BlackPearl Resources Inc.



Reserves/Resources


Oil and Gas Reserves

The following tables summarize certain information contained in the independent reserves report prepared by Sproule Unconventional Limited ("Sproule") as of December 31, 2013. The report was prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Additional reserve information as required under NI 51-101 will be included in the Company's Annual Information.

Summary of Oil and Gas Reserves

(Company interest, before royalties) Heavy Oil Bitumen Total
Crude Oil
Natural
Gas
2013
Total
2012
Total
  (Mbbl) (Mbbl) (Mbbl) (MMcf) (MBoe) (MBoe)
             
Proved developed producing 7,162 1,651 8,813 78 8,826 7,138
Proved developed non-producing 1,772 429 2,201 23 2,205 2,291
Proved undeveloped 52,789 0 52,789 52 52,798 6,456
Total proved 61,724 2,080 63,804 154 63,829 15,885
Probable 47,255 179,499 226,754 137 226,777 197,439
Total proved plus probable 108,979 181,579 290,558 291 290,606 213,324
Notes:
  1. BOE's may be misleading, particularly if used in isolation. In accordance with NI 51-101, a BOE conversion ratio of 6 Mcf: 1 barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
  2. Based on Sproule's December 31, 2013 forecast prices
  3. Columns may not add due to rounding
SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE OF OIL AND GAS RESERVES
AS AT DECEMBER 31, 2013
FORECAST PRICES AND COSTS


  Before Income Taxes Before Tax
  Discounted at (%/Year) Unit Value(1)
  0 5 10 15 20 10%/yr
Reserves Category (M$) (M$) (M$) (M$) (M$) ($/Boe)
Proved            
Developed Producing 238,686 218,667 202,355 188,814 177,393 27.77
Developed Non-Producing 49,554 38,891 31,010 25,021 20,361 15.52
Undeveloped 1,712,866 896,156 499,793 286,730 161,424 11.87
Total Proved 2,001,106 1,153,713 733,158 500,565 359,178 14.26
Probable 6,778,456 2,964,519 1,460,725 788,943 435,070 8.49
Total Proved Plus Probable 8,779,562 4,118,232 2,193,883 1,279,507 794,249 9.82


  After Income Taxes
  Discounted at (%/Year)
  0 5 10 15 20
Reserves Category (M$) (M$) (M$) (M$) (M$)
Proved          
Developed Producing 238,685 218,666 202,355 188,814 177,393
Developed Non-Producing 49,554 38,891 31,010 25,021 20,361
Undeveloped 1,324,267 696,268 387,724 219,111 118,059
Total Proved 1,612,506 953,825 621,089 432,945 315,813
Probable 5,052,868 2,166,674 1,036,657 528,940 276,036
Total Proved Plus Probable 6,665,374 3,120,499 1,657,747 961,885 591,849
Note:
  1. Unit values are based on net reserve volumes
TOTAL FUTURE NET REVENUE (undiscounted)
AS AT DECEMBER 31, 2013
FORECAST PRICES AND COSTS


Reserves Category Revenue Royalties Operating Costs Development Costs Abandonment (1) Future Net Revenue Before Income Taxes Future Income Taxes Future Net Revenue After Income Taxes
(M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$)
                 
Proved 5,194,714 995,231 1,444,438 727,436 26,504 2,001,106 388,600 1,612,506
                 
                 
Proved Plus Probable 23,097,398 5,367,543 6,104,175 2,796,487 49,631 8,779,562 2,114,187 6,665,374
Note:
  1. The abandonment costs only include downhole abandonment costs for the wells considered in Sproule's evaluation of reserves. Abandonment of other wells, surface reclamation and facility site reclamation are not included. See - "Abandonment and Reclamation Costs."
NET PRESENT VALUE OF FUTURE NET REVENUE BY PRODUCTION GROUP
AS AT DECEMBER 31, 2013
FORECAST PRICES AND COSTS


    Future Net Revenue Unit Value(2)
    Before Income Taxes Before Income Taxes
Reserves Category Production Group (Discounted at 10%/Year) (Discounted at 10%/Year)
    (M$) ($/Boe)
Proved Light and Medium Crude Oil (including solution gas and associated by-products) - -
  Heavy Oil (including solution gas and associated by-products) 703,743 14.23
  Bitumen (including solution gas and associated by-products) 29,415 15.16
  Natural Gas (including associated by-products)(1) - -
Proved Plus Probable Light and Medium Crude Oil (including solution gas and associated by-products) - -
  Heavy Oil (including solution gas and associated by-products) 1,380,382 16.26
  Bitumen (including solution gas and associated by-products) 813,502 5.87
  Natural Gas (including associated by-products)(1) - -

Notes:
  1. Includes Corporate Gas Cost Allowance, if applicable.
  2. Unit values are based on net reserve volumes.

Definitions and Notes to Reserves Data Tables

In the tables set forth under the heading "Statement of Reserves and Contingent Resources Data and Other Oil and Gas Information" and elsewhere in this Annual Information Form the following definitions and notes are applicable:
  1. Columns and rows may not add due to rounding.
  2. "COGE Handbook" means the Canadian Oil and Gas Evaluation Handbook prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum, (Petroleum Society), as amended from time to time.
  3. "Development costs" means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from the reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
    1. gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, to the extent necessary in developing the reserves;
    2. drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and wellhead assembly;
    3. acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and
    4. provide improved recovery systems.
  4. "Development well" means a well drilled inside the established limits of an oil and gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.
  5. "Exploration costs" means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
    1. costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies;
    2. costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records;
    3. dry hole contributions and bottom hole contributions;
    4. costs of drilling and equipping exploratory well; and
    5. costs of drilling exploratory type stratigraphic test wells.
  6. "Gross" means:
    1. In relation to the Company's interest in production or reserves, the Company's working interest (operating and non-operating) share before deduction of royalties;
    2. In relation to wells, the total number of wells in which the Company has an interest; and
    3. In relation to properties, the total area of properties in which the Company has an interest.
  7. "Net" means:
    1. In relation to the Company's interest in production or reserves, BlackPearl's working interest (operating and non-operating) share after deduction of royalty obligations, plus the Company's royalty interest in production or reserves;
    2. In relation to the Company's interest in wells, the number of wells obtained by aggregating the Company's working interest in each of its gross wells; and
    3. In relation to the Company's interest in a property, the total area in which BlackPearl has an interest multiplied by the Company's working interest.
  8. "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:
    1. analysis of drilling, geological, geophysical and engineering data;
    2. the use of established technology; and
    3. specified economic conditions (The key economic assumptions include, but are not limited to, the prices and costs used in the estimate, namely the forecast prices and cost).

    Reserves are classified according to the degree of certainty associated with the estimates.

    1. 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.
    2. 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 and probable reserves.
    3. 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.

    Each of the reserve categories (proved, probable and possible) may be divided into developed and undeveloped categories:

    1. 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 (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.
    2. Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of 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.
    3. 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 is unknown.
    4. 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 classification (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 sub-divide the developed reserves for the pool between developed producing and developed non-producing. This allocation is 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.

    The qualitative certainty levels referred to in the definitions above are applicable to individual reserve 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 reserve estimates are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

    1. at least a 90% probability that the quantities actually recovered will equal or exceed the estimated proved reserves;
    2. at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves; and
    3. at least a 10% 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 the COGE Handbook.

  9. "Service well" means a well drilled or completed for the purpose of supporting production in an existing field. Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane or flue gas), water injection, steam injection, air injection, salt water disposal, water supply for injection, observation or injection for combustion.

Pricing Assumptions

The price forecasts that formed the basis for the revenue projections and net present value estimates in the Sproule Report were based on Sproule's December 31, 2013 pricing models. A summary of selected price forecasts used by Sproule is set forth below.

SUMMARY OF PRICING USED IN PREPARATION OF RESERVES
AND CONTINGENT RESOURCES DATA
AS AT DECEMBER 31, 2013
FORECAST PRICES AND COSTS(1)(4)(5)


    Edmonton     Pentanes      
  WTI Par Western Natural Gas Plus Butanes    
  Cushing Price Canadian Select AECO Gas FOB FOB Inflation Exchange
Year Oklahoma 40° API 20.5° API Prices Edmonton Edmonton Rate(2) Rate(3)
  ($US/Bbl) ($Cdn/Bbl) ($Cdn/Bbl) ($Cdn/MMBtu) ($Cdn/Bbl) ($Cdn/Bbl) (%/Yr) ($US/$Cdn)
                 
Historical                
2009 61.63 66.20 58.66 4.19 68.13 49.34 2.0 0.880
2010 79.43 77.80 67.21 4.16 84.21 57.99 1.2 0.971
2011 95.00 95.16 77.09 3.72 104.12 70.93 1.6 1.012
2012 94.19 86.57 73.08 2.43 100.76 64.48 1.3 1.001
2013 97.98 93.24 74.20 3.13 104.86 70.29 0.8 0.971
                 
Forecast                
2014 94.65 92.64 77.81 4.00 103.50 69.05 1.5 0.940
2015 88.37 89.31 75.02 3.99 99.78 66.57 1.5 0.940
2016 84.25 89.63 75.29 4.00 100.14 66.81 1.5 0.940
2017 95.52 101.62 85.36 4.93 113.53 75.74 1.5 0.940
2018 96.96 103.14 86.64 5.01 115.24 76.88 1.5 0.940
2019 98.41 104.69 87.94 5.09 116.97 78.03 1.5 0.940
2020 99.89 106.26 89.26 5.18 118.72 79.20 1.5 0.940
2021 101.38 107.86 90.60 5.26 120.50 80.39 1.5 0.940
2022 102.91 109.47 91.96 5.35 122.31 81.60 1.5 0.940
2023 104.45 111.12 93.34 5.43 124.14 82.82 1.5 0.940
2024 106.02 112.78 94.74 5.52 126.01 84.06 1.5 0.940
Thereafter Escalation Rate of 1.5% per annum        

Notes:
  1. This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer.
  2. Inflation rates used in forecasting prices and costs.
  3. Exchange rates used to generate the benchmark reference prices in this table.
  4. None of the Company's future production is subject to a fixed or contractually committed price.
  5. The Company's weighted average wellhead price in 2013 was $65.09 per Bbl for heavy oil/bitumen/NGLs and $3.16 per Mcf for natural gas.

Reconciliation of Changes in Reserves and Future Net Revenue

The following table summarizes changes in the Company's gross oil and gas reserves (before the deduction for royalties) from December 31, 2012 to December 31, 2013.

RECONCILIATION OF COMPANY GROSS RESERVES
BY PRINCIPAL PRODUCT TYPE
BASED ON FORECAST PRICES AND COSTS


  Light and Medium Oil and Natural Gas Liquids Heavy Oil Bitumen Natural Gas
(non-associated & associated)
  Gross Proved
(Mbbl)
Gross Probable
(Mbbl)
Gross Proved Plus Probable
(Mbbl)
Gross Proved
(Mbbl)
Gross Probable
(Mbbl)
Gross Proved Plus Probable
(Mbbl)
Gross Proved
(Mbbl)
Gross Probable
(Mbbl)
Gross Proved Plus Probable
(Mbbl)
Gross Proved
(MMcf)
Gross Probable
(MMcf)
Gross Proved Plus Probable
(MMcf)
Dec. 31, 2012 0.4 0.5 0.9 14,205 17,301 31,505 1,641 180,137 181,778 234 3 236
Extensions 0.0 0.0 0.0 4,327 1,846 6,174 0 0 0 18 40 58
Improved Recovery 0.0 0.0 0.0 44,740 31,396 76,136 0 0 0 0 0 0
Technical
Revisions
0.0 0.0 0.0 2,156 -3,217 -1,061 525 -638 -113 215 116 331
Discoveries 0.0 0.0 0.0 0 0 0 0 0 0 0 0 0
Acquisitions 0.0 0.0 0.0 0 0 0 0 0 0 210 0 210
Dispositions -0.4 -0.5 -0.9 -344 -75 -420 0 0 0 -10 -11 -21
Economic
Factors
0.0 0.0 0.0 19 4 23 0 0 0 10 -10 0
Production 0.0 0.0 0.0 -3,378 0 -3,378 -86 0 -86 -524 0 -524
Dec. 31, 2013 0.0 0.0 0.0 61,724 47,255 108,979 2,080 179,499 181,579 154 137 291

Undeveloped Reserves

The following table discloses, for each product type, the volumes of undeveloped reserves that were first attributed in each of the most recent three financial years.

Reserves Light & Medium Oil and Natural Gas Liquids Heavy Oil Bitumen Natural Gas
(non-associated & associated)
1st attributed
Gross
(Mbbl)
Cumulative
Gross
(Mbbl)
1st attributed
Gross
(Mbbl)
Cumulative
Gross
(Mbbl)
1st attributed
Gross
(Mbbl)
Cumulative
Gross
(Mbbl)
1st attributed
Gross
(MMcf)
Cumulative
Gross
(MMcf)
Proved Undeveloped                
Prior to Dec. 31, 2011 (in aggregate) 6 6 6,220 13,493 0 0 2 550
Dec. 31, 2011 0.2 0.5 2,796 6,530 890 890 103 213
Dec. 31, 2012 0.0 0.0 749 5,566 0 890 0 0
Dec. 31, 2013 0.0 0.0 47,178 52,789 0 0 52 52
                 
Probable Undeveloped                
Prior to Dec. 31, 2011(in aggregate) 5 5 3,816 20,297 0 0 160 1,247
Dec. 31, 2011 1.2 2.7 7,980 18,132 197 197 540 1,195
Dec. 31, 2012 0.0 0.0 1,530 8,432 179,977 180,052 0 0
Dec. 31, 2013 0.0 0.0 32,870 39,038 0 179,294 123 123

Undeveloped reserves are attributed by Sproule in accordance with standards and procedures contained in the COGE Handbook. Proved undeveloped reserves are those reserves that can be estimated with a high degree of certainty and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. Probable undeveloped reserves are those additional reserves that are less certain to be recovered than proved reserves and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production.

BlackPearl has a significant level of undeveloped reserves relative to developed reserves. The majority of undeveloped reserves assigned by Sproule were to the Blackrod, Mooney, Onion Lake and John Lake fields.

At Blackrod, Sproule assigned proved and probable undeveloped reserves to the current pilot and its expansion and probable reserves to phase one of the Blackrod SAGD Project. The Blackrod SAGD Project represents the majority of BlackPearl's probable undeveloped reserves. If BlackPearl receives regulatory approval for the Blackrod SAGD Project and commits to spend, within three years, the funds necessary to achieve first bitumen production a portion of these probable undeveloped reserves are expected to become proved undeveloped reserves. Upon initiation of production and ramp up of production to design rates, some of these undeveloped reserves are expected to become developed reserves.

At Mooney, the majority of the proved and probable undeveloped reserves were assigned based upon the continued extension of the field to the west and south and the continued conversion of the field to the EOR scheme. Construction of the commercial ASP flood injection facility was completed and ASP injection commenced in 2011; while a new heavy oil processing facility was constructed and began to handle the increased fluid volumes from the area in 2012. In 2012, we began to see production response from the initial re-pressurization of the reservoir and we saw further response in 2013. With this response, we are continuing development of the phase two and phase three lands with 12 to 14 wells expected to be drilled in 2014. In 2013, we received regulatory approval to expand the existing ASP flood to the phase two lands and we expect to implement this expansion in 2014. In the first quarter of 2014, we are also planning to construct the pipeline infrastructure necessary to allow further development drilling of the phase three lands which is expected to take place over the next several years. Future follow up phases of the ASP flood, including phase three, will likely occur over the longer term and will likely be controlled by the throughput constraints of the ASP injection and production facilities. Sproule assigned proved and probable undeveloped reserves to 22 future primary horizontal development locations including the implementation of EOR across 16 future well pairs. The high level of proved and probable undeveloped reserves relative to developed reserves at Mooney reflects the ongoing implementation of the ASP flood and the continued extension of the field; as the Mooney field continues to show increasing production response from the ASP flood, is further delineated and as the ASP flood is implemented across more well pairs, the ratio of undeveloped to developed reserves is expected to decline.

At Onion Lake, Sproule assigned proved and probable undeveloped reserves to 120 future primary drilling locations. We plan to drill 20 to 25 wells in 2014. We anticipate drilling an additional 20 to 30 of these locations in 2015. BlackPearl continues to extend the reservoir boundaries at Onion Lake and as a result there continues to be a relatively high level of undeveloped reserves relative to developed reserves. As the field's primary development continues to mature, it is expected that the ratio of undeveloped to developed reserves will continue to fall. At Onion Lake, Sproule has also assigned proved and probable undeveloped reserves to Phase one and two of the Onion Lake Thermal Project. The Onion Lake Thermal Project represents a large portion of BlackPearl's proved and probable undeveloped reserves. Upon initiation of production and ramp up of production to design rates, some of these undeveloped reserves will become developed reserves.

At John Lake, Sproule assigned proved and probable undeveloped reserves to 18 future horizontal drilling locations. In 2014, we may drill up to 6 horizontal wells. At John Lake exploitation of the Sparky reservoir using horizontal wells is still relatively new and delineation of the Cummings reservoir is in its early stages, as a result, there continues to be a relatively high level of undeveloped reserves relative to developed reserves. As the field's primary development continues to mature it is expected that the ratio of undeveloped to developed reserves will continue to fall.

The actual number of wells drilled could change as a result of changes in, among other items, economic conditions, technical and operating results, or changing budget priorities. A portion of the Company's capital budget is allocated to new projects or projects that do not have reserves assigned as yet. As a result, all capital required to develop the undeveloped reserves may not be spent in the next two years.

For additional information, see "Description of our Business - Description of our Properties".

Significant Factors or Uncertainties

The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering, and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available. A number of economic factors can also affect the reserves, including product prices, royalty and tax regimes, and changes in operating and capital costs. The reserves estimates contained herein are based on current production forecasts, prices and economic conditions. See "Risk Factors".

As circumstances change and additional data become available, reserve estimates also change. Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices, economic conditions and governmental restrictions.

Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. As a result, the subjective decisions, new geological or production information and a changing environment may impact these estimates. Revisions to estimates can arise from changes in year-end oil and natural gas prices and reservoir performance. Such revisions can be either positive or negative. See "Risk Factors".

Future Development Costs

The following table sets forth development costs (all within Canada) deducted in the estimation of future net revenue attributable to the reserve categories below using forecast costs.

Year Total Proved ($M) Total Proved
Plus Probable ($M)
2014 196,322 211,844
2015 80,127 100,251
2016 33,673 205,231
2017 35,918 118,879
2018 11,167 350,509
Remainder 370,229 1,809,773
Total for all years undiscounted 727,436 2,796,487

On-going development at Mooney, John Lake and conventional development at Onion Lake is expected to be funded from cash flow and the Company's existing credit facilities. The first phase of the Onion Lake EOR project is being designed for production of 6,000 barrel per day and capital costs are expected to be approximately $200 million. Subsequent to December 31, 2013, the Company announced a public offering and a private placement of common shares of BlackPearl, for aggregate gross proceeds of approximately $80 million. The proceeds from the equity issuance will be used, in part, to fund the first phase of development of the Onion Lake EOR project. BlackPearl's Board of Directors has approved development of the first phase of the Onion Lake thermal project and construction is expected to take 15 to 18 months. The Company is planning to build the Blackrod SAGD project in phases as well, with the first phase likely to be designed for 20,000 barrels per day and capital costs are expected to be approximately $800 million. Timing of development of this project is dependent on additional financing. We currently do not have the financing necessary to initiate development of the Blackrod SAGD project

There can be no guarantee that funds will be available or that the Board of Directors will allocate funding to develop all of the reserves in the Sproule Report. Failure to develop those reserves would have a negative impact on future cash flow.

The interest or other costs of external funding are not included in the reserves and future net revenue estimates and would reduce reserves and future net revenue to some degree depending upon the funding sources utilized. We do not anticipate that interest or other funding costs would make development of any property uneconomic.

See "Risk Factors - Access to Capital."

CONTINGENT RESOURCES

The following tables summarize certain information contained in the contingent resource evaluations prepared by Sproule as of December 31, 2013. The reports were independently prepared in accordance with definitions, standards and procedures contained in the COGE Handbook, and are based on Sproule's December 31, 2013 pricing models (see "Pricing Assumptions"). The following tables do not include the proved and probable reserves assigned by Sproule as at December 31, 2013 as such information is presented above.

It should not be assumed that the estimates of recovery and net revenue presented in the tables below represent the fair market value of the Company's contingent resources. There is no assurance that the forecast prices and cost assumptions will be realized and variances could be material. The estimated future net revenues contained in the following tables do not necessarily represent the fair market value of the Company's contingent resources. The recovery estimates of the Company's contingent resources provided herein are only estimates and involve additional rules over estimates of reserves and there is no guarantee that the estimated contingent resources will be recovered or produced. Actual contingent resources may be greater than or less than the estimates provided herein. The contingencies which currently prevent the classification of these contingent resources as reserves are described in notes 7, 8 and 9 on pages 44 and 45 of this Annual Information Form. Once all contingencies are removed, the resources may then be reclassified as reserves. There is no certainty that it will be commercially viable for the Company to produce any portion of the contingent resources on any of its properties. See "Forward-Looking Statements" and "Risk Factors."

SUMMARY OF CONTINGENT RESOURCES
AS AT DECEMBER 31, 2013
FORECAST PRICES AND COSTS


  Light and Medium Oil
and Natural Gas Liquids
Heavy Oil Bitumen Natural Gas
(non-associated & associated)
Project Gross
(Mbbl)
Net
(Mbbl)
Gross
(Mbbl)
Net
(Mbbl)
Gross
(Mbbl)
Net
(Mbbl)
Gross
(MMcf)
Net
(MMcf)
Blackrod(7)                
Low Estimate(3) 0 0 0 0 505,358 397,599 0 0
Best Estimate(2) 0 0 0 0 566,141 437,862 0 0
High Estimate(4) 0 0 0 0 626,904 478,633 0 0
Onion Lake(8)                
Low Estimate(3) 0 0 26,588 21,009 0 0 0 0
Best Estimate(2) 0 0 29,815 23,572 0 0 0 0
High Estimate(4) 0 0 34,013 26,587 0 0 0 0
Mooney(9)(10)                
Low Estimate(3) 0 0 36,628 25,446 0 0 3 4
Best Estimate(2) 0 0 34,726 24,459 0 0 0 0
High Estimate(4) 0 0 42,598 29,811 0 0 0 0

SUMMARY OF VOLUMES AND NET PRESENT VALUES OF CONTINGENT RESOURCES
AS AT DECEMBER 31, 2013
FORECAST PRICES AND COSTS


Project Contingent Resources Net Present Values of Future Net Revenue Before Income Taxes
Discounted at (%/year)
  Gross 0% 5% 10% 15% 20%
  (Mboe) ($M)
Blackrod(7)            
Low Estimate(3) 505,358 12,209,519 3,883,361 1,304,303 417,129 90,896
Best Estimate(2) 566,141 15,178,455 4,571,360 1,500,195 486,579 120,741
High Estimate(4) 626,904 18,201,081 5,230,667 1,694,591 567,203 164,474
Onion Lake(8)            
Low Estimate(3) 26,588 1,158,790 423,818 180,299 87,295 46,586
Best Estimate(2) 29,815 1,198,290 565,584 289,947 158,736 91,285
High Estimate(4) 34,013 1,429,656 651,475 325,046 174,864 99,778
Mooney(9)(10)            
Low Estimate(3) 36,629 858,273 519,165 337,693 232,791 168,120
Best Estimate(2) 34,726 898,410 510,646 311,009 200,037 134,295
High Estimate(4) 42,598 1,150,930 656,775 404,071 263,819 180,574

Project Contingent Resources Net Present Values of Future Net Revenue After Income Taxes (11)
Discounted at (%/year)
    0% 5% 10% 15% 20%
  (Mboe) ($M)
Blackrod(7)            
Low Estimate(3) 505,358 9,125,064 2,795,827 866,917 221,112 -4,831
Best Estimate(2) 566,141 11,369,965 3,316,227 1,016,891 275,411 19,011
High Estimate(4) 626,904 13,636,052 3,814,476 1,168,712 341,638 56,627
Onion Lake(8)            
Low Estimate(3) 26,588 845,601 305,175 127,324 59,912 30,682
Best Estimate(2) 29,815 874,400 407,182 205,022 109,528 60,896
High Estimate(4) 34,013 1,042,968 469,958 230,967 121,719 67,524
Mooney(9)(10)            
Low Estimate(3) 36,629 646,246 385,823 247,342 167,804 119,085
Best Estimate(2) 34,726 674,278 378,627 227,345 143,804 94,665
High Estimate(4) 42,598 863,830 487,928 296,655 191,074 128,782

Notes:
  1. Contingent resources are defined in the COGE Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as Contingent Resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status.
  2. Best estimate (P50) is a classification of estimated resources described in the COGE Handbook as being considered to be the best estimate of the quantity that will be actually recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the best estimate.
  3. Low estimate (P90) is a classification of estimated resources described in the COGE Handbook as being considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the Low Estimate. If probabilistic methods are used, there should be a 90% probability that the quantities actually recovered will equal or exceed the Low Estimate.
  4. High estimate (P10) is a classification of estimate resources described in the COGE Handbook as being considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the High Estimate. If probabilistic methods are used, there should be a 10% probability that the quantities actually recovered will equal or exceed the High Estimate.
  5. Gross means, in relation to the Company's interest in contingent resources of bitumen and heavy oil, the Company's working interest share (operating and non-operating) in such contingent resources of bitumen and heavy oil before deducting royalties. The Company has a 100% working interest at Blackrod and Mooney, and a 50% - 100% working interest at Onion Lake.
  6. The amounts included in these tables do not include the volume and value of BlackPearl's proved and probable reserves previously assigned by Sproule to these properties.
  7. The contingencies in the Sproule Report associated with the Company's Blackrod contingent resources are due to the following:
    Technical Contingencies
    • The requirement for more evaluation drilling, as required by the regulatory process, to define the reservoir characteristics to assist in the implementation and operation of the SAGD recovery process.
        We intend to complete delineation drilling as required by the regulatory process for the future phases of commercial development. The timing of additional delineation drilling required to satisfy ERCB requirements for future commercial phases at Blackrod has not been established.
    Non-technical Contingencies
    • The absence of the submission of an application to expand the commercial SAGD development.
        The application to develop phase one (20,000 Bbls/d of the 80,000 Bbls/d commercial development) was submitted to regulatory authorities in the first half of 2012. Timing for the submission of the application to develop future phases of the project have not been established.
    • The uncertainty of timing of production and development.
        BlackPearl expects to commence the first phase of commercial development at Blackrod within the next five years. Timing is dependent upon, among other things, oil and natural gas prices, anticipated capital and operating costs and the Company's ability to finance the construction of the project. The timing of the development of future phases has not been established.
    Economic Contingencies
    • The contingent resources disclosed are not contingent due to economic factors.
  8. The contingencies in the Sproule Report associated with the Company's Onion Lake contingent resources are due to the following:
    Technical Contingencies
    • The requirement for more evaluation drilling to define the reservoir characteristics of the resource to assist in the implementation and operation of the SAGD recovery process;
        BlackPearl intends to continue delineation drilling to better define the resource (as part of its on-going primary development program) in 2014. The timing of additional delineation drilling to define the entire thermal resource has not been established.
    Non-technical Contingencies
    • The absence of approval to extend the SAGD development area;
        BlackPearl has received regulatory approval to build a 12,000 Bbls/d commercial SAGD development. BlackPearl has not established a timetable to apply for the expansion of the commercial SAGD development at Onion Lake.
    • The uncertainty of company commitment for expansion of the commercial SAGD development;
        BlackPearl has not established a timetable for the expansion of the commercial SAGD development at Onion Lake. Timing is dependent upon, among other things, oil and natural gas prices, anticipated capital and operating costs and the Company's ability to finance the construction of the project.
    • The uncertainty of timing of production and development.
        BlackPearl has not established a timetable for the expansion of the commercial SAGD development at Onion Lake. Timing is dependent upon, among other things, oil and natural gas prices, anticipated capital and operating costs and the Company's ability to finance the construction of the project.
    Economic Contingencies
    • The contingent resources disclosed are not contingent due to economic factors.
  9. The contingencies in the Sproule Report associated with the Company's Mooney contingent resources are due to the following:
    Technical Contingencies
    • The requirement for more evaluation wells to further define reservoir and fluid characteristics.
        BlackPearl expects to drill additional evaluation wells over the next several years. The timing of further delineation drilling beyond those wells contemplated in the next several years to further extend the reservoir and better understand its fluid characteristics has not been established.
    Non-technical Contingencies
    • Further establishment of increased oil production response from the Alkali Surfactant Polymer (ASP) flood in phase one, which began July 2011.
        The first phase of the ASP flood is in operation and initial oil production response from the ASP flood was achieved in 2012. Continued demonstration of the positive ASP response is anticipated in 2014.
    • The uncertainty of timing of production and development of the entire field.
        BlackPearl expects to commence phase two of the ASP flood and to initiate primary development of phase three in 2014. Timing of additional phases of the ASP flood have not been determined; however, it is expected that development of future ASP wells will be timed in order to utilize spare capacity as it becomes available at the central ASP injection facility and the central battery.
    Economic Contingencies
    • The contingent resources disclosed are not contingent due to economic factors.
  10. For the Mooney area, to estimate contingent resource volumes and net present values exclusive of reserves, a reserves evaluation of the Mooney assets as of December 31, 2013 was performed. The volumes, forecasts, and net present values from the year end reserves evaluation were subtracted from the total ASP potential to estimate the contingent resource volumes and net present values. The low contingent resource estimate was calculated by subtracting total proved reserves volumes and net present values. The best and high contingent resource estimates were calculated by subtracting the total proved plus probable reserves volumes and net present values. When comparing the low and best resource estimates, the large differential between total proved and total proved plus probable reserves in the Mooney area results in lower volumes and net present values in the best estimate case.
  11. The after-tax net present value of the Company's oil and gas properties here reflects the tax burden on the properties on a stand-alone basis. It does not consider the business-entity-level tax situation, or tax planning. It does not provide an estimate of the value at the level of the business entity, which may be significantly different. The financial statements and the management's discussion & analysis (MD&A) of the Company should be consulted for information at the level of the business entity.

OTHER OIL AND GAS INFORMATION

OIL AND GAS WELLS


The following table sets out BlackPearl's gross and net interests in oil and natural gas wells in which it has a working interest as at December 31, 2013 (all of which are on-shore wells):

  Oil wells Gas wells
  Producing Non-producing Producing Non-producing
  Gross Net Gross Net Gross Net Gross Net
                 
Canada                
Alberta 65 65 116 114 40 40 98 69
Saskatchewan 126 110 204 181 0 0 73 71
Total Canada 191 175 320 295 40 40 171 140
U.S. 0 0 16 8 0 0 0 0
Total 191 175 336 303 40 40 171 140

LAND HOLDINGS INCLUDING PROPERTIES WITH NO ATTRIBUTED RESERVES

The following table sets out the developed and undeveloped land holdings as at December 31, 2013.

  Developed Acres Undeveloped Acres Total Acres
  Gross Net Gross Net Gross Net
             
Alberta 271,040 228,356 114,220 79,606 156,820 148,751
Saskatchewan 48,220 46,647 34,860 34,075 13,360 12,572
Total - Canada  319,260 275,004 149,081 113,681 170,179 161,323
Total - USA 13,937 7,073 440 220 13,497 6,853
Total 333,197 282,077 149,521 113,901 183,677 168,176

BlackPearl expects that rights to explore, develop and exploit approximately 8,349 net acres of its undeveloped land will expire within the next year. All of this expiring acreage is located in Canada.

FORWARD CONTRACTS

As at December 31, 2013, BlackPearl is not bound by any material agreement under which it is precluded from fully realizing, or being protected from, the full effect of future market prices for its production and did not have any fixed price contracts to sell any of its production. The majority of the Company's production is currently sold under short-term contracts. Subsequent to December 31, 2013, the Company has mitigated a portion of the commodity price risk through the use of various derivative financial instruments and has entered into the following commodity contracts:

Subject of Contract Volume Term Reference Strike Price Option Traded
Oil 2,500 bbls/d March 1, 2014 to December 31, 2014 CDN$ WCS CDN$ 82.10/bbl Swap
Oil 1,000 bbls/d March 1, 2014 to December 31, 2014 CDN$ WCS CDN$ 82.00/bbl Swap

ABANDONMENT AND RECLAMATION COSTS

We estimate the costs to abandon and reclaim all producing and shut-in wells, pipelines and facilities. No estimate of salvage value is netted against the estimated costs. The estimate for abandonment and reclamation costs are based on a number of sources including guidelines from provincial regulatory groups, historical data from our operations and management's estimation of costs to remediate, reclaim and abandon wells and facilities in which it has a working interest. BlackPearl expects to incur abandonment and reclamation costs on approximately 738 gross (658 net) wells. We have estimated the undiscounted future cost of abandonment and reclamation cost at $63.9 million (approximately $28 million discounted at 10%) as at December 31, 2013.

BlackPearl has not established a reclamation fund to pay future asset retirement obligation costs. BlackPearl expects to pay approximately $3.7 million in the next three years in respect of its abandonment and reclamation costs. The future asset retirement obligation is reviewed regularly by management based upon current regulations, costs, technologies and industry standards.

The following table summarizes the estimate for abandonment costs deducted from the estimate of future net revenues in the Sproule Report. Only well abandonment costs and disconnect costs for wells which have reserves assigned were deducted in estimating future net revenue in the Sproule Report. No allowance for surface lease reclamation or down-hole salvage value was included. It does not include costs to abandon pipelines, facilities or wells for which no reserves have been assigned.

Total Abandonment and Reclamation Costs and Timing for Expected Payments
Year Total Proved (M$) Total Proved
Plus Probable (M$)
2014 233 121
2015 470 215
2016 416 218
2017 961 466
2018 2,196 856
Remaining 22,228 47,755
Total (Undiscounted) 26,504 49,631
Total (Discounted at 10%) 9,203 10,403

TAX HORIZON

The Company did not pay any current income taxes in the year ended December 31, 2013. As at December 31, 2013, the Company had approximately $595 million of tax pools and loss carry-forwards available to be applied against future income for tax purposes (not all tax pools can be fully utilized in any single year).

On a total proved reserves basis, the Sproule Report estimates that the Company will be taxable in 2018. On a proved and probable reserves basis, the Sproule Report indicates the Company will be taxable in 2017. The Sproule Report does not include capital spending on projects that have not been assigned proved and probable reserves. This additional spending could impact the Company's tax horizon. The Company's internal estimate is that it will not be taxable until at least 2018.

The Company's tax horizon is dependent on, among other things, anticipated levels of operations, anticipated capital spending, the current tax regime and the current commodity price forecast. Changes in these factors from estimates used by the Company could result in the Company paying income taxes earlier or later than expected.

COSTS INCURRED

The following table summarizes capital expenditures made by BlackPearl on oil and natural gas properties for the year ended December 31, 2013.

($millions) Canada U.S. Total
Property acquisition costs - unproved 2.1 0.0 2.1
Property acquisition costs - proved 3.0 0.0 3.0
Exploration costs (1) 24.3 0.0 24.3
Development costs 66.2 0.0 66.2
Total 95.6 0.0 95.6

Note:
  1. Includes costs of land, geological and geophysical expenses and drilling costs for exploration wells.

EXPLORATION AND DEVELOPMENT ACTIVITIES

The following table summarizes the number of gross and net exploratory and development wells BlackPearl participated in drilling during the year ended December 31, 2013.

  Development wells Exploratory wells
  Gross Net Gross Net
         
Oil Wells 45 41 - -
Gas Wells - - - -
Service Wells - - - -
Stratigraphic Wells 1 1    
Dry 1 1 - -
Total 47 43 - -

All of the wells drilled in 2013 were located in Canada, and all of our planned exploration and development activities for 2014 are located in Canada. For a summary of our most important current and likely exploration and development activities, see "Description of Our Business - Description of Our Properties".

PRODUCTION ESTIMATES

The following table sets out the estimated working interest production volumes for the year ended December 31, 2014 which is reflected in the estimate of gross proved and probable reserves disclosed in the tables contained under "Statement of Reserves and Contingent Resources Data and Other Oil and Gas Information".

  Gross Daily
Production Total
Total Proved  
Light & Medium Oil (Bbl/d) 0
Heavy Oil (Bbl/d) 9,682
Bitumen (Bbl/d) 605
Natural Gas (Mcf/d) 219
Natural Gas Liquids (Bbl/d) 0
Total (Boe/d) 10,323
Total Probable  
Light & Medium Oil (Bbl/d) 0
Heavy Oil (Bbl/d) 1,448
Bitumen (Bbl/d) 28
Natural Gas (Mcf/d) 83
Natural Gas Liquids (Bbl/d) 0
Total (Boe/d) 1,490
Total Proved + Probable  
Light & Medium Oil (Bbl/d) 0
Heavy Oil (Bbl/d) 11,130
Bitumen (Bbl/d) 633
Natural Gas (Mcf/d) 302
Natural Gas Liquids (Bbl/d) 0
Total (Boe/d) 11,813

All of BlackPearl's forecasted production for 2014 is expected to come from the Company's Canadian properties. The Onion Lake field in Saskatchewan accounts for 44% (5,253 Boe/d) of BlackPearl's total forecasted 2014 production from its Proved plus Probable reserves and the Mooney field in Alberta accounts for 41% (4,812 Boe/d) of BlackPearl's total forecasted 2014 production from its Proved plus Probable reserves.

PRODUCTION HISTORY

The following table indicates the Company's average gross daily oil and gas production in 2012 and 2013:

      2013       2012  
  Heavy Oil Bitumen Natural Gas Boe/d Heavy Oil Bitumen Natural Gas Boe/d
  (Bbl/d) (Bbl/d) (Mcf/d)   (Bbl/d) (Bbl/d) (Mcf/d)  
Onion Lake 4,797 - - 4,797 5,947 - - 5,947
Mooney 3,543 - 854 3,685 2,475 - 369 2,537
John Lake 898 - - 898 573 - - 573
Blackrod - 236 - 236 - 272 - 272
Other 17 - 580 114 36 - 5 37
  9,255 236 1,434 9,730 9,031 272 374 9,366

NETBACKS

The following table sets forth certain information in respect of production, product prices, royalties, transportation costs, production costs and netbacks received for each quarter of the Company's most recently completed financial year. The table excludes operating results of the pilot project at Blackrod.

  Quarter Ended Year Ended
  Mar. 31, 2013 June 30, 2013 Sep. 30, 2013 Dec. 31, 2013 2013
           
Average Daily Production (1)          
Heavy Oil (Bbl/d) 8,868 9,358 8,805 9,981 9,494
Natural Gas (mcf/d) 879 1,942 1,643 1,266 1,434
Products Combined (Boe/d) 9,014 9,682 9,079 10,192 10,928
Average Net Prices Received          
Heavy Oil ($/Bbl) 50.64 67.30 84.85 58.44 65.09
Natural Gas ($/Mcf) 3.18 3.59 2.38 3.50 3.16
Products Combined (Boe/d) 50.13 66.20 82.72 57.67 64.11
Transportation Costs (2)          
Heavy Oil ($/Boe) 3.60 3.32 2.50 1.77 2.77
Royalties          
Heavy Oil ($/Boe) 7.80 13.33 17.39 11.87 12.62
Production Costs (2)          
Heavy Oil ($/Boe) 23.05 20.90 19.95 19.65 20.84
Netback Received (3)          
Heavy Oil ($/Boe) 15.68 28.65 42.88 24.38 27.88

Notes:
  1. Before deduction of royalties.
  2. Operating expenses are composed of direct costs incurred to operate both oil and gas wells. The majority of our gas volumes are associated gas from oil wells and are not material amounts (1%); therefore, we have reported transportation costs, royalties, production costs and netbacks on a Boe basis only.
  3. Netbacks are calculated by subtracting royalties, transportation costs and production expenses from revenues.
 



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