- 1 -

The following is a summary of the oil and natural gas reserves and the value of future net revenue of
Nordic Oil and Gas Ltd. (the "Company") as evaluated by Chapman Petroleum Engineering Ltd.
(“Chapman”) as at December 31, 2013, and dated April 24, 2014 (the "Chapman Report"). Chapman is an independent qualified reserves evaluator and auditor.
All evaluations of future revenue are after the deduction of future income tax expenses, unless otherwise noted in the tables, royalties, development costs, production costs and well abandonment costs but before consideration of indirect costs such as administrative, overhead and other miscellaneous expenses. The estimated future net revenue contained in the following tables does not necessarily represent the fair market value of the Company's reserves. There is no assurance that the forecast price and cost assumptions contained in the Chapman Report will be attained and variances could be material. Other assumptions and qualifications relating to costs and other matters are included in the Chapman Report. The recovery and reserves estimates on the Company's properties described herein are estimates only. The actual reserves on the Company's properties may be greater or less than those calculated.
All monetary values presented in this document are expressed in terms of Canadian dollars.
SUMMARY OF OIL AND GAS RESERVES
BASED ON FORECAST PRICES AND COSTS
AS AT DECEMBER 31, 2013
Company Reserves
(1)
Light & Medium Oil Heavy Oil Natural Gas* [9] CBM Natural Gas Liquids
Gross Net Gross Net Gross Net Gross Net Gross Net
Reserves Category MSTB MSTB MSTB MSTB MMscf MMscf MMscf MMscf Mbbl Mbbl
PROVED
Developed Producing
(2)(6)
Developed Non-Producing (2)(7)
0 0 22 21 64 59 188 177 0
0 0 0 0 404 348 127 122 0
Undeveloped (2)(8)
TOTAL PROVED (2)
TOTAL PROBABLE (3)
0 0 0 0 0 0 1,897 1,728 0
0 0 22 21 468 407 2,212 2,027 0
132 117 67 46 2,156 1,938 2,157 1,963 0
TOTAL PROVED + PROBABLE (2)(3) 132 117 89 66 2,624 2,345 4,369 3,990 1
0
0
0
0
0
1
Notes: [*] Includes associated, non-associated and solution gas where applicable.
- 2 -

SUMMARY OF NET PRESENT VALUES
BASED ON FORECAST PRICES AND COSTS
AS AT DECEMBER 31, 2013
Reserves Category
PROVED
Developed Producing (2)(6)
Developed Non-Producing (2)(7)
Undeveloped (2)(8)
TOTAL PROVED (2)
TOTAL PROBABLE
(3)
TOTAL PROVED +
PROBABLE (2)(3)
Net Present Values of Future Net Revenue
Before Income Tax
Discounted at
After Income Tax
Discounted at
0%/yr 5%/yr. 10%/yr. 15%/yr. 20%/ yr.
$M $M $M $M
0%/yr
$M $M
5%/yr.
$M
10%/yr.
$M
15%/yr.
$M
20%/yr.
$M
1,189 964 809 697 614 1,189 964 809 697 614
1,464 1,116 887 727 613 1,464 1,116 887 727 613
3,496 2,077 1,171 576 172 3,496 2,077 1,171 576 172
6,149 4,158 2,866 2,000 1,400 6,149 4,158 2,866 2,000 1,400
20,938 13,422 9,371 6,945 5,361 16,119 10,597 7,560 5,705 4,469
27,087 17,580 12,238 8,945 6,761 22,268 14,755 10,427 7,705 5,869
Revenue
($M)
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
BASED ON FORECAST PRICES AND COSTS
AS AT DECEMBER 31, 2013
Royalties
($M)
Operating
Costs
($M)
Development
Costs
($M)
Abandonment and
Reclamation
Costs
($M)
Future
Net Revenue
Before
Income Taxes
($M)
Total Proved (2)
Total Proved Plus
Probable (2)(3)
13,994 1,251 3,132 2,509
51,257 5,944 11,577 5,241
953
1,409
6,149
Income
Taxes
($M)
0
Future
Net
Revenue After
Income Taxes
($M)
6,149
27,087 (4,819) 22,268
FUTURE NET REVENUE BY PRODUCTION GROUP
BASED ON FORECAST PRICES AND COSTS
AS AT DECEMBER 31, 2013
Reserve Category
Total Proved (2)
Production Group
Light and Medium Oil (including solution gas and other by-products)
Heavy Oil (including solution gas and other by-products)
Future Net Revenue Before
Income Taxes (Discounted at 10%/Year)
($M)
0
487
Natural Gas (including by-products but not solution gas)
Coal Bed Methane
Total Proved Plus Probable
(2)(3)
Light and Medium Oil (including solution gas and other by-products)
647
1,732
4,083
Heavy Oil (including solution gas and other by-products) 995
Natural Gas (including by-products but not solution gas) 2,528
Coal Bed Methane
4,631
- 3 -

OIL AND GAS RESERVES AND NET PRESENT VALUES BY PRODUCTION GROUP
BASED ON FORECAST PRICES AND COSTS
AS AT DECEMBER 31, 2013
Reserves Net Present Unit Values
Oil Gas
(9)
NGL
Reserve Group by Category Gross Net Gross Net Gross Net
Value (BIT) @ 10%/yr
10%
MSTB MSTB MMscf MMscf Mbbl Mbbl M$
$/STB
Light and Medium Oil [A]
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Proved Plus Probable
Heavy Oil [A]
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Proved Plus Probable
Assoc & Non-Assoc Gas
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Proved Plus Probable
Coal Bed Methane
Proved
Developed Producing
0 0 0
0 0 0
0 0 0
0 0 0
132 117 0
132 117 0
22 21 0
0 0 0
0 0 0
22 21 0
67 46 0
89 66 0
0 0 64 59
0 0 404 348
0 0 0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 0 468 407
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0 2,156 1,938 0 0
0 0 2,625 2,346 1 1
Developed Non-Producing
Undeveloped
Total Proved
Probable
0 0 188 177
0 0 127 122
0 0 1,897 1,728 0 0
0
0
0
0
2,212 2,027
2,157 1,962
0 0
0 0
0
0
0
0
Proved Plus Probable
Reference: Item 2.2 (3)© NI 51-101F1
0 0 4,369 3,989 0 0
M$ means thousands of dollars
Columns may not add precisely due to accumulative rounding of values throughout the report
Reserves s hown as “0” reflect a value if less than 0.5 (MSTB/MMscf/Mbbl)
Notes: [A] Includes solution gas.
0
0
0
0
4,083
4,083
487
0
0
487
509
23.56
11.03
995 15.12
$/Mscf
(4)
650
0
-0.07
1.87
N/A
647
1,882
2,528
1.59
0.97
1.08
N/A
N/A
N/A
N/A
34.76
34.76
23.56
N/A
N/A
326
236
1,171
1,732
$/Mscf
1.84
1.93
0.68
0.85
2,900
4,631
1.48
1.16
- 4 -

Notes:
1. "Gross Reserves" are the Company's working interest (operating or non-operating) share before deducting of royalties and without including any royalty interests of the Company. "Net Reserves" are the Company's working interest (operating or nonoperating) share after deduction of royalty obligations, plus the Company's royalty interests in reserves.
2. "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.
3. "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.
4. "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.
5. "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.
6. "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.
7. "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.
8. "Undeveloped" reserves are those reserves expected to be recovered from know 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 classification (proved, probable, possible) to which they are assigned.
9. Includes associated, non-associated and solution gas where applicable.
- 5 -

The following tables detail the benchmark reference prices for the regions in which the Company operated, as at December 31, 2013, reflected in the reserves data disclosed above under “Part 2 –
Disclosure of Reserves Data ”. The forecast price assumptions assume the continuance of current laws and regulations and take into account inflation with respect to future operating and capital costs.
There will be adjustments to field prices from the benchmarks below:
CRUDE OIL
HISTORICAL, CONSTANT, CURRENT AND FUTURE PRICES
January 1, 2014
Date
HISTORICAL PRICES
2004
2005
2006
41.48
56.62
65.91
2007
2008
2009
2010
2011
2012
72.35
99.70
61.64
79.42
95.03
94.16
2013
AB Synthetic
WTI [1] Crude Price [2]
$US/STB $CDN/STB
97.93
52.89
69.16
72.88
75.57
102.98
76.77
80.56
102.45
92.56
100.17
Western Canada
Select [3]
$CDN/STB
Sask. Sask. B.C. Exchange
Light [4] Heavy [5] Light [6] Rate
$CDN/STB $CDN/STB $CDN/STB $US/$CDN
37.52
43.25
50.40
53.17
83.88
53.04
66.58
77.43
71.70
75.76
48.96
62.04
66.77
71.42
98.02
72.56
77.02
92.42
84.58
91.82
45.74
56.53
61.23
64.55
92.45
64.37
72.79
83.44
77.58
82.70 n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a
0.77
0.83
0.88
0.94
0.94
0.88
0.97
1.01
1.00
0.97
CONSTANT PRICES (The average of the first-day-of-the-month price for the preceding 12 months-SEC)
97.47
FORECAST PRICES
99.76 74.80 95.76 86.87 97.27
2014
2015
95.00
90.00
99.00
93.74
75.24
71.24
90.09
85.30
81.08
76.77
96.53
91.39
2016
2017
2018
2019
2020
2021
90.00
96.00
97.00
98.00
100.00
100.00
93.74
100.05
101.11
102.16
104.26
104.26
71.24
76.04
76.84
77.64
79.24
79.24
85.30
91.05
92.01
92.96
94.88
94.88
76.77
81.94
82.81
83.67
85.39
85.39
91.39
97.55
98.58
99.60
101.66
101.66
2022
2023
2024
2025
2026
2027
2028
2029
102.00
104.04
106.12
108.24
110.41
112.62
114.87
117.17
106.37
108.52
110.71
112.94
115.22
117.54
119.91
122.33
80.84
82.47
84.14
85.83
87.57
89.33
91.13
92.97
96.80
98.75
100.74
102.78
104.85
106.96
109.12
111.32
87.12
88.87
90.67
92.50
94.36
96.27
98.21
100.19
103.71
105.80
107.94
110.12
112.34
114.60
116.92
119.27
0.97
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
Constant thereafter
Notes: [1] West Texas Intermediate quality (D2/S2) crude (40API)landed in Cushing, Oklahoma.
[2] Equivalent price for Light Sweet Crude (D2/S2) & Synthetic Crude (34API)landed in Edmonton.
[3]
[4]
[5]
[6]
Western Canada Select (20.5API)
Light Sour Blend at Cromer, Saskatchewan (850 kg/m3, 1.2% sulphur).
Midale at Cromer, Saskatchewan (880 kg/m3, 2.0% sulphur).
B.C. Light at Taylor, British Columbia (825 kg/m3, 0.5% sulphur).
- 6 -

NATURAL GAS & BY-PRODUCTS
HISTORICAL, CONSTANT, CURRENT AND FUTURE PRICES
January 1, 2014
Date
GRP [1]
AECO Spot
Gas
Sask.
Gas [2]
B.C. Pentanes NGL
Gas [3] Propane [4] Butane [4] Plus [4] Mix [5]
$/MMBTU $/GJ $/MMBTU $/MMBTU $/MMBTU $/BBL $/BBL $/BBL $/BBL
HISTORICAL PRICES
2004
2005
2006
6.31
8.31
6.57
2007
2008
2009
2010
6.21
7.89
3.85
3.93
2011
2012
2013
3.46
2.25
3.00
5.98
7.87
6.22
5.88
7.47
3.65
3.73
3.28
2.13
2.84
6.60
8.82
6.55
6.47
8.17
3.99
4.02
3.63
2.39
3.17
6.56
8.56
6.82
6.46
8.14
4.10
4.18
3.71
2.50
3.17
6.25
8.31
6.57
6.21
8.61
4.35
4.25
3.85
2.68
3.82
31.95
38.54
44.09
49.53
58.80
38.34
44.40
50.17
47.40
50.09
38.40
45.20
59.32
63.71
75.09
49.34
57.99
70.93
64.48
91.43
54.06
69.32
76.08
105.08
104.75
67.52
77.51
97.21
96.26
100.72
40.52
49.90
53.54
70.45
77.47
50.39
58.41
70.51
67.18
77.68
CONSTANT PRICES (The average of the first-day-of-the-month price for the preceding 12 months-SEC)
3.04
FORECAST PRICES
2014 3.83
2015
2016
2017
3.93
4.13
4.53
2018
2019
2020
2021
2022
2023
4.73
4.93
5.13
5.33
5.48
5.63
2024
2025
2026
2027
2028
2029
5.83
5.98
6.08
6.18
6.28
6.43
2.88
5.05
5.19
5.34
5.53
5.67
5.76
3.63
3.73
3.91
4.29
4.48
4.67
4.86
5.86
5.95
6.09
3.21
5.30
5.50
5.65
5.80
6.00
6.15
4.00
4.10
4.30
4.70
4.90
5.10
6.25
6.35
6.45
6.60
3.46
5.75
5.90
6.05
6.25
6.40
6.50
4.25
4.35
4.55
4.95
5.15
5.35
5.55
6.60
6.70
6.85
3.81
6.15
6.30
6.45
6.65
6.80
6.90
4.65
4.75
4.95
5.35
5.55
5.75
5.95
7.00
7.10
7.25
50.09
49.40
46.80
46.80
49.92
50.44
50.96
52.00
52.00
53.04
54.10
55.18
56.29
57.41
58.56
59.73
60.93
91.43
74.10
70.20
70.20
74.88
75.66
76.44
78.00
78.00
79.56
81.15
82.77
84.43
86.12
87.84
89.60
91.39
100.72
95.95
90.90
90.90
96.96
97.97
98.98
101.00
101.00
103.02
105.08
107.18
109.33
111.51
113.74
116.02
118.34
77.68
70.78
67.05
67.05
71.52
72.27
73.01
74.50
74.50
75.99
77.51
79.06
80.64
82.25
83.90
85.58
87.29
Constant thereafter
Notes: [1] Alberta Gas Reference Price (GRP) represents the average of all system and direct (spot and firm) sales.
[2] Price paid at field delivery point.
[3]
[4]
[5]
Price paid by CanWest net of raw gas gathering and processing charges but before deduction of field gathering and compression charges.
Reference point is FOB Edmonton for fractionated product.
Natural Gas Liquids blended mix price assuming typical liquid composition of 40% propane,
30% butane and 30% pentanes plus.
The Company’s weighted average prices received this fiscal year are: $$2.41/GJ for natural gas and
$34.40/MSTB.
- 7 -

The following table sets forth a reconciliation of the changes in the Company's gross reserves as at
December 31, 2013 against such reserves as at December 31, 2012 based on the forecast price and cost assumptions:
RECONCILIATION OF COMPANY GROSS
RESERVES BY PRINCIPAL PRODUCT TYPE
BASED ON FORECAST PRICES AND COSTS
AS AT DECEMBER 31, 2013
At Dec 31, 2012
Light and Medium
Oil Heavy Oil
Associated and
Non-Associated Gas CBM NGL
Proved Proved Proved Proved
Proved Probable Probable Proved Probable
(Mbbl) (Mbbl)
Plus
(Mbbl) (Mbbl) (Mbbl)
Plus
Probable Proved
(Mbbl) (Mbbl)
Plus
Probable Probable
(Mbbl) (Mbbl)
Proved
(MMscf)
Probable
(MMscf)
Plus
Probable
(MMscf)
Proved
(Mbbl)
Proved
Probable
(Mbbl)
Plus
Probable
(Mbbl)
0 132 132 23 67 90 1,153 2,517 3,670 767 1,781 2,547 0 0 0
Production(Sales) 0 0 0 (1) 0 (1) (18) 0 (18) (25) 0 (25) 0 0 0
Acquisitions
Dispositions
Discoveries
Extensions &
Improved Recovery
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
(649) (324) (973)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Economic Factors 0
Technical Revisions 0
At Dec 31, 2013
0
0
0
0
0
0
0
0
0
0
0 0 0 0 0 0
(18) (37) (55) 1,470 376 1,847
0
0
0
0
0
1
0 132 132 22 67 89 468 2,156 2,624 2,212 2,157 4,369 0 0 1
Undeveloped Reserves
The following table sets forth the volumes of proved undeveloped net reserves that were first attributed for each of the Company ’s product types for the most recent three financial years and in the aggregate before that time:
Aggregate prior to 2011
2011
2012
2013
Light & Medium Oil
(Mbbl)
0
0
0
0
Heavy Oil
(Mbbl)
47
0
(47)
0
Natural Gas
(MMscf)
0
0
566
(566)
CBM
(MMscf)
273
232
(112)
1504
The following table sets forth the volumes of probable undeveloped net reserves that were first attributed for each of the Company ’s product types for the most recent three financial years and in the aggregate before that time:
Aggregate prior to 2011
2011
2012
2013
Light & Medium Oil
(Mbbl)
0
123
(64)
0
Heavy Oil
(Mbbl)
70
50
(73)
0
Natural Gas
(MMscf)
716
(241)
1,006
188
CBM
(MMscf)
485
90
1,019
(178)
- 8 -

The following discussion generally describes the basis on which the Company attributes proved and probable undeveloped reserves and its plans for developing those undeveloped reserves.
Proved Undeveloped Reserves
The Company’s proved undeveloped reserves are located on Company lands near current producers where the formations are well known and the productivity of undrilled locations can be predicted with a high degree of certainty. These reserves are scheduled to be developed in 2014 and 2015.
Probable Undeveloped Reserves
The Company’s probable undeveloped reserves are based on similar considerations as the proved reserves except the predicted recoveries are known with less certainty. These reserves are also forecast to be developed in 2014 and 2015.
Significant Factors or Uncertainties
The estimation of reserves requires significant judgment and decisions based on available geological, geophysical, engineering and economic data. These estimates can change substantially as additional information from ongoing development activities and production performance becomes available and as economic and political conditions impact oil and gas prices and costs change. The Company’s estimates are based on current production forecast, prices and econom ic conditions. All of the Company’s reserves are evaluated by Chapman Petroleum Engineering Ltd., an independent engineering firm.
As circumstances change and additional data becomes available, reserve estimates also change. Based on new information, reserves estimates are reviewed and revised, either upward or downward, as warranted. Although every reasonable effort has been made by the Company to ensure that reserves estimate are accurate, revisions may arise as new information becomes available. As new geological, production and economic data is incorporated into the process of estimating reserves the accuracy of the reserve estimate improves.
Certain information regarding the Company set forth in this report, including management’s assessment of the Comp any’s future plans and operations contain forward-looking statements that involve substantial known and unknown risks and uncertainties. These risks include, but are not limited to: the risks associated with the oil and gas industry, commodity prices and exchange rates; industry related risks could include, but are not limited to, operational risks in exploration, development and production, delays or changes in plans, risks associated with the uncertainty of reserve estimates, health and safety risks and the uncertainty of estimates and projections of production, costs and expenses. Competition from other producers, the lack of available qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources are additional risks the Company faces in this market. The Company’s actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward looking statements and accordingly, no assurance can be given that any events anticipated by the forward looking statements will transpire or occur, if any of them do, what benefits the Company can derive from. The reader is cautioned not to place undue reliance on this forward looking information.
- 9 -

Future Development Costs
The following table shows the development costs anticipated in the next five years, which have been deducted in the estimation of the future net revenues of the proved and probable reserves.
Total Proved
Estimated Using
Forecast Prices and Costs
(Undiscounted)
Total Proved
Plus Probable
Estimated
Using Forecast
Prices and
Costs
(Undiscounted)
2014
($M)
1,166
($M)
3,899
2015
2016
2017
2018
1,343
0
0
1,343
0
0
Total for five years
Remainder
Total for all years
0
2,509
0
2,509
0
5,241
0
5,241
The Company has been successful in raising its required capital through equity financings and plans to continue to do so for the development costs specified above. The effect of the costs of the expected funding would have no impact on the revenues or reserves currently being reported.
Oil and Gas Properties and Wells
The following table sets forth the number of wells in which the Company held a working interest as at
December 31, 2013:
All Areas
Producing
Non-producing
Gross
(1)
3
1
Oil
Net
(1)
1.5
0.5
Natural Gas
Gross
(1)
Net
(1)
8
5
4.78
3.25
All of the Company ’s wells are located onshore in the western Canadian plains in Alberta and
Saskatchewan and are part of or close to active oil and gas fields.
Properties with No Attributed Reserves
The Company has no properties to which no reserves have been assigned.
Forward Contracts
Currently, the Company has no forward contracts.
- 10 -

Additional Information Concerning Abandonment and Reclamation Costs
The estimated abandonment and restoration costs used by Chapman are based on the AER Directive 11, which details the typical costs of abandonment and reclamation by well type in each specific geographic region. The Company expects to have costs relating to 21.8 net wells, including the locations to be drilled. Costs have been included in the Chapman report for all wells to which reserves have been assigned. The Company owns 2.7 net wells to which no reserves have been assigned. The cost of abandoning these wells is included in the following table but not in the Chapman report.
2014
2015
2016
Total for three years
Remainder
Total for all years
FUTURE ABANDONMENT AND RESTORATION COSTS
Total Proved
Estimated Using
Forecast Prices and Costs
(Undiscounted)
($M)
0
0
0
0
953
953
Total Proved
Estimated
Using Forecast
Prices and
Costs (10%
Discounted)
($M)
0
0
0
0
290
290
Total Proved
Plus Probable
Estimated Using
Forecast Prices and Costs
(Undiscounted)
($M)
0
0
0
0
1,409
1,409
Total Proved
Plus Probable
Estimated Using
Forecast Prices and Costs (10%
Discounted)
($M)
0
0
0
0
274
274
Tax Horizon
The Company is not expected to become taxable under the total proved cash flow forecast in this report, but will become taxable in 2017 and thereafter in the proved plus probable case.
Costs Incurred
The following table summarizes the capital expenditures made by the Company on oil and natural gas properties for the year ended December 31, 2013:
Property Acquisition Costs
($M)
Proved Properties Unproved Properties
Exploration Costs
($M)
Development Costs
($M)
Nil Nil xxx xxx
The Company also had exploration costs of $____Nil_______ expended on the ___N/A____ project, which is not a conventional oil and gas property.
Exploration and Development Activities
The following table sets forth the number of exploratory and development wells which the Company completed during its 2013 financial year:
Oil Wells
Gas Wells
Service Wells
Dry Holes
Total Completed Wells
Exploratory Wells
Gross
(1)
Net
(1)
0
0
0
0
0
0
0
0
0 0
Development Wells
Gross
(1)
Net
(1)
0
0
0
0
0
0
0
0
0 0
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The Company did not drill or develop any additional reserves in the fiscal year.
Production Estimates
The following table sets forth the volume of production estimated by Chapman for 2014 (12 mos.):
AREA
TOTAL PROVED RESERVES
Light and Medium
Oil
(Mbbl)
Heavy Oil
(Mbbl)
Natural Gas
(MMscf)
Natural Gas
Liquids
(Mbbl)
Total for all areas
0 2.642 112 0
AREA
TOTAL PROVED PLUS PROBABLE RESERVES
Light and Medium
Oil
(Mbbl)
Heavy Oil
(Mbbl)
Natural Gas
(MMscf)
Natural Gas
Liquids
(Mbbl)
Total for all areas
8.046 4.951 269 0
These values are gross to Company’s working interest before the deduction of royalties payable to others.
Production History
The following tables on the following page set forth certain information in respect of production, product prices received, royalties, production costs and netbacks received by the Company for each quarter of its most recently completed financial year:
Three Months
Ended March 31,
2013
Three Months
Ended June 30,
2013
Three Months
Ended September
30, 2013
Avg. daily gas volume
GJ/day
Volume 10³M³/day
Avg. BOEs/day
Weighted avg. price received per GJ $$
83.36
2.19
13.62 26.86
2.74
Production costs – yearly average: $1.65/GJ
Royalties paid – yearly average: $0.15/GJ
164.46
4.27
2.98
Three Months
Ended December
31, 2013
246.55 183.47
6.40 4.76
40.27
2.09
29.97
1.86
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Avg. daily heavy oil
Production/BBL
Three Months
Ended March 31,
2013
11.87
Three Months
Ended June 30,
2013
4.58
Three Months
Ended September
30, 2013
Nil
Three Months
Ended December
31, 2013
Nil
Avg. net price received
(10³M³/day) $$
Avg. price received/BBL
\
Avg. royalties paid/BBL
295.18
46.93
10.55
273.98
43.56
10.52
Nil
Nil
Nil
Nil
Nil
Nil
Bbls
Mbbls
MMbbls
MSTB
Bbls/d
NGLs
STB
STB/d
Other
AECO
BIT
AIT
BOE
Avg. production costs/BBL
Avg. resulting netback/BBL
9.29 10.32 Nil Nil
37.09 31.72 Nil Nil
ABBREVIATIONS AND CONVERSION
In this document, the abbreviations set forth below have the following meanings:
Oil and Natural Gas Liquids Natural Gas
Bbl barrel Mscf thousand standard cubic feet barrels thousand barrels million barrels
1,000 stock tank barrels barrels per day natural gas liquids stock tank barrels of oil stock tank barrels of oil per day
MMscf
Mscf/d
MMscf/d
MMBTU
Bscf
GJ million standard cubic feet thousand standard cubic feet per day million standard cubic feet per day million British Thermal Units billion standard cubic feet gigajoule
BOE/d m 3
$M
WTI
Niska Gas Storage’s natural gas storage facility located at Suffield, Alberta.
Before Income Tax
After Income Tax barrel of oil equivalent on the basis of 1 BOE to 6 Mscf of natural gas. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 1 BOE for 6 Mscf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. barrel of oil equivalent per day cubic metres thousands of dollars
West Texas Intermediate, the reference price paid in U.S. dollars at Cushing,
Oklahoma for crude oil of standard grade
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