GLJ - Canadian Stocks

Item 1: Identity of Reporting Issuer
1.1 Name and Address of Reporting Issuer
TOUCHSTONE EXPLORATION INC.
FORM 51-102 F4
Touchstone Exploration Ltd. (“Touchstone” or the “Company”)
200, 209 – 8 Avenue S.W.
Calgary, Alberta T2P 3H2
1.2 Executive Officer
The name of the executive officer of Touchstone, who is knowledgeable about the significant acquisition and this
report is Gregory Marr, Chief Financial Officer and his business telephone number is (403) 781-7946.
Item 2: Details of Acquisition
2.1 Nature of Assets Acquired
On January 31, 2011, the Company completed the acquisition of a 100% interest in the Lease Operatorship
Agreements in the Coora Block and certain Farm-out Agreements in the New Dome and South Palo Seco blocks
and associated equipment and production facilities from Cirrus Energy Corporation (“Cirrus”), Cirrus Energy
(Trinidad) Ltd. and Damus Oil Limited (“Damus”) (the “Acquisition”). The Acquisition was completed through
the Company’s wholly owned subsidiary Territorial Services Limited (“TSL”).
All the Cirrus and Damus assets acquired are located in Trinidad. The two lease operatorship blocks acquired at
Coora CO-1 and Coora CO-2 cover approximately 1700 acres of land and provide access to over 350 wellbores.
The Acquisition of the New Dome and South Palo Seco blocks include oil production, as well as, over 2500 acres
of land held under Farm-out Agreements. The areas have well developed infrastructure and good access, and are
covered by a 3-D seismic program that was recently shot.
At the time of the Acquisition, Touchstone’s management estimated the Cirrus’s and Damus’s production to be
approximately 250 barrels of oil per day with estimated total proved and probable reserves of 2,823,000 barrels of
oil (net after royalty). A reserve evaluation was prepared by GLJ Petroleum Consultants Ltd. and dated January
26, 2011, the evaluation with an effective date of August 31, 2010 estimated the total proved and probable
reserves discounted at 10% to have a present value of $21,287,000 on an after tax basis.
2.2 Date of Acquisition
The Acquisition closed on January 31, 2011which is also the effective date and the assets are included in
Touchstone’s results of operations as of this date.
2.3 Consideration
The Acquisition was paid in cash $4,367,859 to Damus and $3,716,179 to Cirrus.
In connection with the Acquisition, the Company raised an aggregate of $12,859,367 USD in equity pursuant to a
marketed “best efforts” private placement subscription receipt financing managed by a syndicate of agents. An
aggregate of 23,380,688 subscription receipts were issued at a price of $0.55 USD per subscription receipt, all of
which were converted, without any further payment or action required by the holders, thereof, on a one for one
basis into units of Touchstone, each unit consisted of one common share of Touchstone and one-half of one
common share purchase warrant of Touchstone, with each whole warrant being exercisable for one common share
at an exercise price of $0.75 USD until June 11, 2012.

Of the funds raised, 62.8% was used for the Acquisition and the remainder for working capital.
2.4 Effect on Financial Position
Other than as may be disclosed in this business acquisition report, the Company does not currently have any plans
or proposals for material changes in its business affairs of the business acquired pursuant to the acquisition of the
Damus/Cirrus assets. The Company acquired producing assets which will a significant effect on the results of
operations and financial position of the Company.
In connection with the Acquisition, the Company arranged for the preparation of a reserve report (the “Reserves
Report”) with respect to the reserves acquired, in accordance with the form set out in National Instrument 51-101.
A copy of the Reserve Report as prepared by GLJ Petroleum Consultants Ltd. is attached at the end of this report.
The following tables disclosed the estimated reserves and related future net revenue attributed to the business
acquired pursuant to the Acquisition, as well as the pricing assumptions used to develop these estimates. The
Company retained GLJ Petroleum Consultants Ltd., an independent qualified reserves evaluator for the purposes
of National Instrument 51-101, to prepare the reserves and future net revenue estimates. The pricing assumptions
used were based on GLJ Petroleum Consultants Ltd. July 1, 2010 price forecast. The estimates of future net
revenue disclosed do not represent current fair market value. The estimates of oil reserves provided herein are
estimates only. Actual oil reserves may be greater or less than the estimates provided herein. All dollar amounts
are reported in United States currency, unless otherwise indicated.
Proven Producing 986
Proven Developed
(Non-Producing) 712
Proved Undeveloped 475
Total Proven 2,173
Probable 2,626
Total Proven Plus
Probable 4,799
Economically Recoverable
Remaining Reserves
Gross - 100% Lease
Company Gross
Company Net
O il O il
O il
Light & Light & Light &
Medium Heavy Gas Medium Heavy Gas Medium Heavy
Mbbl Mbbl MMcf Mbbl Mbbl MMcf Mbbl Mbbl
-
-
-
-
-
-
SUMMARY O F RESERVES
EFFECTIVE AUGUST 31, 2010
-
-
-
-
-
-
986
712
475
2,173
2,626
4,799
TO TAL CO MPANY INTERESTS (FO RECAST VALUES)
BEFO RE TAX PRESENT VALUE - (M$ US)
EFFECTIVE AUGUST 31, 2010
Proven Producing 10,768
Proved Developed Non-Producing 23,042
Proved Undeveloped 12,468
Total Proven 46,278
Probable 98,265
Total Proven Plus Probable 144,542
-
-
-
-
-
-
-
-
-
-
-
-
534
415
296
1,245
1,577
2,823
Undisc 5%
Discounted at
10% 15% 20%
7,328
16,261
9,176
32,765
61,010
93,775
5,569
11,707
7,108
24,384
41,957
66,341
4,529
8,632
5,723
18,884
30,936
49,820
-
-
-
-
-
-
3,844
6,509
4,745
15,099
23,945
39,044

TO TAL CO MPANY INTERESTS (FO RECAST VALUES)
AFTER TAX PRESENT VALUE - (M$ - US)
EFFECTIVE AUGUST 31, 2010
Proven Producing 4,052
Proved Developed Non-Producing 6,252
Proved Undeveloped 2,836
Total Proven 13,140
Probable 23,958
Total Proven Plus Probable 37,097
Undisc 5%
Discounted at
10% 15% 20%
2,536
5,352
2,825
10,714
17,025
27,738
1,924
4,214
2,580
8,718
12,569
21,287
1,612
3,236
2,307
7,155
9,667
16,822
1,417
2,464
2,059
5,940
7,709
13,649
NYMEX WTII Near
ICE BRENT
Near Mo nth
Mo nth Futures Light, Sweet Bo w River Llo yd Blend
Bank o f Mo nth Futures Co ntract
Co ntract Crude Oil Crude Oil Crude Oil
Canada Crude Oil at
Crude Oil (40 AP I, 0.3%S) Stream Quality Stream Quality
Average Cus ing Oklaho ma FOB No rth Sea at Edmo nto n at Hardis ty at Hardis ty
No o n Co ns tant Then Then Then Then Then
Inflation Exchange 2,010.00 Current Current Current Current Current
Year (%) $ US/$ Cdn $ US/bbl $ US/bbl $ US/bbl $ Cdn/bbl $ Cdn/bbl $ Cdn/bbl
1996 1.6
1997 1.6
1998 1.0
1999 1.7
2000 2.7
2001 2.5
2002 2.3
2003 2.8
2004 1.8
2005 2.2
2006 2.0
2007 2.2
2008 2.4
2009 0.0
2010 Q1 1.6
2010 Q2 (e) 1.8
2010 Q3 2.0
2010 Q4 2.0
2010 Full Year 1.9
2010 Q3-Q4 2.0
2011 2.0
2012 2.0
2013 2.0
2014 2.0
2015 2.0
2016 2.0
2017 2.0
2018 2.0
2019 2.0
2020 + 2.0
0.733
0.722
0.675
0.673
0.673
0.646
0.637
0.716
0.770
0.826
0.882
0.935
0.943
0.880
0.961
0.969
0.950
0.950
0.958
0.950
0.950
0.950
0.950
0.950
0.950
0.950
0.950
0.950
0.950
0.950
CRUDE O IL PRICE FO RECAST
EFFECTIVE JULY 1, 2010
28.77
26.57
18.30
24.20
37.33
31.27
30.57
35.62
46.17
61.98
70.95
76.05
102.44
62.01
78.72
77.90
80.00
80.00
79.16
80.00
81.37
82.66
83.87
85.00
85.00
85.00
85.00
85.00
85.00
85.00
21.98
20.62
14.44
19.25
30.23
26.00
26.08
31.07
41.38
56.58
66.22
72.39
99.64
61.78
78.72
77.90
80.00
80.00
79.16
80.00
20.31
19.32
13.34
17.99
28.41
24.87
25.02
28.47
38.02
55.14
66.16
72.71
98.30
62.50
77.26
78.91
78.50
78.50
78.29
78.50
29.38
27.85
20.36
27.63
44.57
39.44
40.33
43.66
52.96
69.02
73.21
77.06
102.89
66.32
80.56
77.22
83.26
83.26
81.08
83.26
25.12
21.18
14.63
23.78
35.28
27.69
31.83
32.11
37.43
44.73
51.82
53.64
84.31
60.18
73.74
67.19
71.61
70.77
70.83
71.19
21.55
20.55
15.38
22.14
32.61
23.47
30.60
31.18
36.31
43.03
50.36
52.03
82.60
58.40
72.24
65.73
70.36
69.52
69.46
69.94
83.00 81.50 86.42 72.59 71.30
86.00 84.50 89.58 73.45 72.11
89.00 87.50 92.74 74.19 72.80
92.00 90.50 95.90 76.72 75.28
93.84 92.34 97.84 78.27 76.80
95.72 94.22 99.81 79.85 78.35
97.64 96.14 101.83 81.46 79.93
99.59 98.09 103.88 83.11 81.55
101.58 100.08 105.98 84.78 83.19
+ 2.0% / year + 2.0% / year + 2.0% / year + 2.0% / year + 2.0% / year

Reserve Definitions
Bank o f WCS Heavy Crude Light Crude Medium Crude
Canada Stream Quality P ro xy (12 AP I) (35 AP I, 1.2%S) (29 api, (29 api, 205%s )
Average at Hardis ty at Hardis ty at Cro mer at Cro mer
No o n Then Then Then Then
Inflation Exchange Current Current Current Current
Year (%) $ US/$ Cdn $ Cdn/bbl $ US/bbl $ US/bbl $ Cdn/bbl
1996 1.6
1997 1.6
1998 1.0
1999 1.7
2000 2.7
2001 2.5
2002 2.3
2003 2.8
2004 1.8
2005 2.2
2006 2.0
2007 2.2
2008 2.4
2009 0.0
2010 Q1 1.6
2010 Q2 (e) 1.8
2010 Q3 2.0
2010 Q4 2.0
2010 Full Year 1.9
2010 Q3-Q4 2.0
2011 2.0
2012 2.0
2013 2.0
2014 2.0
2015 2.0
2016 2.0
2017 2.0
2018 2.0
2019 2.0
2020 + 2.0
CRUDE O IL PRICE FO RECAST - continued
EFFECTIVE JULY 1, 2010
0.733
0.722
0.675
0.673
0.673
0.646
0.637
0.716
0.770
0.826
0.882
0.935
0.943
0.880
0.961
0.969
0.950
0.950
0.958
0.950
0.950
0.950
0.950
0.950
0.950
0.950
0.950
0.950
0.950
0.950
N/A 20.06
N/A 14.41
N/A 9.45
N/A 19.49
N/A 27.49
N/A 16.77
N/A 26.57
N/A 26.26
N/A 29.11
43.74 34.07
50.66 41.84
52.38 43.42
82.95 74.94
58.66 54.46
72.58
66.18
70.76
69.92
69.86
70.34
The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree of
associated uncertainty. Categories of proved and probable reserves have been established to reflect the level of
these uncertainties and to provide an indication of the probability of recovery.
The estimation and classification of reserves requires the application of professional judgement combined with
geological and engineering knowledge to assess whether or not specific reserves classification criteria have been
satisfied Knowledge of concepts, including uncertainty and risk, probability and statistics, and deterministic and
probabilistic estimation methods, is required to properly use and apply reserves definitions.
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:
66.43
58.45
64.99
63.90
Analysis of drilling, geological, geophysical and engineering data;
The use of established technology; and
Specified economic conditions, which are general accepted as being reasonable and shall be disclosed.
63.44
63.44
Reserves are classified according to the degree of certainty associated with the estimates.
28.41
26.52
19.31
26.97
43.28
35.22
37.43
40.09
49.14
62.18
66.38
71.13
96.08
63.84
78.69
75.01
79.93
79.93
78.39
79.93
26.08
23.72
16.96
25.37
39.92
31.58
35.48
37.55
45.64
56.77
62.26
65.71
93.10
62.96
76.87
73.47
78.27
78.27
76.72
78.27
71.70 65.24 81.24 79.94
72.51 65.33 83.31 81.52
73.20 65.26 86.25 82.54
75.68 67.52 89.19 85.35
77.20 68.90 90.99 87.07
78.75 70.32 92.82 88.83
80.33 71.76 94.70 90.63
81.95 73.22 96.61 92.46
83.59 74.72 98.56 94.32
+ 2.0% / year + 2.0% / year + 2.0% / year + 2.0% / year

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.
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 well exceed the sum of the estimated proved
plus probable plus possible reserves.
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 (eg: when
compared to the cost of drilling a well) to put the reserves on production. The development 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 cost of drilling a well) is required to render them
capable of production. They must fully meet the requirement of the reserves category (proved, probable,
possible) to which they are assigned.
The Acquisition will provide the Company with the ability to achieve economies of scale through production of
oil from existing wells and through increased production from the exploration and development of new oil wells
in the 4,200 acres acquired. The Company plans to fund the drilling and recompletion of 5 wells. Increased
production from the workovers and new wells will provide the necessary cash flow from operations to not only
break-even, but the potential to generate greater cash flow from higher oil prices for expansion. Expertise
demonstrated through increased production and cash flow will enhance the Company’s presence given the fiscal
and tax regime of Trinidad. The greater presence provides the Company with more opportunities to acquire other
existing oil and gas operations in Trinidad.
The effect of the acquisition on the Company’s financial position is outlined in the Company’s audited statements
of operations, which are attached to the Business Acquisition Report and referred to item 3 below.

Abbreviations
2.5 Prior Valuations
Oil and Natural Gas Liquids Natural Gas
bbls Barrels Mcf thousand cubic feet
Mbbls thousand barrels MMcf million cubic feet
bbls/d barrels of oil per day Mcf/d thousand cubic feet per day
boe/d barrels of oil equivalent per day m3 cubic meters
NGLs natural gas liquids (consisting of any one
or more of propane, butane and
condensate thousand stock tank barrels
of oil
bpd barrels of production per day
Other
boe means barrels of oil equivalent. A barrel of oil equivalent is determined by converting a volume
of natural gas to barrels using the ration of six (6) mcf to one (1) barrel. Boes may be misleading,
particularly if used in isolation the boe conversion ration of six (6) mcf: one (1) bbl is based on an
energy equivalency method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead.
GORR means gross overriding royalty
The Company had an independent evaluation of the oil and gas reserves with an effective date of August 31,
2010, prepared by GLJ Petroleum Consultants Ltd., even though an evaluation opinion was not required by
securities legislation or a Canadian stock exchange or market to support the consideration paid for the acquisition
of Damus/Cirrus assets.
2.6 Parties to Transaction
The transaction was not with an informed person, associate or affiliate of Touchstone.
2.7 Date of Report
April 15, 2011.
Item 3: Financial Statements
3.1 Schedule “A” - Audited Statement of Operations
The audited Statement of Operations for the properties acquired for the year ended September 30, 2010 and
September 30, 2009.
3.2 Schedule “B” - Unaudited Statement of Operations
The unaudited Interim Statement of Operations for the properties acquired includes the operations for the three
months ended December 31, 2010 and 2009.
3.3 Schedule “C” – Unaudited Pro Forma Statements of Operations
The unaudited pro forma operating statement for the year ended September 30, 2010 and the unaudited pro forma
operating statement for the three months ended December 31, 2010.
Cautionary Statements

This report contains forward-looking statements and information (“forward-looking statements”) within the meaning of the applicable securities
laws. Although Touchstone believes that the expectations reflected in its forward-looking statements are reasonable, such statements have been
based upon currently available information to the Company. Such statements are subject to known and unknown risks, uncertainties, and other
factors that could influence actual results or events and cause actual results or events to differ materially from those stated, anticipated or implied
in forward-looking statements. Risks include, but are not limited to: the risks associated with the oil and gas industry (e.g., operational risks in
development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures;
the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety
and environmental risks), commodity price, price and exchange rate fluctuations and uncertainties resulting from potential delays or changes in
plans with respect to exploration and development projects or capital expenditures. Readers are cautioned not to place undue reliance on
forward-looking statements. The statements in this report are made as of the date of this report and, except as required by applicable law,
Touchstone does not undertake any obligation to publicly update or to revise any of the included forward-looking statements, whether as a result
of new information, future events or otherwise. The forward-looking statements contained expectations or statements made by third-parties in
respect of the Company or its financial or operating results or its securities.

To the Board of Directors of
Touchstone Exploration Inc.
SCHEDULE “A”
AUDITORS’ REPORT
We have audited the accompanying schedules of revenue and operating expenses for Cirrus Energy (Trinidad) Ltd.’s
(``Cirrus``) and the Damus Oil Limited’s (``Damus``) interests in the Lease Operatorship Agreements in the Coora Block
(“Cirrus/Damus Interest) for the years ended September 30, 2010 and 2009 and a summary of significant accounting
policies and other explanatory information (together the ``Operating Statements``).
Management`s responsibility for the operating statement.
Management of Touchstone Exploration Inc. is responsible for the preparation of the Operating Statements of the
Cirrus/Damus interest in the Lease Operatorship Agreements in the Coora Block and for such internal controls as
management determines is necessary to enable the preparation of the Operating Statements that are free from material
misstatement, whether due to fraud or error.
Auditors`responsibility
Our responsibility is to express an opinion on the Operating Statements based on our audits. We conducted our audits in
accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical
requirements and plan and perform the audit to obtain reasonable assurance about whether the Operating Statements are
free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the Operating
Statements. The procedures selected depend on the auditors` judgement, including the assessment of the risks of material
misstatements of the Operating Statements, whether due to fraud or error. In making those risk assessments, the auditors
consider internal control relevant to the entity`s preparation of the Operating Statements in order to design audit
procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness
of the entity`s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the
reasonableness of accounting estimates, if any, made by management, as well as evaluating the overall presentation of the
Operating Statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the Operating Statements of the Cirrus/Damus Interest in the Lease Operating Agreements in the Coora
Block for each of the years ended September 30, 2010 and 2009 are prepared, in all material respects, in accordance with
the financial reporting framework as described in Note 1.
Calgary, Alberta Canada
April 15, 2010 Chartered Accountants

SCHEDULE “B”
Cirrus and Damus Interest
Statement of Revenue, Royalties and Operating Expenses
For the Years Ended September 30, 2010 and 2009
“See accompanying notes”
Year Ended
September 30, 2010
US$
Year Ended
September 30, 2009
US$
Oil sales 5,657,837 3,520,984
Less: Royalties (2,389,863) (1,603,666)
3,267,974 1,917,318
Less: Operating expenses (1,423,469) (1,487,802)
1,844,505 429,516

Cirrus and Damus Interest
Notes to Schedules of Revenue, Royalties and Operating Expenses
For the Years ended September 30, 2010 and 2009
1. Basis of presentation
The Schedules of Revenue and Operating Expenses (the ``Schedules``) include the operating results relating to the
operations of oil and gas properties for Coora (the ``Cirrus and Damus Interest``) indirectly acquired by Touchstone
Exploration Inc. through the wholly owned subsidiary Territorial Services Ltd. pursuant to a Purchase and Sale
agreement with Cirrus Energy Corporation, Cirrus Energy (Trinidad) Ltd. (collectively “Cirrus”) and Damus Oil
Limited (“Damus”) dated October 29, 2010. The properties were acquired with an effective date of January 31, 2011
and closing date was the January 31, 2011. The New Dome and South Seco blocks were considered immaterial to the
transaction by management and no value or reserves were assigned.
The line items in the Schedules have been prepared in all material respects using accounting policies that are
permitted by Generally Accepted Accounting Principles (“GAAP”), with such accounting policies applying to those
line items as if such line items were presented as part of a complete set of financial statements. The line items
comprising the Schedules are presented in accordance with a reporting framework prescribed by securities regulatory
authorities that requires the presentation of a schedule of gross revenue, royalty expense, production costs and
operating income.
Accordingly, the Schedules include the following line items: revenue, royalties and operating expenses related to the
Cirrus and Damus Interest and do not include any provision for depletion and depreciation, asset retirement
obligations, future capital costs, impairment of unevaluated properties, general and administrative expense or income
taxes as these amounts are based on the combined consolidated operations of Cirrus and Damus.
2. Significant accounting policies
Revenue recognition
Revenue associated with sales of crude oil is recognized upon transfer of title, which is when the risk of ownership
passes to the purchaser and physical delivery occurs.
Royalties
Royalties are recorded at the time the product is produced or sold. Royalties are calculated in accordance with rules
and regulations as set out by the Petroleum Company of Trinidad and Tobago Limited (“Petrotrin”).
The Country of Trinidad has a notional royalty rate which is 12.5% of production and there is a notional overriding
royalty of 33.0% on production that is payable to the Petrotrin. Included in royalties are user fees that cover
electricity, maintenance of the electrical high voltage system, labour and any other costs associated with management
of the Lease Operatorship Agreement.
Operating expenses
Operating expenses are the costs of maintaining and operating property and equipment on producing oil leases and
includes field labour, insurance, maintenance, repairs, utilities, and supplies that relate to the operations of the wells.

SCHEDULE “B”
Cirrus and Damus Interest
Statement of Revenue, Royalties and Operating Expenses
For the Three Months ended December 31, 2010 and 2009
“See accompanying notes”
Three Months Ended
December 31, 2010
US$
(unaudited)
Three Months Ended
December 31, 2009
US$
(unaudited)
Oil sales 1,438,773 1,367,957
Less: Royalties (659,074) (564,023)
779,699 803,934
Less: Operating expenses (461,340) (331,114)
318,359 472,820

Cirrus and Damus Interest
Notes to Schedules of Revenue, Royalties and Operating Expenses
For the Three Months Ended December 31, 2010 and 2009
1. Basis of presentation
The Schedules of Revenue and Operating Expenses (the ``Schedules``) include the operating results relating to the
operations of oil and gas properties for Coora (the ``Cirrus and Damus Interest``) indirectly acquired by Touchstone
Exploration Inc. through the wholly owned subsidiary Territorial Services Ltd. pursuant to a Purchase and Sale
agreement with Cirrus Energy Corporation, Cirrus Energy (Trinidad) Ltd. (“Cirrus”), and Damus Oil Limited
(“Damus”) dated October 29, 2010. The properties were acquired with an effective date of January 31, 2011 and
closing date of January 31, 2011. The New Dome and South Seco blocks were considered immaterial to the
transaction by management and no value or reserves were assigned.
The line items in the Schedules have been prepared in all material respects using accounting policies that are
permitted by Generally Accepted Accounting Principles (“GAAP”), with such accounting policies applying to those
line items as if such line items were presented as part of a complete set of financial statements. The line items
comprising the Schedules are presented in accordance with a reporting framework prescribed by securities regulatory
authorities that requires the presentation of a schedule of gross revenue, royalty expense, production costs and
operating income.
Accordingly, the Schedules include the following line items: revenue, royalties and operating expenses related to the
Cirrus and Damus Interest and do not include any provision for depletion and depreciation, asset retirement
obligations, future capital costs, impairment of unevaluated properties, general and administrative expense or income
taxes as these amounts are based on the combined consolidated operations of Cirrus and Damus.
2. Significant accounting policies
Revenue recognition
Revenue associated with sales of crude oil is recognized upon transfer of title, which is when the risk of ownership
passes to the purchaser and physical delivery occurs.
Royalties
Royalties are recorded at the time the product is produced or sold. Royalties are calculated in accordance with rules
and regulations as set out by the Petroleum Company of Trinidad and Tobago Limited (“Petrotrin”).
The Country of Trinidad has a notional royalty rate which is 12.5% of production and there is a notional overriding
royalty of 33.0% on production that is payable to the Petrotrin. Included in royalties are user fees that cover
electricity, maintenance of the electrical high voltage system, labour and any other costs associated with management
of the Lease Operatorship Agreement.
Operating expenses
Operating expenses are the costs of maintaining and operating property and equipment on producing oil leases and
includes field labour, insurance, maintenance, repairs, utilities, and supplies that relate to the operations of the wells.

SCHEDULE “C”
Pro Forma Schedule of Revenue, Royalties and Operating Expenses
For the year ended September 30, 2010; and
For the three months ended December 31, 2010
TOUCHSTONE EXPLORATION INC.
Pro Forma Schedule of Revenue, Royalties and Operating Expenses
For the year ended September 30, 2010
Cirrus and Damus Touchstone
For the year ended
September 30, 2010
Pro Forma
Touchstone
Interest Exploration Inc. Exploration Inc.
$US
$US
$US
Oil sales 5,657,837 896,268 6,554,105
Less: Royalties (2,389,863) (411,627) (2,801,490)
3,267,974 484,641 3,752,615
Less: Operating expenses (1,423,469) (174,513) (1,597,982)
1,844,505 310,128 2,154,633
TOUCHSTONE EXPLORATION INC.
Pro Forma Schedule of Revenue, Royalties and Operating Expenses
For the three months ended December 31, 2010
Cirrus and Damus
Interest
$US
Touchstone
Exploration Inc.
$US
For the three
months ended
December 31, 2010
Pro Forma
Touchstone
Exploration Inc.
$US
Oil sales 1,438,773 1,156,004 2,594,777
Less: Royalties (659,074) (513,642) (1,172,716)
779,699 642,362 1,422,061
Less: Operating expenses (461,340) (173,124) (634,464)
“See accompanying note
318,359 469,238 787,597

Notes to Pro Forma Schedule of Revenue, Royalties and Operating Expenses
For the year ended September 30, 2010
For the three months ended December 31, 2010
1. Basis of presentation
On January 31, 2011, the Company completed the acquisition of a 100% interest in the Lease Operatorship
Agreements in the Coora Block and certain Farm-out Agreements in the New Dome and South Palo Seco blocks and
associated equipment and production facilities (“the Acquisition”) from Cirrus Energy Corporation, Cirrus Energy
(Trinidad) Ltd. and Damus Oil Limited (“Cirrus and Damus Interest”). The Acquisition was completed through the
Company’s wholly owned subsidiary Territorial Services Limited.
The unaudited pro forma operating statements of the Company have been prepared by management of the Company
and have been derived from and should be read in conjunction with, the following:
(a) The Company’s audited consolidated financial statements for the year ended September 30, 2010;
(b) The Company’s unaudited consolidated financial statements for the three months ended December 31, 2010; and
(c) The unaudited schedules of revenue, royalties, and operating expenses for the three months ended December 31,
2010 and 2009 and the audited schedules of revenue, royalties and operating expenses for the years ended
September 30, 2010 and 2009.
The unaudited pro forma operating statement for the year ended September 30, 2010 and the unaudited pro forma
operating statement for the three months ended December 31, 2010 have been prepared assuming the Acquisition
occurred on October 1, 2009 has been prepared assuming the Acquisition occurred on October 1, 2010. The pro
forma operating statements are not necessarily indicative of the results that actually would have occurred if the events
reflected herein had taken place on the dates indicated, or of the results which may be obtained in the future.
The unaudited pro forma operating statements do not include any provision for depletion and depreciation, asset
retirement obligations, future capital costs, impairment of unevaluated properties, general and administrative expense
or income taxes as these amounts are based on the consolidated operations of the Predecessor of which the acquired
Cirrus and Damus Interest formed only a part.
2. Significant accounting policies
Revenue recognition
Revenue associated with sales of crude oil is recognized upon transfer of title, which is when the risk of ownership
passes to the purchaser and physical delivery occurs.
Royalties
Royalties are recorded at the time the product is produced or sold. Royalties are calculated in accordance with rules
and regulations as set out by the Petroleum Company of Trinidad and Tobago Limited (“Petrotrin”).
The Country of Trinidad has a notional royalty rate which is 12.5% of production and there is a notional overriding
royalty of 33.0% on production that is payable to Petrotrin. Included in royalties are user fees that cover electricity,
maintenance of the electrical high voltage system, labour and any other costs associated with management of the
Lease Operatorship Agreement.
Operating expenses
Operating expenses are the costs of maintaining and operating property and equipment on producing oil leases and
includes field labour, insurance, maintenance, repairs, utilities, and supplies.

“SCHEDULE “D”
GLJ PETROLEUM CONSULTANTS LTD.
RESERVE REPORT

TOUCHSTONE EXPLORATION
COORA BLOCK
Effective August 31, 2010
Prepared by
T. Mark Jobin, P. Geol.
Scott M. Quinell, P. Eng.
The analysis of this property as reported herein was conducted within the context of an evaluation of a distinct
group of properties in aggregate. Extraction and use of this analysis outside this context may not be appropriate
without supplementary due diligence.
GLJ
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COORA BLOCK
TABLE OF CONTENTS
GLJ
Page: 2 of 144
COVER LETTER 4
INDEPENDENT PETROLEUM CONSULTANTS' CONSENT 5
INTRODUCTION 6
SUMMARY
Summary of Reserves and Values 8
Historical and Forecast Oil Production Gross Lease/Company Interest 9
Daily Production, Reserves and Present Value Summary 10
DISCUSSION 15
LAND
Summary of Well Interests and Burdens 30
MAPS
Map 1 Land Map 42
Map 2 Base Map - Coora Block 1 and Block 2 43
Map 3 Proposed Locations - Coora Block 1 and Block 2 44
PLOTS
Plot 1 Coora Block - Oil Time Semilog Property Plot 45
Plot 2 Coora Block - Oil Cum Coord Property Plot 46
TABLES
Table 1 Well List and Production Summary 47
Table 2 Gross Lease Reserves Summary 57
Table 2.1 Oil Reservoir Parameters 61
Table 2.2 Oil Decline Parameters 66
Table 3 Gross Lease Daily Oil Production 68
Table 3.1 Company Daily Oil Production 72
Table 4 Economic Parameters 76
ECONOMIC FORECASTS
Proved Producing 79
Proved Developed Nonproducing 82
Proved Undeveloped 85
Total Proved 88
Total Probable 91
Total Proved Plus Probable 94
EVALUATION PROCEDURE 97
RESERVES DEFINITIONS 103
PRODUCT PRICE AND MARKET FORECASTS 107
Page
January 28, 2011 15:10:30
Petroleum Consultants

TABLE OF CONTENTS
GLJ
Page: 3 of 144
APPENDIX I 109
Reserves Estimation - Supporting Information
APPENDIX II
Certificates of Qualification 141
Page
January 28, 2011 15:10:30
Petroleum Consultants

Mr. Ron Bryant
Touchstone Exploration Inc.
200, 209 – 8 th Avenue SW
Calgary, Alberta T2P 1B8
Dear Sir:
January 26, 2011
Project 1110792
Re: Touchstone Exploration Inc.
Coora Block Acquisition
Effective August 31, 2010
GLJ Petroleum Consultants (GLJ) has completed an independent reserves assessment and evaluation of the
Coora Block property of Touchstone Exploration Inc. (the “Company”). The effective date of this evaluation is
August 31, 2010.
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.
It was GLJ’s primary mandate in this evaluation to provide an independent evaluation of the oil and gas reserves
of the Company in aggregate. Accordingly it may not be appropriate to extract individual property or entity
estimates for other purposes. Our engagement letter notes these limitations on the use of this report.
It is trusted that this evaluation meets your current requirements. Should you have any questions regarding this
analysis, please contact the undersigned.
JLA/ljn
Attachments
GLJ Petroleum
Consultants
Yours very truly,
GLJ PETROLEUM CONSULTANTS LTD.
ORIGINALLY SIGNED BY
Jodi L. Anhorn, M.Sc., P. Eng.
Vice President
Principal Officers:
Harry Jung, P. Eng.
President, C.E.O.
Dana B. Laustsen, P. Eng.
Executive V.P., C.O.O.
Keith M. Braaten, P. Eng.
Executive V.P.
Officers / Vice Presidents:
Terry L. Aarsby, P. Eng.
Jodi L. Anhorn, P. Eng.
Leonard L. Herchen, P. Eng.
Myron J. Hladyshevsky, P. Eng.
Bryan M. Joa, P. Eng.
Mark Jobin, P. Geol.
John E. Keith, P. Eng.
John H. Stilling, P. Eng.
Douglas R. Sutton, P. Eng.
James H. Willmon, P. Eng.
4100, 400 - 3rd Avenue S.W., Calgary, Alberta, Canada T2P 4H2 • (403) 266-9500 • Fax (403) 262-1855 • GLJPC.com

INDEPENDENT PETROLEUM CONSULTANTS’ CONSENT
The undersigned firm of Independent Petroleum Consultants of Calgary, Alberta, Canada has
prepared an independent evaluation of the Touchstone Exploration Inc. Coora Block property and
hereby gives consent to the use of its name and to the said estimates. The effective date of the
evaluation is August 31, 2010.
In the course of the evaluation, Touchstone Exploration Inc. provided GLJ 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. Touchstone Exploration Inc. 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 Touchstone
Exploration Inc. 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 and production estimate is a function of the quality and quantity of
available data and of engineering interpretation and judgment. While reserves 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 evaluated herein.
PERMIT TO PRACTICE
GLJ PETROLEUM CONSULTANTS LTD.
ORIGINALLY SIGNED BY
Signature: Doug R. Sutton
Date: January 26, 2011
PERMIT NUMBER: P 2066
The Association of Professional Engineers,
Geologists and Geophysicists of Alberta
Page: 5 of 144
ORIGINALLY SIGNED BY
Keith M. Braaten
GLJ Petroleum Consultants Ltd.
GLJ
Petroleum Consultants

INTRODUCTION
GLJ Petroleum Consultants (GLJ) was commissioned by Touchstone Exploration Inc. (the
“Company”) to prepare an independent evaluation of its oil and gas reserves effective August 31,
2010. The locations of the most significant reserves properties are indicated on the attached
index map.
The evaluation was initiated in September 2010 and completed by November 2010. Estimates of
reserves and projections of production were generally prepared using well information and
production data available from public sources to approximately August 31, 2010. The Company
provided land, accounting data and other technical information not available in the public
domain to approximately August 31, 2010. In certain instances, the Company also provided
recent engineering, geological and other information up to August 31, 2010. 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.
This evaluation has been prepared in accordance with procedures and standards contained in the
Canadian Oil and Gas Evaluation (COGE) Handbook. The reserves definitions used in preparing
this report (included herein under “Reserves Definitions”) are those contained in the COGE
Handbook and the Canadian Securities Administrators National Instrument 51-101 (NI 51-101).
The evaluation was conducted on the basis of the GLJ July 1, 2010 Price Forecast which is
summarized in the Product Price and Market Forecasts section of this report.
Tables summarizing production, royalties, costs, revenue projections, reserves and present value
estimates for various reserves categories for individual properties and the Company total are
provided in the tabbed sections of this Summary Report.
The Evaluation Procedure section outlines general procedures used in preparing this evaluation. The
individual property reports, provided under separate cover, provide additional evaluation details.
The following summarizes evaluation matters that have been included/excluded in cash flow
projections:
• in accordance with NI 51-101, the effect on projected revenues of the Company’s
financial hedging activity has not been included,
GLJ
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Petroleum Consultants

• provisions for the abandonment of all of the Company’s wells to which reserves have
been attributed have been included; all other abandonment and reclamation costs have
not been included,
• general and administrative (G&A) costs and overhead recovery have not been included,
• undeveloped land values have not been included.
GLJ
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Petroleum Consultants

Company: Touchstone Exploration Reserve Class: Various
Property: Coora Block Development Class: Classifications
Pricing: GLJ (2010-07)
Effective Date: August 31, 2010
Summary of Reserves and Values
Proved Total
Developed Proved
Proved Non- Proved Total Total Plus
Producing producing Undeveloped Proved Probable Probable
MARKETABLE RESERVES
Light/Medium Oil (Mbbl)
Gross Lease 986 712 475 2,173 2,626 4,799
Total Company Interest 986 712 475 2,173 2,626 4,799
Net After Royalty 534 415 296 1,246 1,577 2,823
Oil Equivalent (Mbbl)
Gross Lease 986 712 475 2,173 2,626 4,799
Total Company Interest 986 712 475 2,173 2,626 4,799
Net After Royalty 534 415 296 1,246 1,577 2,823
BEFORE TAX PRESENT VALUE (M$)
0% 10,768 23,042 12,468 46,278 98,265 144,542
5% 7,328 16,261 9,176 32,765 61,010 93,775
8% 6,153 13,313 7,831 27,298 48,256 75,554
10% 5,569 11,707 7,108 24,384 41,957 66,341
12% 5,094 10,334 6,492 21,920 36,885 58,805
15% 4,529 8,632 5,723 18,884 30,936 49,820
20% 3,844 6,509 4,745 15,099 23,945 39,044
AFTER TAX PRESENT VALUE (M$)
0% 4,052 6,252 2,836 13,140 23,958 37,097
5% 2,536 5,352 2,825 10,714 17,025 27,738
8% 2,114 4,659 2,688 9,461 14,120 23,580
10% 1,924 4,214 2,580 8,718 12,569 21,287
12% 1,778 3,798 2,470 8,045 11,263 19,308
15% 1,612 3,236 2,307 7,155 9,667 16,822
20% 1,417 2,464 2,059 5,940 7,709 13,649
Run Date: January 27, 2011 14:46:37
BOE Factors: HVY OIL 1.0 RES GAS 6.0 PROPANE 1.0 ETHANE 1.0
COND 1.0 SLN GAS 6.0 BUTANE 1.0 SULPHUR 0.0
Page: 8 of 144
1110792 Class (A,B1,B2,C,F,I), GLJ (2010-07), psum January 27, 2011 14:49:05
GLJ
Petroleum Consultants

Historical and Forecast Production
Company: Touchstone Exploration Pricing: GLJ (2010-07)
Property: Coora Block Effective Date: August 31, 2010
1 10 100 1000 10000
Oil Production (bbl/d)
1 10 100 1000
Oil Production (bbl/d)
Gross Lease Oil
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
Year
Company Interest Oil
Legend
A Proved Producing
C Total Proved
G Proved Plus Probable Producing
I Total Proved Plus Probable
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
Year
Legend
A Proved Producing
C Total Proved
G Proved Plus Probable Producing
I Total Proved Plus Probable
*Note: Historical company interest production is based on current interests in the evaluated reserves entities applied to reported actual gross
lease production. Consequently, company actuals may differ from the history shown due to changes in ownership.
Company Interest Oil
1110792 / Jan 27, 2011
GLJ
Page: 9 of 144
I
C
G
A
I
C
G
A
Petroleum Consultants

Company: Touchstone Exploration Reserve Class: Various
Property: Coora Block Development Class: Classifications
Pricing: GLJ (2010-07)
Effective Date: August 31, 2010
Daily Production, Reserves and Present Value Summary
Before Tax
2010 Gross Lease Production 2010 Company Interest Production Gross Lease Reserves Company Interest Reserves 10% Dcf
Present
Reserve Gas Oil NGL Oil Eq. Gas Oil NGL Oil Eq. Gas Oil NGL Sulphur Oil Eq. Gas Oil NGL Sulphur Oil Eq. Value
Entity Description Class Mcf/d bbl/d bbl/d boe/d Mcf/d bbl/d bbl/d boe/d MMcf Mbbl Mbbl Mlt Mboe MMcf Mbbl Mbbl Mlt Mboe M$
Proved Producing
Coora
1) Current Production.
1) Coora Producing A 0 222 0 222 0 222 0 222 0 986 0 0 986 0 986 0 0 986 5,569
Total: 1) Current Production. 0 222 0 222 0 222 0 222 0 986 0 0 986 0 986 0 0 986 5,569
Total: Coora 0 222 0 222 0 222 0 222 0 986 0 0 986 0 986 0 0 986 5,569
Total: Proved Producing 0 222 0 222 0 222 0 222 0 986 0 0 986 0 986 0 0 986 5,569
Proved Developed Nonproducing
Coora
1) Current Production.
1) Coora Producing 0 0 0 0 0 0 0 0 0 -213 0 0 -213 0 -213 0 0 -213 4,576
Total: 1) Current Production. 0 0 0 0 0 0 0 0 0 -213 0 0 -213 0 -213 0 0 -213 4,576
2) Recompletions/Workovers
2011-Q3 B1 0 0 0 0 0 0 0 0 0 253 0 0 253 0 253 0 0 253 2,148
2012-Q3 B1 0 0 0 0 0 0 0 0 0 249 0 0 249 0 249 0 0 249 2,111
2013-Q3 B1 0 0 0 0 0 0 0 0 0 243 0 0 243 0 243 0 0 243 1,915
2014-Q3 B1 0 0 0 0 0 0 0 0 0 180 0 0 180 0 180 0 0 180 958
Total: 2) Recompletions/Workovers 0 0 0 0 0 0 0 0 0 925 0 0 925 0 925 0 0 925 7,131
Total: Coora 0 0 0 0 0 0 0 0 0 712 0 0 712 0 712 0 0 712 11,707
Total: Proved Developed Nonproducing 0 0 0 0 0 0 0 0 0 712 0 0 712 0 712 0 0 712 11,707
Proved Undeveloped
Coora
1) Current Production.
1) Coora Producing 0 0 0 0 0 0 0 0 0 85 0 0 85 0 85 0 0 85 1,789
Total: 1) Current Production. 0 0 0 0 0 0 0 0 0 85 0 0 85 0 85 0 0 85 1,789
2) Recompletions/Workovers
2011-Q3 0 0 0 0 0 0 0 0 0 16 0 0 16 0 16 0 0 16 652
2012-Q3 0 0 0 0 0 0 0 0 0 18 0 0 18 0 18 0 0 18 486
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Daily Production, Reserves and Present Value Summary
Before Tax
2010 Gross Lease Production 2010 Company Interest Production Gross Lease Reserves Company Interest Reserves 10% Dcf
Present
Reserve Gas Oil NGL Oil Eq. Gas Oil NGL Oil Eq. Gas Oil NGL Sulphur Oil Eq. Gas Oil NGL Sulphur Oil Eq. Value
Entity Description Class Mcf/d bbl/d bbl/d boe/d Mcf/d bbl/d bbl/d boe/d MMcf Mbbl Mbbl Mlt Mboe MMcf Mbbl Mbbl Mlt Mboe M$
Proved Undeveloped (Cont.)
Coora (Cont.)
2) Recompletions/Workovers (Cont.)
2013-Q3 0 0 0 0 0 0 0 0 0 19 0 0 19 0 19 0 0 19 322
2014-Q3 0 0 0 0 0 0 0 0 0 17 0 0 17 0 17 0 0 17 190
Total: 2) Recompletions/Workovers 0 0 0 0 0 0 0 0 0 71 0 0 71 0 71 0 0 71 1,649
3) Replacement Wells
Location F B2 0 0 0 0 0 0 0 0 0 177 0 0 177 0 177 0 0 177 2,138
Total: 3) Replacement Wells 0 0 0 0 0 0 0 0 0 177 0 0 177 0 177 0 0 177 2,138
4) Sidetrack Wells
CO-362 Sidetrack B2 0 0 0 0 0 0 0 0 0 142 0 0 142 0 142 0 0 142 1,543
Other Revenue and Expenses C 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 -10
Total: 4) Sidetrack Wells 0 0 0 0 0 0 0 0 0 142 0 0 142 0 142 0 0 142 1,532
Total: Coora 0 0 0 0 0 0 0 0 0 475 0 0 475 0 475 0 0 475 7,108
Total: Proved Undeveloped 0 0 0 0 0 0 0 0 0 475 0 0 475 0 475 0 0 475 7,108
Total Proved
Coora
1) Current Production.
1) Coora Producing C 0 222 0 222 0 222 0 222 0 858 0 0 858 0 858 0 0 858 11,934
Total: 1) Current Production. 0 222 0 222 0 222 0 222 0 858 0 0 858 0 858 0 0 858 11,934
2) Recompletions/Workovers
2011-Q3 C 0 0 0 0 0 0 0 0 0 269 0 0 269 0 269 0 0 269 2,800
2012-Q3 C 0 0 0 0 0 0 0 0 0 267 0 0 267 0 267 0 0 267 2,597
2013-Q3 C 0 0 0 0 0 0 0 0 0 263 0 0 263 0 263 0 0 263 2,236
2014-Q3 C 0 0 0 0 0 0 0 0 0 197 0 0 197 0 197 0 0 197 1,147
Total: 2) Recompletions/Workovers 0 0 0 0 0 0 0 0 0 996 0 0 996 0 996 0 0 996 8,780
3) Replacement Wells
Location F B2 0 0 0 0 0 0 0 0 0 177 0 0 177 0 177 0 0 177 2,138
Total: 3) Replacement Wells 0 0 0 0 0 0 0 0 0 177 0 0 177 0 177 0 0 177 2,138
4) Sidetrack Wells
CO-362 Sidetrack B2 0 0 0 0 0 0 0 0 0 142 0 0 142 0 142 0 0 142 1,543
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Daily Production, Reserves and Present Value Summary
Before Tax
2010 Gross Lease Production 2010 Company Interest Production Gross Lease Reserves Company Interest Reserves 10% Dcf
Present
Reserve Gas Oil NGL Oil Eq. Gas Oil NGL Oil Eq. Gas Oil NGL Sulphur Oil Eq. Gas Oil NGL Sulphur Oil Eq. Value
Entity Description Class Mcf/d bbl/d bbl/d boe/d Mcf/d bbl/d bbl/d boe/d MMcf Mbbl Mbbl Mlt Mboe MMcf Mbbl Mbbl Mlt Mboe M$
Total Proved (Cont.)
Coora (Cont.)
4) Sidetrack Wells (Cont.)
Other Revenue and Expenses C 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 -10
Total: 4) Sidetrack Wells 0 0 0 0 0 0 0 0 0 142 0 0 142 0 142 0 0 142 1,532
Total: Coora 0 222 0 222 0 222 0 222 0 2,173 0 0 2,173 0 2,173 0 0 2,173 24,384
Total: Total Proved 0 222 0 222 0 222 0 222 0 2,173 0 0 2,173 0 2,173 0 0 2,173 24,384
Total Probable
Coora
1) Current Production.
1) Coora Producing 0 1 0 1 0 1 0 1 0 249 0 0 249 0 249 0 0 249 4,814
Total: 1) Current Production. 0 1 0 1 0 1 0 1 0 249 0 0 249 0 249 0 0 249 4,814
2) Recompletions/Workovers
2011-Q3 0 0 0 0 0 0 0 0 0 166 0 0 166 0 166 0 0 166 4,115
2012-Q3 0 0 0 0 0 0 0 0 0 168 0 0 168 0 168 0 0 168 3,927
2013-Q3 0 0 0 0 0 0 0 0 0 172 0 0 172 0 172 0 0 172 3,539
2014-Q3 0 0 0 0 0 0 0 0 0 238 0 0 238 0 238 0 0 238 3,927
2015-Q3 I 0 0 0 0 0 0 0 0 0 305 0 0 305 0 305 0 0 305 2,876
2016-Q3 I 0 0 0 0 0 0 0 0 0 305 0 0 305 0 305 0 0 305 2,509
Total: 2) Recompletions/Workovers 0 0 0 0 0 0 0 0 0 1,354 0 0 1,354 0 1,354 0 0 1,354 20,894
3) Replacement Wells
Location F 0 0 0 0 0 0 0 0 0 64 0 0 64 0 64 0 0 64 1,789
Location G H2 0 0 0 0 0 0 0 0 0 102 0 0 102 0 102 0 0 102 1,384
Location H H2 0 0 0 0 0 0 0 0 0 135 0 0 135 0 135 0 0 135 1,325
Location L H2 0 0 0 0 0 0 0 0 0 136 0 0 136 0 136 0 0 136 1,161
Total: 3) Replacement Wells 0 0 0 0 0 0 0 0 0 438 0 0 438 0 438 0 0 438 5,659
4) Sidetrack Wells
CO-180 Sidetrack H2 0 0 0 0 0 0 0 0 0 141 0 0 141 0 141 0 0 141 2,527
CO-362 Sidetrack 0 0 0 0 0 0 0 0 0 52 0 0 52 0 52 0 0 52 1,246
QU-080 Sidetrack H2 0 0 0 0 0 0 0 0 0 186 0 0 186 0 186 0 0 186 3,036
QU-119 Sidetrack H2 0 0 0 0 0 0 0 0 0 77 0 0 77 0 77 0 0 77 1,079
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Daily Production, Reserves and Present Value Summary
Before Tax
2010 Gross Lease Production 2010 Company Interest Production Gross Lease Reserves Company Interest Reserves 10% Dcf
Present
Reserve Gas Oil NGL Oil Eq. Gas Oil NGL Oil Eq. Gas Oil NGL Sulphur Oil Eq. Gas Oil NGL Sulphur Oil Eq. Value
Entity Description Class Mcf/d bbl/d bbl/d boe/d Mcf/d bbl/d bbl/d boe/d MMcf Mbbl Mbbl Mlt Mboe MMcf Mbbl Mbbl Mlt Mboe M$
Total Probable (Cont.)
Coora (Cont.)
4) Sidetrack Wells (Cont.)
QU-428 Sidetrack H2 0 0 0 0 0 0 0 0 0 130 0 0 130 0 130 0 0 130 2,697
Other Revenue and Expenses 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 5
Total: 4) Sidetrack Wells 0 0 0 0 0 0 0 0 0 586 0 0 586 0 586 0 0 586 10,591
Total: Coora 0 1 0 1 0 1 0 1 0 2,626 0 0 2,626 0 2,626 0 0 2,626 41,957
Total: Total Probable 0 1 0 1 0 1 0 1 0 2,626 0 0 2,626 0 2,626 0 0 2,626 41,957
Total Proved Plus Probable
Coora
1) Current Production.
1) Coora Producing I 0 223 0 223 0 223 0 223 0 1,107 0 0 1,107 0 1,107 0 0 1,107 16,748
Total: 1) Current Production. 0 223 0 223 0 223 0 223 0 1,107 0 0 1,107 0 1,107 0 0 1,107 16,748
2) Recompletions/Workovers
2011-Q3 I 0 0 0 0 0 0 0 0 0 435 0 0 435 0 435 0 0 435 6,915
2012-Q3 I 0 0 0 0 0 0 0 0 0 435 0 0 435 0 435 0 0 435 6,524
2013-Q3 I 0 0 0 0 0 0 0 0 0 435 0 0 435 0 435 0 0 435 5,776
2014-Q3 I 0 0 0 0 0 0 0 0 0 435 0 0 435 0 435 0 0 435 5,074
2015-Q3 I 0 0 0 0 0 0 0 0 0 305 0 0 305 0 305 0 0 305 2,876
2016-Q3 I 0 0 0 0 0 0 0 0 0 305 0 0 305 0 305 0 0 305 2,509
Total: 2) Recompletions/Workovers 0 0 0 0 0 0 0 0 0 2,350 0 0 2,350 0 2,350 0 0 2,350 29,674
3) Replacement Wells
Location F H2 0 0 0 0 0 0 0 0 0 241 0 0 241 0 241 0 0 241 3,927
Location G H2 0 0 0 0 0 0 0 0 0 102 0 0 102 0 102 0 0 102 1,384
Location H H2 0 0 0 0 0 0 0 0 0 135 0 0 135 0 135 0 0 135 1,325
Location L H2 0 0 0 0 0 0 0 0 0 136 0 0 136 0 136 0 0 136 1,161
Total: 3) Replacement Wells 0 0 0 0 0 0 0 0 0 615 0 0 615 0 615 0 0 615 7,797
4) Sidetrack Wells
CO-180 Sidetrack H2 0 0 0 0 0 0 0 0 0 141 0 0 141 0 141 0 0 141 2,527
CO-362 Sidetrack H2 0 0 0 0 0 0 0 0 0 194 0 0 194 0 194 0 0 194 2,788
QU-080 Sidetrack H2 0 0 0 0 0 0 0 0 0 186 0 0 186 0 186 0 0 186 3,036
QU-119 Sidetrack H2 0 0 0 0 0 0 0 0 0 77 0 0 77 0 77 0 0 77 1,079
1110792 Class (A,B1,B2,C,F,I), GLJ (2010-07), ppv January 27, 2011 14:49:44
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Page: 13 of 144

Daily Production, Reserves and Present Value Summary
Before Tax
2010 Gross Lease Production 2010 Company Interest Production Gross Lease Reserves Company Interest Reserves 10% Dcf
Present
Reserve Gas Oil NGL Oil Eq. Gas Oil NGL Oil Eq. Gas Oil NGL Sulphur Oil Eq. Gas Oil NGL Sulphur Oil Eq. Value
Entity Description Class Mcf/d bbl/d bbl/d boe/d Mcf/d bbl/d bbl/d boe/d MMcf Mbbl Mbbl Mlt Mboe MMcf Mbbl Mbbl Mlt Mboe M$
Total Proved Plus Probable (Cont.)
Coora (Cont.)
4) Sidetrack Wells (Cont.)
QU-428 Sidetrack H2 0 0 0 0 0 0 0 0 0 130 0 0 130 0 130 0 0 130 2,697
Other Revenue and Expenses I 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 -5
Total: 4) Sidetrack Wells 0 0 0 0 0 0 0 0 0 728 0 0 728 0 728 0 0 728 12,123
Total: Coora 0 223 0 223 0 223 0 223 0 4,799 0 0 4,799 0 4,799 0 0 4,799 66,341
Total: Total Proved Plus Probable 0 223 0 223 0 223 0 223 0 4,799 0 0 4,799 0 4,799 0 0 4,799 66,341
BOE Factors: HVY OIL 1.0 RES GAS 6.0 PROPANE 1.0 ETHANE 1.0
COND 1.0 SLN GAS 6.0 BUTANE 1.0 SULPHUR 0.0
1110792 Class (A,B1,B2,C,F,I), GLJ (2010-07), ppv January 27, 2011 14:49:44
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Page: 14 of 144

GENERAL
Touchstone Exploration Inc. (Touchstone) has recently acquired a 100 percent interest in the
leases defined within the Coora-1 and Coora-2 Blocks. The Coora Blocks are located onshore in
the southern part of the Republic of Trinidad and Tobago (Map 1). The Coora Field area is a
mature operation having been discovered in 1936 and having produced in excess of 83 MMSTB
from the entire field area, and over 69 MMSTB from within the boundaries of Blocks 1 and 2.
The Coora Blocks are multi-zone and multi-pool developments primarily consisting of shallow to
moderate depths (1000 to 6500 feet in depth) and intermediate crude oil (18 to 28 degree API).
Total current production from the blocks averaged over 220 BOPD during the last 12 months
ending August 31, 2010, from a total producing count of approximately 57 wells. A number of
wells only produce for less than one-half day per month during swabbing operations. GLJ
Petroleum Consultants (GLJ) has assigned reserves to current production as well as locations with
identified recompletion potential, sidetrack locations and a select amount of ‘replacement’ or
infill drilling locations.
GLJ
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General
Southern Basin
GEOLOGY
Page: 16 of 144
The Coora Field is located onshore, in the south part of Trinidad (Map 1). The sediments in this area
occupy a tectonic province known as the Southern Basin, the stratigraphy of which is shown in
Table 1. This basin continues into eastern Venezuela, forming the eastern section of the Eastern
Venezuela Basin.
During the period from early Cretaceous through late Eocene, this part of the Southern Basin was a
deep, northward dipping continental slope off the Guyana Shield to the south. Deposition at this time
was largely confined to clays, very fine-grained clastics, and rare gravity flows (turbidites). The deep
water and anoxic conditions at this time preserved the organic material deposited with the clay,
permitting the accumulation of the thick, organic rich rocks of the Gautier and Naparima Hill
Formations.
Gradual uplift during the Paleocene and Eocene resulted in the deposition of a thick, overall
regressive sequence (Lizard Springs through San Fernando Formations), culminating in basin wide
exposure and erosion at the end of the Eocene (Upper Eocene unconformity).
By Oligocene to early Miocene time, plate movements and the associated compressional forces
dominated the area, completing the shift from a passive basin margin phase to an active margin
phase. A thrust belt along the northern margin of South America and rising terraines to the north
created significant lithospheric loading, resulting in a series of foredeep sub-basins in the area of
interest. Clays were deposited in these deepwater sub-basins, eventually becoming the thick shales
and marls that characterize the Cipero Formation. Thick sequences of sandstone, deposited via
gravity flows, are known to be present near sediment supply areas and feeder canyons/channels in
the slope. Accumulations of these slope and basin floor turbidite fans are known as the Nariva,
Retrench, Herrera and Karamat sandstones.
Tectonic activity increased dramatically in the area during the Mid-Miocene. The Cipero Formation
and the turbidite accumulations within were folded and thrust faulted into a series of high amplitude,
asymmetric, east-northeast trending anticlines, and detached overthrusts. Continued uplift and
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exposure and erosion of these structures at the end of the Mid-Miocene resulted in extensive
beveling of the highs, and the creation of a much more even surface.
By Late Miocene time, compressional forces in the areas gave way to largely extensional ones. A
relative drop in sea level brought marine conditions to the area again. The rocks deposited at this
time suggest a largely transgressional/progradational sequence, with the calcareous shales of the
Lengua Formation giving way to the coarser clastics characteristic of the deltaic deposits of the
Pliocene age formations, including the Cruse, Forest, and Morne L’Enfer Formations. However,
compressional forces returned in the late Pliocene to Pleistocene, adding another layer of structural
complexity to the basin.
The onshore Southern Basin in Trinidad is a well-known, prolific petroleum producing province.
Producing reservoirs within the basin include the Morne L'Enfer, Forest, Cruse, Karamat, and
Herrera Formations. These reservoirs occur at depths ranging from 300 to 12,000 feet. The source
rock for these hydrocarbons is generally accepted to be the organic rich Cretaceous Naparima Hill
Formation. Oil is believed to have migrated into the reservoirs along fractures associated with recent
tectonism such as the Los Bajos Fault zone.
Coora Blocks
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Touchstone has an interest in two blocks, the Coora-1 (CO-1) and Coora-2 (CO-2), within the
onshore Southern Basin of Trinidad (Map 2). These blocks are within the producing Coora Field.
The development of this field began in 1936, and to date 562 wells have been drilled within the 1687
acres of the interest blocks.
Regionally, the field is located on the southern flank of the Siparia syncline that rises southward at a
dip of 15 to 20 degrees until it abruptly terminates against the Los Bajos dextral strike slip fault.
Additionally, the antithetic Coora Fault cuts the field. Touchstone interprets that Coora Fault soles
out against the Los Bajos Fault in the Lower Forest sequence.
Oil production from the field is from the relatively shallow (1000’ to 6500’) Pliocene age clastics, of
the Cruse, Forest, and Morne L'Enfer Formations (Table 1). These sediments were deposited as part
of a delta complex. The major Cruse and Forest sequences represent the eastward progradation of the
proto-Orinoco delta over the region. Delta progradation was followed by a period of uplift and
erosion. The sequence was subsequently flooded as delta sedimentation shifted back to the west. A
number of different depositional environments are recognized within the delta complex. These
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include deeper marine submarine fans, marine channels, levees, distributary channels, distributary
mouth bars, cheniers and tidal channels.
Based on detailed correlation of well data, Touchstone has identified and mapped individual
reservoir units. Touchstone has subdivided the major Upper Cruse, Lower Forest, and Upper Forest
sequences into a number of parasequences (Table 1). The Coora Field is interpreted to consist of a
number of vertically stacked reservoir sands, which act as discrete oil pools. To date, Touchstone has
mapped 56 pools within the various sequences across the field. Trapping is interpreted to be largely
stratigraphic in nature with the reservoir limits defined by the sandstone limits. Areal extents of the
pools are generally small due to the depositional nature of the reservoir sands. In some cases the oil
is associated with an aquifer or a gas cap which also the limits of the accumulation. It is also
recognized that faulting may further compartmentalize the reservoirs.
Workover Program
Touchstone has identified a large number of potential workover candidates. The workovers in these
wells would involve re-perforating or fracturing the current producing interval with resin coated
proppant. For each of these wells, Touchstone has estimated the completed net oil pay from available
well log data. GLJ has audited the net pay in over 23 wells, which were interpreted to have the
greatest potential for production increase. GLJ’s audited net pay values were less than the values
determined by Touchstone. The ratio of GLJ audited net pay to Touchstone net pay was applied to
the remainder of the identified workover candidates and used as GLJ’s audited net pay values. These
audited net pay values were then used in a reservoir inflow analysis.
Drilling Locations
The replacement well program has been reviewed by GLJ. These well locations have been selected
such that they would penetrate a minimum of two stacked, low recovery reservoirs. Initial
replacement well locations include:
• Location G well will be located in the central portion of the CO-1 Block and will target the
Cruse 2, Cruse 5 and Top Cruse reservoir horizons.
Page: 18 of 144
• Location H will be drilled in the southcentral portion of the CO-1 Block and the well will
target an Upper Forest 5 Pool. In addition, the well will target reservoirs in the Lower Forest
2 and Upper Forest 4.
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• Location L will be drilled in the north central portion of the CO-1 Block. The well will target
reservoir sands in the Middle Cruse, Cruse 7, Cruse 5 and Cruse 2.
• Locations F will be drilled in the southcentral portion of the CO-1 Block. This well will
target common pools in the Middle Cruse, Cruse 5, Cruse 2 and Top Cruse sands. Upper
Forest reservoirs penetrated by these wells will likely be depleted.
GLJ was provided with detailed mapping for all potential reservoir horizons to be penetrated by
these replacement well locations. GLJ has audited this net pay mapping, paying particular attention
to wells that immediately offset a proposed location.
In addition, GLJ has attempted to allocate production in these pools to individual reservoir zones.
This is problematic, in that well test and cumulative production data for most wells covers a large
vertical interval and may include a number of separate reservoir sands. GLJ has allocated the
production from a well to the completed reservoir horizons based on a ratio of net pay thickness.
Sidetrack Locations
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GLJ has reviewed the proposed sidetrack locations in a similar manner to the replacement locations,
as described above. Again, these well locations have been selected such that they would penetrate a
minimum of two stacked, low recovery reservoirs. Initially these wells experienced formation sand
production, loss of wellbore integrity, and flowback control problems, but have encountered good
reservoir. Initial sidetrack locations include:
• Qu 428 was initially drilled in August 2005, and commenced production in October 2006, at
low oil production rates. The well is located in the CO-2 Block, south of the Los Bajos fault
zone. Due to large volumes of fluid lost to the formation while drilling, poor performance has
been realized at this well.
• Sidetrack CO-362 will be drilled in the southeast corner of the CO-2 Block. The well will
target reservoir sands in the Middle Cruse 3, Cruse 5, Lower Forest 8, Upper Forest 8 and the
Upper Forest 5.
• QU-080 will be drilled in the west central region of the CO-1 Block, north of the Los Bajos
fault zone. This sidetrack will target reservoir sands in the top Cruise, Cruise 2, Cruise 5 and
the Middle Cruise.
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• QU-119 will be drilled in the northwest region of CO-1 Block, north of the Los Bajos fault
zone. This sidetrack will target reservoir sands in the Middle Cruise and Cruise 7
• CO-180 will be drilled in the central region of CO-1 Block, north of the Los Bajos fault. This
sidetrack will target the Cruise 5 and the Middle Cruise sands.
Volumetric Parameters
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Estimating oil-in-place for individual pools within the Coora Field is hindered by lack of open hole
well log data. While log data is available for the majority of the wells within the field, the log suite
typically includes only a spontaneous potential (SP) log and resistivity log. Net pays values were
estimated using the response of these logs. The SP log was used to identify permeable sands, while
the resistivity log (and test data) was used to determine if the sands contained hydrocarbons. The
absence of a porosity log results in additional uncertainty with respect to individual pool oil-in-place.
GLJ has reviewed all available core data and have determined the average porosity from the core for
all zones to be 29.8 percent. When the core data is sorted by zone, GLJ determined average porosity
values of 30.9, 31.5 and 28.7 percent for the Morne L'Enfer, Forest, and Cruse samples, respectively.
While the number of core sample reviewed is small, the porosity values appear to be consistent with
reported values for these formations. The core porosity values also compare favorably to the 30
percent porosity used in all reservoirs in the field. This value is consistent with the porosity values
estimated for the Cruse horizons in the recently drilled Qu 428 well. This well has a full suite of
open hole logs. Similarly, A water saturation of 25 percent was used for all zones in the field. This
value appears reasonable and is within the range of reported water saturation values for these
formations.
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RESERVES
Touchstone has compiled a significant database of information from the files of the current
operator Damus and Petrotrin, the historical operator in the field. This database consists of
completion records, historical production, current fluid level measurements, core data (limited),
and oil gravity values by zone. Although the database is large, it is incomplete, especially with
respect to engineering and production data. The largest deficiency identified is the lack of data for
each specific zone, with the majority of fluid and production records sourced from multiple
completions covering various zones.
Based upon our review of the available data, the reservoir fluid properties for each zone have
been estimated. These fluid properties are calculated based on regional averages of zone depth
and temperature. They are estimated to be:
Zone
Oil Gravity
[°API]
Formation
Volume Factor
[stb/rbbl]
Oil Viscosity
[cP]
Morne L'Enfer 19 1.04 110
Producing Reserves
Upper Forest 22 1.06 40
Lower Forest 24 1.08 24
Cruse 28 1.12 8
Cumulative production values were provided for each well up to December 31, 2001. Monthly
production data from January 2002 through August 2010 was available by well and included oil
volumes and water volumes; however, solution gas production was not recorded. In addition to
the production database, a significant amount of pressure data has been recorded in the Coora
Field. Periodic static fluid levels and dynamic fluid levels are measured, with a field wide study
conducted during February to March 2005 that encompassed 62 wells.
Individual well and total pool production decline has been utilized to estimate the producing
reserves. The operational conditions of each well (e.g. downtime, swabbing) made it very difficult
to identify trends on an individual well basis. Due to this, producing reserves have assigned using
decline analysis on recent trends observed for the total production in Blocks CO-1 and CO-2
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(Plots 1 and 2). Decline analysis results in proved producing and proved producing plus probable
producing remaining reserves of 985.9 and 1175.9 MSTB (gross lease), respectively (Table 2.1).
Workover/Recompletion Potential
Analysis of the completion and inflow performance data for the producing wells in Blocks CO-1
and CO-2 indicate that significant increases in oil rates can be achieved through removal of gravel
pack liners and other remediation. Re-perforating, fracturing and artificial lift optimization. The
Forest and Cruse sands are unconsolidated reservoirs, and during the early stages of development
high production rates resulted in fines migration within the reservoir. This had the effect of fully
sanding off many wells and reducing the effective permeability (increased skin) in and around the
wellbores. Evidence of reduced inflow performance was seen when PLT’s were run over
perforated intervals with 40 to 65 percent of the perforations partially or completely plugged.
Compounding this problem was the original perforation density of one to four shots-per-foot
(SPF). This low density results in high fluid velocities through the limited perforations, which
encourages the movement of fines and sand. Historically, the operators had focused on reducing
sand production by reducing the pressure drop, hence fluid velocity, across the perforations. To
do this the pumping rate is reduced to the point were sand production is minimized and frequent
clean-out trips are avoided, In addition pumps have been set high in the fluid column, often 200 to
400 feet above, which has reduced the efficiency of the pumping systems.
An inflow performance analysis was conducted over the complete database of producing wells.
The first analysis utilized the current production data (oil and water fluid rates, along with static
and dynamic fluid levels) to construct the Vogel IPR relationship for each well. This allowed GLJ
to calculate the theoretical maximum oil production rates by fully pumping off the fluid to the
mid-point depth of the perforations. The total potential for all of the wells are in excess of 500
BOPD, which represents an incremental oil rate of approximately 270 BOPD compared with the
average 2010 rates observed. By eliminating all wells with a water cut in excess of 20 percent or
incremental oil rates of less than 5 BOPD, there are 15 wells remaining with a total incremental
oil rate of 120 BOPD.
As previously discussed in the Geology section of this report, GLJ has audited the net pay in
several wells and have arrived at an audit adjusted net pay value for each well and current
completion in the Coora Blocks. GLJ then correlated the inflow potential (described above for
each well) to the net pay and current reservoir pressure. A linear relationship should exist
between the wells inflow relationship and the product of net thickness and pressure, (i.e. wells
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with high net pay and high reservoir pressure should produce at higher oil rates with all other
factors being equal). This analysis allows us to identify the wells that appear to be the most
damaged by ineffective completions or the result of plugging.
To mitigate some of the uncertainties in this analysis, we categorized the wells into groups by the
upper most productive zones. This was done to eliminate some of the effects of varying depths,
fluids, permeability, and temperature. The ensuing analysis resulted in a best-fit correlation on the
four groups of wells: Cruse only, primarily Lower Forest, primarily Upper Forest and primarily
Morne L'Enfer.
The inflow performance calculated above was then translated into Darcy’s flow equations. The
reservoir temperature was correlated with depth and was used to calculate in-situ oil viscosity
values for each of the productive horizons. The only remaining unknowns were then the reservoir
permeability and skin factors. These two factors are not well understood in the Coora Blocks due
to the lack of flow and buildup testing, however, they tend to balance out in the equation. For
example, if the permeability is overstated the resulting skin factor would also be overstated. To
aid in this, the available core data was then reviewed to help determine the expected reservoir
permeability for each of the productive horizons. The skin factor was adjusted until the Darcy
flow equation yielded the same results as the inflow performance previously discussed. It is
evident that significant positive skin factors are identified in the field, with averages in the +30 to
+60 range. Based on our analysis the following average permeability and apparent skin was
determined:
Zone
Average Permeability
[md]
Apparent Skin Factor
[ ]
Morne L'Enfer 300 +30
Upper Forest 200 +30
Lower Forest 100 +60
Cruse 80 +60
Wells that are currently under performing compared with the Darcy flow parameters shown in the
table above were identified. If the recompletions/workovers were conducted on each
underperforming well, the total potential for all of the wells is in excess of 900 BOPD, which
represents and incremental oil rate of 650 BOPD. By eliminating all wells with a water cut in
excess of 20 percent or incremental oil rates of less than 10 BOPD, there remain 26 wells with a
total incremental oil rate in excess of 400 BOPD.
GLJ
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While oil rates varied by well, on average a recompleted well has historically observed initial
production rates in the range of 20 to 25, while initial (instantaneous) rates in some instances
exceeded 300 BOPD. These candidates have been assigned reserves in the proved and proved
plus probable non-producing categories based upon the average performance of the recently
recompleted wells, and upon the methodology previously described.
Recent application of resin-coated proppant during fracturing of the wells (frac pack technology)
has aided the flowback control of sands upon workover of wells. Frac pack technology helps to
improve the performance of the wells by removing the need for the use of gravel packs and/or
liners. This technology uses a resin-coated proppant to maintain the fracture opening and reduce
sand production. This technology has also been demonstrated in various studies to reduce average
skin experienced by the well.
In the last quarter of 2007, three wells underwent workover programs utilizing the resin-coated
proppant, Co-275, Co-63, and Co-113. As of December 2007, these wells have exhibited
excellent flow back control, and produced at average rates of 20 BOPD. These observed rates are
in the initial stages of post-frac production and are consistent with historical averages for
workovers. However, it is evident that the resin-coated proppant is aiding in flowback control of
reservoir sands and maintaining the fracture opening, due to the absence of sand being produced
and the continuous production observed at the well. The resin frac packs allow for more
continuous production, with lessened down time due to bailing of sands which have caused
restricted flow due to covering of perforated intervals.
Based on the results obtained to date with the application of resin frac pack technology, and in
consideration of the potential for improved recovery following the inflow performance review
mentioned earlier in this discussion, reserves have been assigned to 54 proved and 18 probable
recompletion attempts. Based on historical statistics, it was assumed that three of every four
recompletions attempts will result in a successful well.
Infill Drilling (Replacement and Sidetrack Locations)
As discussed in the Geology section of this report, GLJ has reviewed the proposed replacement
and sidetrack wells. The locations were chosen to access what is believed to be multiple stacked
reservoir units with significant remaining reserves potential. There appears to be little reservoir
risk associated with these locations, however, due to the tight well spacing, significant depletion
may have occurred. By studying the nine locations (labeled Co-362, Co-180, Qu-119, Qu-80, Qu-
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428, F, G, H, and L) in detail we were able to form an assessment of analogous well rates and
recoveries along with estimating the current pool pressures in the area.
GLJ has audited the net pay mapping and examined in detail the wells that immediately offset a
proposed location. Offset wells reviewed by GLJ were used as analogies in volumetric reserve
estimates at the proposed infill locations. Audited net pay maps were used to estimate volumes of
oil-in-place that may be accessed by each reservoir horizon at a proposed infill location.
Production allocation was used to estimate recovery to date on a zone basis in the area of
proposed infill locations and to estimate the volume of oil that may be recovered by each of the
infill locations. In areas that appear to have a high recovery factor to date, or have recently
recorded low reservoir pressures, the assigned reserves were reduced significantly.
Probable non-producing reserves are assigned to all nine well locations using volumetric estimates
(Table 2.1). Drainage areas were typically assigned on the order of 5 to 20 acres, depending on the
demonstrated recovery from the nearby analogous wells. Remaining recovery factors were
assigned in the range of 5 to 15 percent depending on the estimated current pool pressures in the
area of the infill well. Using these volumetric parameters, reserves of 77 to 240 MSTB (gross) per
well have been assigned.
Proved non-producing reserves are assigned to two of the locations, namely CO-362 and F, based
on higher geological and engineering confidence. Volumetric parameters have been assigned
similar to the proved plus probable cases in these wells, except that recovery factors are reduced.
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Using the production inflow relationships discussed in this report, each well zone was calculated to
have an ‘average’ production rate determined by the Darcy flow equations using the formation
permeability and skin factors previously calculated. This calculation resulted in estimated well
production rates of 40 to 100 BOPD (Table 2.2). These production rates combined with the
assignments represent hyperbolic (b=0.4) decline rates on the order of 11 to 27 percent.
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PRODUCTION AND DEVELOPMENT FORECAST
The producing reserves have been forecast to continue along established decline trends until the
depletion of the assigned reserves.
The forecast recompletion/workovers are scheduled on-stream in groups of nine wells every year,
starting in Q3 2011. The last group of nine wells is scheduled on-stream in late 2016. Production is
forecast in a three stage profile to match performance expectations. Production for each well is
forecast to decline at 40 percent during the first year, 20 percent in the second year, and 13 percent
thereafter until recovery of the assigned remaining reserves. The gross lease cost is estimated at
$175M CDN per recompletion.
Development of the sidetrack and replacement wells is scheduled to commence in Q3 2011. Wells
are forecast on-stream on groups of either two or three wells yearly until Q3 2014. The gross lease
capital expenditures are estimated at $510M CDN per sidetrack well and $750M CDN per
replacement well.
As per the terms of the contract with the Lessor, Petrotrin, Touchstone is only responsible for the
company’s working interest share of abandonment liability on any new wells drilled (sidetrack
and replacement wells). The gross lease cost to abandon these wells has been forecast at $30M
CDN per well.
GLJ
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ECONOMIC ANALYSIS
A summary of economic parameters used in this evaluation, including product pricing, operating
expenses and capital costs is provided in Table 4. It is noted that all prices and revenues in this
report are presented in CDN Dollars unless otherwise noted.
GLJ was provided with available accounting data for the Coora Blocks for the period August 31,
2001 to August 31, 2010. Operating costs are estimated at a total of approximately 24
$CDN/BBL for the producing reserves forecast. The rate is high due to the low current
production rates relative to the fixed operating costs.
A historical review of the wellhead price received for the crude oil at the Coora Blocks was
conducted relative to the WTI benchmark. For the current economic evaluation, GLJ has utilized
a price differential of 13 percent. This differential was chosen to best represent the observed
historical differential during periods where the posted WTI was similar to that utilized in the
current price forecast.
INCOME TAX AND ROYALTIES
Trinidad Royalties
Crown royalties are determined by governmental regulation, are calculated as a percentage of the
value of the gross production, and are currently fixed at 12.5 percent for the Coora property. In
addition, the Company is required to pay an additional royalty as follows:
Liquid Price Received - $US Between Royalty Rate (%)
$0.00 and $8.00 5
$8.01 and $10.00 8
$10.01 and $12.00 11
$12.01 and $14.00 14
$14.01 and $16.00 17
$16.01 and $18.00 21
$18.01 and $20.00 24
$20.01 and $22.00 26
$22.01 and $24.00 28
$24.01 and $26.00 30
$26.01 and $28.00 32
$28.01 and Above Held at 33% for base
& 30% for incremental
production
New wells (replacement and sidetrack status) are subject to a 0 percent royalty in the first year
and receive a 50 percent reduction in the second year.
GLJ
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Income Taxes
Trinidad income taxes were calculated based on currently legislated tax rates, tax regulations, and
tax pool information. After tax values are not shown for reserves development status
subcategories (i.e. developed, undeveloped). After tax values and economic forecasts for reserves
production status subcategories (i.e. producing, non-producing) are determined by the difference
between the total reserves and developed producing categories.
In addition to royalties, the Coora Block property is subject to production levy, oil impost tax,
supplemental petroleum tax, unemployment levy, and a petroleum profits tax. The production
levy is limited to 3 percent of the gross income from production. Oil impost tax is paid annually
by petroleum producing companies to pay for the annual expenses of the Ministry of Energy for
the administration of the petroleum industry. Oil impost payments are made in proportion to each
company's level of crude oil and natural gas production. The supplemental profits tax (SPT),
applies only to liquids production (not natural gas) and varies with the price received for liquid
production, the date of the block license and whether the block is on or offshore. The revenue
base for the calculation of SPT is the gross income less royalties. SPT rates applicable for the
Coora Block property at various liquid prices are set out below:
Liquid Price Received - $US Between SPT Rate (%)
$0 and $18.00 0
$18.01 and $19.50 1
$19.51 and $22.51 2
$22.51 and $27.00 3
$27.01 and $30.00 4
$30.01 and $31.50 5
$31.51 and $33.00 6
$33.01 and $34.50 7
$34.51 and $36.00 8
$36.01 and $37.50 9
$37.51 and $39.00 10
$39.01 and $40.50 11
$40.51 and $42.00 12
$42.01 and $43.50 13
$43.51 and $45.00 14
$45.01 and $46.50 15
$46.51 and $48.00 16
$48.01 and $49.50 17
$49.51 and over 18
The petroleum profits tax (PPT) and unemployment levy are 50 and 5 percent, respectively, and
are fixed by the Trinidad Government. The same revenue base is used for the calculation of both
the PPT and the unemployment levy and is the gross income less 100 percent of the royalty, 100
percent of the production levy, 100 percent of the SPT, 100 percent of workover allowance, 100
GLJ
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percent of dry hole expenditures, all heavy oil allowance, all operating and administrative
expenses, and capital allowances (different capital items are allowed to be depreciated over
different timelines per Government regulations).
Economic forecasts for each of the reserves categories have been included in the Economic
Forecasts section of this report.
Other Economic Considerations
This report does not address the following issues:
• 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.
GLJ
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Company: Touchstone Exploration Reserve Class: Proved Plus Probable
Property: Coora Block Development Class: Total
Pricing: GLJ (2010-07)
Effective Date: August 31, 2010
Summary of Well Interests and Burdens
Working Interest Royalty Interest Other Royalty Burdens
BPO APO Rem PO BPO APO Rem PO Lessor BPO APO Rem PO
Entity Description % % (000's) Type % % (000's) Royalty Type % % (000's)
Coora Block
Coora
1) Current Production.
1) Coora Producing 100.000 - - - - - ALTA CR ROY 45.7% - - -
CO-0001
CO-0002
CO-0003
CO-0005
CO-0006
CO-0007
CO-0008
CO-0009
CO-0010
CO-0011
CO-0012
CO-0013
CO-0014
CO-0015
CO-0016
CO-0017
CO-0018
CO-0019
CO-0020
CO-0021
CO-0022
CO-0023
CO-0024
CO-0025
CO-0026
CO-0027
CO-0028
CO-0029
CO-0030
CO-0031
CO-0032
CO-0033
CO-0034
CO-0035
CO-0036
CO-0037
CO-0038
CO-0039
CO-0040
CO-0041
CO-0042
CO-0043
CO-0044
CO-0045
CO-0046
1110792 Total Proved Plus Probable, GLJ (2010-07), int January 27, 2011 14:49:48
GLJ
Petroleum Consultants
Page: 30 of 144

Summary of Well Interests and Burdens
Working Interest Royalty Interest Other Royalty Burdens
BPO APO Rem PO BPO APO Rem PO Lessor BPO APO Rem PO
Entity Description % % (000's) Type % % (000's) Royalty Type % % (000's)
Coora Block (Cont.)
Coora (Cont.)
1) Current Production. (Cont.)
CO-0047
CO-0048
CO-0049
CO-0050
CO-0051
CO-0052
CO-0053
CO-0054
CO-0055
CO-0056
CO-0057
CO-0058
CO-0059
CO-0060
CO-0061
CO-0062
CO-0063
CO-0064
CO-0065
CO-0066
CO-0067
CO-0068
CO-0069
CO-0070
CO-0071
CO-0072
CO-0073
CO-0074
CO-0075
CO-0076
CO-0077
CO-0078
CO-0079
CO-0080
CO-0081
CO-0082
CO-0083
CO-0084
CO-0085
CO-0086
CO-0087
CO-0088
CO-0089
CO-0090
CO-0091
CO-0092
CO-0093
CO-0094
CO-0095
1110792 Total Proved Plus Probable, GLJ (2010-07), int January 27, 2011 14:49:48
GLJ
Page 2
Petroleum Consultants
Page: 31 of 144

Summary of Well Interests and Burdens
Working Interest Royalty Interest Other Royalty Burdens
BPO APO Rem PO BPO APO Rem PO Lessor BPO APO Rem PO
Entity Description % % (000's) Type % % (000's) Royalty Type % % (000's)
Coora Block (Cont.)
Coora (Cont.)
1) Current Production. (Cont.)
CO-0096
CO-0097
CO-0098
CO-0099
CO-0100
CO-0101
CO-0102
CO-0103
CO-0104
CO-0105
CO-0106
CO-0107
CO-0108
CO-0109
CO-0110
CO-0111
CO-0112
CO-0113
CO-0114
CO-0115
CO-0116
CO-0117
CO-0118
CO-0119
CO-0120
CO-0121
CO-0122
CO-0123
CO-0124
CO-0125
CO-0126
CO-0127
CO-0128
CO-0129
CO-0130
CO-0131
CO-0132
CO-0133
CO-0134
CO-0135
CO-0136
CO-0137
CO-0138
CO-0139
CO-0140
CO-0141
CO-0142
CO-0143
CO-0144
1110792 Total Proved Plus Probable, GLJ (2010-07), int January 27, 2011 14:49:48
GLJ
Page 3
Petroleum Consultants
Page: 32 of 144

Summary of Well Interests and Burdens
Working Interest Royalty Interest Other Royalty Burdens
BPO APO Rem PO BPO APO Rem PO Lessor BPO APO Rem PO
Entity Description % % (000's) Type % % (000's) Royalty Type % % (000's)
Coora Block (Cont.)
Coora (Cont.)
1) Current Production. (Cont.)
CO-0145
CO-0146
CO-0147
CO-0148
CO-0149
CO-0150
CO-0151
CO-0152
CO-0153
CO-0155
CO-0156
CO-0157
CO-0158
CO-0159
CO-0160
CO-0161
CO-0162
CO-0163
CO-0164
CO-0165
CO-0166
CO-0167
CO-0168
CO-0169
CO-0170
CO-0171
CO-0172
CO-0173
CO-0174
CO-0175
CO-0176
CO-0177
CO-0178
CO-0179
CO-0180
CO-0181
CO-0182
CO-0183
CO-0185
CO-0186
CO-0187
CO-0188
CO-0189
CO-0190
CO-0191
CO-0192
CO-0193
CO-0194
CO-0195
1110792 Total Proved Plus Probable, GLJ (2010-07), int January 27, 2011 14:49:48
GLJ
Page 4
Petroleum Consultants
Page: 33 of 144

Summary of Well Interests and Burdens
Working Interest Royalty Interest Other Royalty Burdens
BPO APO Rem PO BPO APO Rem PO Lessor BPO APO Rem PO
Entity Description % % (000's) Type % % (000's) Royalty Type % % (000's)
Coora Block (Cont.)
Coora (Cont.)
1) Current Production. (Cont.)
CO-0197
CO-0198
CO-0199
CO-0200
CO-0201
CO-0202
CO-0203
CO-0204
CO-0205
CO-0206
CO-0207
CO-0208
CO-0209
CO-0210
CO-0211
CO-0212
CO-0213
CO-0214
CO-0215
CO-0216
CO-0217
CO-0218
CO-0219
CO-0220
CO-0221
CO-0222
CO-0223
CO-0224
CO-0225
CO-0226
CO-0227
CO-0228
CO-0229
CO-0230
CO-0232
CO-0232W
CO-0233
CO-0234
CO-0235
CO-0236
CO-0237
CO-0238
CO-0239
CO-0240
CO-0241
CO-0242
CO-0244
CO-0245
CO-0246
1110792 Total Proved Plus Probable, GLJ (2010-07), int January 27, 2011 14:49:48
GLJ
Page 5
Petroleum Consultants
Page: 34 of 144

Summary of Well Interests and Burdens
Working Interest Royalty Interest Other Royalty Burdens
BPO APO Rem PO BPO APO Rem PO Lessor BPO APO Rem PO
Entity Description % % (000's) Type % % (000's) Royalty Type % % (000's)
Coora Block (Cont.)
Coora (Cont.)
1) Current Production. (Cont.)
CO-0247
CO-0248
CO-0249
CO-0250
CO-0251
CO-0252
CO-0253
CO-0254
CO-0255
CO-0256
CO-0257
CO-0258
CO-0259
CO-0260
CO-0261
CO-0263
CO-0265
CO-0267
CO-0269
CO-0271
CO-0272
CO-0273
CO-0274
CO-0275
CO-0276
CO-0277
CO-0280
CO-0282
CO-0283
CO-0284
CO-0285
CO-0286
CO-0287
CO-0288
CO-0288W
CO-0289
CO-0290
CO-0294
CO-0296
CO-0297
CO-0299
CO-0300
CO-0301
CO-0302
CO-0303
CO-0304
CO-0306
CO-0307
CO-0308
1110792 Total Proved Plus Probable, GLJ (2010-07), int January 27, 2011 14:49:48
GLJ
Page 6
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Page: 35 of 144

Summary of Well Interests and Burdens
Working Interest Royalty Interest Other Royalty Burdens
BPO APO Rem PO BPO APO Rem PO Lessor BPO APO Rem PO
Entity Description % % (000's) Type % % (000's) Royalty Type % % (000's)
Coora Block (Cont.)
Coora (Cont.)
1) Current Production. (Cont.)
CO-0309
CO-0310
CO-0311
CO-0312
CO-0313
CO-0314
CO-0315
CO-0316
CO-0317
CO-0318
CO-0319
CO-0320
CO-0321
CO-0322
CO-0323
CO-0324W
CO-0326
CO-0328W
CO-0331W
CO-0332W
CO-0334
CO-0335
CO-0336W
CO-0337
CO-0338
CO-0339W
CO-0340W
CO-0341W
CO-0342W
CO-0343W
CO-0344
CO-0346
CO-0347
CO-0348
CO-0349
CO-0350
CO-0351
CO-0352
CO-0353
CO-0354
CO-0355
CO-0356W
CO-0359
CO-0359X
CO-0359X2
CO-0360
CO-0361
QU-0001
QU-0002
1110792 Total Proved Plus Probable, GLJ (2010-07), int January 27, 2011 14:49:48
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Page 7
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Page: 36 of 144

Summary of Well Interests and Burdens
Working Interest Royalty Interest Other Royalty Burdens
BPO APO Rem PO BPO APO Rem PO Lessor BPO APO Rem PO
Entity Description % % (000's) Type % % (000's) Royalty Type % % (000's)
Coora Block (Cont.)
Coora (Cont.)
1) Current Production. (Cont.)
QU-0003
QU-0004
QU-0005
QU-0006
QU-0007
QU-0008
QU-0009
QU-0010
QU-0011
QU-0012
QU-0013
QU-0014
QU-0015
QU-0016
QU-0017
QU-0018
QU-0019
QU-0020
QU-0021
QU-0022
QU-0023
QU-0024
QU-0025
QU-0026
QU-0027
QU-0028
QU-0029
QU-0030
QU-0031
QU-0032
QU-0034
QU-0038
QU-0039
QU-0040
QU-0041
QU-0042
QU-0043
QU-0044
QU-0045
QU-0047
QU-0048
QU-0049
QU-0050
QU-0051
QU-0052
QU-0053
QU-0054
QU-0055
QU-0057
1110792 Total Proved Plus Probable, GLJ (2010-07), int January 27, 2011 14:49:48
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Page 8
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Page: 37 of 144

Summary of Well Interests and Burdens
Working Interest Royalty Interest Other Royalty Burdens
BPO APO Rem PO BPO APO Rem PO Lessor BPO APO Rem PO
Entity Description % % (000's) Type % % (000's) Royalty Type % % (000's)
Coora Block (Cont.)
Coora (Cont.)
1) Current Production. (Cont.)
QU-0058
QU-0059
QU-0060
QU-0061
QU-0062
QU-0063
QU-0065
QU-0066
QU-0067
QU-0068
QU-0069
QU-0072
QU-0073
QU-0074
QU-0075
QU-0076
QU-0077
QU-0078
QU-0079
QU-0080
QU-0081
QU-0082
QU-0083
QU-0084
QU-0085
QU-0086
QU-0087
QU-0088
QU-0089
QU-0090
QU-0091
QU-0092
QU-0093
QU-0094
QU-0096
QU-0098
QU-0100
QU-0102
QU-0103
QU-0106
QU-0108
QU-0109
QU-0112
QU-0113
QU-0115
QU-0117
QU-0118
QU-0119
QU-0120
1110792 Total Proved Plus Probable, GLJ (2010-07), int January 27, 2011 14:49:48
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Page: 38 of 144

Summary of Well Interests and Burdens
Working Interest Royalty Interest Other Royalty Burdens
BPO APO Rem PO BPO APO Rem PO Lessor BPO APO Rem PO
Entity Description % % (000's) Type % % (000's) Royalty Type % % (000's)
Coora Block (Cont.)
Coora (Cont.)
1) Current Production. (Cont.)
QU-0124
QU-0125
QU-0126
QU-0135
QU-0148
QU-0149
QU-0150
QU-0153
QU-0154
QU-0156
QU-0174
QU-0175
QU-0178
QU-0185
QU-0187
QU-0189
QU-0194
QU-0196
QU-0199
QU-0200
QU-0201
QU-0202
QU-0203
QU-0206
QU-0211
QU-0217
QU-0220
QU-0221
QU-0223
QU-0224
QU-0225
QU-0226
QU-0228
QU-0229
QU-0230
QU-0231
QU-0236
QU-0237
QU-0239
QU-0249
QU-0256
QU-0257
QU-0258
QU-0259
QU-0260
QU-0261
QU-0279
QU-0280
QU-0286
1110792 Total Proved Plus Probable, GLJ (2010-07), int January 27, 2011 14:49:48
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Page: 39 of 144

Summary of Well Interests and Burdens
Working Interest Royalty Interest Other Royalty Burdens
BPO APO Rem PO BPO APO Rem PO Lessor BPO APO Rem PO
Entity Description % % (000's) Type % % (000's) Royalty Type % % (000's)
Coora Block (Cont.)
Coora (Cont.)
1) Current Production. (Cont.)
QU-0287
QU-0291
QU-0297
QU-0298
QU-0300
QU-0302
QU-0303
QU-0304
QU-0305
QU-0306
QU-0307
QU-0309
QU-0310
QU-0311
QU-0313
QU-0314
QU-0316
QU-0317
QU-0318
QU-0319
QU-0322
QU-0325
QU-0326
QU-0327
QU-0329
QU-0333
QU-0334
QU-0335
QU-0336
QU-0337
QU-0338
QU-0339
QU-0340
QU-0341
QU-0343
QU-0346
QU-0347
QU-0348
QU-0349
QU-0350
QU-0351
QU-0353
QU-0354
QU-0355
QU-0356
QU-0360
QU-0362
QU-0373
QU-0374
1110792 Total Proved Plus Probable, GLJ (2010-07), int January 27, 2011 14:49:48
GLJ
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Page: 40 of 144

Summary of Well Interests and Burdens
Working Interest Royalty Interest Other Royalty Burdens
BPO APO Rem PO BPO APO Rem PO Lessor BPO APO Rem PO
Entity Description % % (000's) Type % % (000's) Royalty Type % % (000's)
Coora Block (Cont.)
Coora (Cont.)
1) Current Production. (Cont.)
QU-0376
QU-0377
QU-0378
QU-0379
QU-0381
QU-0385
QU-0386
QU-0389
QU-0391
QU-0395
QU-0428
Q_-19
Q_-20
2) Recompletions/Workovers
2011-Q3 100.000 - - - - - ALTA CR ROY 45.7% - - -
2012-Q3 100.000 - - - - - ALTA CR ROY 45.7% - - -
2013-Q3 100.000 - - - - - ALTA CR ROY 45.7% - - -
2014-Q3 100.000 - - - - - ALTA CR ROY 45.7% - - -
2015-Q3 100.000 - - - - - ALTA CR ROY 45.7% - - -
2016-Q3 100.000 - - - - - ALTA CR ROY 45.7% - - -
3) Replacement Wells
Location F 100.000 - - - - - ALTA CR ROY 45.7% - - -
Location G 100.000 - - - - - ALTA CR ROY 45.7% - - -
Location H 100.000 - - - - - ALTA CR ROY 45.7% - - -
Location L 100.000 - - - - - ALTA CR ROY 45.7% - - -
4) Sidetrack Wells
CO-180 Sidetrack 100.000 - - - - - ALTA CR ROY 45.7% - - -
CO-362 Sidetrack 100.000 - - - - - ALTA CR ROY 45.7% - - -
QU-080 Sidetrack 100.000 - - - - - ALTA CR ROY 45.7% - - -
QU-119 Sidetrack 100.000 - - - - - ALTA CR ROY 45.7% - - -
QU-428 Sidetrack 100.000 - - - - - ALTA CR ROY 45.7% - - -
Glossary
APO=BPO interests unless otherwise specified
CR: Crown Royalty
ROY: Royalty Percent
1110792 Total Proved Plus Probable, GLJ (2010-07), int January 27, 2011 14:49:48
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Plot 1
Daily Oil (bbl/d)
Property :Coora Block
10 100 1000 10000
# Oil Wells (month)
Daily Oil Calendar Day (bbl/d)
0 600
10 100 1000 10000
Historical and Forecast Production
Coora Block - Total Property
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
Total Reserves Summary @ 2010/09/01
Reserves ( Mbbl )
Reserves
Classification Ultimate Cum Production Remaining
Pv Prd A(R) 70400 69414 986
Total Pv C(R) 71746 69414 2332
P + P Prd G(R) 70590 69414 1176
Total P + P I(R) 74283 69414 4869
Year
Projections Illustrate
Production Forecast
Average Production Rates (Last 12 months ending 2010/08/31)
Gas : 0.0 Mcf/d 0.0 Mcf/cd WGR : 0.0 bbl/MMcf
Oil : 538.8 bbl/d 221.8 bbl/cd GOR : 0.0 scf/bbl
Avg Wells : 33.7 WC : 49.3 %
Cumulative Production
Oil : 69414.1 Mbbl Gas : 820295.3 MMcf Water : 13099.9 Mbbl
GLJ
I
C
G
A
0.1 1.0 10.0 100.0
0 2000
Water Cut (%)
GOR (scf/bbl)
Coora Block
1110792 / Jan 27, 2011
Petroleum Consultants
Page: 45 of 144

Plot 2
Daily Oil (bbl/d)
Property :Coora Block
0 200 400 600 800 1000 1200 1400 1600 1800 2000
# Oil Wells (month)
Daily Oil Calendar Day (bbl/d)
0 600
0 200 400 600 800 1000 1200 1400 1600 1800 2000
Historical and Forecast Production
Coora Block - Total Property
68500 69000 69500 70000 70500 71000 71500 72000 72500 73000 73500 74000 74500
Total Reserves Summary @ 2010/09/01
Reserves ( Mbbl )
Reserves
Classification Ultimate Cum Production Remaining
Pv Prd A(R) 70400 69414 986
Total Pv C(R) 71746 69414 2332
P + P Prd G(R) 70590 69414 1176
Total P + P I(R) 74283 69414 4869
A
Cumulative Oil (Mbbl)
Projections Illustrate
Production Forecast
G C
I
Average Production Rates (Last 12 months ending 2010/08/31)
Gas : 0.0 Mcf/d 0.0 Mcf/cd WGR : 0.0 bbl/MMcf
Oil : 538.8 bbl/d 221.8 bbl/cd GOR : 0.0 scf/bbl
Avg Wells : 33.7 WC : 49.3 %
Cumulative Production
Oil : 69414.1 Mbbl Gas : 820295.3 MMcf Water : 13099.9 Mbbl
GLJ
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
0 2000
Year
GOR (scf/bbl)
Coora Block
1110792 / Jan 27, 2011
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Page: 46 of 144

Table 1
Property: Coora Block Page 1
Last Month of Data: Alta.: 2010-11 Sask.: 2010-10
B.C.: 2010-11 Man.: 2010-10
Well List and Production Summary
Production Dates Last Quarter Production Statistics Cumulative Production
RigRel First Last Inj Prod Oil Gas GOR WGR WC Oil Gas Water
# Well Location Regulatory Field Pool Current Status Days bbl/d Mcf/d scf/bbl bbl/MMcf % Mbbl MMcf Mbbl
yr-mm yr-mm yr-mm yr-mm
1 CO-0001 2002-12 0 3,424 0 312 0 0
2 CO-0002 2010-04 3 0 0 29 0 0
3 CO-0003 2002-12 0 1,981 0 180 0 0
4 CO-0005 2010-08 92 4 0 33.4 358 1 14
5 CO-0006 2002-12 0 2,524 0 230 0 0
6 CO-0007 2010-08 91 4 0 4.4 156 0 3
7 CO-0008 2002-12 0 322 0 29 0 0
8 CO-0009 2002-12 0 2,519 0 1.6 229 0 4
9 CO-0010 2002-12 0 2,009 0 183 0 0
10 CO-0011 2002-12 0 1,526 0 0.1 139 0 0
11 CO-0012 2002-12 0 1,420 0 129 0 0
12 CO-0013 2010-08 89 7 0 16.4 190 3 4
13 CO-0014 2002-12 0 2,451 0 223 0 0
14 CO-0015 2002-12 0 531 0 0.8 48 0 0
15 CO-0016 2010-06 4 0 0 2.3 77 1 3
16 CO-0017 2002-12 0 1,678 0 153 0 0
17 CO-0018 2002-12 0 1,272 7 5 4,190 2.1 116 1 2
18 CO-0019 2002-12 0 99 0 9 0 0
19 CO-0020 2002-12 0 2,711 0 247 0 0
20 CO-0021 2002-12 0 821 0 0.0 75 0 0
21 CO-0022 2007-06 16 0 0 91.8 100 3 5
22 CO-0023 2002-12 0 722 0 66 0 0
23 CO-0024 2002-12 0 310 0 28 0 0
24 CO-0025 2002-12 0 46 0 4 0 0
25 CO-0026 2002-12 0 1,421 6 4 584 0.2 129 1 0
26 CO-0027 2002-12 0 1,318 0 120 0 0
27 CO-0028 2002-12 0 42 0 4 0 0
28 CO-0029 2002-12 0 1,252 8 7 880 0.6 114 1 1
29 CO-0030 2002-12 0 72 0 7 0 0
30 CO-0031 2003-03 90 0 0 88.2 45 0 1
31 CO-0032 2002-12 0 352 0 0.0 32 0 0
32 CO-0033 2002-12 0 111 0 10 0 0
33 CO-0034 2010-02 3 0 0 0.6 26 1 1
34 CO-0035 2002-12 0 1,819 0 166 0 0
35 CO-0036 2002-12 0 1,533 6 4 584 0.2 140 1 0
36 CO-0037 2002-12 0 109 0 10 0 0
37 CO-0038 2002-12 0 349 0 32 0 0
38 CO-0039 2010-02 69 2 0 1.6 182 0 0
39 CO-0040 2002-12 0 34 0 3 0 0
40 CO-0041 2002-12 0 444 0 40 0 0
41 CO-0042 2009-10 2 0 0 0.5 41 1 1
42 CO-0043 2002-12 0 726 0 66 0 0
43 CO-0044 0 0 0 0 0 0
44 CO-0045 2005-08 62 0 0 0.2 39 0 0
45 CO-0046 2009-05 1 0 0 255 1 3
46 CO-0047 2002-12 0 1,356 0 123 0 0
47 CO-0048 2002-12 0 184 7 36 3,791 11.9 17 1 2
48 CO-0049 2002-12 0 293 0 27 0 0
49 CO-0050 2003-10 92 0 0 57 0 0
50 CO-0051 2002-12 0 1,190 0 108 0 0
51 CO-0052 2002-12 0 1,200 0 109 0 0
52 CO-0053 2002-12 0 903 0 82 0 0
53 CO-0054 2009-09 19 0 0 29 0 0
54 CO-0055 2002-12 0 991 0 90 0 0
55 CO-0056 2002-12 0 1,313 0 119 0 0
56 CO-0057 2002-12 0 2,704 0 246 0 0
57 CO-0058 2002-12 0 2,205 0 201 0 0
1110792 January 27, 2011 14:51:34
GLJ
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Table 1
Property: Coora Block Page 2
Last Month of Data: Alta.: 2010-11 Sask.: 2010-10
B.C.: 2010-11 Man.: 2010-10
Well List and Production Summary
Production Dates Last Quarter Production Statistics Cumulative Production
RigRel First Last Inj Prod Oil Gas GOR WGR WC Oil Gas Water
# Well Location Regulatory Field Pool Current Status Days bbl/d Mcf/d scf/bbl bbl/MMcf % Mbbl MMcf Mbbl
yr-mm yr-mm yr-mm yr-mm
58 CO-0059 2010-07 4 0 0 0.3 113 0 0
59 CO-0060 2002-12 0 2,916 0 265 0 0
60 CO-0061 2008-02 1 0 0 146 0 0
61 CO-0062 2002-12 0 81 0 7 0 0
62 CO-0063 2010-08 92 6 0 17.5 301 0 2
63 CO-0064 2010-04 2 0 0 0.3 217 0 0
64 CO-0065 2002-12 0 1,803 0 164 0 0
65 CO-0066 2002-12 0 6,736 5,637 837 150 11.1 613 513 77
66 CO-0067 2002-12 0 823 0 75 0 0
67 CO-0068 2002-12 0 104 0 9 0 0
68 CO-0069 2002-12 0 319 0 29 0 0
69 CO-0070 2002-12 0 192 0 18 0 0
70 CO-0071 2002-12 0 368 0 33 0 0
71 CO-0072 2002-12 0 253 0 23 0 0
72 CO-0073 2002-12 0 44 0 4 0 0
73 CO-0074 2002-12 0 185 0 17 0 0
74 CO-0075 2010-04 1 0 0 62 0 0
75 CO-0076 2002-12 0 489 0 45 0 0
76 CO-0077 2010-08 92 18 0 15.1 167 0 2
77 CO-0078 2010-08 91 2 0 0.4 25 0 0
78 CO-0079 2007-08 61 2 0 27.7 195 0 0
79 CO-0080 2002-12 0 2,288 0 208 0 0
80 CO-0081 2002-12 0 1,029 0 94 0 0
81 CO-0082 2002-12 0 4,502 0 410 0 0
82 CO-0083 0 0 0 0 0 0
83 CO-0084 2010-08 92 1 0 73.6 225 0 18
84 CO-0085 2002-12 0 1,030 0 94 0 0
85 CO-0086 2006-11 64 1 0 16.5 255 0 1
86 CO-0087 2002-12 0 1,233 0 112 0 0
87 CO-0088 2010-08 43 2 0 11.0 481 0 13
88 CO-0089 2002-12 0 1,713 0 0 333 0.0 156 0 0
89 CO-0090 2002-12 0 3,542 0 322 0 0
90 CO-0091 2010-01 3 0 0 1.1 81 31 13
91 CO-0092 2002-12 0 911 0 83 0 0
92 CO-0093 2002-12 0 966 0 88 0 0
93 CO-0094 2002-12 0 168 0 0 15 0 0
94 CO-0095 2010-06 1 0 0 205 0 1
95 CO-0096 2002-12 0 3,323 0 0 29 0.0 302 0 0
96 CO-0097 2002-12 0 2,970 0 0.0 270 0 0
97 CO-0098 2002-12 0 1,167 0 106 0 0
98 CO-0099 2002-12 0 1,913 0 174 0 0
99 CO-0100 2002-12 0 2,136 142 67 1,220 7.5 194 13 16
100 CO-0101 2002-12 0 3 0 0.3 0 0 0
101 CO-0102 2010-07 1 0 0 0.7 253 0 10
102 CO-0103 2009-12 2 0 0 16.1 72 0 2
103 CO-0104 2010-04 3 0 0 0.5 279 0 0
104 CO-0105 2002-12 0 367 0 33 0 0
105 CO-0106 2002-12 0 405 0 0 8,598 0.1 37 0 0
106 CO-0107 2010-03 1 0 0 272 0 7
107 CO-0108 2009-01 64 5 0 14.4 366 0 1
108 CO-0109 2008-03 66 1 0 22.7 28 1 3
109 CO-0110 2002-12 0 5,330 0 485 0 0
110 CO-0111 2002-12 0 2,757 0 0.0 251 0 0
111 CO-0112 2007-09 2 0 0 427 0 0
112 CO-0113 2010-08 92 15 0 14.9 742 1 2
113 CO-0114 2010-03 1 0 0 106 0 0
114 CO-0115 2002-12 0 429 0 39 0 0
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Table 1
Property: Coora Block Page 3
Last Month of Data: Alta.: 2010-11 Sask.: 2010-10
B.C.: 2010-11 Man.: 2010-10
Well List and Production Summary
Production Dates Last Quarter Production Statistics Cumulative Production
RigRel First Last Inj Prod Oil Gas GOR WGR WC Oil Gas Water
# Well Location Regulatory Field Pool Current Status Days bbl/d Mcf/d scf/bbl bbl/MMcf % Mbbl MMcf Mbbl
yr-mm yr-mm yr-mm yr-mm
115 CO-0116 2002-12 0 2,307 0 0 210 0 0
116 CO-0117 2002-12 0 403 0 37 0 0
117 CO-0118 2002-12 0 0 0 3.0 0 0 0
118 CO-0119 2002-12 0 1,441 3 2 1,468 0.3 131 0 0
119 CO-0120 2010-08 6 1 0 0.7 115 1 9
120 CO-0121 2002-12 0 1,218 7 6 1,052 0.6 111 1 1
121 CO-0122 2002-12 0 1,622 0 148 0 0
122 CO-0123 2010-08 6 1 0 0.2 135 0 1
123 CO-0124 2010-08 2 0 0 1.1 41 0 1
124 CO-0125 2002-12 0 2,153 0 0.0 196 0 0
125 CO-0126 2002-12 0 27 0 17 3,366 5.3 2 0 0
126 CO-0127 2002-12 0 15 0 1 0 0
127 CO-0128 2002-12 0 1,787 0 0.3 163 0 0
128 CO-0129 2002-12 0 341 0 31 0 0
129 CO-0130 2002-12 0 695 0 63 0 0
130 CO-0131 2010-06 1 0 0 356 1 11
131 CO-0132 2002-12 0 1,962 0 179 0 0
132 CO-0133 2002-12 0 1,027 0 93 0 0
133 CO-0134 2002-12 0 1,324 0 120 0 0
134 CO-0135 2002-12 0 536 0 49 0 0
135 CO-0136 2010-08 32 1 0 1.5 313 0 36
136 CO-0137 2002-12 0 2,616 0 238 0 0
137 CO-0138 2002-12 0 991 0 90 0 0
138 CO-0139 2002-12 0 479 3 6 1,202 0.7 44 0 0
139 CO-0140 2002-12 0 3,744 495 132 1,771 19.0 341 45 80
140 CO-0141 2002-12 0 2,301 0 0.1 209 0 0
141 CO-0142 2002-12 0 2,156 44 20 >9999 49.4 196 4 191
142 CO-0143 2002-12 0 2,876 60 21 3,545 6.9 262 6 20
143 CO-0144 2002-12 0 1,588 0 0.1 145 0 0
144 CO-0145 2002-12 0 3,157 0 287 0 0
145 CO-0146 2002-12 0 707 0 64 0 0
146 CO-0147 2002-12 0 698 0 64 0 0
147 CO-0148 2006-03 1 0 0 0.4 408 0 0
148 CO-0149 2002-12 0 62 0 6 0 0
149 CO-0150 2007-11 11 0 0 94.1 257 0 5
150 CO-0151 2002-12 0 1,410 0 128 0 0
151 CO-0152 2002-12 0 3,395 0 309 0 0
152 CO-0153 2010-08 50 0 0 46.1 121 0 0
153 CO-0155 2002-12 0 1,676 0 152 0 0
154 CO-0156 0 0 0 0 0 0
155 CO-0157 2010-08 91 2 0 75.4 74 0 13
156 CO-0158 2006-03 1 0 0 2.0 114 0 0
157 CO-0159 2002-12 0 453 0 41 0 0
158 CO-0160 2003-10 92 1 0 21.7 119 0 0
159 CO-0161 2008-01 1 0 0 289 0 0
160 CO-0162 2010-08 92 3 0 21.2 146 0 1
161 CO-0163 2002-12 0 603 0 55 0 0
162 CO-0164 2002-12 0 89 0 8 0 0
163 CO-0165 2003-09 92 0 0 50.0 104 0 0
164 CO-0166 2010-08 22 1 0 26 0 2
165 CO-0167 2002-12 0 2,953 0 269 0 0
166 CO-0168 2002-12 0 2,973 0 271 0 0
167 CO-0169 0 0 0 0 0 0
168 CO-0170 2002-12 0 2,058 0 187 0 0
169 CO-0171 2010-08 89 2 0 2.2 406 0 0
170 CO-0172 2010-08 91 3 0 75.4 89 0 27
171 CO-0173 2010-08 92 6 0 9.6 354 0 2
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Table 1
Property: Coora Block Page 4
Last Month of Data: Alta.: 2010-11 Sask.: 2010-10
B.C.: 2010-11 Man.: 2010-10
Well List and Production Summary
Production Dates Last Quarter Production Statistics Cumulative Production
RigRel First Last Inj Prod Oil Gas GOR WGR WC Oil Gas Water
# Well Location Regulatory Field Pool Current Status Days bbl/d Mcf/d scf/bbl bbl/MMcf % Mbbl MMcf Mbbl
yr-mm yr-mm yr-mm yr-mm
172 CO-0174 2010-08 4 1 0 2.8 5 0 0
173 CO-0175 2005-11 4 1 0 0.6 114 0 0
174 CO-0176 2002-12 0 1,311 0 119 0 0
175 CO-0177 2002-12 0 872 0 79 0 0
176 CO-0178 2002-12 0 3,092 0 1.6 281 0 5
177 CO-0179 2002-12 0 690 0 7.1 63 0 5
178 CO-0180 2006-04 2 0 0 2.0 290 12 4
179 CO-0181 2010-08 8 2 0 0.6 12 0 0
180 CO-0182 2010-08 2 0 0 7.2 280 0 0
181 CO-0183 2002-12 0 1,643 0 6.5 150 0 10
182 CO-0185 2002-12 0 2,928 0 6.1 266 0 17
183 CO-0186 2010-08 69 1 0 75.4 156 2 19
184 CO-0187 2002-12 0 2,990 22,628 7,569 4 2.6 272 2,059 7
185 CO-0188 2002-12 0 531 0 48 0 0
186 CO-0189 2010-03 1 0 0 1.0 501 12,691 19
187 CO-0190 2002-12 0 1,668 0 152 0 0
188 CO-0191 2002-12 0 788 0 72 0 0
189 CO-0192 2010-08 92 8 0 66.7 160 0 40
190 CO-0193 2010-08 10 0 0 2.1 101 0 1
191 CO-0194 2010-08 21 1 0 6.2 112 1 0
192 CO-0195 2010-08 90 2 0 49.9 171 9,321 24
193 CO-0197 2010-08 92 21 0 0.4 185 0 1
194 CO-0198 2002-12 0 819 4 5 465 0.2 74 0 0
195 CO-0199 2002-12 0 1,163 0 106 0 0
196 CO-0200 2002-12 0 2,465 38,063 15,440 2 3.5 224 3,464 8
197 CO-0201 2002-12 0 2,904 89,220 30,724 2 4.6 264 8,119 13
198 CO-0202 2002-12 0 1,294 0 0.3 118 0 0
199 CO-0203 2010-03 1 0 0 119 0 0
200 CO-0204 2010-03 2 0 0 1.0 122 1 1
201 CO-0205 2002-12 0 409 0 37 0 0
202 CO-0206 2010-08 8 2 0 0.7 68 1 3
203 CO-0207 2002-12 0 1,590 4 2 246 0.1 145 0 0
204 CO-0208 2010-08 3 0 0 20.8 94 0 1
205 CO-0209 2002-12 0 381 0 35 0 0
206 CO-0210 2002-12 0 1,483 96 65 392 2.5 135 9 3
207 CO-0211 2010-08 92 6 0 0.4 104 0 2
208 CO-0212 2002-12 0 8,014 116,408 14,525 57 45.4 729 10,593 606
209 CO-0213 2006-05 31 1 0 16.9 65 0 0
210 CO-0214 2002-12 0 3,037 0 276 0 0
211 CO-0215 2002-12 0 114 0 10 0 0
212 CO-0216 2009-07 3 1 0 57 0 0
213 CO-0217 2004-10 92 0 0 58 0 0
214 CO-0218 2002-12 0 631 0 57 0 0
215 CO-0219 2010-08 77 1 0 4.3 74 0 0
216 CO-0220 2010-08 36 1 0 3.2 56 0 0
217 CO-0221 2002-12 0 1,095 0 100 0 0
218 CO-0222 2002-12 0 588 0 54 0 0
219 CO-0223 2002-12 0 2,906 0 264 0 0
220 CO-0224 2002-12 0 3,137 0 285 0 0
221 CO-0225 2006-08 6 0 0 182 0 0
222 CO-0226 2002-12 0 8,305 0 756 0 0
223 CO-0227 2007-11 13 0 0 180 0 0
224 CO-0228 2002-12 0 5,205 0 474 0 0
225 CO-0229 2010-08 92 16 0 62.6 202 0 62
226 CO-0230 2002-12 0 880 0 80 0 0
227 CO-0232 2002-12 0 2,139 0 195 0 0
228 CO-0232W 0 0 0 0 0 0
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Table 1
Property: Coora Block Page 5
Last Month of Data: Alta.: 2010-11 Sask.: 2010-10
B.C.: 2010-11 Man.: 2010-10
Well List and Production Summary
Production Dates Last Quarter Production Statistics Cumulative Production
RigRel First Last Inj Prod Oil Gas GOR WGR WC Oil Gas Water
# Well Location Regulatory Field Pool Current Status Days bbl/d Mcf/d scf/bbl bbl/MMcf % Mbbl MMcf Mbbl
yr-mm yr-mm yr-mm yr-mm
229 CO-0233 2002-12 0 2 0 0 0 0
230 CO-0234 2010-04 2 0 0 0.6 131 0 0
231 CO-0235 2010-08 91 1 0 2.2 168 0 1
232 CO-0236 2002-12 0 1,609 0 146 0 0
233 CO-0237 2002-12 0 1,045 0 95 0 0
234 CO-0238 2009-10 2 0 0 55 0 0
235 CO-0239 2010-08 92 8 0 1.3 80 0 2
236 CO-0240 2009-08 5 0 0 33 0 0
237 CO-0241 2002-12 0 2,096 0 191 0 0
238 CO-0242 2002-12 0 4,726 0 430 0 0
239 CO-0244 2010-08 4 1 0 0.9 293 0 0
240 CO-0245 2010-08 76 10 0 81.1 176 0 108
241 CO-0246 2009-03 1 0 0 21 0 0
242 CO-0247 2002-12 0 519 0 47 0 0
243 CO-0248 2010-08 71 9 0 66.0 117 0 35
244 CO-0249 2006-07 2 0 0 79 0 0
245 CO-0250 0 0 0 0 0 0
246 CO-0251 2002-12 0 1,916 0 174 0 0
247 CO-0252 2008-04 1 0 0 9 0 0
248 CO-0253 2010-08 2 0 0 13.7 179 0 0
249 CO-0254 2010-01 2 0 0 0.7 254 0 0
250 CO-0255 2002-12 0 1,950 0 177 0 0
251 CO-0256 2004-03 91 0 0 88 0 0
252 CO-0257 2002-12 0 1,849 0 168 0 0
253 CO-0258 2002-12 0 858 0 78 0 0
254 CO-0259 2002-12 0 1,087 0 99 0 0
255 CO-0260 2002-12 0 512 0 47 0 0
256 CO-0261 2009-12 1 0 0 0.6 17 0 0
257 CO-0263 2010-08 2 0 0 4.7 75 0 0
258 CO-0265 2010-08 4 1 0 0.7 59 0 0
259 CO-0267 2010-08 48 3 0 71.2 157 207 20
260 CO-0269 2008-08 1 0 0 19 0 0
261 CO-0271 2002-12 0 1,061 0 97 0 0
262 CO-0272 2002-12 0 18 0 2 0 0
263 CO-0273 2010-08 76 10 0 66.5 70 0 65
264 CO-0274 2003-12 92 2 0 8.6 48 0 0
265 CO-0275 2010-08 92 16 0 25.4 39 0 13
266 CO-0276 2008-03 1 0 0 46 0 0
267 CO-0277 2002-12 0 2,650 0 241 0 0
268 CO-0280 2007-11 3 0 0 71 0 1
269 CO-0282 2004-10 92 0 0 113 0 0
270 CO-0283 2002-12 0 2,506 0 228 0 0
271 CO-0284 2009-09 1 0 0 1.1 4 0 0
272 CO-0285 2002-12 0 1,316 0 120 0 0
273 CO-0286 2002-12 0 613 0 56 0 0
274 CO-0287 2006-02 2 0 0 2.0 48 0 0
275 CO-0288 2010-08 91 5 0 2.2 15 0 0
276 CO-0288W 0 0 0 0 0 0
277 CO-0289 2002-12 0 2,437 0 222 0 0
278 CO-0290 2007-05 2 0 0 59 0 0
279 CO-0294 2010-08 6 1 0 0.8 4 0 0
280 CO-0296 2004-10 92 0 0 239 0 0
281 CO-0297 2002-12 0 117 0 11 0 0
282 CO-0299 2009-02 1 0 0 154 0 0
283 CO-0300 2006-03 1 0 0 0.8 209 0 0
284 CO-0301 2010-07 2 0 0 92 0 0
285 CO-0302 2002-12 0 1,437 0 131 0 0
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Table 1
Property: Coora Block Page 6
Last Month of Data: Alta.: 2010-11 Sask.: 2010-10
B.C.: 2010-11 Man.: 2010-10
Well List and Production Summary
Production Dates Last Quarter Production Statistics Cumulative Production
RigRel First Last Inj Prod Oil Gas GOR WGR WC Oil Gas Water
# Well Location Regulatory Field Pool Current Status Days bbl/d Mcf/d scf/bbl bbl/MMcf % Mbbl MMcf Mbbl
yr-mm yr-mm yr-mm yr-mm
286 CO-0303 2010-04 3 0 0 0.4 25 0 0
287 CO-0304 0 0 0 0 0 0
288 CO-0306 2006-04 7 0 0 2.0 117 0 0
289 CO-0307 2010-08 8 1 0 0.9 129 0 0
290 CO-0308 0 0 0 0 0 0
291 CO-0309 2002-12 0 574 0 52 0 0
292 CO-0310 2002-12 0 625 0 57 0 0
293 CO-0311 2002-12 0 2,927 0 266 0 0
294 CO-0312 2010-08 2 0 0 22.3 107 0 0
295 CO-0313 2002-12 0 99 0 9 0 0
296 CO-0314 2002-12 0 1,809 0 165 0 0
297 CO-0315 2002-12 0 1,346 0 123 0 0
298 CO-0316 2008-02 3 1 0 168 0 0
299 CO-0317 2008-04 4 1 0 73 0 0
300 CO-0318 2010-08 4 1 0 11.6 91 0 0
301 CO-0319 2008-12 1 0 0 9 0 0
302 CO-0320 2002-12 0 137 0 12 0 0
303 CO-0321 2010-08 4 0 0 1.0 137 0 0
304 CO-0322 2002-12 0 664 0 60 0 0
305 CO-0323 2002-12 0 4 0 0 0 0
306 CO-0324W 0 0 0 0 0 0
307 CO-0326 2002-12 0 146 7 50 5,682 22.0 13 1 4
308 CO-0328W 0 0 0 0 0 0
309 CO-0331W 0 0 0 0 0 0
310 CO-0332W 0 0 0 0 0 0
311 CO-0334 0 0 0 0 0 0
312 CO-0335 0 0 0 0 0 0
313 CO-0336W 0 0 0 0 0 0
314 CO-0337 0 0 0 0 0 0
315 CO-0338 0 0 0 0 0 0
316 CO-0339W 0 0 0 0 0 0
317 CO-0340W 0 0 0 0 0 0
318 CO-0341W 0 0 0 0 0 0
319 CO-0342W 0 0 0 0 0 0
320 CO-0343W 0 0 0 0 0 0
321 CO-0344 2010-08 91 2 0 21.8 11 0 7
322 CO-0346 2002-12 0 348 57,188 >99999 60 90.7 32 5,204 310
323 CO-0347 2002-12 0 1,770 142,454 80,486 44 78.0 161 12,963 571
324 CO-0348 2002-12 0 493 47,132 95,671 36 77.3 45 4,289 153
325 CO-0349 2002-12 0 361 108,178 >99999 10 75.5 33 9,844 101
326 CO-0350 2002-12 0 878 75,800 86,362 16 58.5 80 6,898 112
327 CO-0351 0 0 0 0 0 0
328 CO-0352 2002-12 0 554 246,874 >99999 5 67.8 50 22,466 106
329 CO-0353 2002-12 0 89 0 82.2 8 0 37
330 CO-0354 0 0 0 0 0 0
331 CO-0355 2002-12 0 1,239 76,796 61,969 83 83.8 113 6,988 581
332 CO-0356W 0 0 0 0 0 0
333 CO-0359 0 0 0 0 0 0
334 CO-0359X 2010-08 52 2 0 0.9 5 171 3
335 CO-0359X2 2004-09 92 2 0 1 0 0
336 CO-0360 2002-12 0 373 141,524 >99999 6 68.8 34 12,879 75
337 CO-0361 2002-12 0 504 144,013 >99999 2 38.8 46 13,105 29
338 QU-0001 2002-12 0 11,878 2 0 >9999 0.8 1,081 0 8
339 QU-0002 2002-12 0 3,579 0 19.3 326 0 78
340 QU-0003 2002-12 0 3,734 0 340 0 0
341 QU-0004 2002-12 0 3,620 0 9.0 329 0 33
342 QU-0005 2002-12 0 7,285 62,981 8,646 3 2.6 663 5,731 17
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Table 1
Property: Coora Block Page 7
Last Month of Data: Alta.: 2010-11 Sask.: 2010-10
B.C.: 2010-11 Man.: 2010-10
Well List and Production Summary
Production Dates Last Quarter Production Statistics Cumulative Production
RigRel First Last Inj Prod Oil Gas GOR WGR WC Oil Gas Water
# Well Location Regulatory Field Pool Current Status Days bbl/d Mcf/d scf/bbl bbl/MMcf % Mbbl MMcf Mbbl
yr-mm yr-mm yr-mm yr-mm
343 QU-0006 2002-12 0 3,299 0 0.8 300 0 3
344 QU-0007 2002-12 0 1,457 0 4.5 133 0 6
345 QU-0008 2002-12 0 4,223 63,213 14,967 41 38.0 384 5,752 236
346 QU-0009 2002-12 0 2,739 37,140 13,559 11 12.9 249 3,380 37
347 QU-0010 2002-12 0 2,524 0 230 0 0
348 QU-0011 2002-12 0 2,142 0 195 0 0
349 QU-0012 2002-12 0 2,087 2,394 1,147 49 5.3 190 218 11
350 QU-0013 2002-12 0 1,993 0 6.8 181 0 13
351 QU-0014 2002-12 0 2,743 6,003 2,189 2 0.5 250 546 1
352 QU-0015 2002-12 0 5,178 0 0.8 471 0 4
353 QU-0016 2002-12 0 4,543 38,367 8,446 34 22.1 413 3,491 117
354 QU-0017 2002-12 0 30 0 3 0 0
355 QU-0018 2002-12 0 5,017 0 13.9 457 0 74
356 QU-0019 2002-12 0 2,359 0 215 0 0
357 QU-0020 2002-12 0 2,599 0 0.0 236 0 0
358 QU-0021 2002-12 0 1,046 0 14.1 95 0 16
359 QU-0022 2003-02 59 3,443 0 0.1 317 0 0
360 QU-0023 2002-12 0 2,300 0 209 0 0
361 QU-0024 2010-08 3 0 0 0.4 108 0 29
362 QU-0025 2002-12 0 375 0 34 0 0
363 QU-0026 2002-12 0 4,078 0 0.9 371 0 3
364 QU-0027 2002-12 0 3,727 53,809 14,437 13 15.9 339 4,897 64
365 QU-0028 2002-12 0 4,432 3,328 751 529 28.4 403 303 160
366 QU-0029 2002-12 0 576 0 1.2 52 0 1
367 QU-0030 2002-12 0 1,080 0 98 0 0
368 QU-0031 2002-12 0 3,775 81,557 21,604 12 19.9 344 7,422 85
369 QU-0032 2002-12 0 851 31,445 36,962 7 21.4 77 2,862 21
370 QU-0034 2002-12 0 4,862 31,523 6,484 34 18.2 442 2,869 98
371 QU-0038 2002-12 0 4,555 23,026 5,055 3 1.5 414 2,095 6
372 QU-0039 2010-08 50 2 0 7 0 4
373 QU-0040 2002-12 0 2,523 50,981 20,206 14 22.2 230 4,639 66
374 QU-0041 2006-12 80 1 0 2.6 45 0 0
375 QU-0042 2002-12 0 428 0 1.5 39 0 1
376 QU-0043 2002-12 0 990 44 45 214 1.0 90 4 1
377 QU-0044 2002-12 0 1,234 221 179 394 6.6 112 20 8
378 QU-0045 2002-12 0 3,021 19,612 6,492 30 16.4 275 1,785 54
379 QU-0047 2002-12 0 1,494 0 0.1 136 0 0
380 QU-0048 2002-12 0 2,203 0 5.1 200 0 11
381 QU-0049 2002-12 0 10,818 0 1.0 984 0 10
382 QU-0050 2002-12 0 3,283 0 2.8 299 0 9
383 QU-0051 2002-12 0 2,213 157,688 71,258 18 56.8 201 14,350 265
384 QU-0052 2002-12 0 365 0 33 0 0
385 QU-0053 2002-12 0 4,620 131,814 28,529 12 25.4 420 11,995 143
386 QU-0054 2002-12 0 578 0 53 0 0
387 QU-0055 2002-12 0 438 0 0.0 40 0 0
388 QU-0057 2002-12 0 947 102,030 >99999 7 44.1 86 9,285 68
389 QU-0058 2002-12 0 2,518 0 1.3 229 0 3
390 QU-0059 2002-12 0 3,120 0 0.0 284 0 0
391 QU-0060 2002-12 0 108 0 10 0 0
392 QU-0061 2002-12 0 673 57,826 85,925 1 8.8 61 5,262 6
393 QU-0062 2002-12 0 8,482 0 6.0 772 0 49
394 QU-0063 2002-12 0 4,984 87,554 17,566 17 22.7 454 7,967 133
395 QU-0065 2002-12 0 1,226 0 112 0 0
396 QU-0066 2002-12 0 790 378,630 >99999 0 9.2 72 34,455 7
397 QU-0067 2002-12 0 4,532 100,271 22,123 34 42.7 412 9,125 307
398 QU-0068 2010-07 1 0 0 0.4 273 0 4
399 QU-0069 2002-12 0 929 0 2.4 85 0 2
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Table 1
Property: Coora Block Page 8
Last Month of Data: Alta.: 2010-11 Sask.: 2010-10
B.C.: 2010-11 Man.: 2010-10
Well List and Production Summary
Production Dates Last Quarter Production Statistics Cumulative Production
RigRel First Last Inj Prod Oil Gas GOR WGR WC Oil Gas Water
# Well Location Regulatory Field Pool Current Status Days bbl/d Mcf/d scf/bbl bbl/MMcf % Mbbl MMcf Mbbl
yr-mm yr-mm yr-mm yr-mm
400 QU-0072 2006-04 1 0 0 0.6 130 0 0
401 QU-0073 2002-12 0 1,239 0 0.3 113 0 0
402 QU-0074 2002-12 0 42 0 4 0 0
403 QU-0075 2002-12 0 3,390 0 0.2 309 0 1
404 QU-0076 2002-12 0 2,726 54,487 19,991 3 5.4 248 4,958 14
405 QU-0077 2002-12 0 400 0 30.0 36 0 16
406 QU-0078 2002-12 0 2,181 39,026 17,892 6 9.2 198 3,551 20
407 QU-0079 2002-12 0 1,524 63,665 41,767 16 39.7 139 5,794 91
408 QU-0080 2002-12 0 2,544 12,469 4,902 19 8.7 231 1,135 22
409 QU-0081 2002-12 0 802 6 7 641 0.4 73 1 0
410 QU-0082 2006-04 2 0 0 5.0 225 0 254
411 QU-0083 2002-12 0 3,851 35,151 9,129 31 21.9 350 3,199 98
412 QU-0084 2002-12 0 1,960 0 13.2 178 0 27
413 QU-0085 2002-12 0 1,924 0 2.3 175 0 4
414 QU-0086 2002-12 0 1,079 0 0.0 98 0 0
415 QU-0087 2002-12 0 152 0 14 0 0
416 QU-0088 2002-12 0 3,745 0 7.3 341 0 27
417 QU-0089 2010-03 12 2 0 150 0 0
418 QU-0090 2002-12 0 1 0 0 0 0
419 QU-0091 2010-03 2 0 0 1.0 42 0 0
420 QU-0092 2002-12 0 685 0 62 0 0
421 QU-0093 2008-02 2 0 0 4 0 0
422 QU-0094 2002-12 0 1,069 0 97 0 0
423 QU-0096 2002-12 0 836 91 109 1,352 12.9 76 8 11
424 QU-0098 0 0 0 0 0 0
425 QU-0100 2002-12 0 523 15,394 29,428 4 9.6 48 1,401 5
426 QU-0102 2006-12 64 2 0 1.0 79 1 0
427 QU-0103 2002-12 0 1,028 0 94 0 0
428 QU-0106 2002-12 0 403 1 2 1,024 0.2 37 0 0
429 QU-0108 2002-12 0 3 0 0 0 0
430 QU-0109 2002-12 0 190 0 17 0 0
431 QU-0112 2002-12 0 3,098 0 0.5 282 0 1
432 QU-0113 2002-12 0 48 0 4 0 0
433 QU-0115 2002-12 0 3,561 0 3.8 324 0 13
434 QU-0117 2010-08 91 3 0 24.4 7 0 1
435 QU-0118 2002-12 0 1,717 0 156 0 0
436 QU-0119 2002-12 0 2,898 51,396 17,735 0 0.1 264 4,677 0
437 QU-0120 2002-12 0 5,153 43,599 8,461 3 2.4 469 3,968 12
438 QU-0124 2002-12 0 3,177 209,997 66,094 12 43.9 289 19,110 226
439 QU-0125 2002-12 0 2,516 17,364 6,901 9 5.6 229 1,580 14
440 QU-0126 2002-12 0 3,291 85,421 25,959 10 20.4 299 7,773 77
441 QU-0135 2002-12 0 1,956 0 0.1 178 0 0
442 QU-0148 2002-12 0 2,200 115,307 52,403 2 11.5 200 10,493 26
443 QU-0149 2002-12 0 3,128 178,006 56,901 25 58.2 285 16,199 397
444 QU-0150 2002-12 0 388 4,449 11,459 12 12.0 35 405 5
445 QU-0153 2002-12 0 1,348 64,884 48,130 11 34.7 123 5,904 65
446 QU-0154 2002-12 0 2,068 101,378 49,011 10 33.2 188 9,225 93
447 QU-0156 2002-12 0 1,845 201,949 >99999 27 74.7 168 18,377 495
448 QU-0174 2002-12 0 2,176 89,104 40,947 2 6.8 198 8,108 14
449 QU-0175 2002-12 0 773 14,407 18,640 5 7.9 70 1,311 6
450 QU-0178 0 0 0 0 0 0
451 QU-0185 0 0 0 0 0 0
452 QU-0187 2010-08 91 3 0 87.9 13 0 60
453 QU-0189 2010-08 2 0 0 18.4 1 0 0
454 QU-0194 2002-12 0 185 60,943 >99999 1 31.5 17 5,546 8
455 QU-0196 0 0 0 0 0 0
456 QU-0199 0 0 0 0 0 0
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Table 1
Property: Coora Block Page 9
Last Month of Data: Alta.: 2010-11 Sask.: 2010-10
B.C.: 2010-11 Man.: 2010-10
Well List and Production Summary
Production Dates Last Quarter Production Statistics Cumulative Production
RigRel First Last Inj Prod Oil Gas GOR WGR WC Oil Gas Water
# Well Location Regulatory Field Pool Current Status Days bbl/d Mcf/d scf/bbl bbl/MMcf % Mbbl MMcf Mbbl
yr-mm yr-mm yr-mm yr-mm
457 QU-0200 2002-12 0 389 33,933 87,149 6 35.0 35 3,088 19
458 QU-0201 2002-12 0 192 0 4.0 17 0 1
459 QU-0202 0 0 0 0 0 0
460 QU-0203 0 0 0 0 0 0
461 QU-0206 2003-03 90 0 0 0 0 0
462 QU-0211 2002-12 0 586 0 53 0 0
463 QU-0217 2002-12 0 204 0 30.2 19 0 8
464 QU-0220 2010-08 3 1 0 0.9 2 0 0
465 QU-0221 2002-12 0 1,271 0 26.1 116 0 41
466 QU-0223 2002-12 0 479 0 0.0 44 0 0
467 QU-0224 2002-12 0 295 6 19 3,922 6.9 27 1 2
468 QU-0225 2002-12 0 651 17 26 2,894 6.9 59 2 4
469 QU-0226 2002-12 0 1,940 0 0.0 177 0 0
470 QU-0228 2010-08 7 2 0 0.6 45 0 0
471 QU-0229 2002-12 0 1,064 10 9 483 0.5 97 1 0
472 QU-0230 2010-08 17 1 0 0.7 111 226 0
473 QU-0231 2002-12 0 504 0 4.6 46 0 2
474 QU-0236 2002-12 0 1,308 0 119 0 0
475 QU-0237 2010-08 90 3 0 39.8 116 0 3
476 QU-0239 2005-08 85 1 0 1.7 116 1 19
477 QU-0249 2002-12 0 5 0 0 0 0
478 QU-0256 2002-12 0 330 826 2,505 11 2.8 30 75 1
479 QU-0257 2002-12 0 492 7,577 15,407 2 2.3 45 689 1
480 QU-0258 2002-12 0 172 719 4,191 17 6.6 16 65 1
481 QU-0259 2002-12 0 974 0 0.0 89 0 0
482 QU-0260 2002-12 0 1,621 1,165 718 2 0.1 148 106 0
483 QU-0261 2002-12 0 1,339 9,716 7,255 1 0.6 122 884 1
484 QU-0279 2002-12 0 915 86,015 93,965 8 44.3 83 7,827 66
485 QU-0280 2007-07 15 1 0 52.0 0 0 0
486 QU-0286 2002-12 0 1,671 531,725 >99999 3 44.6 152 48,387 122
487 QU-0287 2010-08 5 1 0 0.6 21 2,087 1
488 QU-0291 2006-04 83 2 0 2.0 18 4,012 0
489 QU-0297 2002-12 0 718 18,221 25,391 37 48.5 65 1,658 61
490 QU-0298 2002-12 0 756 113,353 >99999 8 55.2 69 10,315 85
491 QU-0300 2002-12 0 991 101,825 >99999 1 7.0 90 9,266 7
492 QU-0302 2010-08 91 3 0 1.1 13 12,538 1
493 QU-0303 2002-12 0 963 72,511 75,288 1 4.5 88 6,598 4
494 QU-0304 2002-12 0 0 0 0 0 0
495 QU-0305 2002-12 0 84 0 0.2 8 0 0
496 QU-0306 2002-12 0 337 5,426 16,096 228 78.6 31 494 113
497 QU-0307 2002-12 0 771 125,617 >99999 3 30.4 70 11,431 31
498 QU-0309 2002-12 0 22 1,093 50,278 129 86.7 2 100 13
499 QU-0310 2002-12 0 471 91,401 >99999 3 39.8 43 8,317 28
500 QU-0311 2002-12 0 658 73,749 >99999 1 14.2 60 6,711 10
501 QU-0313 2008-11 64 3 0 65.6 68 822 10
502 QU-0314 2002-12 0 89 0 71.1 8 0 20
503 QU-0316 2002-12 0 607 0 46.8 55 0 49
504 QU-0317 2002-12 0 15 0 90.5 1 0 13
505 QU-0318 2002-12 0 99 18,321 >99999 24 81.6 9 1,667 40
506 QU-0319 2002-12 0 35 14,536 >99999 0 14.3 3 1,323 1
507 QU-0322 2002-12 0 1,027 98,054 95,509 26 71.0 93 8,923 229
508 QU-0325 2002-12 0 48 0 4 0 0
509 QU-0326 2002-12 0 70 26,153 >99999 13 82.3 6 2,380 30
510 QU-0327 2002-12 0 2 0 0 0 0
511 QU-0329 2002-12 0 20 8,787 >99999 1 31.5 2 800 1
512 QU-0333 2002-12 0 876 178,082 >99999 21 80.7 80 16,205 332
513 QU-0334 2002-12 0 487 86,359 >99999 4 42.2 44 7,859 32
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Table 1
Property: Coora Block Page 10
Last Month of Data: Alta.: 2010-11 Sask.: 2010-10
B.C.: 2010-11 Man.: 2010-10
Well List and Production Summary
Production Dates Last Quarter Production Statistics Cumulative Production
RigRel First Last Inj Prod Oil Gas GOR WGR WC Oil Gas Water
# Well Location Regulatory Field Pool Current Status Days bbl/d Mcf/d scf/bbl bbl/MMcf % Mbbl MMcf Mbbl
yr-mm yr-mm yr-mm yr-mm
514 QU-0335 2002-12 0 761 83,426 >99999 59 86.6 69 7,592 447
515 QU-0336 2002-12 0 1,055 133,389 >99999 25 76.0 96 12,138 303
516 QU-0337 2002-12 0 921 133,831 >99999 17 71.0 84 12,179 205
517 QU-0338 2002-12 0 882 83,925 95,140 17 61.7 80 7,637 129
518 QU-0339 2002-12 0 311 27,057 86,990 25 68.9 28 2,462 63
519 QU-0340 2002-12 0 1,067 198,948 >99999 22 80.2 97 18,104 394
520 QU-0341 2002-12 0 448 113,984 >99999 4 50.8 41 10,373 42
521 QU-0343 0 0 0 0 0 0
522 QU-0346 2002-12 0 162 218,397 >99999 5 86.3 15 19,874 93
523 QU-0347 2002-12 0 715 103,577 >99999 11 61.0 65 9,425 102
524 QU-0348 2002-12 0 1,568 316,051 >99999 6 55.1 143 28,761 175
525 QU-0349 2002-12 0 567 48,978 86,410 10 47.3 52 4,457 46
526 QU-0350 2002-12 0 646 129,732 >99999 14 73.6 59 11,806 164
527 QU-0351 2002-12 0 733 71,519 97,605 16 61.1 67 6,508 105
528 QU-0353 2002-12 0 18 0 2 0 0
529 QU-0354 2002-12 0 11 4,610 >99999 6 70.2 1 420 2
530 QU-0355 2002-12 0 901 134,935 >99999 13 66.9 82 12,279 165
531 QU-0356 2002-12 0 86 9,713 >99999 22 71.7 8 884 20
532 QU-0360 2002-12 0 815 141,698 >99999 13 69.6 74 12,895 169
533 QU-0362 2002-12 0 36 13,242 >99999 10 79.2 3 1,205 12
534 QU-0373 2002-12 0 1,195 197,696 >99999 21 77.7 109 17,990 378
535 QU-0374 2002-12 0 384 45,372 >99999 12 58.7 35 4,129 50
536 QU-0376 2002-12 0 190 40,501 >99999 1 13.3 17 3,686 3
537 QU-0377 2002-12 0 0 187 >99999 0 17 0
538 QU-0378 0 0 0 0 0 0
539 QU-0379 2002-12 0 12 469 39,920 430 94.5 1 43 18
540 QU-0381 2002-12 0 191 12,241 64,207 25 61.5 17 1,114 28
541 QU-0385 2002-12 0 730 0 66 0 0
542 QU-0386 2002-12 0 240 66,953 >99999 27 88.1 22 6,093 162
543 QU-0389 2002-12 0 132 17,870 >99999 21 74.2 12 1,626 34
544 QU-0391 2002-12 0 392 67,727 >99999 9 60.1 36 6,163 54
545 QU-0395 2002-12 0 425 137,180 >99999 12 79.4 39 12,483 149
546 QU-0428 2009-01 3 1 0 1.0 3 0 0
547 Q_-19 2002-12 0 213 0 19 0 0
548 Q_-20 2002-12 0 603 0 55 0 0
Total 551,661 8,551,171 69,414 820,295 13,100
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Table 2
Company: Touchstone Exploration Reserve Class: Various
Property: Coora Block Development Class: Classifications
Pricing: GLJ (2010-07)
Effective Date: August 31, 2010
Gross Lease Reserves Summary
Oil (Mbbl) Non-Associated Gas (MMcf) Other Gross Lease Reserves
Reserve Initial Cumulative Initial Cumulative Raw Sol'n Gas Cond LPG Sulphur
Entity Description Class Methodology Recoverable Production Reserves Recoverable Production Gas Reserves MMcf Mbbl Mbbl Mlt
Proved Producing
Coora
1) Current Production.
1) Coora Producing A Dec 70,400 69,414 986 0 0 0 0 0 0 0 0
Total: 1) Current Production. 70,400 69,414 986 0 0 0 0 0 0 0 0
Total: Coora 70,400 69,414 986 0 0 0 0 0 0 0 0
Total: Proved Producing 70,400 69,414 986 0 0 0 0 0 0 0 0
Proved Developed Nonproducing
Coora
1) Current Production.
1) Coora Producing 0 0 -213 * 0 0 0 0 0 0 0 0
Total: 1) Current Production. 0 0 -213 * 0 0 0 0 0 0 0 0
2) Recompletions/Workovers
2011-Q3 B1 Dec 270 0 253 * 0 0 0 0 0 0 0 0
2012-Q3 B1 Dec 270 0 249 * 0 0 0 0 0 0 0 0
2013-Q3 B1 Dec 270 0 243 * 0 0 0 0 0 0 0 0
2014-Q3 B1 Dec 200 0 180 * 0 0 0 0 0 0 0 0
Total: 2) Recompletions/Workovers 1,010 0 925 * 0 0 0 0 0 0 0 0
Total: Coora 1,010 0 712 * 0 0 0 0 0 0 0 0
Total: Proved Developed Nonproducing 1,010 0 712 * 0 0 0 0 0 0 0 0
Proved Undeveloped
Coora
1) Current Production.
1) Coora Producing 0 0 85 * 0 0 0 0 0 0 0 0
Total: 1) Current Production. 0 0 85 * 0 0 0 0 0 0 0 0
2) Recompletions/Workovers
2011-Q3 0 0 16 * 0 0 0 0 0 0 0 0
2012-Q3 0 0 18 * 0 0 0 0 0 0 0 0
2013-Q3 0 0 19 * 0 0 0 0 0 0 0 0
2014-Q3 0 0 17 * 0 0 0 0 0 0 0 0
Total: 2) Recompletions/Workovers 0 0 71 * 0 0 0 0 0 0 0 0
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Table 2 Page 2
Gross Lease Reserves Summary
Oil (Mbbl) Non-Associated Gas (MMcf) Other Gross Lease Reserves
Reserve Initial Cumulative Initial Cumulative Raw Sol'n Gas Cond LPG Sulphur
Entity Description Class Methodology Recoverable Production Reserves Recoverable Production Gas Reserves MMcf Mbbl Mbbl Mlt
Proved Undeveloped (Cont.)
Coora (Cont.)
3) Replacement Wells
Location F B2 Vol 184 0 177 * 0 0 0 0 0 0 0 0
Total: 3) Replacement Wells 184 0 177 * 0 0 0 0 0 0 0 0
4) Sidetrack Wells
CO-362 Sidetrack B2 Vol 152 0 142 * 0 0 0 0 0 0 0 0
Total: 4) Sidetrack Wells 152 0 142 * 0 0 0 0 0 0 0 0
Total: Coora 336 0 475 * 0 0 0 0 0 0 0 0
Total: Proved Undeveloped 336 0 475 * 0 0 0 0 0 0 0 0
Total Proved
Coora
1) Current Production.
1) Coora Producing C Dec 70,400 69,414 858 * 0 0 0 0 0 0 0 0
Total: 1) Current Production. 70,400 69,414 858 * 0 0 0 0 0 0 0 0
2) Recompletions/Workovers
2011-Q3 C Dec 270 0 269 * 0 0 0 0 0 0 0 0
2012-Q3 C Dec 270 0 267 * 0 0 0 0 0 0 0 0
2013-Q3 C Dec 270 0 263 * 0 0 0 0 0 0 0 0
2014-Q3 C Dec 200 0 197 * 0 0 0 0 0 0 0 0
Total: 2) Recompletions/Workovers 1,010 0 996 * 0 0 0 0 0 0 0 0
3) Replacement Wells
Location F B2 Vol 184 0 177 * 0 0 0 0 0 0 0 0
Total: 3) Replacement Wells 184 0 177 * 0 0 0 0 0 0 0 0
4) Sidetrack Wells
CO-362 Sidetrack B2 Vol 152 0 142 * 0 0 0 0 0 0 0 0
Total: 4) Sidetrack Wells 152 0 142 * 0 0 0 0 0 0 0 0
Total: Coora 71,746 69,414 2,173 * 0 0 0 0 0 0 0 0
Total: Total Proved 71,746 69,414 2,173 * 0 0 0 0 0 0 0 0
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Table 2 Page 3
Gross Lease Reserves Summary
Oil (Mbbl) Non-Associated Gas (MMcf) Other Gross Lease Reserves
Reserve Initial Cumulative Initial Cumulative Raw Sol'n Gas Cond LPG Sulphur
Entity Description Class Methodology Recoverable Production Reserves Recoverable Production Gas Reserves MMcf Mbbl Mbbl Mlt
Total Probable
Coora
1) Current Production.
1) Coora Producing 190 0 249 * 0 0 0 0 0 0 0 0
Total: 1) Current Production. 190 0 249 * 0 0 0 0 0 0 0 0
2) Recompletions/Workovers
2011-Q3 165 0 166 * 0 0 0 0 0 0 0 0
2012-Q3 165 0 168 * 0 0 0 0 0 0 0 0
2013-Q3 165 0 172 * 0 0 0 0 0 0 0 0
2014-Q3 235 0 238 * 0 0 0 0 0 0 0 0
2015-Q3 I Dec 305 0 305 0 0 0 0 0 0 0 0
2016-Q3 I Dec 305 0 305 0 0 0 0 0 0 0 0
Total: 2) Recompletions/Workovers 1,340 0 1,354 * 0 0 0 0 0 0 0 0
3) Replacement Wells
Location F 57 0 64 * 0 0 0 0 0 0 0 0
Location G H2 Vol 103 0 102 0 0 0 0 0 0 0 0
Location H H2 Vol 135 0 135 0 0 0 0 0 0 0 0
Location L H2 Vol 136 0 136 0 0 0 0 0 0 0 0
Total: 3) Replacement Wells 431 0 438 * 0 0 0 0 0 0 0 0
4) Sidetrack Wells
CO-180 Sidetrack H2 Vol 141 0 141 0 0 0 0 0 0 0 0
CO-362 Sidetrack 42 0 52 * 0 0 0 0 0 0 0 0
QU-080 Sidetrack H2 Vol 186 0 186 0 0 0 0 0 0 0 0
QU-119 Sidetrack H2 Vol 77 0 77 0 0 0 0 0 0 0 0
QU-428 Sidetrack H2 Vol 130 0 130 0 0 0 0 0 0 0 0
Total: 4) Sidetrack Wells 576 0 586 * 0 0 0 0 0 0 0 0
Total: Coora 2,537 0 2,626 * 0 0 0 0 0 0 0 0
Total: Total Probable 2,537 0 2,626 * 0 0 0 0 0 0 0 0
Total Proved Plus Probable
Coora
1) Current Production.
1) Coora Producing I Dec 70,590 69,414 1,107 * 0 0 0 0 0 0 0 0
Total: 1) Current Production. 70,590 69,414 1,107 * 0 0 0 0 0 0 0 0
2) Recompletions/Workovers
2011-Q3 I Dec 435 0 435 0 0 0 0 0 0 0 0
2012-Q3 I Dec 435 0 435 0 0 0 0 0 0 0 0
2013-Q3 I Dec 435 0 435 0 0 0 0 0 0 0 0
2014-Q3 I Dec 435 0 435 0 0 0 0 0 0 0 0
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Table 2 Page 4
Gross Lease Reserves Summary
Oil (Mbbl) Non-Associated Gas (MMcf) Other Gross Lease Reserves
Reserve Initial Cumulative Initial Cumulative Raw Sol'n Gas Cond LPG Sulphur
Entity Description Class Methodology Recoverable Production Reserves Recoverable Production Gas Reserves MMcf Mbbl Mbbl Mlt
Total Proved Plus Probable (Cont.)
Coora (Cont.)
2) Recompletions/Workovers (Cont.)
2015-Q3 I Dec 305 0 305 0 0 0 0 0 0 0 0
2016-Q3 I Dec 305 0 305 0 0 0 0 0 0 0 0
Total: 2) Recompletions/Workovers 2,350 0 2,350 0 0 0 0 0 0 0 0
3) Replacement Wells
Location F H2 Vol 241 0 241 0 0 0 0 0 0 0 0
Location G H2 Vol 103 0 102 0 0 0 0 0 0 0 0
Location H H2 Vol 135 0 135 0 0 0 0 0 0 0 0
Location L H2 Vol 136 0 136 0 0 0 0 0 0 0 0
Total: 3) Replacement Wells 615 0 615 0 0 0 0 0 0 0 0
4) Sidetrack Wells
CO-180 Sidetrack H2 Vol 141 0 141 0 0 0 0 0 0 0 0
CO-362 Sidetrack H2 Vol 194 0 194 0 0 0 0 0 0 0 0
QU-080 Sidetrack H2 Vol 186 0 186 0 0 0 0 0 0 0 0
QU-119 Sidetrack H2 Vol 77 0 77 0 0 0 0 0 0 0 0
QU-428 Sidetrack H2 Vol 130 0 130 0 0 0 0 0 0 0 0
Total: 4) Sidetrack Wells 728 0 728 0 0 0 0 0 0 0 0
Total: Coora 74,283 69,414 4,799 * 0 0 0 0 0 0 0 0
Total: Total Proved Plus Probable 74,283 69,414 4,799 * 0 0 0 0 0 0 0 0
Notes
1. [*] Remaining reserves are less than the estimate due to economic limit.
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Table 2.1
Company: Touchstone Exploration Effective Date: August 31, 2010
Property: Coora Block
Oil Reservoir Parameters
Original Cum
Net Water Original Reservoir Oil Oil Formation Oil Recovery Recoverable Production Remaining
Reserve Area Pay Porosity Sat'n Pressure Temp. Gravity Solution Volume In Place Factor Reserves 2010-09-01 2010-08-31
Resource Entity Zone Method Class acre ft % % psi °R oAPI GOR Factor Mbbl % Mbbl Mbbl Reserves
Proved Producing
Blocks 1 and 2
1) Coora Producing UMLE to Lower Cruse Decline A - - - - - - - - - - - 70,400.0 69,414.1 985.9
Total: Proved Producing 70,400.0 69,414.1 985.9
Proved Developed Nonproducing
Blocks 1 and 2
2) Recompletions/Workovers
2011-Q3 UMLE to Lower Cruse Decline B1 - - - - - - - - - - - 270.0 - 270.0
2012-Q3 UMLE to Lower Cruse Decline B1 - - - - - - - - - - - 270.0 - 270.0
2013-Q3 UMLE to Lower Cruse Decline B1 - - - - - - - - - - - 270.0 - 270.0
2014-Q3 UMLE to Lower Cruse Decline B1 - - - - - - - - - - - 200.0 - 200.0
Total: Proved Developed Nonproducing 1,010.0 0.0 1,010.0
Proved Undeveloped
Blocks 1 and 2
3) Replacement Wells
Location F
2) F-TC Top Cruse Vol B2 15 12.0 30.0 25.0 715 560 24 100 1.120 280.5 5.0 14.0 - -
3) F-CR2 Cruse 2 Vol B2 20 30.0 30.0 25.0 600 560 24 100 1.120 935.1 4.0 37.4 - -
4) F-CR5 Cruse 5 Vol B2 20 35.0 30.0 25.0 700 560 24 100 1.120 1,091.0 5.0 54.5 - -
5) F-MCR Middle Cruse Vol B2 20 50.0 30.0 25.0 1,000 570 24 100 1.120 1,558.5 5.0 77.9 - -
Location F Commingled B2 3,865.1 4.8 183.9 - 183.9
4) Sidetrack Wells
CO-362 Sidetrack
1) A-UF5 Upper Forest 5 Vol B2 15 15.0 30.0 25.0 250 550 22 100 1.060 370.5 8.0 29.6 - -
2) A-UF8 Upper Forest 8 Vol B2 10 15.0 30.0 25.0 268 550 22 100 1.060 247.0 6.0 14.8 - -
3) A-LF8 Lower Forest 8 Vol B2 10 50.0 30.0 25.0 356 560 22 100 1.080 808.1 5.0 40.4 - -
4) A-CR5 Cruse 5 Vol B2 20 15.0 30.0 25.0 476 570 24 100 1.120 467.6 5.0 23.4 - -
6) A-MCR3 Middle Cruse 3 Vol B2 20 20.0 30.0 25.0 818 570 24 100 1.120 623.4 7.0 43.6 - -
CO-362 Sidetrack Commingled B2 2,516.6 6.0 151.9 - 151.9
Total: Proved Undeveloped 335.8 0.0 335.8
Total Proved
Blocks 1 and 2
1) Coora Producing UMLE to Lower Cruse Decline A - - - - - - - - - - - 70,400.0 69,414.1 985.9
2) Recompletions/Workovers
2011-Q3 UMLE to Lower Cruse Decline B1 - - - - - - - - - - - 270.0 - 270.0
2012-Q3 UMLE to Lower Cruse Decline B1 - - - - - - - - - - - 270.0 - 270.0
2013-Q3 UMLE to Lower Cruse Decline B1 - - - - - - - - - - - 270.0 - 270.0
2014-Q3 UMLE to Lower Cruse Decline B1 - - - - - - - - - - - 200.0 - 200.0
3) Replacement Wells
Location F
2) F-TC Top Cruse Vol B2 15 12.0 30.0 25.0 715 560 24 100 1.120 280.5 5.0 14.0 - -
3) F-CR2 Cruse 2 Vol B2 20 30.0 30.0 25.0 600 560 24 100 1.120 935.1 4.0 37.4 - -
4) F-CR5 Cruse 5 Vol B2 20 35.0 30.0 25.0 700 560 24 100 1.120 1,091.0 5.0 54.5 - -
5) F-MCR Middle Cruse Vol B2 20 50.0 30.0 25.0 1,000 570 24 100 1.120 1,558.5 5.0 77.9 - -
Location F Commingled B2 3,865.1 4.8 183.9 - 183.9
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Oil Reservoir Parameters
Original Cum
Net Water Original Reservoir Oil Oil Formation Oil Recovery Recoverable Production Remaining
Reserve Area Pay Porosity Sat'n Pressure Temp. Gravity Solution Volume In Place Factor Reserves 2010-09-01 2010-08-31
Resource Entity Zone Method Class acre ft % % psi °R oAPI GOR Factor Mbbl % Mbbl Mbbl Reserves
Total Proved (Cont.)
Blocks 1 and 2 (Cont.)
4) Sidetrack Wells
CO-362 Sidetrack
1) A-UF5 Upper Forest 5 Vol B2 15 15.0 30.0 25.0 250 550 22 100 1.060 370.5 8.0 29.6 - -
2) A-UF8 Upper Forest 8 Vol B2 10 15.0 30.0 25.0 268 550 22 100 1.060 247.0 6.0 14.8 - -
3) A-LF8 Lower Forest 8 Vol B2 10 50.0 30.0 25.0 356 560 22 100 1.080 808.1 5.0 40.4 - -
4) A-CR5 Cruse 5 Vol B2 20 15.0 30.0 25.0 476 570 24 100 1.120 467.6 5.0 23.4 - -
6) A-MCR3 Middle Cruse 3 Vol B2 20 20.0 30.0 25.0 818 570 24 100 1.120 623.4 7.0 43.6 - -
CO-362 Sidetrack Commingled B2 2,516.6 6.0 151.9 - 151.9
Total: Total Proved 71,745.8 69,414.1 2,331.7
Total Probable
Blocks 1 and 2
2) Recompletions/Workovers
2011-Q3 UMLE to Lower Cruse Decline B1 - - - - - - - - - - - -270.0 - -270.0
2011-Q3 UMLE to Lower Cruse Decline H1 - - - - - - - - - - - 435.0 - 435.0
2012-Q3 UMLE to Lower Cruse Decline B1 - - - - - - - - - - - -270.0 - -270.0
2012-Q3 UMLE to Lower Cruse Decline H1 - - - - - - - - - - - 435.0 - 435.0
2013-Q3 UMLE to Lower Cruse Decline B1 - - - - - - - - - - - -270.0 - -270.0
2013-Q3 UMLE to Lower Cruse Decline H1 - - - - - - - - - - - 435.0 - 435.0
2014-Q3 UMLE to Lower Cruse Decline B1 - - - - - - - - - - - -200.0 - -200.0
2014-Q3 UMLE to Lower Cruse Decline H1 - - - - - - - - - - - 435.0 - 435.0
2015-Q3 UMLE to Lower Cruse Decline H1 - - - - - - - - - - - 305.0 - 305.0
2016-Q3 UMLE to Lower Cruse Decline H1 - - - - - - - - - - - 305.0 - 305.0
3) Replacement Wells
Location F
2) F-TC Top Cruse Vol B2 -15 -12.0 -30.0 -25.0 -715 -560 -24 -100 -1.120 280.5 -5.0 -14.0 - -
2) F-TC Top Cruse Vol H2 15 12.0 30.0 25.0 715 560 24 100 1.120 280.5 7.0 19.6 - -
3) F-CR2 Cruse 2 Vol B2 -20 -30.0 -30.0 -25.0 -600 -560 -24 -100 -1.120 935.1 -4.0 -37.4 - -
3) F-CR2 Cruse 2 Vol H2 20 30.0 30.0 25.0 600 560 24 100 1.120 935.1 5.0 46.8 - -
4) F-CR5 Cruse 5 Vol B2 -20 -35.0 -30.0 -25.0 -700 -560 -24 -100 -1.120 1,091.0 -5.0 -54.5 - -
4) F-CR5 Cruse 5 Vol H2 20 35.0 30.0 25.0 700 560 24 100 1.120 1,091.0 6.0 65.5 - -
5) F-MCR Middle Cruse Vol B2 -20 -50.0 -30.0 -25.0 -1,000 -570 -24 -100 -1.120 1,558.5 -5.0 -77.9 - -
5) F-MCR Middle Cruse Vol H2 20 50.0 30.0 25.0 1,000 570 24 100 1.120 1,558.5 7.0 109.1 - -
Location F - - - - - -
Location G
1) G-TC Top Cruse Vol H2 15 14.0 30.0 25.0 715 560 24 100 1.120 327.3 5.0 16.4 - -
2) G-CR2 Cruse 2 Vol H2 20 50.0 30.0 25.0 535 560 24 100 1.120 1,558.5 5.0 77.9 - -
3) G-CR5 Cruse 5 Vol H2 5 35.0 30.0 25.0 350 570 24 100 1.120 272.7 3.0 8.2 - -
Location G Commingled H2 2,158.6 4.7 102.5 - 102.5
Location H
1) H-UF4 Upper Forest 4 Vol H2 10 10.0 30.0 25.0 576 550 22 100 1.060 164.7 11.0 18.1 - -
2) H-UF5 Upper Forest 5 Vol H2 20 25.0 30.0 25.0 400 550 22 100 1.060 823.4 7.0 57.6 - -
3) H-LF2 Lower Forest 2 Vol H2 15 35.0 30.0 25.0 450 560 22 100 1.080 848.5 7.0 59.4 - -
Location H Commingled H2 1,836.6 7.4 135.1 - 135.1
Location L
L-CR5 Cruise 5 Vol H2 5 35.0 30.0 25.0 600 570 24 100 1.120 272.7 6.0 16.4 - -
L-CR7 Cruise 7 Vol H2 20 35.0 30.0 25.0 800 570 24 100 1.120 1,091.0 5.0 54.5 - -
L-MCR Middle Cruse Vol H2 20 35.0 30.0 25.0 600 570 24 100 1.120 1,091.0 6.0 65.5 - -
Location L Commingled H2 2,454.7 5.6 136.4 - 136.4
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Oil Reservoir Parameters
Original Cum
Net Water Original Reservoir Oil Oil Formation Oil Recovery Recoverable Production Remaining
Reserve Area Pay Porosity Sat'n Pressure Temp. Gravity Solution Volume In Place Factor Reserves 2010-09-01 2010-08-31
Resource Entity Zone Method Class acre ft % % psi °R oAPI GOR Factor Mbbl % Mbbl Mbbl Reserves
Total Probable (Cont.)
Blocks 1 and 2 (Cont.)
4) Sidetrack Wells
CO-180 Sidetrack
CR5 Cruse 5 Vol H2 5 62.0 30.0 25.0 1,000 - 24 100 1.120 483.1 6.0 29.0 - -
MC Middle Cruse Vol H2 20 60.0 30.0 25.0 600 - 24 100 1.120 1,870.2 6.0 112.2 - -
CO-180 Sidetrack Commingled H2 2,353.4 6.0 141.2 - 141.2
CO-362 Sidetrack
1) A-UF5 Upper Forest 5 Vol B2 -15 -15.0 -30.0 -25.0 -250 -550 -22 -100 -1.060 370.5 -8.0 -29.6 - -
1) A-UF5 Upper Forest 5 Vol H2 15 15.0 30.0 25.0 250 550 22 100 1.060 370.5 10.0 37.1 - -
2) A-UF8 Upper Forest 8 Vol B2 -10 -15.0 -30.0 -25.0 -268 -550 -22 -100 -1.060 247.0 -6.0 -14.8 - -
2) A-UF8 Upper Forest 8 Vol H2 10 15.0 30.0 25.0 268 550 22 100 1.060 247.0 8.0 19.8 - -
3) A-LF8 Lower Forest 8 Vol B2 -10 -50.0 -30.0 -25.0 -356 -560 -22 -100 -1.080 808.1 -5.0 -40.4 - -
3) A-LF8 Lower Forest 8 Vol H2 10 50.0 30.0 25.0 356 560 22 100 1.080 808.1 6.0 48.5 - -
4) A-CR5 Cruse 5 Vol B2 -20 -15.0 -30.0 -25.0 -476 -570 -24 -100 -1.120 467.6 -5.0 -23.4 - -
4) A-CR5 Cruse 5 Vol H2 20 15.0 30.0 25.0 476 570 24 100 1.120 467.6 7.0 32.7 - -
6) A-MCR3 Middle Cruse 3 Vol B2 -20 -20.0 -30.0 -25.0 -818 -570 -24 -100 -1.120 623.4 -7.0 -43.6 - -
6) A-MCR3 Middle Cruse 3 Vol H2 20 20.0 30.0 25.0 818 570 24 100 1.120 623.4 9.0 56.1 - -
CO-362 Sidetrack - - - - - -
QU-080 Sidetrack
2) D-TC Top Cruse Vol H2 15 8.0 30.0 25.0 715 560 24 100 1.120 187.0 7.0 13.1 - -
3) D-CR2 Cruse 2 Vol H2 20 45.0 30.0 25.0 600 560 24 100 1.120 1,402.7 5.0 70.1 - -
4) D-CR5 Cruse 5 Vol H2 20 20.0 30.0 25.0 700 570 24 100 1.120 623.4 6.0 37.4 - -
5) D-MCR Middle Cruse Vol H2 20 30.0 30.0 25.0 1,000 570 24 100 1.120 935.1 7.0 65.5 - -
QU-080 Sidetrack Commingled H2 3,148.2 5.9 186.1 - 186.1
QU-119 Sidetrack
1) MC Middle Cruse Vol H2 20 23.0 30.0 25.0 1,000 - 24 100 1.120 716.9 7.0 50.2 - -
2) CR7 Cruse 7 Vol H2 20 17.0 30.0 25.0 800 - 24 100 1.120 529.9 5.0 26.5 - -
QU-119 Sidetrack Commingled H2 1,246.8 6.2 76.7 - 76.7
QU-428 Sidetrack
1) P-CR4 Cruse 4 Vol H2 20 25.0 30.0 40.0 1,620 - 24 200 1.120 623.4 15.0 93.5 - -
2) P-CR5 Cruse 5 Vol H2 10 67.0 26.0 40.0 1,230 - 24 100 1.120 724.0 5.0 36.2 - -
QU-428 Sidetrack Commingled H2 1,347.4 9.6 129.7 - 129.7
Total: Total Probable 2,247.7 0.0 2,247.7
Total Proved Plus Probable
Blocks 1 and 2
1) Coora Producing UMLE to Lower Cruse Decline G - - - - - - - - - - - 70,590.0 69,414.1 1,175.9
2) Recompletions/Workovers
2011-Q3 UMLE to Lower Cruse Decline H1 - - - - - - - - - - - 435.0 - 435.0
2012-Q3 UMLE to Lower Cruse Decline H1 - - - - - - - - - - - 435.0 - 435.0
2013-Q3 UMLE to Lower Cruse Decline H1 - - - - - - - - - - - 435.0 - 435.0
2014-Q3 UMLE to Lower Cruse Decline H1 - - - - - - - - - - - 435.0 - 435.0
2015-Q3 UMLE to Lower Cruse Decline H1 - - - - - - - - - - - 305.0 - 305.0
2016-Q3 UMLE to Lower Cruse Decline H1 - - - - - - - - - - - 305.0 - 305.0
3) Replacement Wells
Location F
2) F-TC Top Cruse Vol H2 15 12.0 30.0 25.0 715 560 24 100 1.120 280.5 7.0 19.6 - -
3) F-CR2 Cruse 2 Vol H2 20 30.0 30.0 25.0 600 560 24 100 1.120 935.1 5.0 46.8 - -
4) F-CR5 Cruse 5 Vol H2 20 35.0 30.0 25.0 700 560 24 100 1.120 1,091.0 6.0 65.5 - -
5) F-MCR Middle Cruse Vol H2 20 50.0 30.0 25.0 1,000 570 24 100 1.120 1,558.5 7.0 109.1 - -
Location F Commingled H2 3,865.1 6.2 240.9 - 240.9
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Oil Reservoir Parameters
Original Cum
Net Water Original Reservoir Oil Oil Formation Oil Recovery Recoverable Production Remaining
Reserve Area Pay Porosity Sat'n Pressure Temp. Gravity Solution Volume In Place Factor Reserves 2010-09-01 2010-08-31
Resource Entity Zone Method Class acre ft % % psi °R oAPI GOR Factor Mbbl % Mbbl Mbbl Reserves
Total Proved Plus Probable (Cont.)
Blocks 1 and 2 (Cont.)
3) Replacement Wells (Cont.)
Location G
1) G-TC Top Cruse Vol H2 15 14.0 30.0 25.0 715 560 24 100 1.120 327.3 5.0 16.4 - -
2) G-CR2 Cruse 2 Vol H2 20 50.0 30.0 25.0 535 560 24 100 1.120 1,558.5 5.0 77.9 - -
3) G-CR5 Cruse 5 Vol H2 5 35.0 30.0 25.0 350 570 24 100 1.120 272.7 3.0 8.2 - -
Location G Commingled H2 2,158.6 4.7 102.5 - 102.5
Location H
1) H-UF4 Upper Forest 4 Vol H2 10 10.0 30.0 25.0 576 550 22 100 1.060 164.7 11.0 18.1 - -
2) H-UF5 Upper Forest 5 Vol H2 20 25.0 30.0 25.0 400 550 22 100 1.060 823.4 7.0 57.6 - -
3) H-LF2 Lower Forest 2 Vol H2 15 35.0 30.0 25.0 450 560 22 100 1.080 848.5 7.0 59.4 - -
Location H Commingled H2 1,836.6 7.4 135.1 - 135.1
Location L
L-CR5 Cruise 5 Vol H2 5 35.0 30.0 25.0 600 570 24 100 1.120 272.7 6.0 16.4 - -
L-CR7 Cruise 7 Vol H2 20 35.0 30.0 25.0 800 570 24 100 1.120 1,091.0 5.0 54.5 - -
L-MCR Middle Cruse Vol H2 20 35.0 30.0 25.0 600 570 24 100 1.120 1,091.0 6.0 65.5 - -
Location L Commingled H2 2,454.7 5.6 136.4 - 136.4
4) Sidetrack Wells
CO-180 Sidetrack
CR5 Cruse 5 Vol H2 5 62.0 30.0 25.0 1,000 - 24 100 1.120 483.1 6.0 29.0 - -
MC Middle Cruse Vol H2 20 60.0 30.0 25.0 600 - 24 100 1.120 1,870.2 6.0 112.2 - -
CO-180 Sidetrack Commingled H2 2,353.4 6.0 141.2 - 141.2
CO-362 Sidetrack
1) A-UF5 Upper Forest 5 Vol H2 15 15.0 30.0 25.0 250 550 22 100 1.060 370.5 10.0 37.1 - -
2) A-UF8 Upper Forest 8 Vol H2 10 15.0 30.0 25.0 268 550 22 100 1.060 247.0 8.0 19.8 - -
3) A-LF8 Lower Forest 8 Vol H2 10 50.0 30.0 25.0 356 560 22 100 1.080 808.1 6.0 48.5 - -
4) A-CR5 Cruse 5 Vol H2 20 15.0 30.0 25.0 476 570 24 100 1.120 467.6 7.0 32.7 - -
6) A-MCR3 Middle Cruse 3 Vol H2 20 20.0 30.0 25.0 818 570 24 100 1.120 623.4 9.0 56.1 - -
CO-362 Sidetrack Commingled H2 2,516.6 7.7 194.1 - 194.1
QU-080 Sidetrack
2) D-TC Top Cruse Vol H2 15 8.0 30.0 25.0 715 560 24 100 1.120 187.0 7.0 13.1 - -
3) D-CR2 Cruse 2 Vol H2 20 45.0 30.0 25.0 600 560 24 100 1.120 1,402.7 5.0 70.1 - -
4) D-CR5 Cruse 5 Vol H2 20 20.0 30.0 25.0 700 570 24 100 1.120 623.4 6.0 37.4 - -
5) D-MCR Middle Cruse Vol H2 20 30.0 30.0 25.0 1,000 570 24 100 1.120 935.1 7.0 65.5 - -
QU-080 Sidetrack Commingled H2 3,148.2 5.9 186.1 - 186.1
QU-119 Sidetrack
1) MC Middle Cruse Vol H2 20 23.0 30.0 25.0 1,000 - 24 100 1.120 716.9 7.0 50.2 - -
2) CR7 Cruse 7 Vol H2 20 17.0 30.0 25.0 800 - 24 100 1.120 529.9 5.0 26.5 - -
QU-119 Sidetrack Commingled H2 1,246.8 6.2 76.7 - 76.7
QU-428 Sidetrack
1) P-CR4 Cruse 4 Vol H2 20 25.0 30.0 40.0 1,620 - 24 200 1.120 623.4 15.0 93.5 - -
2) P-CR5 Cruse 5 Vol H2 10 67.0 26.0 40.0 1,230 - 24 100 1.120 724.0 5.0 36.2 - -
QU-428 Sidetrack Commingled H2 1,347.4 9.6 129.7 - 129.7
Total: Total Proved Plus Probable 74,282.8 69,414.1 4,868.7
The reserves calculated above may not match the economic forecasts due to economic limit considerations.
Glossary
A: Proved Producing
B1: Proved Developed Nonproducing
B2: Proved Undeveloped
G: Proved Plus Probable Producing
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H1: Proved Plus Probable Developed Nonproducing
H2: Proved Plus Probable Undeveloped
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Table 2.2
Company: Touchstone Exploration Effective Date: August 31, 2010
Property: Coora Block
Oil Decline Parameters
Analysis Data
Original Cum Cum Remaining
Initial Initial Final Reserve Recoverable Production Production Reserves
Res. Decline Analysis Effective Rate Rate Decline Life Reserve @ Analysis 2010-09-01 2010-08-31
Resource Entity Zone Method Class Type Date Decline bbl/d bbl/d Exponent yrs Mbbl Mbbl Mbbl Mbbl
Proved Producing
Blocks 1 and 2
1) Coora Producing UMLE to Lower Cruse Decline A OR 2010-09-01 8.76 225.00 35.00 0.40 29.6 70,400.0 69,414.1 69,414.1 985.9
Total: Proved Producing 225.00 70,400.0 69,414.1 69,414.1 985.9
Proved Developed Nonproducing
Blocks 1 and 2
2) Recompletions/Workovers
2011-Q3 UMLE to Lower Cruse Decline B1 OR 2010-09-01 20.52 155.00 9.00 0.20 16.3 270.0 - - 270.0
2012-Q3 UMLE to Lower Cruse Decline B1 OR 2010-09-01 20.52 155.00 9.00 0.20 16.3 270.0 - - 270.0
2013-Q3 UMLE to Lower Cruse Decline B1 OR 2010-09-01 20.52 155.00 9.00 0.20 16.3 270.0 - - 270.0
2014-Q3 UMLE to Lower Cruse Decline B1 OR 2010-09-01 20.00 115.00 9.00 0.20 14.6 200.0 - - 200.0
Total: Proved Developed Nonproducing 580.00 1,010.0 0.0 0.0 1,010.0
Proved Undeveloped
Blocks 1 and 2
3) Replacement Wells
Location F Commingled B2 OR 2010-09-01 - 80.00 5.00 0.40 - 183.9 - - 183.9
4) Sidetrack Wells
CO-362 Sidetrack Commingled B2 OR 2010-09-01 - 50.00 5.00 0.40 - 151.9 - - 151.9
Total: Proved Undeveloped 130.00 335.8 0.0 0.0 335.8
Total Proved
Blocks 1 and 2
1) Coora Producing UMLE to Lower Cruse Decline A OR 2010-09-01 8.76 225.00 35.00 0.40 29.6 70,400.0 69,414.1 69,414.1 985.9
2) Recompletions/Workovers
2011-Q3 UMLE to Lower Cruse Decline B1 OR 2010-09-01 20.52 155.00 9.00 0.20 16.3 270.0 - - 270.0
2012-Q3 UMLE to Lower Cruse Decline B1 OR 2010-09-01 20.52 155.00 9.00 0.20 16.3 270.0 - - 270.0
2013-Q3 UMLE to Lower Cruse Decline B1 OR 2010-09-01 20.52 155.00 9.00 0.20 16.3 270.0 - - 270.0
2014-Q3 UMLE to Lower Cruse Decline B1 OR 2010-09-01 20.00 115.00 9.00 0.20 14.6 200.0 - - 200.0
3) Replacement Wells
Location F Commingled B2 OR 2010-09-01 - 80.00 5.00 0.40 - 183.9 - - 183.9
4) Sidetrack Wells
CO-362 Sidetrack Commingled B2 OR 2010-09-01 - 50.00 5.00 0.40 - 151.9 - - 151.9
Total: Total Proved 935.00 71,745.8 69,414.1 69,414.1 2,331.7
Total Probable
Blocks 1 and 2
2) Recompletions/Workovers
2011-Q3 UMLE to Lower Cruse Decline B1 OR 2010-09-01 -20.52 -155.00 -9.00 -0.20 -16.3 -270.0 - - -270.0
2011-Q3 UMLE to Lower Cruse Decline H1 OR 2010-09-01 20.01 235.00 9.00 0.20 20.2 435.0 - - 435.0
2012-Q3 UMLE to Lower Cruse Decline B1 OR 2010-09-01 -20.52 -155.00 -9.00 -0.20 -16.3 -270.0 - - -270.0
2012-Q3 UMLE to Lower Cruse Decline H1 OR 2010-09-01 20.01 235.00 9.00 0.20 20.2 435.0 - - 435.0
2013-Q3 UMLE to Lower Cruse Decline B1 OR 2010-09-01 -20.52 -155.00 -9.00 -0.20 -16.3 -270.0 - - -270.0
2013-Q3 UMLE to Lower Cruse Decline H1 OR 2010-09-01 20.01 235.00 9.00 0.20 20.2 435.0 - - 435.0
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Oil Decline Parameters
Analysis Data
Original Cum Cum Remaining
Initial Initial Final Reserve Recoverable Production Production Reserves
Res. Decline Analysis Effective Rate Rate Decline Life Reserve @ Analysis 2010-09-01 2010-08-31
Resource Entity Zone Method Class Type Date Decline bbl/d bbl/d Exponent yrs Mbbl Mbbl Mbbl Mbbl
Total Probable (Cont.)
Blocks 1 and 2 (Cont.)
2) Recompletions/Workovers (Cont.)
2014-Q3 UMLE to Lower Cruse Decline B1 OR 2010-09-01 -20.00 -115.00 -9.00 -0.20 -14.6 -200.0 - - -200.0
2014-Q3 UMLE to Lower Cruse Decline H1 OR 2010-09-01 20.01 235.00 9.00 0.20 20.2 435.0 - - 435.0
2015-Q3 UMLE to Lower Cruse Decline H1 OR 2010-09-01 19.58 165.00 9.00 0.20 17.7 305.0 - - 305.0
2016-Q3 UMLE to Lower Cruse Decline H1 OR 2010-09-01 19.58 165.00 9.00 0.20 17.7 305.0 - - 305.0
3) Replacement Wells
Location G Commingled H2 OR 2010-09-01 - 50.00 5.00 0.40 - 102.5 - - 102.5
Location H Commingled H2 OR 2010-09-01 - 40.00 5.00 0.40 - 135.1 - - 135.1
Location L Commingled H2 OR 2010-09-01 - 40.00 5.00 0.40 - 136.4 - - 136.4
4) Sidetrack Wells
CO-180 Sidetrack Commingled H2 OR 2010-09-01 - 80.00 5.00 0.40 - 141.2 - - 141.2
QU-080 Sidetrack Commingled H2 OR 2010-09-01 - 80.00 5.00 0.40 - 186.1 - - 186.1
QU-119 Sidetrack Commingled H2 OR 2010-09-01 - 40.00 5.00 0.40 - 76.7 - - 76.7
QU-428 Sidetrack Commingled H2 OR 2010-09-01 - 90.00 5.00 0.40 - 129.7 - - 129.7
Total: Total Probable 1,110.00 2,247.7 0.0 0.0 2,247.7
Total Proved Plus Probable
Blocks 1 and 2
1) Coora Producing UMLE to Lower Cruse Decline G OR 2010-09-01 7.42 225.00 35.00 0.40 35.3 70,590.0 69,414.1 69,414.1 1,175.9
2) Recompletions/Workovers
2011-Q3 UMLE to Lower Cruse Decline H1 OR 2010-09-01 20.01 235.00 9.00 0.20 20.2 435.0 - - 435.0
2012-Q3 UMLE to Lower Cruse Decline H1 OR 2010-09-01 20.01 235.00 9.00 0.20 20.2 435.0 - - 435.0
2013-Q3 UMLE to Lower Cruse Decline H1 OR 2010-09-01 20.01 235.00 9.00 0.20 20.2 435.0 - - 435.0
2014-Q3 UMLE to Lower Cruse Decline H1 OR 2010-09-01 20.01 235.00 9.00 0.20 20.2 435.0 - - 435.0
2015-Q3 UMLE to Lower Cruse Decline H1 OR 2010-09-01 19.58 165.00 9.00 0.20 17.7 305.0 - - 305.0
2016-Q3 UMLE to Lower Cruse Decline H1 OR 2010-09-01 19.58 165.00 9.00 0.20 17.7 305.0 - - 305.0
3) Replacement Wells
Location F Commingled H2 OR 2010-09-01 - 100.00 5.00 0.40 - 240.9 - - 240.9
Location G Commingled H2 OR 2010-09-01 - 50.00 5.00 0.40 - 102.5 - - 102.5
Location H Commingled H2 OR 2010-09-01 - 40.00 5.00 0.40 - 135.1 - - 135.1
Location L Commingled H2 OR 2010-09-01 - 40.00 5.00 0.40 - 136.4 - - 136.4
4) Sidetrack Wells
CO-180 Sidetrack Commingled H2 OR 2010-09-01 - 80.00 5.00 0.40 - 141.2 - - 141.2
CO-362 Sidetrack Commingled H2 OR 2010-09-01 - 60.00 5.00 0.40 - 194.1 - - 194.1
QU-080 Sidetrack Commingled H2 OR 2010-09-01 - 80.00 5.00 0.40 - 186.1 - - 186.1
QU-119 Sidetrack Commingled H2 OR 2010-09-01 - 40.00 5.00 0.40 - 76.7 - - 76.7
QU-428 Sidetrack Commingled H2 OR 2010-09-01 - 90.00 5.00 0.40 - 129.7 - - 129.7
Total: Total Proved Plus Probable 2,075.00 74,282.8 69,414.1 69,414.1 4,868.7
The reserves calculated above may not match the economic forecasts due to economic limit considerations.
Glossary
A: Proved Producing
B1: Proved Developed Nonproducing
B2: Proved Undeveloped
G: Proved Plus Probable Producing
H1: Proved Plus Probable Developed Nonproducing
H2: Proved Plus Probable Undeveloped
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Table 3
Company: Touchstone Exploration Reserve Class: Various
Property: Coora Block Development Class: Classifications
Pricing: GLJ (2010-07)
Effective Date: August 31, 2010
Gross Lease Daily Oil Production
Year (bbl/d) Totals (Mbbl)
Entity Description
Reserve
Class 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Subtotal Remainder Total
Proved Producing
Coora
1) Current Production.
1) Coora Producing A 222 208 191 175 161 149 138 127 118 110 103 96 603 383 986
Total: 1) Current Production. 222 208 191 175 161 149 138 127 118 110 103 96 603 383 986
Total: Coora 222 208 191 175 161 149 138 127 118 110 103 96 603 383 986
Total: Proved Producing 222 208 191 175 161 149 138 127 118 110 103 96 603 383 986
Proved Developed Nonproducing
Coora
1) Current Production.
1) Coora Producing 0 0 0 0 0 0 0 0 0 0 0 0 0 -213 -213
Total: 1) Current Production. 0 0 0 0 0 0 0 0 0 0 0 0 0 -213 -213
2) Recompletions/Workovers
2011-Q3 B1 0 48 104 78 66 58 51 44 39 35 31 27 212 41 253
2012-Q3 B1 0 0 69 97 75 65 57 50 44 38 34 30 204 45 249
2013-Q3 B1 0 0 0 69 97 76 65 57 50 44 38 34 193 50 243
2014-Q3 B1 0 0 0 0 51 72 56 49 43 38 33 30 136 44 180
Total: 2) Recompletions/Workovers 0 48 173 243 290 270 229 199 175 154 137 121 744 181 925
Total: Coora 0 48 173 243 290 270 229 199 175 154 137 121 744 -32 712
Total: Proved Developed Nonproducing 0 48 173 243 290 270 229 199 175 154 137 121 744 -32 712
Proved Undeveloped
Coora
1) Current Production.
1) Coora Producing 0 0 0 0 0 0 0 0 0 0 0 0 0 85 85
Total: 1) Current Production. 0 0 0 0 0 0 0 0 0 0 0 0 0 85 85
2) Recompletions/Workovers
2011-Q3 0 0 0 0 0 0 0 0 0 0 0 0 0 16 16
2012-Q3 0 0 0 0 0 0 0 0 0 0 0 0 0 18 18
2013-Q3 0 0 0 0 0 0 0 0 0 0 0 0 0 19 19
2014-Q3 0 0 0 0 0 0 0 0 0 0 0 0 0 17 17
Total: 2) Recompletions/Workovers 0 0 0 0 0 0 0 0 0 0 0 0 0 71 71
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Table 3 Page 2
Gross Lease Daily Oil Production
Year (bbl/d) Totals (Mbbl)
Entity Description
Reserve
Class 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Subtotal Remainder Total
Proved Undeveloped (Cont.)
Coora (Cont.)
3) Replacement Wells
Location F B2 0 38 65 54 45 38 33 28 25 22 19 17 140 37 177
Total: 3) Replacement Wells 0 38 65 54 45 38 33 28 25 22 19 17 140 37 177
4) Sidetrack Wells
CO-362 Sidetrack B2 0 24 43 38 33 29 26 23 21 19 17 15 105 37 142
Total: 4) Sidetrack Wells 0 24 43 38 33 29 26 23 21 19 17 15 105 37 142
Total: Coora 0 63 109 92 78 67 59 51 45 40 36 32 246 229 475
Total: Proved Undeveloped 0 63 109 92 78 67 59 51 45 40 36 32 246 229 475
Total Proved
Coora
1) Current Production.
1) Coora Producing C 222 208 191 175 161 149 138 127 118 110 103 96 603 255 858
Total: 1) Current Production. 222 208 191 175 161 149 138 127 118 110 103 96 603 255 858
2) Recompletions/Workovers
2011-Q3 C 0 48 104 78 66 58 51 44 39 35 31 27 212 57 269
2012-Q3 C 0 0 69 97 75 65 57 50 44 38 34 30 204 63 267
2013-Q3 C 0 0 0 69 97 76 65 57 50 44 38 34 193 70 263
2014-Q3 C 0 0 0 0 51 72 56 49 43 38 33 30 136 62 197
Total: 2) Recompletions/Workovers 0 48 173 243 290 270 229 199 175 154 137 121 744 252 996
3) Replacement Wells
Location F B2 0 38 65 54 45 38 33 28 25 22 19 17 140 37 177
Total: 3) Replacement Wells 0 38 65 54 45 38 33 28 25 22 19 17 140 37 177
4) Sidetrack Wells
CO-362 Sidetrack B2 0 24 43 38 33 29 26 23 21 19 17 15 105 37 142
Total: 4) Sidetrack Wells 0 24 43 38 33 29 26 23 21 19 17 15 105 37 142
Total: Coora 222 319 472 510 529 487 426 378 339 305 276 249 1,593 580 2,173
Total: Total Proved 222 319 472 510 529 487 426 378 339 305 276 249 1,593 580 2,173
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Table 3 Page 3
Gross Lease Daily Oil Production
Year (bbl/d) Totals (Mbbl)
Entity Description
Reserve
Class 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Subtotal Remainder Total
Total Probable
Coora
1) Current Production.
1) Coora Producing 1 3 5 7 8 10 10 11 12 12 12 12 37 212 249
Total: 1) Current Production. 1 3 5 7 8 10 10 11 12 12 12 12 37 212 249
2) Recompletions/Workovers
2011-Q3 0 24 53 40 34 30 27 24 21 19 17 15 111 55 166
2012-Q3 0 0 36 50 39 34 30 26 23 21 18 16 108 61 168
2013-Q3 0 0 0 35 50 39 34 30 26 23 21 18 101 72 172
2014-Q3 0 0 0 0 53 75 58 50 43 38 33 29 139 99 238
2015-Q3 I 0 0 0 0 0 73 104 81 70 62 55 48 180 125 305
2016-Q3 I 0 0 0 0 0 0 73 103 80 69 61 54 161 144 305
Total: 2) Recompletions/Workovers 0 24 89 126 177 251 326 313 264 232 205 181 799 555 1,354
3) Replacement Wells
Location F 0 10 17 14 12 10 9 8 7 6 5 5 37 27 64
Location G H2 0 0 24 40 33 28 23 20 17 15 13 11 82 20 102
Location H H2 0 0 0 20 35 31 28 25 23 20 19 17 80 56 135
Location L H2 0 0 0 0 20 35 31 28 25 23 21 19 74 63 136
Total: 3) Replacement Wells 0 10 40 74 100 105 92 81 72 64 58 52 272 165 438
4) Sidetrack Wells
CO-180 Sidetrack H2 0 0 38 62 48 39 32 26 22 19 16 14 115 26 141
CO-362 Sidetrack 0 5 9 8 7 6 6 5 5 4 4 4 23 29 52
QU-080 Sidetrack H2 0 0 38 65 54 45 39 33 29 25 22 19 135 51 186
QU-119 Sidetrack H2 0 0 0 19 32 26 22 18 16 14 12 10 62 15 77
QU-428 Sidetrack H2 0 42 65 49 38 30 24 20 16 14 12 10 117 13 130
Total: 4) Sidetrack Wells 0 47 150 203 180 147 122 103 88 76 66 57 452 134 586
Total: Coora 1 83 285 409 465 512 550 508 435 383 341 303 1,560 1,066 2,626
Total: Total Probable 1 83 285 409 465 512 550 508 435 383 341 303 1,560 1,066 2,626
Total Proved Plus Probable
Coora
1) Current Production.
1) Coora Producing I 223 211 196 182 169 158 148 139 130 122 115 108 640 466 1,107
Total: 1) Current Production. 223 211 196 182 169 158 148 139 130 122 115 108 640 466 1,107
2) Recompletions/Workovers
2011-Q3 I 0 72 157 118 101 88 78 68 60 53 47 42 323 112 435
2012-Q3 I 0 0 104 147 115 99 87 76 67 59 52 46 311 124 435
2013-Q3 I 0 0 0 104 147 114 99 86 76 67 59 52 294 141 435
2014-Q3 I 0 0 0 0 104 147 115 99 86 76 67 59 274 161 435
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Table 3 Page 4
Gross Lease Daily Oil Production
Year (bbl/d) Totals (Mbbl)
Entity Description
Reserve
Class 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Subtotal Remainder Total
Total Proved Plus Probable (Cont.)
Coora (Cont.)
2) Recompletions/Workovers (Cont.)
2015-Q3 I 0 0 0 0 0 73 104 81 70 62 55 48 180 125 305
2016-Q3 I 0 0 0 0 0 0 73 103 80 69 61 54 161 144 305
Total: 2) Recompletions/Workovers 0 72 261 369 466 521 555 513 439 386 342 302 1,543 807 2,350
3) Replacement Wells
Location F H2 0 48 82 68 57 48 42 36 31 28 24 22 177 64 241
Location G H2 0 0 24 40 33 28 23 20 17 15 13 11 82 20 102
Location H H2 0 0 0 20 35 31 28 25 23 20 19 17 80 56 135
Location L H2 0 0 0 0 20 35 31 28 25 23 21 19 74 63 136
Total: 3) Replacement Wells 0 48 106 128 145 143 125 109 96 86 77 69 413 202 615
4) Sidetrack Wells
CO-180 Sidetrack H2 0 0 38 62 48 39 32 26 22 19 16 14 115 26 141
CO-362 Sidetrack H2 0 29 52 46 40 36 32 28 26 23 21 19 128 66 194
QU-080 Sidetrack H2 0 0 38 65 54 45 39 33 29 25 22 19 135 51 186
QU-119 Sidetrack H2 0 0 0 19 32 26 22 18 16 14 12 10 62 15 77
QU-428 Sidetrack H2 0 42 65 49 38 30 24 20 16 14 12 10 117 13 130
Total: 4) Sidetrack Wells 0 71 194 240 213 176 148 126 109 94 83 73 557 171 728
Total: Coora 223 402 757 919 994 999 976 886 774 688 617 552 3,153 1,646 4,799
Total: Total Proved Plus Probable 223 402 757 919 994 999 976 886 774 688 617 552 3,153 1,646 4,799
1110792 Class (A,B1,B2,C,F,I), GLJ (2010-07), glo January 27, 2011 14:50:52
GLJ
Petroleum Consultants
Page: 71 of 144

Table 3.1
Company: Touchstone Exploration Reserve Class: Various
Property: Coora Block Development Class: Classifications
Pricing: GLJ (2010-07)
Effective Date: August 31, 2010
Company Daily Oil Production
Year (bbl/d) Totals (Mbbl)
Entity Description
Reserve
Class 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Subtotal Remainder Total
Proved Producing
Coora
1) Current Production.
1) Coora Producing A 222 208 191 175 161 149 138 127 118 110 103 96 603 383 986
Total: 1) Current Production. 222 208 191 175 161 149 138 127 118 110 103 96 603 383 986
Total: Coora 222 208 191 175 161 149 138 127 118 110 103 96 603 383 986
Total: Proved Producing 222 208 191 175 161 149 138 127 118 110 103 96 603 383 986
Proved Developed Nonproducing
Coora
1) Current Production.
1) Coora Producing 0 0 0 0 0 0 0 0 0 0 0 0 0 -213 -213
Total: 1) Current Production. 0 0 0 0 0 0 0 0 0 0 0 0 0 -213 -213
2) Recompletions/Workovers
2011-Q3 B1 0 48 104 78 66 58 51 44 39 35 31 27 212 41 253
2012-Q3 B1 0 0 69 97 75 65 57 50 44 38 34 30 204 45 249
2013-Q3 B1 0 0 0 69 97 76 65 57 50 44 38 34 193 50 243
2014-Q3 B1 0 0 0 0 51 72 56 49 43 38 33 30 136 44 180
Total: 2) Recompletions/Workovers 0 48 173 243 290 270 229 199 175 154 137 121 744 181 925
Total: Coora 0 48 173 243 290 270 229 199 175 154 137 121 744 -32 712
Total: Proved Developed Nonproducing 0 48 173 243 290 270 229 199 175 154 137 121 744 -32 712
Proved Undeveloped
Coora
1) Current Production.
1) Coora Producing 0 0 0 0 0 0 0 0 0 0 0 0 0 85 85
Total: 1) Current Production. 0 0 0 0 0 0 0 0 0 0 0 0 0 85 85
2) Recompletions/Workovers
2011-Q3 0 0 0 0 0 0 0 0 0 0 0 0 0 16 16
2012-Q3 0 0 0 0 0 0 0 0 0 0 0 0 0 18 18
2013-Q3 0 0 0 0 0 0 0 0 0 0 0 0 0 19 19
2014-Q3 0 0 0 0 0 0 0 0 0 0 0 0 0 17 17
Total: 2) Recompletions/Workovers 0 0 0 0 0 0 0 0 0 0 0 0 0 71 71
1110792 Class (A,B1,B2,C,F,I), GLJ (2010-07), oil January 27, 2011 14:50:55
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Table 3.1 Page 2
Company Daily Oil Production
Year (bbl/d) Totals (Mbbl)
Entity Description
Reserve
Class 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Subtotal Remainder Total
Proved Undeveloped (Cont.)
Coora (Cont.)
3) Replacement Wells
Location F B2 0 38 65 54 45 38 33 28 25 22 19 17 140 37 177
Total: 3) Replacement Wells 0 38 65 54 45 38 33 28 25 22 19 17 140 37 177
4) Sidetrack Wells
CO-362 Sidetrack B2 0 24 43 38 33 29 26 23 21 19 17 15 105 37 142
Total: 4) Sidetrack Wells 0 24 43 38 33 29 26 23 21 19 17 15 105 37 142
Total: Coora 0 63 109 92 78 67 59 51 45 40 36 32 246 229 475
Total: Proved Undeveloped 0 63 109 92 78 67 59 51 45 40 36 32 246 229 475
Total Proved
Coora
1) Current Production.
1) Coora Producing C 222 208 191 175 161 149 138 127 118 110 103 96 603 255 858
Total: 1) Current Production. 222 208 191 175 161 149 138 127 118 110 103 96 603 255 858
2) Recompletions/Workovers
2011-Q3 C 0 48 104 78 66 58 51 44 39 35 31 27 212 57 269
2012-Q3 C 0 0 69 97 75 65 57 50 44 38 34 30 204 63 267
2013-Q3 C 0 0 0 69 97 76 65 57 50 44 38 34 193 70 263
2014-Q3 C 0 0 0 0 51 72 56 49 43 38 33 30 136 62 197
Total: 2) Recompletions/Workovers 0 48 173 243 290 270 229 199 175 154 137 121 744 252 996
3) Replacement Wells
Location F B2 0 38 65 54 45 38 33 28 25 22 19 17 140 37 177
Total: 3) Replacement Wells 0 38 65 54 45 38 33 28 25 22 19 17 140 37 177
4) Sidetrack Wells
CO-362 Sidetrack B2 0 24 43 38 33 29 26 23 21 19 17 15 105 37 142
Total: 4) Sidetrack Wells 0 24 43 38 33 29 26 23 21 19 17 15 105 37 142
Total: Coora 222 319 472 510 529 487 426 378 339 305 276 249 1,593 580 2,173
Total: Total Proved 222 319 472 510 529 487 426 378 339 305 276 249 1,593 580 2,173
1110792 Class (A,B1,B2,C,F,I), GLJ (2010-07), oil January 27, 2011 14:50:55
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Petroleum Consultants
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Table 3.1 Page 3
Company Daily Oil Production
Year (bbl/d) Totals (Mbbl)
Entity Description
Reserve
Class 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Subtotal Remainder Total
Total Probable
Coora
1) Current Production.
1) Coora Producing 1 3 5 7 8 10 10 11 12 12 12 12 37 212 249
Total: 1) Current Production. 1 3 5 7 8 10 10 11 12 12 12 12 37 212 249
2) Recompletions/Workovers
2011-Q3 0 24 53 40 34 30 27 24 21 19 17 15 111 55 166
2012-Q3 0 0 36 50 39 34 30 26 23 21 18 16 108 61 168
2013-Q3 0 0 0 35 50 39 34 30 26 23 21 18 101 72 172
2014-Q3 0 0 0 0 53 75 58 50 43 38 33 29 139 99 238
2015-Q3 I 0 0 0 0 0 73 104 81 70 62 55 48 180 125 305
2016-Q3 I 0 0 0 0 0 0 73 103 80 69 61 54 161 144 305
Total: 2) Recompletions/Workovers 0 24 89 126 177 251 326 313 264 232 205 181 799 555 1,354
3) Replacement Wells
Location F 0 10 17 14 12 10 9 8 7 6 5 5 37 27 64
Location G H2 0 0 24 40 33 28 23 20 17 15 13 11 82 20 102
Location H H2 0 0 0 20 35 31 28 25 23 20 19 17 80 56 135
Location L H2 0 0 0 0 20 35 31 28 25 23 21 19 74 63 136
Total: 3) Replacement Wells 0 10 40 74 100 105 92 81 72 64 58 52 272 165 438
4) Sidetrack Wells
CO-180 Sidetrack H2 0 0 38 62 48 39 32 26 22 19 16 14 115 26 141
CO-362 Sidetrack 0 5 9 8 7 6 6 5 5 4 4 4 23 29 52
QU-080 Sidetrack H2 0 0 38 65 54 45 39 33 29 25 22 19 135 51 186
QU-119 Sidetrack H2 0 0 0 19 32 26 22 18 16 14 12 10 62 15 77
QU-428 Sidetrack H2 0 42 65 49 38 30 24 20 16 14 12 10 117 13 130
Total: 4) Sidetrack Wells 0 47 150 203 180 147 122 103 88 76 66 57 452 134 586
Total: Coora 1 83 285 409 465 512 550 508 435 383 341 303 1,560 1,066 2,626
Total: Total Probable 1 83 285 409 465 512 550 508 435 383 341 303 1,560 1,066 2,626
Total Proved Plus Probable
Coora
1) Current Production.
1) Coora Producing I 223 211 196 182 169 158 148 139 130 122 115 108 640 466 1,107
Total: 1) Current Production. 223 211 196 182 169 158 148 139 130 122 115 108 640 466 1,107
2) Recompletions/Workovers
2011-Q3 I 0 72 157 118 101 88 78 68 60 53 47 42 323 112 435
2012-Q3 I 0 0 104 147 115 99 87 76 67 59 52 46 311 124 435
2013-Q3 I 0 0 0 104 147 114 99 86 76 67 59 52 294 141 435
2014-Q3 I 0 0 0 0 104 147 115 99 86 76 67 59 274 161 435
1110792 Class (A,B1,B2,C,F,I), GLJ (2010-07), oil January 27, 2011 14:50:55
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Table 3.1 Page 4
Company Daily Oil Production
Year (bbl/d) Totals (Mbbl)
Entity Description
Reserve
Class 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Subtotal Remainder Total
Total Proved Plus Probable (Cont.)
Coora (Cont.)
2) Recompletions/Workovers (Cont.)
2015-Q3 I 0 0 0 0 0 73 104 81 70 62 55 48 180 125 305
2016-Q3 I 0 0 0 0 0 0 73 103 80 69 61 54 161 144 305
Total: 2) Recompletions/Workovers 0 72 261 369 466 521 555 513 439 386 342 302 1,543 807 2,350
3) Replacement Wells
Location F H2 0 48 82 68 57 48 42 36 31 28 24 22 177 64 241
Location G H2 0 0 24 40 33 28 23 20 17 15 13 11 82 20 102
Location H H2 0 0 0 20 35 31 28 25 23 20 19 17 80 56 135
Location L H2 0 0 0 0 20 35 31 28 25 23 21 19 74 63 136
Total: 3) Replacement Wells 0 48 106 128 145 143 125 109 96 86 77 69 413 202 615
4) Sidetrack Wells
CO-180 Sidetrack H2 0 0 38 62 48 39 32 26 22 19 16 14 115 26 141
CO-362 Sidetrack H2 0 29 52 46 40 36 32 28 26 23 21 19 128 66 194
QU-080 Sidetrack H2 0 0 38 65 54 45 39 33 29 25 22 19 135 51 186
QU-119 Sidetrack H2 0 0 0 19 32 26 22 18 16 14 12 10 62 15 77
QU-428 Sidetrack H2 0 42 65 49 38 30 24 20 16 14 12 10 117 13 130
Total: 4) Sidetrack Wells 0 71 194 240 213 176 148 126 109 94 83 73 557 171 728
Total: Coora 223 402 757 919 994 999 976 886 774 688 617 552 3,153 1,646 4,799
Total: Total Proved Plus Probable 223 402 757 919 994 999 976 886 774 688 617 552 3,153 1,646 4,799
1110792 Class (A,B1,B2,C,F,I), GLJ (2010-07), oil January 27, 2011 14:50:55
GLJ
Petroleum Consultants
Page: 75 of 144

Table 4
Company: Touchstone Exploration Effective Date: August 31, 2010
Property: Coora Block
Economic Parameters
A) Price Forecasts and By-Product Data
GLJ (2010-07)
Oil Reference: Light Crude to Cushing, in $US, Quality 40 degree API, Sul. 0.3%
Gas/Oil Ratio: 0 scf/bbl
Price Adjustment:
Oil:
B) Operating Costs (2010 Dollars)
All variable costs are $/product (sales).
-10.40 (2010) -10.79 (2011) -11.18 (2012) -11.57 (2013) -11.96 (2014) -12.20 (2015) -12.44 (2016) -12.69 (2017) -12.95
(2018) -13.21 (2019) -13.47 (2020) -13.74 (2021) -14.01 (2022) -14.29 (2023) -14.58 (2024) -14.87 (2025) -15.17 (2026)
-15.47 (2027) -15.78 (2028) -16.10 (2029) -16.42 (2030) -16.75 (2031) -17.08 (2032) -17.42 (2033) -17.77 (2034) -18.13
(2035) -18.49 (2036) -18.86 (2037) -19.24 (2038) -19.62 (2039) -20.01 (2040) -20.41 (2041) -20.82 (2042) -21.24 (2043)
-21.66 (2044) -22.10 (2045) -22.54 (2046) -22.99 (2047) -23.45 (2048) -23.92 (2049) -24.40 (2050) -24.89 (2051) -25.38
(2052) -25.89 (2053) -26.41 (2054) -26.94 (2055) -27.48 (2056) -28.03 (2057) -28.59 (2058) -29.16 (2059) $/bbl
Major Stream
Costs
Variable
Name Zone RC Product $/Product
Coora Block
Coora
1) Current Production.
1) Coora Producing UMLE to Lower Cruse C Oil [1]
1) Coora Producing UMLE to Lower Cruse A Oil [2]
1) Coora Producing UMLE to Lower Cruse C1 Oil [3]
1) Coora Producing UMLE to Lower Cruse G Oil [4]
1) Coora Producing UMLE to Lower Cruse I1 Oil [5]
1) Coora Producing UMLE to Lower Cruse I Oil [6]
2) Recompletions/Workovers
2011-Q3 UMLE to Lower Cruse B1 Oil [3]
2011-Q3 UMLE to Lower Cruse H1 Oil [5]
2011-Q3 UMLE to Lower Cruse I Oil [6]
2011-Q3 UMLE to Lower Cruse C Oil [1]
2012-Q3 UMLE to Lower Cruse B1 Oil [3]
2012-Q3 UMLE to Lower Cruse H1 Oil [5]
2012-Q3 UMLE to Lower Cruse I Oil [6]
2012-Q3 UMLE to Lower Cruse C Oil [1]
2013-Q3 UMLE to Lower Cruse B1 Oil [3]
2013-Q3 UMLE to Lower Cruse H1 Oil [5]
2013-Q3 UMLE to Lower Cruse I Oil [6]
2013-Q3 UMLE to Lower Cruse C Oil [1]
2014-Q3 UMLE to Lower Cruse B1 Oil [3]
2014-Q3 UMLE to Lower Cruse H1 Oil [5]
2014-Q3 UMLE to Lower Cruse I Oil [6]
2014-Q3 UMLE to Lower Cruse C Oil [1]
2015-Q3 UMLE to Lower Cruse I Oil [6]
2015-Q3 UMLE to Lower Cruse H1 Oil [5]
2016-Q3 UMLE to Lower Cruse I Oil [6]
2016-Q3 UMLE to Lower Cruse H1 Oil [5]
3) Replacement Wells
Location F B2 Oil [1]
Location F H2 Oil [6]
Location G Oil [6]
Location H Oil [6]
Location L Oil [6]
4) Sidetrack Wells
CO-180 Sidetrack Oil [6]
CO-362 Sidetrack B2 Oil [1]
CO-362 Sidetrack H2 Oil [6]
QU-080 Sidetrack Oil [6]
QU-119 Sidetrack Oil [6]
QU-428 Sidetrack Oil [6]
Glossary
Oil product units are bbl
Notes
1.
2.
23.89 (2010) 19.09 (2011) 14.78 (2012) 14.46 (2013) 14.33 (2014) 15.31 (2015) 16.17 (2016) 17.51 (2017) 18.18 (2018) 19.25 (2019) 20.12 (2020) 21.02 (2021)
21.84 (2022) 23.10 (2023) 23.79 (2024) 24.48 (2025) 26.06 (2026) 26.18 (2027) 41.30 (2028) 41.14 (2029) 41.29 (2030) 41.65 (2031) 45.63 (2032) 80.42 (2033)
144.84 (2034) 235.94 (2035)
23.89 (2010) 25.79 (2011) 26.30 (2012) 27.24 (2013) 27.55 (2014) 29.21 (2015) 29.26 (2016) 31.07 (2017) 30.87 (2018) 31.72 (2019) 31.93 (2020) 32.10 (2021)
32.00 (2022) 32.93 (2023) 32.40 (2024) 31.73 (2025) 33.10 (2026) 34.53 (2027)
Page: 76 of 144
1110792 January 27, 2011 15:14:50
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3.
4.
5.
6.
Table 4
Economic Parameters
23.89 (2010) 22.31 (2011) 17.48 (2012) 16.32 (2013) 15.75 (2014) 16.75 (2015) 17.71 (2016) 19.19 (2017) 19.90 (2018) 21.07 (2019) 22.00 (2020) 22.97 (2021)
23.84 (2022) 25.23 (2023) 25.95 (2024) 26.66 (2025) 28.41 (2026) 28.47 (2027) 51.67 (2028) 51.64 (2029) 52.02 (2030) 52.69 (2031) 62.02 (2032) 170.30
(2033-2035)
23.85 (2010) 25.54 (2011) 26.53 (2012) 26.64 (2013) 28.11 (2014) 27.94 (2015) 29.40 (2016) 28.93 (2017) 29.97 (2018) 29.80 (2019) 29.37 (2020) 29.79 (2021)
31.07 (2022) 30.76 (2023) 31.97 (2024) 31.45 (2025) 32.70 (2026) 34.00 (2027) 32.92 (2028) 34.25 (2029) 35.57 (2030) 33.71 (2031) 34.58 (2032) 35.67 (2033)
35.57 (2034) 36.66 (2035) 37.75 (2036) 39.07 (2037) 38.88 (2038) 40.20 (2039) 41.52 (2040) 43.11 (2041) 38.88 (2042) 40.21 (2043) 41.54 (2044) 45.66 (2045)
23.85 (2010) 20.68 (2011) 15.27 (2012) 13.71 (2013) 13.14 (2014) 12.77 (2015) 13.05 (2016) 13.39 (2017) 14.44 (2018) 15.13 (2019) 15.76 (2020) 16.65 (2021)
17.82 (2022) 18.60 (2023) 19.85 (2024) 20.66 (2025) 22.06 (2026) 23.55 (2027) 24.27 (2028) 25.93 (2029) 27.65 (2030) 28.19 (2031) 28.97 (2032) 28.91 (2033)
28.07 (2034) 27.41 (2035) 26.39 (2036) 23.54 (2037) 26.23 (2038) 35.62 (2039) 43.07 (2040) 45.71 (2041) 41.36 (2042) 42.58 (2043) 43.80 (2044) 47.98 (2045)
23.85 (2010) 16.22 (2011) 11.52 (2012) 10.64 (2013) 10.73 (2014) 10.89 (2015) 11.31 (2016) 11.74 (2017) 12.62 (2018) 13.26 (2019) 13.86 (2020) 14.67 (2021)
15.69 (2022) 16.42 (2023) 17.52 (2024) 18.31 (2025) 19.17 (2026) 20.66 (2027) 21.61 (2028) 23.22 (2029) 25.04 (2030) 25.27 (2031) 26.04 (2032) 26.16 (2033)
25.66 (2034) 25.32 (2035) 23.33 (2036) 23.96 (2037) 25.31 (2038) 30.07 (2039) 35.45 (2040) 45.10 (2041) 40.78 (2042) 42.02 (2043) 43.27 (2044) 47.43 (2045)
C) Gas Cost Allowance (2010 Dollars)
Additonal GCA Allowance: 0.00 $/Mcf
D) Abandonment Costs (2010 Dollars)
Facility Costs Well Costs
Name RC M$ M$/Well
Coora Block
Coora
3) Replacement Wells B2,H2 30.0
4) Sidetrack Wells B2,H2 30.0
4) Sidetrack Wells 50.0
E) Capital Costs (2010 Dollars)
Capital Summary (2010 Dollars)
Gross Lease Capital
Expenditures Company Capital
On Development Total Interest
Year Stream Well/Area RC Description Development Total M$ %
Proved Developed Nonproducing
2011 Sep 2011-Q3 B1 Recomplete/Workover 9 Wells 1,575 1,575 1,575 100.00
2012 Jul 2012-Q3 B1 Recomplete/Workover 9 Wells 1,575 1,575 1,575 100.00
2013 Jul 2013-Q3 B1 Recomplete/Workover 9 Wells 1,575 1,575 1,575 100.00
2014 Jul 2014-Q3 B1 Recomplete/Workover 9 Wells 1,575 1,575 1,575 100.00
Total: Proved Developed Nonproducing 6,300 6,300 6,300 100.00
Proved Undeveloped
2011 Jul CO-362 Sidetrack B2 Sidetrack well. 600 600 600 100.00
Jul Location F B2 D&C Replacement Well 750 750 750 100.00
Total: Proved Undeveloped 1,350 1,350 1,350 100.00
Total Proved
2011 Jul CO-362 Sidetrack B2 Sidetrack well. 600 600 600 100.00
Jul Location F B2 D&C Replacement Well 750 750 750 100.00
Sep 2011-Q3 B1 Recomplete/Workover 9 Wells 1,575 1,575 1,575 100.00
2012 Jul 2012-Q3 B1 Recomplete/Workover 9 Wells 1,575 1,575 1,575 100.00
2013 Jul 2013-Q3 B1 Recomplete/Workover 9 Wells 1,575 1,575 1,575 100.00
2014 Jul 2014-Q3 B1 Recomplete/Workover 9 Wells 1,575 1,575 1,575 100.00
Total: Total Proved 7,650 7,650 7,650 100.00
Total Probable
2011 Jul QU-428 Sidetrack H2 Sidetrack well. 360 360 360 100.00
2012 Jul CO-180 Sidetrack H2 Sidetrack well. 420 420 420 100.00
Jul Location G H2 D&C Replacement Well 750 750 750 100.00
Jul QU-080 Sidetrack H2 Sidetrack well. 420 420 420 100.00
2013 Jul Location H H2 D&C Replacement Well 750 750 750 100.00
Jul QU-119 Sidetrack H2 Sidetrack well. 420 420 420 100.00
2014 Jul Location L H2 D&C Replacement Well 750 750 750 100.00
2015 Jul 2015-Q3 H1 Recomplete/Workover 9 Wells 1,575 1,575 1,575 100.00
2016 Jul 2016-Q3 H1 Recomplete/Workover 9 Wells 1,575 1,575 1,575 100.00
Total: Total Probable 7,020 7,020 7,020 100.00
Total Proved Plus Probable
2011 Jul CO-362 Sidetrack H2 Sidetrack well. 600 600 600 100.00
Jul Location F H2 D&C Replacement Well 750 750 750 100.00
Jul QU-428 Sidetrack H2 Sidetrack well. 360 360 360 100.00
Sep 2011-Q3 H1 Recomplete/Workover 9 Wells 1,575 1,575 1,575 100.00
2012 Jul 2012-Q3 H1 Recomplete/Workover 9 Wells 1,575 1,575 1,575 100.00
Jul CO-180 Sidetrack H2 Sidetrack well. 420 420 420 100.00
Jul Location G H2 D&C Replacement Well 750 750 750 100.00
Jul QU-080 Sidetrack H2 Sidetrack well. 420 420 420 100.00
1110792 January 27, 2011 15:14:50
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Page 2
Petroleum Consultants

Table 4
Economic Parameters
Capital Summary (2010 Dollars)
Gross Lease Capital
Expenditures Company Capital
On Development Total Interest
Year Stream Well/Area RC Description Development Total M$ %
Total Proved Plus Probable (Cont.)
2013 Jul 2013-Q3 H1 Recomplete/Workover 9 Wells 1,575 1,575 1,575 100.00
Jul Location H H2 D&C Replacement Well 750 750 750 100.00
Jul QU-119 Sidetrack H2 Sidetrack well. 420 420 420 100.00
2014 Jul 2014-Q3 H1 Recomplete/Workover 9 Wells 1,575 1,575 1,575 100.00
Jul Location L H2 D&C Replacement Well 750 750 750 100.00
2015 Jul 2015-Q3 H1 Recomplete/Workover 9 Wells 1,575 1,575 1,575 100.00
2016 Jul 2016-Q3 H1 Recomplete/Workover 9 Wells 1,575 1,575 1,575 100.00
Total: Total Proved Plus Probable 14,670 14,670 14,670 100.00
1110792 January 27, 2011 15:14:50
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Page 3
Petroleum Consultants

Company: Touchstone Exploration Reserve Class: Proved
Property: Coora Block Development Class: Producing
Pricing: GLJ (2010-07)
Effective Date: August 31, 2010
Economic Forecast
PRODUCTION FORECAST
Light/Medium Oil Production
Company Company
Gross Oil Gross Daily Daily Yearly Net Yearly Price
Year Wells bbl/d bbl/d Mbbl Mbbl $/bbl
2010 60 222 222 27 15 69.60
2011 60 208 208 76 41 72.21
2012 55 191 191 70 38 74.82
2013 52 175 175 64 35 77.43
2014 47 161 161 59 32 80.04
2015 47 149 149 54 29 81.64
2016 42 138 138 50 27 83.28
2017 42 127 127 47 25 84.95
2018 37 118 118 43 23 86.64
2019 35 110 110 40 22 88.37
2020 32 103 103 38 20 90.14
2021 29 96 96 35 19 91.94
Sub. 603 327 80.85
Rem. 383 208 108.62
Tot. 986 534 91.64
REVENUE AND EXPENSE FORECAST
Page: 79 of 144
Revenue Before Burdens
Royalty Burdens Gas Processing Total Net
Working Interest Royalty Company Pre-Processing Allowance Royalty Revenue Operating Expenses
Interest Interest After After
Oil Gas NGL+Sul Total Total Total Crown Other Crown Other Process. Royalty Fixed Variable Total
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 1,881 0 0 1,881 0 1,881 862 0 0 0 862 1,020 0 646 646
2011 5,495 0 0 5,495 0 5,495 2,517 0 0 0 2,517 2,978 0 2,002 2,002
2012 5,223 0 0 5,223 0 5,223 2,392 0 0 0 2,392 2,831 0 1,910 1,910
2013 4,946 0 0 4,946 0 4,946 2,265 0 0 0 2,265 2,681 0 1,846 1,846
2014 4,705 0 0 4,705 0 4,705 2,155 0 0 0 2,155 2,550 0 1,753 1,753
2015 4,428 0 0 4,428 0 4,428 2,028 0 0 0 2,028 2,400 0 1,749 1,749
2016 4,190 0 0 4,190 0 4,190 1,919 0 0 0 1,919 2,271 0 1,658 1,658
2017 3,951 0 0 3,951 0 3,951 1,810 0 0 0 1,810 2,142 0 1,660 1,660
2018 3,745 0 0 3,745 0 3,745 1,715 0 0 0 1,715 2,030 0 1,564 1,564
2019 3,558 0 0 3,558 0 3,558 1,629 0 0 0 1,629 1,928 0 1,526 1,526
2020 3,395 0 0 3,395 0 3,395 1,555 0 0 0 1,555 1,840 0 1,466 1,466
2021 3,228 0 0 3,228 0 3,228 1,478 0 0 0 1,478 1,750 0 1,401 1,401
Sub. 48,745 0 0 48,745 0 48,745 22,325 0 0 0 22,325 26,420 0 19,180 19,180
Rem. 41,602 0 0 41,602 0 41,602 19,054 0 0 0 19,054 22,548 0 19,020 19,020
Tot. 90,347 0 0 90,347 0 90,347 41,379 0 0 0 41,379 48,968 0 38,200 38,200
Disc 38,679 0 0 38,679 0 38,679 17,715 0 0 0 17,715 20,964 0 15,395 15,395
Net Net Capital Investment Before Tax Cash Flow
Mineral Capital NPI Prod'n Other Aband. Oper.
Tax Tax Burden Revenue Income Costs Income Dev. Plant Tang. Total Annual Cum. 10.0% Dcf
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 0 0 0 374 0 0 374 0 0 0 0 374 374 368
2011 0 0 0 977 0 0 977 0 0 0 0 977 1,350 1,270
2012 0 0 0 921 0 0 921 0 0 0 0 921 2,271 2,043
2013 0 0 0 834 0 0 834 0 0 0 0 834 3,106 2,680
2014 0 0 0 797 0 0 797 0 0 0 0 797 3,903 3,233
2015 0 0 0 651 0 0 651 0 0 0 0 651 4,554 3,644
2016 0 0 0 613 0 0 613 0 0 0 0 613 5,167 3,996
2017 0 0 0 482 0 0 482 0 0 0 0 482 5,649 4,247
2018 0 0 0 466 0 0 466 0 0 0 0 466 6,115 4,468
2019 0 0 0 402 0 0 402 0 0 0 0 402 6,517 4,641
2020 0 0 0 374 0 0 374 0 0 0 0 374 6,891 4,788
2021 0 0 0 348 0 0 348 0 0 0 0 348 7,240 4,912
Sub. 0 0 0 7,240 0 0 7,240 0 0 0 0 7,240 7,240 4,912
Rem. 0 0 0 3,528 0 0 3,528 0 0 0 0 3,528 10,768 5,569
Tot. 0 0 0 10,768 0 0 10,768 0 0 0 0 10,768 10,768 5,569
Disc 0 0 0 5,569 0 0 5,569 0 0 0 0 5,569 5,569 5,569
1110792 Proved Producing, GLJ (2010-07), pri January 27, 2011 14:51:07
GLJ
Petroleum Consultants

AFTER TAX ANALYSIS
Tax Pool Balances Incl. Current Year Additions Depreciation & Writeoffs
Oper.
Income CCA COGPE CDE CEE Other CCA COGPE CDE CEE Other Total
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 374 0 0 0 0 0 0 0 0 0 0 0
2011 977 0 0 0 0 0 0 0 0 0 0 0
2012 921 0 0 0 0 0 0 0 0 0 0 0
2013 834 0 0 0 0 0 0 0 0 0 0 0
2014 797 0 0 0 0 0 0 0 0 0 0 0
2015 651 0 0 0 0 0 0 0 0 0 0 0
2016 613 0 0 0 0 0 0 0 0 0 0 0
2017 482 0 0 0 0 0 0 0 0 0 0 0
2018 466 0 0 0 0 0 0 0 0 0 0 0
2019 402 0 0 0 0 0 0 0 0 0 0 0
2020 374 0 0 0 0 0 0 0 0 0 0 0
2021 348 0 0 0 0 0 0 0 0 0 0 0
Sub. 7,240 0 0 0 0 0 0 0 0 0 0 0
Rem. 3,528 0 0 0 0 0 0 0 0 0 0 0
Tot. 10,768 0 0 0 0 0 0 0 0 0 0 0
Disc 5,569 0 0 0 0 0 0 0
Federal Provincial Net Cash Flow Net Cash Flow
ARTD & Income Before Income Tax After Income Tax
Taxable Income Income Investment Tax
Income Tax Tax Credits Payable Annual Cum. 10.0% Dcf Annual Cum. 10.0% Dcf
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 374 187 0 0 187 374 374 368 187 187 184
2011 977 550 0 0 550 977 1,350 1,270 427 613 578
2012 921 526 0 0 526 921 2,271 2,043 395 1,008 909
2013 834 499 0 0 499 834 3,106 2,680 335 1,344 1,165
2014 797 478 0 0 478 797 3,903 3,233 319 1,663 1,387
2015 651 454 0 0 454 651 4,554 3,644 197 1,860 1,511
2016 613 431 0 0 431 613 5,167 3,996 182 2,042 1,616
2017 482 405 0 0 405 482 5,649 4,247 77 2,119 1,656
2018 466 386 0 0 386 466 6,115 4,468 80 2,199 1,694
2019 402 366 0 0 366 402 6,517 4,641 36 2,235 1,709
2020 374 351 0 0 351 374 6,891 4,788 23 2,258 1,718
2021 348 335 0 0 335 348 7,240 4,912 13 2,272 1,723
Sub. 7,240 4,968 0 0 4,968 7,240 7,240 4,912 2,272 2,272 1,723
Rem. 3,528 1,748 0 0 1,748 3,528 10,768 5,569 1,780 4,052 1,924
Tot. 10,768 6,716 0 0 6,716 10,768 10,768 5,569 4,052 4,052 1,924
Disc 5,569 3,645 0 0 3,645 5,569 5,569 5,569 1,924 1,924 1,924
SUMMARY OF RESERVES
Remaining Reserves at Sep 01, 2010 Oil Equivalents Reserve Life Indic. (yr)
Working Roy/NPI Total Oil Eq. Company % of Reserve Life Half
Product Units Gross Interest Interest Company Net Factor Mboe Total Life Index Life
Light/Med Oil Mbbl 986 986 0 986 534 1.000 986 100 30.3 12.2 9.1
Total: Oil Eq. Mboe 986 986 0 986 534 1.000 986 100 30.3 12.2 9.1
PRODUCT REVENUE AND EXPENSES
Average First Year Unit Values Net Revenue After Royalties
Wellhead Operating Other Prod'n Undisc % of 10% Disc % of
Product Units Base Price Price Adjust. Price Net Burdens Expenses Expenses Revenue M$ Total M$ Total
Light/Med Oil $/bbl 83.26 -13.66 69.60 31.88 23.89 0.00 13.83 48,968 100 20,964 100
Total: Oil Eq. $/boe 83.26 -13.66 69.60 31.88 23.89 0.00 13.83 48,968 100 20,964 100
1110792 Proved Producing, GLJ (2010-07), pri January 27, 2011 14:51:07
GLJ
Page: 80 of 144
Page 2
Petroleum Consultants

INTEREST AND NET PRESENT VALUE SUMMARY
Net Present Value Before Income Tax Net Present Value After Income Tax
Revenue Interests and Burdens (%) Disc. Prod'n Operating Capital Cash Flow Operating Capital Cash Flow
Rate Revenue Income Invest. Income Invest.
Initial Average % M$ M$ M$ M$ $/boe M$ M$ M$ $/boe
Working Interest 100.0000 100.0000 0.0 10,768 10,768 0.0 10,768 10.92 4,052 0 4,052 4.11
Capital Interest 100.0000 100.0000 5.0 7,328 7,328 0.0 7,328 7.43 2,536 0 2,536 2.57
Royalty Interest 0.0000 0.0000 8.0 6,153 6,153 0.0 6,153 6.24 2,114 0 2,114 2.14
Crown Royalty 45.8000 45.8000 10.0 5,569 5,569 0.0 5,569 5.65 1,924 0 1,924 1.95
Non-crown Royalty 0.0000 0.0000 12.0 5,094 5,094 0.0 5,094 5.17 1,778 0 1,778 1.80
Mineral Tax 0.0000 0.0000 15.0 4,529 4,529 0.0 4,529 4.59 1,612 0 1,612 1.63
20.0 3,844 3,844 0.0 3,844 3.90 1,417 0 1,417 1.44
Evaluator: Quinell, Scott M.
Run Date: January 27, 2011 14:46:18
1110792 Proved Producing, GLJ (2010-07), pri January 27, 2011 14:51:07
GLJ
Page: 81 of 144
Page 3
Petroleum Consultants

Company: Touchstone Exploration Reserve Class: Proved
Property: Coora Block Development Class: Developed Nonproducing
Pricing: GLJ (2010-07)
Effective Date: August 31, 2010
Economic Forecast
PRODUCTION FORECAST
Light/Medium Oil Production
Company Company
Gross Oil Gross Daily Daily Yearly Net Yearly Price
Year Wells bbl/d bbl/d Mbbl Mbbl $/bbl
2010 0 0 0 0 0 0.00
2011 2 48 48 17 10 72.21
2012 6 173 173 63 36 74.82
2013 10 243 243 89 51 77.43
2014 14 290 290 106 61 80.04
2015 16 270 270 99 57 81.64
2016 16 229 229 84 48 83.28
2017 16 199 199 73 42 84.95
2018 16 175 175 64 37 86.64
2019 16 154 154 56 32 88.37
2020 16 137 137 50 29 90.14
2021 16 121 121 44 25 91.94
Sub. 744 427 82.74
Rem. -32 -12 224.08
Tot. 712 415 76.40
REVENUE AND EXPENSE FORECAST
Page: 82 of 144
Revenue Before Burdens
Royalty Burdens Gas Processing Total Net
Working Interest Royalty Company Pre-Processing Allowance Royalty Revenue Operating Expenses
Interest Interest After After
Oil Gas NGL+Sul Total Total Total Crown Other Crown Other Process. Royalty Fixed Variable Total
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
2011 1,252 0 0 1,252 0 1,252 533 0 0 0 533 719 0 124 124
2012 4,711 0 0 4,711 0 4,711 2,009 0 0 0 2,009 2,702 0 505 505
2013 6,878 0 0 6,878 0 6,878 2,937 0 0 0 2,937 3,941 0 798 798
2014 8,466 0 0 8,466 0 8,466 3,614 0 0 0 3,614 4,852 0 1,053 1,053
2015 8,060 0 0 8,060 0 8,060 3,442 0 0 0 3,442 4,618 0 1,080 1,080
2016 6,967 0 0 6,967 0 6,967 2,968 0 0 0 2,968 3,999 0 1,014 1,014
2017 6,184 0 0 6,184 0 6,184 2,640 0 0 0 2,640 3,544 0 969 969
2018 5,537 0 0 5,537 0 5,537 2,360 0 0 0 2,360 3,178 0 934 934
2019 4,976 0 0 4,976 0 4,976 2,125 0 0 0 2,125 2,850 0 905 905
2020 4,497 0 0 4,497 0 4,497 1,917 0 0 0 1,917 2,579 0 882 882
2021 4,053 0 0 4,053 0 4,053 1,725 0 0 0 1,725 2,328 0 861 861
Sub. 61,581 0 0 61,581 0 61,581 26,270 0 0 0 26,270 35,311 0 9,125 9,125
Rem. -7,161 0 0 -7,161 0 -7,161 -3,839 0 0 0 -3,839 -3,322 0 -6,799 -6,799
Tot. 54,420 0 0 54,420 0 54,420 22,431 0 0 0 22,431 31,989 0 2,326 2,326
Disc 38,300 0 0 38,300 0 38,300 16,248 0 0 0 16,248 22,053 0 5,027 5,027
Net Net Capital Investment Before Tax Cash Flow
Mineral Capital NPI Prod'n Other Aband. Oper.
Tax Tax Burden Revenue Income Costs Income Dev. Plant Tang. Total Annual Cum. 10.0% Dcf
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 0 0 0 0 0 0 0 0 0 0 0 0 0 0
2011 0 0 0 595 0 0 595 1,607 0 0 1,607 -1,012 -1,012 -934
2012 0 0 0 2,197 0 0 2,197 1,639 0 0 1,639 559 -453 -465
2013 0 0 0 3,142 0 0 3,142 1,671 0 0 1,671 1,471 1,018 658
2014 0 0 0 3,799 0 0 3,799 1,705 0 0 1,705 2,094 3,112 2,111
2015 0 0 0 3,539 0 0 3,539 0 0 0 0 3,539 6,651 4,343
2016 0 0 0 2,985 0 0 2,985 0 0 0 0 2,985 9,636 6,055
2017 0 0 0 2,575 0 0 2,575 0 0 0 0 2,575 12,211 7,398
2018 0 0 0 2,243 0 0 2,243 0 0 0 0 2,243 14,454 8,461
2019 0 0 0 1,945 0 0 1,945 0 0 0 0 1,945 16,400 9,299
2020 0 0 0 1,698 0 0 1,698 0 0 0 0 1,698 18,098 9,964
2021 0 0 0 1,467 0 0 1,467 0 0 0 0 1,467 19,565 10,487
Sub. 0 0 0 26,186 0 0 26,186 6,621 0 0 6,621 19,565 19,565 10,487
Rem. 0 0 0 3,477 0 0 3,477 0 0 0 0 3,477 23,042 11,707
Tot. 0 0 0 29,663 0 0 29,663 6,621 0 0 6,621 23,042 23,042 11,707
Disc 0 0 0 17,025 0 0 17,025 5,319 0 0 5,319 11,707 11,707 11,707
1110792 Proved Developed Nonproducing, GLJ (2010-07), pri January 27, 2011 14:51:41
GLJ
Petroleum Consultants

AFTER TAX ANALYSIS
Tax Pool Balances Incl. Current Year Additions Depreciation & Writeoffs
Oper.
Income CCA COGPE CDE CEE Other CCA COGPE CDE CEE Other Total
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 0 0 0 0 0 0 0 0 0 0 0 0
2011 595 0 0 1,607 0 0 0 0 482 0 0 482
2012 2,197 0 0 2,763 0 0 0 0 829 0 0 829
2013 3,142 0 0 3,606 0 0 0 0 1,082 0 0 1,082
2014 3,799 0 0 4,229 0 0 0 0 1,269 0 0 1,269
2015 3,539 0 0 2,960 0 0 0 0 888 0 0 888
2016 2,985 0 0 2,072 0 0 0 0 622 0 0 622
2017 2,575 0 0 1,450 0 0 0 0 435 0 0 435
2018 2,243 0 0 1,015 0 0 0 0 305 0 0 305
2019 1,945 0 0 711 0 0 0 0 213 0 0 213
2020 1,698 0 0 498 0 0 0 0 149 0 0 149
2021 1,467 0 0 348 0 0 0 0 104 0 0 104
Sub. 26,186 0 0 348 0 0 0 0 6,378 0 0 6,378
Rem. 3,477 0 0 348 0 0 0 0 215 0 0 215
Tot. 29,663 0 0 348 0 0 0 0 6,593 0 0 6,593
Disc 17,025 0 0 0 4,384 0 0 4,384
Federal Provincial Net Cash Flow Net Cash Flow
ARTD & Income Before Income Tax After Income Tax
Taxable Income Income Investment Tax
Income Tax Tax Credits Payable Annual Cum. 10.0% Dcf Annual Cum. 10.0% Dcf
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 0 0 0 0 0 0 0 0 0 0 0
2011 113 128 0 0 128 -1,012 -1,012 -934 -1,140 -1,140 -1,053
2012 1,368 488 0 0 488 559 -453 -465 71 -1,069 -993
2013 2,060 719 0 0 719 1,471 1,018 658 752 -317 -419
2014 2,530 953 0 0 953 2,094 3,112 2,111 1,141 824 373
2015 2,651 986 0 0 986 3,539 6,651 4,343 2,553 3,377 1,983
2016 2,364 850 0 0 850 2,985 9,636 6,055 2,135 5,512 3,208
2017 2,140 1,547 0 0 1,547 2,575 12,211 7,398 1,028 6,540 3,744
2018 1,939 1,703 0 0 1,703 2,243 14,454 8,461 540 7,080 4,000
2019 1,732 1,515 0 0 1,515 1,945 16,400 9,299 430 7,511 4,185
2020 1,548 1,365 0 0 1,365 1,698 18,098 9,964 333 7,844 4,316
2021 1,363 1,225 0 0 1,225 1,467 19,565 10,487 242 8,086 4,402
Sub. 19,809 11,479 0 0 11,479 19,565 19,565 10,487 8,086 8,086 4,402
Rem. 3,262 5,311 0 0 5,311 3,477 23,042 11,707 -1,834 6,252 4,214
Tot. 23,071 16,790 0 0 16,790 23,042 23,042 11,707 6,252 6,252 4,214
Disc 12,642 7,493 0 0 7,493 11,707 11,707 11,707 4,214 4,214 4,214
SUMMARY OF RESERVES
Remaining Reserves at Sep 01, 2010 Oil Equivalents Reserve Life Indic. (yr)
Working Roy/NPI Total Oil Eq. Company % of Reserve Life Half
Product Units Gross Interest Interest Company Net Factor Mboe Total Life Index Life
Light/Med Oil Mbbl 712 712 0 712 415 1.000 712 100 30.3 41.1 5.8
Total: Oil Eq. Mboe 712 712 0 712 415 1.000 712 100 30.3 41.1 5.8
PRODUCT REVENUE AND EXPENSES
Average First Year Unit Values Net Revenue After Royalties
Wellhead Operating Other Prod'n Undisc % of 10% Disc % of
Product Units Base Price Price Adjust. Price Net Burdens Expenses Expenses Revenue M$ Total M$ Total
Light/Med Oil $/bbl 0.00 0.00 0.00 0.00 0.00 0.00 0.00 31,989 100 22,053 100
Total: Oil Eq. $/boe 0.00 0.00 0.00 0.00 0.00 0.00 0.00 31,989 100 22,053 100
1110792 Proved Developed Nonproducing, GLJ (2010-07), pri January 27, 2011 14:51:41
GLJ
Page: 83 of 144
Page 2
Petroleum Consultants

INTEREST AND NET PRESENT VALUE SUMMARY
Net Present Value Before Income Tax Net Present Value After Income Tax
Revenue Interests and Burdens (%) Disc. Prod'n Operating Capital Cash Flow Operating Capital Cash Flow
Rate Revenue Income Invest. Income Invest.
Initial Average % M$ M$ M$ M$ $/boe M$ M$ M$ $/boe
Working Interest 0.0000 100.0000 0.0 29,663 29,663 6,621 23,042 32.35 12,873 6,621 6,252 8.78
Capital Interest 0.0000 100.0000 5.0 22,172 22,172 5,911 16,261 22.83 11,263 5,911 5,352 7.51
Royalty Interest 0.0000 0.0000 8.0 18,856 18,856 5,543 13,313 18.69 10,202 5,543 4,659 6.54
Crown Royalty 0.0000 41.2180 10.0 17,025 17,025 5,319 11,707 16.43 9,532 5,319 4,214 5.92
Non-crown Royalty 0.0000 0.0000 12.0 15,444 15,444 5,109 10,334 14.51 8,907 5,109 3,798 5.33
Mineral Tax 0.0000 0.0000 15.0 13,453 13,453 4,821 8,632 12.12 8,057 4,821 3,236 4.54
20.0 10,907 10,907 4,398 6,509 9.14 6,862 4,398 2,464 3.46
Evaluator: Quinell, Scott M.
Run Date: January 27, 2011 14:46:21
1110792 Proved Developed Nonproducing, GLJ (2010-07), pri January 27, 2011 14:51:41
GLJ
Page: 84 of 144
Page 3
Petroleum Consultants

Company: Touchstone Exploration Reserve Class: Proved
Property: Coora Block Development Class: Undeveloped
Pricing: GLJ (2010-07)
Effective Date: August 31, 2010
Economic Forecast
PRODUCTION FORECAST
Light/Medium Oil Production
Company Company
Gross Oil Gross Daily Daily Yearly Net Yearly Price
Year Wells bbl/d bbl/d Mbbl Mbbl $/bbl
2010 0 0 0 0 0 0.00
2011 3 63 63 23 20 72.21
2012 3 109 109 40 33 74.82
2013 3 92 92 33 25 77.43
2014 3 78 78 29 18 80.04
2015 3 67 67 25 14 81.64
2016 3 59 59 21 12 83.28
2017 3 51 51 19 11 84.95
2018 3 45 45 17 10 86.64
2019 3 40 40 15 8 88.37
2020 3 36 36 13 8 90.14
2021 3 32 32 12 7 91.94
Sub. 246 165 81.00
Rem. 229 131 106.26
Tot. 475 296 93.18
REVENUE AND EXPENSE FORECAST
Page: 85 of 144
Revenue Before Burdens
Royalty Burdens Gas Processing Total Net
Working Interest Royalty Company Pre-Processing Allowance Royalty Revenue Operating Expenses
Interest Interest After After
Oil Gas NGL+Sul Total Total Total Crown Other Crown Other Process. Royalty Fixed Variable Total
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
2011 1,648 0 0 1,648 0 1,648 208 0 0 0 208 1,441 0 138 138
2012 2,970 0 0 2,970 0 2,970 464 0 0 0 464 2,506 0 237 237
2013 2,588 0 0 2,588 0 2,588 677 0 0 0 677 1,910 0 211 211
2014 2,285 0 0 2,285 0 2,285 877 0 0 0 877 1,408 0 190 190
2015 2,011 0 0 2,011 0 2,011 852 0 0 0 852 1,159 0 173 173
2016 1,790 0 0 1,790 0 1,790 771 0 0 0 771 1,019 0 159 159
2017 1,597 0 0 1,597 0 1,597 678 0 0 0 678 919 0 148 148
2018 1,438 0 0 1,438 0 1,438 610 0 0 0 610 828 0 138 138
2019 1,304 0 0 1,304 0 1,304 554 0 0 0 554 750 0 130 130
2020 1,191 0 0 1,191 0 1,191 506 0 0 0 506 685 0 123 123
2021 1,088 0 0 1,088 0 1,088 470 0 0 0 470 618 0 117 117
Sub. 19,910 0 0 19,910 0 19,910 6,667 0 0 0 6,667 13,243 0 1,765 1,765
Rem. 24,318 0 0 24,318 0 24,318 10,379 0 0 0 10,379 13,939 0 11,405 11,405
Tot. 44,227 0 0 44,227 0 44,227 17,046 0 0 0 17,046 27,181 0 13,170 13,170
Disc 17,222 0 0 17,222 0 17,222 5,819 0 0 0 5,819 11,402 0 2,999 2,999
Net Net Capital Investment Before Tax Cash Flow
Mineral Capital NPI Prod'n Other Aband. Oper.
Tax Tax Burden Revenue Income Costs Income Dev. Plant Tang. Total Annual Cum. 10.0% Dcf
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 0 0 0 0 0 0 0 0 0 0 0 0 0 0
2011 0 0 0 1,303 0 0 1,303 1,377 0 0 1,377 -74 -74 -69
2012 0 0 0 2,268 0 0 2,268 0 0 0 0 2,268 2,194 1,836
2013 0 0 0 1,699 0 0 1,699 0 0 0 0 1,699 3,893 3,133
2014 0 0 0 1,218 0 0 1,218 0 0 0 0 1,218 5,111 3,978
2015 0 0 0 986 0 0 986 0 0 0 0 986 6,098 4,601
2016 0 0 0 860 0 0 860 0 0 0 0 860 6,957 5,094
2017 0 0 0 772 0 0 772 0 0 0 0 772 7,729 5,496
2018 0 0 0 690 0 0 690 0 0 0 0 690 8,419 5,823
2019 0 0 0 620 0 0 620 0 0 0 0 620 9,039 6,090
2020 0 0 0 562 0 0 562 0 0 0 0 562 9,601 6,310
2021 0 0 0 500 0 0 500 0 0 0 0 500 10,101 6,488
Sub. 0 0 0 11,478 0 0 11,478 1,377 0 0 1,377 10,101 10,101 6,488
Rem. 0 0 0 2,533 0 167 2,367 0 0 0 0 2,367 12,468 7,108
Tot. 0 0 0 14,012 0 167 13,845 1,377 0 0 1,377 12,468 12,468 7,108
Disc 0 0 0 8,403 0 23 8,380 1,272 0 0 1,272 7,108 7,108 7,108
1110792 Proved Undeveloped, GLJ (2010-07), pri January 27, 2011 14:51:46
GLJ
Petroleum Consultants

AFTER TAX ANALYSIS
Tax Pool Balances Incl. Current Year Additions Depreciation & Writeoffs
Oper.
Income CCA COGPE CDE CEE Other CCA COGPE CDE CEE Other Total
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 0 0 0 0 0 0 0 0 0 0 0 0
2011 1,303 0 0 1,377 0 0 0 0 413 0 0 413
2012 2,268 0 0 964 0 0 0 0 289 0 0 289
2013 1,699 0 0 675 0 0 0 0 202 0 0 202
2014 1,218 0 0 472 0 0 0 0 142 0 0 142
2015 986 0 0 331 0 0 0 0 99 0 0 99
2016 860 0 0 231 0 0 0 0 69 0 0 69
2017 772 0 0 162 0 0 0 0 49 0 0 49
2018 690 0 0 113 0 0 0 0 34 0 0 34
2019 620 0 0 79 0 0 0 0 24 0 0 24
2020 562 0 0 56 0 0 0 0 17 0 0 17
2021 500 0 0 39 0 0 0 0 12 0 0 12
Sub. 11,478 0 0 39 0 0 0 0 1,350 0 0 1,350
Rem. 2,367 0 0 39 0 0 0 0 45 0 0 45
Tot. 13,845 0 0 39 0 0 0 0 1,395 0 0 1,395
Disc 8,380 0 0 0 1,052 0 0 1,052
Federal Provincial Net Cash Flow Net Cash Flow
ARTD & Income Before Income Tax After Income Tax
Taxable Income Income Investment Tax
Income Tax Tax Credits Payable Annual Cum. 10.0% Dcf Annual Cum. 10.0% Dcf
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 0 0 0 0 0 0 0 0 0 0 0
2011 890 262 0 0 262 -74 -74 -69 -336 -336 -311
2012 1,979 501 0 0 501 2,268 2,194 1,836 1,767 1,431 1,173
2013 1,497 452 0 0 452 1,699 3,893 3,133 1,247 2,678 2,125
2014 1,076 301 0 0 301 1,218 5,111 3,978 917 3,595 2,762
2015 887 830 0 0 830 986 6,098 4,601 156 3,752 2,860
2016 790 1,852 0 0 1,852 860 6,957 5,094 -992 2,759 2,291
2017 723 833 0 0 833 772 7,729 5,496 -61 2,698 2,259
2018 656 438 0 0 438 690 8,419 5,823 252 2,950 2,379
2019 596 398 0 0 398 620 9,039 6,090 222 3,172 2,474
2020 545 364 0 0 364 562 9,601 6,310 198 3,370 2,552
2021 489 334 0 0 334 500 10,101 6,488 166 3,536 2,611
Sub. 10,128 6,565 0 0 6,565 10,101 10,101 6,488 3,536 3,536 2,611
Rem. 2,322 3,067 0 0 3,067 2,367 12,468 7,108 -700 2,836 2,580
Tot. 12,450 9,632 0 0 9,632 12,468 12,468 7,108 2,836 2,836 2,580
Disc 7,328 4,528 0 0 4,528 7,108 7,108 7,108 2,580 2,580 2,580
SUMMARY OF RESERVES
Remaining Reserves at Sep 01, 2010 Oil Equivalents Reserve Life Indic. (yr)
Working Roy/NPI Total Oil Eq. Company % of Reserve Life Half
Product Units Gross Interest Interest Company Net Factor Mboe Total Life Index Life
Light/Med Oil Mbbl 475 475 0 475 296 1.000 475 100 21.3 20.8 11.3
Total: Oil Eq. Mboe 475 475 0 475 296 1.000 475 100 21.3 20.8 11.3
PRODUCT REVENUE AND EXPENSES
Average First Year Unit Values Net Revenue After Royalties
Wellhead Operating Other Prod'n Undisc % of 10% Disc % of
Product Units Base Price Price Adjust. Price Net Burdens Expenses Expenses Revenue M$ Total M$ Total
Light/Med Oil $/bbl 0.00 0.00 0.00 0.00 0.00 0.00 0.00 27,181 100 11,402 100
Total: Oil Eq. $/boe 0.00 0.00 0.00 0.00 0.00 0.00 0.00 27,181 100 11,402 100
1110792 Proved Undeveloped, GLJ (2010-07), pri January 27, 2011 14:51:46
GLJ
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Petroleum Consultants

INTEREST AND NET PRESENT VALUE SUMMARY
Net Present Value Before Income Tax Net Present Value After Income Tax
Revenue Interests and Burdens (%) Disc. Prod'n Operating Capital Cash Flow Operating Capital Cash Flow
Rate Revenue Income Invest. Income Invest.
Initial Average % M$ M$ M$ M$ $/boe M$ M$ M$ $/boe
Working Interest 0.0000 100.0000 0.0 14,012 13,845 1,377 12,468 26.27 4,213 1,377 2,836 5.97
Capital Interest 0.0000 100.0000 5.0 10,559 10,498 1,322 9,176 19.33 4,147 1,322 2,825 5.95
Royalty Interest 0.0000 0.0000 8.0 9,156 9,123 1,291 7,831 16.50 3,979 1,291 2,688 5.66
Crown Royalty 0.0000 38.5416 10.0 8,403 8,380 1,272 7,108 14.98 3,852 1,272 2,580 5.44
Non-crown Royalty 0.0000 0.0000 12.0 7,760 7,744 1,253 6,492 13.68 3,723 1,253 2,470 5.20
Mineral Tax 0.0000 0.0000 15.0 6,958 6,949 1,226 5,723 12.06 3,533 1,226 2,307 4.86
20.0 5,932 5,928 1,183 4,745 10.00 3,242 1,183 2,059 4.34
Evaluator: Quinell, Scott M.
Run Date: January 27, 2011 14:46:24
1110792 Proved Undeveloped, GLJ (2010-07), pri January 27, 2011 14:51:46
GLJ
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Petroleum Consultants

Company: Touchstone Exploration Reserve Class: Proved
Property: Coora Block Development Class: Total
Pricing: GLJ (2010-07)
Effective Date: August 31, 2010
Economic Forecast
PRODUCTION FORECAST
Light/Medium Oil Production
Company Company
Gross Oil Gross Daily Daily Yearly Net Yearly Price
Year Wells bbl/d bbl/d Mbbl Mbbl $/bbl
2010 60 222 222 27 15 69.60
2011 65 319 319 116 71 72.21
2012 64 472 472 172 107 74.82
2013 65 510 510 186 110 77.43
2014 64 529 529 193 110 80.04
2015 66 487 487 178 100 81.64
2016 61 426 426 155 88 83.28
2017 61 378 378 138 78 84.95
2018 56 339 339 124 70 86.64
2019 54 305 305 111 63 88.37
2020 51 276 276 101 57 90.14
2021 48 249 249 91 51 91.94
Sub. 1,593 919 81.76
Rem. 580 327 101.33
Tot. 2,173 1,246 86.98
REVENUE AND EXPENSE FORECAST
Page: 88 of 144
Revenue Before Burdens
Royalty Burdens Gas Processing Total Net
Working Interest Royalty Company Pre-Processing Allowance Royalty Revenue Operating Expenses
Interest Interest After After
Oil Gas NGL+Sul Total Total Total Crown Other Crown Other Process. Royalty Fixed Variable Total
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 1,881 0 0 1,881 0 1,881 862 0 0 0 862 1,020 0 646 646
2011 8,395 0 0 8,395 0 8,395 3,257 0 0 0 3,257 5,138 0 2,264 2,264
2012 12,903 0 0 12,903 0 12,903 4,865 0 0 0 4,865 8,039 0 2,652 2,652
2013 14,411 0 0 14,411 0 14,411 5,880 0 0 0 5,880 8,531 0 2,855 2,855
2014 15,456 0 0 15,456 0 15,456 6,646 0 0 0 6,646 8,810 0 2,995 2,995
2015 14,500 0 0 14,500 0 14,500 6,322 0 0 0 6,322 8,178 0 3,002 3,002
2016 12,947 0 0 12,947 0 12,947 5,658 0 0 0 5,658 7,289 0 2,831 2,831
2017 11,732 0 0 11,732 0 11,732 5,127 0 0 0 5,127 6,605 0 2,777 2,777
2018 10,721 0 0 10,721 0 10,721 4,685 0 0 0 4,685 6,036 0 2,636 2,636
2019 9,837 0 0 9,837 0 9,837 4,309 0 0 0 4,309 5,528 0 2,561 2,561
2020 9,083 0 0 9,083 0 9,083 3,978 0 0 0 3,978 5,105 0 2,471 2,471
2021 8,370 0 0 8,370 0 8,370 3,674 0 0 0 3,674 4,695 0 2,379 2,379
Sub. 130,236 0 0 130,236 0 130,236 55,262 0 0 0 55,262 74,974 0 30,070 30,070
Rem. 58,759 0 0 58,759 0 58,759 25,594 0 0 0 25,594 33,165 0 23,627 23,627
Tot. 188,995 0 0 188,995 0 188,995 80,856 0 0 0 80,856 108,139 0 53,696 53,696
Disc 94,201 0 0 94,201 0 94,201 39,782 0 0 0 39,782 54,419 0 23,421 23,421
Net Net Capital Investment Before Tax Cash Flow
Mineral Capital NPI Prod'n Other Aband. Oper.
Tax Tax Burden Revenue Income Costs Income Dev. Plant Tang. Total Annual Cum. 10.0% Dcf
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 0 0 0 374 0 0 374 0 0 0 0 374 374 368
2011 0 0 0 2,874 0 0 2,874 2,984 0 0 2,984 -109 265 267
2012 0 0 0 5,387 0 0 5,387 1,639 0 0 1,639 3,748 4,012 3,414
2013 0 0 0 5,676 0 0 5,676 1,671 0 0 1,671 4,004 8,017 6,471
2014 0 0 0 5,814 0 0 5,814 1,705 0 0 1,705 4,110 12,126 9,323
2015 0 0 0 5,176 0 0 5,176 0 0 0 0 5,176 17,303 12,588
2016 0 0 0 4,458 0 0 4,458 0 0 0 0 4,458 21,761 15,145
2017 0 0 0 3,828 0 0 3,828 0 0 0 0 3,828 25,589 17,141
2018 0 0 0 3,400 0 0 3,400 0 0 0 0 3,400 28,989 18,752
2019 0 0 0 2,967 0 0 2,967 0 0 0 0 2,967 31,956 20,031
2020 0 0 0 2,634 0 0 2,634 0 0 0 0 2,634 34,590 21,062
2021 0 0 0 2,316 0 0 2,316 0 0 0 0 2,316 36,906 21,887
Sub. 0 0 0 44,904 0 0 44,904 7,998 0 0 7,998 36,906 36,906 21,887
Rem. 0 0 0 9,539 0 167 9,372 0 0 0 0 9,372 46,278 24,384
Tot. 0 0 0 54,443 0 167 54,276 7,998 0 0 7,998 46,278 46,278 24,384
Disc 0 0 0 30,998 0 23 30,975 6,591 0 0 6,591 24,384 24,384 24,384
1110792 Total Proved, GLJ (2010-07), pri January 27, 2011 14:51:10
GLJ
Petroleum Consultants

AFTER TAX ANALYSIS
Tax Pool Balances Incl. Current Year Additions Depreciation & Writeoffs
Oper.
Income CCA COGPE CDE CEE Other CCA COGPE CDE CEE Other Total
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 374 0 0 0 0 0 0 0 0 0 0 0
2011 2,874 0 0 2,984 0 0 0 0 895 0 0 895
2012 5,387 0 0 3,727 0 0 0 0 1,118 0 0 1,118
2013 5,676 0 0 4,280 0 0 0 0 1,284 0 0 1,284
2014 5,814 0 0 4,701 0 0 0 0 1,410 0 0 1,410
2015 5,176 0 0 3,291 0 0 0 0 987 0 0 987
2016 4,458 0 0 2,304 0 0 0 0 691 0 0 691
2017 3,828 0 0 1,612 0 0 0 0 484 0 0 484
2018 3,400 0 0 1,129 0 0 0 0 339 0 0 339
2019 2,967 0 0 790 0 0 0 0 237 0 0 237
2020 2,634 0 0 553 0 0 0 0 166 0 0 166
2021 2,316 0 0 387 0 0 0 0 116 0 0 116
Sub. 44,904 0 0 387 0 0 0 0 7,727 0 0 7,727
Rem. 9,372 0 0 387 0 0 0 0 260 0 0 260
Tot. 54,276 0 0 387 0 0 0 0 7,987 0 0 7,987
Disc 30,975 0 0 0 5,436 0 0 5,436
Federal Provincial Net Cash Flow Net Cash Flow
ARTD & Income Before Income Tax After Income Tax
Taxable Income Income Investment Tax
Income Tax Tax Credits Payable Annual Cum. 10.0% Dcf Annual Cum. 10.0% Dcf
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 374 187 0 0 187 374 374 368 187 187 184
2011 1,979 940 0 0 940 -109 265 267 -1,049 -862 -785
2012 4,268 1,515 0 0 1,515 3,748 4,012 3,414 2,233 1,370 1,090
2013 4,392 1,670 0 0 1,670 4,004 8,017 6,471 2,334 3,705 2,872
2014 4,404 1,732 0 0 1,732 4,110 12,126 9,323 2,378 6,082 4,522
2015 4,189 2,270 0 0 2,270 5,176 17,303 12,588 2,906 8,989 6,355
2016 3,767 3,133 0 0 3,133 4,458 21,761 15,145 1,325 10,314 7,115
2017 3,344 2,785 0 0 2,785 3,828 25,589 17,141 1,043 11,357 7,659
2018 3,061 2,527 0 0 2,527 3,400 28,989 18,752 873 12,230 8,072
2019 2,730 2,279 0 0 2,279 2,967 31,956 20,031 688 12,918 8,369
2020 2,468 2,080 0 0 2,080 2,634 34,590 21,062 554 13,472 8,586
2021 2,200 1,894 0 0 1,894 2,316 36,906 21,887 422 13,894 8,736
Sub. 37,177 23,012 0 0 23,012 36,906 36,906 21,887 13,894 13,894 8,736
Rem. 9,112 10,126 0 0 10,126 9,372 46,278 24,384 -754 13,140 8,718
Tot. 46,289 33,138 0 0 33,138 46,278 46,278 24,384 13,140 13,140 8,718
Disc 25,539 15,666 0 0 15,666 24,384 24,384 24,384 8,718 8,718 8,718
SUMMARY OF RESERVES
Remaining Reserves at Sep 01, 2010 Oil Equivalents Reserve Life Indic. (yr)
Working Roy/NPI Total Oil Eq. Company % of Reserve Life Half
Product Units Gross Interest Interest Company Net Factor Mboe Total Life Index Life
Light/Med Oil Mbbl 2,173 2,173 0 2,173 1,246 1.000 2,173 100 21.3 26.8 7.4
Total: Oil Eq. Mboe 2,173 2,173 0 2,173 1,246 1.000 2,173 100 21.3 26.8 7.4
PRODUCT REVENUE AND EXPENSES
Average First Year Unit Values Net Revenue After Royalties
Wellhead Operating Other Prod'n Undisc % of 10% Disc % of
Product Units Base Price Price Adjust. Price Net Burdens Expenses Expenses Revenue M$ Total M$ Total
Light/Med Oil $/bbl 83.26 -13.66 69.60 31.88 23.89 0.00 13.83 108,139 100 54,419 100
Total: Oil Eq. $/boe 83.26 -13.66 69.60 31.88 23.89 0.00 13.83 108,139 100 54,419 100
1110792 Total Proved, GLJ (2010-07), pri January 27, 2011 14:51:10
GLJ
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Page 2
Petroleum Consultants

INTEREST AND NET PRESENT VALUE SUMMARY
Net Present Value Before Income Tax Net Present Value After Income Tax
Revenue Interests and Burdens (%) Disc. Prod'n Operating Capital Cash Flow Operating Capital Cash Flow
Rate Revenue Income Invest. Income Invest.
Initial Average % M$ M$ M$ M$ $/boe M$ M$ M$ $/boe
Working Interest 100.0000 100.0000 0.0 54,443 54,276 7,998 46,278 21.30 21,138 7,998 13,140 6.05
Capital Interest 0.0000 100.0000 5.0 40,058 39,998 7,233 32,765 15.08 17,946 7,233 10,714 4.93
Royalty Interest 0.0000 0.0000 8.0 34,166 34,132 6,834 27,298 12.56 16,295 6,834 9,461 4.35
Crown Royalty 45.8000 42.7821 10.0 30,998 30,975 6,591 24,384 11.22 15,308 6,591 8,718 4.01
Non-crown Royalty 0.0000 0.0000 12.0 28,298 28,282 6,362 21,920 10.09 14,407 6,362 8,045 3.70
Mineral Tax 0.0000 0.0000 15.0 24,940 24,931 6,046 18,884 8.69 13,201 6,046 7,155 3.29
20.0 20,683 20,679 5,581 15,099 6.95 11,521 5,581 5,940 2.73
Evaluator: Quinell, Scott M.
Run Date: January 27, 2011 14:46:24
1110792 Total Proved, GLJ (2010-07), pri January 27, 2011 14:51:10
GLJ
Page: 90 of 144
Page 3
Petroleum Consultants

Company: Touchstone Exploration Reserve Class: Probable
Property: Coora Block Development Class: Total
Pricing: GLJ (2010-07)
Effective Date: August 31, 2010
Economic Forecast
PRODUCTION FORECAST
Light/Medium Oil Production
Company Company
Gross Oil Gross Daily Daily Yearly Net Yearly Price
Year Wells bbl/d bbl/d Mbbl Mbbl $/bbl
2010 0 1 1 0 0 69.60
2011 1 83 83 30 24 72.21
2012 9 285 285 104 78 74.82
2013 10 409 409 149 109 77.43
2014 18 465 465 170 115 80.04
2015 16 512 512 187 117 81.64
2016 25 550 550 201 119 83.28
2017 21 508 508 185 107 84.95
2018 25 435 435 159 91 86.64
2019 23 383 383 140 80 88.37
2020 22 341 341 124 71 90.14
2021 23 303 303 110 63 91.94
Sub. 1,560 975 83.55
Rem. 1,066 602 109.22
Tot. 2,626 1,577 93.97
REVENUE AND EXPENSE FORECAST
Page: 91 of 144
Revenue Before Burdens
Royalty Burdens Gas Processing Total Net
Working Interest Royalty Company Pre-Processing Allowance Royalty Revenue Operating Expenses
Interest Interest After After
Oil Gas NGL+Sul Total Total Total Crown Other Crown Other Process. Royalty Fixed Variable Total
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 5 0 0 5 0 5 0 0 0 0 0 4 0 0 0
2011 2,193 0 0 2,193 0 2,193 491 0 0 0 491 1,702 0 163 163
2012 7,773 0 0 7,773 0 7,773 1,917 0 0 0 1,917 5,856 0 660 660
2013 11,570 0 0 11,570 0 11,570 3,136 0 0 0 3,136 8,434 0 934 934
2014 13,575 0 0 13,575 0 13,575 4,357 0 0 0 4,357 9,218 0 1,217 1,217
2015 15,259 0 0 15,259 0 15,259 5,671 0 0 0 5,671 9,588 0 1,383 1,383
2016 16,732 0 0 16,732 0 16,732 6,807 0 0 0 6,807 9,925 0 1,707 1,707
2017 15,754 0 0 15,754 0 15,754 6,665 0 0 0 6,665 9,089 0 1,588 1,588
2018 13,765 0 0 13,765 0 13,765 5,893 0 0 0 5,893 7,872 0 1,543 1,543
2019 12,361 0 0 12,361 0 12,361 5,281 0 0 0 5,281 7,080 0 1,419 1,419
2020 11,209 0 0 11,209 0 11,209 4,788 0 0 0 4,788 6,421 0 1,332 1,332
2021 10,155 0 0 10,155 0 10,155 4,347 0 0 0 4,347 5,808 0 1,295 1,295
Sub. 130,351 0 0 130,351 0 130,351 49,352 0 0 0 49,352 80,999 0 13,240 13,240
Rem. 116,466 0 0 116,466 0 116,466 50,750 0 0 0 50,750 65,716 0 27,264 27,264
Tot. 246,817 0 0 246,817 0 246,817 100,102 0 0 0 100,102 146,714 0 40,504 40,504
Disc 94,090 0 0 94,090 0 94,090 35,588 0 0 0 35,588 58,502 0 11,159 11,159
Net Net Capital Investment Before Tax Cash Flow
Mineral Capital NPI Prod'n Other Aband. Oper.
Tax Tax Burden Revenue Income Costs Income Dev. Plant Tang. Total Annual Cum. 10.0% Dcf
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 0 0 0 4 0 0 4 0 0 0 0 4 4 4
2011 0 0 0 1,540 0 0 1,540 367 0 0 367 1,172 1,176 1,087
2012 0 0 0 5,195 0 0 5,195 1,654 0 0 1,654 3,541 4,718 4,060
2013 0 0 0 7,500 0 0 7,500 1,242 0 0 1,242 6,259 10,976 8,838
2014 0 0 0 8,001 0 0 8,001 812 0 0 812 7,190 18,166 13,827
2015 0 0 0 8,205 0 0 8,205 1,739 0 0 1,739 6,466 24,632 17,906
2016 0 0 0 8,218 0 0 8,218 1,774 0 0 1,774 6,444 31,076 21,602
2017 0 0 0 7,502 0 0 7,502 0 0 0 0 7,502 38,578 25,513
2018 0 0 0 6,329 0 0 6,329 0 0 0 0 6,329 44,907 28,513
2019 0 0 0 5,661 0 0 5,661 0 0 0 0 5,661 50,569 30,953
2020 0 0 0 5,090 0 0 5,090 0 0 0 0 5,090 55,658 32,946
2021 0 0 0 4,513 0 0 4,513 0 0 0 0 4,513 60,172 34,554
Sub. 0 0 0 67,759 0 0 67,759 7,588 0 0 7,588 60,172 60,172 34,554
Rem. 0 0 0 38,451 0 358 38,093 0 0 0 0 38,093 98,265 41,957
Tot. 0 0 0 106,211 0 358 105,852 7,588 0 0 7,588 98,265 98,265 41,957
Disc 0 0 0 47,342 0 31 47,311 5,354 0 0 5,354 41,957 41,957 41,957
1110792 Total Probable, GLJ (2010-07), pri January 27, 2011 14:51:13
GLJ
Petroleum Consultants

AFTER TAX ANALYSIS
Tax Pool Balances Incl. Current Year Additions Depreciation & Writeoffs
Oper.
Income CCA COGPE CDE CEE Other CCA COGPE CDE CEE Other Total
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 4 0 0 0 0 0 0 0 0 0 0 0
2011 1,540 0 0 367 0 0 0 0 110 0 0 110
2012 5,195 0 0 1,911 0 0 0 0 573 0 0 573
2013 7,500 0 0 2,580 0 0 0 0 774 0 0 774
2014 8,001 0 0 2,617 0 0 0 0 785 0 0 785
2015 8,205 0 0 3,571 0 0 0 0 1,071 0 0 1,071
2016 8,218 0 0 4,274 0 0 0 0 1,282 0 0 1,282
2017 7,502 0 0 2,991 0 0 0 0 897 0 0 897
2018 6,329 0 0 2,094 0 0 0 0 628 0 0 628
2019 5,661 0 0 1,466 0 0 0 0 440 0 0 440
2020 5,090 0 0 1,026 0 0 0 0 308 0 0 308
2021 4,513 0 0 718 0 0 0 0 215 0 0 215
Sub. 67,759 0 0 718 0 0 0 0 7,085 0 0 7,085
Rem. 38,093 0 0 718 0 0 0 0 513 0 0 513
Tot. 105,852 0 0 718 0 0 0 0 7,598 0 0 7,598
Disc 47,311 0 0 0 4,418 0 0 4,418
Federal Provincial Net Cash Flow Net Cash Flow
ARTD & Income Before Income Tax After Income Tax
Taxable Income Income Investment Tax
Income Tax Tax Credits Payable Annual Cum. 10.0% Dcf Annual Cum. 10.0% Dcf
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 4 1 0 0 1 4 4 4 3 3 3
2011 1,429 321 0 0 321 1,172 1,176 1,087 851 854 789
2012 4,622 1,306 0 0 1,306 3,541 4,718 4,060 2,235 3,090 2,666
2013 6,726 4,550 0 0 4,550 6,259 10,976 8,838 1,709 4,798 3,970
2014 7,216 5,980 0 0 5,980 7,190 18,166 13,827 1,210 6,008 4,810
2015 7,134 5,488 0 0 5,488 6,466 24,632 17,906 978 6,986 5,427
2016 6,936 4,284 0 0 4,284 6,444 31,076 21,602 2,160 9,146 6,666
2017 6,604 4,861 0 0 4,861 7,502 38,578 25,513 2,641 11,787 8,043
2018 5,701 4,168 0 0 4,168 6,329 44,907 28,513 2,161 13,948 9,067
2019 5,222 3,759 0 0 3,759 5,661 50,569 30,953 1,902 15,851 9,887
2020 4,782 3,422 0 0 3,422 5,090 55,658 32,946 1,668 17,518 10,540
2021 4,298 3,073 0 0 3,073 4,513 60,172 34,554 1,440 18,959 11,053
Sub. 60,674 41,213 0 0 41,213 60,172 60,172 34,554 18,959 18,959 11,053
Rem. 37,580 33,094 0 0 33,094 38,093 98,265 41,957 4,999 23,958 12,569
Tot. 98,255 74,307 0 0 74,307 98,265 98,265 41,957 23,958 23,958 12,569
Disc 42,893 29,388 0 0 29,388 41,957 41,957 41,957 12,569 12,569 12,569
SUMMARY OF RESERVES
Remaining Reserves at Sep 01, 2010 Oil Equivalents Reserve Life Indic. (yr)
Working Roy/NPI Total Oil Eq. Company % of Reserve Life Half
Product Units Gross Interest Interest Company Net Factor Mboe Total Life Index Life
Light/Med Oil Mbbl 2,626 2,626 0 2,626 1,577 1.000 2,626 100 30.3 999.9 9.9
Total: Oil Eq. Mboe 2,626 2,626 0 2,626 1,577 1.000 2,626 100 30.3 999.9 9.9
PRODUCT REVENUE AND EXPENSES
Average First Year Unit Values Net Revenue After Royalties
Wellhead Operating Other Prod'n Undisc % of 10% Disc % of
Product Units Base Price Price Adjust. Price Net Burdens Expenses Expenses Revenue M$ Total M$ Total
Light/Med Oil $/bbl 83.26 -13.66 69.60 3.90 5.15 0.00 60.55 146,714 100 58,502 100
Total: Oil Eq. $/boe 83.26 -13.66 69.60 3.90 5.15 0.00 60.55 146,714 100 58,502 100
1110792 Total Probable, GLJ (2010-07), pri January 27, 2011 14:51:13
GLJ
Page: 92 of 144
Page 2
Petroleum Consultants

INTEREST AND NET PRESENT VALUE SUMMARY
Net Present Value Before Income Tax Net Present Value After Income Tax
Revenue Interests and Burdens (%) Disc. Prod'n Operating Capital Cash Flow Operating Capital Cash Flow
Rate Revenue Income Invest. Income Invest.
Initial Average % M$ M$ M$ M$ $/boe M$ M$ M$ $/boe
Working Interest 100.0000 100.0000 0.0 106,211 105,852 7,588 98,265 37.41 31,545 7,588 23,958 9.12
Capital Interest 0.0000 100.0000 5.0 67,437 67,338 6,328 61,010 23.23 23,353 6,328 17,025 6.48
Royalty Interest 0.0000 0.0000 8.0 54,020 53,971 5,715 48,256 18.37 19,834 5,715 14,120 5.38
Crown Royalty 5.5963 40.5573 10.0 47,342 47,311 5,354 41,957 15.97 17,923 5,354 12,569 4.79
Non-crown Royalty 0.0000 0.0000 12.0 41,931 41,910 5,026 36,885 14.04 16,288 5,026 11,263 4.29
Mineral Tax 0.0000 0.0000 15.0 35,535 35,523 4,588 30,936 11.78 14,254 4,588 9,667 3.68
20.0 27,927 27,922 3,977 23,945 9.12 11,685 3,977 7,709 2.93
Evaluator: Quinell, Scott M.
Run Date: January 27, 2011 14:46:37
1110792 Total Probable, GLJ (2010-07), pri January 27, 2011 14:51:13
GLJ
Page: 93 of 144
Page 3
Petroleum Consultants

Company: Touchstone Exploration Reserve Class: Proved Plus Probable
Property: Coora Block Development Class: Total
Pricing: GLJ (2010-07)
Effective Date: August 31, 2010
Economic Forecast
PRODUCTION FORECAST
Light/Medium Oil Production
Company Company
Gross Oil Gross Daily Daily Yearly Net Yearly Price
Year Wells bbl/d bbl/d Mbbl Mbbl $/bbl
2010 60 223 223 27 15 69.60
2011 66 402 402 147 95 72.21
2012 73 757 757 276 186 74.82
2013 75 919 919 336 219 77.43
2014 82 994 994 363 225 80.04
2015 82 999 999 364 218 81.64
2016 86 976 976 356 207 83.28
2017 82 886 886 324 185 84.95
2018 81 774 774 283 161 86.64
2019 77 688 688 251 143 88.37
2020 73 617 617 225 128 90.14
2021 71 552 552 201 114 91.94
Sub. 3,153 1,894 82.64
Rem. 1,646 929 106.44
Tot. 4,799 2,823 90.81
REVENUE AND EXPENSE FORECAST
Page: 94 of 144
Revenue Before Burdens
Royalty Burdens Gas Processing Total Net
Working Interest Royalty Company Pre-Processing Allowance Royalty Revenue Operating Expenses
Interest Interest After After
Oil Gas NGL+Sul Total Total Total Crown Other Crown Other Process. Royalty Fixed Variable Total
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 1,886 0 0 1,886 0 1,886 862 0 0 0 862 1,024 0 646 646
2011 10,589 0 0 10,589 0 10,589 3,748 0 0 0 3,748 6,840 0 2,426 2,426
2012 20,676 0 0 20,676 0 20,676 6,782 0 0 0 6,782 13,894 0 3,313 3,313
2013 25,981 0 0 25,981 0 25,981 9,015 0 0 0 9,015 16,966 0 3,790 3,790
2014 29,030 0 0 29,030 0 29,030 11,003 0 0 0 11,003 18,028 0 4,212 4,212
2015 29,759 0 0 29,759 0 29,759 11,993 0 0 0 11,993 17,766 0 4,384 4,384
2016 29,679 0 0 29,679 0 29,679 12,465 0 0 0 12,465 17,214 0 4,538 4,538
2017 27,486 0 0 27,486 0 27,486 11,791 0 0 0 11,791 15,694 0 4,365 4,365
2018 24,486 0 0 24,486 0 24,486 10,578 0 0 0 10,578 13,908 0 4,179 4,179
2019 22,198 0 0 22,198 0 22,198 9,590 0 0 0 9,590 12,609 0 3,980 3,980
2020 20,292 0 0 20,292 0 20,292 8,766 0 0 0 8,766 11,526 0 3,803 3,803
2021 18,524 0 0 18,524 0 18,524 8,021 0 0 0 8,021 10,503 0 3,674 3,674
Sub. 260,587 0 0 260,587 0 260,587 104,614 0 0 0 104,614 155,972 0 43,309 43,309
Rem. 175,225 0 0 175,225 0 175,225 76,344 0 0 0 76,344 98,881 0 50,891 50,891
Tot. 435,811 0 0 435,811 0 435,811 180,958 0 0 0 180,958 254,853 0 94,200 94,200
Disc 188,291 0 0 188,291 0 188,291 75,370 0 0 0 75,370 112,921 0 34,581 34,581
Net Net Capital Investment Before Tax Cash Flow
Mineral Capital NPI Prod'n Other Aband. Oper.
Tax Tax Burden Revenue Income Costs Income Dev. Plant Tang. Total Annual Cum. 10.0% Dcf
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 0 0 0 378 0 0 378 0 0 0 0 378 378 372
2011 0 0 0 4,414 0 0 4,414 3,351 0 0 3,351 1,063 1,441 1,354
2012 0 0 0 10,582 0 0 10,582 3,293 0 0 3,293 7,289 8,730 7,474
2013 0 0 0 13,176 0 0 13,176 2,913 0 0 2,913 10,263 18,993 15,308
2014 0 0 0 13,816 0 0 13,816 2,517 0 0 2,517 11,299 30,292 23,150
2015 0 0 0 13,382 0 0 13,382 1,739 0 0 1,739 11,643 41,935 30,494
2016 0 0 0 12,676 0 0 12,676 1,774 0 0 1,774 10,902 52,837 36,747
2017 0 0 0 11,330 0 0 11,330 0 0 0 0 11,330 64,167 42,654
2018 0 0 0 9,729 0 0 9,729 0 0 0 0 9,729 73,896 47,265
2019 0 0 0 8,629 0 0 8,629 0 0 0 0 8,629 82,525 50,983
2020 0 0 0 7,723 0 0 7,723 0 0 0 0 7,723 90,248 54,009
2021 0 0 0 6,829 0 0 6,829 0 0 0 0 6,829 97,077 56,441
Sub. 0 0 0 112,663 0 0 112,663 15,586 0 0 15,586 97,077 97,077 56,441
Rem. 0 0 0 47,990 0 525 47,465 0 0 0 0 47,465 144,542 66,341
Tot. 0 0 0 160,653 0 525 160,128 15,586 0 0 15,586 144,542 144,542 66,341
Disc 0 0 0 78,340 0 54 78,286 11,944 0 0 11,944 66,341 66,341 66,341
1110792 Total Proved Plus Probable, GLJ (2010-07), pri January 27, 2011 14:51:16
GLJ
Petroleum Consultants

AFTER TAX ANALYSIS
Tax Pool Balances Incl. Current Year Additions Depreciation & Writeoffs
Oper.
Income CCA COGPE CDE CEE Other CCA COGPE CDE CEE Other Total
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 378 0 0 0 0 0 0 0 0 0 0 0
2011 4,414 0 0 3,351 0 0 0 0 1,005 0 0 1,005
2012 10,582 0 0 5,638 0 0 0 0 1,692 0 0 1,692
2013 13,176 0 0 6,860 0 0 0 0 2,058 0 0 2,058
2014 13,816 0 0 7,319 0 0 0 0 2,196 0 0 2,196
2015 13,382 0 0 6,862 0 0 0 0 2,059 0 0 2,059
2016 12,676 0 0 6,577 0 0 0 0 1,973 0 0 1,973
2017 11,330 0 0 4,604 0 0 0 0 1,381 0 0 1,381
2018 9,729 0 0 3,223 0 0 0 0 967 0 0 967
2019 8,629 0 0 2,256 0 0 0 0 677 0 0 677
2020 7,723 0 0 1,579 0 0 0 0 474 0 0 474
2021 6,829 0 0 1,105 0 0 0 0 332 0 0 332
Sub. 112,663 0 0 1,105 0 0 0 0 14,812 0 0 14,812
Rem. 47,465 0 0 1,105 0 0 0 0 773 0 0 773
Tot. 160,128 0 0 1,105 0 0 0 0 15,585 0 0 15,585
Disc 78,286 0 0 0 9,854 0 0 9,854
Federal Provincial Net Cash Flow Net Cash Flow
ARTD & Income Before Income Tax After Income Tax
Taxable Income Income Investment Tax
Income Tax Tax Credits Payable Annual Cum. 10.0% Dcf Annual Cum. 10.0% Dcf
Year M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
2010 378 188 0 0 188 378 378 372 190 190 187
2011 3,409 1,261 0 0 1,261 1,063 1,441 1,354 -198 -8 4
2012 8,890 2,821 0 0 2,821 7,289 8,730 7,474 4,468 4,460 3,756
2013 11,118 6,220 0 0 6,220 10,263 18,993 15,308 4,043 8,503 6,842
2014 11,620 7,712 0 0 7,712 11,299 30,292 23,150 3,587 12,090 9,331
2015 11,323 7,758 0 0 7,758 11,643 41,935 30,494 3,885 15,975 11,782
2016 10,703 7,417 0 0 7,417 10,902 52,837 36,747 3,485 19,460 13,781
2017 9,948 7,646 0 0 7,646 11,330 64,167 42,654 3,684 23,144 15,701
2018 8,763 6,695 0 0 6,695 9,729 73,896 47,265 3,034 26,178 17,140
2019 7,952 6,038 0 0 6,038 8,629 82,525 50,983 2,591 28,769 18,256
2020 7,250 5,502 0 0 5,502 7,723 90,248 54,009 2,221 30,990 19,126
2021 6,498 4,967 0 0 4,967 6,829 97,077 56,441 1,862 32,852 19,789
Sub. 97,851 64,225 0 0 64,225 97,077 97,077 56,441 32,852 32,852 19,789
Rem. 46,692 43,220 0 0 43,220 47,465 144,542 66,341 4,245 37,097 21,287
Tot. 144,543 107,445 0 0 107,445 144,542 144,542 66,341 37,097 37,097 21,287
Disc 68,432 45,054 0 0 45,054 66,341 66,341 66,341 21,287 21,287 21,287
SUMMARY OF RESERVES
Remaining Reserves at Sep 01, 2010 Oil Equivalents Reserve Life Indic. (yr)
Working Roy/NPI Total Oil Eq. Company % of Reserve Life Half
Product Units Gross Interest Interest Company Net Factor Mboe Total Life Index Life
Light/Med Oil Mbbl 4,799 4,799 0 4,799 2,823 1.000 4,799 100 30.3 59.0 8.7
Total: Oil Eq. Mboe 4,799 4,799 0 4,799 2,823 1.000 4,799 100 30.3 59.0 8.7
PRODUCT REVENUE AND EXPENSES
Average First Year Unit Values Net Revenue After Royalties
Wellhead Operating Other Prod'n Undisc % of 10% Disc % of
Product Units Base Price Price Adjust. Price Net Burdens Expenses Expenses Revenue M$ Total M$ Total
Light/Med Oil $/bbl 83.26 -13.66 69.60 31.81 23.85 0.00 13.95 254,853 100 112,921 100
Total: Oil Eq. $/boe 83.26 -13.66 69.60 31.81 23.85 0.00 13.95 254,853 100 112,921 100
1110792 Total Proved Plus Probable, GLJ (2010-07), pri January 27, 2011 14:51:16
GLJ
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Page 2
Petroleum Consultants

INTEREST AND NET PRESENT VALUE SUMMARY
Net Present Value Before Income Tax Net Present Value After Income Tax
Revenue Interests and Burdens (%) Disc. Prod'n Operating Capital Cash Flow Operating Capital Cash Flow
Rate Revenue Income Invest. Income Invest.
Initial Average % M$ M$ M$ M$ $/boe M$ M$ M$ $/boe
Working Interest 100.0000 100.0000 0.0 160,653 160,128 15,586 144,542 30.12 52,683 15,586 37,097 7.73
Capital Interest 0.0000 100.0000 5.0 107,495 107,335 13,561 93,775 19.54 41,299 13,561 27,738 5.78
Royalty Interest 0.0000 0.0000 8.0 88,185 88,103 12,549 75,554 15.74 36,129 12,549 23,580 4.91
Crown Royalty 45.7000 41.5221 10.0 78,340 78,286 11,944 66,341 13.82 33,231 11,944 21,287 4.44
Non-crown Royalty 0.0000 0.0000 12.0 70,229 70,193 11,388 58,805 12.25 30,696 11,388 19,308 4.02
Mineral Tax 0.0000 0.0000 15.0 60,475 60,454 10,634 49,820 10.38 27,456 10,634 16,822 3.50
20.0 48,610 48,601 9,557 39,044 8.14 23,206 9,557 13,649 2.84
Evaluator: Quinell, Scott M.
Run Date: January 27, 2011 14:46:37
1110792 Total Proved Plus Probable, GLJ (2010-07), pri January 27, 2011 14:51:16
GLJ
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Page 3
Petroleum Consultants

INTEREST DESCRIPTIONS
WELL DATA
ACCOUNTING SUMMARY
PRODUCTION FORECASTS
ECONOMIC PARAMETERS
BOE EQUIVALENT
INCOME TAX
CONSTANT PRICE ANALYSIS
LIST OF ABBREVIATIONS
EVALUATION PROCEDURE
TABLE OF CONTENTS
GLJ
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Petroleum Consultants

EVALUATION PROCEDURE
The following outlines the methodology employed by GLJ Petroleum Consultants (GLJ) in
conducting the evaluation of the Company’s oil and gas properties. GLJ evaluation procedures are
in compliance with standards contained in the Canadian Oil and Gas Evaluation (COGE)
Handbook.
INTEREST DESCRIPTIONS
The Company provided GLJ with current land interest information. The Company provided a
representation letter confirming accuracy of land information. Certain cross-checks of land and
accounting information were undertaken by GLJ as recommended in the COGE Handbook. In this
process, nothing came to GLJ’s attention that indicated that information provided by the Company
was incomplete or unreliable.
In GLJ’s reports, “Company Interest” reserves and values refer to the sum of royalty interest * and
working interest reserves before deduction of royalty burdens payable. “Working Interest” reserves
equate to those reserves that are referred to as “Company Gross” reserves by the Canadian
Securities Administrators (CSA) in NI 51-101.
* Royalty interest reserves include royalty volumes derived only from other working interest owners.
WELL DATA
Pertinent interest and offset well data such as drill stem tests, workovers, pressure surveys,
production tests, etc., were provided by the Company or were obtained from other operators, public
records or GLJ nonconfidential files.
ACCOUNTING SUMMARY
The Company provided GLJ with available accounting data on a property basis and for the
corporate total for the period September 1, 2009, to August 31, 2010. In some circumstances this
information was also provided on a cost centre basis to address major reserves entities that are a
subset of a Company property.
PRODUCTION FORECASTS
GLJ
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In establishing all production forecasts, consideration was given to existing gas contracts and the
possibility of contract revisions, to the operator's plans for development drilling and to reserves
and well capability. Generally, development drilling in an area was not considered unless there
was some indication from the operator that drilling could be expected.
The on-stream date for currently shut-in reserves was estimated with consideration given to the
following:
• proximity to existing facilities
• plans of the operator
• economics
ECONOMIC PARAMETERS
Pertinent economic parameters are listed as follows:
a) The effective date is August 31, 2010.
b) Operating and capital costs were estimated in 2010 Canadian dollars and then escalated as
summarized in the Product Price and Market Forecasts section of this report.
c) Economic forecasts were prepared for each property on a before income tax basis. Detailed
discounting of future cash flow was performed using a discount factor of 10.0 percent with all
values discounted annually to August 31, 2010, on a mid-calendar-year basis.
d) Trinidad and Tobago Royalties
Page: 99 of 144
Crown royalties are determined by governmental regulation, are calculated as a percentage of
the value of the gross production, and are currently fixed at 10 percent for the Coora
property. In addition, the Company is required to pay an additional royalty as follows:
GLJ
Petroleum Consultants

Liquid Price Received - $US Between Royalty Rate (%)
0.00 and 8.00 5
8.01 and 10.00 8
10.01 and 12.00 11
12.01 and 14.00 14
14.01 and 16.00 17
16.01 and 18.00 21
18.01 and 20.00 24
20.01 and 22.00 26
22.01 and 24.00 28
24.01 and 26.00 30
26.01 and 28.00 32
28.01 and Above Negotiated
New wells are subject to a 0 percent royalty in the first year and receive a 50 percent
reduction in the second year.
g) Field level overhead charges have been included; recovery of overhead expenses has not been
included.
h) The Company’s office G&A costs have not been included.
Well abandonment costs for wells with reserves have been included at the property level.
Additional abandonment costs associated with non-reserves wells, lease reclamation costs and
facility abandonment and reclamation expenses have not been included in this analysis.
BOE EQUIVALENT
In this report, quantities of hydrocarbons have been converted to barrels of oil equivalent (BOE)
using factors of 6 MCF/BOE for gas, 1 BBL/BOE for all liquids, and 0 BOE for sulphur. Users
of oil equivalent values are cautioned that while BOE based metrics are useful for comparative
purposes, they may be misleading when used in isolation.
INCOME TAX
Trinidad and Tobago
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Trinidad income taxes were calculated based on currently legislated tax rates, tax regulations and
tax pool information provided by the Company.
GLJ
Petroleum Consultants

In addition to royalties, the Coora Block property is subject to production levy, oil impost tax,
supplemental petroleum tax, unemployment levy and a petroleum profits tax. The production
levy is limited to 3 percent of the gross income from production. Oil impost tax is paid annually
by petroleum producing companies to pay for the annual expenses of the Ministry of Energy for
the administration of the petroleum industry. Oil impost payments are made in proportion to each
company's level of crude oil and natural gas production. The supplemental profits tax ("SPT"),
applies only to liquids production (not natural gas) and varies with the price received for liquid
production, the date of the block license and whether the block is on or offshore. The revenue
base for the calculation of SPT is the gross income less royalties, 50 percent of geological and
geophysical costs, 100 percent of direct exploration costs, 40 percent of development expenses,
and 100 percent of enhanced recovery costs. SPT rates applicable for the Coora Block property
at various liquid prices are set out below:
Liquid Price Received - $US Between SPT Rate (%)
0 and 18.00 0
18.01 and 19.50 1
19.51 and 22.50 2
22.51 and 27.00 3
27.01 and 30.00 4
30.01 and 31.50 5
31.51 and 33.00 6
33.01 and 34.50 7
34.51 and 36.00 8
36.01 and 37.50 9
37.51 and 39.00 10
39.01 and 40.50 11
40.51 and 42.00 12
42.01 and 43.50 13
43.51 and 45.00 14
45.01 and 46.50 15
46.51 and 48.00 16
48.01 and 49.50 17
49.51 and over 18
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The petroleum profits tax ("PPT") and unemployment levy are 50 and 5 percent, respectively,
and are fixed by the Trinidad Government. The same revenue base is used for the calculation of
both the PPT and the unemployment levy and is the gross income less 100 percent of the royalty,
100 percent of the production levy, 100 percent of the SPT, 100 percent of workover allowance,
100 percent of dry hole expenditures, all heavy oil allowance, all operating and administrative
expenses and capital allowances (different capital items are allowed to be depreciated over
different timelines per Government regulations).
GLJ
Petroleum Consultants

LIST OF ABBREVIATIONS
AOF absolute open flow
ARTC Alberta Royalty Tax Credit
BBL barrels
BCF billion cubic feet of gas at standard conditions
BOE barrel of oil equivalent, in this evaluation determined using 6 MCF/BOE
for gas, 1 BBL/BOE for all liquids, and 0 BOE for sulphur
BOPD barrels of oil per day
BTU British thermal units
BWPD barrels of water per day
DSU drilling spacing unit
GCA gas cost allowance
GOC gas-oil contact
GOR gas-oil ratio
GORR gross overriding royalty
GWC gas-water contact
MBBL thousand barrels
MBOE thousand BOE
MCF thousand cubic feet of gas at standard conditions
MLT thousand long tons
M$ thousand Canadian dollars
MM$ million Canadian dollars
MMBBL million barrels
MMBOE million BOE
MMBTU million British thermal units
MMCF million cubic feet of gas at standard conditions
MRL maximum rate limitation
MSTB thousand stock tank barrels
MMSTB million stock tank barrels
NGL natural gas liquids (ethane, propane, butane and condensate)
NPI net profits interest
OGIP original gas-in-place
OOIP original oil-in-place
ORRI overriding royalty interest
OWC oil-water contact
P&NG petroleum and natural gas
psia pounds per square inch absolute
psig pounds per square inch gauge
PVT pressure-volume-temperature
RLI reserves life index, calculated by dividing reserves by the forecast of
first year production
SCF standard cubic feet
STB stock tank barrel
WI working interest
WTI West Texas Intermediate
GLJ
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Petroleum Consultants

RESERVES DEFINITIONS
Reserves estimates have been prepared by GLJ Petroleum Consultants (GLJ) in accordance with
standards contained in the Canadian Oil and Gas Evaluation (COGE) Handbook. The following
reserves definitions are set out by the Canadian Securities Administrators in National Instrument
51-101 Standards of Disclosure for Oil and Gas Activities (NI 51-101; in Part 2 of the Glossary to
NI 51-101) with reference to the COGE Handbook.
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 conditions 1 , 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.
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.
Page: 103 of 144
1 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 12
months of the reporting issuer’s financial year, under US SEC rules (this is optional disclosure
under NI 51-101).
GLJ
Petroleum Consultants

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 nonproducing.
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.
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:
• 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].
GLJ
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DOCUMENTED RESERVES CATEGORIES
Production and revenue projections are prepared for each of the following main reserves
categories:
Reserves Category
Proved
Proved Plus Probable
Production and Development Status
Developed Producing*
Developed Non-producing
Undeveloped
Total (sum of developed producing, developed non-producing and undeveloped)
* as producing reserves are inherently developed, GLJ simply refers to “developed producing”
reserves as “producing”
Reserves and revenue projections are available in GLJ’s evaluation database for any reserves and
development subcategory including those determined by difference (e.g., probable producing).
The following reserves categories are documented in this Corporate Summary volume:
Proved Producing
Proved Developed Non-producing
Proved Undeveloped
Total Proved
Total Probable
Total Proved Plus Probable
Documentation for the following additional reserves categories is provided in the “Expanded
Corporate Summary Information”, which has been provided to the Company in electronic format
only.
Proved
Developed Producing
Developed Non-producing
Undeveloped
Total
Probable
Developed Producing
Developed Non-producing
Undeveloped
Total
GLJ
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Petroleum Consultants

Proved Plus Probable
Developed Producing
Developed Non-producing
Undeveloped
Total
Page: 106 of 144
Individual property evaluation reports contain detailed documentation of reserves estimation
methodology and evaluation procedures.
When evaluating reserves, GLJ evaluators generally first identify the producing situation and
assign proved, proved plus probable and proved plus probable plus possible reserves in
recognition of the existing level of development and the existing depletion strategy. Incremental
non-producing (developed non-producing or undeveloped) reserves are subsequently assigned
recognizing future development opportunities and enhancements to the depletion mechanism. It
should be recognized that future developments may result in accelerated recovery of producing
reserves.
GLJ
Petroleum Consultants

PRODUCT PRICE AND MARKET FORECASTS
July 1, 2010
GLJ Petroleum Consultants (GLJ) has prepared its July 1, 2010, interim price and market
forecast as summarized in the attached Table 1 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 informed
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.
Trinidad
GLJ has forecast the Coora Field crude oil price based on the differential between actual
wellhead prices received at Coora and West Texas Intermediate for crude oil sales for the period
from January 2002 to August 2010. The historic differential between the Coora oil price in
$US/BBL to the dated WTI crude oil price in $US/BBL of six months previous is approximately
17 percent. GLJ has forecast the sales oil price for Coora based on a 17 percent differential to the
average WTI price forecast.
Netherlands
The price of natural gas in the Netherlands is calculated using historical average prices for
competing heavy fuel oil, gas-oil and coal over periods of five to fourteen months. The prices of
these competing fuels are heavily influenced by world oil price and, therefore, a correlation
exists between the current gas price in the Netherlands and the historic dated Brent crude oil
price.
Recently the Gas Terra gas pricing contract has been modified to include the current trading
price of natural gas at the National Balancing Point (NBP). To reflect this, GLJ has prepared a
price forecast of Netherlands gas using a blend of 65 percent dated Brent and 35 percent NBP
forecast.
The sales gas price forecast for the Netherlands is presented in Table 3.
GLJ
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Table 1
GLJ Petroleum Consultants
Crude Oil and Natural Gas Liquids
Price Forecast
Effective July 1, 2010
NYMEX WTI Near ICE BRENT Near Light, Sweet
Bank of Month Futures Contract Month Futures Contract Crude Oil Bow River Crude Oil Lloyd Blend Crude Oil WCS Heavy Crude Oil Light Crude Oil Medium Crude Oil Alberta Natural Gas Liquids
Canada Crude Oil at Crude Oil (40 API, 0.3%S) Stream Quality Stream Quality Stream Quality Proxy (12 API) (35 API, 1.2%S) (29 API, 2.0%S) (Then Current Dollars)
Average Noon Cushing Oklahoma FOB North Sea at Edmonton at Hardisty at Hardisty at Hardisty at Hardisty at Cromer at Cromer Edmonton
Exchange Constant Then Then Then Then Then Then Then Then Then Spec Edmonton Edmonton Pentanes
Inflation Rate 2010 $ Current Current Current Current Current Current Current Current Current Ethane Propane Butane Plus
Year % $US/$Cdn $US/bbl $US/bbl $US/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl
1996 1.6 0.733 28.77 21.98 20.31 29.38 25.12 21.55 N/A 20.06 28.41 26.08 N/A 23.13 17.83 30.05
1997 1.6 0.722 26.57 20.62 19.32 27.85 21.18 20.55 N/A 14.41 26.52 23.72 N/A 19.41 19.76 30.91
1998 1.0 0.675 18.30 14.44 13.34 20.36 14.63 15.38 N/A 9.45 19.31 16.96 N/A 11.74 12.69 21.87
1999 1.7 0.673 24.20 19.25 17.99 27.63 23.78 22.14 N/A 19.49 26.97 25.37 N/A 15.86 18.65 27.64
2000 2.7 0.673 37.33 30.23 28.41 44.57 35.28 32.61 N/A 27.49 43.28 39.92 N/A 32.15 35.59 46.31
2001 2.5 0.646 31.27 26.00 24.87 39.44 27.69 23.47 N/A 16.77 35.22 31.58 N/A 31.92 31.25 42.48
2002 2.3 0.637 30.57 26.08 25.02 40.33 31.83 30.60 N/A 26.57 37.43 35.48 N/A 21.39 27.08 40.73
2003 2.8 0.716 35.62 31.07 28.47 43.66 32.11 31.18 N/A 26.26 40.09 37.55 N/A 32.14 34.36 44.23
2004 1.8 0.770 46.17 41.38 38.02 52.96 37.43 36.31 N/A 29.11 49.14 45.64 N/A 34.70 39.97 53.94
2005 2.2 0.826 61.98 56.58 55.14 69.02 44.73 43.03 43.74 34.07 62.18 56.77 N/A 43.04 51.80 69.57
2006 2.0 0.882 70.95 66.22 66.16 73.21 51.82 50.36 50.66 41.84 66.38 62.26 N/A 43.85 60.17 75.41
2007 2.2 0.935 76.05 72.39 72.71 77.06 53.64 52.03 52.38 43.42 71.13 65.71 N/A 49.56 61.78 77.38
2008 2.4 0.943 102.44 99.64 98.30 102.89 84.31 82.60 82.95 74.94 96.08 93.10 N/A 58.38 75.33 104.78
2009 0.4 0.880 62.01 61.78 62.50 66.32 60.18 58.40 58.66 54.46 63.84 62.96 N/A 38.03 48.17 68.17
2010 Q1 1.6 0.961 78.72 78.72 77.26 80.56 73.74 72.24 72.58 66.43 78.69 76.87 N/A 57.06 76.58 88.28
2010 Q2 (e) 1.8 0.969 77.90 77.90 78.91 77.22 67.19 65.73 66.18 58.45 75.01 73.47 N/A 46.80 65.85 86.63
2010 Q3 2.0 0.950 80.00 80.00 78.50 83.26 71.61 70.36 70.76 64.99 79.93 78.27 14.02 49.96 66.61 84.93
2010 Q4 2.0 0.950 80.00 80.00 78.50 83.26 70.77 69.52 69.92 63.90 79.93 78.27 16.60 49.96 66.61 84.93
2010 Full Year 1.9 0.958 79.16 79.16 78.29 81.08 70.83 69.46 69.86 63.44 78.39 76.72 N/A 50.95 68.91 86.19
2010 Q3-Q4 2.0 0.950 80.00 80.00 78.50 83.26 71.19 69.94 70.34 64.44 79.93 78.27 15.31 49.96 66.61 84.93
2011 2.0 0.950 81.37 83.00 81.50 86.42 72.59 71.30 71.70 65.24 81.24 79.94 17.33 54.45 66.54 88.15
2012 2.0 0.950 82.66 86.00 84.50 89.58 73.45 72.11 72.51 65.33 83.31 81.52 19.87 56.43 68.98 91.37
2013 2.0 0.950 83.87 89.00 87.50 92.74 74.19 72.80 73.20 65.26 86.25 82.54 21.51 58.42 71.41 94.59
2014 2.0 0.950 85.00 92.00 90.50 95.90 76.72 75.28 75.68 67.52 89.19 85.35 22.78 60.42 73.84 97.82
2015 2.0 0.950 85.00 93.84 92.34 97.84 78.27 76.80 77.20 68.90 90.99 87.07 23.69 61.64 75.33 99.79
2016 2.0 0.950 85.00 95.72 94.22 99.81 79.85 78.35 78.75 70.32 92.82 88.83 24.89 62.88 76.85 101.81
2017 2.0 0.950 85.00 97.64 96.14 101.83 81.46 79.93 80.33 71.76 94.70 90.63 25.98 64.15 78.41 103.86
2018 2.0 0.950 85.00 99.59 98.09 103.88 83.11 81.55 81.95 73.22 96.61 92.46 26.59 65.45 79.99 105.96
2019 2.0 0.950 85.00 101.58 100.08 105.98 84.78 83.19 83.59 74.72 98.56 94.32 27.17 66.77 81.60 108.10
2020+ 2.0 0.950 85.00 +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr
Historical futures contract price is an average of the daily settlement price of the near month contract over the calendar month.
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Petroleum Consultants
Page: 108 of 144

APPENDIX I
RESERVES ESTIMATION - SUPPORTING INFORMATION
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Page: 109 of 144
OIL
1) Coora Producing - Oil+Fluids Time Semilog/Oil+Fluids Cum Coord Plot 110
2) Recompletions/Workovers - Oil Time Semilog/Oil Cum Coord Plot 111
2011-Q3 - Oil Time Semilog/Oil Cum Coord Plot 112
2012-Q3 - Oil Time Semilog/Oil Cum Coord Plot 113
2013-Q3 - Oil Time Semilog/Oil Cum Coord Plot 114
2014-Q3 - Oil Time Semilog/Oil Cum Coord Plot 115
2015-Q3 - Oil Time Semilog/Oil Cum Coord Plot 116
2016-Q3 - Oil Time Semilog/Oil Cum Coord Plot 117
3) Replacement Wells - Oil Time Semilog/Oil Cum Coord Plot 118
Location F - Oil Time Semilog Plot - Oil Volumetric Data 119
Location G - Oil Time Semilog Plot - Oil Volumetric Data 122
Location H - Oil Time Semilog Plot - Oil Volumetric Data 124
Location L - Oil Time Semilog Plot - Oil Volumetric Data 126
4) Sidetrack Wells - Oil Time Semilog/Oil Cum Coord Plot 128
CO-180 Sidetrack - Oil Time Semilog Plot - Oil Volumetric Data 129
CO-362 Sidetrack - Oil Time Semilog Plot - Oil Volumetric Data 131
QU-080 Sidetrack - Oil Time Semilog Plot - Oil Volumetric Data 134
QU-119 Sidetrack - Oil Time Semilog Plot - Oil Volumetric Data 137
QU-428 Sidetrack - Oil Time Semilog Plot - Oil Volumetric Data 139
Page
January 28, 2011 15:10:32
Petroleum Consultants

Property :Coora Block
Daily Oil Calendar Day (bbl/d)
10 100 1000 10000
Daily Fluid (bbl/d)
10 100 1000 10000
Daily Oil (bbl/d)
10 100 1000 10000
0 600
# Oil Wells (month)
Daily Oil Calendar Day (bbl/d)
0 200 400 600 800 1000 1200 1400 1600 1800 2000
Daily Fluid (bbl/d)
0 200 400 600 800 1000 1200 1400 1600 1800 2000
Daily Oil (bbl/d)
0 200 400 600 800 1000 1200 1400 1600 1800 2000
0 600
# Oil Wells (month)
Historical and Forecast Production
1) Coora Producing
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
Year
Projections Illustrate
Production Forecast
68500 68800 69100 69400 69700 70000 70300 70600 70900 71200 71500
Cumulative Oil (Mbbl)
Decline Analysis Summary @ 2010/09/01
Reserves ( Mbbl ) Rates ( bbl/d ) Decline
Reserves
Classification Ultimate Cum Prd Remain Initial Final Initial Expont
Pv Prd A 70400 69414 986 225 35 8.8% 0.40
P + P Prd G 70590 69414 1176 225 35 7.4% 0.40
1) Coora Producing
1110792 / Jan 27, 2011
A
G
Projections Illustrate
Production Forecast
G
A
0.1 1.0 10.0 100.0
Water Cut (%)
Page: 110 of 144
0 2000
GOR (scf/bbl)
0 10 20 30 40 50 60 70 80 90 100
0 2000
Oil Cut (%)
GOR (scf/bbl)
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
Year
Average Production Rates (Last 12 months ending 2010/08/31)
Gas : 0.0 Mcf/d 0.0 Mcf/cd WGR : 0.0 bbl/M...
Oil : 538.8 bbl/d 221.8 bbl/cd GOR : 0.0 scf/bbl
Avg Wells : 33.7 WC : 49.3 %
Cumulative Production
Oil : 69414.1 Mbbl Gas : 82029... MMcf Water : 13099.9 Mbbl
GLJ
Petroleum Consultants

Property :Coora Block
1 10 100 1000
Daily Oil Cal Day (bbl/d)
0 80 160 240 320 400 480 560 640 720 800
Daily Oil (bbl/d)
Historical and Forecast Production
2) Recompletions/Workovers
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Year
Projections Illustrate
Production Forecast
B1
H1
0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000
Total Reserves Summary @ 2010/09/01
Reserves ( Mbbl )
Reserves
Classification Ultimate Cum Production Remaining
Pv Dev NPrd B1(R) 1010 0 1010
P + P Dev ... H1(R) 2350 0 2350
2) Recompletions/Workovers
1110792 / Jan 27, 2011
Cumulative Oil (Mbbl)
Projections Illustrate
Production Forecast
Average Production Rates (Last 12 months ending 2010/09/01)
Gas : 0.0 Mcf/d 0.0 Mcf/cd WGR : 0.0 bbl/MMcf
Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/bbl
On Prod : 0.0 days WC : 0.0 %
Cumulative Production
Oil : 0.0 Mbbl Gas : 0.0 MMcf Water : 0.0 Mbbl
GLJ
H1
B1
Page: 111 of 144
Petroleum Consultants

Property :Coora Block
1 10 100 1000
Daily Oil Cal Day (bbl/d)
0 40 80 120 160 200 240 280 320 360 400
Daily Oil (bbl/d)
Historical and Forecast Production
2011-Q3
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Year
Projections Illustrate
Production Forecast
0 50 100 150 200 250 300 350 400 450 500
Cumulative Oil (Mbbl)
Decline Analysis Summary @ 2010/09/01
Reserves ( Mbbl ) Rates ( bbl/d ) Decline
Reserves
Classification Ultimate Cum Prd Remain Initial Final Initial Expont
Pv Dev NPrd B1 270 0 270 155 9 20.5% 0.20
P + P Dev N... H1 435 0 435 235 9 20.0% 0.20
2011-Q3
1110792 / Jan 27, 2011
B1
Projections Illustrate
Production Forecast
Average Production Rates (Last 12 months ending 2010/09/01)
Gas : 0.0 Mcf/d 0.0 Mcf/cd WGR : 0.0 bbl/M...
Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/bbl
On Prod : 0.0 days WC : 0.0 %
Cumulative Production
Oil : 0.0 Mbbl Gas : 0.0 MMcf Water : 0.0 Mbbl
H1
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H1
B1
Page: 112 of 144
Petroleum Consultants

Property :Coora Block
1 10 100 1000
Daily Oil Cal Day (bbl/d)
0 40 80 120 160 200 240 280 320 360 400
Daily Oil (bbl/d)
Historical and Forecast Production
2012-Q3
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Year
Projections Illustrate
Production Forecast
0 50 100 150 200 250 300 350 400 450 500
Cumulative Oil (Mbbl)
Decline Analysis Summary @ 2010/09/01
Reserves ( Mbbl ) Rates ( bbl/d ) Decline
Reserves
Classification Ultimate Cum Prd Remain Initial Final Initial Expont
Pv Dev NPrd B1 270 0 270 155 9 20.5% 0.20
P + P Dev N... H1 435 0 435 235 9 20.0% 0.20
2012-Q3
1110792 / Jan 27, 2011
B1
Projections Illustrate
Production Forecast
Average Production Rates (Last 12 months ending 2010/09/01)
Gas : 0.0 Mcf/d 0.0 Mcf/cd WGR : 0.0 bbl/M...
Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/bbl
On Prod : 0.0 days WC : 0.0 %
Cumulative Production
Oil : 0.0 Mbbl Gas : 0.0 MMcf Water : 0.0 Mbbl
H1
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H1
B1
Page: 113 of 144
Petroleum Consultants

Property :Coora Block
1 10 100 1000
Daily Oil Cal Day (bbl/d)
0 40 80 120 160 200 240 280 320 360 400
Daily Oil (bbl/d)
Historical and Forecast Production
2013-Q3
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Year
Projections Illustrate
Production Forecast
0 50 100 150 200 250 300 350 400 450 500
Cumulative Oil (Mbbl)
Decline Analysis Summary @ 2010/09/01
Reserves ( Mbbl ) Rates ( bbl/d ) Decline
Reserves
Classification Ultimate Cum Prd Remain Initial Final Initial Expont
Pv Dev NPrd B1 270 0 270 155 9 20.5% 0.20
P + P Dev N... H1 435 0 435 235 9 20.0% 0.20
2013-Q3
1110792 / Jan 27, 2011
B1
Projections Illustrate
Production Forecast
Average Production Rates (Last 12 months ending 2010/09/01)
Gas : 0.0 Mcf/d 0.0 Mcf/cd WGR : 0.0 bbl/M...
Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/bbl
On Prod : 0.0 days WC : 0.0 %
Cumulative Production
Oil : 0.0 Mbbl Gas : 0.0 MMcf Water : 0.0 Mbbl
H1
GLJ
H1
B1
Page: 114 of 144
Petroleum Consultants

Property :Coora Block
1 10 100 1000
Daily Oil Cal Day (bbl/d)
0 40 80 120 160 200 240 280 320 360 400
Daily Oil (bbl/d)
Historical and Forecast Production
2014-Q3
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Year
Projections Illustrate
Production Forecast
0 50 100 150 200 250 300 350 400 450 500
Cumulative Oil (Mbbl)
Decline Analysis Summary @ 2010/09/01
Reserves ( Mbbl ) Rates ( bbl/d ) Decline
Reserves
Classification Ultimate Cum Prd Remain Initial Final Initial Expont
Pv Dev NPrd B1 200 0 200 115 9 20.0% 0.20
P + P Dev N... H1 435 0 435 235 9 20.0% 0.20
2014-Q3
1110792 / Jan 27, 2011
B1
Projections Illustrate
Production Forecast
Average Production Rates (Last 12 months ending 2010/09/01)
Gas : 0.0 Mcf/d 0.0 Mcf/cd WGR : 0.0 bbl/M...
Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/bbl
On Prod : 0.0 days WC : 0.0 %
Cumulative Production
Oil : 0.0 Mbbl Gas : 0.0 MMcf Water : 0.0 Mbbl
H1
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H1
B1
Page: 115 of 144
Petroleum Consultants

Property :Coora Block
1 10 100 1000
Daily Oil Cal Day (bbl/d)
0 25 50 75 100 125 150 175 200 225 250
Daily Oil (bbl/d)
Historical and Forecast Production
2015-Q3
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Year
Projections Illustrate
Production Forecast
0 50 100 150 200 250 300 350 400
Cumulative Oil (Mbbl)
Decline Analysis Summary @ 2010/09/01
Reserves ( Mbbl ) Rates ( bbl/d ) Decline
Reserves
Classification Ultimate Cum Prd Remain Initial Final Initial Expont
P + P Dev N... H1 305 0 305 165 9 19.6% 0.20
2015-Q3
1110792 / Jan 27, 2011
H1
Projections Illustrate
Production Forecast
Average Production Rates (Last 12 months ending 2010/09/01)
Gas : 0.0 Mcf/d 0.0 Mcf/cd WGR : 0.0 bbl/M...
Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/bbl
On Prod : 0.0 days WC : 0.0 %
Cumulative Production
Oil : 0.0 Mbbl Gas : 0.0 MMcf Water : 0.0 Mbbl
GLJ
H1
Page: 116 of 144
Petroleum Consultants

Property :Coora Block
1 10 100 1000
Daily Oil Cal Day (bbl/d)
0 25 50 75 100 125 150 175 200 225 250
Daily Oil (bbl/d)
Historical and Forecast Production
2016-Q3
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Year
Projections Illustrate
Production Forecast
0 50 100 150 200 250 300 350 400
Cumulative Oil (Mbbl)
Decline Analysis Summary @ 2010/09/01
Reserves ( Mbbl ) Rates ( bbl/d ) Decline
Reserves
Classification Ultimate Cum Prd Remain Initial Final Initial Expont
P + P Dev N... H1 305 0 305 165 9 19.6% 0.20
2016-Q3
1110792 / Jan 27, 2011
H1
Projections Illustrate
Production Forecast
Average Production Rates (Last 12 months ending 2010/09/01)
Gas : 0.0 Mcf/d 0.0 Mcf/cd WGR : 0.0 bbl/M...
Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/bbl
On Prod : 0.0 days WC : 0.0 %
Cumulative Production
Oil : 0.0 Mbbl Gas : 0.0 MMcf Water : 0.0 Mbbl
GLJ
H1
Page: 117 of 144
Petroleum Consultants

Property :Coora Block
1 10 100 1000
Daily Oil Cal Day (bbl/d)
0 25 50 75 100 125 150 175 200 225 250
Daily Oil (bbl/d)
Historical and Forecast Production
3) Replacement Wells
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
B2
Year
Projections Illustrate
Production Forecast
0 100 200 300 400 500 600 700 800
Total Reserves Summary @ 2010/09/01
Reserves ( Mbbl )
Reserves
Classification Ultimate Cum Production Remaining
Pv UDev B2(R) 184 0 184
P + P UDev H2(R) 615 0 615
3) Replacement Wells
1110792 / Jan 27, 2011
Cumulative Oil (Mbbl)
H2
Projections Illustrate
Production Forecast
Average Production Rates (Last 12 months ending 2010/09/01)
Gas : 0.0 Mcf/d 0.0 Mcf/cd WGR : 0.0 bbl/MMcf
Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/bbl
On Prod : 0.0 days WC : 0.0 %
Cumulative Production
Oil : 0.0 Mbbl Gas : 0.0 MMcf Water : 0.0 Mbbl
GLJ
H2
B2
Page: 118 of 144
Petroleum Consultants

Property :Coora Block
1 10 100 1000
Daily Oil Cal Day (bbl/d)
Historical and Forecast Production
Location F
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Decline Analysis Summary @ 2010/09/01
Reserves ( Mbbl ) Rates ( bbl/d ) Decline
Reserves
Classification Ultimate Cum Prd Remain Initial Final Initial Expont
Pv UDev B2... 184 0 184 80 5 18.6% 0.40
P + P UDev H... 241 0 241 100 5 18.3% 0.40
Year
Projections Illustrate
Production Forecast
Average Production Rates (Last 12 months ending 2010/09/01)
Gas : 0.0 Mcf/d 0.0 Mcf/cd WGR : 0.0 bbl/M...
Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/bbl
On Prod : 0.0 days WC : 0.0 %
Cumulative Production
Oil : 0.0 Mbbl Gas : 0.0 MMcf Water : 0.0 Mbbl
Entity: Location F Effective date: August 31, 2010
Zone:
Location F
1110792 / Jan 27, 2011
Oil Volumetric Reservoir Parameters
H2
B2 Proved Plus Probable
Proved Undeveloped Undeveloped
Original Oil In-Place Mbbl 3865 3865
Recovery Factor % 4.8 6.2
Original Oil Resources Mbbl 183.9 240.9
Remaining Oil Resources Mbbl 183.9 240.9
GLJ
H2
B2
Page: 119 of 144
Petroleum Consultants

Property :Coora Block
Historical and Forecast Production
Location F
Entity: 2) F-TC Effective date: August 31, 2010
Zone: Top Cruse
Oil Volumetric Reservoir Parameters
H2
B2 Proved Plus Probable
Proved Undeveloped Undeveloped
Area acre 15 15
Net Pay ft 12.0 12.0
Porosity % 30.0 30.0
Water Saturation % 25.0 25.0
Formation Volume Factor 1.12 1.12
Oil Gravity oAPI 24 24
Original Oil In-Place Mbbl 281 281
Recovery Factor % 5.0 7.0
Original Oil Reserves Mbbl 14.0 19.6
Remaining Oil Reserves Mbbl 14.0 19.6
Entity: 3) F-CR2 Effective date: August 31, 2010
Zone: Cruse 2
Oil Volumetric Reservoir Parameters
H2
B2 Proved Plus Probable
Proved Undeveloped Undeveloped
Area acre 20 20
Net Pay ft 30.0 30.0
Porosity % 30.0 30.0
Water Saturation % 25.0 25.0
Formation Volume Factor 1.12 1.12
Oil Gravity oAPI 24 24
Original Oil In-Place Mbbl 935 935
Recovery Factor % 4.0 5.0
Original Oil Reserves Mbbl 37.4 46.8
Remaining Oil Reserves Mbbl 37.4 46.8
Entity: 4) F-CR5 Effective date: August 31, 2010
Zone: Cruse 5
Location F
1110792 / Jan 27, 2011
Oil Volumetric Reservoir Parameters
H2
B2 Proved Plus Probable
Proved Undeveloped Undeveloped
Area acre 20 20
Net Pay ft 35.0 35.0
Porosity % 30.0 30.0
Water Saturation % 25.0 25.0
Formation Volume Factor 1.12 1.12
Oil Gravity oAPI 24 24
Original Oil In-Place Mbbl 1091 1091
Recovery Factor % 5.0 6.0
Original Oil Reserves Mbbl 54.5 65.5
Remaining Oil Reserves Mbbl 54.5 65.5
GLJ
Page: 120 of 144
Petroleum Consultants

Property :Coora Block
Historical and Forecast Production
Location F
Entity: 5) F-MCR Effective date: August 31, 2010
Zone: Middle Cruse
Location F
1110792 / Jan 27, 2011
Oil Volumetric Reservoir Parameters
H2
B2 Proved Plus Probable
Proved Undeveloped Undeveloped
Area acre 20 20
Net Pay ft 50.0 50.0
Porosity % 30.0 30.0
Water Saturation % 25.0 25.0
Formation Volume Factor 1.12 1.12
Oil Gravity oAPI 24 24
Original Oil In-Place Mbbl 1559 1559
Recovery Factor % 5.0 7.0
Original Oil Resources Mbbl 77.9 109.1
Remaining Oil Resources Mbbl 77.9 109.1
GLJ
Page: 121 of 144
Petroleum Consultants

Property :Coora Block
1 10 100 1000
Daily Oil Cal Day (bbl/d)
Historical and Forecast Production
Location G
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
Decline Analysis Summary @ 2010/09/01
Reserves ( Mbbl ) Rates ( bbl/d ) Decline
Reserves
Classification Ultimate Cum Prd Remain Initial Final Initial Expont
P + P UDev H... 102 0 102 50 5 19.2% 0.40
Year
Projections Illustrate
Production Forecast
Average Production Rates (Last 12 months ending 2010/09/01)
Gas : 0.0 Mcf/d 0.0 Mcf/cd WGR : 0.0 bbl/M...
Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/bbl
On Prod : 0.0 days WC : 0.0 %
Cumulative Production
Oil : 0.0 Mbbl Gas : 0.0 MMcf Water : 0.0 Mbbl
Entity: Location G Effective date: August 31, 2010
Zone:
Location G
1110792 / Jan 27, 2011
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Original Oil In-Place Mbbl 2159
Recovery Factor % 4.7
Original Oil Reserves Mbbl 102.5
Remaining Oil Reserves Mbbl 102.5
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H2
Page: 122 of 144
Petroleum Consultants

Property :Coora Block
Historical and Forecast Production
Location G
Entity: 3) G-CR5 Effective date: August 31, 2010
Zone: Cruse 5
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Area acre 5
Net Pay ft 35.0
Porosity % 30.0
Water Saturation % 25.0
Formation Volume Factor 1.12
Oil Gravity oAPI 24
Original Oil In-Place Mbbl 273
Recovery Factor % 3.0
Original Oil Resources Mbbl 8.2
Remaining Oil Resources Mbbl 8.2
Entity: 2) G-CR2 Effective date: August 31, 2010
Zone: Cruse 2
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Area acre 20
Net Pay ft 50.0
Porosity % 30.0
Water Saturation % 25.0
Formation Volume Factor 1.12
Oil Gravity oAPI 24
Original Oil In-Place Mbbl 1559
Recovery Factor % 5.0
Original Oil Reserves Mbbl 77.9
Remaining Oil Reserves Mbbl 77.9
Entity: 1) G-TC Effective date: August 31, 2010
Zone: Top Cruse
Location G
1110792 / Jan 27, 2011
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Area acre 15
Net Pay ft 14.0
Porosity % 30.0
Water Saturation % 25.0
Formation Volume Factor 1.12
Oil Gravity oAPI 24
Original Oil In-Place Mbbl 327
Recovery Factor % 5.0
Original Oil Reserves Mbbl 16.4
Remaining Oil Reserves Mbbl 16.4
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Petroleum Consultants

Property :Coora Block
1 10 100 1000
Daily Oil Cal Day (bbl/d)
Historical and Forecast Production
Location H
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Decline Analysis Summary @ 2010/09/01
Reserves ( Mbbl ) Rates ( bbl/d ) Decline
Reserves
Classification Ultimate Cum Prd Remain Initial Final Initial Expont
P + P UDev H... 135 0 135 40 5 11.8% 0.40
Year
Projections Illustrate
Production Forecast
Average Production Rates (Last 12 months ending 2010/09/01)
Gas : 0.0 Mcf/d 0.0 Mcf/cd WGR : 0.0 bbl/M...
Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/bbl
On Prod : 0.0 days WC : 0.0 %
Cumulative Production
Oil : 0.0 Mbbl Gas : 0.0 MMcf Water : 0.0 Mbbl
Entity: Location H Effective date: August 31, 2010
Zone:
Location H
1110792 / Jan 27, 2011
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Original Oil In-Place Mbbl 1837
Recovery Factor % 7.4
Original Oil Reserves Mbbl 135.1
Remaining Oil Reserves Mbbl 135.1
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H2
Page: 124 of 144
Petroleum Consultants

Property :Coora Block
Historical and Forecast Production
Location H
Entity: 1) H-UF4 Effective date: August 31, 2010
Zone: Upper Forest 4
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Area acre 10
Net Pay ft 10.0
Porosity % 30.0
Water Saturation % 25.0
Formation Volume Factor 1.06
Oil Gravity oAPI 22
Original Oil In-Place Mbbl 165
Recovery Factor % 11.0
Original Oil Resources Mbbl 18.1
Remaining Oil Resources Mbbl 18.1
Entity: 2) H-UF5 Effective date: August 31, 2010
Zone: Upper Forest 5
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Area acre 20
Net Pay ft 25.0
Porosity % 30.0
Water Saturation % 25.0
Formation Volume Factor 1.06
Oil Gravity oAPI 22
Original Oil In-Place Mbbl 823
Recovery Factor % 7.0
Original Oil Reserves Mbbl 57.6
Remaining Oil Reserves Mbbl 57.6
Entity: 3) H-LF2 Effective date: August 31, 2010
Zone: Lower Forest 2
Location H
1110792 / Jan 27, 2011
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Area acre 15
Net Pay ft 35.0
Porosity % 30.0
Water Saturation % 25.0
Formation Volume Factor 1.08
Oil Gravity oAPI 22
Original Oil In-Place Mbbl 849
Recovery Factor % 7.0
Original Oil Reserves Mbbl 59.4
Remaining Oil Reserves Mbbl 59.4
GLJ
Page: 125 of 144
Petroleum Consultants

Property :Coora Block
1 10 100 1000
Daily Oil Cal Day (bbl/d)
Historical and Forecast Production
Location L
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Decline Analysis Summary @ 2010/09/01
Reserves ( Mbbl ) Rates ( bbl/d ) Decline
Reserves
Classification Ultimate Cum Prd Remain Initial Final Initial Expont
P + P UDev H... 136 0 136 40 5 11.7% 0.40
Year
Projections Illustrate
Production Forecast
Average Production Rates (Last 12 months ending 2010/09/01)
Gas : 0.0 Mcf/d 0.0 Mcf/cd WGR : 0.0 bbl/M...
Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/bbl
On Prod : 0.0 days WC : 0.0 %
Cumulative Production
Oil : 0.0 Mbbl Gas : 0.0 MMcf Water : 0.0 Mbbl
Entity: Location L Effective date: August 31, 2010
Zone:
Location L
1110792 / Jan 27, 2011
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Original Oil In-Place Mbbl 2455
Recovery Factor % 5.6
Original Oil Reserves Mbbl 136.4
Remaining Oil Reserves Mbbl 136.4
GLJ
H2
Page: 126 of 144
Petroleum Consultants

Property :Coora Block
Historical and Forecast Production
Location L
Entity: L-CR7 Effective date: August 31, 2010
Zone: Cruise 7
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Area acre 20
Net Pay ft 35.0
Porosity % 30.0
Water Saturation % 25.0
Formation Volume Factor 1.12
Oil Gravity oAPI 24
Original Oil In-Place Mbbl 1091
Recovery Factor % 5.0
Original Oil Resources Mbbl 54.5
Remaining Oil Resources Mbbl 54.5
Entity: L-CR5 Effective date: August 31, 2010
Zone: Cruise 5
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Area acre 5
Net Pay ft 35.0
Porosity % 30.0
Water Saturation % 25.0
Formation Volume Factor 1.12
Oil Gravity oAPI 24
Original Oil In-Place Mbbl 273
Recovery Factor % 6.0
Original Oil Reserves Mbbl 16.4
Remaining Oil Reserves Mbbl 16.4
Entity: L-MCR Effective date: August 31, 2010
Zone: Middle Cruse
Location L
1110792 / Jan 27, 2011
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Area acre 20
Net Pay ft 35.0
Porosity % 30.0
Water Saturation % 25.0
Formation Volume Factor 1.12
Oil Gravity oAPI 24
Original Oil In-Place Mbbl 1091
Recovery Factor % 6.0
Original Oil Reserves Mbbl 65.5
Remaining Oil Reserves Mbbl 65.5
GLJ
Page: 127 of 144
Petroleum Consultants

Property :Coora Block
1 10 100 1000
Daily Oil Cal Day (bbl/d)
0 40 80 120 160 200 240 280 320 360 400
Daily Oil (bbl/d)
Historical and Forecast Production
4) Sidetrack Wells
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Year
Projections Illustrate
Production Forecast
B2
H2
0 100 200 300 400 500 600 700 800
Total Reserves Summary @ 2010/09/01
Reserves ( Mbbl )
Reserves
Classification Ultimate Cum Production Remaining
Pv UDev B2(R) 152 0 152
P + P UDev H2(R) 728 0 728
4) Sidetrack Wells
1110792 / Jan 27, 2011
Cumulative Oil (Mbbl)
Projections Illustrate
Production Forecast
Average Production Rates (Last 12 months ending 2010/09/01)
Gas : 0.0 Mcf/d 0.0 Mcf/cd WGR : 0.0 bbl/MMcf
Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/bbl
On Prod : 0.0 days WC : 0.0 %
Cumulative Production
Oil : 0.0 Mbbl Gas : 0.0 MMcf Water : 0.0 Mbbl
GLJ
H2
B2
Page: 128 of 144
Petroleum Consultants

Property :Coora Block
1 10 100 1000
Daily Oil Cal Day (bbl/d)
Historical and Forecast Production
CO-180 Sidetrack
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Decline Analysis Summary @ 2010/09/01
Reserves ( Mbbl ) Rates ( bbl/d ) Decline
Reserves
Classification Ultimate Cum Prd Remain Initial Final Initial Expont
P + P UDev H... 141 0 141 80 5 23.3% 0.40
Year
Projections Illustrate
Production Forecast
Average Production Rates (Last 12 months ending 2010/09/01)
Gas : 0.0 Mcf/d 0.0 Mcf/cd WGR : 0.0 bbl/M...
Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/bbl
On Prod : 0.0 days WC : 0.0 %
Cumulative Production
Oil : 0.0 Mbbl Gas : 0.0 MMcf Water : 0.0 Mbbl
Entity: CO-180 Sidetrack Effective date: August 31, 2010
Zone:
CO-180 Sidetrack
1110792 / Jan 27, 2011
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Original Oil In-Place Mbbl 2353
Recovery Factor % 6.0
Original Oil Reserves Mbbl 141.2
Remaining Oil Reserves Mbbl 141.2
GLJ
H2
Page: 129 of 144
Petroleum Consultants

Property :Coora Block
Historical and Forecast Production
CO-180 Sidetrack
Entity: MC Effective date: August 31, 2010
Zone: Middle Cruse
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Area acre 20
Net Pay ft 60.0
Porosity % 30.0
Water Saturation % 25.0
Formation Volume Factor 1.12
Oil Gravity oAPI 24
Original Oil In-Place Mbbl 1870
Recovery Factor % 6.0
Original Oil Reserves Mbbl 112.2
Remaining Oil Reserves Mbbl 112.2
Entity: CR5 Effective date: August 31, 2010
Zone: Cruse 5
CO-180 Sidetrack
1110792 / Jan 27, 2011
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Area acre 5
Net Pay ft 62.0
Porosity % 30.0
Water Saturation % 25.0
Formation Volume Factor 1.12
Oil Gravity oAPI 24
Original Oil In-Place Mbbl 483
Recovery Factor % 6.0
Original Oil Reserves Mbbl 29.0
Remaining Oil Reserves Mbbl 29.0
GLJ
Page: 130 of 144
Petroleum Consultants

Property :Coora Block
1 10 100 1000
Daily Oil Cal Day (bbl/d)
Historical and Forecast Production
CO-362 Sidetrack
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Decline Analysis Summary @ 2010/09/01
Reserves ( Mbbl ) Rates ( bbl/d ) Decline
Reserves
Classification Ultimate Cum Prd Remain Initial Final Initial Expont
Pv UDev B2... 152 0 152 50 5 13.6% 0.40
P + P UDev H... 194 0 194 60 5 13.2% 0.40
Year
Projections Illustrate
Production Forecast
Average Production Rates (Last 12 months ending 2010/09/01)
Gas : 0.0 Mcf/d 0.0 Mcf/cd WGR : 0.0 bbl/M...
Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/bbl
On Prod : 0.0 days WC : 0.0 %
Cumulative Production
Oil : 0.0 Mbbl Gas : 0.0 MMcf Water : 0.0 Mbbl
Entity: CO-362 Sidetrack Effective date: August 31, 2010
Zone:
CO-362 Sidetrack
1110792 / Jan 27, 2011
Oil Volumetric Reservoir Parameters
H2
B2 Proved Plus Probable
Proved Undeveloped Undeveloped
Original Oil In-Place Mbbl 2517 2517
Recovery Factor % 6.0 7.7
Original Oil Reserves Mbbl 151.9 194.1
Remaining Oil Reserves Mbbl 151.9 194.1
GLJ
H2
B2
Page: 131 of 144
Petroleum Consultants

Property :Coora Block
Historical and Forecast Production
CO-362 Sidetrack
Entity: 6) A-MCR3 Effective date: August 31, 2010
Zone: Middle Cruse 3
Oil Volumetric Reservoir Parameters
H2
B2 Proved Plus Probable
Proved Undeveloped Undeveloped
Area acre 20 20
Net Pay ft 20.0 20.0
Porosity % 30.0 30.0
Water Saturation % 25.0 25.0
Formation Volume Factor 1.12 1.12
Oil Gravity oAPI 24 24
Original Oil In-Place Mbbl 623 623
Recovery Factor % 7.0 9.0
Original Oil Reserves Mbbl 43.6 56.1
Remaining Oil Reserves Mbbl 43.6 56.1
Entity: 4) A-CR5 Effective date: August 31, 2010
Zone: Cruse 5
Oil Volumetric Reservoir Parameters
H2
B2 Proved Plus Probable
Proved Undeveloped Undeveloped
Area acre 20 20
Net Pay ft 15.0 15.0
Porosity % 30.0 30.0
Water Saturation % 25.0 25.0
Formation Volume Factor 1.12 1.12
Oil Gravity oAPI 24 24
Original Oil In-Place Mbbl 468 468
Recovery Factor % 5.0 7.0
Original Oil Reserves Mbbl 23.4 32.7
Remaining Oil Reserves Mbbl 23.4 32.7
Entity: 1) A-UF5 Effective date: August 31, 2010
Zone: Upper Forest 5
CO-362 Sidetrack
1110792 / Jan 27, 2011
Oil Volumetric Reservoir Parameters
H2
B2 Proved Plus Probable
Proved Undeveloped Undeveloped
Area acre 15 15
Net Pay ft 15.0 15.0
Porosity % 30.0 30.0
Water Saturation % 25.0 25.0
Formation Volume Factor 1.06 1.06
Oil Gravity oAPI 22 22
Original Oil In-Place Mbbl 371 371
Recovery Factor % 8.0 10.0
Original Oil Reserves Mbbl 29.6 37.1
Remaining Oil Reserves Mbbl 29.6 37.1
GLJ
Page: 132 of 144
Petroleum Consultants

Property :Coora Block
Historical and Forecast Production
CO-362 Sidetrack
Entity: 2) A-UF8 Effective date: August 31, 2010
Zone: Upper Forest 8
Oil Volumetric Reservoir Parameters
H2
B2 Proved Plus Probable
Proved Undeveloped Undeveloped
Area acre 10 10
Net Pay ft 15.0 15.0
Porosity % 30.0 30.0
Water Saturation % 25.0 25.0
Formation Volume Factor 1.06 1.06
Oil Gravity oAPI 22 22
Original Oil In-Place Mbbl 247 247
Recovery Factor % 6.0 8.0
Original Oil Reserves Mbbl 14.8 19.8
Remaining Oil Reserves Mbbl 14.8 19.8
Entity: 3) A-LF8 Effective date: August 31, 2010
Zone: Lower Forest 8
CO-362 Sidetrack
1110792 / Jan 27, 2011
Oil Volumetric Reservoir Parameters
H2
B2 Proved Plus Probable
Proved Undeveloped Undeveloped
Area acre 10 10
Net Pay ft 50.0 50.0
Porosity % 30.0 30.0
Water Saturation % 25.0 25.0
Formation Volume Factor 1.08 1.08
Oil Gravity oAPI 22 22
Original Oil In-Place Mbbl 808 808
Recovery Factor % 5.0 6.0
Original Oil Resources Mbbl 40.4 48.5
Remaining Oil Resources Mbbl 40.4 48.5
GLJ
Page: 133 of 144
Petroleum Consultants

Property :Coora Block
1 10 100 1000
Daily Oil Cal Day (bbl/d)
Historical and Forecast Production
QU-080 Sidetrack
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Decline Analysis Summary @ 2010/09/01
Reserves ( Mbbl ) Rates ( bbl/d ) Decline
Reserves
Classification Ultimate Cum Prd Remain Initial Final Initial Expont
P + P UDev H... 186 0 186 80 5 18.4% 0.40
Year
Projections Illustrate
Production Forecast
Average Production Rates (Last 12 months ending 2010/09/01)
Gas : 0.0 Mcf/d 0.0 Mcf/cd WGR : 0.0 bbl/M...
Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/bbl
On Prod : 0.0 days WC : 0.0 %
Cumulative Production
Oil : 0.0 Mbbl Gas : 0.0 MMcf Water : 0.0 Mbbl
Entity: QU-080 Sidetrack Effective date: August 31, 2010
Zone:
QU-080 Sidetrack
1110792 / Jan 27, 2011
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Original Oil In-Place Mbbl 3148
Recovery Factor % 5.9
Original Oil Reserves Mbbl 186.1
Remaining Oil Reserves Mbbl 186.1
GLJ
H2
Page: 134 of 144
Petroleum Consultants

Property :Coora Block
Historical and Forecast Production
QU-080 Sidetrack
Entity: 2) D-TC Effective date: August 31, 2010
Zone: Top Cruse
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Area acre 15
Net Pay ft 8.0
Porosity % 30.0
Water Saturation % 25.0
Formation Volume Factor 1.12
Oil Gravity oAPI 24
Original Oil In-Place Mbbl 187
Recovery Factor % 7.0
Original Oil Resources Mbbl 13.1
Remaining Oil Resources Mbbl 13.1
Entity: 3) D-CR2 Effective date: August 31, 2010
Zone: Cruse 2
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Area acre 20
Net Pay ft 45.0
Porosity % 30.0
Water Saturation % 25.0
Formation Volume Factor 1.12
Oil Gravity oAPI 24
Original Oil In-Place Mbbl 1403
Recovery Factor % 5.0
Original Oil Reserves Mbbl 70.1
Remaining Oil Reserves Mbbl 70.1
Entity: 4) D-CR5 Effective date: August 31, 2010
Zone: Cruse 5
QU-080 Sidetrack
1110792 / Jan 27, 2011
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Area acre 20
Net Pay ft 20.0
Porosity % 30.0
Water Saturation % 25.0
Formation Volume Factor 1.12
Oil Gravity oAPI 24
Original Oil In-Place Mbbl 623
Recovery Factor % 6.0
Original Oil Reserves Mbbl 37.4
Remaining Oil Reserves Mbbl 37.4
GLJ
Page: 135 of 144
Petroleum Consultants

Property :Coora Block
Historical and Forecast Production
QU-080 Sidetrack
Entity: 5) D-MCR Effective date: August 31, 2010
Zone: Middle Cruse
QU-080 Sidetrack
1110792 / Jan 27, 2011
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Area acre 20
Net Pay ft 30.0
Porosity % 30.0
Water Saturation % 25.0
Formation Volume Factor 1.12
Oil Gravity oAPI 24
Original Oil In-Place Mbbl 935
Recovery Factor % 7.0
Original Oil Resources Mbbl 65.5
Remaining Oil Resources Mbbl 65.5
GLJ
Page: 136 of 144
Petroleum Consultants

Property :Coora Block
1 10 100 1000
Daily Oil Cal Day (bbl/d)
Historical and Forecast Production
QU-119 Sidetrack
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
Decline Analysis Summary @ 2010/09/01
Reserves ( Mbbl ) Rates ( bbl/d ) Decline
Reserves
Classification Ultimate Cum Prd Remain Initial Final Initial Expont
P + P UDev H... 77 0 77 40 5 19.5% 0.40
Year
Projections Illustrate
Production Forecast
Average Production Rates (Last 12 months ending 2010/09/01)
Gas : 0.0 Mcf/d 0.0 Mcf/cd WGR : 0.0 bbl/M...
Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/bbl
On Prod : 0.0 days WC : 0.0 %
Cumulative Production
Oil : 0.0 Mbbl Gas : 0.0 MMcf Water : 0.0 Mbbl
Entity: QU-119 Sidetrack Effective date: August 31, 2010
Zone:
QU-119 Sidetrack
1110792 / Jan 27, 2011
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Original Oil In-Place Mbbl 1247
Recovery Factor % 6.2
Original Oil Reserves Mbbl 76.7
Remaining Oil Reserves Mbbl 76.7
GLJ
H2
Page: 137 of 144
Petroleum Consultants

Property :Coora Block
Historical and Forecast Production
QU-119 Sidetrack
Entity: 1) MC Effective date: August 31, 2010
Zone: Middle Cruse
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Area acre 20
Net Pay ft 23.0
Porosity % 30.0
Water Saturation % 25.0
Formation Volume Factor 1.12
Oil Gravity oAPI 24
Original Oil In-Place Mbbl 717
Recovery Factor % 7.0
Original Oil Reserves Mbbl 50.2
Remaining Oil Reserves Mbbl 50.2
Entity: 2) CR7 Effective date: August 31, 2010
Zone: Cruse 7
QU-119 Sidetrack
1110792 / Jan 27, 2011
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Area acre 20
Net Pay ft 17.0
Porosity % 30.0
Water Saturation % 25.0
Formation Volume Factor 1.12
Oil Gravity oAPI 24
Original Oil In-Place Mbbl 530
Recovery Factor % 5.0
Original Oil Reserves Mbbl 26.5
Remaining Oil Reserves Mbbl 26.5
GLJ
Page: 138 of 144
Petroleum Consultants

Property :Coora Block
1 10 100 1000
Daily Oil Cal Day (bbl/d)
Historical and Forecast Production
QU-428 Sidetrack
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
Decline Analysis Summary @ 2010/09/01
Reserves ( Mbbl ) Rates ( bbl/d ) Decline
Reserves
Classification Ultimate Cum Prd Remain Initial Final Initial Expont
P + P UDev H... 130 0 130 90 5 27.8% 0.40
Year
Projections Illustrate
Production Forecast
Average Production Rates (Last 12 months ending 2010/09/01)
Gas : 0.0 Mcf/d 0.0 Mcf/cd WGR : 0.0 bbl/M...
Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/bbl
On Prod : 0.0 days WC : 0.0 %
Cumulative Production
Oil : 0.0 Mbbl Gas : 0.0 MMcf Water : 0.0 Mbbl
Entity: QU-428 Sidetrack Effective date: August 31, 2010
Zone:
QU-428 Sidetrack
1110792 / Jan 27, 2011
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Original Oil In-Place Mbbl 1347
Recovery Factor % 9.6
Original Oil Reserves Mbbl 129.7
Remaining Oil Reserves Mbbl 129.7
GLJ
H2
Page: 139 of 144
Petroleum Consultants

Property :Coora Block
Historical and Forecast Production
QU-428 Sidetrack
Entity: 1) P-CR4 Effective date: August 31, 2010
Zone: Cruse 4
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Area acre 20
Net Pay ft 25.0
Porosity % 30.0
Water Saturation % 40.0
Formation Volume Factor 1.12
Oil Gravity oAPI 24
Original Oil In-Place Mbbl 623
Recovery Factor % 15.0
Original Oil Reserves Mbbl 93.5
Remaining Oil Reserves Mbbl 93.5
Entity: 2) P-CR5 Effective date: August 31, 2010
Zone: Cruse 5
Oil Volumetric Reservoir Parameters
H2
Proved Plus Probable
Undeveloped
Area acre 10
Net Pay ft 67.0
Porosity % 26.0
Water Saturation % 40.0
Formation Volume Factor 1.12
Oil Gravity oAPI 24
Original Oil In-Place Mbbl 724
Recovery Factor % 5.0
Original Oil Reserves Mbbl 36.2
Remaining Oil Reserves Mbbl 36.2
Entity: 3) P-LCR Effective date: August 31, 2010
Zone: Lower Cruse
Oil Volumetric Reservoir Parameters
Remaining Oil Reserves Mbbl
QU-428 Sidetrack
1110792 / Jan 27, 2011
GLJ
Page: 140 of 144
Petroleum Consultants

APPENDIX II
CERTIFICATES OF QUALIFICATION
Jodi L. Anhorn
T. Mark Jobin
Scott M. Quinell
GLJ
Page: 141 of 144
Petroleum Consultants

CERTIFICATION OF QUALIFICATION
I, Jodi L. Anhorn, Professional Engineer, 4100, 400 - 3rd 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 Coora Block property of Touchstone Exploration Inc. The effective
date of this evaluation is August 31, 2010.
2. That I do not have, nor do I expect to receive any direct or indirect interest in the securities of
Touchstone Exploration Inc. or its affiliated companies.
3. That I attended the University of Calgary and that I graduated with a Master of Science
Degree in Chemical and Petroleum Engineering in 1992; that I am a Registered Professional
Engineer in the Province of Alberta; and that I have in excess of eighteen years experience in
engineering studies relating to Western Canadian and International 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 Touchstone Exploration Inc., and the appropriate provincial
regulatory authorities.
ORIGINALLY SIGNED BY
Page: 142 of 144
Jodi L. Anhorn, M.Sc., P. Eng.
GLJ
Petroleum Consultants

CERTIFICATION OF QUALIFICATION
I, T. Mark Jobin, Professional Geologist, 4100, 400 - 3rd 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 Coora Block property for Touchstone Exploration Inc. The effective
date of this evaluation is August 31, 2010.
2. That I do not have, nor do I expect to receive any direct or indirect interest in the securities of
Touchstone Exploration Inc. or its affiliated companies.
3. That I attended the University of Calgary and that I graduated in 1984 with a Bachelor of
Science Degree in Geology; that I am a Registered Professional Geologist in the Province of
Alberta; and, that I have in excess of twenty-six years experience in geological studies
relating to Canadian and International 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 Touchstone Exploration Inc., and the appropriate provincial
regulatory authorities.
Page: 143 of 144
ORIGINALLY SIGNED BY
T. Mark Jobin, P. Geol.
GLJ
Petroleum Consultants

CERTIFICATION OF QUALIFICATION
I, Scott M. Quinell, Professional Engineer, 4100, 400 - 3rd Avenue S.W., Calgary, Alberta, Canada
hereby certify:
1. That I am an employee of GLJ Petroleum Consultants Ltd., which company did prepare an
independent evaluation of the Coora Block property of Touchstone Exploration Inc. The
effective date of this evaluation is August 31, 2010.
2. That I do not have, nor do I expect to receive any direct or indirect interest in the securities of
Touchstone Exploration Inc. or its affiliated companies.
3. That I attended the University of Alberta where I graduated with a Bachelor of Science
Degree in Petroleum Engineering in 2006; and, that I am an Registered Professional
Engineer in the Province of Alberta; and, that I have in excess of four years of experience in
engineering studies relating to Western Canadian 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 Touchstone Exploration Inc., and the appropriate provincial
regulatory authorities.
ORIGINALLY SIGNED BY
Page: 144 of 144
Scott M. Quinell, P. Eng.
GLJ
Petroleum Consultants