 23 km2
of3D in 2012.
.
.
Disposal stream from Pilot will be
utilized as make-up water. One
additional well was drilled in 2013.
Additional wells will be required to
facilitate ramp-up and additional water
requirements for cyclic operation. A
new pipeline will be required to bring
water from these new wells into the
facility.
Confirmed
Confirmed and Tied-in
.
.
.
.
Pipehned and Tied-in
.
Under Construction
Will utilize existing Pilot disposal
system. Three disposal wells have been
drilled, completed, tested and licensed
within the project area. Pipeline has
been installed to connect the wells to
the facility.
ATCO has a project underway to
supply utility power to the Saleski
Phase 1 development. The project has
regulatory approval and engineering is
complete. Plan to be in service by Q3
2016 in order to support construction at
Salesld.
Under Construction
.
Additional wells will be drilled
annually to increase the delineation.
Natural gas pipeline and TCPL meter
station have been completed and tied in
to Pilot. Capacity exists within this
system for Phase 1 with minor metenng
upgrades.
.
Regulatory application for the Stony
Mountain Pipeline was approved in Q22013 with certain permits subsequently
sold to TCPL. A major section of
.
.
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Project Component
Status
Comments
pipeline was installed in Ql-2014. A
separate TCPL project, the Grand
Rapids Pipeline, has been approved and
is currently under construction with a
planned start-up of Qi 2016.
Stakeholder Consultation
Regulatory Approvals
Engineering
Horizontal Wells
Observation Wells
Ongomg
Approved
Ongoing
Planned
Ongoing
Regular consultation meetings with
regional stakeholders. No objections or
letters of concern.
All significant regulatory approvals are
in place for the Phase 1 project. The
AER approval will be updated to reflect
the final process design and well
configuration. An update to the Water
Act approval will be required once the
source water wells are in place.
An international EPCM firm has been
engaged. Engineering is approximately
85% complete at the end of December,
2014. Full development cost estimate of
$520 million (gross) has been
reconfirmed.
Up to 32 horizontal wells will be drilled
from a single pad starting in Q3 2015.
Initially plan to drill 20 horizontal
wells.
Six observation wells equipped with
temperature and pressure sensors are
currently recording baseline conditions
in the first pad development area.
The above table, provided by the Company, outlines the development status of the Saleski project. An independent review
of representations made by the Company, beyond considering information in the public domain and submissions to the
regulatory authorities, was not conducted. It is standard procedure for GIJ to include a notice to advise that certain
information provided by the client was relied upon in the evaluation. The company has provided GLJ with a signed
representation letter accordingly.
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Petroleum
Consultants
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GEOLOGY
The Saleski project targets bitumen contained in the Upper Devonian Grosmont formation, which
is a dolomitized, shallow marine and tidal flat carbonate complex. The Grosmont is overlain
either conformably by a variable thickness of Upper freton dolomites and shales or
unconformably by clastics of the Lower Cretaceous Mannville Group. The Devonian carbonates
sub crop along a northwest to southeast trend and dip towards the southwest. The Upper Ireton has
been completely eroded just to the east of the study lands. The Devonian Nisku Formation, which
overlies the Upper Ireton, also subcrops over the study area. The Nisku is not believed to be
prospective within the study area.
Wells drilled in 2012 and 2013 have excellent core recovery compared to earlier poor core
recoveries. This data provides increased confidence in determining fades trends and changes in
fluid saturations within distinct fades. There are 46 vertical delineation wells on the property that
have penetrated the Grosmont and of those 37 have been cored. Well density ranges from one
well/section to 16 wells/section at the original Pilot area. The Alberta Energy Regulator (AER)
has agreed that four wells/section with at least two cored wells and 3D seismic (14 section 3D
covering the development area) fulfills the minimum requirements and gives adequate evaluation.
Currently, an amendment to the Pilot Project proposes the addition of 10,700 bbls/d to the Pilot’s
1,800 bbls/d. Those wells on a pad located in Section 27-085-19W4 have been licensed.
The Grosmont has been informally divided into Units A (lowest), B, C, and D (highest) within the
study area. These Units are separated by laterally continuous marl intervals, which may or may
not act as permeability barriers for a steam injection project. This study looks specifically at the
two uppermost units, the Grosmont C and Grosmont D, as well as some smaller potential within
the overlying Upper freton.
Although the dolomitization process is believed to have been completed in the Grosmont by
Mississippian time, the Grosmont was exposed during the pre-Cretaceous unconformity. During
exposure the Grosmont was subject to erosion and extensive leaching by fresh waters. Some
stratigraphic control is evident on porosity development. Low porosity zones are present at the
base and top of the C Unit and just above the middle of the D Unit. This is indicative of greater
movement of leaching fluids along fades with initially higher porosity and permeability. Porosity
types within the Grosmont include intercrystalline, mouldic, vuggy, leached, and fracture. Karst
processes are believed to have overprinted the earlier rock fabrics resulting in localized formation
of dissolution cavities, collapse breccias and karst pipes. Abundant vertical and sub-vertical
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Consultants
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bitumen stained fractures are present. The smaller fractures appear somewhat ‘bed-bound’
(confined to individual beds) with more frequent fracturing associated with increased amounts of
dissolution.
The Grosmont C and D were evaluated using core photos, core analysis where available and
down hole logs. A 9 percent dolomite scale porosity cutoff and 100 ohms resistivity were used as
pay cutoffs.
The Grosmont D can be subdivided into three zones. The uppermost zone is a porous and
somewhat laminated grainstone, possibly from a tidal environment. The middle zone is a lower
porosity mudstone facies, with occasional fossil remnants, that may have formed within a
lagoonal setting. The lower zone is the highest porosity interval within the Grosmont and has
undergone extensive diagenetic changes and original textures have been largely distorted. A
significant portion of this zone currently consists of unconsolidated dolomite crystals held
together by bitumen. The dolomite crystals are fine grained and somewhat degraded. It is
speculated that they formed as a result of intense fresh water leaching. A collapsed breccia
containing angular dolomite clasts is occasionally found within the dolomite crystal facies.
Intervals within the lower zone show an increase in the gamma log response. This is believed to
have formed where the greatest amount of leaching occurred and is commonly associated with the
best porosity. The Grosmont D is entirely bitumen saturated over most of the lease area. The
Saleski Grosmont Gas Field is present within the Grosmont D up dip of the Company lease
(therefore will not affect SAGD operations) and bottom water appears on the southwest edge of
the lease.
The Company suggests that Grosmont D Middle fracture Zone is in communication with the
Saleski Gas Pool and has seen pressure depletion from production of the gas. The middle
fractured zone is low porosity but highly fractured. It is possible that the fractures are partially
open, not completely filled with bitumen. Water would not push through the fractures if they
were filled with bitumen. If this is the case then the fractures may have formed after
immobilization of the oil.
The Grosmont C is separated from the D by a marl section up to 2 metres in thickness that is
known as the C / D marl. Examination of core photos over this interval reveals the presence of a
number of high-angle bitumen stained fractures. The bitumen stain indicates that the fractures
were open to reservoir fluids at reservoir conditions. This suggests that communication may be
possible between the Grosmont C and D Units within a SAGD steam chamber. The examination
of the core photos does not give the number, vertical extent or permeability of these fractures,
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Petroleum
Consultants
Page: 32 of 141
therefore the viability of a steam chamber progressing across this shale cannot be assessed in this
report.
The upper portion of the Grosmont C is composed of laminated dolostone that may have a tidal
origin. Over the main portions of the field, the uppermost 1 or 2 metres of the laminated zone is
frequently tight, with the rest of the zone porous reservoir. This overlies a porous vuggy interval.
Short sub-vertical fractures are common within the vuggy dolomites. As the amount of vuggy
porosity increases within this section, so does the amount of fracturing. It has been suggested that
fracturing occurred as a result of overburden compaction during the leaching process. It also
seems possible that fracturing was caused by stresses related to the Larimide orogeny. The lower
portion of the Grosmont C is formed of a tight argillaceous dolomitized wackestone that is not
reservoir rock. Sub-vertical bitumen stained fractures are also somewhat common with in the
mudstones and laminated intervals. Grosmont C cores show some facies variation, especially
towards the southwest edges of the lease. The Grosmont C may vary from medium to small sized
vugs to laminated dolomites. Both the facies and the reservoir fluids have significant effects on
the log resistivity. Therefore the presence of cores over this zone is important in determining
bitumen and water saturations. Where no cores were cut, pay determinations were based on offset
wells with both cores and similar log suites.
Average porosity and oil saturation data were taken directly from the core analysis on
representative wells. Sections of the core that were not analyzed have been assumed to be tight or
unsaturated and were excluded from the interpreted pay. Intervals of lost core were excluded from
interpreted pay over areas that match low porosity on logs. Where the lost core corresponds to
porous intervals on logs it was included in the net pay. Lost core intervals that were interpreted as
pay have been correlated back to the logs and assigned the average porosity and oil saturations
that were calculated for that unit. In general, average porosities and oil saturations were rounded
up in view of the low core recovery in karstifled regions.
An average porosity of 19 percent with an average oil saturation of 82 percent was calculated for
the Grosmont C using a 9 percent porosity cutoff. For the Grosmont D, an average porosity of 25
percent with an oil saturation of 83 percent was calculated using the same porosity cut-off. Net
bitumen pay for the Grosmont C and D have been illustrated on Maps 3 and 4.
Water appears to underlie the bitumen within the Grosmont C on the western and southwestern
edges of the lease. The basal water zones (identified by blue circles on the maps) are confirmed
by oil saturations from core analysis. A resistivity cutoff 100 ohm-metres was used to identif’
water on wells without core analysis. A possible transition between the bottom water and bitumen
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as seen on the core analysis of 07-04-085-19W4. The transition zone is believed to be identified
on other wells as having resistivity values between 100 and 200 ohm-metres. Unfortunately the
resistivity does not always reflect the oil saturation values seen on cores. It is believed that the
disparity is caused by different pore geometries (and therefore different resistivity responses)
within each of the separate depositional facies identified. There appears to be a tilted bitumenwater contact within the Grosmont C at $aleski. This may have occurred as the oil was
biodegraded and immobilized before the Larimide orogeny was completed. Later stages of
mountain building resulted in lower Devonian structures to the west and a tilted bitumen —water
contact. A separate and somewhat higher bitumen-water contact also appears within the
Grosmont D in the southwest corner of the study area.
A potential karst pipe or ‘sinkhole’ has been noted in the Grosmont D on the well at AAIO 1-28084-19W4. Well logs show a high gamma response with high porosity readings and low Pe and
low resistivity values. The variations in porosity which can be so readily correlated between the
other wells are not seen in 01-28. Core photos and analysis both show good porosity and bitumen
saturations. Karsting can be seen and has been identified on 3D seismic. As referenced in
“Seismic Characterization of Collapse Dolines in the Grosmont formation, Alberta Canada”
Houston et al, Osum Oil Sands Corp. acquired a high resolution 3D seismic survey over nine
sections in Township 085, Range 1 8W4. Evaluation of the seismic character enabled the
interpretation of the presence of collapse dolines/karsts in the Grosmont Formation. The karsts
are seen to have an average diameter of 70 metres and are anticipated to enhance proximal area
porosity and permeability. The karsts have variable fill including shale, mudstone, sand, and
breccias. These features do not impact caprock integrity.
A west east stratigraphic cross-section (Saleski A-A’) was constructed and shows very good
correlation of formations and internal markers as well as consistent thickness and log signatures
in the Grosmont B, C and D. The cross-section compares wells that are located in the Pad 1, Pilot
Project, east of Pilot Project, and west edge of Osum’s Sepilco Kesik property.
-
A porous and permeable bitumen saturated zone within the Upper freton has been analyzed across
the study area. In some of the wells within the study area this zone directly overlies pay within the
Grosmont D; in the others a thin argillaceous interval separates the Upper Ireton carbonates from
the Grosmont. The Upper freton appears to be somewhat argillaceous, with high porosity and
somewhat low resistivity values. On core photos the Upper freton is largely rubble, with bitumen
stain that is somewhat irregular, and generally lighter in colour than the better zones within the
Grosmont D reservoir. Net bitumen pay for the freton at an 18 percent pay porosity cutoff is
illustrated on Map 5. In the Upper freton cores that were analyzed, an average porosity of 25.7
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percent with an average bitumen saturation of 70 percent was determined. The few permeability
values reported have been within the range of 50 to 100 mD.
The caprock for the project areas! property is the Clearwater Formation which is comprised of the
Clearwater shale and Wabiskaw Member. Total thickness of the Clearwater Formation exceeds
80 metres with the Clearwater Shale being 50 metre thick. Source water for the Projects is the
Lower Grand Rapids Formation. After water recycling any water needing to be disposed of will
be disposed into the Cooking Lake formation which is the perforated zone in the 102/05-23-08520W4 water disposal well.
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Consultonts
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RESERVES
GLJ has prepared estimates of probable and probable plus possible reserves for the Saleski
property. The BlIP and reserves estimates can be found in Tables 2 and 2.1. Proved reserves
have not been assigned to the Saleski property.
The Company’s current plans are to develop the Grosmont C and D reservoirs using horizontal
LP-CS$ wells. In areas where the Grosmont C and D are both present, one horizontal well will
be placed in each zone. The Upper freton Formation was not considered for reserves.
Grosinont Formation
There is sufficient evaluation well density to classify all of the mapped lands as discovered. The
discovered lands are generally assessed as sections with an evaluation well and sections surrounding
a section with an evaluation well. Evaluation wells are vertical wells with enough information to
establish the COGEH “known accumulation” criteria.
The probable and possible undeveloped reserves were assigned to portions of the lease within the
Phase 1 project approval area, directly adjacent to the Saleski Pilot having 3D seismic data and
sufficient vertical well density for effective project execution.
Effective net pay was designated as the vertically contiguous oil pay that is interpreted to be
suitable for the LP-CSS process as illustrated in Maps 3 to 6. The BlIP for each legal subdivision
SD) is calculated using average parameters based on the contribution of each facies to the total
pay thickness. The appended land map highlights lands that were considered for probable and
possible reserve bookings.
Reserves estimates were prepared based upon the horizontal well LP-CSS technology as per the
Pilot. Evidence of the anticipated success of such a scheme is based on:
•
Ongoing data collection from the Saleski Pilot, including demonstrated productivity,
recovery factor to date and steam oil ratios for the Grosmont C and D reservoirs; which
are directly adjacent to the Phase 1 development.
•
Results from the original Buffalo Creek vertical well Pilot, which is a geological
analogue to the Company Pilot and Phase 1 areas.
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Page; 36 at 141
•
Simulation work conducted by the Company, where they successfully history matched
the performance of the Buffalo Creek vertical well Pilot, and then used the simulator to
derive predictions for horizontal development.
•
Simulation sensitivities conducted by the Company for various configurations of
Grosmont D/C zone connectivity and well placements.
•
Steam flood tests on Grosmont C and D core samples and a steam rise test on an freton
core sample.
•
Success of the horizontal well CS$ process in sandstone reservoirs throughout the Cold
Lake oil sands region.
•
Recovery factor algorithm developed by GLJ based on thermal recovery methods, the
performance of operational SAGD and CSS projects and a review of simulation studies
conducted by other operators in carbonate reservoirs.
Specific uses of the aforementioned data as they pertain to reserve estimates are included where
applicable.
Ultimate recoverable reserves were calculated volumetrically using techniques traditionally
employed to thermal recovery in clastic reservoirs, adjusted for differences in reservoir
properties, specific to the Saleski Grosmont. th order to match performance from the Pilot data,
as well as capture differences in performance between the Grosmont C and D, the original
volumetric model was modified to a dual permeability model. The percentage of porosity
attributed to the fracture and vug network in the Grosmont C and D, were estimated using
fracture characterization work performed by the Company, and viewed as reasonable by GLJ.
One of the biggest uncertainties in the potential success of CSS or SAGD in the Saleski
Grosmont Formation is the prediction of the portion of the reservoir that will effectively be
heated by the steam to allow gravity drainage. The simulation of the Buffalo Creek Pilot
demonstrated that fracturing and karsting in this area of the reservoir was extensive enough for
the Grosmont C and D zones to be in communication and for the reservoir to act as a single
porosity system. Temperature communication is evident based on production performance of the
recent cycles in the Grosmont P1 D well; however the extent of hydraulic communication is less
certain.
Solvent injection tests conducted by the Company in 2008 demonstrated good pressure
communication between the Grosmont C and D zones. Cores exhibit oil-stained fractures in the
marl zone between the Grosmont C and D, as well as between the Grosmont D and freton. The
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Page: 37 of
degree and geographic variability of the communication as a result of this fracturing is somewhat
uncertain, however.
Zone
—
Connectivity
In the probable reserves category, the Grosmont C and D zones were treated as separate zones
with no significant hydraulic communication. In the probable plus possible reserves category, the
Grosmont C and Grosmont D were assumed to be in sufficient hydraulic communication, such
that bitumen below the Grosmont D producer well could be drained, through the marl, by a well
in the Grosmont C. Temperature communication between the Grosmont C and D was assumed in
all cases.
The following figure is a two dimensional cross section through a horizontal single well CS$
steam chamber, illustrating the idealized portions of the reservoir that are expected to be drained:
br* iic
—D-
Top O( R(VO1t
-1
Cychcinjearand
•
Displacement efficiency (Ed) Ed has been calculated using initial average oil saturations
detailed in Table 2 and residual oil saturations.
-
Based on performance to date, residual oil saturation in the fracture network was
estimated at 10 percent in the probable reserves category and 2.5 percent in the probable
plus possible reserves category. The probable number compares to typical residual oil
saturation in a elastic reservoir of approximately 10 percent, whereas the lower value
reflects the potential to virtually deplete the fracture network.
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The Company performed preliminary core-steaming tests to help quantify recovery in the
reservoir matrix. Steam soak tests (ten days in length) recovered 41 and 30 percent of the
bitumen from Grosmont C and D core samples, respectively. Drainage was still occurring
at the end of these tests and CT scanning of the core samples provided evidence of matrix
drainage in both instances. A steam rise test (20 hours of steaming) recovered
approximately 30 percent of the bitumen from freton core with a low measured
permeability of 21.6 mD. It is expected that actual steam drive and longer time periods
would result in significantly higher oil recovery. A more recent end-point saturation test
was conducted which measured a residual oil saturation of 38 percent. Afler correcting
for capillary effects the end point residual oil saturation was determined to be 25 percent.
The test was conducted on a Grosmont C core sample with a porosity of 31.5 percent
(predominantly matrix porosity).
Matrix residual oil saturation was estimated at 25 percent for the probable and probable
plus possible undeveloped reserves categories. This value was based on the
aforementioned core flood test, conducted by the Company.
There is evidence that under field scale operating conditions the residual saturation in the
matrix could be even lower than the laboratory result of 25 percent. As previously
mentioned, in the discussion of the Buffalo Creek Pilot, a core well was drilled 10 metres
offsetting the vertical C$S, 20 years following steam operations. Residual oil saturations
were found to be less than 20 percent in areas that originally had oil saturations near 90
percent prior to production including regions of matrix porosity.
•
Gross vertical sweep efficiency (Eq) E is the ratio of the net pay thickness above the
producer (effective pay) divided by the total continuous net pay. In the absence of bottom
water, Grosmont D producer well standoffs, from the base of the C/D marl, were
estimated at 2.5 and 2.0 metres for the probable and probable plus possible undeveloped
reserves categories respectively. In the absence of bottom water, Grosmont C Standoff
was estimated at 1.0 and 0.5 meters for the probable and probable plus possible
undeveloped reserve cases respectively. There is no bottom water within the approved
project area.
—
Grosmont D standoff is based on industry standard results for horizontal well standoffs,
as demonstrated in the Athabasca and Cold Lake regions. These standoffs are consistent
with results to date drilling the D Pilot wells.
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The reduction in Grosmont C standoff is based on the Company’s ability to place
weilbores closer to the base of pay without negatively affecting productivity, as
demonstrated with the C Pilot wells.
•
Gross horizontal sweep efficiency (Eh) Eh is a function of the slope of the bottom of the
steam chamber at depletion, inter-well spacing, and net pay thickness above the producer.
LP-CSS steam chamber slopes of approximately 12 and 7 percent were used in the
probable and probable plus possible undeveloped reserves categories respectively.
—
A 10 percent value is a typical slope exhibited for SAGD in clastic reservoirs. It is
expected that abandonment will occur sooner for LP-CSS wells and as such the steam
chamber at abandonment will be slightly higher. Simulation work conducted by the
Company indicates the steam chamber slope at depletion could be as low as 5 percent for
SAGD; however, it is dependent upon the relative vertical to horizontal permeability.
•
Continuity efficiency (Eu) E accounts for remaining sweep inefficiencies including
uneven steam heating along the welibore, heterogeneities and local permeability breaks in
the reservoir, operational upsets and risk due to uncertainties in the recovery process. 4D
seismic, as well as temperature measurement can give an indication of areal
conformance. Typically the longer a well produces the higher the areal conformance, as
evidenced in 4D seismic.
-
As a point of reference, best estimate conformance in clastic reservoirs, spaced
approximately 100 metres apart, typically is in the range of 75 to 90 percent, as
evidenced by 4D seismic and production performance of historical wells. Individual well
conformance, for wells in the middle of a producing pad, can approach 100 percent,
though this is not indicative of conformance on a field level. Decreased well spacing will
tend to increase aerial conformance.
In the Saleski Grosmont, there is risk that injected steam may travel preferentially along
the vug and fracture network resulting in a lower overall areal conformance. In addition
the presence of karsts may impact conformance; wells must be properly placed and steam
and bitumen must travel around or through the karst. While these concerns still remain,
the Company has gathered data to identif’ karsts and quantify the portion of the resource
which may be affected by their presence. The conformance factor has been estimated
considering this data.
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To increase weilbore conformance, the Company has employed acid stimulations on the
wells increasing near weilbore penneability and mitigating damage from drilling. Future
more balanced drilling is expected to minimize welibore damage and decrease the
requirements for acid stimulation. P2C was drilled balanced and production to date
supports improved performance. Temperature data gathered from injector wells prior to
acid stimulation showed that steam was preferentially entering certain areas of the
weilbore. Following acid stimulation, the temperature profile is much more uniform,
showing good welibore conformance. 4D seismic, last updated February 2014, shows
good areal conformance along the length of both the 1C and 2C weilbores as shown in
the following figure.
Lastly, the conformance will include additional allowances for operational upsets, which
can affect steam chamber growth as well as any other perceived uncertainties.
Separate conformance values were estimated for the matrix and fracture-vuggy porosity
in the Grosmont reservoir. Though somewhat conceptual, this separation allows for better
resolution between recoverable volume estimates between the fracture-vug dominated
Grosmont C and the matrix dominated Grosmont D.
Conformance in the fracture-vug system was estimated at 85 and 95 percent in the
probable and probable plus possible undeveloped reserves categories, respectively. These
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values are similar to demonstrated confonnance in elastic reservoirs, and are supported
by the 4D seismic and temperature results to date.
Conformance in the matrix was reduced to 60 and 85 percent in the probable and
probable plus possible undeveloped reserves categories, respectively. Conceptually the
conformance in the matrix is estimated at a lower value because of the higher
temperatures required for imbibition effects to take place. Ultimately the matrix within
the heated area will compete for heat from steaming operations, with fractures beyond the
heated area. At this point in the development of the Grosmont, it should be noted that the
matrix conformance has been risked substantially compared to elastic reservoirs.
The above conformance in the matrix is for 60 metre inter-well spacing, proposed for the
initial well pads in 2013. The company has revised initial well pad Grosmont C well from
60 metre to 120 metre spacing while Grosmont D well will remain at 60 metre spacing.
For future wells, the Company plans to increase inter well spacing to 120 metres in the
Grosmont C. (Grosmont D will remain at 60m) Matrix conformance was decreased by
2.5 percent from the initial values for areas with 120 metre spacing.
Economic and Facility Liinits
Marginal well pair economics were found to support development down to an economic
threshold of 300 MbblJwell for 1000 metre wells. Initial wells are forecast at 925 metres and are
all determined to be economic. Recoverable bitumen volumes for all resource categories were
based on a 9 percent porosity cutoff, verified from core flood tests conducted by the Company
and their partner. Economically exploitable reserves lands are illustrated in Appendix III.
Recovery factors were ultimately assigned in consideration of technical uncertainty associated
with the process; as described below:
Type Well
Probable Recovery Factor
Probable
+
Possible Recovery Factor
Grosmont C Initial Pad
(120 m Spacing)
4 1.0%
62.5%
Grosmont C Additional Reserve Area
(120 m Spacing)
40.5%
62.1%
Grosmont D Initial Pad
(60 m Spacing)
40.4%
57.8%
40.I/o
57.5/o
—
—
—
Grosmont D Additional Reserve Area
(60 m Spacing)
—
.
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Petroleum
Consultants
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The CSS recovery factor is believed to be reasonable when compared to those exhibited by
CNRL’s Primrose Clearwater horizontal C$$ project, where CNRL is predicting a 20 percent
recovery factor for 160 metre spacing development, 40 percent recovery in 80 metre spacing and
50 percent recovery factor for 60 metre spacing. Imperial Oil’s Cold Lake vertical well CSS
project is forecast to recover approximately 38 percent of effective bitumen-in-place using an $
percent bitumen weight percent cutoff or 26 percent using a 6 percent bitumen weight percent
cutoff.
For reserve estimation, steam injection and bitumen production rates are limited by the Phase 1
facility design (10,700 bbl/d and SOR of 3.9). Current Phase 1 capacity is insufficient to allow
for development of all potentially bookable reserve volumes within the 50 year maximum life; as
such any lands that cannot be developed, within the 50 year life, were classified as contingent
resources.
Phase 1 of the Saleski project will represent the first commercial application of thermal recovery
in the Grosmont Formation. COGEH Volume 2, Section 6.7.3 states that “the first commercial
application of a process cannot rely on analogies and requires actual performance of a Pilot or
operational scheme”. The Saleski Pilot is currently operational and GLJ has relied on Pilot data
gathered since late 2010 in its assessment of the technical and economic viability of the LP- CSS
process. Longer term performance projections, commercial development planning, and steaming
strategies are assisted by experiences and best-practices from clastic oil sands projects, adjusted
for specific characteristics of the Grosmont Reservoir, and calibrated with existing Pilot data.
Production to date from the Pilot wells has been extrapolated to ultimate recovery factors,
calculated using the aforementioned sweep efficiencies. The recovery versus pore volume plot
below shows the extrapolated reserve type well forecasts for probable, probable plus possible
and P90 type wells, compared to the Pilot data to date. At the time of booking, economic
sensitivities were undertaken for the probable reserves, based on a range of oil prices, drilling
costs and bitumen wellhead prices, to confirm positive economics.
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Saleski Reserve Area Type Well Plots
-
70%
60%
55%
50%
45%
40%
Cl. Ctr C On
—
La
35%
0Z
30%
—
Dl
p,aD.snzC.a.C. PCl*..OntC*ZDt
—
P;dl 5lzzCtd.D.Pn::ateLndne,.d
—
g.nnA’n.Dt c,a,D. ?r:C,C.Und.., Late
25%
20%
-
Pl-SrI:Ced.C.Pt;Da: ,*P:uC.Cnd!n:p4d
P3ll..lllC.ed.D.PTCCIC *CZfC Ct
15%
R.nr..Ds.,.Dla:k.C.C.Pr,btL., P0CC. LndCflp,d
D,nn.*At,.Cttck.d.D.P,al,b
tC
LndC,Dptd
10%
hi D.St.:k
R,s.fl.
.O.PiJtn.:.0h,C Ct.d
tI.St&lCEd.C.P3ZICC.:.e I,
5%
kI,.CtLak.i-D.PCCOn.zulC:tEook,d
0%
0
0.2
0.4
0.6
0.8
1
1.2
1.4
1.6
1.8
2
2.2
Pore Volume Injected
The Grosmont C type wells are based on extrapolation from the P2C production to date. Since
2012, P2C has shown consistent production at approximately 200 bopcd (yearly average) with a
CSOR of approximately 4.
Performance in the Grosmont D has been limited, due to availability of steam and focus on the
Grosmont C. A number of cycles have demonstrated production rates greater than 100 bopcd
with an SOR of less than 2. These recent results give confidence that the recovery factor
calculations utilized in the Grosmont C can be also be applied in the Grosmont D. Ultimate
recovery is extrapolated based on the same methodology utilized for the Grosmont C. It should
be noted that the ID and 2D wells were also drilled using the original over-balanced drilling
technique. It is expected that balanced drilling should improve productivity of the Grosmont D
formation, in the same way as it did with the 2C for the Grosmont C. P3D was drilled in 2014
with balanced drilling and its performance will be closely monitored to determine Grosmont D
productivity.
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Petroleum
Consultants
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RESOURCES
GLJ has prepared estimates of best estimate and high estimate for the Saleski property. The
resources estimates can be found in Table 2.2. Low estimate contingent resources were found to
be uneconomic on a project basis and are assessed to be zero.
Best and high estimate contingent resources are assigned to all economically exploitable lands
beyond the reserves lands.
Effective net pay was designated as the vertically contiguous oil pay that is interpreted to be
suitable for the LP-CSS process as illustrated in Maps 3 to 6. The BlIP for each LSD is
calculated using average parameters based on the contribution of each facies to the total pay
thickness.
In general, best estimate contingent resource parameters were consistent with those used in the
probable reserve estimates, whereas high estimate resource parameters were consistent with
probable plus possible reserves estimates. Unlike the reserves categories, the Upper freton has
been considered in the contingent resource categories.
The recovery factor algorithm incorporates zone connectivity and the following sweep
efficiencies:
Zone
—
Connectivity
In the low estimate contingent resource cases, the Grosmont C and D zones were not assumed to
be hydraulically connected, nor the Grosmont D and freton. In the best estimate contingent
resource category, the Grosmont D and Ireton zones were assumed to be in communication
whereas the Grosmont C and D were assumed not to be in communication. In the high estimate
contingent resource category, the Grosmont C, Grosmont D and freton zones were all assumed to
be in communication. Temperature communication between the Grosmont C and D was assumed
in all cases.
•
Displacement efficiency (Eu) E has been calculated using initial average oil saturations
detailed in Table 2 and residual oil saturations.
-
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Displacement efficiency was calculated using the same methodology as described in the
reserves section.
Residual oil saturation in the fracture network was estimated at 25, 10 and 2.5 percent in
the low, best and high estimate resource categories, respectively. Matrix residual oil
saturation was estimated at 40 percent in the low estimate and 25 percent for the best and
high estimate contingent resource categories.
Residual oil saturation in the Upper Ireton was estimated at 30 and 25 percent in the best
and high estimate contingent resource cases. The higher value used in the Upper Ireton is
due to the higher uncertainty in the formation at this stage of development.
•
Gross vertical sweep efficiency (E) E is the ratio of the net pay thickness above the
producer (effective pay) divided by the total continuous net pay. Grosmont D producer
well standoffs of 3.0, 2.5 and 2.0 metres were used in the low, best and high estimate
categories, respectively. Grosmont C Standoff was reduced to 1.5, 1.0 and 0.5 meters in
the low, best and high estimate categories, respectively, based on the ability to place
wellbores closer to the base of pay, as demonstrated with the PlC and P2C Pilot wells.
—
For CSS development, in regions with thin underlying bottom water (less than five
metres), producer offset was increased by 1.5 metres, to prevent drilling wells near the
oil-water contact. In regions with greater than five metres bottom water, no recoverable
resources were assessed. Bottom water occurs in the Grosmont C, and to a lesser extent
in the Grosmont D, in the western and south western regions of the interest land as
indicated on Maps 3 and 4.
•
Gross horizontal sweep efficiency (Eh) —Slopes of 22, 12 and 7 percent were used in the
low, best and high estimate categories, respectively. The reservoir development scenario
assumes development of the lease with 1000 metre long wells placed 60 metres apart in
the Grosmont D and 120 metres apart in the Grosmont C.
•
Continuity efficiency (E) E accounts for remaining sweep inefficiencies including
uneven steam heating along the welibore, heterogeneities and local permeability breaks in
the reservoir, operational upsets and risk due to uncertainties in the recovery process. 4D
seismic, as well as temperature measurement can give an indication of areal
conformance. Typically the longer a well produces the higher the areal conformance, as
evidenced in 4D seismic.
-
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Petroleum
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fracture conformance was estimated at 65, 85 and 95 low, best and high estimate
resource categories, respectively. Matrix conformance was estimated at 45, 60 and $5
percent in the low, best and high estimate resource categories, respectively. Conformance
in the Ireton was set equal to the matrix conformance in the Grosmont.
The above matrix conformance is for 60m inter well spacing, proposed for the Grosmont
D wells. For Grosmont C wells, the Company plans to increase inter well spacing to 120
metres. Matrix conformance was decreased by 2.5 percent from the initial values for
areas with 120 metre spacing. In the low estimate resource case, both matrix and fracture
conformance were reduced by 2.5 percent.
As for the resources, the economic threshold for development was determined to be 300
Mbbl/well. Economically exploitable contingent resource lands are illustrated in Appendix III.
Contingenciesfor the Conversion ofResources to Reserves
The following contingencies specific to the $aleski property preclude the classification of these
recoverable resources to reserves at this time. Steps needed to remove the contingencies are also
included below:
Economic
• There are no economic contingencies for the best and high estimate contingent resource
categories; the best and high estimate net present values (NPV) are positive at a 10
percent discount factor based upon the same forecast fiscal conditions used in the
assessment of reserves. The low estimate contingent resources are uneconomic under the
forecast fiscal conditions; recoverable volumes are assessed to be zero for this category.
future reserves estimates will require high quality cost estimates and/or historically
demonstrated costs to confirm positive project economics.
•
Reserves estimates require high quality cost estimates and/or historically demonstrated
costs to confirm positive project economics. High quality cost estimates have been
obtained for Phase 1 only.
o Reserve estimates for Phase 1 use demonstrated drilling and completion costs
from the Pilot latest 3D well.
o Phase 1 facility costs were based on estimates provided by the Company. These
estimates agree with expected costs from GLJ’s confidential and non confidential
database of historical projects. Facility design will not be substantially different
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from those utilized to produce via CSS from clastic reservoirs, of which there are
multiple commercial examples.
Non-Technical
Project maturity the Saleski property has sufficient core-hole delineation to all be
considered discovered. VlIhile the “known accumulation” criteria have been satisfied for
the property, additional drilling within the area of the discovery lands is required to allow
further project definition for portions of the Phase 1 area and for the balance of the
property. GLJ has considered contiguous lands within the project development area of
Phase 1 with 3D seismic and a delineation density sufficient for effective project
execution to satisfy this contingency for probable and possible reserves.
—
Regulatory application submission the submission of the regulatory application for
development typically confinns a level of company commitment and advanced
development planning including project feasibility and technical studies suitable for an
investment decision. In this instance, the Company received regulatory approval for a
10,700 bopd commercial CSS project in 2013. Probable and possible undeveloped
reserves have been assessed for portions of the reservoir within the approval project area.
Proved reserves have not been booked due to an economic contingency. Additional
applications and approvals will be required for reserves assessment for future phases of
development on lands outside of the approval project area.
—
Finn development plans and company commitment confirmation of corporate intent to
proceed with initial major capital expenditures within a reasonable timeframe is a
requirement for the assessment of reserves. Following COGEH guidelines, reserves may
be assessed provided significant capital is scheduled to be spent within three years for
proved reserves and five years for proved plus probable reserves. In this instance, the
Company’s Saleski Phase 1 first steam is scheduled for 2017 with first major capital
incurred in 2015. Probable undeveloped reserves are assessed within the project area
subject to delineation drilling requirements and approved facility design. Subsequent
facility phases are dependent upon firm development plans and company commitment
and, therefore, remain in the contingent resource category.
High quality project cost estimates high quality capital cost estimates are required to
confirm positive project economics. The Company has provided high quality estimates
for Phase 1. The resource valuation incorporates a degree of capital cost savings
associated with future drilling and completion improvements, pad cost reductions,
economies of scale, modularization and execution improvements.
—
—
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Petroleum
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•
inadequate access to these
Access to labor, materials, infrastructure and markets
resources may impact project timelines. This property is located in the Athabasca oil
sands region proximal to existing oil sands developments. Some infrastructure such as
gas, power, source water, disposal and all weather roads already exists for the Saleski
Pilot; additional capacity will be required for Phase 1 and subsequent phases. Diluent and
bitumen transportation infrastructure will be needed to support higher production
volumes. There is a reasonable expectation that the Company will have access to labor,
materials, infrastructure and markets at a future date as development proceeds.
—
Technical
•
Technology the CSS recovery process proposed for this property is an established
technology which has been applied successfully commercially in certain sandstone
reservoirs in the Canadian Oil Sands Region. Results from the $aleski Pilot have been
scaled and extrapolated to form the basis of the reserve estimates for the Phase 1 project,
directly adjacent and analogous to the Pilot. For portions of this property, the contingent
resources assessed are analogous to the Pilot and recoverable volumes are estimated
using the same methodology. Other portions of this property are not considered to be
analogous to the Pilot; in the absence of a good analogue, further pilot or demonstration
roject results providing sufficient quality and quantity of data to allow for scaling and
extrapolation will be required to verif’ the technical, economic and commercial viability
of the recovery process.
—
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PRODUCTION AND DEVELOPMENT FORECAST
Production forecasts were determined for average type wells as detailed in Table 3.
Current plans are to develop the lease in stages. The Pilot scheme has been operational since 2010
and will be followed by a 10,700 bopd commercial phase (Phase 1) on-stream by 2017. Additional
phases are scheduled to be developed using modular facility design, which will be shared with
Germain, allowing for rapid development of the resource base and lower total installed costs. The
additional phases are sized at 75,000-125,000 bopd and SOR of 3.3 consisting of three to five subphases of 25,000 bopd. Facility SOR design was based on the Company’s plans.
Reserves Prodttction forecasts
Peak production rates for LP-C$$ wells were calculated using GLJ’s standard analytical
correlations, calibrated to actual production performance demonstrated by the Pilot.
To date, 2C (450 metre long well) is the best well producing at approximately 200 bopcd during
2012 and 2013. In 2014, 2C produced 166 bopcd. 1C production ($00 metre long well) is
currently approximately 98 bopcd. The Company has demonstrated the ability to increase
productivity in the Grosmont C through balanced drilling and acid stimulation.
The 1D well is currently producing approximately 129 bopcd. The Grosmont D well has shown
increasing oil rates over the first three cycles in contrast to the Grosmont C, which responded
quickly to steam injection. This is consistent with the fact that the Grosmont D has a higher
portion of matrix porosity. It is expected that the Grosmont D will take longer to respond to
steaming operations. Although the Grosmont D has been forecast with lower peak rates, the
profile is sustained given the substantial recoverable resource. Notably, 3D well was recently
drilled with improved drilling and stimulation techniques to demonstrate enhanced productivity
in the Grosmont D.
For Pad 1 of the pending commercial phase, GLJ has estimated average yearly peak oil rates for
of 410 bopcd and 240 bopcd for the Grosmont C and D, respectively. Production forecasts for
reserve type wells are presented in Table 3 of the report.
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Petroleum
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Contingent Resottrce Prodttction forecasts
Production forecasts for contingent resource categories were detennined for average type wells
as detailed in Table 2.2. Peak oil production and SOR values were selected principally based on
a review of Pilot production with consideration given to Buffalo Creek Pilot and Saleski Pilot
simulation work provided by the Company and the longer tenn performance exhibited by
operational CSS projects in the Cold Lake Oil Sands Region.
Analytical models were adjusted for uncertainties associated with scaling the Pilot results across
the reservoir. Production rates are based upon the following:
• An average operating pressure of 1500 kPa
• Uptime factor of 75 to 90 percent in the Phases
• Reservoir permeability of 8 Darcies for the Grosmont C, and
• Reservoir permeability of 1.5 to 2 Darcies for the Grosmont D in the best and high
contingent resource categories, respectively.
Calendar day cyclic production and injection rates were adjusted to approximately half the rate
calculated for traditional SAGD gravity drainage to account for injection time and production
profile associated with the CSS process. The resulting production profiles are highlighted in
Table 3 of the report.
Steam-Oil Ratio Catcittations
SOR’s were based on a review Pilot performance to date, simulation results and values
calculated from the “Unified Model for Prediction of CSOR in Steam Based Bitumen Recovery”
(CIM Paper 2007-027) developed by N. Edmunds et al of the Company. This model has
successfully been utilized to predict steam oil ratios for multiple clastic SAGD and CSS projects
throughout the Athabasca and Cold Lake regions. Differences between clastic and carbonate
reservoirs can be accounted for by adjusting the appropriate rock and fluid properties within the
model. for Saleski, the model has been further calibrated using Pilot performance. With these
modifications, future steam requirements can be estimated with reasonable certainty for probable
and possible undeveloped reserve estimates, as well as for contingent resources.
Cumulative SORs were estimated for individual type wells as detailed in Tables 3. Plot 7 of the
report shows calculated recovery versus pore volume injection of the reserve area type curves,
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Petroleum
Consultants
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compared to the Pilot production to date. Representative P90 type curves are presented on the
plot though no proved reserves or low estimate contingent resources were assigned to the project.
Production, drilling, capital and operating cost forecasts are detailed in Tables 4 through 4.3.9.
Drilling and production were scheduled to meet facility design capacities with steam facility
downtime. After Core-hole drilling was scheduled assuming a core-hole density of four wells per
section plus 3D seismic costs.
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ECONOMIC ANALYSIS
Economic forecasts for the reserves and resource categories are presented in the Economic
Forecasts section of this report. The Company has provided
•
Historical capital costs for the Pilot,
•
Lease operating statements for the Pilot,
•
Capital cost estimates for Phase 1, and
Detailed operating cost budgets for Phase 1 and 2 bridged to current operations at Saleski
and Germain.
•
Given the experimental nature of the Pilot, the historical operating costs are high and reserves
have, accordingly, not been assigned to the Pilot. The Pilot operating costs have been forecast to
decrease once Phase 1 comes on-stream in 2017 given cost sharing synergies with the larger
adjacent phase.
The operating costs were estimated at $9,000 per C$S well per month, $1.50 per bbl of oil and
$1.00 per bbl of water plus purchased natural gas. Steam generation fuel and gas injection costs
were forecast using the GLJ Alberta Spot Plant Gate gas price with an added $0.1 0/Mcf for
transportation and quality adjustments. Fuel to steam conversion efficiency was estimated at 0.40
Mcf/bbl of steam based on Pilot gas usage and steam generation data. Fixed annual operating
costs are forecast as follows:
•
Phase 1 oil battery
•
Phase 1 steamer
•
Future phases
•
Future phases
—
—
—
$600 M/year per Mbbl/day of installed capacity
$35 M/year per MMbtu/hr of installed capacity
$500 M/year per Mbbl/day of installed capacity
—
$30 M/year per MMbtulhr of installed capacity
The fixed annual oil battery and steamer costs were increased by 100 and 50 percent in the first
and second years of operations, respectively, to account for higher costs typically encountered.
The above operating costs are based on the Saleski lease operating statements, the Company’s
detailed operating cost budgets and GLJ’s experience with similar thermal projects within the
Athabasca Oil Sands Region. The fixed and variable well operating costs are estimated to be
higher than comparably sized thermal sandstone projects based on operating experience to date
and the expectation for additional costs associated with routine acid jobs plus other maintenance
specifically associated with a carbonate project.
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Phase 1 facility capital cost estimates have been based primarily on the Company’s estimates.
These cost estimates are within the range exhibited by other operators for similar sized recent
projects. GLJ has estimated the cost for future phases based on the Company’s Phase 1
projections and our knowledge of other projects. The future phases include a synergistic cost
reduction typical of brownfield development.
In contrast to the facility operations, drilling and completion of the Grosmont presents additional
technical challenges when compared to standard thermal operations. These technical challenges
include lost circulation while drilling and near welibore formation damage. In drilling the Pilot
well pairs, the Company has shown the ability to adapt its drilling techniques to address these
challenges, using balanced drilling and acid stimulation as examples. Cost improvements have
been shown in the 3D based on improved drilling and completion design. Notably, demonstrated
costs (including acid stimulation) are still approximately twice as high as typical drilling and
completion costs observed in sandstone reservoirs. At Germain, the Company has demonstrated
an ability to reduce drilling costs by approximately 20 percent for a multi well program.
In light of these technical challenges, initial drilling and completion costs for reserve wells are
estimated at 5.25 MM$ per well, derived using actual costs from the drilling and completion of
the 3D well. The drilling and complete costs of the reserve wells include acid stimulation on two
thirds of the wells; the Company’s plan includes costs to acidize 30% of the wells. Long term
drilling costs were reduced by 12 percent to reflect additional cost improvements and synergies
associated with a larger program. Saleski Phase 1 will compare the performance of acidized and
non-acidized wells to determine stimulation effectiveness. The current cost of acidizing a single
well is $1 .5MM, representing a large part of the drilling and completion costs.
For contingent resource categories, drilling and completion costs were estimated at 4.5
MM$/well for 925 metre wells and 4.6 MM$/well for 1000 metre wells, reducing in the long
term to 3.5 MM$Iweil. These long term costs are greater than single well drilling and completion
costs in sandstone reservoirs within the Canadian Oil Sands Region.
Additional capital is included for pad construction and piping (1.525 MM$ per well) and
pumping equipment (0.4MM$ per well) in both the reserve and resource categories. Pad costs
were reduced in later years to account for equipment and construction material re-use. Core-hole
costs were estimated at 1,450 M$ per well initially, decreasing to 850 M$ per well in later years.
Annual sustaining capital was forecast at 1 percent of central facility costs plus 175 M$ per CSS
well. Well abandonment costs were included at 250 M$ per well.
Capital and operating costs are inflated at 2 percent per year.
LIi GLJ
Petroleum
Consultants
Pane: 54 of 141
Indicative economic forecasts for the resources categories are presented in the Economic
Forecasts section of this report. These economics beyond Phase 1 are scoping in nature, as
detailed project designs and capital cost estimates have not been prepared by the Company.
Phase level economics are included in Appendix I.
Crown royalties were calculated using the current Alberta Oil Sands royalty fonnula. The
royalties are calculated based on a cleaned crude bitumen product. Pre-payout, the base Tate is 1
percent of gross revenue and increases for every dollar the WTI is priced above $55 per barrel, to
a maximum of 9 percent when the WTI is priced at or above $120 per barrel. Post-payout, the
base rate is 25 percent of net revenue and increases for every dollar the WTI is priced above $55
per barrel, to a maximum of 40 percent when the WIT is priced at or above $120 per barrel. An
allowable costs royalty balance of 69.0 MM$ and a return allowance of 3.6 percent was
incorporated.
The bitumen produced from the property is to be sold into the open market as a diluent-bitumen
blend (dilbit). Dilbit and diluent will be initially trucked followed by pipeline installation to
support increased production from both Germain and Saleski. field gate oil prices were forecast
assuming blending with diluent at a long term blending ratio of 0.426 bbl diluent per bbl of
bitumen.
In the reserves cases, long-term dilbit and diluent transportation tariffs are estimated at $3.25 per
bbl and $5.15 per bbl, respectively. In the resource cases, long-term dilbit and diluent
transportation tariffs are estimated at $1.75 per bbl and $1.50 per bbl, respectively. The
difference in pricing scenarios reflects a volume discount in the resource case. Pricing
assumptions for the reserves and contingent resource cases respectively are summarized in
Tables 5a and Sb.
Other Economic Considerations
This report does not address the following issues:
•
Non-reserves/resource well abandonment, welisite reclamation and facility abandonment/
salvage including possible environmental concerns.
•
Potential processing income.
•
The current condition of field, gathering and processing facilities, i.e. an inspection was not
carried out.
•
Potential carbon taxes associated with greenhouse gas emissions.
LIJ GLJ
Petroleum
Consultants
Page: 55 of 141
Map 1
Land Map
Company: Laricina Energy Ltd.
Effective Date: December31, 2014
Property: Saleski
Project: si 143197/sal_land
R.20
R.21
R. 19
R. 18
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-
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UTM Zone 12N
‘project’sll43l97ldrafting’Mxd\salmOl_sl 143197.mxd
Well
Source: It-IS (Decerr1er 22. 2014)
Geologist:
Created by; lohudyk
Engineer. A. Wong
Created on. February 12.2015
Petroleum
Consultants
—f
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I GLJ
Project: yt 1431 97/sutsspgrnsntC_9
EtTective Date: December 31,2014
Net Continuous Bitumen Pay Map
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rmo 57 at 141
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Company: Loricina Energy Ltd.
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Project: st 143 t97/sol_opgrsmtD_9
Effective Dote: December 31,2514
Net Continuous Bitumen Pay Map
Grosmont “D° formation
9% Porosity Cutoff
Peon SC d141
::
-
e
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Project: a! 1431 97/sal_np_uirto_15
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Project: et 143 197/natjrp_nnks
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I 41
GLJ 4ii
Effective nste: December31. 2014
Net Continuous Bitumen Pay Map
Nieku Formation
tUB
0
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Gas:
Oil
Water:
2010
2012
2013
it
Year
2014
——-
----
Solvlnj
Coed Inj:
Gas lnj:
2015
2016
2018
Cumulative Injection
0.OMMcf Steam Inj:
6.9Mbbl
Water Inj:
0.OMMcf
2017
i___._._..___.________.____________________
-h1!-4--
iftirm
:
Cumulative Production
75,6 MMcf
403.5 Mbbl
2117.9Mbbl
2011
i
————-__
Property : Saleski
Historical Production and Injection
Pilot
2019
0
CO
o
o
0
CO
o
N
o
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GLJ
Petroleum
Consultants
Pilot
1t43197 lion 23, 20t5
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3558.2 Mhbl
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Water:
Cumulative Production
Year
Solv Inj:
Cond Inj:
Gas In]:
Cumulative Injection
a:
26.4 MMcf
161.3 MbbI
541.4Mbbl
0.OMMcf
6.9Mbbl
0.OMMcf
Steam Inj:
Water Inj:
‘NJ
0
0
C,,
0
a:
GLJ Consultants
Petroleum
IC
1143 197 /Jan 23, 2015
1258.0 Mbbl
0.0 Mbbl
U
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0
0
0
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0
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0
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Gas:
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Water:
Property : Saleski
2010
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/
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2012
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Cumulative Production
20.0 MMcf
114.6MbbI
713.8MbbI
2011
IA:
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—.
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—
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-
2013
Year
2014
—
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2015
2016
2016
Cumulative Injection
Steam In]
0.OMMcf
0.OMbbl
Gas mi
2017
—--_—__
—________
Historical Production and Injection
1D
2019
0
a
N
CS
o
o
a
o
C-
0
L] GLJ
Consultants
ID
1143197/Jan 23.2015
626.2Mbbl
0.0 MMcf
N
o
N
o
o
o
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0
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Cs
o
o
Cs
o
o
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0
2009
Gas:
Oil :
Water:
2010
2012
Cumulative Production
24.0 MMcf
176.3 Mbbl
649.5 Mbbl
2011
fl
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Property : Saleski
2Q13
—
Year
2014
-
C:
fT
Solv Inj:
Water In]
2015
-
Historical Production and Injection
2C
2016
2015
Cumulative Injection
Steam Icij:
0.0 MMcf
Gas Inj:
0,0Mbbl
2017
-___
-
2019
Cs
o
ci
Cs
o
Co
o
o
o
CD
C-
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0
0
to
o
—
L“J GLJ
Petroleum
Consultants
2C
t143t97/3an23,2015
963.$Mbbl
0.0 MMcf
-
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2010
Status Summary
2009
On Production date:
On Injection date
Status date
Statuu : STEAM ASSISTED GRA
o
o
::
8
C
0
N
0
12/10/01 Gas:
12/08/01 Oil:
12/08/01 Water:
2011
2013
A
z
-
-
HIA
Year
2014
Cumulative Production
1.6 MMCI’
17.0 Mbbl
140.5 MbbI
2012
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Property : Saleski
Welt Name :LELETAL 101 120 SALESK 15-26-85-19
+
4
Solv Inj:
Water Inj
2015
2016
2018
Cumulative Injection
Steam In]
0.OMMcf
0.0 Mbbl
Gas In]
2017
Regulatory Field : Undefined
Regulatory Pool : Grosmont
Operator : Laricina Energy Ltd.
Historical Production and Injection
2D
2019
0
01
o
o
o
o
r-
a,
o
0
a:
0
01
o
a
o
a
F-
a,
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LJ
GLJ Consultants
Petroleum
20
1143197 /Jan 23. 2015
515.7MbbI
0.0 MMcf
-
o
:+:+
o
.5
0
a,
0
0
0
O
.0
-
0-
2009
2010
14/06/01 Gas:
14105/01 Oil
14/05/25 Water:
2011
2013
A
Year
2014
j
----
Cumulative Production
3,6MMcf
242Mbbl
72,7MbbI
2012
o
*_______
-.
0
0
-
Status Summary
On Production date:
On Injection date:
Statua date:
Status: STEAMASSISTED GRA
U)
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0
0
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0
0
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-
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Property : Saleski
Well Name :LELETAL 101 P3D SALES}U 14-26-85-19
Solvlnj
Water Inj
2015
-
2016
2018
Cumulative Injection
Steam Inj
0.OMMcf
0.OMbbl
Gas Inj:
2017
Regulatoiy Field : Undefined
Regulatory Pool : Grosmont
Operator : Laricina Energy Ltd.
Historical Production and Injection
3D
2019
o
a>
e
CD
o
U,
o
0
0
CS
0
CS
0
Petroleum
Consullonts
3D
/.a 23, 2015
LJ GLJ
l
194.4 Mbbl
0.OMMcf
0
0
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0
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30%
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1.8
Saleski Reserve Area Type Well Plots
•
•
—
—
Oniy
-
-
-
-
-
+
Possible Undeveloped
-
-
Possible Uvdeveloped
Possible Undeveloped
-
2
-
-
-
2.2
Petroleum
GLJ Consultants
Reserve Area Stacked -0- P90 forecast (Not Booked(
-
Reserve Area Stacked C PRO forecast (Not Booked(
-
Pad 1- Stacked D P90 forecast (Not Booked(
-
+
+
Pad;- Stacked C P90 forecast (Not 500ked(
-
Reserve Area - Stacked D - Probable
Reserve Area - Stacked - C Probable
Pad 1- Stacked -0- Probable + PossIble Undeveloped
Pad 1-Stacked C Probable
-
Reserve Area Stacked -0- Probable Undeveloped
Reserve Area -Stacked - C Probable Undeveloped
Pad 1- Stacked -0- Probable Undeveloped
Pad 1- Stacked C Probable Undeveloped
D3
D2
Dl - Cyclic
C2
Cl Cyclic Only
0
-C
UNDEFINEDGROSMONT
00/15-26-085-19W412
4
1143197
03/15-26-085-19W4/0
6 04115-26-085-19W4/2
7 05/15-26-085-19W4/0
8 06/1 5-26-085-19W4/0
9 04/15-26-085-19W4/0
10 P2D
Total
STEAMASSISTEDGRAVITY.
OSSERVATION
STEAM ASSISTED GRAVITY...
ABNDANDWIIIF
UNDEFINEDGROSMONT
UNDEFINED GROSMONT
UNDEFINEDGROSMONT
OBSERVATION
STEAMASSISTEDGRAVITY...
STEAMASSISTEDGRAVITY.,.
OBSERVATION
STEAMASSISTEDGRAVITY...
Current Status
UNDEFINEDOROSMONT
UNOEFINEDOROSMONT
00/14-26-085-19W4/0
3
5
UNDEFINEDOROSMONT
UNDEFINEDOROSMONT
UNDEFINEDGROSMONT
07/l0-26-085-19W4/0
08/10-26-0$5-19W4/0
Regulatory Field Pool
1
2
Well Location
Property: Salesld
0
19
63
0
88
62
0
30
0
0
2012-05
2012-05
2014-05
2011-01
2010-12
2012-08
2010-12
2011-01
2013-08
2014-12
2014-12
2013-11
2014-12
2014-12
2013-01
2014-12
2012-02
2014-04
2010-08
2010-03
2010-09
2010-03
2010-08
2010-09
2012-06
2014-06
2011-02
2010-12
2012-10
2012-04
2011-04
First
yr-mm
2012-03
RigRel
yr-mm
Last
yr-mm
Prod
Days
Inj
yr-mm
Production Dates
Well List and Production Summary
Table I
0
15
115
0
38
20
0
26
0
0
214
Gas
Mcf/d
7
3
0
8
0
0
44
o
7
19
o
314
187
140
476
165
GOR
scf/stb
>9999
>9999
>9999
>9999
>9999
WGR
bbl/MMcf
Last Quarter Production Statistics
Oil
bblld
WC
%
95
96
95
98
79
0
176
24
0
115
17
0
161
0
0
493
Oil
Mbbl
0
24
4
0
20
2
0
26
0
0
76
0
649
71
0
714
141
0
541
0
0
2,116
Water
Mbbl
GLJ Consultants
Petroleum
Jasuay 26,2015 16:07:02
Gas
MMcf
Cumulative Production
Page 1
Currency Date: 2014-12
C
-s
18%
24%
26%
22%
13.4
125,588
Porosity
11.6
21.5
6.2
ft
Net Pay
43630
43640
38,317
Area
(acres)
DBIIP is based upon a single mapping interpretation.
Total
GrosmontC
GrosmontD
Upper reton
Entity Description
Table 2
Volumetric Parameters Summary
Discovered Bitumen Initially-In-Place
Saleski
18%
17%
15%
30%
Sw
1,909,520
4,857128
1,088,749
7,855,397
1.005
1.005
1.005
1.005
BlIP
(MbbI)
LJ Consultants
T IPetroleum
-
-
-
-
22.4
21.6
28.3
27.3
48.0
19.3
18.5
28.3
27.3
44.7
)
Net Pay
19%
19%
24%
24%
22%
18%
18%
24%
24%
21%
Porosity
17%
17%
15%
15%
16%
17%
17%
15%
15%
16%
Sw
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
FVF
BlIP
20,550
95,709
33,857
148,652
298,769
16905
125,666
33,857
238,095
414,523
LMfl
62%
62%
58%
58%
59%
41%
40%
40%
40%
40%
Recovery
Factor
12,835
59,482
19,564
85,488
177,369
6933
50,866
13,673
95,470
166,941
fl
Gross Cease
Original
Recoverable
Reserves
12,835
59,482
19,564
85,488
177,369
6933
50,866
13,673
95,470
166,941
Gross Lease
Remaining
Recoverable
Reserves
{)
0
0
0
0
0
0
0
0
0
0
Gross Cease
Production
to
2014-12-31
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
7,701
35,689
11,739
51,293
106,422
4,160
30,519
8,204
57,282
100,165
Company
Interest
Remaining
Recoverable
Working Reserves
hiterest
M)
J GLJ
Petroleum
Consultants
Reserves are truncated by the maximum 50 year forecast in accordance with COGEH. Groas Lease Recoverable volumes of 13,727 and 108,484 Mbbl are forecast to be produced beyond 50 years and are classified as best and
high estimate contingent resources, respectively.
The economic threshold for development is 300 MbbI/CSS well.
The reserves above may not match the economic forecasts due to economic limit considerations.
Notes:
231
1114
231
1,056
1,345
Probable + PossIble Undeveloped Reserves
Grosmont C Pad I
Grosmont C Reserve Area
Grosmont D Pad 1
Grosmont D Reserve Area
Total: Probable + Possible Undeveloped Reserves
-
-
-
-
231
1,790
231
1,691
2,022
Area
Probable Undeveloped Reserves
Grosmont C Pad I
Grosmont C Reserve Area
Grosmont D Pad I
Grosmont D Reserve Area
Total: Probable Undeveloped Reserves
Entity Description
Table 2.1
Volumetric Parameters Summary
Reserves
Saleski
20
12
0
772
8,905
11,202
20
20
21
231
1,886
8,876
31,349
40,491
-
-
17.8
17.9
0.0
21.6
20.7
16.5
24.8
24.8
24.8
7.8
18.4
31.2
26.1
37.5
17.8
17.9
0.0
18.5
17.7
13.3
32.7
32.9
33.1
7.8
9.2
31.2
26.8
36.0
ft)
Net Pay
18%
18%
0%
19%
19%
19%
24%
24%
24%
26%
25%
24%
24%
23%
18%
18%
0%
18%
18%
18%
24%
24%
24%
26%
25%
24%
24%
23%
Porosity
17%
17%
0%
17%
17%
17%
15%
15%
15%
30%
20%
18%
18%
18%
17%
17%
0%
17%
17%
17%
19%
19%
19%
30%
26%
18%
18%
18%
Sw
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
FVF
BlIP
1,333
795
0
66,364
736,282
747,584
2,527
2,526
2,708
8,262
172,145
1,398,004
4,117,547
7,256,076
1,333
795
0
6,691
596,417
564,134
3,243
3.257
3,504
8,262
82,703
1,398,004
4,009,209
6,677,552
{M
62%
64%
0%
62%
62%
59%
54%
54%
54%
55%
57%
57%
54%
56%
43%
45%
0%
40%
40%
35%
36%
36%
36%
34%
36%
39%
37%
37%
Recovery
Factor
827
510
0
41,244
454,874
443,806
1,367
1,366
1,465
4,514
97,416
790,874
2,231,530
4,069,794
578
357
0
2,708
237,598
198,704
1,156
1,160
1,248
2,833
29,952
540,290
1,468,558
2,485,142
Gross Lease
Original
Recoverable
Resources
161
176
0
0
0
0
115
17
24
0
0
0
0
493
161
176
0
0
0
0
115
17
24
0
0
0
0
493
Gross Lease
Production
to
2014-12-31
666
333
0
41,244
454,874
443,806
1,252
1,349
1,441
4,514
97,416
790,874
2231,530
4,069,300
417
181
0
2,708
237,598
198,704
1,041
1,143
1,224
2,833
29,952
540,290
1,468,558
2,484,649
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
LI] GLJ
Petroleum
Consultants
400
200
0
24,746
272,924
266,284
751
809
865
2,709
58,450
474,525
1,338,918
2,441,580
250
108
0
1,625
142,559
119,223
625
686
734
1,700
17,971
324,174
881,135
1,490,789
Company
Gross Lease
Interest
Remaining
Recoverable
Recoverable
Resources Working Resources
Interest
1MII
Notes:
‘Reserves are truncated by the maximum 50 year forecast in accordance with COGEH. Recoverable volumes forecast to be produced beyond 50 years are classified as contingent resources.
2
Reserves are truncated by the maximum 50 year forecast in accordance with COGEH. Recoverable volumes forecast to be produced beyond 50 years are classified as contingent resources.
The economic threshold for development is 300 Mbbl/CSS well.
The recoverable resources above may not match the economic forecasts due to economic limit considerations.
Low estimate contingent resources were found to be uneconomic and are assessed to be zero.
The contingent resources have not been risked for the chance of development.
-
-
-
High Estimate Contingent Resources
PlC
P2C
Grosmont C Pad 1
GrosmontC-ReserveArea’
GrosmontC-Phase2
GrosmontC-Remaining
P1D
12D (Producer)
P3D
Grosmont 0 & Ireton Pad 1
GrosmontD&lreton-ReserveArea2
Grosmont D & Ireton Phase 2
GrosmontD&lreton-Remaining
Total: High Estimate Contingent
-
-
-
20
12
0
95
8,905
11202
20
20
21
231
1,886
8,876
29,709
36,933
Area
g)
Best Estimate Contingent Resources
PlC
P2C
Grosmont C Pad 1
GrosmontC-ReserveArea’
GrosmontC-Phase2
Grosmont C Remaining
P10
20 (Producer)
P30
Ireton Pad 1
Grosmont 0 & Ireton Reserve Area2
GrosmontD&lreton-Phase2
Grosmont D & Ireton Remaining
Total: Best Estimate ContIngent
Entity Description
Table 2.2
Volumetric Parameters Summary
Contingent Resources
Saloski
Page: 72 of 141
Table 3
THERMAL PROJECT
TYPE WELL FORECAST
Padi -Stacked-D
Probable Undeveloped
Type Curve #2
Pad I -Stacked-C
Probable Undeveloped
Type Curve #7
Sleamilood Recovery
SteamSood Area
Well Spacing
Well Length
Single Welt Drainage Area
Net Pay
Number of Wells Required
Peak Rate per Well
-
867
231
120
925
289
19.3
8
410
Mbbl per well
Acres
Metres
Metres
Acres
Metres
Welts
bbUd *
Includes 25m of drainage at each end of the well
855
231
60
925
14 5
28.3
16
240
Steamflood Recovery
Steamilood Atea
Well Spacing
Well Levgth
Single Well Drainage Area
Net Pay
Number of Wells Required
Peak Rate per Well
*
-
Includes 25m of drainage at each end of Ihe well
Type Well Production Profile
Type Welt Production Profile
wnnuai reverages
Annual wverages
Year
Oil
Rate
bblld
Yearly
SOR
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
205
410
410
394
301
221
162
119
88
84
0
0
0
0
0
Totals
867
Year
Oil
Rate
bblld
Yearly
SOR
WOR
Steam
Injection
bblld
876
1752
1752
1767
1417
1093
843
651
502
387
0
0
0
0
0
I
2
3
4
5
6
7
8
9
10
11
12
13
14
15
30
150
240
239
224
204
165
169
153
139
127
115
105
95
87
2.4
2.4
2.4
2.5
2.6
2.8
2.9
3,0
3.2
3.3
3.5
3.7
3.9
4,1
4.3
2.4
2,4
2.4
2.5
2.6
2.8
2.9
3.0
3.2
3.3
3,5
3.7
3.9
4.1
4.3
71
357
571
599
589
562
536
512
489
467
446
425
406
388
370
4030
Totals
865
3.0
3.0
2606
WOR
Steam
Injection
bblld
4,3
4.3
4.3
4.5
4.7
4,9
5.2
5.5
5.7
6,0
0,0
0.0
9.0
0.0
0.0
4.3
4.3
4.3
4.5
4.7
4.9
5.2
5.5
5.7
6,0
0.0
0.0
0.0
0.0
0,0
4.6
4.6
Reserve Area Stacked D
Probable undeveloped
Type Curve #4
Reserve Area- Stacked C
Probable Undeveloped
Type Curve #3
-
-
-
Sleamfood Recovery
878
MbbI par well
Stnamfsod Recovery
860
Steamf cod Area
Well Spacing
Wail Length
Single Well Drainage Area
Nat Pay
Number of Wells Required
Peak Rale per Wail
1066
120
1000
31.1
18.5
61
430
Acres
Metres
Metres
Acres Metres
Wells
bbud •
Steavifood Area
Well Spacing
Wall Length
Single Well Drainage Area
Net Pay
Number of Wells Required
PeSk Rate per Well
1606
60
1000
15.6
27,3
127
250
-
Mbbl perwell
Acres
Metres
Metres
Acres
Metres
Wells
bbl!d *
Includes 25w of drainage at each end of the well
-
-
.
Mbbl per well
Acres
Metres
Metres
Acres
Metres
Walls
bblid
Includes 25m of drainage at each end of Ihe well
Type Well Production Profile
Type Well Production Profile
Year
Oil
Rate
bbl!d
Yearly
SOR
WOR
Oteam
InjectIon
bblld
Year
Oil
Rate
bblld
Yearly
SOR
WOR
oteam
Injection
bblld
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
215
430
430
413
313
228
167
122
89
0
0
0
0
0
0
4.3
4.3
4.3
4.5
4.8
5.0
5.2
5.5
5.8
0.0
0.0
0.0
0.0
0.0
0.0
4,3
4.3
4.3
4.5
4.8
5.0
5.2
5.5
5.8
0.0
0.0
0.0
0.0
0.0
0.0
927
1854
1854
1866
1488
1140
874
669
513
0
0
0
0
0
0
1
2
3
4
5
6
7
8
9
10
II
12
13
14
15
125
250
250
241
279
198
180
163
148
134
121
110
100
91
82
2.2
2.2
2.2
2.3
2.5
2,6
2.7
2.5
3.0
3.1
3.3
3.5
3,6
3.8
4.0
2.2
2.2
2.2
2.3
2.5
2.6
2.7
2.8
3.0
3.7
3,3
3.5
3.6
3.8
4.0
278
557
557
564
537
517
487
463
441
420
400
381
362
345
328
Totals
878
4.6
6.6
4084
Totals
880
2.7
2.7
2420
L
Petroleum
GLJ Consultants
Page: 73 of 141
Table 3
THERMAL PROJECT
TYPE WELL FORECAST
Pad 1-Stacked-C
Probable + Possible Undeveloped
Type Curve #5
Sleamilood Recovery
Steamilood Area
Well Spacing
Well Length
Single Well Drainage Area
Net Pay
Number of Wells Required
Peak Rate per Well
-
1604
231
120
925
289
224
9
520
Pad 1-Stacked-D
Probable + Possible Undeveloped
Type Curve #6
Mbbl per welt
Acres
Metres
Metres
Acres *
Metres
Wells
bbUd
Includes 25m of drainage at each end of the well
Sleamfood Recovery
Sleamfuod Area
Well Spacing
Well Length
Single Well Drainage Area
Net Pay
Number of Wells Required
Peak Rate per Well
-
Type Well Production Profile
Includes 25m of drainage al each end of the well
Year
Oil
Rate
bbtid
Yearly
SOR
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
260
520
520
520
520
520
477
347
246
178
128
92
66
0
0
0
0
0
0
0
3.7
3.7
3.7
3.7
3.7
3.7
3.8
3.9
4.0
41
4.2
4.3
4.4
0.0
0.0
0.0
00
0.0
00
0.0
Totals
1604
3.8
Annual Averages
Year
Oil
Rate
bblld
Yearly
SOR
WOR
Steam
Injection
bblid
962
1924
1924
1924
1924
1924
1810
1348
990
727
534
393
288
0
0
0
0
0
0
0
2
3
4
5
6
7
8
9
10
ii
12
13
14
15
16
17
18
19
20
39
194
310
310
310
300
270
241
216
193
173
155
135
124
111
99
89
79
0
0
2.3
2.3
2.3
2.3
2.3
2.4
2.4
2.5
2.6
2.6
2.7
2.6
2.8
2.9
3.0
3.0
3.1
3.2
0.0
0.0
2,3
2.3
2.3
2.3
2.3
2.4
2.4
2.5
2.6
2.6
2.7
2.8
2.8
2.9
3.0
3.0
3.1
32
0.0
0.0
90
450
720
720
720
715
658
603
553
508
465
427
391
359
329
302
277
254
0
0
6985
Totals
1223
2.5
2.5
3118
WOR
Steam
Injection
bblld
3,7
3.7
3.7
3.7
3.7
3.7
3.8
3.9
4.0
4,1
4.2
4.3
4.4
0.0
0.0
0.0
0.0
0.0
0.0
0.0
3.8
Reserve Area Stacked C
Probable + Possible Undeveloped
Type Curve #7
-
Steamilnod Recovery
Sleamf pod Area
Well Spacing
Well Length
Single Well Drainage Area
Net Pay
Number of Wells Required
Peak Rate per Well
-
MbbI per well
Acres
Metres
Metres
Acres•
Metres
Wells
bhl/d
Type Well Production Profile
Annual Averages
*
1223
231
60
925
14.5
28.3
16
310
Reserve Area Stacked .0
Probable + Possible Undeveloped
Type Curve #8
-
1651
1886
120
1000
31.1
21.6
61
550
-
MbbI per well
Acres
Metres
Metres
Acres *
Metres
Wells
bbird
Includes 25w of drainage at each end of the well
Sleamfiond Recovery
Sleamfood Area
Well Spacing
Well Length
Single Well Drainage Area
Nel Pay
Number of Wells Required
Peak Rate par Well
-
Type Well Production Profile
1262
1886
60
1000
15.6
27.3
121
330
MbbI per well
Acres
Metres
Metres
Acres
Metres
Wells
bb7d
Includes 25m of draInage at each end of the well
Type Well Production Profile
Annual Averages
Annual Averages
Year
Oil
Rate
bblld
Yearly
SOR
WOR
1
2
3
4
5
6
7
6
9
10
11
12
13
14
15
16
17
18
19
20
275
550
550
550
5511
550
502
358
251
177
124
87
0
0
0
0
0
0
0
0
3.7
3.7
3.7
3.7
3.7
3.7
3.8
3.9
4.0
4.1
4.2
4.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
3.7
3.7
3.7
3.7
3.7
3.7
3.5
3.9
4.0
4.1
4.2
4.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
00
1023
2045
2045
2045
2045
2045
1915
1398
1007
725
522
376
0
0
0
0
Totals
1651
3.8
3.8
Year
Oil
Rate
bbt!d
Yearly
5CR
WOR
165
330
330
317
288
261
237
215
195
177
161
146
133
121
109
99
90
82
0
0
1.9
1.9
1.9
2.0
2.0
2.1
2.1
2.2
2.3
2.3
2.4
2.4
2.5
2.6
2.6
2.7
2.7
2.8
00
0.0
1.9
1.9
1.5
2.0
2.0
2.1
2.1
2.2
2.3
2.3
2.4
24
2.5
2.6
2.6
2.7
2.7
2.8
0.0
0.0
321
641
641
631
588
547
5119
474
441
410
382
355
330
308
286
266
248
231
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
6275
Totals
1262
2.2
2.2
2777
Steam
Injection
bbtld
Steam
Injection
bbUd
Iii] GLJ
Petroleum
Consultants
Page: 74 of 141
Table 3
THERMAL PROJECT
TYPE WELL FORECAST
Pilot INt’l -D
Best Estimate Contingent Resources
Type Curve #25
Pilot WPI C
Best Estimate Contingent Resources
Type Curve #24
-
578
20
90
800
18.9
17.8
1
170
Sleam600d Recovery
Sleamifood Area
Well SpacIng
Well Length
Single Well Drainage Area
Net Pay
Number of Wells Required
Peak Rule per Well
Mbbl per well
Acres
Metres
Metres
Acres *
Metres
Wells
bbPd
*_lnctudes 25m of drainage ul each end of the well
Sleamilood Recovery
Sleamilood Area
Well Spacing
Well Length
Single Well Drainage Area
Net Pay
Number of Wells Required
Peak Rate per Well
-
Includes 25m of drainage at each end of ihe well
Annual Averages
Annual Averages
WOR
Steam
Injection
tiMid
5.0
5.3
5.5
5.8
6.1
6.4
6.7
7,0
7.4
0.0
0.0
0.0
0.0
0.0
0.0
5.0
5.3
5.5
5.8
6.1
6.4
6.7
7.0
7.4
0.0
0,0
0.0
0.0
0.0
0,0
6.0
6.0
Year
Oil
Rate
bbtld
Yearly
SOR
2015
2018
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
170
162
148
135
123
112
107
97
89
0
0
0
0
0
0
Totals
417
Year
Oil
Rate
bblld
Yearly
SOR
WaR
Steam
Injection
bblld
850
852
815
779
746
713
715
684
654
0
0
0
0
0
0
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
200
200
200
200
200
108
195
192
189
186
164
161
178
175
173
5.0
5,0
5.0
5.0
5.0
5.3
5.5
5,8
6.1
6,4
6.7
7.0
7.4
7.8
8.1
5.0
5.0
5.0
5.0
5.0
5.3
5.5
5.8
6.1
6.4
6.7
7.0
7.4
7.6
8.1
1000
1000
1000
1000
1000
1042
1077
1114
1151
1190
1230
1272
1315
1359
1405
2465
Totals
1041
6.0
6.0
6262
Pilot WP2 D
Best Estimate Contingent Resources
Type Curve #27
Pilot WP2-C
Best Estimate Contingent Resources
Type Curve #26
-
MbN per well
Acres
Metres
Metres
Acres
Metres
Wells
bbvd *
Type Welt Production Profile
Type Well Production Profile
Steamfioud Recovery
Steumfivod Area
Well Spacing
Well Length
Single Well Drainage Area
Net Pay
Number of Wells Requirnd
Peak Rate per Well
1150
20
90
800
18.9
32.7
1
210
.
357
12
90
450
1 1.1
17.9
1
190
-
Mbbl per well
Acres
Metros
Metres
Acres *
Metres
Wells
bbtrd
includes 25m of drainage at each end of the well
Sleamfood Recovery
Sleamfiood Area
Well Spacing
Well Length
Single Well Drainage Area
Net Pay
Number of Wells Required
Peak Rate per Well
-
1160
20
90
800
189
32.9
1
210
MbbI per well
Acres
Metres
Metres
Acres*
Melres
Wells
bblld
Includes 25m of drainage at each end 01 the well
Type Well Production Profile
Type Well Production Profile
Annual Averages
Year
Oil
Rate
bbtld
Yearly
SOR
WOR
Steam
Injection
obtld
Year
Oil
Rate
bblid
Yearly
SOR
WOR
Steam
Injection
bblld
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
180
137
98
71
0
0
0
0
0
0
0
0
0
0
0
0
6.0
6.3
6.6
6.9
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
6.0
6.3
6.6
6.9
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1140
860
649
480
0
0
0
0
0
0
0
0
0
0
0
0
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
130
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
4.9
5.1
5.1
5.1
5.1
5.1
5,4
5.7
6.0
6.3
6.6
6.9
7.2
7.8
8.0
8.4
4.9
5.1
5.1
5.1
5.1
5.1
5.4
5.7
6.0
6.3
6.6
6.6
7.2
7.6
8.0
8.4
637
1029
1029
1029
1029
1029
1081
1135
1192
1252
1314
1381
1450
1523
1509
1660
Totals
181
6.3
6.3
1146
Totals
1143
6.2
6.2
7076
Lrj GLJ
Petroleum
Consultants
Page: 75 of 141
Table 3
THERMAL PROJECT
TYPE WELL FORECAST
Pilot WP3 -0
Best Estimate Contingent Resources
Type Curve #28
Steamilood Recovery
Steam1100d Area
Well Spacing
Well Length
Single Well Drainage Area
NetPay
Number of Wells RequIred
Peak Rate per Well
-
1246
21
00
800
18.9
33.1
1
210
2P
Mbbl perwell
Acres
Metres
Metres
Acres
Metres
Wells
bblid •
Padi -Stacked-C
Best Estimate Contingent Resources
Type Curve #29
Sleam1100d Recovery
Steamfood Area
Well SpacIng
Well Length
Single Well DraInage Area
NelPay
Number of Wells RequIred
Peak Rate per Well
Includes 25m of drainage at each end of the well
-
Type Well Production Profile
+
Year
Yearly
SOR
bblid
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
105
210
210
210
219
210
210
210
210
210
210
192
176
161
147
134
123
112
103
0
Totals
1224
Annual Averages
WOR
Steam
Injection
bblld
4.5
4.5
4.5
4.5
4,5
4.5
4.5
4.5
4.5
4.5
4.5
4.7
5.0
5.2
5.5
5.7
6.0
6.3
6.6
3.5
4.5
4.5
4.5
4.5
4.5
4.5
4,5
4.5
4.5
4.5
4.5
4.7
5.0
5.2
5.5
5.7
6.0
6.3
6.6
3.5
Year
Oil
Rate
bbUd
Yearly
SOR
WOR
Steam
Injection
bblId
473
945
945
945
945
945
945
945
945
945
945
908
872
837
804
772
742
712
684
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
205
410
410
364
301
221
162
119
88
64
0
0
0
0
0
0
0
0
0
0
4.3
4.3
4.3
4.5
4.7
4.9
5.2
5.5
5.7
6.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
4.3
4.3
4.3
4.5
4.7
4.9
5,2
5.5
5.7
6.0
0.0
0.0
0.0
0.0
0,0
0.0
0.0
0.0
0.0
0.0
876
1752
1752
1767
1417
1093
843
651
502
387
0
0
0
0
0
0
0
0
0
0
4.8
4.8
6932
Totals
897
4.6
4.6
4030
Pad I -Stacked-D
Best Estimate Contingent Resources
Type Curve #30
Sleamf sod Recovery
Sleamf sod Area
Well Spacing
Well Length
Single Well Drainage Area
Net Pay
Number of Wells Required
Peak Rate per Well
-
Wells
Includes 25m of drainage at each end of the well
Annual Averages
+
Mbbl perwell
Acres
Metres
Metres
Acres
Metres
Type Well Production Profile
OIl
Rate
bblld
2P
867
231
120
925
28.9
19.3
8
410
1032
231
60
925
14.5
36,2
16
260
Reserve Area Stacked - C
Best Estimate Contingent Resources
Type Curve #37
-
2P +
Mbbl per Well
Acres
Metres
Metres
Acres
Metres
Wells
bbUd *
Includes 25m of drainage at each end of the well
Steamilood Recovery
Steumfood Area
Well Spacing
Well Len9th
Single Well Drainage Area
Net Pay
Number of Wells Required
Peak Rate per Well
*
Type Well Production Protile
-
878
1886
120
1000
31.1
10.5
61
430
Mbbl per well
Acres
Metres
Metres
Acres
Metres
Wells
bbl/d *
Includes 25m of drainage at each end of the well
Type Well Production Profily
Annual Avemoes
Year
OtI
Rate
bbUd
Yearly
SOR
WaR
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
33
163
260
260
260
258
236
211
189
170
152
137
123
110
99
88
79
0
0
0
2.5
2.5
2.5
2.5
2.5
2,6
2.8
2.9
3.0
3.2
3.3
3,5
3.7
3.9
4.1
4.3
4,5
0.0
0.0
0.0
2.5
2,5
2.5
2.5
2.5
2.6
2.8
2,9
3.0
3.2
3.3
3.5
3.7
3.9
4.1
4.3
4.5
0.0
0.0
0.0
Totals
1032
3.0
3.0
Steam
Injection
bblld
Year
Oil
Rate
bbWd
Yearly
SOR
WOR
81
405
649
649
649
675
648
610
574
541
505
480
452
425
400
377
355
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
215
430
430
413
313
228
167
122
89
0
0
0
0
0
0
0
0
0
0
0
4.3
4.3
4.3
4.5
4.8
5.0
5.2
5.5
5.8
0.0
0.0
0.0
0.0
0.0
0.0
0,0
0.0
0.0
0.0
0.0
4.3
4.3
4.3
4,5
4.8
5,0
5.2
5.5
5.8
0.0
0,0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
927
1854
1854
1868
1488
1140
874
669
513
0
0
3095
Totals
876
4.6
4.6
4084
‘
Steam
Injection
bblld
0
0
C
GLJ Petroleum
Consultants
Page: 76 at 141
Table 3
THERMAL PROJECT
TYPE WELL FORECAST
+
Phase 2- Stacked C
Best Estimate Contingent ResoOrces
Type Curve #33
Reserve Area Stacked D
Best Estimate Contingent Resources
Type Curve #32
-
2P
-
-
1037
1886
60
1000
15.6
33.7
121
270
Sleam000d Recoveiy
Steamfiond Area
Well Spacing
Well Length
Single Well Drainage Area
Net Pay
Number of Wells Required
Peak Rate per Well
Mbbl per well
Acres
MIres
Metres
Acres
Metres
Wells
bbl/d *
Includes 25m of drainage at each end of the well
Steamflood Recovery
Sleamfiond Area
Well Spacing
Well Length
‘Single Well Drainage Area
Net Pay
Number of Wells Required
Peak Rate per Well
*
-
831
8905
120
1000
31.1
17.7
286
420
Mbbl per well
Acres
Metres
Metres
Acres
Metres
Wells
hOOd *
Includes 25m of drainage at each end of the well
Type Well Prpductlon Profile
Type Well Production Profile
Annual Averages
Year
Oil
Rate
bblld
Yearly
SOR
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
135
270
270
270
268
245
219
195
174
155
139
124
111
99
88
79
0
0
0
0
2.3
2.3
2,3
2.3
2.4
2.5
2.6
2.8
2.9
3.1
3.2
3.4
3.5
3.7
3.9
4.1
0.0
0.0
0.0
0.0
Totals
1037
2.7
Annual Averages
WOR
Steam
Injection
bblld
Year
Oil
Rate
bbtid
Yearly
SOR
WOR
Steam
Injection
bblld
2.3
2,3
2.3
2.3
2.4
2.5
2.6
2.8
2.9
3.1
3.2
3.4
3,5
3,7
3.9
4.1
0.0
0.0
0.0
0.0
308
616
616
616
642
616
578
541
507
476
446
418
392
367
344
322
0
0
0
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
210
420
420
401
295
208
146
103
73
0
0
0
0
0
0
0
0
0
0
0
3.8
3.8
3.8
4.0
4.2
4.4
4.6
4.9
5.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
3.8
3.8
3.8
4.0
4.2
4.4
4.6
4.9
5.1
0.0
0.0
0.0
0.0
0.0
0.0
Ô.0
0.0
0.0
0.0
0.0
002
1604
1604
1609
1242
919
679
502
371
0
0
0
0
0
0
0
0
0
0
0
2.75
2849
Totals
831
4.1
4.10
3406
RemaInIng Stacked - C
Best Estimate Contingent Resources
Type Curve #36
Phase 2- Stacked D
Best EstImate Contingent Resources
Type Curve #34
-
940
8876
60
1000
15.6
31.2
570
260
Steamfiood Recnvery
Sleamfivod Area
Well Spocing
Well Length
Single Well Drainage Area
NelPay
Number of Wells Required
Peak Rate per Well
-
Mbbl perwell
Acres
Metres
Metres
Acres *
Metres
Wells
hhl/d •
.lncludes 25w of drainage at each end of the well
Sleamfioud Recovery
Sleamilood Area
Wet Spacing
Well Length
Single Well Drainage Area
NetPay
Number of Wells Required
Peak Rate per Well
-
553
10958
120
1000
31.1
13.3
352
360
MOM per well
Acres
Metres
Metres
Acres *
Metres
Wells
bhUd
Includes 25m of draiCage at each end of the well
Type Welt Producfion Profile
Type Well Production Profile
ennuai averages
annuai averages
Year
Oil
Rate
bblld
Yearly
SOR
WOR
Steam
Injection
bblld
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
130
260
260
256
236
214
195
170
162
147
134
122
111
101
02
Totals
949
Year
Oil
Rate
bblld
Yearly
SOR
WOR
Steam
Injection
bblld
2.0
2,0
2.0
2.1
2,2
2.3
2.4
2.6
2.7
2.8
3.0
3.1
3.3
3.4
3.6
2.0
10
2.0
2.1
2.2
2.3
2.4
2.6
2.7
2.8
3.0
3.1
3.3
3.4
3.6
262
524
524
542
523
500
478
456
436
417
398
380
363
347
332
I
2
3
4
5
6
7
8
9
10
ii
12
13
14
15
180
360
360
241
158
103
68
44
0
0
0
0
0
0
0
4.6
4.6
4.6
4.8
5.1
5.3
5.6
5.9
0.0
0.0
0.0
0.0
0.0
0.0
0.0
4.6
4.6
4.6
4.8
5.1
5.3
5.6
5.9
0.0
0.0
0.0
0.0
0.0
0.0
0.0
825
1650
1650
1161
798
549
377
259
0
0
0
0
0
0
0
2.5
2,5
2368
Totals
553
4.8
4.80
2664
L
GLJbom
Consultants
Page: 77 nfl 41
Table 3
THERMAL PROJECT
TYPE WELL FORECAST
RemaIning Stacked -0
Best Estimate Contingent Resources
Type Curve #37
Remaining C Only
Best Estimate Contingent Resources
Type Curve #38
-
Steamilood Recovery
Steamilood Area
Well Spacing
Well Length
Single Well Drainage Area
Net Pay
Number of Wells Required
Peak Rate per Welt
-
736
10958
60
1000
15.6
25.4
704
230
-
Mbbl per well
Acres
Metres
Metres
Acres’
Metres
Wells
bbird *
Includes 25m of drainage at each end of the well
Steamflood Recovery
Steamflood Area
Well Spacing
Well Length
Single Well Drainage Area
Net Pay
Namber of Wells Required
Peak Rate per Well
-
Type Well Production Profile
514
244
120
1000
31.1
12.9
8
350
Mbbl perwell
Acres
Metres
Metres
Acres *
Metres
Wells
bblid *
Includes 25m of drainage at each end of the well
Type Well ProductIon Profile
Annual Averages
Year
Oil
Rate
bbtld
Yearty
SOR
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
115
230
230
217
196
178
161
146
132
119
106
68
88
0
0
Totals
736
Annual Averages
Year
Oil
Rate
bblld
Yearly
SOR
WOR
Steam
Injection
bblld
246
492
492
487
463
440
418
397
377
359
341
324
308
0
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
175
350
350
230
148
85
61
0
0
0
8
0
0
0
0
5.8
5.8
5.8
6.1
6.4
6.7
7.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
5.8
5.8
5.8
6.1
6.4
6.7
7.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1019
2038
2038
1407
948
835
430
0
0
0
0
0
0
0
0
1877
Totals
514
6.0
6.0
3110
WOR
Steam
Injection
bbtld
2.1
2.1
2.1
2.2
2.4
2.5
2.6
2.7
2.9
3.0
3.2
3.3
3.5
0.0
0.0
2.1
2.1
2.1
2.2
2.4
2.5
2.6
2.7
2.9
3.0
32
3.3
3.5
0.0
0.0
2.5
2.5
Remaining -0 Only
Best Estimate Con8ngent Resources
Type Curve #39
Steamf 004 Recovery
Steamfiood Area
Well Spacing
Well Length
Single Well Drainage Area
Net Pay
Number of Wells Required
Peak Rate per Well
789
18752
60
1000
15.6
27.6
1205
240
Pilot WPI C
High Estimate Contingent Resources
Type Curve #40
-
Mbbl per well
Acres
Metres
Metres
Acres’
Metres
Wells
bb9d’
‘-Includes 25m of draInage at each end of the well
Steamf 004 Recovery
Sleamflood Area
Well Spacing
Well Length
Single Well Drainage Area
Net Pay
Number of Wells Required
Peak Rate per Well
-
Type Well ProductIon Profile
827
20
90
600
18.9
17.8
1
350
Mbbl per well
Acres
Metres
Melres
Acres’
Metres
Wells
bblld’
Includes 25w of drainage at each end of the well
Type Well Production Profile
Annual Averages
Year
OIl
Rate
bblld
Yearly
SOR
1
2
3
4
5
6
7
8
8
10
11
12
13
14
15
120
240
240
226
204
184
166
149
135
121
109
99
59
80
0
Totals
789
Annual Averages
Year
OIl
Rate
bblId
Yearly
SOR
WOR
Steam
Injection
bblld
348
695
695
687
650
615
583
552
522
495
468
443
420
397
0
2015
2016
2017
2018
2016
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
185
380
390
287
211
155
114
84
0
0
0
0
0
0
0
4.0
4.0
4.0
4.1
42
4.3
4.4
4.5
0.0
0.0
0.0
0.0
0.0
0.0
0.0
4.0
4.0
4.0
4.1
4.2
4,3
4.4
4.5
0.0
8.0
0.0
0.0
00
0.0
0.0
780
1560
1560
1175
885
667
502
378
0
0
0
0
0
0
0
2763
Totals
666
4.1
4.1
2740
WOR
Steam
InjectIon
bblld
2.9
2.9
2.9
3.0
32
3.4
3.5
3.7
3.9
4.1
4.3
4.5
4.7
5.0
0.0
2.9
2.9
2.9
3.0
3.2
3.4
3.5
3.7
3.9
4.1
4.3
4.5
4.7
5.0
0.0
3.5
3.5
LIiI GLJ
Petroleum
Consultants
Page: 78 of 141
Tab’e 3
THERMAL PROJECT
TYPE WELL FORECAST
Pilot WP2 C
High EstImate Contingent Resources
Te Curve #42
Pilot WPI -D
Htgh Estimate Contingent Resources
Type Curve #47
1367
20
90
800
18,9
24.8
1
250
Steamtlood Recovery
Steamflood Area
Well Spacing
Well Length
SinglO Well Drainage Area
Net Pay
Number of Wells Required
Peak Rate per Well
-
Mbbl perwelt
Acres
Metres
Metres
Acres
Metres
Wells
bblid *
510
12
90
450
11.1
17.9
I
220
Steamfood Recovery
Steamfood Area
Wall Spacing
Wet Length
Single Well Drainage Area
Net Pay
Number of Wells Required
Peak Rate per Well
* Includes 25m of drainage at each end of the well
*
Type Well Production Profile
Type Well Production Profile
-
-
Includes 25m of drainage at each end of the well
Annual Averaoes
Annual Averages
-
Year
Oil
Rate
bblId
Yearly
SOR
WOR
Steam
Injection
bblld
844
563
769
769
769
782
788
785
801
608
815
821
828
835
842
2015
2816
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
220
220
169
129
99
76
0
0
0
0
0
0
0
0
0
0
5.0
5.0
5,1
5.3
5.4
5.5
0,0
0.0
00
0.0
0.0
0.0
0,0
0,0
0.0
0.0
5.0
5.0
5.1
5.3
5.4
5.5
0.0
0.0
0.0
0.0
0.0
0,0
0.0
0.0
0.0
0.0
1100
1100
865
680
534
420
0
0
0
0
0
0
0
0
0
0
4317
Totals
333
5.1
5.1
1715
Year
Oil
Rate
bblld
Yearly
5CR
WOR
Steam
Injection
bblld
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
188
188
250
250
250
248
244
248
236
232
228
225
221
217
214
4.5
3.0
3.1
3.1
3.1
3.2
3.2
3.3
3,4
3.5
3.6
3.7
3.7
3,8
3.9
4.5
3,0
3.1
3,1
3.1
3,2
3.2
3,3
3.4
3.5
3.6
3.7
3.7
3.8
3,9
Totals
1252
3.4
3.4
PIlot WP3 D
HIgh EstImate Contingent Resources
Typo Curve #44
Pilot WP2 - P
High Estimate Contingent Resources
Type Curie #43
1366
20
90
800
18.9
24,8
1
250
Sleamfood Recovery
Sleamfnod Area
Well Spacing
Well Length
Single Well Drainage Area
Net Pay
Number of Wells Required
Peak Rate per Well
*
-
-
MbbI per well
Acres
Metres
Metres
Acres *
Metres
Wells
bbud *
Includes 25m of drainage at each end of the welt
1465
21
90
800
18.9
24.8
1
250
Sleamilood Recovery
Steamfiond Area
Well Spacing
Well Length
Single Well Drainage Area
Net Pay
Number of Wells Requited
Peak Rate per Well
-
Mbbl perwelt
Acres
Mytres
Metres
Acres
Metres
Wells
bblid
Includes 25m of drainage et each end of the well
Type Well Production Profile
Type Well Production Profile
Annual suerages
Annual Averages
-
Mbbl perwetl
Acres
Metres
Metres
Acres *
Metres
Wells
bblid *
Year
Oil
Rate
bblld
Yearly
SOR
WOR
Steam
Injection
bbtid
525
718
718
919
919
919
938
953
969
585
1001
1017
1033
1050
1067
1085
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
156
198
188
250
245
239
234
229
224
219
215
210
206
201
197
193
189
185
181
4.2
4,2
42
4.2
4.2
4.2
4.2
4.2
4,2
4.2
4,3
4.4
4.5
4.6
4.9
4.9
5.0
5.1
5.2
4.2
4.2
4.2
4,2
4,2
4.2
4.2
4.2
4,2
4.2
4,3
4.4
4.5
4.6
4.8
4.9
5.0
5.1
5.2
656
788
788
1050
1027
1005
984
963
942
922
925
927
930
933
936
939
941
944
947
5408
Totals
1441
4.4
4.4
6494
Year
OIl
Rate
bbltd
Yearly
SOR
WOR
Steam
Injection
bblld
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
150
200
200
250
250
250
249
247
245
243
241
238
236
234
232
230
3.5
3.6
3.6
3.7
3.7
3.7
3.8
3.9
4.0
4.1
4.2
4.3
4.4
4.5
4,6
4.7
3.5
3.6
3.6
3.7
3.7
3.7
3.8
3.9
4.0
4.1
4.2
4.3
4.4
4.5
4.6
4.7
Totals
1349
4.0
4.0
L
GLJ Petroleum
Consultonts
Page: 79 of 141
Table 3
THERMAL PROJECT
TYPE WELL FORECAST
3P
+
Pad 1-Stacked-C
High Estimate Contingent Resources
Type Curve #45
3P
Peril -Stacked-D
High Estimate Contingent Resources
Type Curve #46
+
Steamilood Recovery
1604
Mbbl per well
Steamfoud Recovery
1505
Steamilood Area
231
Acres
Steamflood Area
231
Well Spadvg
Well Length
Single Well Drainage Area
Net Pay
Number of Wells Required
Peak Rate per Well
120
925
26.9
22.4
8
520
Metres
Metres
Acres
Metres
VArlls
bbtid •
Well Spacing
Well Length
Single Well Drainage Area
Net Pay
Number of Wells Required
Peak Rate per Well
60
925
14.5
36.2
16
300
*
-
Includes 25m of drainage at each end 01 the well
-
Type Well Production ProfIle
Includes 25m of drainage at each end of the well
Type Welt Production Profile
Annual Averages
Ott
Rate
bblld
Yearly
SOR
8
9
10
11
12
13
14
15
16
17
18
19
20
260
520
520
520
520
520
476
343
244
174
123
88
87
0
0
0
0
0
0
0
Totals
1684
Year
1
2
3
4
5
6
7
Annual Averages
WOR
Steam
Injection
bblld
3.6
3.6
3,6
3.6
3.6
3.6
3.7
3.8
3.9
4.0
4.1
4.2
4.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
3,6
3.6
3.6
3.6
3.6
3.6
3.7
3.8
3.9
4.0
4.1
4.2
4.3
0.0
0.0
0.0
0.0
0.0
0,0
0.0
3.7
3.7
Year
Oil
Rate
bblld
Yearly
SOR
WOR
Steam
Injection
bbl!d
936
1872
1872
1872
1872
1872
1758
1299
947
690
503
367
372
0
0
0
0
0
0
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
38
186
300
300
300
300
300
300
300
279
247
219
194
172
152
135
119
105
93
83
2.3
2.3
2.3
2.3
2.3
2.3
2.3
2.4
2,5
2.5
2.6
2.7
2.7
2.8
2.9
2.9
3.0
3.1
3.2
3.2
2.3
2.3
2.3
2.3
2.3
2.3
2,3
2.4
2.5
2.5
2.6
2.7
2.7
2.8
2.9
2.9
3.0
3.1
3.2
3.2
88
440
704
704
704
704
704
721
739
706
641
581
528
479
434
394
356
325
295
267
5925
Totals
1505
2.5
2.5
3838
Reseree Area Stacked - C
High Estimate Contingent Resources
-
3P
+
Reserve Area Stacked -0
High Estimate Contingent Resources
-
3P
+
Type Curve #47
Slaum1100d Recovery
Steamilood Area
Well Spacing
Well Length
Single Well Drainage Area
Net Pay
Numberof Wells Required
Peak Rate per Well
*
-
Mbbl per well
Acres
Metres
Metres
Acres *
Metres
Wells
bbtid
Type Curve #48
1651
1886
120
1000
31.1
21.6
61
550
Mbbl perwell
Acres
Metres
Metres
Acres *
Metres
Wells
bblld *
Includes 25m of draInage at each end of the well
‘
Steamilond Recovery
Steamfinod Area
Well Spacing
Well Length
Single Well Drainage Area
Net Pay
Numberof Wells Required
Peak Rate per Well
*
-
Type Well Production Profile
1512
1886
60
1000
15.6
33.7
121
310
Mbbl perwell
Acres
Metres
Metres
Acres *
Metres
Wells
bb6d
Includes 25w of drainage at each end of the well
Type Well Production Profile
Annual Averages
Year
Oil
Rate
bbtid
Yearly
SOR
1
2
3
4
5
6
7
8
9
10
II
12
13
14
15
16
17
18
19
20
275
550
550
550
550
550
502
358
251
177
124
87
0
0
0
0
0
0
0
0
Totals
1651
Annual Averages
WOR
Steam
InjecUon
bbl!d
3.7
3.7
3.7
3.7
3.7
3.7
3.8
3.9
4.0
4.1
4.2
4.3
0.0
0.0
0.0
0.0
0.0
0,0
0,0
0.0
3.7
3.7
3.7
3.7
3.7
3.7
3.8
3.9
4.0
4.1
4.2
4.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
3.8
3.8
Year
Oil
Rate
bblld
Yearly
SOR
WOR
Steam
Injection
bblld
1009
2019
2019
2019
2019
2019
1889
1380
993
715
515
371
0
0
0
0
0
0
0
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
155
310
310
310
310
310
310
291
261
234
209
188
168
150
135
121
108
97
87
78
2.0
2.0
2.0
2.0
2.0
2.0
2.1
2.1
2.2
2.2
2.3
2,3
2.4
2.5
2.5
2.6
2.6
2.7
2.8
2.8
2.0
2.0
2.0
2,0
2.0
2.0
2.1
2.1
2,2
2.2
2.3
2.3
2.4
2.5
2.5
2.6
2.6
2.7
2.8
2.8
312
624
624
624
624
624
639
616
565
519
477
437
402
369
339
311
285
262
240
221
6192
Totals
1512
2.2
2.2
3326
Li1 GLJ
Petroleum
Consultants
Page: 80 of 141
Table 3
THERMAL PROJECT
TYPE WELL FORECAST
Phase 2-Stacked-D
High Estimate Contingent Resources
Type Curve #50
Phase 2- Stacked C
High Estimate Contingent Resources
Type Curve #49
-
1500
8505
120
1000
31.1
20,7
286
540
Steamflood Recovery
Steamflood Area
Well Spacing
Well LeSglh
Single Well Drainage Area
NetPuy
Number of Wells RequIred
Peak Rate per Well
Mbbl per well
ASres
Metres
Metres
Acres Makes
Wells
bbl/d -
Steamflood Recovery
Steamfluod Area
Well Spacing
Well Length
SIngle Well Drainage Area
NetPay
Number of Wells Required
Peak Rate per Well
* Includes 25w of drainage at each end of the well
-
-
Includes 25w of drainage at each end of the well
Annual Averages
Annual Averaoes
Year
Oil
Rate
bbl!d
Yearly
SOR
WOR
Steam
Injection
bbtfd
888
1776
1776
1776
1776
1776
1629
1203
883
648
476
0
0
0
0
0
0
0
0
0
1
2
3
4
5
6
7
8
0
10
11
12
13
14
15
16
17
18
19
20
150
300
300
300
300
300
300
268
239
213
190
170
151
135
120
107
96
86
76
0
2.2
2.2
2,2
2.2
2.2
2.2
2.2
2.2
2.3
2,3
2.4
2.4
2.5
2.6
2.6
2.7
2,5
2.8
2,9
0.0
2.2
2.2
2.2
2,2
2.2
2.2
2.2
2.2
2.3
2.3
2.4
2.4
2.5
2.6
2,6
2.7
2.8
2.8
2.0
0.0
323
645
645
645
645
645
645
590
540
493
451
4i3
377
345
316
289
264
241
221
0
5332
Totals
1357
2.3
2.3
3188
WOR
Steam
Injection
bbfld
3.3
3.3
3.3
3.3
3.3
3.3
3.4
3.5
3.5
3,6
3.7
0.0
0.0
0.0
0.0
0.0
0,0
0.0
0.0
0.0
3.3
3.3
3.3
3.3
3.3
3.3
3.4
3.5
3.5
3,6
3.7
0.0
0,0
0.0
0.0
0.0
0.0
0.0
0.0
0,0
3.4
3.4
Year
Oil
Rate
bblid
Yearly
SOR
I
2
3
4
5
6
7
8
9
10
II
12
13
14
15
16
17
18
15
20
270
540
540
540
540
540
483
349
249
179
128
0
0
0
0
0
0
0
0
0
Totals
1598
1233
11040
120
1000
31.1
16.5
355
480
Steamilood Recovery
Steamflood Area
Well Spacing
Well Length
Single Well Drainage Area
Net Pay
Number Sf Wells Required
Peak Rate per Well
-
RemaIning Stacked -0
High Estimate Contingent Resources
Type Curve #53
Remaining-Stacked - C
High Estimate Contingent Resources
Type Curve #52
-
Mbbl per well
Acres
Metres
Melms
Acreu *
Metreu
Wells
bbl/d *
Type Well Production Profile
Type Well Production Profile
*
1387
8876
60
1000
15.6
31,2
570
300
-
MbbI per well
Acres
Metres
Metres
Acres
Metres
Wells
bblld *
*
Includes 25m of draInage at each end of the well
1098
11040
60
1000
15.6
25.3
709
270
Steamilood Recovery
SteamiloodArea
Well Spacing
Well Length
Single Well Drainage Area
Nel Pay
Number of Wells Required
Peak Rate per Well
-
Mbbl per well
Acres
Metres
Metres
Acres *
Metres
Wells
bblld -
Includes 25w of drainage al each’end of the well
Type Well Production Profile
Type Well Production Profile
Annual Averages
Annual Averages
Year
Oil
Rate
bblld
Yearly
SOR
WOR
Steam
Injection
bblfd
855
1711
1711
1711
1586
1469
1119
647
642
486
368
0
0
0
0
0
0
0
0
0
1
2
3
4
5
6
7
8
9
10
II
12
13
14
15
16
17
18
10
20
135
270
270
270
270
260
234
210
158
169
151
136
122
109
98
88
0
0
0
0
2.1
2.1
2.1
2.1
2.1
2.2
2.2
2.3
2.4
2.4
2.5
2.5
2,6
2.7
2.7
2.8
0.0
0,0
0.0
‘0,0
2.1
2.1
2.1
2.1
2.1
2,2
2.2
2.3
2.4
2.4
2.5
2.5
2.6
2.7
2.7
2.8
0.0
0.0
0.0
0.0
289
570
578
578
578
571
526
483
444
409
376
345
317
292
268
247
0
0
0
0
4554
Totals
1088
2.3
2.3
2511
WOR
Steam
Injection
bblld
3.6
3.6
3.6
3.6
3.7
3.7
3.8
3.9
4.0
4.1
4.2
0.0
0.0
0,0
0.0
0.0
0.0
0.0
0.0
0.0
3.6
3,6
3.6
3.6
3.7
3.7
3.5
3.0
4.0
4.1
4.2
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
3.7
3.7
Year
Oil
Rate
bblld
Yearly
SOR
1
2
3
4
5
6
7
8
g
10
11
12
13
14
15
16
17
18
19
O
240
480
400
480
434
392
291
215
159
118
87
0
0
0
0
0
0
0
0
0
Totals
1233
LLj7 GLJ
Petroleum
Consultants
Page: St of 141
Table 3
THERMAL PROJECT
TYPE WELL FORECAST
RemaIning C Only
High Estimate Contingent Resources
Type Curve #54
Remaining -0 Only
High Estimate Contingent Resources
Type Curve l55
-
Steamfocd Recovery
Steamflood Area
Well Spacing
Well Length
Single Well Drainage Area
Net Pay
Number of Wells Required
Peak Rate per Well
*
-
1246
162
120
1000
31.1
16.1
5
480
MbbI perwet
Acres
Metres
Metres
Acres
Metres
Weils
bbUd
inciudes 25m of drainage at each end of the well
Steamfinod Recovery
Steamflood Area
Well Spacing
Well Length
Single Well Drainage Area
Net Pay
Number 01 Welts Required
Peak Rate per Wet
-
Type Welt Production Profile
ilIg
20310
60
1000
15.6
26.5
1305
270
Mbbl perwell
Acres
Metres
Metres
Acres
Metres
Wells
bbtd
Includes 25m of drainage at each end of the well
Type Well Production Profile
Annual Averages
Year
Oil
Rate
bbtld
Yearly
SOR
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
240
480
480
480
480
426
298
209
149
102
71
0
0
0
0
0
0
0
0
0
Totals
1246
Annual Averages
Year
Oil
Rale
bblld
Yearly
SOR
WOR
Steam
Injection
bbtld
1066
2133
2133
2133
2133
1940
1398
1001
717
513
368
0
0
0
0
0
0
0
0
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
135
270
270
270
270
260
234
210
189
169
152
136
122
110
99
69
80
0
0
0
3.2
3.2
3.2
3.2
3.2
3.3
3,3
3.4
3.5
3.6
3.7
3.6
3.9
4.0
4.1
4.2
4.3
0.0
0.0
0.0
3.2
3.2
3,2
3.2
3.2
33
3.3
3.4
3.5
3.6
3.7
3.8
3.9
4.0
4.1
4.2
4.3
0.0
0.0
0.0
429
858
858
858
858
848
792
719
662
609
560
515
474
439
401
369
340
0
0
0
5670
Totals
1119
3.5
3.5
3861
WOR
Steam
Injection
bbt!d
4.4
4.4
4.4
4.4
4.4
4.6
4.7
4.8
4.9
5,0
5.2
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
4.4
4.4
4.4
4.4
4.4
4.6
4.7
4.8
4.9
5,0
5.2
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
4.5
4.5
‘
LIi GLJ
Petroleum
Consultants
Year
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2532
2033
2034
2035
2036
3537
2036
2039
2040
2541
2042
2043
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055
2058
2057
2558
2059
2060
2081
2002
2003
2084
Produolog
CSS
Wells
0
0
8
24
33
36
38
42
42
48
51
54
56
52
54
57
58
81
61
51
48
52
50
55
50
56
53
56
51
55
54
57
53
58
52
55
54
52
55
54
52
55
52
54
55
51
56
53
52
48
NCG lrectdn
CSS Wot Coat
mM Coot
told
Steam Elfic5ency.
Fa46ty SOft
Produclsg
101111
Wells
0
0
0
0
0
0
0
0
0
5
5
0
0
0
0
0
0
0
0
0
5
0
0
0
0
0
0
0
5
5
0
0
0
0
0
0
5
0
5
0
0
0
0
S
0
0
0
S
0
0
Bfttaneo pmduotion:
Steam Srjeldon:
Steam
leje080o
bblld
0
0
3,760
12,757
25,038
33,715
34,144
34,273
33,253
32,417
33,527
33,439
33,534
33,784
33.430
34,125
33,488
33,782
33.410
32,055
33.335
33.429
33,836
34.612
33,264
33,799
34.489
33,034
34,206
33,631
34,240
34.539
33,555
34,014
34.201
34,373
34,094
32.592
33,554
34,534
31,065
34,739
32,390
34,145
34,282
33,298
33,704
34,246
32,755
31,724
567,215
166,941
sot0151 average
bbUday
bbVday (vao)
UMBIu1SO
MoWot
BItumen
Rate
bb6d
0
S
940
3,420
7.435
10,300
10,269
10,137
9,727
9,441
9.781
9,629
0,865
9,871
8,842
0,851
9,810
0,544
9,538
0,577
9,975
9,909
10,028
10,239
9,813
9.965
10,130
10,059
15,196
9,953
10,104
10,197
9.887
6,079
10,103
10,153
10,135
9,860
9,763
10,746
9,477
9,952
9.601
10.103
10,100
9,048
0.929
10.718
9,462
9.071
206
S
200
10.700
41.736
700
0400
300
3.40
AeoUat Aeeuol
CSOR
ISOR
0,00
0,60
0,00
5,00
4,53
4.03
3,74
3.80
3,37
303
3.27
3.41
3.33
3,38
336
3.30
339
3.42
3.40
3,43
346
340
3,47
341
3.44
3.42
339
3.41
3.40
3.41
3,46
3.41
342
3.48
3.54
3.43
3.00
3.43
3,35
3,43
334
3,42
3.35
3.42
3.42
3,37
3,38
3,41
341
339
3,41
3,39
3,40
3.41
338
3.41
3.41
335
338
3.41
339
341
339
340
3.40
339
341
3,40
3.40
339
3,39
3,40
336
3,40
3,40
3.40
336
3.40
3,40
3.40
3.30
3,40
342
3,40
3.35
340
338
3,40
3.37
3.40
3,40
3,36
3.39
3.40
3.40
3.38
3.40
3.40
340
343
prodooson
567,219
Water
ProductIon
bwpd
0
0
3.790
12,797
25.036
33,715
34,144
34,273
33,253
32,417
33,027
33,429
33,934
33,164
33.439
34.125
33,466
33,782
33.410
32,055
33,335
33,429
33,836
34,512
33,264
33,799
34489
33,534
34,200
33,031
34.240
34,539
33,505
34,514
34,201
34,373
34,004
33.052
33.054
34,534
31,855
34,139
32,350
34,145
34,282
33,298
33,704
34,248
32,155
31,724
Aeoual
IWOR
000
0,00
403
3.74
3,37
327
333
3.38
3.42
343
3.46
3.47
344
336
3.40
346
3A5
354
3.50
3,35
3.34
335
3.37
3.38
339
339
340
3.36
335
338
339
3,39
3.39
3.41
3.36
339
336
340
338
340
336
3.42
3.35
3.38
337
3.38
339
336
340
3,43
Fuel
Gas
Mclpd
0
0
1,519
5,119
10,015
13,486
13,550
13,709
13,301
12,967
13,531
13,370
13,573
73,266
13,372
13.650
13,395
13.513
13.394
12,522
13,334
13.372
13.535
13.845
13.306
13.519
13,796
13,534
13,682
13,452
13.959
13,016
13,422
13,505
13.500
13,749
13,939
13,421
13,221
13.613
72.746
13,059
12,056
13,650
73,713
13,319
13,402
13,059
12.892
12.450
0
9,000
1.00
1.00
NCG
lnjeotloe
Mold
5
0
0
0
0
0
0
0
0
0
0
0
0
S
0
0
5
0
0
0
S
0
0
0
0
0
0
5
0
0
0
0
0
5
0
5
0
0
0
0
0
0
0
0
0
0
5
0
5
5
*
Gas
PrIce
8
Real Cogen
SIMoP UnIts
S
3,10
5
3,56
3.73
0
0
3.59
5
405
0
4.19
5
433
4.46
S
459
9
455
0
405
6
4.115
5
4.65
0
5
465
4.65
0
0
465
4,65
5
465
0
465
0
5
4.65
4.65
0
5
4.65
4.65
0
0
465
0
465
5
4.65
0
455
5
4.65
4,55
0
5
465
4,65
8
4.65
8
4.65
0
465
0
4,65
0
4,65
5
465
5
4.05
0
0
4.05
0
465
405
0
0
405
5
405
0
465
0
455
4.65
0
S
465
5
4,65
465
S
4,65
0
00.10/Md
Gas
PrIce
Current
0/Not
3,10
3,63
3,66
4.13
4.38
403
4,56
5,13
5,30
5,56
9.07
578
5.00
5.51
0.13
526
6.38
5.51
6,64
6,77
5.91
7.05
7.19
7.33
740
7,53
775
793
8.00
8.25
8,42
8,59
8,76
8,94
0.11
930
9,48
557
6,07
10.06
10.26
10.47
1060
1068
11,11
1133
11.58
71.78
1203
1227
MS/yr
S/woO-month
0/SkI
51551
$1 moP
MIOpar/unit
At cost Olberta Spot Plant Gate
2% per year
24,500 M$lyr
350 M$l yr per mmWoW lnotaged Wpavity
Steamer
Otherrued Cools
OIIWON:
OIl:
Water
Flue Coop:
Cogen
Fuel
Op coot Intaton:
6.420 MSl yr
600 M5I yr per Ubb0dav tnstatlad eapantly
Battery’
Probable Undeveloped
-
Table 4
Production & Development Forecast
Sateskl Phase I
CoGeo
Power
Fuel
Moftot
0
S
S
0
5
5
5
0
0
0
5
5
S
5
0
0
5
5
0
8
0
S
0
0
0
0
0
0
5
0
0
5
0
0
0
0
0
0
5
0
5
0
0
0
0
0
0
0
0
5
Nat Gas
2010 MS
5
S
2,005
7,274
74,794
20.630
21,594
02,335
22,277
22,001
22,958
22.594
23,530
22,500
22,680
23,160
22,727
22.927
22,674
21,759
22.624
22,687
22,964
23.490
22,576
22,938
23,407
22,952
23,215
22,824
23,238
23,441
22,773
23.584
23,211
23,328
23,139
22,771
22,433
23.437
21.626
23.169
21.962
23,173
23.267
22,099
22,874
23.243
21,823
21.123
OperatIng Costs
Flued
VarIable
2015 MS
2015 MS
0
0
S
0
1,898
62.369
6,043
56,429
42,017
13,210
77,950
34,051
18,005
34.051
35,299
18,060
17 463
35,299
35,147
17.001
35,271
17,702
17,477
36.595
36811
17,787
17,509
39,379
17,508
36.595
17.049
36,919
37,527
17.404
37,351
17,556
37,351
17,410
10,944
36,271
35,947
17,029
17,660
36.379
36,183
17,840
18,239
36.703
17.514
36,163
17.792
36.811
18,135
36,407
17.857
35,811
38,271
18.009
17,725
35,703
36.595
18,029
36,919
18.189
17681
36,467
37,027
17,078
18,064
36,379
36.703
18,105
36,595
77,993
17.045
30.379
17.426
36,703
18,760
36,505
36,379
76,079
17,926
36,703
17,112
30,379
17.994
36,595
18.076
36,703
17.540
36,271
17,738
34,111
18,040
34,022
33,023
16,917
16,327
32,119
Non-gao OpetabOg coOt
Told:
Total
2010 MS
5
0
68,392
70,244
70,021
73,239
74,329
75.693
75,039
74,945
78,030
78,768
77,627
76,300
76,873
77.028
77,238
77,833
77,441
74,070
76,169
70.725
70,967
79,432
76,252
77.540
78,028
77,630
77,554
77,252
77.662
76.549
76,920
77,089
77,654
78,136
77.727
70,794
76,582
78,192
74024
77.796
75.473
77,762
78,045
76.415
74,723
75,305
71,763
69,508
Total
Current MS
0
0
69,032
74,544
75,793
00,082
83,707
86,047
87,920
86,570
93,777
95,449
58,450
98,826
101,432
704.980
106,031
100.885
110,605
109,217
113.227
115,295
118,989
123679
122,647
127,212
130,574
132,505
135,024
137,187
141.036
145.120
144,960
149,913
152.253
756,263
158.554
159.785
182,486
169,265
165,214
175,217
173,379
162,212
156,031
186,258
185,000
191,500
185,557
103,060
Operatleg
Cost
loftaUoe
Faotur
1,560
1 520
1.040
1.081
1.062
1.704
7.726
1,149
1.172
1.105
1.219
1.243
1,200
1.294
1.319
1,346
1.373
1.400
1,420
1.457
1488
1.516
1,546
7.577
1,660
1.641
1.573
1.707
1.741
1.776
1.911
1840
1.505
7.922
1.961
2000
2,040
2.081
2.122
2.165
2.208
2252
2.297
2.343
2.300
2.438
2407
2,536
2.587
2.639
040 01001 total rat air years at copaurty
1465 5011010101 for aO yearn atoupaorty
21.23 0/font total for aS years at capacity
6,26 Wont 10181 prtyeol lIe
15.602010 total pro4eot tie
21 072010 total poooO 110
Average Operatoog Costa
Nat Gas opvratarg cost
Nov-gas operabeg coot
Total.
OporaSog Cools at Peak PoducSon
roar ta5 operatory COOL
602 2051 12017)
187.37 WoN (2017)
193,39 5/bot (20171
NatGasoyerasvgerot
Non-gao oyerat5rg coot
Total’
tonal uporawo toots
Petroleum
GLJ Consultants
0
00
Onstrearu
a
0
0
0
0
0
0
41730
o
5
0
0
0
0
0
10700
0
5
5
10
9
3
0
0
0
6
3
3
5
3
3
3
3
3
0
0
5
0
3
6
S
9
0
5
0
5
3
5
5
9
3
3
6
0
0
0
0
3
0
3
5
5
9
5
5
5
4)10
2018
2017
2010
2019
2020
2021
2022
2023
2024
2525
2020
2027
2020
2029
2030
2031
2032
2033
2034
2035
2036
2037
2036
2039
2045
2041
2042
2043
2044
2045
2046
2047
2048
2049
2059
2051
2052
2053
2054
2055
2056
2057
2058
2559
2000
2061
2002
2663
2084
200
5)0.500
0
6
24
33
36
36
42
42
46
51
54
56
52
54
57
56
01
01
51
48
52
50
05
55
56
53
56
51
55
54
57
53
58
52
55
54
52
55
54
52
55
52
84
55
51
56
53
52
45
0
WoOo
9
0
5
5
5
0
0
0
0
0
5
S
S
5
0
0
0
5
5
5
5
5
5
5
0
5
5
0
0
0
0
0
5
5
0
0
0
0
a
1
55.400
5
u
0
0
0
5
0
5
0
0
5
5
5
0
0
0
0
0
S
0
0
5
5
5
5
0
0
0
5
5
5
WlIo
Wall Deeeleomont
Producing
Producing
Intel
055
Well,
Initli
CSS
Wells
VOO..
2% per year
Capital mOat/On
5
0
S
0
0
2
S
5
S
0
0
0
0
2
5
5
5
5
5
1
0
0
0
5
0
6
5
0
0
0
0
DeRWe
lnfraetruclure and Regutalnry
Cugen
Other rtheler Sources, Waler Plpehfle end Road)
10% ntoayllallyr
Facility Maintenance Capital
Total Rennaliling Facility, Intrustruclure, maintenance
Facility
Phase
Phase 2
Phase 3
Phase 4
PhaseS
Phase 6
Phase 7
Phase
Total tool/lies
1,556,100
0
40,005
67,200
53650
19,350
1,200
31,500
2,400
27,000
16,200
15,090
25,000
16,200
15000
15,095
15,095
19,000
28,500
43,500
3,600
27,600
16,200
26,600
2,400
41,400
3,605
41,495
3,800
27,600
I6,208
26,000
2,400
41,450
17,400
15,000
28,606
2,400
41,400
3,695
27,695
16,206
28,690
15.205
28,505
2,490
41,400
3,600
23,000
2,000
S
CSS
Welts
DICIAC
Design
SOIl
390
000
000
000
000
000
000
000
300
280,206
0
5
0
1.525
4,575
0
9100
0
9,150
4,575
4,575
9,150
4,575
4,575
4,575
4,575
4,575
9,150
13,725
0
9,150
4,575
9,150
0
12,375
0
12,375
0
0,250
4,125
0,250
5
12,375
4,125
4,120
0,255
5
12,370
5
6,250
4,125
0,255
4,125
5,250
0
12375
0
5,075
5
0
C90
Wells
PadlGath
39,03I
5
47,725
0
0
0
0
0
0
0
330,058
330050
Total Cost
2015 MS
raci.ny 000 InTra,vslslaro 0_ass,
Capacity )Stream Dot)
07 1551/it)
She Ibblidi
10,700
41730
1,366,300
0
40,800
67,200
55,175
23,925
1,200
40,650
2,400
36,750
20,775
19,575
37,950
20,770
19,575
19,575
50,575
19,575
37,900
57,529
3,600
36,750
25,775
37,900
2,400
53,775
3,600
53,775
3,600
35,650
20,325
37,050
2,400
53,775
21,525
15,125
37,050
2,400
53,775
3600
35,850
20,325
37,050
25,325
37,080
2,490
53,775
3,600
29,875
2,000
5
CSS
Welts
Tutat
5
0
S
0
5
0
5
0
0
0
0
5
5
0
5
423,555
5
1,400
4,200
5,775
6,300
6,300
7,350
7,350
0,400
8,925
9,450
9,595
9,100
9,450
9,975
10,150
10675
10,075
8,925
0,400
5,150
6,700
9,625
0,750
9,600
9,275
9,500
0,925
9,625
9,450
9,975
9,275
10,100
9,150
9,025
9,450
9,150
9,625
8,450
9.105
9,625
9,160
9,450
9,625
8,925
9,500
6,275
9,150
8.400
0
5
0
5
5
5
0
0
5
0
0
0
5
5
S
5
5
5
5
5
0
0
0
0
5
0
5
S
0
0
6
0
5
5
0
MatnL
$thtyd
0285
0
0
0
0
0
0
0
6,295
0
0
leOtI
Well,
504,962
37939
0
25.506
ReIn Cost
2015 MS
364,414
0
0
0
0
0
0
0
264414
Wall Ce,),
1.092
0
22,220
Spent
2015 MS
45,544
S
0
0
0
0
0
0
40,644
Probable Undeveloped
Table 4
Production & Development Forecast
Saleski- Phase I
9
0
5
5
0
204,414
5
5
0
5
0
0
0
7,255
162,608
54,939
0
0
0
5
0
0
0
0
0
0
5
0
0
0
0
0
5
0
5
0
0
5
0
0
0
0
6
5
S
5
0
0
0
0
5
0
0
5
5
5
5
50 (01
CPF
0
0
S
5
2,900
5
5
5
S
0
0
0
2,900
0
0
0
5
5
1,450
0
5
0
0
0
0
0
0
5
5
0
0
0
0
0
5
5
5
S
5
5
0
0
5
5
DeltneaSee
Well,
S/Snpd
30,647
0
0
0
0
0
0
0
30,647
37,839
5
0
5
5
5
5
19445
15,362
5
5
5
5
0
0
0
0
0
0
0
S
S
0
5
5
5
5
5
0
0
0
5
5
5
5
5
5
5
5
0
0
5
5
5
0
0
5
5
5
6
4.5)4
25,956
5
0
0
5
5
0
11,4I3
10,865
0
0
5
0
0
5
0
0
0
5
0
0
0
0
0
0
0
5
0
0
5
5
5
5
5
0
0
S
5
0
0
0
0
0
6
0
0
5
S
5
5
3,01)0
157,103
S
3,301
3,301
3,301
3,301
3,301
3,301
3,301
3,35I
3,301
3,301
3.301
3,301
3,301
3,301
3,301
3,301
3,301
3,301
3,301
3,301
3,301
3,301
3,301
3,301
3,301
3,301
3,301
3,361
3,301
3,391
3,301
3,301
3,301
3,301
3,301
3,301
3,301
3,30l
3,301
3,301
3,301
3,301
3301
3,301
3,011
3,036
2,941
2,890
0
FacIlIty and lntrastmoture Cests
Cogee &
tefroslsslulore
Other
Malet.
(3,340
2,242,362
31,001
50,701
36,776
31,976
32,326
32551
33,026
51,926
72,951
15.826
48,451
33,175
50,001
15,326
05.026
15,751
06,351
19,701
48,076
33,251
49,501
15,676
06,351
34,976
31,526
49,979
15,151
68,175
16,626
49,601
32,726
49,876
32,726
49,501
15,326
66,001
16,411
42,106
14,041
11,250
32,476
234,345
172,587
62,675
35,901
10,801
50,251
13,051
47,401
3,500,041
105,975
27,399
111,032
29,506
83,701
09,048
90,207
29,592
125 040
67,231
61,011
99,946
30,605
137,691
35.072
105,206
72,259
112,555
75,179
116,692
36629
160,900
46,908
106,988
39,324
28,792
24,167
239,033
178,572
66,512
36,065
11,825
56,580
14,991
55,037
38,611
38,765
63,040
48,640
41,364
42,653
44,213
45,337
72,706
104,191
23,005
71,985
90,263
77,300
(3,340
Total
Total Costs
Total
1,737,400
902,955
Total
2015 MS
40,500
176,500
764,400
111,325
138.075
02,400
7,250
G1 GLJ Petroleum
Consultants
1 520
1,040
l26ll
I 062
1.104
1,120
I 148
1.172
I 195
1219
I 243
1,265
1,294
I 319
1 346
I 373
1400
1,425
1 457
1 456
1,516
I 546
1 577
1.606
1541
1.073
1.707
1 741
1,779
I OIl
1 548
I 065
1.922
1061
2,000
2.040
2051
2,122
2,105
2.206
2,252
2.297
2,343
2,390
2.438
2.467
2.536
2567
2,039
1.12.5)
CapItal Cost
InflatIon
51,046 S/bnpd
13.43 S/Slit
includes capdal up to and including the tout pearot Phase 1 operehon
Capital inlenslty (IoWa) cns000p000y):
Rem. cap/tel (total pm). cnsolnlal b/O)
Total FanItly and Well CapItal Cast MetrIcs
Wall Caste
Coat par
Wel/lnhll
Catoemp
2015 Ms
Doll, 001011 COO wag tO2Smt
5,150 MS/ well
Drill, oupit CSS wet (100cm)
5,250 MS I wet
Dliii, cmpll COO well lcd. oplimizaltun
4,600 M5 I well
Pad, tacit, plpmg perwoll
1,525 MS / well
Pad, tacit, piping IOU. optho/oaticn
1,375 MSl wet
Dcwnhde Pumps
400 MS / well
5
I,450 MS/well
Md/I/coal dullneatice wells
FCoustelo/ngCapllal
l75M$lwelllyr
Total wells
C
.5
00
Wet/a
S
0
8
24
27
27
27
27
30
33
39
39
42
40
48
44
45
45
48
01
49
42
38
41
43
45
45
43
43
43
46
43
48
44
43
45
40
45
45
44
40
43
45
43
45
45
43
45
43
44
Yea,
2015
2016
2017
2018
2019
2900
2521
2902
2023
2524
2025
2026
2027
2028
2939
2036
2031
3032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2543
2044
2045
2046
2547
2040
2049
2050
2051
2052
2053
2054
2555
2058
2057
2058
2059
2060
2061
2082
2063
2064
Productng
CSS
NCG treo5on
Count
Intel C05nt
tn/at
CSS WeS
Producing
tnfitt
Watt.
S
0
S
0
S
S
0
0
0
5
0
0
S
0
5
0
5
S
S
0
S
0
0
0
0
0
0
S
0
S
0
0
5
0
0
S
0
0
0
0
0
5
5
0
0
0
0
0
0
0
Steam Effdcncy;
FacIlity SOR.
Bitumen produotionl
Steam frgectov:
509,504
177,369
6604
5
S
4,207
14,421
25,333
30,237
30,237
30,197
31,030
31,071
31,723
31,179
29,737
30,514
31,531
29.894
29,589
30,222
29.522
30,357
29,787
29,257
29,805
25,929
29,800
30,652
30,943
29,041
25.655
29,087
29,845
30,035
35,147
30,578
29,280
29,707
35,071
30,073
35,303
30,155
30,650
29,582
29.483
29,962
29,797
30,710
28,840
29,298
29,269
30,197
hbOd
Steam
t0)estton
5
S
1.195
4,360
8330
10,330
10336
10,265
15,402
10.384
10,746
10,572
10,209
10,491
10,808
10311
10,307
10,5t9
10,225
10.405
10,354
70,301
10,504
10,241
10,550
10,805
70,904
10,390
70,128
10,446
70.530
10,608
15,599
10,859
10,359
10,000
10,598
15,624
10,717
15,545
10,854
10,414
10.415
10.544
15,543
10.832
10.105
10.348
10,3)0
10,485
-
Bttieoen
Rate
601/day
bin/day )m)
MUSts/tv
Mctlbbt
Aenoat
505
090
0.00
352
3.31
304
293
203
294
3.59
269
290
202
281
2.91
292
250
2.87
207
289
259
280
283
282
262
203
204
284
285
283
204
2.83
2.83
283
202
284
283
284
203
203
283
282
284
283
284
293
284
263
2,83
204
2.88
2.87
Annuat
0505
090
058
3.52
335
3,17
3.00
352
3.90
3.50
3.00
299
258
2.96
297
297
296
2.95
295
294
2.94
294
2.93
293
292
2.92
291
291
2.91
290
290
2.90
2.90
209
2.89
2,89
2.89
299
208
250
268
208
208
299
208
288
200
287
267
287
2.87
0 soft/a aunrage p6495/co
290
S
290
10,700
41,730
750
S 450
3.90
Table 4.1
-
509,004
Water
Prndootlon
bwud
0
0
4,257
14,421
25,333
30,237
30,237
30,197
31,030
31,071
31,723
31,179
29,737
30,514
31,031
25,004
29,569
30,223
29,522
30,357
29,787
29,257
29,005
28.929
29,880
30,802
30,943
29,641
28,855
29,807
29,845
30,035
30,147
30,575
29,280
29,787
30,071
30,573
30,363
30,155
30,850
29,502
29.403
29,962
29,757
30,715
28,640
29,298
29,209
30,197
Annuat
IWOR
058
5.90
3.92
331
3.04
263
2.93
294
256
299
295
2.52
2.91
297
202
290
287
207
2.89
209
206
203
2.82
282
293
284
204
295
283
284
203
283
293
282
204
283
284
283
2.83
283
292
284
203
284
283
204
263
283
264
288
OOmt Ford Costs
04 Wet’
0+
Wean
F/ce Compl
Cogun
Font
Op cost slat/On
203,801
S
1,603
5,769
10,133
12,095
12,265
12.078
12.412
12,426
12,689
12,472
11,895
12,268
12,972
11,950
11,828
12,009
11,909
12,143
11,915
11.703
11,642
11,572
11,952
1Z261
12,377
71,857
11,462
11,887
11,938
12.014
12,059
12,231
11,704
11,915
12.028
12,529
12,140
12,002
12,280
11,633
11,793
11,985
11,919
12,204
11.456
11.719
11,700
12,079
Fact
Gas
Mefod
0
0
NCG
tn)eotton
Meted
0
0
0
5
0
5
0
0
0
S
0
0
0
0
5
0
0
0
0
0
0
0
0
5
0
5
0
S
5
0
0
0
0
0
Gas
Pt/ce
Current
CUd
3.18
3.63
388
4.13
438
453
488
513
538
5.56
5.67
570
5.95
6.01
6.13
6.26
5.38
6.51
6.64
6.77
6.91
7.05
7.19
7.33
748
763
7.70
7,93
8.S9
825
8.42
6.59
8.76
8,94
9.11
930
9.49
967
987
1006
1026
15.47
1068
1089
1111
11,33
11.50
11.79
12.03
1227
Gas
PrIce
Reat
StUd
3.18
355
3.73
389
405
4 19
433
4.48
459
4.55
465
4.65
485
405
405
455
4.65
4.65
465
465
4,65
465
465
4.65
465
465
465
485
465
465
4,65
465
465
4.65
4.65
4.65
465
465
465
4.65
465
4,65
4.65
4.65
465
4.65
4.65
485
465
4.65
0 MS / yr
8,0500/ weS-mont
1.80 5/b/a
I 90 9/ bbt
S/md
MS14nar/urst
At cost PJbeOa Spet Plant Gate. $0.15/Md
2% peryear
6
Cages
Oct/a
0
0
5
0
S
5
9
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
5
0
0
0
0
0
5
0
0
0
0
0
0
0
0
0
0
0
0
0
0
9
0
0
5
24,500 US/yr
350 US / yr per mmb5olrr Insta8ed oapaoly
Steamer
Possible Undeveloped
6420 MS/yr
690 MS/yr per Mb/a/day dulaOed OapaOly
+
Battelyl
Probable
Production & Development Forecast
Saieskt Phase I
CoGen
Power
Feat
Motod
0
0
0
0
0
0
5
5
0
0
0
0
5
5
5
5
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
5
0
0
0
0
0
0
0
5
0
0
0
0
0
0
5
5
5
938,487
Not Gas
2095 MS
0
0
2,292
6,197
14,988
18.510
19.123
19,579
29788
21,587
21,829
21,168
20,161
20,756
21,350
20,260
20,560
20,511
20,036
25603
20,216
19,656
20,092
19,634
20,279
20,803
21,000
20,117
19,447
20,134
20,255
20,364
20,465
20,752
19.808
20,2)6
20,408
20.410
20,506
20,466
20.801
20.077
20,009
20,335
20,223
20,842
19,437
19,884
19,884
20,494
‘..
t OnM tornteasm ci
5,926,709
3,448,886
1,734,641
775,556
Totat
Current MS
0
5
69,573
76,098
75,826
76,050
78,262
60,407
64,139
66,572
95,165
91.211
01,216
94,701
98,660
57,398
99,514
102,110
103,342
107,361
108,194
100,371
110560
111,944
116,408
120.632
123,643
122,949
123,365
128,016
131.564
134,062
137.635
141,039
145,363
144,920
146.511
151,527
155,306
157,626
162,408
162.119
165620
189,764
173,263
179,436
165,309
172,101
174,806
162358
Tn/at
2015 MS
0
0
66,871
72.275
70,144
08,881
89,494
69,999
71.812
72,445
73,986
73,350
71,923
73,207
74,772
72.359
72.126
72,923
72,356
73,696
72,81)
71,501
71.615
75,990
72,368
73.025
73,886
72.031
70,658
72,080
72,644
72,501
73.034
73,373
71,589
72,464
7Z554
72,826
73,178
72,815
73,553
71,983
72,095
72,450
72,493
73,004
60,512
67,054
67,569
65,708
I1 GLJ
Operating
Cost
tsffatton
Factor
1.090
1.020
1 040
1 061
1 563
1.104
1.126
I 149
1 172
1,195
1.219
1.243
1.268
1294
1.319
1 346
1.373
1.498
1.428
1.457
1.466
I 516
1,546
1.577
1,600
1641
1 673
1.707
I 741
1.776
1.811
1648
1.885
1.922
1961
2065
2,040
2681
2)22
2165
2208
2252
2297
2343
2390
2438
2407
2538
2587
2639
13.58 St/a total for aS years at rapauty
18.69 Sot/a total for aS yeats at cayaoty
-
5.29 Sot/a total p10)/s ate
St/a total pm)nd ale
19.44 $10/a to/at pr0)ect hfe
14.15
5.26 Sot/a (2017)
148.00 Sot/a (2017)
153.31 St/a (2017)
Operating Costs
Ff064
Vartabte
2015 MS
2015 US
0
5
5
0
82,309
2,180
56,425
7,851
13,807
41,368
33,679
16,652
33,679
16,892
33,679
16,642
34,853
17,521
34,327
17,528
34,975
17.462
34,975
17,223
76,443
35,299
35,633
16.870
35,947
17,426
35,515
16,596
35,633
16,436
35,623
16,790
35,947
16,374
36,271
15.823
16,541
36,055
16,346
35,299
34,667
16,556
16,766
35,181
35,407
16,803
35,623
17,104
35,623
17,264
16.508
35,407
35.407
16,504
16,547
35.407
35,73)
16,658
16.770
35,407
35,731
16,843
17,106
35,015
35,407
16.324
35,623
16,526
16,773
35,623
35.523
16,793
16,950
35.623
35,515
16.835
17,129
35.623
16,489
35,407
35,623
16.463
16,709
30.407
16,640
35,623
17,140
35.623
31,089
15,986
31.810
16,359
31,374
16.331
31,849
16,763
...
Openaterg Costs at Peak P/s/sos
sat ISO opnrwr cost
640-gas operatIng cost
TO/at
Aunraqe Operatero Cools
Nat Gas opera/so cost
Non-gas opnra50g cost
To/at
tn/Sal Operating Costs
Nat Gas operaSog cost
Non-gnu operaoog cost
Tn/all
Consultants
Vs.,
15
2016
2017
2018
2019
2020
2021
2022
2003
2024
2025
2006
2027
2028
2029
2030
2031
2032
2033
2034
2035
2038
2037
2036
2639
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2958
2551
2052
2053
2054
2055
2556
2057
2558
2009
2060
2081
2062
2563
2554
Onsheam
a
0
0
0
0
41,730
o
o
0
0
0
10,700
2% per year
Wall Deeeloperent
Prsdsuln5
Inst
Predauleg
COO
Wag.
still
WaIt.
6I.66m
Walk
0
0
0
0
0
0
8
0
0
24
0
0
27
0
0
27
0
0
27
0
0
27
0
0
30
0
33
0
0
39
0
0
39
0
0
42
0
0
45
0
0
48
0
0
44
0
45
0
45
0
0
46
0
0
51
0
0
49
0
0
42
0
0
30
0
0
41
0
0
43
0
0
45
0
0
45
0
0
43
0
0
43
0
0
43
0
0
46
0
0
43
0
0
46
0
0
44
0
0
43
0
0
45
0
0
45
0
5
45
0
0
45
0
0
44
0
0
45
0
0
43
0
0
45
0
0
43
0
0
45
0
0
45
0
0
43
0
0
45
0
0
43
0
0
44
0
0
0
Capital Intaiton
COO
Walt.
91.66.0
0
0
6
15
3
0
0
0
3
3
8
0
3
3
3
0
6
5
3
3
3
6
0
3
3
3
3
0
6
0
6
0
6
0
3
3
3
3
3
3
3
0
6
0
8
5
3
3
3
6
147
5
Delle’e
Wall.
0
0
0
0
2
0
0
0
0
0
0
0
2
0
0
0
0
0
I
0
5
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
inhashcctt%n and Regulalmy
Cogen
Other oVater Sournen, Water thpeitne and Road)
Fsdhty Maintenance Capital
10% olcapllallyr
Total Renrakdng Faintly, lntraslructute, maintenance
Fac81v
Phase 1
Phase 2
Phase 3
Phase 4
PhaseS
Phase 8
Phase 7
Phases
Total ladidle,
164,575
758,250
1,002
0
22,220
39,031
0
47,725
CS5
Well,
PadlOath
2815 US
0
0
0
9
5
0
5
5
1,525
9,150
0
4,575
4,575
4,575
0
9,150
0
4,575
4,575
4.575
9.150
5
4,575
4,575
4,125
4.125
0
8,250
0
5,256
0
8,206
0
4,125
4,125
4,125
4,125
4,125
4,125
4,125
0
8,250
0
8,250
0
4,125
4.125
4,125
0,250
0
a
0
0
0
45,643
n
0
0
0
330.059
504.567
37,639
0
25,506
Rem Cost
2015 MO
uoo,cro
0
8
0
o
0
0
0
284,414
922,825
0
Well Canto
COO
W.ll.
ln811
Wells
Tetat
2815 US
201660
0
0
0
40,855
64,605
0
21,700
0
1,250
0
0
0
0
0
15,790
0
18,475
0
41,856
0
2,450
0
20,325
0
0
19.575
18575
0
1,200
0
36,750
0
2,490
0
16,375
0
19,575
0
19,575
0
37,950
0
2,400
0
0
18,375
19,575
0
19,125
0
0
19,125
1,250
0
35,850
0
2,450
0
0
35,850
2,400
0
0
35.850
2,450
0
17,925
0
5
10,125
19,125
0
19,125
0
19,125
0
19,125
0
15.125
0
1,200
0
0
35,959
2,400
0
5
35859
0
2,450
0
17.925
0
19,125
19.125
0
37,050
0
0
2,450
a
0mO
Welt.
DICIAL
2815 US
0
45,895
84,806
21.700
1,200
0
0
15,750
15,950
32,795
2,450
15,750
15,500
15,095
1,206
27.600
2,450
13,890
15,000
15.095
28,800
2.450
13,855
15,005
15,060
15,095
1,206
27,655
2,455
27,600
2,450
27,650
2,450
13,805
15,000
15,095
15,065
15,000
15,050
15,500
1,200
27,000
2,400
27,650
2,400
13,800
15,000
15,000
25,855
2,400
0.00
000
0.00
000
390
-
2015 MS
45,643
0
0
Spent
344,450
Minet
2615 Ut
0
0
1,450
4,250
4.725
4,725
4,725
4,725
5,250
5,775
6,920
6,625
7,350
7,875
8,450
7,755
7,975
7,875
8,455
8,925
8,575
7,350
6.650
7,175
7,525
7,875
7,875
7,525
7,525
7,525
8.050
7,525
8,050
7,750
7,525
7,875
7,575
7,970
7,875
7,790
7.975
7,525
7,875
7,525
7.875
7.875
7,525
7,875
7,525
7,700
284,414
0
0
0
0
0
0
0
0
0
0
0
O
O
0
0
0
0
0
0
0
0
0
7,250
CPF
2515 US
66,787
162,680
54.939
0
0
0
0
0
0
0
0
0
0
0
0
0
5
0
0
a
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Dellnoatlen
Well.
281560
o
0
0
0
2,690
0
0
O
o
0
0
O
2,950
0
0
0
0
O
1,450
o
0
0
0
0
0
0
0
0
O
O
0
0
0
O
0
30,947
0
0
0
0
0
0
0
0
a
0
0
0
6,255
-
3u,O0
Sthogd
0,755
5190,4
Probable + Possible Undeveloped
a
0
0
ooo
050
050
-
330,055
Total Cost
2015 M$
350
Design
SOR
racoiiy ann .nrosnwccow j.e,o.
CaWinty 1058am OWl
04150641
059150641
10,750
41,730
0
0
O
0
Table 4.1
Saleskl- Phase
Productton & Development Forecast
37,935
25,509
Tetat
2015 MS
73,325
234,346
170,487
29,201
12,126
8,025
8,025
23,778
27,025
50,925
12,529
30,45t
33,126
30,751
12381
47,751
13,576
29,551
32,726
31,601
49,826
13,051
28,326
30,051
29,951
30,301
12,378
48,676
13,226
48,676
13,751
46,676
13,751
28,826
29,651
20,301
36,301
30.301
30,301
30,128
12,375
46,576
13,578
46,676
13,578
29,101
29.487
29,870
47,443
13,007
Tetat
CanreetUS
73,326
239,033
177,374
30,998
13.125
8,861
9,038
27,311
31,666
60,661
15,269
37,861
42,011
39,779
17,022
64,266
15,836
41.378
46,740
46,327
74036
19,780
43.791
47,387
48.174
49.711
20,710
79.670
23,026
82,889
24,907
98,237
25.914
55,602
58,723
06,558
61.610
63,045
64,307
65,214
27,326
105,123
31,186
109,370
32,446
70,043
73,323
75,761
122,738
34,324
Tnbt Cant.
1567ditil7790412.778,it46
Faotltty and tntra.trootore Cant.
Cages S
lelrweteactare
Other
Malni
2910 MS
2815 US
2010 US
3.132
3,408
0
11.413
19,445
0
3,301
15,362
10,685
3,301
0
0
3,301
0
0
0
0
3,301
5
0
3,301
3,301
5
0
3,381
0
0
0
0
3,301
0
0
3,381
3,301
0
0
0
0
3,301
0
0
3,301
3,301
0
0
0
0
3,301
o
p
3.351
0
0
3,301
o
a
3,301
o
a
3,361
0
0
3,301
0
0
3,301
0
0
3,301
0
0
3,301
0
0
3.301
3,301
0
0
0
0
3,301
0
0
3,301
0
0
3,251
O
0
3,201
0
0
3,301
0
0
3,361
0
0
3,30t
O
0
3,301
0
0
3,301
0
0
3,361
3,301
0
5
O
0
3,301
O
0
3,301
0
0
3,361
3,301
0
0
0
0
3,301
0
0
3,301
3,301
0
0
3.301
0
0
0
0
3,301
0
0
2,837
0
0
2870
0
0
2,809
0
0
2,907
Includes capital upin and Including the first yearn! P58861 opera158
Capital inteflsity (Initial cnsocapacity):
Rem. capital (total pro). costdotal bta(
3455
1,274.475
Total
2015 MO
137,705
75,750
483,000
65,575
89,000
58,800
7,250
CapItal Cs,t
lnflnflen
P.0850
l.
1020
1.040
1.561
1.082
1104
1129
1,149
1,172
1.195
1.219
1,243
1.268
1.254
1 319
1 346
1.373
1406
1.428
1457
1.496
1.518
1 546
1 577
1.608
1841
1.673
1.707
1741
1.776
1.811
1 848
1 885
1922
1 841
2000
2.040
2.081
2,122
2.165
2.208
2.252
2,297
2343
2,390
2438
2487
2.536
2.587
2.839
50,824 SISoyd
1003 5160
143 l8
MS I wet
MS I anlI
MS I welt
MSI8
MS 1991
MOlawl
MOl woS lyr
Total Faalllty and Well CapItal Cast Meplo.
Welt Cents
Coat per
WeWInfill
Catenory
2015 MS
5,100
Doll, cmyft CSS well (925m)
5,250
Drill. cmpll COO wet ll000rn)
4,660
ony, 0mpg CSS 6081501. npomlzallnn
1,525
Pad, tadI, piping per wot
Pad, 1581, piping mci opilmizalon
1,375
Doinohote Pumps
400
Mdltmonaldn6nealloewels
5
1,450
175
PC Sustaining Capital
Totalwells
Petroleum
GLJ Consultants
t
to
Year
0015
20(8
2017
2019
2019
2020
2021
2002
2003
2004
2025
2006
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2049
2046
2047
2048
2049
2050
2051
2052
2053
2554
2055
2008
2057
2050
2559
2000
2061
2062
2063
5
5
13
29
37
37
40
43
85
(78
431
699
955
1,076
(.319
1,439
1,560
1,676
1,732
1,715
1,723
1,767
1,031
1,846
1,771
1,684
1,649
1,694
1,629
1,548
1,560
1,459
1,387
1,250
1,158
1,075
971
880
751
645
573
379
252
93
69
55
28
3
0
Producing
CS5
Welts
NCG lrienrioo:
CSS Well Count
IngS Coast
total
Steam E9denoy:
Facaity 5CR:
Prodooing
cAll
Welts
Stamen prod001100:
Steam injeoton:
0
0
0
0
0
0
0
0
0
S
5
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
5
0
5
0
S
0
0
0
5
0
9
9
0
0
0
0
0
0
bboday
bbllday (awe)
MM8tolhr
Mut61ta
Bitumen
Rate
bbtd
795
909
l,600
4,315
9,458
11,005
11,045
11.250
17.337
38,687
88,463
159.327
228,764
266,386
286,893
296,907
298,226
296,047
298,391
206,840
293,045
289,743
283,546
280,643
291.792
280,944
279,572
275,763
277,414
279,960
275,880
252,526
232,644
203,831
175,855
150,534
125,866
105,647
85,064
68,485
50,366
36,885
23,997
10,051
7,142
5,330
2,596
275
0
Steam
Annual Annual
tejeotloe
bbffd
CSOR
SOR
4,100 5.16
6.45
4,686 5,16
8.07
8,266 4.58
5.51
4.81
17,350 402
28,825 3.53
420
37,444 3.40
3.80
37734 3.42
3.76
38,331
3,41
358
3.56
55,645 3.21
116,045 305
3.38
269,533 3,05
3,23
3,16
491,674 3,86
3.15
716,009 3.13
835,293 3,14
3.15
892.906 3,11
3,14
9(3,228 3.06
3,12
3.11
913,372 3.09
915,466 3.07
3.11
916,596 3,07
2.10
3,10
815,497 3,08
911,042 3.11
3,10
919,879 3,17
3,11
918,812 3,24
3,12
921,024 328
3.13
927.183 3,29
3,14
922,836 3,29
3,15
3,18
923,812 3,36
3,17
909,368 3.35
901816 3,25
3,17
901,453 3.22
3,18
3,18
894,856 3.24
830,379 329
3,18
3,19
777,899 3.34
3.20
690,309 339
320
3,45
607,251
3.21
538,343 3.56
463,149 3,68
3,32
398,906 3,78
3,23
327,417 3.85
323
270,191
3.24
3.94
231406 4.11
3,25
(49,529 4,05
325
98,448 4,02
326
33,341
3,26
3.32
24,248 3.40
3.26
18,730 3,51
3,29
9,338 3.60
3.26
995 352
3,26
3.26
9 0.90
9 sotWa average prodorvtiorr
3.336
333
312,569
(037730
17,300
0,400
3.32
Table 4.2
Water
Produotiss
bwpd
4.150
4,586
8,266
17350
36,825
37,444
37,734
38,331
55,645
116,045
269,533
491,674
716,029
835,293
892,905
913,238
913,372
918,466
916,586
919,497
911,042
919.879
918.812
921,024
927,183
922,830
923,812
908,368
901,618
99l,453
894,856
830,379
777.898
690,368
607,251
536,343
463,149
390.908
327,4(7
270,191
231,406
149,529
96,448
33,341
24,249
18,730
8,338
995
0
Annual
IWOR
5.16
SIB
4,59
402
3.53
3,40
3.42
2,41
3,21
3,05
3.09
3.09
2,13
3.14
3,11
300
3.08
3.07
3.07
3.08
3.11
3,17
3.24
3,28
3.29
3,29
3,30
3,30
3,25
3,22
3,24
3,29
3.34
339
3,45
3,56
269
378
3,85
3,94
4.11
4,05
4,52
3,32
3.40
351
3.85
3,62
000
0
0452402
0
5
0
0
0
0
0
0
0
6
0
0
0
0
0
0
0
0
5
0
0
5
0
NCG
tnjeotlos
Meted
Fuel
Gas
Meted
1840
1,874
3,307
6,940
11,930
14,978
15,003
15,332
22.258
46.419
(07,813
186,670
286,412
334,117
357,160
365,291
365,349
366,186
306,039
366,189
304,417
367,951
367.445
369,410
370,873
369,172
368,525
363747
395646
366,581
357,942
332.152
311,159
276,147
242,906
214,537
185,260
100,563
130,967
108,076
92,063
59,811
38,579
13,337
9,099
7,492
3,735
398
0
S
9,500
1.50
1.05
Gas
Gas
Pitoe
Prloe
Real
Current
5184sf $lMcI
3,18
3.16
3.63
3,56
3,73
3.68
4.13
3,89
4.38
4.05
4.63
4.19
4.88
4,33
4,46
6,13
5,39
4.58
4,65
5,56
4,65
5.67
465
5.79
5,96
4,65
465
8.01
6.13
4.65
6,26
4.65
465
6,36
6,51
4,65
4,65
9.64
6.77
4,65
4,65
6,91
4,65
7,05
4.65
7.19
4.85
7.33
4,65
7,46
7.93
465
7.78
4.65
7.93
465
8.09
4.65
4.65
8.25
8,42
4.65
469
8.59
8.76
4,65
4.55
8,94
9,11
4.65
465
9.30
465
9.49
465
9,67
9.87
465
465
10.06
1026
4,65
4.65
10.47
10.58
4,65
10.89
4.65
4,95
(III
4,65
11,33
11,56
4,65
11.79
4,65
12,53
4.65
645 (yr
Slwel-rrronth
Sitta
$1610
$1 tnOl
MSlyearlond
At oust ittsorta Spot Plant Gate * 20.10(64*!
2% peryear
0
0
0
0
0
0
0
0
9
6
0
0
0
0
5
0
9
5
0
0
5
0
0
0
0
0
0
0
6
Cogeo
Units
524,669 MS (yr
30.3 US (yr per mrrrtitUThr ilulnd rapacity
Steamer,
Other floed oslo:
04 Wet:
04.
Waler
Fkra Coop:
Cogen
Fuel:
Op oust inlasorr:
157,680 M$(yr
555 Us (yr per MbbUdoy installed capuody
Ballery
-
Production & Development Forecast
Saleskl All Phases
21’ + Best Estimate Contingent Resources
CeGen
Fewer
Font
Mofed
0
0
0
5
0
5
0
0
0
0
0
0
0
0
5
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
8
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
18,935408
27,258,575
Operating
Floed
2010 Mt
10,595
10,095
71,119
65,156
47.906
40,219
40,543
40.887
152,003
364,617
860,503
903.447
909,363
972334
690,962
650,072
851,663
862,231
669,279
866,443
867,307
872,059
878.971
600,591
872,491
863,095
859,315
884,175
857,155
856,477
846,973
835,093
827,743
814,027
803,011
793,832
782517
772,020
578,893
479,324
457,247
377,370
296,963
103,308
57,640
49,940
33381
6,180
S
1Z608,440
Costs
Variable
2015 MS
1,932
2,208
4,006
8,695
15,5(7
19,883
(9,920
35,169
28,802
63,198
146.913
266,693
386,599
450,735
482,683
405,685
496.866
497,328
497,927
496,680
492,972
404,390
490,536
489,626
402.703
490,688
490,257
482,906
485,974
452,319
477,666
441,346
411,305
363,582
317,927
278103
237,930
203,443
166.090
136,121
115,323
74,772
49342
17,672
12,761
9,755
4,629
514
S
55860,521
Total
2015 Mt
13,630
(4,740
79,629
82,714
81,048
82,833
64,227
65,896
219,902
509,571
900,321
1,503,626
1,n71.912
1,989,861
1,979,833
1,965,741
1,968,411
1,980,859
1,989,276
1,984,447
1,978,579
1,900,747
1.992,943
1,995,492
1,954,448
1,960,150
1.579.538
1,964.239
1,950,032
1,990,588
1,931,954
1,839,996
1,786,987
1,646,144
1,533,083
1,436,006
1,334,775
1,246,792
1,967,182
798,8(6
729,520
553,624
410,762
143,608
66,658
72408
44,557
7,357
0
91,321091
Total
Correct Mt
13,930
15,035
82,846
86,828
n7.729
91.495
94,853
98,762
257,744
605,400
(207,195
1,868,819
2.274,037
2,574,326
2,612,349
2,645,629
2,702.207
2,773,681
2.839,747
2,690,964
2940,005
3,017,308
3,081,050
3,140,690
3,207,946
3,249,645
3,307,576
3,352,733
3395,053
3,463,942
3,499,488
3,396,556
3,329,958
3,164,269
3,055,839
2,871,854
2,722,790
2594,182
2264,679
1,729,234
1,611,030
1.246,872
943,621
338,501
207,595
176,516
110,795
16,660
0
L] GLJ
Operulleg
Cost
Inflation
Factor
1,000
1,020
1.040
1.091
1,082
1,104
1,126
1,149
1.172
1.155
1,219
1,243
1.298
1294
1,319
1.346
1.373
1,490
1,426
1.457
1.486
1,516
1,546
(.577
1,608
1,641
1,573
1.707
1.741
1,776
(.811
1.840
(.885
(.922
1.961
2.066
2.040
2,081
2.122
2.165
2,208
2.252
2297
2.343
2,390
2,438
2.467
2,536
2.587
5.69 51551 total tor 00 years at capaoty
1456 5(6161 total touao years at rapacity
20.66 51510 total (not years at rapacity
Operating Costs at Peak FedonSmr
Nat bas operating oust:
Non-gao poerohrrg oust
Total.
Nat Gas
2015 MS
1,903
2437
4,504
9,862
17,622
22,922
23,864
24,980
37,277
78,756
182,925
333,687
485,951
566,692
906,088
618,784
819,882
621,303
622,070
621,324
619,301
624,298
623,438
625,076
629255
626,369
626,967
817,105
811,804
61(793
607,3t5
563,557
527,639
468,535
412,125
364792
314,326
270,729
222.209
183,372
157,050
101,481
65,457
22,629
16,457
12,712
8,330
676
0
6.050(510 total p4450 tile
15.03 SWa total prtaeol No
21 09 SWa total p44eot tite
Average Operating Casts
Not Gas operatatig oust
Non-gas operating oust
Total:
0.59 9(561(00101
41.45 $61bl (20(5)
49,00 $1551 (2015)
Nut baN OperatIng COSt
Non-gas operatIng cost
Total.
Petroleum
Consultonts
Phase Aol Each Phase
Onsheam
2010
2017
2023
2024
2025
2026
Pmdoole5
COO
WeOC
5
13
29
37
37
40
43
85
175
431
689
955
1079
1310
1439
1550
1676
1732
1715
1723
1767
1531
1646
1771
1694
1649
1694
1629
1648
1560
1450
1387
1260
1158
1075
971
950
751
645
573
379
252
93
69
55
28
3
0
COO
Walle
Sleeloe
0
8
10
9
0
3
3
42
05
252
255
270
130
241
122
143
110
150
67
124
64
59
170
149
153
51
154
119
175
29
40
32
3
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Vee.
2015
2017
2015
2019
2020
2021
2022
2023
2024
2025
2026
2027
2025
2029
2530
2031
2032
2033
2034
2035
2035
2037
2036
2039
2040
2041
2042
2043
2044
2045
2045
2047
2046
2549
2050
2051
2052
2093
2054
2555
2055
2097
2058
2059
2060
2061
2062
2063
Capital 1010600
Wean
0
0
0
5
5
0
5
5
0
S
S
S
S
S
S
S
0
S
S
0
0
0
0
0
S
0
S
S
S
S
0
0
0
0
0
0
0
5
5
5
0
5
S
0
6
0
0
5
5
0
0
5
0
0
5
S
S
0
5
S
S
S
0
S
0
5
S
S
6
0
0
5
5
S
S
S
0
5
S
S
S
0
0
0
0
0
5
5
5
0
S
S
0
S
0
0
5
0
Predaolng
10511
Wade
Dellen
0
0
0
14
18
18
10
18
18
22
18
18
17
15
11
10
8
6
6
6
6
6
6
6
6
4
2
S
S
0
S
0
0
0
5
5
5
5
5
5
5
S
0
8
0
8
10% 01 capital! yr
S
36,560
78,600
47,000
3,555
13,800
15,500
194,455
453,955
1,197,200
1,553,860
1,048,260
563,090
595,500
023,405
549,300
442,250
569,000
364,500
460,050
273.655
372,t60
634,600
589,005
585,155
239,700
664,450
490,100
660,155
171,555
151,604
120,080
23,355
1,200
5
S
5
0
S
5
0
0
0
0
0
0
5
5
S
5010 US
CSS
Wells
DICIAL
39
33
33
33
3.3
33
41,730
247,500
247,500
247,500
247,000
1,037,730
10,700
70,000
75,500
75,060
70,000
312,560
-
3.3
-
5,600
DesIgn
SOS
1,606
Total Phase
Cepedly lSlream Oayl
011 tbbildl
01w 105541
510.5w
Welt Development
101111
Wells
2% per year
Infraslroolom
Cogen
Other
FactSy Minelenance Capital
Total Rerealnhng Facility. Inhasooclore, maintenance
PhoSe 1
Phase 2
PhaSe 3
Phase 4
Phase 5
Tolel tacihOm
P101
Faotty
Table 4.2
0
0
S
1,525
0
4,575
4,575
64,555
144,875
384,350
393,450
411,750
198,255
367,525
106,555
215,075
167,755
256,250
115,625
170,505
08,090
136,120
233,750
204,875
215,375
70,125
253,080
183.625
245,625
39,875
05,000
44,500
4,120
0
0
6
0
0
S
0
0
5
S
5
0
0
0
0
0
2015 US
COO
Wells
PadtGath
0
36,060
76,600
40,325
3,609
18,375
19,575
256,455
558,675
1,501,960
1,397,250
1,459,955
761,250
1,263,525
759,450
767.375
659,058
775,250
484,125
039,355
361,650
508,225
066,350
704,370
055,475
309,620
917,450
653,725
900,725
211,375
206,600
172,080
27,425
1,208
0
5
S
S
S
S
0
6
5
5
0
5
5
5
5
2810 US
2015 MS
Well Caste
COO
Walls
10611
Total
Welts
5
5
S
S
S
0
S
S
S
0
0
0
0
5
0
0
S
0
S
S
0
S
0
0
0
0
0
0
0
0
5
5
5
0
5
0
0
0
0
0
0
0
0
0
0
0
0
0
5
07,045
S
25,506
2578136
5,655,246
1,092
6
22,220
075
075
2,275
5,075
6,475
6,475
7,055
7,525
14,975
31,329
70,420
120,575
167120
158,550
235,825
25I,825
276,500
293,300
303,150
300.125
301,525
359,225
320,425
323,550
309,525
294,755
258,575
296,450
260,575
288,405
273,000
253.700
242,725
220.500
252,650
108,125
169,925
154,000
131,425
112,075
100,275
66,325
44,105
18,275
12,075
9,625
4,900
025
0
2515 US
Malnt.
6,290
5,567
4,755
4,700
4,700
4,903
89532
S
47,725
13,SZ1
SMpd
0
-
284,414
1,634,000
1,515,750
1,515,750
1,515,755
6,465694
Row CosI
2515 MS
45,043
0
0
0
0
154,227
108,584
Spent
2015 Ms
330055
1,534,000
1,515750
1,515,750
1,515,750
6,519692
195504
Total Coot
20151.4$
2P + Best Estimate Contingent Resources
Production & Development Forecast
Saleskl -All Phases
DelineatIon
Wells
2805 MS
0
0
0
0
7,505
6,060
11,960
15,300
15,300
15,309
15300
15,355
21,108
10,360
15350
14,450
12,755
0,355
9,750
0,150
5.100
5,100
5,109
5,150
5,150
5,160
5,100
5,155
3,404
1,755
S
6
0
0
0
0
0
0
0
0
5
5
0
S
S
S
6
0
6
30,547
21,787
20,210
20,210
20,210
21,194
50,344
$Eopd
871 MSlweO
175 ME well I yr
1,437 M5 (well
Average Cost
Well
2015 MO
4,541 MO (well
Facility end letrastrooturn Casts
Co9ee &
CPF
Infrasleoclare
Other
Malet.
2015 MS
2815 MS
2015 US
2015 MS
66,767
3,132
3,406
1,056
19,445
11,413
1,006
162,608
54,639
15,362
15,685
4,306
4,366
0
5
0
S
S
0
4,396
417
4,386
62,350
5
S
4,3W
355,450
2,560
805,175
6,250
S
4,366
10,060
S
15.621
1,224,425
1,414,750
11,667
S
25,726
10,560
0
35,084
1,212,650
757,675
6,250
S
51,041
353,150
2,500
S
61,146
417
50,525
S
66,199
0
0
S
66,199
S
66,199
S
S
S
0
S
66,199
S
5
S
66,159
0
S
0
66,159
0
S
0
66,159
0
S
0
66,100
0
S
0
66,109
0
S
66,199
0
0
0
66,199
S
S
0
S
56,199
0
S
66,199
0
S
5
0
66,199
0
0
0
66,199
5
0
S
66,199
0
5
0
60,656
0
0
S
65,656
0
65,056
0
S
0
0
0
65,547
6
5
0
60,547
0
S
0
65,547
0
5
5
65,553
0
S
0
60,469
5
5
5
65,475
0
0
0
57,067
0
5
39,054
5
0
0
5
38,010
0
0
0
32,889
5
0
5
26,029
0
0
0
9,670
0
5
0
5,506
0
5
0
4,479
0
0
8
3,536
0
0
0
549
S
0
5
5
Total
2015 US
75,207
231,597
164,440
58,786
21,W1
98,803
305,812
1,097,567
1,673,697
3.075,219
2,746,459
2,410,591
1,316,271
1,554,116
1,021,774
1,099,949
965,399
1,144,599
063,124
1,010,724
734,424
566,749
1,265,574
1,108,724
1,188,599
675,024
1,277,274
1,521,474
1,255,399
567,131
545,256
461,456
330,097
287,247
269,107
253,028
235,413
219,475
169,302
152,729
138,755
09,214
70.726
26,245
17,161
14,104
7,038
1,574
0
26,009,825
Lg30,055
251,650
4,786,625
Tolat
2515 MO
l3,460,500
1
Petroleum
GLJ Consultants
CapItal Cast
lnnalion
Factor
1000
1.525
1540
1.561
1.562
1 154
1125
1,149
1.172
1.195
1.219
1.243
1.268
1.294
1 319
I 346
1.373
1.409
1 428
1.457
1.406
1 516
1 546
1.577
1 608
1.641
1.073
I 707
1.741
1.776
1 011
1.548
I 865
1.922
1.061
2.505
2,540
2081
2,122
2,165
2,208
2.252
2257
2.343
2390
2436
2,407
2.539
2.567
1307 0461
Total
CarrootUS
75,267
236,137
171,591
62,354
23,772
100,087
445,748
1,280,258
2,195,569
3,675,170
3,347,919
2,997,765
1,669,350
2,549,222
1,348,259
1,465,252
1,325,206
1,662,015
1,232754
1,472,434
1,091,315
1,347,547
1,948,540
1,074,498
1,908,731
1,108,761
2,137,413
1,743,540
2,165,560
1,057,137
087,656
007,816
632,630
552,156
525,849
507,227
480,217
456,657
401,046
330,620
306,443
223,451
162,475
51,497
41,019
34,383
10,735
2,725
0
Total Caste
Total Facility and Well Capital Cast Metrics
Rem, capital (total prn( msStoIal 551):
DelIneatIon welts
PC SustainIng CepIlot
Total wells
Pad. 1461, pIping per woN
Cateqmy
UrIS, cmps CSS well
0
S
no
Year
2015
2016
2017
2018
20t9
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2038
2037
2036
2039
2040
2041
2042
2043
2044
2045
2046
2047
2049
2049
2050
2001
2052
2003
2554
2055
2056
2057
2050
2059
2060
2061
2082
2063
5
5
13
20
32
32
31
31
86
lEO
326
660
911
1,223
1,302
1,544
1,616
1,754
1,920
2,756
2.164
2,396
2,311
2,430
Z408
2,534
2,549
2,541
2,375
2.102
1,063
7.864
1,759
1,745
1,715
1,667
1,326
1,215
920
879
658
589
417
356
740
127
42
16
0
Produnlng
CSs
Wells
NCG t0(ection:
COO Wee Count
/074 Cost
total
Prodaclog
tnflll
Wall,
Steam Elf/denny:
FacIlity 000:
Bitumen production:
Steam /rrje5500:
0
0
0
0
0
5
5
S
0
9
0
0
0
0
0
0
S
S
5
0
0
5
5
0
5
0
0
0
0
0
5
0
9
0
5
5
bb0day
bbl/day (owe)
MMBtoThr
Mct0/bl
BItumen
Rate
bb0d
065
1,185
2,380
5,456
6,249
11.009
10.971
10,930
17,575
42.463
80,323
178,159
279,292
375301
454,245
409,401
517,871
518,945
510,927
516.609
517,447
514,490
572,599
500,55l
505,733
508,018
495,498
402,026
470.743
434,120
454,027
364,503
326,274
294,084
251,486
228,298
177,350
149,183
111,421
96.146
70,161
57,796
39,004
37,362
13,390
10,475
3,377
1,377
S
Steam
lnjeotleo
Anneal Annual
10016
bbod
CSOR
3,905 430
6.04
4,728 390
5.34
8,795 3.65
450
405
18,842 3,45
28,045 3.12
3.03
3.41
33,299 3.08
32,718 3.98
3,30
32,594 2.96
3.23
3.14
55,297 2.87
300
117,123 2.76
246,137 2.73
2.00
488,846 2,74
282
769.999 276
279
1.037.598 2.78
2.78
1,299,044 2.77
278
1,386,068 278
2,78
1,446.827 2.79
2.70
1,452.186 2,85
2.78
2.75
1,434,008 261
1,465,824 2.84
2.79
1,461,294 2.86
2.60
2.67
1,492,271
2.09
1,480,797 280
2.02
1,476,924 290
2.82
1,400,333 2.93
2.83
1,478.153 299
284
2.85
7,484,304 3.58
1,466,629 354
286
I,44g,404 359
2,87
1,352.349 3.12
2.89
318
2.90
1.276,571
2.91
1,171,060 3.22
2.92
1,584,862 339
977.508 3.32
293
3.45
868,591
294
792,613 3.47
295
3.47
914,687
296
533,097 3.57
2.97
2,98
350.559 3.56
2.98
351,100 365
254,896 3.63
2.99
299
213,735 3.70
146,021 3.57
2,99
117,500 3.73
2.99
45,075 3,37
3.50
36,655 3.51
3.00
9,642 2.60
3.00
3,974 2.69
3.00
350
5 5.00
S scObte average production
3,441
0
3,441
512,500
1,607,730
29,340
0400
331
-
Water
Penduotloo
bend
3,005
4,729
8,790
18,042
28,840
33.299
32,715
32,594
06,297
117,123
246,137
406,846
789,995
1,037.580
1,259,044
1,366,008
1,446.927
1,402,166
1,434,000
1,465,624
1,491,294
1,482,271
1,480,797
7,476,924
1,480,333
7,478,153
1,484,304
7,466,639
1,449,404
1,352,389
1,278,571
1,171,000
1,064,862
877,508
808,591
792,613
674,691
533,007
396,555
357,108
254,806
213,735
145,021
717,066
45,075
36,005
9,642
3,974
5
Annual
IWOR
4.30
399
355
340
3,12
309
2.98
2.98
2.87
2.76
2,73
2.74
2.76
278
2.77
278
2.79
2.80
281
2.84
2.86
298
2.59
2,00
253
296
300
304
308
3.12
3.76
3.22
3.26
3.32
3.40
3.47
2.47
3 57’
3.56
365
3.63
3,75
3,57
3,73
3.37
3.51
2.86
2.09
500
Other Goad Coot,’
04 Wet:
04
Water
Fin, Cony’
Cogen
Punt:
Op cost lntat/nc
1,552
1,091
3,5i
7,457
lt,938
13.210
13,597
13,038
20,103
46,849
98455
195,530
307,998
415.032
503,618
554,435
578,731
590,974
573,003
506,250
562,516
592,909
592,310
508,770
592,133
591,261
553,722
586,551
579,762
545,056
511,429
468,760
425,545
391792
355,230
317,545
245,972
213,239
159,622
140,445
101.959
05,494
59,409
40,034
18,030
14,722
3.857
1,550
0
7401,8
Fuel
Gas
0
0
0
0
0
0
0
5
0
0
5
0
0
5
5
5
0
0
5
0
0
0
0
0
S
5
S
5
5
0
0
0
9
0
5
0
5
5
5
0
0
NCG
InjectIng
Mofnd
0
0
0
0
0
0
0
Gas
P400
Currant
BfMof
3.18
3.93
3.89
4.13
436
403
488
5.13
538
5.56
587
5.78
5.98
8.01
8.13
5.20
6.36
6.51
6.64
5.77
097
7.05
7.19
7.33
7.48
7.63
7.78
7.03
6.09
825
8.42
8.59
9.76
8,94
9.11
938
9.40
9.07
687
10.06
10,28
70.47
15,55
1009
11 11
11,33
11 56
1179
1203
Gas
PrIce
Real
StUnt
3.18
3.58
373
3.89
4.05
419
4.33
4.46
459
405
455
4.65
4.65
465
465
469
4.60
465
465
4.65
4.65
465
4.65
4.65
4.65
4.69
4.65
4.55
465
4.65
4.65
4.65
465
465
465
465
4.65
4.65
4.05
465
4.65
4,65
455
465
4.65
465
4.65
4.65
465
0 MS / yr
5,000 5/ weftimmrfh
1.50 5/SOt
1.005/but
5/ mcI
U97jear/uoti
Atcnnt Aberta Spot Pfattt Gale * $0.10/Md
2% per War
#
Cogan
51,16,
0
0
0
0
0
0
0
0
0
5
5
0
0
5
0
0
0
0
0
0
0
0
0
0
0
S
5
0
0
5
0
0
0
5
0
0
5
0
5
5
5
0
5
0
0
0
0
0
0
054,900 us, yr
30.2 M$/ yr per mmblrulrr Installed capacIty
Stgemer
High Estimate Contingent Resources
257,680 MS/yr
503 MS / yr per MbbUdoy installed oapacrty
+
Battery’
3P
Table 4.3
ProductIon & Development Forecast
Satesk( MI Phase,
CoGeg
Power
Fool
Motod
0
0
0
5
0
0
0
5
S
0
5
0
0
5
5
0
5
0
9
0
0
S
0
S
0
0
0
0
0
5
0
0
5
0
0
0
0
0
0
0
0
0
5
0
0
0
0
5
0
ZJ,OJt,00ZOZ,0040.4
10,000,flt
Cools
Variable
2015 MS
1,923
2,374
4,517
9.008
15,584
19,230
17,940
17,861
27.933
05,999
139,237
275,971
433.960
564,154
750,250
778,796
811,620
814,170
603,145
917.707
823,075
822,712
621,133
817,609
817,2t0
913,285
813,556
799,666
798,754
731,356
587,803
627.309
567,309
517,981
467,317
414,296
321,462
278,258
205,746
180,791
131,450
109,656
75,090
59,907
23,783
19,769
5,366
2,204
0
,Ztr,*JO
Total
2015 MS
13,031
74,928
85.420
05,561
00,080
70,293
78,211
76,602
2tZ452
500,502
955,527
1,878.093
2.209,206
2,746,679
3,051,947
3,172,161
3,146,480
3,113,624
3,084,799
3,156,546
3,774,225
3,198,682
3,706,923
3,194,494
3.193,191
3,201,364
3,206,822
3,108,008
3,138,169
2,992,778
2,961,003
2,735,181
2,597.090
2,409,891
2,366.494
2,243,490
1,093,091
1,880,500
7.653.210
1,574,521
1,057,633
975,772
660,695
520,078
204,554
168,782
56,020
29,423
0
14U,IJ,Z41
Total
Cadent MS
13,031
15,227
93,677
90,798
86,594
00,442
88,078
06,393
240.021
607,914
1,164,782
2,099,409
2,866,491
3,553.123
4,026,583
4,269,311
4,319,454
4,360,105
4.405,952
4,598,495
4,716,732
4,949,135
4,920,919
5,537,395
5,735,999
5,252,177
5,366,354
5,429,060
5,463,612
5.374,708
5,219,539
5.053,491
4,883,015
4,76g,647
4.639,908
4,498,712
4795,620
3,912,728
3,560,606
3,408,436
2,335,295
2,204.390
1,916,238
1.219.640
400,855
411,466
139,321
74627
5
LJ GLJ
Operuong
Coot
Inflation
Fantor
1 000
1.020
1.040
1561
1 582
1.104
1,126
1.149
1.172
1.195
1.210
1.243
1.290
1,294
1.319
1.346
1 373
1.400
1.420
1.457
l.406
1.516
1.546
1.577
1608
1.647
1 673
7.707
1.741
7776
1 811
1.848
1.885
1.922
1961
2
2040
2.081
2122
2.165
2.209
2.252
2257
2.343
2365
2.439
2,497
2536
2.587
son toss tsar renal years at capaoty
1439 $Weintatlsa7yearsalcapadty
20.06 0/bin blat Is all yearo at eapacdy
Operating Costs at Peak Pndrethuc
NOt be, operatmg coot
Non-gao operabng coot
Total:
Operating
Flood
2015 MS
10,095
10,005
71,179
05,150
47,389
39,579
30.571
39,571
150,851
363,705
849243
1,080.355
1,353,673
1,456,397
1,498,918
1,452,602
1,352,938
1,374,592
1,300,431
1,344,071
1,344,935
1,309,991
1,300,811
1,374,635
1,371,287
1,394,505
1,306,407
1,305,651
1,307,723
1.343639
1,325,307
1,372,525
1,301,067
1,299093
1,396.443
1,291,259
l,254.431
1,242,443
1,178,333
1,155,447
753,191
724,059
466.704
360,757
l5O,l00
124,635
44.118
24,522
0
5.57 S/but inlet prc(ect tile
14.52 S/but total p44,01 tire
25.08 $0/ta total p44ont tire
Acetage Operating Coors
Nat Gas oyecasog coot
Non-gao operating cost
Tn/al:
Nat Gas
2015 MS
1,813
2,459
4,752
10,596
17,000
20304
20,092
27,241
33,809
79.490
107,547
331,767
52Z575
704,179
854,401
940,702
991,824
909,561
973.223
904.681
1,005,316
1,005,979
7,004,070
1,002,350
1,054,604
1,003,184
1.007.359
995,363
983,673
517.832
007,733
795,339
722,694
863,408
602,725
537,626
417,168
381,799
269,132
238,282
772,962
745,596
99,101
79,463
30,591
24,979
0,544
2,697
5
5.46 tint, (2015)
36.23 $0/b/12015)
4170 $0/in (2015)
tn/fiat Oporasog Coats
Net Gas operating coot
Non-gao operating cost
Total:
Petroleum
Consultants
Year
2915
2018
2517
2518
2019
2020
2521
2022
2923
2024
2025
2028
2027
2028
2029
2030
2031
2022
2033
2034
2035
2038
2037
2036
2039
2040
2047
2042
2043
2044
2045
2046
2547
2048
2049
2050
2051
2552
2553
2054
2055
2056
2057
2055
2059
2880
2061
2062
2063
2017
2023
2024
2025
2026
CBS
Wells
Starlap
5
5
8
16
3
S
5
5
36
99
161
339
248
312
159
167
78
136
72
342
42
284
34
221
75
180
75
220
37
92
5
0
5
5
5
0
5
S
5
0
0
0
0
0
0
0
5
5
5
Capital InflatIon
Producing
CBS
Wells
5
5
13
29
32
32
31
31
66
165
328
665
911
7223
1382
1544
1616
7754
1826
2158
2164
2396
2311
2439
2406
2534
2548
2547
2375
2152
1983
1864
1758
1745
1715
1667
1326
1215
925
879
656
586
417
356
149
127
42
18
6
WeO Deoeloperoet
10611
Wells
Startap
S
0
0
5
0
0
0
S
0
5
5
5
0
5
5
0
0
5
5
5
0
S
5
S
0
0
0
0
5
S
0
0
S
5
0
0
0
0
5
0
0
5
5
5
0
0
5
5
5
2% per year
Infrastroclone
Cogen
Other
Facility Maintenance Capital
Totat Remaining Facility, (nfrastvaotore, maintenance
Facapy
Porn
Phase 1
Phase 2
Phase 3
Phase 4
PhaseS
Total (anuses
Phase Ant Each Phase
Onslream
41,730
412,502
4(2.502
412502
412,500
1.697,730
Prodauteg
(dill
Watts
0
0
S
0
0
S
S
0
0
5
5
0
0
0
5
5
0
5
5
S
S
0
0
S
6
5
0
5
5
S
5
0
0
0
0
0
5
S
5
0
0
5
5
5
5
0
5
5
S
313
500ne
Wells
0
S
S
1
6
7
12
17
17
77
17
17
21
17
17
17
17
15
14
9
8
7
6
6
6
6
6
6
6
6
5
4
2
5
5
0
5
0
5
S
5
0
5
5
5
5
0
0
5
1 0% of capital lyr
10:702
125002
125000
125020
125,000
512502
Total Phase
Capacity (Sheen Day)
Od(bbtdl
Sttn (ShOd)
39
33
33
3.3
33
33
13,752,060
0
36,000
75,200
19,900
1,202
5
5
105,600
469,800
700,200
1,250,900
990,602
7,190,405
687,300
946,700
339,000
514,200
307,202
1,225,602
253,802
1.010,500
232,600
707,758
356,505
660006
334.550
900,000
217,500
336,805
36,500
0
6
0
0
0
0
5
5
5
0
0
0
5
0
0
5
5
5
5
CSS
Watts
DIC)AL
2015 MS
Dnslgn
SOB
Table 4.3
99,031
S
47,725
4,919,366
5
S
0
0
0
0
5
0
6
0
0
5
5
S
0
0
5
0
0
0
0
0
0
50,329
150,978
242,475
510,970
375,150
475,805
242,475
254,675
118,550
768,750
99,000
475,255
57,750
390,502
46,750
303,875
103,125
247,500
153.125
302,502
50,875
126,500
CSS
Wells
Padocath
2815 MS
18,672,300
6
5
5
0
0
0
0
0
0
0
0
5
5
0
5
5
5
0
5
5
5
5
5
0
0
5
0
0
5
0
0
5
5
5
5
5
0
S
0
5
5
S
0
6
S
5
0
5
5
S
97,939
S
28,506
3315671
13,936,780
5
284,414
2,844,S00
2,526,250
2,526,250
2.526.250
10007064
Ron Cost
2015 Mt
Well Costs
CSS
Wells
10511
Total
Welts
2515 MS
2815 MS
0
36.000
70,200
19,900
1,250
5
0
215,925
820,779
1,022,675
1,757,875
1,371,750
1,608,200
923,775
902,775
458.750
703,955
458,200
1,696,050
341,550
1,401,300
279,350
1,590,975
454,025
907,500
437.625
1,152,505
255,375
463,300
36 0’0
0
5
0
0
0
0
5
S
5
5
0
0
0
0
0
0
5
5
0
1,092
S
22,220
330,559
2,844,500
2,520,250
2,526,250
2.528,250
10,661,591
00,000
Spent
2015 MS
oo,aos
45,643
5
0
5
5
154,227
Total Cost
2015 MS
-
9,643,375
Matni
2815 Mt
875
875
2,275
5,575
5,600
5,000
5,425
5,425
11,550
26,870
57,050
116,375
159,425
214,025
241 850
270,200
282,800
306,950
319,050
377,380
378,700
419,300
404,425
426,825
421.459
443,450
445,500
444,675
415,625
376,600
347,025
326,205
357,650
305,375
300,125
291.725
232,050
212,625
181,500
153.825
115,150
102.550
72,975
52,350
26,075
22,229
7.350
3,155
0
$Mpd
13021
8295
4:920
4,702
4,702
4.700
4,824
Production & Development Porecast
Saleskl AU Phases
3P + High Estimate Contingent Resources
272,000
0
5
0
5
0
0
Delleoa800
Well,
2015 MS
0
0
0
850
7,500
9,950
10,200
14,450
14,450
14,450
14,450
14,450
20,200
74,450
14,450
74,490
14,450
12,750
13,102
7,650
6,800
5,950
5,105
5,100
9,100
5,150
5,100
5,100
5,150
5,100
5,100
3,400
1,700
Slbopd
65,324
30,847
21,156
20,210
20.210
20,210
25,804
10,507,664
87,939
25,506
3,315,671
FacIlIty and lefrastuotare Cost,
Cogee &
Other
Mdcc
2008 MS
2815 MS
3,408
1,096
11,413
1,586
70685
4,386
5
4,306
4,306
0
5
4,306
5
4,306
5
4,396
10,821
S
20,728
5
0
35,884
0
96.094
0
76,304
S
91,461
101,566
0
0
106,619
0
188,619
5
105679
5
106,619
0
158.819
188819
0
0
158,619
106,819
5
5
106,619
(06,619
5
5
106,819
106,619
S
158,819
0
5
106,579
S
705,619
0
106,619
0
106,679
5
158,619
106,619
0
5
(06,619
5
(06,619
5
106,618
0
106,819
5
103,587
5
101,607
0
66,539
5
64,031
0
42,963
S
32,741
5
14.375
5
15,875
0
3,505
5
2.766
0
0
CPF
totrastractare
2875 MS
20(8 MS
66,707
3,132
182,505
19,445
54,939
15,362
5
0
5
0
62,350
250
1,500
350,450
605,175
3,750
1,274,950
6,250
1,717,850
8,500
1,919,950
9,500
1,717,850
8,002
1,263,125
6.250
757,875
3,750
303,150
1,500
50525
250
0
5
0
5
0
5
0
0
S
0
0
0
5
0
5
0
5
0
5
S
S
0
0
0
S
0
0
0
0
5
0
0
5
5
0
5
5
0
5
0
0
5
5
0
5
0
5
0
S
0
0
0
0
0
0
0
0
0
5
0
S
0
0
5
0
5
869 MS )wn9
175 USI we9 0 yr
1,432 US) well
Watt costs
Aoota5e Coot
Walt
25(5 MS
4,503 MS tAns
42,524,555
Tetal
2015 MS
75,287
231,507
182,548
30,211
18688
78,536
371,961
1,049,111
7,930,596
2,813,576
3,804,709
3,265,019
3.191,554
2,895,336
1,569,291
000,784
1,107,619
832,519
2,135,3(6
633,119
1,893,419
811,219
1,607,119
992,569
1,440,619
992,794
1,660,119
524,769
990,644
525,119
459,744
436,219
415,969
411,994
406,744
396344
336,669
3(9,244
264,587
255,432
181,189
166,561
115.938
95,041
40.451
33,505
11,255
5,315
5
Total
28,567,725
Capital Cost
lefldflan
Factor
1,066
1,020
1,540
1.891
1.082
1.154
1.126
1149
1.172
1.195
1.219
1.243
1.266
1.294
1.319
1.346
1.373
1,402
1428
1457
1498
1518
1546
1 577
1555
1.641
1573
1.707
1.741
1.776
1.811
1,648
(SitS
1.922
1.961
2.000
2040
2581
2.122
2.165
2.208
2.252
2297
2.343
2395
2.436
2.467
2.530
2,597
E1 GLJ
61,110,464
272,050
919,300
9,590375
4
Total
2015 MS
13,793,020
1001 Stain
Total
Correct MS
75,287
236,137
189,427
32,081
20,227
86,711
478,689
1,205,099
2.271,375
3,361,687
4,837,919
4,084,508
4,547,662
2,594,116
2,065,369
1,212,350
1,520,798
1,765,727
3,049,761
1,2r3,697
2,813,521
1,229,537
2,484,573
1,565,181
2.317,145
1628,784
2,778.073
1.457,787
1,724,735
932,530
830,951
605,953
783,970
791,945
797,493
796,644
690,846
604,246
561,534
052.945
408,072
375,174
268,338
222,700
96,651
80,605
27,994
13,483
0
Costs
Total Fa0066 aed Watt Capital Cost Metdos
Rem. Capital (total pro). C055total 550)
068400000 svnss
FC 500taining Capital
Total wells
Pad, tact, plpin9 per welt
Category
DOS, corps CSS welt
Average
Petroleum
Consultants
or
4-
Os
Notes:
2016
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025+
WCS
Stream Quality
at Hardisty
Current
$Cdn/bbl
54.35
67.20
72.00
76.80
81.60
86.40
89.19
90.98
92.79
94.65
+2.0%/yr
Bitumen density 1023 kg!m3
Diluent density 665 kg/m3
Long term blend density target 924 kg/m3, based on pipelining from project
West Texas
Light, Sweet
Bank of
Intermediate
Crude Oil
Canada
Crude Oil at
(40 API, 0.3%S)
Oil Sands Average Noon Cushing Oklahoma
at Edmonton
Inflation
Rate
Current
Current
%
$US!$Cdn
$US/bbl
$Cdnlbbl
2.0
0.850
62.50
64.71
0.875
75.00
2.0
80.00
2.0
0.875
80.00
85.71
2.0
0.875
85.00
91.43
90.00
2.0
0.875
97.14
2.0
0.875
96.00
102,86
2.0
0.875
98,54
106.18
2.0
0.875
100.51
108.31
0.875
102.52
2.0
110.47
2.0
0.875
104.57
112.67
+2,0%/yr
0.875
+2.0%/yr
+2.0%/yr
Dil-bit
Quality Differential
Current
$Cdn/bbl
-0.75
-2.40
4.00
4.08
4.16
4.24
4,33
4.42
4.50
4.59
+2.0%/yr
-
DiI-bit
Stream Quality
at Hardisty
Current
$Cdnlbbl
53.60
64.80
68.00
72,72
77.44
82.16
84.86
86.56
88.29
90.06
+2.0%/yr
Table 5a
Bitumen Netback Pricing Reserves
GLJ -January 1,2015 PricIng Assumptions
Edmonton
Pentanes
Plus
SCdn/bbl
69.24
85.60
91.71
97.83
103.94
110.06
113.62
115.89
118.20
120.56
+2.0%/yr
Diluent
Transp. &
Postings+
$Cdn/bbl
11.70
11.70
11.70
8.43
5.16
5.15
5.16
5.15
5.15
5.15
+2.0%/yr
Diluent
at Field
Current
$Cdnlbbl
80.94
97.30
103.41
106.26
109.09
115.21
118.77
121.04
123.35
125.71
+2.0%/yr
Transportation
Current
$Cdnlbbl
12.70
12.70
12,70
7.98
3.26
3.25
3.25
3.25
3.25
3.25
+2.0%/yr
Diluent
to Bitumen
Blend
Ratio
0.240
0.240
0.240
0.333
0.426
0.426
0.426
0.426
0.426
0.426
Petroleum
GLJ Consultants
Bitumen
Wellhead
Current
$Cdn/bbl
31.29
41.25
43.75
50.92
59.32
63.44
65.78
67.24
68.71
70.23
+2.0%/yr
Notes:
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025+
WCS
Stream Quality
at Hardisty
Current
$Cdn/bbl
54.35
67.20
72.00
76,80
81.60
86.40
89.19
90.98
92.79
94.65
+2,0%/yr
Bitumen density 1023 kg/m3
Diluent densIty 665 kg/m3
Long term blend density target 924 kg/m3, based on pipelining from project
Light, Sweet
West Texas
Crude Oil
Intermediate
Bank of
(40 API. 0.3%S)
Canada
Crude Oil at
at Edmonton
Oil Sands Average Noon Cushing Oklahoma
Current
Rate
Current
Inflation
$Cdn/bbl
%
$US/$Cdn
$US/bbl
64.71
2.0
0.850
62.50
0.875
75.00
80.00
2.0
0.875
80.00
85,71
2.0
0.875
85.00
91.43
2.0
97.14
0.875
90.00
2.0
0,875
95.00
102.86
2.0
106.18
2.0
0.875
98.54
108.31
2.0
0.875
100.51
110.47
2.0
0.875
102.52
0.875
104.57
112.67
2.0
+2.0%/yr
0.875
+2.0%/yr
+2.0%/yr
Oil-bit
Stream Quality
at Hardisty
Current
$Cdn/bbl
53.60
64.80
68.00
72.72
77.44
82.16
84.86
86,56
88,29
90.06
+2.0%/yr
Oil-bit
Quality Differential
Current
$Cdn/bbl
-0.75
-2.40
-4.00
-4.08
4.16
-4.24
4.33
4.42
4.50
-4.59
+2.0%/yr
-
Edmonton
Pentanea
Plus
$Cdn/bbl
uv.x4
85.60
91.71
97.83
103.94
110.06
113.62
115.89
118.20
120.56
+2.0%/yr
Table 5b
Bitumen Netback Pricing Combined Reserves and Resources
GLJ -January 1,2015 Pricing Assumptions
Diluent
Transp. &
Postings+
$Cdn/bbl
11(0
11.70
11.70
8.43
5.15
2.70
1.50
1.50
1.50
1.50
+2.0%/yr
Diluent
at Field
Current
$Cdn/bbl
80.94
97.30
103.41
106.26
109.09
112.76
115.12
117.39
119.70
122.06
+2.0%/yr
Transportation
Current
$Cdn/bbl
12.70
12.70
12.70
7.98
3.25
2.25
1.75
1.75
1.75
1.75
+2.0%/yr
Diluent
to Bitumen
Blend
Ratio
0.240
0.240
0.240
0.333
0.426
0.426
0.426
0.426
0.426
0.426
Petro’eum
GLJ Consu(tants
Bitumen
Wellhead
Current
$Cdn/bbl
31.29
41.25
43.75
50.92
59.32
65.91
69.47
70.94
72.41
73.93
+2.0%/yr
0
OQ
Page: 92 of
Company:
Property:
Reserve Class:
Development Class:
Pricing:
Effective Date:
Laricina Energy Ltd.
Saleski
141
Probable
Undeveloped
CLI (2015-01)
December31, 2014
Economic Forecast
PRODUCTION FORECAST
Bitumen Production
Year
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057
2058
2059
2060
2061
2062
2063
2064
Tot.
1143197
Gross Oil Gross Daily
bbl/d
Wells
0
0
$
24
33
36
36
42
42
48
51
54
56
52
54
57
58
61
61
51
48
52
50
55
50
56
53
56
51
55
54
57
53
58
52
55
54
52
55
54
52
55
52
54
55
51
56
53
52
48
0
0
940
3,420
7,435
10,308
10,269
10,137
9,727
9,441
9,781
9,629
9,865
9,871
9,842
9,851
9,610
9,544
9,538
9,577
9,975
9,969
10,028
10,239
9,813
9,965
10,130
10,059
10,199
9,953
10,104
10,197
9,887
9,979
10,193
10,153
10,135
9,860
9,793
10,146
9,477
9,982
9,661
10,103
10,160
9,848
9,929
10,118
9,462
9,071
Company
Daily
bblld
0
0
564
2,052
4,461
6,185
6,161
6,082
5,836
5,664
5,869
5,777
5,919
5,923
5,905
5,910
5,766
5,726
5,723
5,746
5,985
5,981
6,017
6,143
5,888
5,979
6,078
6,036
6,119
5,972
6,062
6,118
5,932
5,987
6,116
6,092
6,081
5,916
5,876
6,088
5,686
5,989
5,797
6,062
6,096
5,909
5,957
6,071
5,677
5,443
Company
Yearly
Mbbl
0
0
206
749
1,628
2,257
2,249
2,220
2,130
2,068
2,142
2,109
2,161
2,162
2,155
2,157
2,105
2,090
2,089
2,097
2,185
2,183
2,196
2,242
2,149
2,182
2,219
2,203
2,234
2,180
2,213
2,233
2,165
2,185
2,232
2,223
2,220
2,159
2,145
2,222
2,075
2,186
2,116
2,213
2,225
2,157
2,174
2,216
2,072
1,987
100,165
Net Yearly
Mbbl
0
0
195
703
1,516
2,086
2,067
2,034
1,946
1,883
1,949
1,919
1,966
1,868
1,739
1,747
1,713
1,784
1,867
1,629
1,820
1,759
1,836
1,728
1,870
1,694
1,921
1,707
1,853
1,759
1,849
1,725
1,884
1,773
1,785
1,857
1,711
1,880
1,667
1,851
1,684
1,834
1,711
1,849
1,716
1,876
1,677
1,809
1,594
1,522
83,813
Price
$/bbl
0.00
0.00
43.75
50.92
59.32
63.44
65.79
67.24
68.72
70.23
71.63
73.06
74.52
76.01
77.54
79.09
80.67
82.28
83.93
85.61
87.32
89.06
90.84
92.66
94.52
96.41
98.33
100.30
102.31
104.35
106.44
108.57
110.74
112.95
115.21
117.52
119.87
122.27
124.71
127.20
129.75
132.34
134.99
137.69
140.44
143.25
146.12
149.04
152.02
155.06
102.32
Febrsary 04, 2015 14:32:22
Probable Undeveloped, GLJ (2015.01), pri
L
GLJ Petroleum
Consultants
Page: 93 of 141
Page 2
REVENUE AND EXPENSE FORECAST
Revenue Before Burdens
Working Interest
Year
2015
2016
2017
201$
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
203$
2039
2040
2041
2042
2043
2044
2045
2046
2047
204$
2049
2050
2051
2052
2053
2054
2055
2056
2057
205$
2059
2060
2061
2062
2063
2064
Tot.
Disc
1143197
Oil
MM$
0
0
9
38
97
143
148
149
146
145
153
154
161
164
167
171
170
172
175
180
191
194
200
20$
203
210
218
221
229
227
236
242
240
247
257
261
266
264
267
283
269
289
286
305
312
309
318
330
315
308
10,249
1,202
NGL+Sul
MM$
Gas
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Total
MM$
0
0
9
38
97
143
148
149
146
145
153
154
161
164
167
171
170
172
175
180
191
194
200
208
203
210
218
221
229
227
236
242
240
247
257
261
266
264
267
283
269
289
286
305
312
309
318
330
315
308
10,249
1,202
Probable Undeveloped, CU (20t50t), pri
Royalty Company
Interest Interest
Total
Total
MM$
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
9
38
97
143
14$
149
146
145
153
154
161
164
167
171
170
172
175
180
191
194
200
208
203
210
218
221
229
227
236
242
240
247
257
261
266
264
267
283
269
289
286
305
312
309
318
330
315
30$
10,249
1,202
Royalty Burdens
Pre-Processing
Gas Processing
Allowance
Crown
MM$
Crown
MM$
0
0
0
2
7
11
12
12
13
13
14
14
14
22
32
32
32
25
19
40
32
38
33
48
26
47
29
50
39
44
39
55
31
47
51
43
61
34
60
47
51
47
55
50
71
40
73
61
73
72
1,760
154
Other
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Total
Royalty
After
Process.
MM$
Other
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
It
12
12
13
13
14
14
14
22
32
32
32
25
19
40
32
38
33
48
26
47
29
50
39
44
39
55
31
47
51
43
61
34
60
47
51
47
55
50
71
40
73
61
73
72
1,760
154
Net
Revenue
After
Royalty
MM$
0
0
9
36
90
132
136
137
134
132
140
140
147
142
135
138
138
147
157
139
159
157
167
160
177
163
189
171
190
184
197
187
209
200
206
21$
205
230
208
235
219
243
231
255
241
269
245
270
242
236
8,488
1,047
Operating Expenses
Fixed
MM$
Variable
MM$
0
0
40
41
37
37
38
40
40
42
43
44
46
46
47
49
49
St
51
51
52
54
55
57
57
59
60
61
62
63
65
67
67
69
70
72
73
74
75
78
77
81
80
84
86
86
85
87
85
84
2,917
390
0
0
I
4
9
12
12
12
12
12
13
13
14
14
14
14
14
15
15
15
16
16
17
17
17
18
18
18
19
19
20
20
20
21
21
22
22
22
22
24
22
24
24
25
26
26
26
27
26
26
$56
102
Total
MM$
0
0
41
45
45
49
50
52
53
54
56
57
59
59
61
63
64
65
66
66
68
70
71
74
74
76
78
80
81
82
85
87
87
90
91
94
95
96
97
102
99
105
104
109
112
112
lIt
115
Ill
110
3,773
492
February 04, 20t5 14:32:22
I1 GLJ
Petroleum
Consultants
Page: 94 of 141
Page 3
Before Tax Cash Flow
Net Capital Investment
Year
Mineral
Tax
MM$
Capital Tax
MMS
Net Prod’n
Revenue
MM$
NPI
Burden
MM$
0
0
0
0
0
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
202$
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057
2058
2059
2060
2061
2062
2063
2064
Tot.
Disc
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Aband.
Costs
MM$
Other
Income
MM$
0
0
-33
-9
44
84
$6
85
81
78
83
83
87
83
74
75
75
81
90
74
91
87
95
86
103
$7
111
92
109
101
112
100
122
110
114
125
110
134
110
134
119
138
127
145
129
157
134
155
131
126
4,716
556
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Oper.
Income
MM$
—
0
0
-33
-9
44
84
86
85
81
78
83
82
86
83
74
75
75
80
86
73
91
86
95
85
102
86
109
90
108
100
111
99
121
108
114
122
109
132
110
131
119
134
127
143
128
155
132
153
129
107
4,653
552
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
1
4
1
0
1
0
1
1
1
2
1
1
1
1
1
1
3
0
2
1
2
0
3
0
3
0
2
1
1
1
2
2
19
63
3
Plant
MM$
Dev.
MM$
0
15
33
23
13
3
19
4
19
13
13
21
15
13
14
14
15
25
36
7
24
16
26
7
36
$
38
8
28
19
30
$
43
22
20
34
9
47
10
35
23
38
24
39
10
Tang.
MM$
44
128
75
17
11
4
15
5
15
II
II
17
13
II
12
12
13
19
27
7
19
14
20
8
27
9
29
9
22
16
24
9
32
18
17
26
10
36
II
28
20
30
21
31
12
42
12
28
11
10
1,066
317
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
55
12
36
10
8
1,038
166
Annual
MM$
Total
MMS
Cum.
MMS
-44
-143
-141
-49
21
77
52
76
48
55
60
44
58
58
48
48
47
37
24
59
47
56
49
70
39
70
42
73
58
65
57
82
46
67
77
62
91
49
89
68
76
67
82
73
106
59
108
89
108
89
2,549
69
44
143
108
40
23
7
34
9
33
23
23
38
28
25
26
27
27
44
63
14
43
30
46
15
64
16
67
17
50
35
54
17
75
40
37
60
19
83
21
63
43
68
45
70
22
97
24
64
22
16
2,104
483
10.0% Def
MM$
-44
-42
-166
-277
-312
-298
-253
-225
-188
-167
-145
-123
-10$
-90
-74
-62
-51
-41
-34
-30
-21
-14
-7
-1
6
10
16
19
25
29
32
36
40
42
44
47
49
52
54
56
58
59
60
62
63
65
65
67
68
69
69
69
69
-187
-328
-377
-356
-279
-227
-152
-104
-49
11
55
114
171
220
268
315
352
376
435
482
538
587
657
696
766
808
881
939
1,004
1,061
1,143
1,189
1,256
1,333
1,396
1,486
1,536
1,625
1,693
1,769
1,836
1,918
1,991
2,097
2,156
2,264
2,352
2,460
2,549
2,549
69
SUMMARY OF RESERVES
Product
Units
Mbbl
Mboe
Bitumen
Total: Oil Eq.
Working
Interest
Gross
166,941
166,941
100,165
100,165
Total
Company
R0yINPI
Interest
0
0
Oil Eq.
factor
Net
100,165
100,165
Reserve Life Indic. &r
Oil Equivalents
Remaining Reserves at Jan 01, 2015
83,813
83,813
Company
Mboe
1.000
1.000
Reserve
Life
% of
Total
100
100
100,165
100,165
Half
Life
Life
Index
50.0
50.0
486.6
486.6
27.0
27.0
PRODUCT REVENUE AND EXPENSES
Net Revenue After Royalties
Average First Year Unit Values
Product
Bitumen
Total: Oil Eq.
1143197
Units
$/bbl
$/boe
Base Price Price Adjust.
0.00
0.00
0.00
0.00
Wellhead
Price
0.00
0.00
Net Burdens
0.00
0.00
Operating
Expenses
0.00
0.00
Other
Expenses
0.00
0.00
Prod’n
Revenue
0.00
0.00
Undisc
MM$
% of
10% Disc
Total
MM$
8,488
8,488
Probable Undevelaped, EL) (2015.01), pri
L
% of
Total
100
100
1,047
1,047
100
100
Februaiy 04,
2015 14:32:22
Petroleum
GLJ Consultants
Page: 95 of 141
Page 4
INTEREST AND NET PRESENT VALUE SUMMARY
Net Present Value Before Income lax
Revenue Interests and Burdens
(%)
Initial
Working Interest
Capital Interest
Royalty Interest
Crown Royalty
Non-crown Royalty
MineralTax
Evaluator:
Run Dale:
1143197
0.0000
60.0000
0.0000
0.0000
0.0000
0.0000
Average
60.0000
60.0000
0.0000
17.1756
0.0000
0.0000
Disc.
Rate
%
0.0
5.0
8.0
10.0
12.0
15.0
20.0
Prod’n Operating Capital
Revenue Income Invest.
MM$
MM$
MM$
4,716
1,330
759
556
422
295
178
4,653
1,318
754
552
420
293
177
2,104
801
569
483
424
364
303
Cash flow
MM$
$/boe
2,549
516
185
69
-4
-71
-126
25.45
5.16
1.84
0.69
-0.04
-0.71
-1.26
tVong, Angie
february 04, 2015 14:31:42
Probable Undeveloped, GU (2015-01), pri
February 04,2015 l4:3222
LtJ GLJ
Petroleum
Consultants
Page: 96 of 141
Company:
Property
Laricina Energy Ltd.
Saleski
Reserve Class:
Devetopment Class
Pricing:
Effective Date:
Probable Plus Possible
Undeveloped
GLI (2015-01)
December 31, 2014
Economic Forecast
PRODUCTION FORECAST
Bitumen Production
Year
Company
Daily
bbl/d
Company
Yearly
Mbbl
Net Yearly
Mbbl
Price
$Ibbl
2046
0
0
8
24
27
27
27
27
30
33
39
39
42
45
48
44
45
45
4$
51
49
42
38
41
43
45
45
43
43
43
46
43
0
0
1,195
4,360
8,330
10,330
10,330
10,265
10,402
10,384
10,746
10,672
10,209
10,481
10,808
10,311
10,307
10,519
10,225
10,489
10,354
10,351
10,504
10,241
10,550
10,805
10,904
10,390
10,128
10,446
10,530
10,608
0
0
717
2,616
4,998
6,198
6,198
6,159
6,241
6,231
6,448
6,403
6,125
6,288
6,485
6,187
6,184
6,311
6,135
6,293
6,212
6,211
6,302
6,145
6,330
6,483
6,542
6,234
6,077
6,267
6,318
6,365
0
0
262
955
1,824
2,262
2,262
2,248
2,278
2,274
2,353
2,337
2,236
2,295
2,367
2,258
2,257
2,304
2,239
2,297
2,267
2,267
2,300
2,243
2,310
2,366
2,388
2,276
2,218
2,288
2,306
2,323
0
0
247
896
1,699
2,090
2,079
2,060
2,081
2,071
1,965
1,826
1,770
1,802
1,778
1,845
1,704
1,801
1,773
1,809
1,861
1,705
1,788
1,758
1,804
1,844
1,785
1,850
1,674
1,858
1,736
1,881
0.00
0.00
43.75
50.92
59.32
63.44
65.79
67.24
68.72
70.23
71.63
73.06
74.52
76.01
77.54
79.09
80.67
82.28
83.93
85.61
87.32
$9.06
90.84
92.66
94.52
96.41
98.33
100.30
102.31
104.35
106.44
108.57
2047
46
10,666
6,399
2,336
1,756
110.74
204$
2049
2050
2051
2052
2053
2054
2055
2056
2057
2058
2059
2060
2061
2062
2063
2064
Tot.
44
43
45
45
45
45
44
45
43
45
43
45
45
43
45
43
44
10,859
10,309
10,508
10,588
10,624
10,717
10,645
10,854
10,414
10,415
10,544
10,543
10,832
10,105
10,348
10,315
10,485
6,515
6,186
6,305
6,353
6,374
6,430
6,387
6,512
6,249
6,249
6,326
6,326
6,499
6,063
6,209
6,189
6,291
2,378
2,258
2,301
2,319
2,327
2,347
2,331
2,377
2,281
2,281
2,309
2,309
2,372
2,213
2,266
2,259
2,296
106,422
1,845
1,769
1,801
1,812
1,817
1,831
1,819
1,777
1,853
1,718
1,872
1,737
1,843
1,720
1,759
1,825
1,713
85,111
112.95
115.21
117.52
119.87
122.27
124.71
127.20
129.75
132.34
134.99
137.69
140.44
143.25
146.12
149.04
152.02
155.06
102.30
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
1143197
Gross Oil Gross Daily
Wells
bbl/d
Probable Plus Possible Undeveloped, GU (2015-01), pri
February 04. 2015 14:32:30
L1iI GLJ
Petroleum
Consultants
Page: 97 of 141
Page 2
REVENUE AND EXPENSE FORECAST
Revenue Before Burdens
Working Interest
Oil
Year
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057
205$
2059
2060
2061
2062
2063
2064
Tot.
Disc
1143197
MMS
0
0
II
49
108
144
149
151
157
160
169
171
167
174
184
179
182
190
188
197
198
202
209
208
218
228
235
228
227
239
245
252
259
269
260
270
278
284
293
297
308
302
30$
31$
324
340
323
338
343
356
10,887
1,280
Gas
MM$
NGL+Sul
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Total
MM$
0
0
11
49
108
144
149
151
157
160
169
171
167
174
184
179
182
190
188
197
198
202
209
208
218
228
235
228
227
239
245
252
259
269
260
270
278
284
293
297
308
302
30$
318
324
340
323
33$
343
356
10,887
1,280
Royalty Company
Interest Interest
Total
Total
MM$
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
II
49
108
144
149
151
157
160
169
171
167
174
184
179
182
190
188
197
198
202
209
208
218
228
235
228
227
239
245
252
259
269
260
270
27$
284
293
297
308
302
30$
31$
324
340
323
33$
343
356
10,887
1,280
Royalty Burdens
Pre-Processing
Gas Processing
Allowance
Crown
MM$
Crown
MM$
0
0
1
3
7
It
12
13
14
14
28
37
35
38
46
33
45
41
39
42
35
50
47
45
48
50
59
43
56
45
61
48
64
60
56
59
61
62
64
65
78
57
76
60
80
76
72
76
66
90
2,266
20$
Other
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Total
Royalty
After
Process.
MMS
Other
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
3
7
Il
12
13
14
14
28
37
35
38
46
33
45
41
39
42
35
50
47
45
48
50
59
43
56
45
61
48
64
60
56
59
61
62
64
65
7$
57
76
60
80
76
72
76
66
90
2,266
20$
Net
Revenue
After
Royalty
MM$
0
0
11
46
101
133
137
139
143
145
141
133
132
137
138
146
137
148
149
155
163
152
162
163
171
178
176
186
171
194
185
204
194
208
204
212
217
222
228
231
231
245
232
258
244
264
251
262
277
266
8,621
1,071
Operating Expenses
Fixed
MM$
Variable
MM$
0
0
40
41
37
35
36
37
39
40
41
42
42
44
45
45
46
47
48
50
50
50
51
52
54
56
57
57
57
59
61
62
64
65
65
67
69
70
72
73
75
75
77
78
80
83
75
78
80
$3
2,746
373
Probable Plus Possible Undeveloped, GLJ (20 15-01), pri
0
0
1
5
9
11
II
11
12
12
13
13
13
13
14
13
14
14
14
15
15
15
15
15
16
17
17
17
17
18
18
19
19
20
19
20
21
21
22
22
23
22
23
23
24
25
24
25
25
27
810
9$
February 04,
L
Total
MM$
0
0
42
46
46
46
47
48
50
52
54
55
55
57
59
58
59
61
62
64
65
65
66
67
70
72
74
74
74
77
79
80
83
85
84
87
89
91
93
95
97
97
99
102
104
10$
99
103
105
109
3,556
471
2015 14:32:30
GLJ Consultants
141
Page: 98 nt
Page 3
Before Tax Cash Flow
Net Capital Investment
Year
Mineral
Tax
MM$
Capital Tax
MM$
0
2015
2016
2017
201$
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
203$
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057
205$
2059
2060
2061
2062
2063
2064
Tot.
Disc
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Net Prod’n
Revenue
MM$
NPI
Burden
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Other
Income
MM$
Aband.
Costs
MM$
0
0
-31
0
55
87
90
90
93
93
87
79
77
80
79
88
78
87
87
90
98
87
96
96
101
105
101
112
97
117
106
124
112
124
120
125
128
131
135
137
133
148
133
156
140
156
152
159
173
156
5,065
601
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Oper.
Income
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
0
0
0
1
0
0
-31
0
55
87
90
90
93
93
87
79
77
80
78
87
78
87
87
89
95
86
96
96
100
105
101
110
97
116
105
123
111
123
119
124
127
130
134
136
132
147
132
154
140
154
152
157
171
139
5,018
599
1
1
1
1
1
0
2
0
2
2
17
47
2
0
0
0
0
0
0
0
Dev.
MMS
Plant
MM$
0
15
32
10
3
2
2
8
10
20
4
12
14
13
5
22
5
13
15
15
25
5
14
15
15
16
5
27
6
28
7
29
7
18
19
19
20
20
21
21
7
35
8
37
9
23
24
25
42
10
776
119
Tang.
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Total
MM$
44
12$
74
9
4
3
4
8
9
10
5
11
12
11
6
17
6
12
13
13
20
7
12
13
13
14
7
21
8
22
8
23
8
16
16
17
17
18
18
18
9
28
10
29
11
20
20
21
32
11
891
285
Annual
MM$
44
143
106
19
8
5
5
16
19
37
9
23
25
24
10
39
11
25
28
28
44
12
26
28
29
30
12
48
14
50
15
52
16
33
35
36
37
38
39
39
16
63
19
66
19
43
44
45
74
21
1,667
404
Cum.
MM$
-44
-143
-137
-19
47
82
84
74
74
57
78
56
52
56
68
48
67
62
59
62
50
74
70
67
72
75
88
62
83
67
90
71
96
89
84
87
90
92
95
97
116
84
113
89
121
112
108
112
97
11$
3,350
194
10.0% Dcf
MM$
-44
-187
-325
-344
-296
-215
-130
-56
17
74
152
208
260
316
383
431
498
560
619
681
731
805
875
942
1,014
1,088
1,177
1,239
1,323
1,389
1,479
1,550
1,646
1,735
1,820
1,907
1,997
2,090
2,185
2,282
2,398
2,482
2,595
2,684
2,804
2,916
3,024
3,135
3,232
3,350
3,350
194
-42
-166
-274
-28$
-257
-209
-163
-127
-95
-72
-43
-24
-9
7
24
35
49
60
71
80
87
97
105
112
119
126
133
137
143
147
152
155
160
163
166
169
172
175
177
179
182
183
185
187
189
190
191
192
193
194
194
194
SUMMARY OF RESERVES
Remaining Reserves at Jan 01, 2015
Product
Units
Mbbl
Mboe
Bitumen
Total: Oil Eq.
Working
Interest
Gross
177,369
177,369
106,422
106,422
Roy/NPI
Interest
Total
Company
0
0
Oil Equivalents
Oil Eq.
Factor
Net
106,422
106,422
85,111
85,111
Company
Mboe
1.000
1.000
Reserve Life Indie. (yr)
% of
Total
106,422
106,422
Reserve
Life
100
100
Life
Index
50.0
50.0
Half
Life
406.6
406.6
26.9
26.9
PRODUCT REVENUE AND EXPENSES
Average First Year Unit Values
Product
Bitumen
Total: OilEq.
t431 97
Units
5/bbl
$/boe
Base Price Price Adjust.
0.00
0.00
0.00
0.00
Wellhead
Price
0.00
0.00
Net Burdens
0.00
0.00
Operating
Expenses
0.00
0.00
Net Revenue After Royalties
Other
Expenses
0.00
0.00
Prodn
Revenue
0.00
0.00
Undisc
MM$
10% Disc
MlvI$
% of
Total
8,621
8,621
100
100
1,071
1,071
% of
Total
100
100
February 04,2015 14:32:30
Probable Plus Possible Undeveloped, GU (2015-01), pri
L
Petroleum
GLJ Consultants
Page: 99 of 141
Page 4
INTEREST AND NET PRESENT VALUE SUMMARY
Net Present Value Before Income Tax
Revenue Interests and Burdens (%)
Disc.
Rate
Initial
Workinglnterest
Capital Interest
Royalty Interest
Crown Royalty
Non-crown Royalty
Mineral Tax
Evaluator:
Run Date:
1143197
Average
%
0.0000
60.0000
0.0000
0.0000
0.0000
60.0000
60.0000
0.0000
20.8149
0.0000
0.0
5.0
8.0
10.0
12.0
0.0000
0.0000
15.0
20.0
Prod’n Operating Capital
Revenue Income Invest.
MlvI$
MMS
MM$
5,065
1,425
$17
601
5,018
1,417
814
599
459
323
199
45$
323
19$
Cash Flow
$lboe
MM$
1,667
646
469
404
360
3,350
771
344
194
98
31.48
7.24
314
26$
$
-69
0.0$
-0.65
3.23
1.83
0.92
Wong, Angie
February 04, 2015 14:3 1:42
Probable Plus Possible Undeveloped, 01.3(2015-01), pri
febnsaiy 04, 2015 l4:3230
I[J GLJ
Petroleum
Consultants
Page: 100 of 141
Company:
Property:
Laricina Energy Ltd.
Saleski
Resource Class:
Development Class:
Pricing:
Effective Date:
Contingent Resources
Best Estimate
GLJ (2015-01)
December 31, 2014
Economic Forecast
PRODUCTION FORECAST
Bitumen Production
Year
2015
2016
2017
201$
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057
2058
2059
2060
2061
2062
2063
2064
Tot.
1143197
Gross Oil Gross Daily
Wells
bbl/d
5
5
5
5
4
1
4
1
43
131
380
635
809
1,026
1,265
1,382
1,522
1,615
1,671
1,664
1,675
1,715
1,781
1,791
1,721
1,628
1,596
1,638
1,578
1,593
1,506
1,393
1,334
1,202
1,106
1,020
917
828
696
591
521
324
200
39
14
4
-28
-53
-52
-48
Company
Daily
bbl/d
Company
Yearly
Mbbl
Net Yearly
Mbbl
Price
$/bbl
795
477
174
168
31.30
909
866
895
1,023
697
776
1,112
7,610
28,626
78,682
149,698
218,899
256,527
277,051
287,057
288,628
288,503
288,853
287,269
283,070
279,775
273,519
270,404
271,979
270,979
269,442
265,704
267,215
270,026
265,776
242,329
222,757
193,852
165,662
140,382
115,674
95,788
75,271
58,348
46,889
26,902
14,336
-53
-3,018
-4,518
-7,333
-10,118
-9,462
-9,071
545
520
537
614
418
466
667
4,566
17,176
47,209
89,819
131,339
153,916
166,231
172,234
173,177
173,102
173,312
172,361
169,842
167,865
164,111
162,242
163,187
162,588
161,665
159,422
160,329
162,016
159,466
145,398
133,654
116,311
99,397
84,229
69,404
57,473
45,163
35,009
28,133
16,141
8,602
-32
-1,811
-2,711
-4,400
-6,071
-5,677
-5,443
199
190
196
224
153
170
244
1,667
6,269
17,231
32,784
47,939
56,179
60,674
62,865
63,210
63,182
63,259
62,912
61,992
61,271
59,901
59,218
59,563
59,344
59,008
58,189
58,520
59,136
58,205
53,070
48,784
42,454
36,280
30,744
25,333
20,977
16,484
12,778
10,269
5,892
3,140
-12
-661
-989
-1,606
-2,216
-2,072
-1,987
1,490,729
190
179
184
209
141
156
223
1,522
5,709
15,680
29,833
43,624
51,223
55,436
57,424
49,181
49,505
48,405
48,998
47,213
47,486
48,044
47,503
47,501
45,527
47,440
46,113
47,037
44,799
44,014
40,503
36,844
32,513
28,311
24,479
20,913
17,692
14,386
10,841
9,092
5,517
3,071
131
-374
-840
-1,159
-1,809
-1,594
-1,522
1,207,664
41.25
43.75
50.92
59.32
102.42
118.35
104.60
77.13
75.14
75.87
77.15
78.62
80.17
81.76
83.39
85.05
86.75
88.49
90.26
92.07
93.92
95.80
97.72
99.67
101.66
103.70
105.78
107.89
110.04
112.25
114.52
116.82
119.20
121.65
124.15
126.73
129.36
132.12
135.06
137.95
141.89
146.88
-1,243.74
122.96
134.36
143.40
149.04
152.02
155.06
99.26
Best Estimate Contingent Resonrces, GU (2015-01), pci
February 04, 2015 14:32:38
L
Petroleum
GLJ Consultants
Page: III of 141
Page 2
REVENUE AND EXPENSE FORECAST
Revenue Before Burdens
-
Working Interest
Year
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057
2058
2059
2060
2061
2062
2063
2064
Tot.
Disc
1143197
Oil
MMS
-
5
8
$
10
13
16
20
25
129
471
1,307
2,529
3,769
4,504
4,961
5,242
5,376
5,481
5,598
5,678
5,708
5,754
5,738
5,787
5,936
6,033
6,119
6,155
6,314
6,508
6,534
6,078
5,699
5,061
4,413
3,817
3,210
2,714
2,178
1,726
1,417
836
461
14
-81
-133
-230
-330
-315
-308
147,963
17,884
Gas
MMS
NGL+Sul
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Total
MMS
-
Royalty Company
Interest Interest
Total
Total
MMS
MMS
5
8
8
10
13
16
20
25
129
471
1,307
2,529
3,769
4,504
4,961
5,242
5,376
5,481
5,598
5,678
5,708
5,754
5,738
5,787
5,936
6,033
6,119
6,155
6,314
6,508
6,534
6,078
5,699
5,061
4,413
3,817
3,210
2,714
2,178
1,726
1,417
836
461
14
-81
-133
-230
-330
-315
-308
147,963
17,884
Best Estimate Contingent Resources, GLJ (2015-0 I), pri
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
5
8
8
10
13
16
20
25
129
471
1,307
2,529
3,769
4,504
4,961
5,242
5,376
5,481
5,598
5,678
5,708
5,754
5,738
5,787
5,936
6,033
6,119
6,155
6,314
6,508
6,534
6,078
5,699
5,061
4,413
3,817
3,210
2,714
2,178
1,726
1,417
836
461
14
-81
-133
-230
-330
-315
-308
147,963
17,884
RoyallyBurdens
Pre-Processing
-
Gas Processing
Allowance
Total
Royalty
After
Pracess.
MM$
--
Crown
MM$
0
0
0
1
1
1
2
2
11
42
118
228
339
398
429
455
1,193
1,186
1,313
1,256
1,360
1,294
1,135
1,145
1,201
1,405
1,199
1,278
1,239
1,577
1,592
1,439
1,393
1,184
969
777
561
425
279
262
163
55
13
-18
-39
-20
-65
-61
-73
-72
28,572
3,058
Other
MM$
Crown
MMS
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Other
MMS
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
2
2
II
42
118
228
339
398
429
455
1,193
1,186
1,313
1,256
1,360
1,294
1,135
1,145
1,201
1,405
1,199
1,278
1,239
1,577
1,592
1,439
1,393
1.184
969
777
561
425
279
262
163
55
13
-18
-39
-20
-65
-61
-73
-72
28,572
3,058
Net
Revenue
After
Royalty
MM$
5
8
8
9
12
14
18
23
117
429
1,190
2,302
3,430
4,106
4,531
4,788
4,183
4,295
4,284
4,422
4,348
4,460
4,603
4,642
4,735
4,629
4,920
4,877
5,075
4,930
4,942
4,639
4,306
3,876
3,444
3,040
2,649
2,289
1,899
1,464
1,253
781
449
32
-43
-112
-165
-270
-242
-236
119,390
14,826
Operating Expenses
-
fixed
MM$
Variable
MM$
7
8
7
7
6
5
6
6
93
276
574
879
1,085
1,149
1,138
1,138
1,163
1,196
1,226
1,250
1,272
1,307
1,339
1,368
1,393
1,407
1,432
1,456
1,472
1,501
1,516
1,484
1,466
1,410
1.359
1,317
1,269
1,229
1,072
783
737
566
419
93
20
6
-26
-87
-85
-84
39,628
4,604
1
1
1
1
1
1
1
1
9
33
94
186
281
336
368
386
395
403
412
419
424
434
438
446
459
466
474
476
484
495
500
469
445
399
353
312
269
232
189
153
131
77
43
0
-$
-11
-19
-27
-26
-26
11,381
1,346
-
Total
MMS
8
9
8
9
7
6
7
7
102
309
668
1,065
1,365
1,485
1,507
1,524
1,558
1,599
1,637
1,669
1,696
1,741
1,777
1,814
1,851
1,873
1,906
1,932
1,956
1,996
2,015
1,953
1,911
1,809
1,712
1.629
1,539
1,461
1,261
936
867
643
462
93
13
-6
45
-115
-111
-110
51,009
5,951
fobmaty 04, 2015 14:32:38
I[] GLJ
Petroleum
Consultants
Page:
102 of 141
Page 3
Net Capital Investment
Year
Mineral
Tax
Capital Tax
MM$
MM$
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057
2058
2059
2060
2061
2062
2063
2064
Tot.
Disc
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NPI
Burden
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Net Prod’n
Revenue
IvB5$
Other
Income
lvUnI$
-3
-l
0
1
5
8
12
16
16
119
522
t,237
2,064
2,621
3,025
3,263
2,626
2,696
2,647
2,753
2,652
2,719
2,826
2,828
2,884
2,756
3,014
2,945
3,119
2,934
2,926
2,666
2,395
2,068
1,732
1,410
1,111
828
638
528
386
138
-14
-60
-55
-107
-120
-155
-131
-126
68,362
8,876
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Aband.
Costs
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Oper.
Income
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
-3
-1
0
1
5
8
12
16
15
119
522
1,237
2,064
2,62t
3,024
3,263
2,623
2,678
2,629
2,729
2,648
2,713
2,790
2,776
2,827
2,735
2,981
2,899
3,079
2,904
2,687
2,661
2,359
2,041
1,708
1,381
1,084
790
605
507
321
98
-66
-67
-59
-115
-130
-153
-129
-107
67,527
8,821
10
18
25
4
7
36
52
57
20
33
46
40
30
40
25
36
27
24
29
27
36
33
21
64
40
54
7
4
8
9
-2
-2
-19
855
55
0
0
0
0
-
Dcv.
MM$
Before Tax Cash Flow
—
Plant
MM$
0
-l
-
Tang.
MM$
Total
MM$
0
0
1
0
-4
0
-2
-2
-6
10
-3
112
247
688
640
693
418
670
440
486
430
519
374
489
333
433
638
630
613
352
692
579
717
301
282
275
141
131
123
102
116
68
90
53
56
16
12
-25
0
-47
-8
-36
-10
-$
12,821
2,322
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-l
-3
49
237
635
1,037
1,494
1,345
1,068
555
535
343
375
338
399
303
381
276
346
484
480
469
297
524
450
544
267
256
252
164
159
155
143
154
123
130
83
84
51
40
-8
3
-29
-5
-28
-11
-10
14,933
3,582
0
0
0
-
Annual
MM$
1
-2
-5
-2
-9
58
233
747
1,284
2,182
1,985
1,761
974
1,205
783
862
768
918
677
870
612
778
1,122
1,110
1,082
649
1,216
1,029
1,261
569
538
527
305
291
278
244
270
191
220
135
141
67
52
-33
3
-76
-13
-64
-22
-18
27,754
5,904
Cum.
MM$
-4
1
5
3
14
-50
-222
-731
-1,269
-2,062
-1,464
-524
1,091
1,416
2,241
2,401
1,855
1,760
1,952
1,859
2,036
1,935
1,668
1,666
1,745
2,086
1,765
1,870
1,818
2,335
2,348
2,133
2,054
1,750
1,429
1,137
814
599
384
372
181
32
-120
-34
-62
-39
-117
-89
-108
-69
39,773
2,917
10.0% Dcf
MM$
-4
4
1
4
18
-32
-253
-984
-2,253
-4,3t5
-5,779
-6,303
-5,212
-3,796
-1,555
847
2,701
4,462
6,413
8,272
10,308
12,243
13,911
15,576
17,321
19,408
21,173
23,043
24,861
27,196
29,544
31,678
33,732
35,482
36,911
38,048
38,862
39,461
39,845
40,217
40,398
40,430
40,309
40,276
40,214
40,175
40,058
39,969
39,862
39,773
39,773
2,917
-4
4
0
2
12
-18
-137
495
-1,059
-1,893
-2,431
-2,606
-2,275
-1,884
-1,321
-773
-388
-56
279,
568
857
1,106
1,302
1,479
1,648
1,832
1,973
2,109
2,229
2,369
2,498
2,604
2,696
2,766
2,822
2,660
2,665
2,902
2,912
2,920
2,924
2,925
2,923
2,922
2,921
2,921
2,919
2,918
2,917
2,917
2,917
2,917
SUMMARY OF RESOURCES
Remaining Resources at Jan 01,2015
Product
Bitumen
Total: Oil Eq.
Units
Mbbl
Mboe
Gross
2,484,549
2,484,549
Working
Interest
1,490,729
1,490,729
RoyINPt
Interest
Total
Company
0
0
Oil Equivalents
Oil Eq.
Factor
Net
1,490,729
1,490,729
1,207,664
1,207,664
Company
Mboe
1.000
1.000
1,490,729
1,490,729
Resource Life Indic. (yr)
% of
Total
Resource
Life
100
100
50.0
50.0
Life
Index
Half
Life
23.4
23.4
999.9
999.9
PRODUCT REVENUE AND EXPENSES
Average First Year Unit Values
Product
Bitumen
Total: Oil Eq.
1143197
Units
$/bbl
Slboe
Base Price Price Adjust.
64.71
64.71
-33.41
-33.41
Best Estimate Contingent Resources, GLJ (2015.01), pri
Wellhead
Price
31.30
31.30
Net Burdens
1.03
1.03
Operating
Expenses
48.00
48.00
Net Revenue After Royalties
-
Other
Expenses
0.00
0.00
Prodn
Revenue
-17.74
-17.74
Undisc
MM$
% of
Total
119,390
119,390
100
100
10% Disc
MIvI$
14,826
14,826
% of
Total
100
100
February 04. 2015 14:32:38
LJ GLJ
Petroleum
Consultants
Page: 103 of 141
Page 4
INTEREST AND NET PRESENT VALUE SUMMARY
Net Present Value Before Income Tax
Revenue Interests and Burdens (%)
Initial
Working Interest
Capitallnterest
Royalty Interest
Crown Royalty
Non-crown Royalty
Mineral Tax
Evaluator:
Run Date:
1143197
60.0000
60.0000
0.0000
3.2805
0.0000
0.0000
Disc.
Rate
Average
60.0000
60.0000
0.0000
19.3003
0.0000
0.0000
%
0.0
5.0
8.0
10.0
12.0
15.0
20.0
Prodn Operating Capital
Revenue Income Invest.
MM$
Mlvt$
MM$
68,382
22,786
12,728
8,876
6,312
3,911
1,893
67,527
22,589
12,638
8,821
6,278
3,893
1,886
27,754
11,802
7,666
5,904
4,62$
3,302
1,991
Cash flow
MM$
$/boe
39,773
10,707
4,973
2,917
1,649
591
-104
26.68
7.24
3.34
1.96
1.10
0.40
-0.07
Wong, Angie
February 04, 2015 14:31:43
Oest Estimate Contingent Resources, GLJ (2015-01). pet
February 04, 2015 14:32:38
LIJ GLJ
Petroleum
Consu[tonts
Page: 104 of 141
Company:
Property
Resource Class:
Development Class
Pricing:
Effective Date:
laricina Energy Ltd.
Saleski
Contingent Resources
High Estimate
GLJ (2015-01)
December31, 2014
Economic Forecast
PRODUCTION FORECAST
Bitumen Production
Year
2015
2016
2017
201$
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
204$
2049
2050
2051
2052
2053
2054
2055
2056
2057
2058
2059
2060
2061
2062
2063
2064
Tot.
1143197
Gross Oil Gross Daily
bbl/d
Wells
5
5
5
5
5
5
4
4
36
132
287
626
869
1,178
1,334
1,500
1,571
1,709
1,778
2,105
2,115
2,354
2,273
2,398
2,365
2,489
2,503
2,498
2,332
2,109
1,937
1,821
1,712
1,701
1,672
1,622
1,281
1,170
875
835
613
543
372
313
104
82
-1
-45
-43
-44
High Estimate Contingent Resources, GLJ (2015-01), pri
909
1,185
1,191
1,126
919
768
641
665
7,113
32,078
79,477
167,488
269,083
364,820
443,437
488,090
507,564
508,426
500,703
506,121
507,094
504,139
502,085
498,310
495,183
489,213
484,594
472,435
460,615
423,683
393,497
353,896
315,608
283,226
251,176
217,787
166,770
138,560
100,705
85,501
59,307
47,361
29,389
20,819
2,847
-357
-6,728
-10,348
-10,315
-10,485
Company
Daily
bbl/d
545
711
715
676
552
461
384
399
4,268
19,247
47,686
100,493
161,450
218,892
266,062
292,854
304,538
305,056
300,422
303,672
304,256
302,483
301,251
298,986
297,110
293,528
290,757
283,461
276,369
254,210
236,098
212,337
189,365
169,935
150,706
130,672
100,062
$3,136
60,423
51,301
35,584
28,429
17,633
12,491
1,708
-214
-4,037
-6,209
-6,189
-6,291
Company
Yearly
Mbbl
199
260
261
241
201
168
140
146
1,558
7,025
17,406
36,680
58,929
79,896
97,113
106,892
111,156
111,345
109,654
110,840
111,054
110,406
109,957
109,130
108,445
107,138
106,126
103,463
100,875
92,787
86,176
77,503
69,118
62,026
55,008
47,695
36,523
30,345
22,054
18,725
12,988
10,377
6,436
4,559
623
-78
-1,473
-2,266
-2,259
-2,296
2,441,279
Net Yearly
Mbbl
192
247
247
231
187
155
129
133
1,423
6,397
16,015
33,679
53,890
72,992
88,748
86,927
82,851
81,701
85,618
81,554
85,795
81,458
84,168
$1,312
82,629
80,133
82,208
77,135
76,202
68,837
64,311
58,320
52,784
48,023
43,350
38,448
30,540
26,321
20,251
17,342
12,205
9,665
6,214
4,378
932
245
-1,047
-1,759
-1,825
-1,713
1,920,181
Pnce
$/bbl
31.30
41.25
43.75
50.92
59.32
99.12
129.03
128.00
77.81
75.12
75.91
77.15
78.59
80.13
81.71
83.33
$5.00
86.70
88.43
90.20
92.00
93.84
95.72
97.64
99.59
101.59
103.62
105.69
107.81
109.98
112.19
114.45
116.76
119.12
121.52
124.00
126.57
129.19
131.97
134.73
137.82
140.84
144.61
148.60
175.19
-77.90
142.26
149.04
152.02
155.06
99.27
Pebrusry 04,2015 14:32:15
L1 GLJ
Petroleum
Consultants
Page: 105 of 141
Page 2
REVENUE AND EXPENSE FORECAST
Revenue Before Burdens
Working Interest
Year
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057
2058
2059
2060
2061
2062
2063
2064
Tot.
Disc
1143197
Oil
MM$
6
11
11
13
12
17
18
19
121
528
1,321
2,630
4,631
6,402
7,935
8,908
9,448
9,653
9,697
9,998
10,217
10,361
10,525
10,655
10,800
10,884
10,997
10,935
10,875
10,204
9,668
8,870
8,070
7,389
6,685
5,914
4,623
3,920
2,910
2,523
1,790
1,461
931
678
109
6
-210
-338
-343
-356
242,334
28,687
Gas
MM$
NGL+Sul
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Total
MM$
6
11
11
13
12
17
18
19
121
528
1,321
2,830
4,631
6,402
7,935
8,908
9,446
9,653
9,697
9,996
10,217
10,361
10,525
10,655
10,800
10,884
10,997
10,935
10,875
10,204
9,668
8,870
8,070
7,389
6,685
5,914
4,623
3,920
2,910
2,523
1,790
1,461
931
678
109
6
-210
-338
-343
-356
242,334
28,687
Royalty Company
Interest Interest
Total
Total
MM$
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
6
11
II
13
12
17
18
19
121
528
1,321
2,830
4,631
6,402
7,935
8,908
9,448
9,653
9,697
9,998
10,217
10,361
10,525
10,655
10,800
10,884
10,997
10,935
10,875
10,204
9,668
8,870
8,070
7,369
6,685
5,914
4,623
3,920
2,910
2,523
1,790
1,461
931
678
109
6
-210
-338
-343
-356
242,334
28,687
Royalty Burdens
Pro-Processing
Gas Processing
Allowance
Crown
MM$
Crown
MM$
10
47
106
233
397
554
685
1,664
2,406
2,570
2,125
2,641
2,323
2,717
2,468
2,716
2,571
2,743
2,479
2,782
2,660
2,633
2,453
2,195
1,907
1,668
1,417
1,147
758
521
240
169
111
102
36
29
-41
-45
-62
-76
-66
-90
51,930
5,752
Other
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Total
Royalty
After
Process.
MM$
Other
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
2
10
47
106
233
397
554
685
1,664
2,406
2,570
2,125
2,641
2,323
2,717
2,466
2,716
2,571
2,743
2,479
2,782
2,660
2,633
2,453
2,195
1,907
1,668
1,417
1,147
758
521
240
189
111
102
36
29
-41
-45
-62
-76
-66
-90
51,930
5,752
Net
Revenue
After
Royalty
MM$
6
10
11
12
II
15
17
17
Ill
481
1,215
2,597
4,234
5,848
7,250
7,244
7,042
7,084
7,571
7,357
7,894
7,645
8,057
7,939
8,229
8,141
8,518
8,153
8,215
7,571
7,215
6,676
6,163
5,721
5,268
4,767
3,865
3,399
2,670
2,334
1,679
1,359
895
648
151
51
-148
-262
-277
-266
190,404
22,934
Operating Expenses
Fixed
MM$
Variable
MM$
7
8
7
7
5
5
5
5
91
278
556
958
1,347
1,635
1,810
1,888
1,877
1,885
1,907
1,995
2,045
2,111
2,143
2,197
2,239
2,295
2,347
2,382
2,399
2,350
2,323
2,275
2,225
2,199
2,169
2,128
1,977
1,933
1,772
1,738
1,152
1,099
731
569
179
136
0
-78
-80
-83
63,148
6,822
High Estimate Contingent Resources, GLJ (2015-01), pri
1
1
1
1
1
1
1
1
8
35
89
193
318
440
547
616
655
670
674
700
720
733
746
758
773
784
799
802
805
762
729
677
622
577
531
477
373
324
240
213
151
126
81
61
10
3
-16
-25
-25
-27
17,739
2,034
Total
MM$
8
9
8
8
6
6
6
6
99
313
645
1,151
1,665
2,075
2,357
2,503
2,532
2,555
2,582
2,695
2,765
2,844
2,890
2,955
3,012
3,079
3,146
3,184
3,204
3,112
3,052
2,952
2,847
2,777
2,700
2,605
2,350
2,257
2,012
1,950
1,304
1,225
812
629
189
139
-16
-103
-105
-109
80,887
6,656
February 04, 2015 14:32:15
L
GLJ Consultants
Page: 106 of 141
Page 3
Before Tax Cash flow
Net Capital Investment
Year
Mineral
Tax
MMS
2015
2016
2017
2016
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057
2058
2059
2060
2061
2062
2063
2064
Tot.
Disc
CapitalTax
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
o
o
o
Net Prod’n
Revenue
MM$
NPI
Burden
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
o
o
o
Other
Income
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-2
2
3
5
9
11
11
12
168
570
1,446
2,569
3,772
4,894
4,741
4,510
4,529
4,990
4,662
5,129
4,801
5,167
4,984
5,218
5,062
5,373
4,970
5,011
4,459
4,163
3,724
3.316
2,944
2,568
2,162
1,514
1,142
658
384
375
134
84
19
-39
-88
-132
-159
-173
-156
109,516
14,078
Oper.
Income
MMS
Aband.
Costs
MM$
—
Dcv.
MM$
-2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
3
6
9
26
22
25
13
14
56
50
82
44
32
29
3
7
14
101
33
91
12
71
23
56
20
71
8
29
15
-2
-2
-17
936
47
Tang.
MM$
Plant
MM$
II
11
12
168
570
1,446
2,569
3,772
4,893
4,741
4,510
4,529
4,987
4,656
5,120
4,775
5,146
4,959
5,205
5,048
5,316
4,919
4,929
4,415
4,131
3,695
3,313
2,936
2,554
2,061
1,481
1,051
647
313
352
78
63
-53
47
-118
-147
-157
-171
-139
108,570
14,031
4
89
263
438
803
660
829
524
546
339
490
353
1,028
366
931
379
821
488
757
507
930
415
548
240
223
190
203
194
193
191
151
139
102
99
84
48
52
16
14
-3
-17
-25
-42
-10
14,550
2,539
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
o
0
0
0
0
0
0
0
0
Cum.
MM$
-3
1
-2
-5
1
4
47
246
707
1,344
1,981
2,774
2,428
2,403
1,533
1,229
689
901
675
1,802
700
1,644
726
1,464
911
1,361
947
1,654
797
1,021
510
484
432
455
442
443
442
377
361
298
293
224
162
141
68
39
6
-27
-45
-74
-21
34,991
7,349
1
0
-2
1
2
44
241
618
1,081
1,542
1,970
1,768
1,574
1,009
683
350
412
322
774
334
713
347
643
423
604
440
724
382
473
270
261
241
252
248
250
251
227
222
196
194
139
114
89
52
25
9
-10
-21
-32
-11
20,441
4,810
0
-1
-3
Annual
MM$
Total
MM$
10.0%Dcf
MM$
-3
-1
-3
-1
6
9
10
-28
-263
-959
-2,291
-4,104
-6,307
-7,289
-7,123
-4,883
-1,219
2,833
6,441
10,296
13,481
17,437
20,913
24,962
28,643
32,692
36,535
40,635
44,297
48,419
52,327
56,232
59,880
63,144
66,001
68,496
70,607
72,226
73,330
74,021
74,369
74,389
74,518
74,434
74,356
74,235
74,150
74,027
73,906
73,795
73.698
73,580
73,580
6,682
-36
-235
-696
-1,332
-1,813
-2,203
-982
166
2,240
3,664
4,052
3,609
3,854
3,186
3,955
3,476
4,049
3,681
4,049
3,844
4,100
3,662
4,122
3,908
3,905
3,648
3,264
2,858
2,495
2,111
1,619
1,104
691
348
20
128
-84
-78
-121
-85
-124
-120
-112
-97
-118
73,580
6,682
5
7
7
-15
-142
482
-1,075
-1,808
-2,618
-2,946
-2,896
-2,277
-1,357
-432
317
1,044
1,590
2,207
2,699
3,221
3,652
4,083
4,455
4,816
5,109
5,409
5,667
5,902
6,101
6,263
6,393
6,495
6,574
6,629
6,663
6,682
6,691
6,691
6,694
6,693
6,691
6,689
6,688
6,686
6,685
6,684
6,683
6,682
6,682
6,682
SUMMARY OF RESOURCES
Remaining Resources at Jan 01, 2015
Product
Units
Mbbl
Mboe
Bitumen
Total:OilEq.
Gross
4,068,798
4,068,798
Working
Interest
2,441,279
2,441,279
Total
Company
RoyINPI
Interest
0
0
Oil Eq.
factor
Net
2,441,279
2,441,279
Resource Life lndfc.(yr)
Oil Equivalents
1,920,181
1,920,181
Company
Mboe
1.000
1.000
2,441,279
2,441,279
% of
Total
Resource
Life
100
100
50.0
50.0
Life
Index
Half
Life
23.4
23.4
999.9
999.9
PRODUCT REVENUE AND EXPENSES
Net Revenue After Royalties
Average First Year Unit Values
Product
Bitumen
Total: Oil Eq.
1143197
Units
S/bbl
$/boe
Base Price Price Adjust.
64.71
64.71
-33.41
-33.41
High Estimate Contingent Resources, 0L3 (2015-01), pci
Welihead
Price
31.30
31.30
Net Burdens
1.03
1.03
Operating
Expenses
41.70
41.70
Other
Expenses
0.00
0.00
Prodn
Revenue
-11.43
-11.43
Undisc
MM$
% of
Total
190,404
190,404
100
100
10% Disc
MM$
22,934
22,934
% of
Total
100
100
Eehruary 04, 2015 14:32:15
I GLJ
Petroleum
Consultants
Page: 107 of 141
Page 4
INTEREST AND NET PRESENT VALUE SUMMARY
Net Present Value Before Income Tax
Revenue Interests and Burdens C %)
Initial
Working Interest
Capital Interest
Royalty Interest
Crown Royalty
Non-crown Royalty
Mineral Tax
Evaluator:
Run Date:
1143197
60.0000
60.0000
0.0000
3.2805
0.0000
0.0000
Average
60.0000
60.0000
0.0000
21.4292
0.0000
0.0000
Disc.
Rate
%
0.0
5.0
8.0
10.0
12.0
15.0
20.0
Prod’n Operating Capital
Revenue Income Invest.
MMS
MM$
MM$
109,516
36,514
20,293
14,078
9,950
6,098
2,894
108,570
36,321
20,212
14,031
9,922
6,085
2,890
34,991
14,782
9,570
7,349
5,741
4,069
2,423
Cash Flow
MM$
$Iboe
73,580
21,539
10,642
6,682
4,181
2,016
467
30.14
8.82
4.36
2.74
1.71
0.83
0.19
Wong, Angie
februaty 04, 2015 14:31:43
High Estimate Contingent Resources, GU (2015.01). pri
Februmy 04, 2015 14:32:15
L1I1 GLJ
Petroleum
Consultants
Page: 108 of 141
APPENDIX I
This section summarizes the results of combined reserves, contingent resources and prospective resources cases,.
referred to as the remaining recoverable resources. Reserves and resources have different classification criteria and
caution is advised in interpreting the results of the aggregation Reserves are commercial and have effectively one
hundred percent chance of development Contingent and prospective resources are subject to the risk of
development and prospective resources are subject to the risk of discovery With reference to item 5 16 of National
instrument 51-1 01, a reporting issuer must not disclose the sum of reserves, contingent resources and/or
prospective resources.
LIJ GLJ
Petroleum
Consultants
Page: 09 o1141
APPENDIX I
COMBII1ED RESERVES AN1 RESOURCES
Page
APPENDIX I COVER PAGE
108
SUMMARY OF RESOURCES AND VALUES
110
FORECAST GROSS LEASE TOTAL OIL PRODUCTION
111
RESOURCES AND PRESENT VALUE SUMMARY
112
VOLUMETRIC PARAMETERS SUMMARY RESERVES
RESOURCES
-
+
CONTINGENT
113
2P + BEST ESTIMATE CONTINGENT RESOURCES
114
3P + HIGH ESTIMATE CONTiNGENT RESOURCES
11$
Fthraay 14,2015 l44323
L
GLJ Consultants
Page: 110 of 141
Company:
Property:
Laricina
Saleski
Energy Ltd.
Resource Class:
Development Class:
Pricing:
Effective Date:
Various
Classifications
GLJ (2015.01)
December31, 2014
Summary of Resources and Values
2P
3P
+
+
Best
Estimate
Contingent
Resources
High
Estimate
Contingent
Resources
MARKETABLE RESOURCES
Bitumen MbJJ)
Gross Lease
Total Company Interest
Net After Royalty
Oil Equivalent (Mboe)
Gross Lease
Total Company Interest
Net After Royalty
BEFORE TAX PRESENT VALUE (MM$)
0%
5%
8%
10%
12%
15%
20%
FIRST 6 YEARS BEFORE TAX CASH FLOW (MM$)
2015
2016
2017
2018
2019
2020
BOR Factors:
HVY OIL
CONO
1.0
1.0
Rrn D,Le, Fthn.ry
04, zOis 14)l,43
1143197
Class (1C2,RC3), GLJ (2015.0!) psum
RES GAS 6.0
SLN GAS 6.0
PROPANE 1.0
BUTANE 1.0
2,651,490
1,590,894
1,291,477
4,246,167
2,547,700
2,005,292
2,651,490
1,590,894
1,291,477
4,246,167
2,547,700
2,005,292
42,322
11,304
5,157
2,986
1,646
520
-230
76,930
22,310
10,986
6,g76
4,279
2,024
397
-48
-143
-136
-46
35
26
-47
-141
-130
-16
48
44
ETHANE 1.0
SULPHUR 0.0
Februsry 04, 2015 14:32:46
—
L
GLJ Petroleum
Consultants
\
t
\
0
0
0
0
0
2 232425 2627 2829 30 3 32
SI1eS1
Ltd.
Effect
38
‘Year
42
Gross Lease Total
t
FOteC
’)
52
GLJ(2O1O
s s
Le°e
so
ic2
C3
—
Entity Description
Laricina Energy Ltd.
Saleski
1143197
Class (tC2,RC3), GU (2015-01), rpv
3P + High Estin,ate L’ontingent Resources
Saleski Total
Saleski Total
2P + Best Estimate Contingent Resources
Company:
Property:
Gas
Ref
0
0
4,246
2,651
Oil
MMbbl
0
0
NGL
MM5bI
0
0
Sulphur
MMlt
Gross Lease Resources
Gas
Ref
0
0
2,548
1,591
Oil
MMbbl
-
NGL
MMbbl
0
0
0
0
Sulphur
MMlt
Company Interest Resources
Gas
Ref
0
0
2,005
1,291
Oil
MMbbl
NGL
MMbbl
0
0
0
0
Sulphur
MMIt
Net Interest Resources
Resources and Present Value Summary
Effective Date:
Pricing:
76,930
42,322
0%
Resource Class:
Development Class:
22,310
11,304
5%
10,986
5,157
8%
6,876
2,986
10%
2,024
520
15%
397
-230
20%
GLJ
Petroleum
Consultants
February 10,2015 08:47:27
4,279
1,646
12%
nefore Income Tax
Discounted Present Value fMM$)
December 31,2014
Classifications
GLJ (201$-UI)
Various
5
‘a
so
Area
-
-
-
-
-
-
-
17%
17%
17%
17%
17%
17%
15%
15%
15%
18%
18%
18%
18%
18%
17%
17%
17%
17%
17%
17%
19%
19%
19%
18%
18%
18%
18%
18%
Sw
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
1.005
FVF
Notes:
The economic threshold for development is 300 Mbbl/CSS well.
The recoverable volumes above may not match the economic forecasts due to economic limit considerations.
The contingent resources have not been risked for the chance of development.
-
18%
18%
19%
19%
19%
19%
24%
24%
24%
24%
24%
24%
24%
23%
18%
18%
18%
18%
18%
18%
24%
24%
24%
24%
24%
24%
24%
23%
Porosity
Probable + Possible Reserves ÷ High Estimate Contingent Resources
17.8
19.7
PlC
11.8
17.9
P2C
22.4
231
Grosmont C Pad 1
1,886
21.6
GrosmontC-ReserveArea
8,905
20.7
GrosmontC-Phase2
11,202
16.5
Grosmont C-Remaining
19.7
24.8
P1D
19.7
24.8
12D (Producer)
24.8
21.1
P30
36.2
231
GrosmontD&lreton-Pad 1
33.7
1.886
Grosmont 0 & lreton Reserve Area
8,876
31.2
Grosmont D & lreton Phase 2
26.1
31,349
GrosmontD & Ireton Remaining
64,658
24.5
Total: Prob. + Poss. + High Est. Cont.
-
-
17.8
17.9
19.3
18.5
17.7
13.3
32.7
32.9
33.1
36.2
33.7
31.2
26.8
36.6
{
Net Pay
Probable Reserves + Best Estimate Contingent Resources
19.7
PlC
11.8
P2C
231
GrosmontC-Pad 1
1886
Grosmont C Reserve Area
8905
GrosmontC-Phase2
11202
Grosmont C Remaining
19.7
PID
19.7
l2D (Producer)
21.1
P3D
231
Grosmont D & Ireton Pad 1
1,886
Grosmont D & Ireton Reserve Area
8,876
Grosmont D & Ireton Phase 2
29,709
Grosmont D & Ireton Remaining
40,771
Total: Prob. + Best Est. Contingent
EntitV Description
1,333
795
20,550
162,073
736,282
747.584
2,527
2,526
2,708
42,119
320,797
1,398,004
4,117,547
7,554,845
1,333
795
16,905
132,356
596,417
564,134
3,243
3,257
3,504
62,119
320,797
1,398,004
4,009,209
7,092,075
BlIP
62.1%
64.1%
62.5%
62.1%
61.8%
59.4%
54.1%
54.1%
54.1%
57.2%
57.0%
56.6%
54.2%
56.2%
43.4%
44.9%
41.0%
40.5%
39.8%
35.2%
35.6%
35.6%
35.6%
39.2%
39.1%
38.6%
36.6%
37.4%
Recovery
Factor
Volumetric Parameters Summary
Reserves Plus Contingent Resources
Saleski
827
510
12,835
100,726
454,874
443,806
1,367
1,366
1,465
24,079
182,904
790,874
2,231,530
4,247,163
578
357
6,933
53,574
237,598
198,704
1,156
1,160
1,248
16,505
125,423
540,290
1,468,558
2,652,084
Gross Lease
Original
Recoverable
Volumes
Ji4fl
161
176
0
0
0
0
115
17
24
0
0
0
0
493
161
176
0
0
0
0
115
17
24
0
0
0
0
493
Gross Lease
Production
to
2014-12-31
666
333
12,835
100,726
454,874
443,806
1,252
1,349
1,441
24,079
182,904
790,874
2,231,530
4,246,670
417
181
6,933
53,574
237,598
198704
1,041
1,143
1,224
16,505
125,423
540,290
1,468,558
2,651,590
Consultants
400
200
7701
60,435
272,924
266,284
751
809
865
14,447
109,743
474,525
1,338,918
2,548,002
250
108
4160
32,144
142,559
119,223
625
686
734
9,903
75,254
324,174
881,135
1,590,954
L] GLJ
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
60%
Company
Gross Lease
Interest
Remaining
Remaining
Recoverable
Recoverable
Working Volumes
Volumes
Interest
LM1)
Page: 114 of 141
Company:
Property
Resource Class:
Development Class
Pricing:
Effective Date:
Laricina Energy Ltd.
Saleski
2P+ Contingent Resources
Total Best Estimate
CU (2015-01)
December 31,2014
Economic Forecast
PRODUCTION FORECAST
Bitumen Production
Year
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057
2058
2059
2060
2061
Tot.
1143197
Gross Oil Gross Daily
Wells
bbVd
5
5
13
29
37
37
40
43
85
179
431
689
955
1,078
1,319
1,439
1,580
1,676
1,732
1,715
1,723
1,767
1831
1 846
1771
1,684
1,649
1,694
1,629
1,648
1560
1,450
1,387
1260
1158
1,075
971
880
751
645
573
379
252
93
69
55
28
795
909
1,806
4,315
8,458
11,005
11,045
11,250
17,337
38,067
88,463
159,327
228,764
266,398
286,893
296,907
298,238
298,047
298,391
296,846
293,045
289,743
283546
280 643
281792
280,944
279,572
275,763
277,414
279,980
275880
252,526
232,644
203 831
175855
150,534
125,809
105,647
85,064
68,495
56,366
36,885
23,997
10,051
7,142
5,330
2,596
Company
Daily
bbl/d
477
545
1,084
2,589
5,075
6,603
6,627
6,750
10,402
22,840
53,078
95,596
137,258
159,839
172,136
178,144
178,943
178,828
179,035
178,108
175,827
173,846
170128
168 386
169075
168,566
167,743
165,458
166,448
167,988
165528
151,516
139,586
122299
105513
90,321
75,486
63,388
51,039
41,097
33,819
22,131
14,398
6,030
4,285
3,198
1,558
Company
Yearly
Mbbl
174
199
396
945
1,852
2,410
2,419
2,464
3,797
8,337
19,373
34,893
50,099
58,341
62,830
65,023
65,314
65,272
65,348
65,009
64,177
63,454
62097
61 461
61713
61,527
61,226
60,392
60,754
61,316
60418
55,303
50,949
44639
38512
32,967
27,552
23,137
18,629
15,000
12,344
8,078
5,255
2,201
1,564
1,167
569
1,590,894
Net Yearly
Mbbl
168
190
374
887
1,725
2,227
2,223
2,257
3,468
7,591
17,630
31,752
45,590
53,090
57,175
59,171
50,894
51,289
50,273
50,627
49,033
49,245
49880
49 232
49371
47,222
49,361
47,820
48,890
46,559
45863
42,228
38,728
34285
30096
26,336
22,624
19,571
16,053
12,692
10,776
7,351
4,782
1,980
1,342
1,036
517
1,291,477
Price
$/bbl
31.30
41.25
43.75
50.92
59.32
65.91
69.48
70.93
72.41
73.92
75.40
76.91
78.44
80.01
81.61
83.25
84.91
86.61
88.34
90.11
91.91
93.75
9562
97 54
9949
101.48
103.51
105.58
107.69
109.84
11204
114.28
116.56
11890
12127
123.70
126.17
128.70
131.27
133.90
136.57
139.31
142.09
144.93
147.83
150.79
153.80
99.45
2P + Best Estimate Costiogest Resources, GLJ (2015-01). pri
February 04, 2015 14:32:08
—
L
GLJ Consultants
Petroleum
Page: 115 of 141
Page 2
REVENUE AND EXPENSE FORECAST
Revenue Before Burdens
Working Interest
Year
2015
2016
2017
201$
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
203$
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057
2058
2059
2060
2061
Tot.
Disc
1143197
Oil
MM$
5
8
17
4$
110
159
16$
175
275
616
1,461
2,683
3,930
4,668
5,128
5,413
5,546
5,653
5,773
5,858
5,899
5,949
5,938
5,995
6,140
6,244
6,337
6,376
6,542
6,735
6,769
6,320
5,939
5,307
4,671
4,078
3,476
2,978
2,445
2,008
1,686
1,125
747
319
231
176
87
158,211
19,086
NGL±Sul
MM$
Gas
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Total
MM$
5
8
17
48
110
159
16$
175
275
616
1,461
2,683
3.930
4,668
5,128
5,413
5,546
5,653
5,773
5,858
5,899
5,949
5,938
5,995
6,140
6,244
6,337
6,376
6,542
6,735
6,769
6,320
5,939
5,307
4,671
4,078
3,476
2,978
2,445
2,008
1,686
1,125
747
319
231
176
87
158,211
19,086
Royalty Company
Interest Interest
Total
Total
MM$
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
5
8
17
48
110
159
16$
175
275
616
1,461
2,683
3,930
4,668
5,128
5,413
5,546
5,653
5,773
5,858
5,899
5,949
5,938
5,995
6,140
6,244
6,337
6,376
6,542
6,735
6,769
6,320
5,939
5,307
4,671
4,078
3,476
2,978
2,445
2,008
1,686
1,125
747
319
231
176
87
158,211
19,086
Royalty Burdens
Pre-Procensing
Gas Processing
Allowance
Crown
MMS
Crown
MM$
0
0
1
3
$
12
14
15
24
55
131
242
354
420
461
487
1,224
1,211
1,332
1,296
1,392
1,332
1,168
1,193
1,228
1,452
1,228
1,327
1,278
1,621
1,631
1,494
1,425
1,231
1,021
820
622
459
338
309
214
101
67
32
33
20
8
30,332
3,212
Other
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Total
Royalty
After
Process.
MMS
Other
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
3
$
12
14
15
24
55
131
242
354
420
461
487
1,224
1,211
1,332
1,296
1,392
1,332
1,168
1,193
1,228
1,452
1,228
1,327
1,278
1,621
1,631
1,494
1,425
1,231
1,021
820
622
459
338
309
214
101
67
32
33
20
$
30,332
3,212
Net
Revenue
After
Royalty
MM$
5
$
16
45
102
147
154
160
251
561
1,329
2,442
3,576
4,248
4,666
4,926
4,321
4,442
4,441
4,562
4,507
4,617
4,770
4,802
4,912
4,792
5,109
5,049
5,265
5,114
5,138
4,826
4,514
4,076
3,650
3,258
2,855
2,519
2,107
1,699
1,472
1,024
680
287
198
156
80
127,879
15,873
Operating Expenses
Fixed
MM$
Variable
MM$
7
$
47
4$
43
42
44
45
134
318
617
923
1,130
1,195
1,185
1,187
1,212
1,246
1,277
1,300
1,325
1,361
1,394
1,425
1,449
1,466
1,492
1,517
1,535
1,564
1,581
1,550
1,533
1,479
1,429
1,389
1,342
1,303
1,147
861
$14
647
500
177
106
92
59
42,545
4,994
2P + Best Estimate Contingent Resources, 01.3(2015-01), psi
1
1
3
6
10
13
13
14
21
45
107
199
294
350
382
400
409
418
427
434
440
450
455
463
475
483
492
495
502
514
519
489
465
419
374
334
291
254
211
177
153
101
67
25
18
14
7
12,237
1,448
Total
MMS
$
9
50
53
53
55
57
59
155
363
724
1,122
1,424
1,545
1,567
1,587
1,621
1,664
1,704
1,735
1,764
1,810
1,849
1,888
1,925
1,949
1,985
2,012
2,037
2,078
2,100
2,040
1,998
1,899
1,804
1,723
1,634
1,557
1,359
1,038
967
748
566
202
125
106
66
54,781
6,442
Fcbmaty 04, 2015 14:32:08
C
GLJ Petroleum
Consultants
Page: ItO of 141
Page 3
Before Tax Cash flow
Net Capital Investment
Year
Mineral
Tax
MM$
2015
2016
CapitalTax
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057
2058
2059
2060
2061
Tot.
Disc
NPI
Burden
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Net Prod’n
Revenue
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Other
Income
MM$
Aband.
Costs
MM$
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-3
-l
-33
-8
50
92
98
101
97
198
605
1,320
2,152
2,703
3,099
3,338
2,700
2,778
2,737
2,827
2,743
2,806
2,921
2,914
2,987
2,843
3,125
3,037
3,228
3,036
3,039
2,786
2,516
2,178
1,846
1,535
1,221
962
748
662
505
276
113
85
74
50
13
73,097
9,431
Oper.
Income
MM$
0
0
0
0
0
0
0
0
0
0
0
1
1
0
0
0
3
20
22
25
4
8
36
53
58
21
35
47
41
31
41
26
37
29
24
31
28
40
34
23
64
43
55
8
5
10
10
918
58
Dcv.
MM$
-3
-l
-33
-8
50
92
98
101
96
198
605
1,319
2,151
2,703
3,098
3,338
2,697
2,758
2,715
2,802
2,738
2,798
2,885
2,861
2,929
2,822
3,090
2,990
3,167
3,005
2,998
2,760
2,480
2,148
1,822
1,503
1,193
922
715
639
441
233
59
77
69
40
3
72,180
9,373
Plant
MMS
0
14
30
21
7
13
16
116
265
700
653
714
433
683
454
501
444
543
410
495
357
449
664
637
649
360
730
587
745
321
313
283
183
153
143
135
125
115
100
88
80
54
36
14
10
8
4
13,859
2,488
Tang.
MM$
-
0
0
45
128
73
17
7
53
252
640
1,052
1,505
1,356
1,084
568
546
355
387
351
418
330
388
297
359
504
487
496
305
553
459
566
284
280
262
196
178
172
169
163
159
141
110
104
80
61
23
14
12
7
15,999
3,899
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Annual
MM$
Total
MM$
45
142
103
37
14
65
267
756
1,317
2,205
2,009
1,799
1,002
1,230
809
888
795
961
740
883
655
808
1,169
1,125
1,145
665
1,282
1,046
1,311
604
593
545
380
331
316
304
288
274
241
198
164
134
97
37
25
21
12
29,858
6,387
Cum.
MM$
-48
-143
-136
-46
35
26
-170
-655
-1,221
-2,007
-1,404
-479
1,149
1,474
2,290
2,450
1,902
1,797
1,975
1,919
2,083
1,990
1,716
1,736
1,784
2,156
1,807
1,944
1,876
2,400
2,405
2,215
2,100
1,817
1,506
1,199
905
648
473
440
257
99
-39
40
44
20
-9
42,322
2,986
10.0%Dcf
MM$
-48
-191
-327
-373
-337
-311
-481
-1,136
-2,357
-4,364
-5,768
-6,248
-5,099
-3,625
-1,335
1,115
3,017
4,814
6,789
8,708
10,791
12,781
14,497
16,233
18,017
20,174
21,981
23,925
25,800
28,200
30,606
32,821
34,921
36,738
38,244
39,444
40,348
40,996
41,470
41,910
42,167
42,266
42,227
42,267
42,311
42,331
42,322
42,322
2,986
-46
-170
-277
-310
-287
-271
-363
-683
-1,226
-2,038
-2,554
-2,714
-2,365
-1,958
-1,383
-824
-429
-90
248
548
843
1,099
1,300
1,485
1,658
1,848
1,992
2,133
2,258
2,402
2,533
2,643
2,738
2,813
2,869
2,910
2,937
2,956
2,968
2,978
2,983
2,985
2,985
2,965
2,986
2,986
2,986
2,986
2,986
SUMMARY OF RESOURCES
Remaining Resources at Jan 01, 2015
Product
Bitumen
Total: Oil Eq.
Units
Mbbl
Mboe
Gross
2,651,490
2,651,490
Working
Interest
Roy/NPI
Interest
1,590,894
1,590,894
Total
Company
0
0
Oil Equivalents
Oil Eq.
Factor
Net
1,590,894
1,590,894
1,291,477
1,291,477
Company
Mhoe
1.000
1.000
1,590,894
1,590,894
Resource Life Indic. (yr)
% of
Total
—
Resource
Life
100
100
Life
Index
47.0
47.0
Half
Life
999.9
999.9
23,5
23.5
PRODUCT REVENUE AND EXPENSES
Average First Year Unit Values
Product
Bitumen
Total: Oil Eq.
1143197
Units
$/bbl
$fboe
Base Price Price Adjust.
64.71
64.71
-33.41
-33.41
Wellhead
Price
31.30
31.30
Net Burdens
1.03
1.03
Operating
Expenses
48.00
48.00
Net RevenueAfter Royalties
Other
Expenses
0.00
0.00
Prod’n
Revenue
-17.74
-17.74
Undisc
MM$
% of
Total
127,879
127,879
2P + Best Estimate Contingent Resources, GLJ (2015-01), pet
10% Disc
MM$
100
100
15,873
15,873
% of
Total
100
100
February 04, 2015 14:32:08
L
GLJ Petroleum
Consultants
Page: 117o1 141
Page 4
INTEREST AND NET PRESENT VALUE SUMMARY
Net Present Value Before Income Tax
Revenue Interests and Burdens (%)
Initial
Working Interest
Capital Interest
Royalty Interest
Crown Royalty
Non-crown Royalty
Mineral Tax
Evaluator:
Run Date:
1143197
60.0000
60.0000
0.0000
3.2805
0.0000
0.0000
Average
60.0000
60.0000
0.0000
19.1721
0.0000
0.0000
Disc.
Rate
%
0.0
5.0
8.0
10.0
12.0
15.0
20.0
Prodn Operating Capital
Revenue Income Invest.
MM$
MM$
MM$
73,097
24,116
13,487
9,431
6,734
4,205
2,070
72,180
23,906
13,392
9,373
6,698
4,186
2,063
29,85$
12,603
8,235
6,387
5,052
3,666
2,294
Cash Flow
MM$
42,322
11,304
5,157
2,986
1,646
520
-230
5/boe
26.60
7.11
3.24
1.88
1.03
0.33
-0.14
Vong, Angie
February 04, 2015 14:31:43
Februrcy 04,205 14:32:08
21’ + Best Estimate Contingent Resources, GU (2015-01), pri
L
GLJ ConsuItant
Page: 118 of 141
Company:
Property
Laricina Energy Ltd.
Saleski
Resource Class:
Development Class
Pricing:
Effective Date:
3P + Contingent Resources
Total High Estimate
GU (2015-01)
December31, 2014
Economic Forecast
PRODUCTION FORECAST
Bitumen Production
Year
2015
2016
2017
201$
2019
2020
5
5
13
29
32
32
2021
31
2022
2023
2024
2025
2027
202$
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
31
66
165
326
665
911
1,223
1,382
1,544
1,616
1,754
1,826
2,156
2,164
2,396
2,311
2,439
2,408
2040
2,534
2041
2042
2043
2,548
2,541
2,375
2,152
1,983
1,864
1,758
1,745
1,715
1,667
1,326
1,215
920
879
658
586
417
356
149
127
42
2026
2044
2045
2046
2047
204$
2049
2050
2051
2052
2053
2054
2055
2056
2057
205$
2059
2060
2061
Tot.
1143197
Gross Oil Gross Daily
Wells
bbl/d
31’ + High Estimate Contingent Resources, GU (2015.01), pri
Company
Daily
bbUd
Company
Yearly
Mbbl
Net Yearly
MbbI
Price
$/bbl
909
1,185
2,386
5,486
9,249
11,098
10,971
10,930
17,515
42,463
90,223
545
711
1,432
3,292
5,550
6,659
6,582
6,558
10,509
25,478
54,134
199
260
523
1,201
2,026
2,430
2,403
2,394
3,836
9,299
19,759
192
247
494
1,127
1,886
2,246
2,208
2,193
3,504
8,468
17,981
31.30
41.25
43.75
50.92
59.32
65.91
69.48
70.93
72.41
73.92
75.40
178,159
106,896
39,017
35,505
76.91
279,292
375,301
454,245
498,401
517,871
518,945
510,927
516,609
517,447
514,490
512,588
508,551
505,733
167,575
225,181
272,547
299,040
310,723
311,367
306,556
309,966
310,468
308,694
307,553
305,131
303,440
61,165
82,191
99,480
109,150
113,414
113,649
111,893
113,137
113,321
112,673
112,257
111,373
110,755
55,660
74,794
90,527
88,773
84,556
83,502
87,391
83,363
87,656
83,163
85,956
83,070
84,433
78.44
80.01
81.61
83.25
84.91
86.61
88.34
90.11
91.91
93.75
95.62
97.54
99.49
500,018
300,011
109,504
81,976
101.48
495,498
482,826
470,743
434,129
404,027
364,503
326,274
294,084
261,486
228,296
177,359
149,183
111,421
96,146
70,161
57,796
39,804
31,362
13,390
10,475
3,377
297,299
289,695
282,446
260,477
242,416
218,702
195,764
176,451
156,891
136,977
106,415
89,510
66,853
57,688
42,097
34,677
23,882
18,817
8,034
6,285
2,026
108,514
105,739
103,093
95,074
88,482
79,826
71,454
64,404
57,265
49,997
38,842
32,671
24,401
21,056
15,365
12,657
8,717
6,868
2,932
2,294
740
2,547,700
83,993
78,985
77,876
70,695
66,048
60,201
54,540
49,868
45,120
40,249
32,352
28,138
22,082
19,161
13,982
11,518
7,932
6,250
2,669
2,088
673
2,005,292
103.51
105.58
107.69
109.84
112.04
114.28
116.56
118.90
121.27
123.70
126.17
128.70
131.27
133.90
136.57
139.31
142.09
144.93
147.83
150.79
153.80
99.39
Febmary 04. 2015 14:32:48
I] GLJ
Petroleum
Consultants
Page: 119 of 141
Page 2
REVENUE AND EXPENSE FORECAST
Revenue Before Burdens
tVorking Interest
•
Year
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057
2058
2059
2060
206l
Tot.
Disc
1143197
Oil
MM$
6
11
23
61
120
160
167
170
278
687
1,490
3,001
4,798
6,576
8,119
9,086
9,630
9,843
9,885
10,195
10,415
10,563
10,734
10,863
11,019
11,112
11,232
11,163
11,102
10,443
9,913
9,122
8,329
7,657
6,945
6,185
4,901
4,205
3,203
2,819
2,098
1,763
1,239
995
434
346
114
253,220
29,966
Gas
NGL+Sul
MMS
MMS
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Total
MM$
6
11
23
61
120
160
167
170
278
687
1,490
3,001
4,798
6,576
8.119
9,086
9,630
9,843
9,885
10,195
10,415
10,563
10,734
10,863
11,019
11,112
11,232
11,163
11,102
10,443
9,913
9,122
8,329
7,657
6,945
6,185
4,901
4,205
3,203
2,819
2,098
1,763
1,239
995
434
346
114
253,220
29,966
Royaity Company
Interest Interest
Total
Total
MMS
Ml’,IS
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
6
Il
23
61
120
160
167
170
278
687
1.490
3,001
4,798
6,576
8,119
9,086
9,630
9,843
9,885
10,195
10,415
10,563
10,734
10,863
11,019
11,112
11,232
11,163
11,102
10,443
9,913
9,122
8,329
7,657
6,945
6,185
4,901
4,205
3,203
2,819
2,098
1,763
1,239
995
434
346
114
253,220
29,966
3P+ High Estimate Contingent Resonmes, OL] (2015-al), pri
Royalty Burdens
Pro-Processing
Gas Processing
Allowance
Other
Crown
MMS
MMS
0
4
$
12
14
14
24
61
134
270
432
592
731
1,696
2,450
2,611
2,165
2,683
2,359
2,767
2,515
2,761
2,619
2,793
2,538
2,825
2,716
2,678
2,513
2,243
1,972
1,728
1,473
1,206
819
583
304
254
189
159
111
90
39
31
10
54,196
5,961
-
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Crown
MM$
Total
Royalty
After
Process.
MM$
Other
MMS
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
4
8
12
14
14
24
61
134
270
432
592
731
1,696
2,450
2,611
2,165
2,683
2,359
2,767
2,515
2,761
2,619
2,793
2,538
2,825
2,716
2,678
2,513
2,243
1,972
1,728
1,473
1,206
819
583
304
254
189
159
III
90
39
31
10
54,196
5,961
Net
Revenue
Operating Expenses
After
Royalty
MM$
6
10
22
57
112
148
153
156
254
626
1,356
2,731
4.366
5,985
7,388
7,390
7,180
7,232
7,720
7,512
8,056
7,796
8,219
8,102
8,400
8,319
8,694
8,339
8,386
7,765
7,400
6,880
6,357
5,929
5,472
4,979
4,082
3,621
2,899
2,566
1,910
1,605
1,127
906
394
315
104
199,024
24,005
Fixed
MMS
Variable
MMS
7
8
47
48
42
40
41
42
130
317
597
1,000
1,390
1,678
1,855
1,933
1,923
1,932
1,955
2,044
2,095
2,161
2,194
2,249
2,293
2,351
2,403
2,438
2,456
2,410
2,384
2,337
2,288
2,264
2,234
2,195
2,046
2,003
1,843
1,810
1,227
1,174
807
647
259
219
76
65,893
7,195
-
1
1
3
6
10
12
12
12
20
47
102
206
330
453
561
629
669
684
688
715
735
748
762
773
789
801
816
819
822
779
748
695
641
597
550
497
393
345
262
235
174
148
104
84
34
28
8
18,549
2,132
Total
MMS
8
9
50
54
52
52
53
54
149
365
699
1,206
1,720
2,132
2,416
2,562
2,592
2,616
2,644
2,759
2,830
2,909
2,956
3,022
3,082
3,151
3,220
3,257
3,278
3,189
3,131
3,032
2,930
2,861
2,784
2,692
2,439
2,348
2,105
2,045
1,401
1,323
911
731
293
247
84
84,443
9,327
Febmaty 04,2015 14:32:40
LI] GLJ
Consultants
Page: 120 at 141
Page 3
Before Tax Cash flow
Net Capital Investment
Year
Mineral
Tax
MMS
2015
2016
2017
201$
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2036
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057
2056
2059
2060
2061
Tot.
Disc
NPI
Burden
MM$
Capital Tax
MM$
Net Prod’n
Revenue
MM$
0
0
0
0
0
0
-2
1
-29
3
60
96
101
101
104
261
657
1,525
2,646
3,853
4,972
4,828
4,588
4,616
5,077
4,753
5,226
4,888
5,263
5,080
5,318
5,167
5,474
5,081
5,108
4,576
4,269
3,848
3,428
3,068
2,688
2,287
1,643
1,274
794
521
508
282
216
175
101
68
20
114,581
14,678
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Other
Income
MMS
0
0
0
0
0
0
0
0
0
0
Aband.
Costs
MMS
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Open
Income
MMS
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
3
7
12
27
22
25
13
15
57
52
82
45
32
29
4
9
14
102
34
92
13
72
24
57
21
73
8
31
16
993
49
0
0
0
0
0
0
0
0
-2
1
-29
3
60
96
101
101
104
261
657
1,525
2,646
3,853
4,971
4,827
4,586
4,616
5,074
4,745
5,215
4,860
5,242
5,055
5,305
5,152
5,417
5,030
5,026
4,531
4,236
3,818
3,424
3,059
2,674
2,184
1,609
1,162
781
449
485
225
195
102
93
37
4
113,588
14,630
-
Dcv.
MM$
—
Plant
MM$
0
14
29
10
6
5
6
98
273
459
807
673
843
537
551
360
495
366
1,043
381
956
384
835
503
772
523
936
441
554
268
230
219
210
211
212
210
170
159
123
120
92
83
60
53
22
20
7
15,326
2,658
Tang.
MMS
0
0
0
0
0
Total
MM$
45
128
73
9
7
47
245
626
1,090
1,559
1,976
1,778
1,586
1,020
689
367
416
334
787
347
732
353
656
436
618
454
731
403
481
292
269
264
260
264
267
268
244
239
214
212
149
142
99
81
36
29
10
21,332
5,096
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Annual
MInIS
45
142
102
19
12
52
251
723
1,363
2,017
2,783
2,451
2,429
1,556
1,239
727
912
699
1,830
728
1,688
736
1,491
939
1,390
977
1,667
$45
1,035
560
499
484
470
475
478
478
415
399
337
332
240
225
160
134
58
46
17
36,658
7,753
Cum.
MM$
-
10.0% Dcf
MMS
-47
-141
-130
-16
48
44
-151
-47
-188
-318
-335
-287
-243
-394
-622
-1,016
-1,258
-1,756
-2,126
-926
218
2,296
3,732
4,100
3,676
3,917
3,244
4,017
3,527
4,123
3,751
4,116
3,915
4,175
3,750
4,185
3,991
3,972
3,738
3,335
2,954
2,584
2,195
1,706
1,194
783
444
117
245
0
35
-32
35
-12
-13
76,930
6,876
-2,274
-4,030
-6,156
-7,082
-6,864
-4,568
-836
3,264
6,940
10,856
14,100
16,117
21,644
25,767
29,518
33,634
37,549
41,724
45,474
49,659
53,650
57,621
61,359
64,694
67,648
70,232
72,427
74,133
75,327
76,110
76,554
76,671
76,916
76,915
76,951
76,919
76,954
76,943
76,930
76,930
6,876
45
-167
-270
-281
-250
-224
-305
-610
-1,169
-1,879
-2,661
-2,970
-2,904
-2,270
-1,333
-397
365
1,104
1,661
2,287
2,787
3,318
3,757
4,195
4,574
4,942
5,242
5,546
5,810
6,049
6,253
6,419
6,552
6,658
6,740
6,798
6,635
6,857
6,868
6,871
6,876
6,876
6,877
6,676
6,877
6,676
6,676
6,876
6,876
SUMMARY OF RESOURCES
Remaining Resources at Jan 01, 2015
Product
Units
Bitumen
Total: Oil Eq.
Mbbl
Mboe
Gross
Working
Interest
4,246,167
4,246,167
2,547,700
2,547,700
Roy/NP!
Interest
Total
Company
0
0
Oil Equivalents
Oil Eq.
Factor
Net
2,547,700
2,547,700
2,005,292
2,005,292
-
Company
Mboe
1.000
1.000
2,547,700
2,547,700
Resource Life Indic. (yr)
¾ of
Total
Resource
Life
100
100
Life
Index
47.0
47.0
Half
Life
23.4
23.4
999.9
999.9
PRODUCT REVENUE AND EXPENSES
Average First Year Unit Values
Product
Bitumen
Total: Oil Eq.
1143197
-
Units
$/bbl
$/boe
Base Price Price Adjust.
64.71
64.71
-33.41
-33.41
tVellhead
Price
-
31.30
31.30
Net Burdens
1.03
1.03
Operating
Expenses
41.70
41.70
Net Revenue After Royalties
Other
Expenses
-
0.00
0.00
-
Prod’n
Revenue
-11.43
-11.43
Undisc
MM$
-
% of
Total
199,024
199,024
3P + High Estimate Contingent Resources, GLJ (2015-01). pri
100
100
10% Disc
MM$
24,005
24,005
% of
Total
100
100
Febrssiy 04,201514:32:48
L
Petroleum
GLJ Consultants
Page: 121 of 141
Page 4
INTEREST AND NET PRESENT VALUE SUMMARY
Net Present Value Before Income Tax
Revenue Interests and Burdens (%)
Disc.
te
-
Initial
Working Interest
Capital Interest
Royaltylnterest
Crown Royalty
Non-crown Royalty
MineralTax
Evaluator:
Run Date:
1143197
60.0000
60.0000
0.0000
3.2805
0.0000
0.0000
Average
60.0000
60.0000
0.0000
21.4028
0.0000
0.0000
0.0
5.0
8.0
10.0
12.0
15.0
20.0
Prodn Operating Capital
Revenue Income Invest.
MlvI$
MMS
MM$
114,581
37,939
21,110
14a678
10,408
6,422
3,093
113,588
37,738
21,026
14,630
10,379
6,408
3,088
36,658
15,428
10,039
7,753
6,100
4,384
2,691
Cash Flow
MM$
$Ihoe
76,930
22,310
10,986
6,876
4,279
2,024
397
30.20
8.76
431
2.70
1.6$
0.79
0.16
Wong, Angie
february 04, 2015 14:31:43
31’ + High Estimate Contingent Resources, GU (2015-01). pri
-
Febmary 04,2015 14:32:48
L1J GLJ
Petroleum
Consultants
Pagc: 122 of 141
APPENDIX II
Petroleum
GLJ Consultants
Pago: 123 of 141
APPENDIX II
ADDITIONAL INFORMATION
Page
APPENDIX II COVER PAGE
122
DEVELOPMENT AND RESERVE AREA MAP
124
ECONOMIC EXPLOITABLE LAND MAP GROSMONT C
125
ECONOMIC EXPLOITABLE LAND MAP GROSMONT B AND IRETON
126
PLOT
127
-
-
SALESKIA-A’ CROSS SECTION
Fbraoy 14,20i5 14:4323
LIJ GLJ
Consultants
Pagm 124 of 141
Map 100
Land Map - Reserve Area
Company: Laricina Energy Ltd.
Effective Date: December31, 2014
Property: Saleski
Project: si 143 197/sa!m100
R.21
R. 19
R.20
+
;
R. 18
+
T.86
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+
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+
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+
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+
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+
+
.
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—
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+++
t
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T.85
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+
I
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+
+
++
+
-4-
+
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+
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C
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+
+
4-
-4-
+
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+
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-
-
W4M
1:160000
0
Ma
Km
Miles
5
Se
Legend
‘
ac\
As
Interest Land
E
Proposed Phase 2 Land
IZJ
Approved Development Area
—
Reserve Area
i::
Phase 1 - Approved Project Area
W4
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1963 UThi Zone 12N
project\s1143i 97lldrafting\MxcfsalrnOlsll43lS7.mxd
Well Saurce: IHS (December 22. 2014)
Geologist:
Created by Ichudyk
Engineer- A Wang
Created on: February 10, 2015
GIj Poleum
Consultants
Page: 125 of 141
Map 7
Exploitable Land Map
Grosmont “C” Formation
Company: Laricina Energy Ltd.
Effective Date: December31, 2014
Property: Saleski
Project: sI 1431 97/sal_el_grsmtC
R.21
R.20
R.19
R.18
T.86
T.85
T.$4
T,83
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0
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Miles
1:160000
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/
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I
•
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on
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-
Approved Project Area
Grosmont C Probable Reserves
\
r,u:eI.si,s:c
Phase I
-
Grosmont C 8est Estimate Contingent Resources
-
ND
12N
iprojecfsl 143038\drafting\Mxd’oalmI000_s1143038mad
Well Source: INS (December 22, 2014)
Geologist:
Created by: awong
Engineer:
Crested on; February 10,2015
Petroleum
Consuftonts
Page: 126 of 141
Map $
Exploitable Land Map
Grosmont “D” Formation
Company: Laricina Energy Ltd.
Effective Date: December31, 2014
Property: Saleski
Project: si 143 197/sal_elgrsmtD
R.21
R.20
R.19
R.18
a
+
+
4,-
+
T.86
1
-4+
0
+
r_
+
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I
++: +
-4-
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-4-
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.
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Legend
Interest Land
Phase 1 - Approved Project Area
Grosmont D
- Probable Reserves
Grosmont D and Ireton
WA
r
- Best Estimate Contingent Resources
,tS,o
NAD 1983 UTM Zone 12N
lprojects1I43038\draftingMxdloalml I 00s1143038mud
Well Source: IHS (December 22,2014)
Geologist:
Created by:
awong
Engineer.
Created on: February 10,2018
cIJ Petroleum
Consultants
I
Page: 128 of 141
RESOURCE AND RESERVES DEFINITIONS
GLJ Petroleum Consultants (GLJ) has prepared estimates of resources and reserves in accordance
with the standards contained in the Canadian Oil and Gas Evaluation (COGE) Handbook. The
following are excerpts from the definitions of resources and reserves, contained in Section 5 of the
COGE Handbook, which is referenced by the Canadian Securities Administrators in “National
Instrument 51-101 Standards of Disclosure for Oil and Gas Activities”.
A. Fundamental Resource Definitions
Total Petroleum Initially-In-Place (PuP) is that quantity of petroleum that is estimated to exist
originally in naturally occurring accumulations It includes that quantity of petroleum that is estimated
as of a given date to be contained in known accumulations prior to production plus those estimated
quantities in accumulations yet to be discovered (equivalent to “total resources’).
Discovered Petroleum Initially In Place (equivalent to discovered resources) is that quantity of
petroleum that is estimated as of a given date to be contained in known accumulations prior to
production The recoverable portion of discovered petroleum initially in place includes production
reserves, and contingent resources; the remainder is unrecoverable.
Reserves are estimated remaining quantities of oil and natural gas and related
substances anticipated to be recoverable from known accumulations as of a given date
based on the analysis of drilling, geological geophysical and engineering data the use of
established technology and specified economic conditions which are generally accepted
as being reasonable Reserves are further classified according to the level of certainty
associated with the estimates and may be subclassified based on development and
production status. (Reserves are further defined below].
Contingent Resources are those quantities of petroleum estimated, as of a given date,
to be potentially recoverable from known accumulations using established technology or
technology under development but which are not currently considered to be commercially
recoverable due to one or more contingencies Contingencies may include factors such as
economic legal environmental political and regulatory mailers or a lack of markets It is
also appropriate to classify as contingent resources the estimated discovered recoverable
quantities associated with a project in the early evaluation stage Contingent Resources
are further classified in accordance with the level of certainty associated with the
estimates and may be subclassified based on project maturity and/or characterized by
their economic status.
Undiscovered Petroleum Initially-In-Place (equivalent to undiscovered resources) is that
quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be
discovered. The recoverable portion of undiscovered petroleum initially in place is referred to as
‘prospective resources,” the remainder as “unrecoverable.”
Prospective Resources are those quantities of petroleum estimated, as of a given date,
to be potentially recoverable from undiscovered accumulations by application of future
development projects Prospective resources have both an associated chance of
discovery and a chance of development Prospective Resources are further subdivided in
accordance with the level of certainty associated with recoverable estimates assuming
their discovery and development and may be subclassified based on project maturity.
LIj GLJ
Petroleum
Consultants
Page: 12 of 141
B. Uncertainty Categories for Resource Estimates
The range of uncertainty of estimated recoverable volumes may be represented by either
deterministic scenarios or by a probability distribution. Resources should be provided as low, best,
and high estimates as follows:
Low Estimate: This is considered to be a conservative estimate of the quantity that will
actually be recovered. It is likely that the actual remaining quantities recovered will exceed
the low estimate. If probabilistic methods are used, there should be at least a 90 percent
probability (P90) that the quantities actually recovered will equal or exceed the low
estimate.
Best Estimate: This is considered to be the best estimate of the quantity that will actually
be recovered. It is equally likely that the actual remaining quantities recovered will be
greater or less than the best estimate. If probabilistic methods are used, there should be
at least a 50 percent probability (P50) that the quantities actually recovered will equal or
exceed the best estimate.
High Estimate: This is considered to be an optimistic estimate of the quantity that will
actually be recovered. It is unlikely that the actual remaining quantities recovered will
exceed the high estimate. If probabilistic methods are used, there should be at least a 10
percent probability (PlO) that the quantities actually recovered will equal or exceed the
high estimate.
This approach to describing uncertainty may be applied to reserves, contingent resources, and
prospective resources. There may be significant risk that sub-commercial and undiscovered
accumulations will not achieve commercial production. However, it is useful to consider and
identify the range of potentially recoverable quantities independently of such risk.
C. Reserves Categories
Reserves are estimated remaining quantities of oil and natural gas and related substances
anticipated to be recoverable from known accumulations, as of a given date, based on:
•
analysis of drilling, geological, geophysical, and engineering data;
•
the use of established technology;
•
specified economic conditions1, which are generally accepted as being reasonable, and
shall be disclosed.
Reserves are classified according to the degree of certainty associated with the estimates.
Proved Reserves
Proved reserves are those reserves that can be estimated with a high degree of certainty
to be recoverable. It is likely that the actual remaining quantities recovered will exceed the
estimated proved reserves.
For securities reporting, the key economic assumptions will be the prices and costs used in the
estimate. The required assumptions may vary by jurisdiction, for example:
(a) forecast prices and costs, in Canada under NI 51-101
(b) constant prices and costs, based on the average of the first day posted prices in each of the 72
months of the reporting issuer’s financial year, under US SEC rules (this is optional disclosure under
NI 51-107).
LI GLJ
Consultants
Page: 130 ci 141
Probable Reserves
Probable reserves are those additional reserves that are less certain to be recovered than
proved reserves. It is equally likely that the actual remaining quantities recovered will be
greater or less than the sum of the estimated proved plus probable reserves.
Possible Reserves
Possible reserves are those additional reserves that are less certain to be recovered than
probable reserves It is unlikely that the actual remaining quantities recovered will exceed
the sum of the estimated proved plus probable plus possible reserves.
Other criteria that must also be met for the classification of reserves are provided in [Section 5.5 of
the COGE Handbook].
Development and Production Status
Each of the reserves categories (proved, probable, and possible) may be divided into developed
and undeveloped categories.
Developed Reserves
Developed reserves are those reserves that are expected to be recOvered from existing
wells and installed facilities or if facilities have not been installed that would involve a low
expenditure (e g when compared to the cost of drilling a well) to put the reserves on
production. The developed category may be subdivided into producing and non-producing.
,
Developed Producing Reserves
Developed producing reserves are those reserves that are expected to be recovered from
completion intervals open at the time of the estimate. These reserves may be currently
producing or, if shut in, they must have previously been on production, and the date of
resumption of production must be known with reasonable certainty.
Developed Non-Producing Reserves
Developed non-producing reserves are those reserves that either have not been on
production, or have previously been on production, but are shut in, and the date of
resumption of production is unknown.
Undeveloped Reserves
Undeveloped reserves are those reserves expected to be recovered from known
accumulations where a significant expenditure (for example when compared to the cost of
drilling a well) is required to render them capable of production They must fully meet the
requirements of the reserves category (proved, probable, possible) to which they are
assigned.
In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and
undeveloped categories or to subdivide the developed reserves for the pool between developed
producing and developed non-producing. This allocation should be based on the estimator’s
assessment as to the reserves that will be recovered from specific wells, facilities, and completion
intervals in the pool and their respective development and production status.
D. Levels of Certainty for Reported Reserves
The qualitative certainty levels referred to in the definitions above are applicable to individual
reserves entities (which refers to the lowest level at which reserves calculations are performed) and
to Reported Reserves (which refers to the highest level sum of individual entity estimates for which
reserves estimates are presented) Reported Reserves should target the following levels of
certainty under a specific set of economic conditions:
LLJ GLJ
Petroleum
Consultants
Page: 131 ol141
•
at least a 90 percent probability that the quantities actually recovered will equal or exceed
the estimated proved reserves;
•
at least a 50 percent probability that the quantities actually recovered will equal or exceed
the sum of the estimated proved plus probable reserves;
•
at least a 10 percent probability that the quantities actually recovered will equal or exceed
the sum of the estimated proved plus probable plus possible reserves.
A quantitative measure of the certainty levels pertaining to estimates prepared for the various
reserves categories is desirable to provide a clearer understanding of the associated risks and
uncertainties. However, the majority of reserves estimates are prepared using deterministic
methods that do not provide a mathematically derived quantitative measure of probability. In
principle, there should be no difference between estimates prepared using probabilistic or
deterministic methods.
Additional clarification of certainty levels associated with reserves estimates and the effect of
aggregation is provided in Section 5.5.3 [of the COGE Handbook].
E. Discovered and Commercial Status and Risks Associated with Resource Estimates
Discovery Status
Total petroleum initially in place is first subdivided based on the discovery status of a petroleum
accumulation. Discovered PIIP, production, reserves, and contingent resources are associated with
known accumulations. Recognition as a known accumulation requires that the accumulation be
penetrated by a well and have evidence of the existence of petroleum, COGEH Volume 2, Sections
5.3 and 5.4, provides additional clarification regarding drilling and testing requirements relating to
recognition of known accumulations.
Commercial Status
Commercial status differentiates reserves from contingent resources. The following outlines the
criteria that should be considered in determining commerciality:
•
economic viability of the related development project;
•
a reasonable expectation that there will be a market for the expected sales quantities of
production required to justify development;
•
evidence that the necessary production and transportation facilities are available or can be
made available;
•
evidence that legal, contractual, environmental, governmental, and other social and
economic concerns will allow for the actual implementation of the recovery project being
evaluated;
•
a reasonable expectation that all required internal and external approvals will be
forthcoming. Evidence of this may include items such as signed contracts, budget
approvals, and approvals for expenditures, etc.;
•
evidence to support a reasonable timetable for development. A reasonable time frame for
the initiation of development depends on the specific circumstances and varies according
to the scope of the project. While five years is recommended as a maximum time frame for
classification of a project as commercial, a longer time frame could be applied where, for
example, development of economic projects are deferred at the option of the producer for,
among other things, market-related reasons or to meet contractual or strategic objectives.
LIJ GLJ
Petroleum
Consultants
Page: 132 of 141
Commercial Risk Applicable to Resource Estimates
Estimates of recoverable quantities ate stated in terms of the sales products derived from a
development program assuming commercial development It must be recognized that reserves
contingent resources and prospective resources involve different risks associated with achieving
commerciality The likelihood that a project will achieve commerciality is referred to as the chance
of commerciality The chance of commerciality varies in different categories of recoverable
resources as follows:
Reserves: To be classified as reserves, estimated recoverable quantities must be
associated with a project(s) that has demonstrated commercial viability Under the fiscal
conditions applied in the estimation of reserves the chance of commerciality is effectively
100 percent.
Contingent Resources: Not all technically feasible development plans Will be commercial.
The commercial viability of a development project is dependent on the forecast of fiscal
conditions over the life of the project For contingent resources the risk component relating
to the likelihood that an accumulation will be commercially developed is referred to as the
‘chance of development” For contingent resources the chance of commerciality is equal to
the chance of development.
Prospective Resources: Not all exploration projects will result in discoveries. The chance
that an exploration project will result in the discovery of petroleum is referred to as the
chance of discovery.” Thus, for an undiscovered accumulation the chance of
commerciality is the product of two risk components
the chance of discovery and the
chance of development.
—
F. Economic Status of Resource Estimates
By definition, reserves are commercially (and hence economically) recoverable. A portion of
contingent resources may also be associated with projects that are economically viable but have
not yet satisfied all requirements of commerciality Accordingly it may be a desirable option to subclassify contingent resources by economic status:
Economic Contingent Resources are those contingent resources that are currently
economically recoverable.
Sub Economic Contingent Resources are those contingent resources that are not
currently economically recoverable.
Where evaluations are incomplete such that it is premature to identify the economic viability of a
project it is acceptable to note that project economic status is undetermined (i e contingent
resources economic status undetermined”).
—
In examining economic viability, the same fiscal conditions should be applied as in the estimation of
reserves, i e specified economic conditions which are generally accepted as being reasonable
(refer to COGEH Volume 2, Section 5.8).
L
Petroleum
GLJ Consultants
Page: 133 at 141
PRODUCT PRICE AND MARKET FORECASTS
January 1, 2015
GLJ Petroleum Consultants has prepared its January 1, 2015 price and market forecasts as
summarized in the attached Tables 1, 2 and 3 after a comprehensive review of information.
Information sources include numerous government agencies, industry publications, Canadian oil
refiners and natural gas marketers. The forecasts presented herein are based on an infonned
interpretation of currently available data. While these forecasts are considered reasonable at this
time, users of these forecasts should understand the inherent high uncertainty in forecasting any
commodity or market. These forecasts will be revised periodically as market, economic and
political conditions change. These future revisions may be significant.
LIj GLJ
Petroleum
Consultants
0.850
0.875
0.875
0.875
0.875
0.875
0.875
0.875
0.875
0.875
0.875
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
201501
201502
201503
201504
20l5FuIlYear
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025+
75.00
80.00
85.00
90.00
95.00
98.54
100.51
102.52
104.57
+2.0%/yr
62.60
55.00
60.00
65,00
70.00
56.58
66.22
72.39
99.64
61.78
79.52
95.12
94.21
97.96
93.06
USDIbbI
82.50
87.50
90.00
95.00
100.00
101.35
103.38
105.45
107.56
+2.0%/yr
80.00
85.71
91.43
97.14
102.86
106.18
108.31
110.47
112.67
+2.0%/yr
64.71
67.50
69.02
73.21
77.06
102.89
66.32
77.87
95.53
86.60
93.47
94.77
55.14
66.16
72.71
98.30
62.50
80.25
110.86
111.71
108.77
99.89
55.88
61.76
67.65
73.53
CAD/bbl
USD/bbl
60.00
65.00
70.00
75.00
Light Sweet
Crude Oil
(40 API, 0.3%S)
at Edmonton
Then
Current
ICE Brent Near
Month Futures
Contract
Crude OIl
FOB North Sea
Then
Current
52.91
13.97
18.53
20.29
25.74
19.63
32.00
38.57
41.14
43.71
46.29
47.78
48.74
10.50
10.50
10.50
11.36
10.72
12.30
13.16
14.03
14.90
15.76
16.63
17.49
18.36
18.98
+2.0%/yr
76,00
81.43
86.86
92.29
97.71
100.87
102.89
104.95
107.04
+2.0%/yr
78.40
84.00
89.60
95.20
100.80
104.06
106.14
108.26
110.42
+2.0%/yr
60.68
65.09
69.49
73.90
78.30
80.87
82.51
84.17
85.87
+2.0%/yr
67.20
72.00
76.80
81.60
86.40
89.19
90.98
92.79
94.65
+2.0%/yr
2014-12-31
61.47
63.41
48.89
54.35
55.00
53.09
58.68
6426
69.85
54.76
60.53
66.29
72.06
42.09
55.69
51.16
46.62
88.33
46.94
51.88
56.82
61.76
Revised
69.24
47.50
51.26
54.79
58.09
43.04
43.85
49.56
58.38
38.03
46.84
53.66
29.04
38.88
45.57
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
56.77
62.26
65.71
93.10
62.96
73.76
62.18
66.38
71.13
96.08
63.84
76,58
81.38
88.13
89.86
47.50
52.50
57.50
62.50
68.00
72.86
77.71
82.57
87.43
90.26
92.06
93,90
95.77
+2.0%/yr
59.79
66.09
72.38
78.68
75.33
48.17
65.91
74.42
66.70
68.81
69.29
CAD/bbl
CAD/bbl
CAD/bUt
CAD/bbl
92.35
34.07
41.84
43.42
74.94
54.46
60.76
67.64
63.64
65.11
74.23
43.74
50.66
52.38
82.95
58.66
67.27
77.14
73.13
75.01
81.62
8451
92.30
92.87
CAD/bbl
cAD/bbl
CADIhbI
50.70
+2.0%/yr
49.71
Petroleum
GLJ Consultants
60.80
65.14
69.49
73,83
78.17
80,70
82.31
83,96
85.63
+2.0%/yr
85.60
91.71
97.83
103.94
110.06
113.62
115.89
118.20
120.56
+2.0%/yr
69.57
75.41
77.38
104.78
68.17
84.27
104.17
100.84
104.70
102.92
51.80
60.17
61.78
CAD!bht
CADIUUI
Edmonton
Edmonton Edmonton Pentanes
Propane
Plus
Butane
Spec
Ethane
Alberta Natural Gas Liquids
(Then CUrrent Dollars)
Medium Crude
Oil
(29 API, 2.0%S)
at Cromer
Then
Current
Light Crude Oil
(35 API, 1 .2%S)
at Cromer
Then
Current
Heavy Crude
Oil
Proxy (12 API)
at Hardisty
Then
Current
44.73
51.82
53.64
84.31
60.18
68.45
78.58
74.42
76.33
82.08
WCS
Stream Quality
at Hardisty
Then
Current
Bow River Crude
Oil
Stream Quality
at Hardisty
Then
Current
Historical futures contract price is an average of the daily settlement price of the near month contract over the calendar month.
73.53
76.89
80.10
83.15
86.04
87.50
87.50
87.50
87.50
87.50
62.50
55.00
60.00
65.00
70.00
67.83
77.64
83.22
112.14
67.86
87.01
102.28
98.42
100.82
94.87
0.826
0.882
0.935
0.943
0.880
0.971
1,012
1.001
0.971
0.905
0.850
0.850
0.850
0.850
USD/bhl
USO/CAD
%
2.2
2.0
2.2
2.4
0.4
1.8
2.9
1.5
0.9
2.0
Year
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014(e)
Inflation
Bank of Canada
Average
Noon
Exchange
Rate
NYMEX WTI Near
Month Futures
Contract
Crude Oil at
Cushing Oktahoma
Constant
Then
Current
2015$
Table I
GLJ Petroleum Consultants Ltd.
Crude Oil and Natural Gas Liquids
Price Forecast
Effective January 1,2015
C
-v
en
3.68
3.84
4.00
4.16
4.30
4.44
4.57
4.69
4.75
4.75
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025+
3.53
3.78
4.03
4.28
4.53
4.78
5.03
5.28
5.46
+2.0%/yr
3.08
3.08
3.46
3.64
3.80
3.95
4.10
4.24
4.38
4.50
4.56
4.56
3.02
3.02
3.02
3.26
8.48
6.29
6.23
7.94
3.79
3.78
3.42
2.21
2.96
4.28
C’
.flWOVUVIULU
3.02
3.02
3.02
3.26
10.16
7.38
7.16
8.93
4.17
4.14
3.68
2.31
3,04
4.36
3.53
3.78
4.03
4.28
4.53
4.78
5.03
5.28
5.46
+2.0%/yr
3.08
3.02
3.02
3.02
3.26
8.30
6.57
6.20
7.88
3.85
3.77
3.46
2.2S
2.98
4.17
nUIWIWDLU
2.96
3.23
3.51
3.78
4.05
4.33
4.60
4,87
5.07
+2.0%/yr
3.18
3.12
3.12
3.12
3.37
2.61
2.43
2.43
2.77
2.56
8.36
6.67
6.18
8.07
3.87
3.96
3.57
2.31
3.09
4.38
SaskEnergy
8.28
6.37
5.87
7,83
3.24
3.31
2.84
1.65
2.60
4.51
Alliance
3.23
3.17
3.17
3.17
3.42
8.64
6.42
6.35
8.04
3.83
3.85
3.58
2.26
3.10
4,44
CADJMMato
Spot
2014-12-31
-
CADIMMBth
ARP
Saskatchewan Plant Gate
Unless otherwise stated, the gas price reference point Is the receipt point on the applicable provincial gas transmission system known as the plant gate.
The plant gate price represents the price before raw gas gathering and processing charges are deducted.
AECO/NIT Spot refers to the same-day spot price averaged over the period.
Revised
-
Then
Current
Alberta Plant Gate
3.69
3.94
4.19
4.45
4.70
4.95
5.20
5.45
5.63
+2.0%/yr
3.31
3.25
3.25
3.25
3.50
8.73
6.52
6.45
8.16
3.99
4.01
3.62
2.40
3.18
4.52
-—
3.77
4.02
4.27
4.53
4,78
5.03
5.28
5.53
5.71
+2.0%/yr
--
CADCAMRft
Constant
2015$
Spot
3.63
3.88
4.13
4.38
4.63
4.88
5.13
5.38
5,56
+2.0%/yr
3.85
4.10
4.35
4.60
4.85
5.10
5.35
5.60
5.78
+2.0%/yr
3.31
2015 Full Year
3.45
3.30
3.30
3.60
3.41
3.25
3.25
3.25
3,50
3.25
3.25
3.25
3.50
201501
201502
201503
2015 Q4
8.24
6.93
6.83
8.91
4.05
4.53
4.21
2.92
3.81
5.36
3.75
4.00
4.25
4.50
4.75
5.00
5.25
5.50
5.68
+2.0%/yr
9.00
6.99
7.12
8.90
4.16
4.40
4.03
2.83
3.72
4.29
10.78
8.19
8.18
10.01
4.58
4.81
4.33
2.95
3.83
4.38
Midwest
Price @ Chicago AECO/NIT Spot
Then
Then
Current
Current
3.31
JOLHMMDIU
UUMMQLL
Year
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014 Ce)
NYMEX Henry Hub
Near Month Contract
Then
Constant
Current
2015$
Table 2
GLJ Petroleum Consultants Ltd.
Natural Gas and Sulphur
Price Forecast
Effective January 1, 2015
3.70
3.95
4.20
4.45
4.70
4,95
5.20
5.45
5.63
+2.0%/yr
3.26
3.50
3.00
3.00
3.55
7.45
6.04
6.52
6.47
3.80
4.13
3.90
2.70
3.71
4.39
““
UD.’ILU
Sumas Spot
3.62
3.87
4.12
4.38
4.63
4.88
5.13
5.38
5.56
+2.0%/yr
3.16
3.20
3.05
3.00
3.40
8.22
6.58
6.40
8.21
3.90
3.78
3.33
2.30
3.14
4,31
CAD/MMBIo
Westcoast
Station 2
3.43
3.68
3.93
4,18
4.42
4.67
4.92
5.17
5.35
+2.0%/yr
2.97
3.01
2.86
2.81
3.21
8.04
6.40
6.16
7.99
3.70
3,63
3.18
2.12
2.94
4,07
“““
Spot
Plant Gate
British Columbia
-
LJ
Petroleum
92.86
92,86
95.71
98.63
101.60
104.63
107.73
110.88
114.10
+2.0%/yr
126.47
126.47
126.47
126.47
126.47
Alberta
Sulphur
at Plant
Gate
CAD/li
33.77
19.27
42.03
488.64
24.57
48.26
171.93
157.91
74.02
110.43
GLJ Consultants
125.00
125.00
127.50
130.05
132.65
135.30
138.01
140.77
143.59
+2.0%/yr
150.00
150.00
150.00
150.00
150.00
-
Sulphur
FOB
Vancouver
uSD/lt
63.50
55.07
81.66
497.39
57.06
88.94
217.16
201.03
105.74
145.41
C
0.850
0.875
0.875
0,875
0.875
0.875
0.875
0.875
0.875
0.875
0.875
2.0
2.0
2.0
2,0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2OlSFullYear
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025+
1.450
1.450
1.450
1.450
1.450
1.450
1,450
1.450
1.450
1.450
1.450
1.800
1.800
1.800
1.800
1,800
1.800
1,800
1.800
1.800
1.800
1.450
1.450
1.450
1,450
1.800
1.800
1,800
1.800
1.800
73.53
85.71
91.43
97.14
102.86
108.57
112.62
114.87
117.17
119.51
+2.0%/yr
75.00
80.00
85.00
90.00
95.00
98.54
100.51
102.52
104.57
+2.0%/yr
64.71
70.59
76.47
82.35
62.50
55.00
60.00
65.00
70.00
NYMEX WTI Near
Crude Oil at
Cushing Oklahoma
Then
Then
Current
Current
USDIbbI CAD/bbl
68.42
56.58
66.22
75,08
76.89
72.39
99.64
104.27
61.78
69.57
81.85
79.52
94.02
95.12
94.11
94.21
100.95
97.96
93.06
102.58
80.02
84.88
88.20
93.10
98,00
99.32
101.31
103.34
105.41
+2.0%/yr
65.48
58.20
63,05
67.90
72.75
Then
Current
USDIbbI
52,81
63.89
75.36
102.31
64.31
82.78
112.33
111.77
106,19
94.75
Revised
2014-1 2-31
94.29
100.00
102.86
108.57
114.29
115,83
118.15
120.51
122.93
+2.0%/yr
82.50
87.50
90.00
95.00
100.00
101.35
103.38
105.45
107.56
+2.0%/yr
3.75
4.00
4.25
4.50
4.75
5.00
5.25
5.50
5.68
+2.0%/yr
3.31
79.41
67.50
73.43
77.88
80.10
84.55
89.00
90.20
92.01
93.85
95.73
+2.0%/yr
83.91
89,00
91.54
96.63
101.71
103.09
105.15
107.26
109.40
+2.0%/yr
70.68
60.08
91.46
97.00
100.80
106,40
112.00
113.51
115.79
118,10
120.47
+2.0%/yr
3.25
3.25
3.25
3.50
9.00
6.99
7.12
6.90
4.16
4.40
4.03
2.83
3.72
4.29
‘“
Then
Current
7.50
8.25
6.75
9.00
9.50
10.00
10.14
10.34
10.54
10.76
+2.0°//yr
6.56
6,30
6.02
4.90
5.18
5.46
5,74
6.02
6.30
6.51
+2.0%/yr
+2.0%/yr
5.52
5.27
4,28
4.53
4.78
5.02
5,27
5.52
5.69
5.58
3.90
4.29
4.57
4.86
5.14
5.43
5.71
6.00
6.29
6.49
+2.0°/dyr
14.02
3.01
3.01
6.20
11.92
2.56
2.56
5.27
3.82
3.82
3,82
4.12
Petroleum
Consultants
9,43
10.00
10.29
10.86
11.43
11.58
11.81
12.05
12.29
+2.0%/yr
8.82
8.82
8.50
8.67
9.29
9.02
9.48
6.44
12,12
5.68
6.58
9.25
9.37
10,82
9.14
LJ GLJ
7.50
7.22
7.37
7.89
9.87
7.04
6.84
8.77
3.87
3.96
3.58
2.72
5.94
7.81
7.51
8.34
6.14
11.41
4.95
6,39
9.35
9.38
10.50
8.26
National
Balancing
Point
(UK)
Then Current Then Current Then Current Then Current
Nova Scotia
Goldboro
8.19
6.20
6.33
8,32
3.35
3.83
3.62
2.72
5,78
7.07
Then
Current
CADIMMBtu
10.83
7.94
7.65
9.36
4.75
4.53
3.98
2.82
3.84
4.74
Henry Hub
Spot
70,59
76.47
82.35
88.24
77.03
68.47
74.18
79.88
85.59
60.00
65.00
70,00
75.00
Then
Current
CAD/bbl
50.36
59.13
63.30
87.62
63.55
72.35
97.52
99.50
100.13
94.97
Brent Blend
Crude Oil
FOB North Sea
Then
Then
Current
Current
USDIbbl CADIbbl
55.14
66,69
66.16
75.01
77.33
72.71
102.81
98.30
70.47
62.50
80.25
82.58
109.57
110.86
111.71
111.57
112.04
108.77
110,11
99.89
62.82
68.06
73.29
78.53
Then
Current
USDIbbI
41.66
52.16
59.69
83.90
56.46
70.29
98.60
99,60
97.26
86.16
Mexican Mayan
Cwde Oil
53.40
57.85
62,30
66.75
Then
Current
CADibN
63.85
72.41
80,13
107.04
72.52
85.20
111.03
111.62
109.32
104.47
Light Louisiana Sweet
Crude Oil
Historical futures contract price is an average of the daily settlement price of the near month contract over the calendar month.
0.850
0.850
0.850
0.850
2.0
2.0
2,0
2.0
201501
201502
201503
201504
USD/CAD CAO!GBP CAD/EUR
1,452
2.206
0.826
1.369
0.882
2.090
1.436
0.935
2.148
1.961
1.548
0.943
1.780
1.585
0.880
1.367
1.593
0.971
1.586
1.376
1.012
1.285
1.584
1.001
1.612
1.369
0.971
1,467
0.905
1.819
2007
2008
2009
2010
2011
2012
2013
2014(e)
2005
2006
Year
Inflation
%
2.2
2.0
2.2
2.4
0.4
1.8
2.9
1,5
0.9
2,0
Bank of Canada Average
Noon Exchange Rates
Tabte 3
GL] Petroleum Consultants Ltd.
International and Frontier
Price Forecast
Effective January 1,2015
-a
00
Page: 137 of 141
APPENDIX I
CERTIFICATES OF QUALIFICATION
Caralyn P. Bennett
William M. Spackman
Angie H.W. Wong
Peter G. Moore
L
GLJ Petroleum
Consultants
Page: 138 otl4I
CERTIFICATION OF QUALIFICATION
I, Caralyn P. Bennett, Professional Engineer, 4100, 400
—
3 Avenue S.W., Calgary, Alberta,
Canada hereby certify:
1.
That I am an employee of GLJ Petroleum Consultants Ltd., which company did prepare a
detailed analysis of the Saleski oil sands property of Laricina Energy Ltd. (the “Company”).
The effective date of this evaluation is December 31, 2014.
2.
That I do not have, nor do I expect to receive any direct or indirect interest in the securities of
the Company or its affiliated companies.
3.
That I attended the University of Waterloo where I graduated with an Honours Bachelor of
Science Degree in Geological Engineering in 1987; that I am a Registered Professional
Engineer in the Province of Alberta; and, that I have in excess of twenty-nine years
experience in engineering studies relating to oil and gas fields.
4.
That a personal field inspection of the properties was not made; however, such an inspection
was not considered necessary in view of the information available from public information
and records, the files of the Company, and the appropriate provincial regulatory authorities
LIii GLJ
Petroleum
Consu[tants
Page: 139 ot141
CERTIFICATION OF QUALIFICATION
I, William M. Spackman, Professional Engineer, 4100, 400
-
3rd Avenue S.W., Calgary, Alberta,
Canada hereby certif’:
1.
That I am an employee of GLJ Petroleum Consultants Ltd., which company did prepare a
detailed analysis of the Saleski oil sands property of Laricina Energy Ltd. (the “Company”).
The effective date of this evaluation is December 31, 2014.
2.
That I do not have, nor do I expect to receive any direct or indirect interest in the securities of
the Company or its affiliated companies.
3.
That I attended the University of Calgary where I graduated with a Bachelor of Science
Degree in Chemical Engineering in 2006; that I am a Registered Professional Engineer in the
Province of Alberta; and, that I have in excess of eight years of experience in engineering
studies relating to oil and gas fields.
4.
That a personal field inspection of the properties was not made; however, such an inspection
was not considered necessary in view of the infomation available from public information
and records, the files of the Company, and the appropriate provincial regulatory authorities.
L1J GLJ
Petroleum
Consultants
Pane: 140 of 141
CERTIFICATION Of QUALIFICATION
I, Angie H.W. Wong, Professional Engineer, 4100, 400
-
3rd Avenue S.W., Calgary, Alberta,
Canada hereby certify:
1.
That I am an employee of GLI Petroleum Consultants Ltd., which company did prepare a
detailed analysis of the Saleski oil sands property of Laricina Energy Ltd. (the “Company”).
The effective date of this evaluation is December 31, 2014.
2.
That I do not have, nor do I expect to receive any direct or indirect interest in the securities of
the Company or its affiliated companies.
3.
That I attended the University of Calgary and that I graduated with a Bachelor of Science
Degree in Chemical Engineering in (2009); that I am a Registered Professional Engineer in
the Province of Alberta; and, that I have in excess of six years experience in engineering
studies relating to oil and gas fields.
4.
That a personal field inspection of the properties was not made; however, such an inspection
was not considered necessary in view of the information available from public information
and records, the files of the Company, and the appropriate provincial regulatory authorities.
L
GLJ Petroleum
Consultants
Page: 141 of 141
CERTIFICATION OF QUALIFICATION
I, Peter G. Moore, Professional Geologist, do 4100, 400
-
3rd Avenue S.W., Calgary, Alberta,
Canada hereby certify:
1.
That I have been retained by GLJ Petroleum Consultants Ltd., which company did prepare a
detailed analysis of the Saleski oil sands property of Laricina Energy Ltd. (the “Company”).
The effective date of this evaluation is December 31, 2014.
2.
That I do not have, nor do I expect to receive any direct or indirect interest in the securities of
the Company or its affiliated companies.
3.
That I attended Acadia University where I graduated with a Bachelors Degree in Geology in
1978; that I am a Registered Professional Geologist in the Province of Alberta; and, that I
have in excess of thirty years experience in geological studies and evaluations of oil and gas
fields.
4.
That a personal field inspection of the properties was not made; however, such an inspection
was not considered necessary in view of the information available from public information
and records, the files of the Company, and the appropriate provincial regulatory authorities.
L
GLJ Consultonts