Exhibit 99.2
ALBERTA STAR DEVELOPMENT CORP.
Statement of Reserve Data
And Other Oil and Gas Information
Effective November 30, 2010
Prepared on March 28, 2011
Statement Date of March 28, 2011
TABLE OF CONTENTS
| |
| CONVERSION OF UNITS | i |
| STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION | 1 |
| PRICING ASSUMPTIONS | 4 |
| RECONCILIATION OF CHANGES IN RESERVES | 5 |
Reserves Reconciliation | 5 |
| ADDITIONAL INFORMATION RELATING TO RESERVES DATA | 5 |
Proved Undeveloped Reserves and Probable Undeveloped Reserves | 5 |
Significant Factors or Uncertainties Affecting Reserves Data | 6 |
Future Development Costs | 6 |
| OTHER OIL AND GAS INFORMATION | 7 |
Properties | 7 |
Alberta | 7 |
Saskatchewan | 8 |
Properties With No Attributed Reserves | 8 |
Forward Contracts | 8 |
Additional Information Concerning Abandonment and Reclamation Costs | 9 |
Tax Horizon | 9 |
Costs Incurred | 9 |
Exploration and Development Activities | 9 |
Production Estimates | 10 |
Production History | 10 |
Netback History | 11 |
Production Volume by Field | 11 |
| |
| APPENDIX A Form 51-101F2 - Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor | A-1 |
| | |
| APPENDIX B Form 51-101F3 - Report of Management and Directors on Reserves Data and Other Information | B-1 |
| | |
| APPENDIX C Oil & Gas Definitions | C-1 |
i
GLOSSARY OF ABBREVIATIONS
| |
| bbl | Barrels |
| bbl/d | Barrels per day |
| boe | Barrel of oil equivalent (6 Mcf = 1Bbl) |
| boe/d | Barrels of oil equivalent per day |
| GJ | Gigajoules |
| GJ/d | Gigajoules per day |
| Mbbl | 1,000 Barrels |
| Mcf | 1,000 cubic feet |
| Mcf/d | 1,000 cubic feet per day |
| MMcf | 1,000,000 cubic feet |
| MMbtu | One Million British Thermal Units |
| NGL | Natural gas liquids |
| WTI | West Texas Intermediate |
| M$ | Thousands of dollars |
| MM$ | Millions of dollars |
CONVERSION OF UNITS
| |
| 1acre | 0.4 hectares |
| 2.5 acres | 1 hectare |
| 1bbl | 0.159 cubic metres |
| 6.29bbl | 1 cubic metre |
| 1foot | 0.3048 metres |
| 3.281feet | 1 metre |
| 1Mcf | 28.2 cubic metres |
| 0.035Mcf | 1 cubic metre |
| 1 MMbtu | 1.054 GJ |
| 0.949 MMbtu | 1 GJ |
In this Statement of Reserves where amounts are expressed on a barrel of oil equivalent basis, natural gas volumes have been converted to oil equivalence at six thousand cubic feet per barrel. The term boe may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet per 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.
FORWARD-LOOKING STATEMENTS
This Statement of Reserves contains forward-looking statements and forward-looking information (collectively, “forward-looking statements”) within the meaning of applicable Canadian securities legislation. These forward-looking statements relate to future events or the Corporation’s future performance. All forward-looking statements contained herein that are not clearly historical in nature constitute forward-looking statements, and the words “may”, “will”, “should”, “could”, “expect”, “plan”, “intend”, “anticipate”, “believe”, “estimate”, “propose”, “predict”, “potential”, “continue”, or the negative of these terms or other comparable terminology are generally intended to identify forward-looking statements. Such statements represent the Corporation’s internal projections, estimates or beliefs concerning, among other things, an outlook on the estimated amounts and timing of capital expenditures, anticipated future debt levels and revenues or other expectations, beliefs, plans, objectives, assumptions, intentions or statements about future events or performance. These statements are not guarantees of future performance and involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in the forward-looking statements. In addition, this Statement of Reserves may contain forward-looking statements attributed to third party industry sources. Alberta Star believes that the expectations reflected in these forward-looking statements are reasonable, however, undue reliance should not be placed on these forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur.
Forward-looking statements in this Statement of Reserves include, but are not limited to, statements with respect to:
the business plan of Alberta Star;
the ability of Alberta Star to retain and attract skilled persons in the future;
acquisition, including the considerations taken into account, and financing opportunities;
drilling inventory, drilling plans and timing of drilling, re-completion and tie-in of wells;
the ability of internally generated cash flow and unused bank credit facilities to fund future development costs;
drilling, completion and facilities costs;
growth expectations within Alberta Star;
timing of development of undeveloped reserves;
the tax horizon of Alberta Star;
abandonment and reclamation costs;
the performance and characteristics of Alberta Star’s oil and natural gas properties;
oil and natural gas production levels;
the quantity of oil and natural gas reserves;
capital expenditure programs;
expected royalty rates, operating and general administrative costs, costs of services and other costs and expenses.
Some of the risks and other factors which could cause actual results to differ materially from those expressed in the forward-looking statements contained in this Statement of Reserves include, but are not limited to:
general economic and business conditions in Canada, the United States and globally;
the ability of management to execute its business plan;
fluctuations in the price of oil and natural gas, interest and exchange rates;
the risks of the oil and gas industry both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil and natural gas and market demand;
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actions taken by governmental authorities, including increases in taxes and changes in government regulations and incentive programs;
geological, technical, drilling and processing problems;
risks and uncertainties involving geology of oil and gas deposits;
risks inherent in marketing operations, including credit risk;
the ability to enter into or renew leases;
the uncertainty of estimates and projections relating to production, costs and expenses;
potential delays or changes in plans with respect to exploration or development projects or capital expenditures;
availability of sufficient financial resources to fund the Corporation’s capital expenditures;
uncertainty of finding reserves, developing and marketing those reserves;
unanticipated operating events, which could reduce production or cause production to be shut in or delayed;
incorrect assessments of the value of acquisitions;
ability to locate satisfactory properties for acquisition or participation;
shut-ins of connected wells resulting from extreme weather conditions;
insufficient storage or transportation capacity;
hazards such as fire, explosion, blowouts, cratering and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury;
encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations;
the ability to add production and reserves through development and exploration activities;
the possibility that government policies or laws, including laws and regulations related to the environment, may change or governmental approvals may be delayed or withheld;
uncertainty in amounts and timing of royalty payments;
uncertainties inherent in estimating quantities of oil and natural gas reserves and cash flows to be derived therefrom;
failure to obtain industry partner and other third party consents and approvals, as and when required;
stock market volatility and market valuations;
changes in hydrocarbon or investment policies;
competition for and/or inability to retain drilling rigs and other services;
the need to obtain required approvals from regulatory authorities; and
competition for, among other things, capital, acquisition of reserves, undeveloped land and skilled personnel.
Forward-looking statements contained in certain documents incorporated by reference into this Statement of Reserves are based on the key assumptions described in such documents. The reader is cautioned that such information, although considered reasonable by the Corporation may prove to be incorrect. Actual results achieved during the forecast period will vary from the forward-looking statements provided in this Statement of Reserves and in the documents incorporated by reference herein as a result of numerous known and unknown risks and uncertainties and other factors which are discussed in the documents incorporated herein by reference.
With respect to forward-looking statements contained in this Statement of Reserves, the Corporation has made assumptions regarding: the impact of increasing competition; the general stability of the economic and political environment in which the Corporation operates; the timely receipt of any required regulatory approvals; the ability of the Corporation to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which the Corporation has an interest to operate the field in a safe, efficient and effective manner; the ability of the Corporation to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development of exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Corporation to secure adequate product transportation; future oil and natural gas prices; currency exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Corporation operates; and the ability of the Corporation to successfully market its oil and natural gas products. Readers are cautioned that this information may not be appropriate for other purposes.
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Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking statements contained in this Statement of Reserves are expressly qualified by this cautionary statement. In addition, please note that information relating to reserves are deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described can be economically produced in the future.
This forward-looking statements is made as of the date of this Statement of Reserves, and the Corporation disclaims any intent or obligation to update publicly any such forward-looking information, whether as a result of new information, future events or results or otherwise, other than as required by applicable Canadian securities laws.
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
Chapman Petroleum Engineering Ltd. (“Chapman”), independent petroleum engineers of Calgary, Alberta, prepared a report entitled “Alberta Star Development Corp. - Reserve and Economic Evaluation (as of December 1, 2010)” (the “Chapman Report”), effective November 30, 2010, and dated March 14, 2011, evaluating the proved and probable reserves attributable to Alberta Star’s interest in 100% of its Canadian properties and the net present value of estimated future cash flow from such reserves, based on forecast price and cost assumptions. The reserves information presented herein was prepared and is presented in accordance with the requirements of National Instrument 51 101 –Standards of Disclosure for Oil and Gas Activities(“NI 51-101”).
In preparing the Chapman Report, Chapman obtained information from Alberta Star, 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 the Chapman Report is based, was obtained from public records, other operators and from Chapman’s non-confidential files. The extent and character of ownership and the accuracy of all factual data supplied for the independent evaluation, from all sources, was accepted by Chapman as represented.
All evaluations of the present value of estimated future net revenue in the Chapman Report are stated after provision for estimated future capital expenditures, well abandonment and reclamation costs (including the offsetting salvage value of tangible equipment after abandonment) but prior to income taxes and indirect costs and do not necessarily represent the fair market value of the reserves. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumption will be attained and variances could be material. Actual reserves may be greater than or less than the estimates provided herein. Please note that information relating to reserves are deemed to be forward-looking statements, as they involve the implicit assessment, based on certain estimates and assumptions, that the reserves described can be economically produced in the future. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.
Reference to oil, gas, natural gas liquids, coalbed methane, reserves (gross, net, proved, probable, possible, developed, developed producing, developed non producing, undeveloped), forecast prices and costs, operating costs, development costs, future net revenue and future income tax expenses shall, unless expressly stated to be to the contrary, have the meaning attributed to such terms as set out in NI 51-101, the companion policy to NI 51-101 and all forms referenced therein.
Throughout the following summary, table differences may arise due to rounding.
In accordance with the requirements of NI 51-101, attached hereto are the following appendices:
| |
| Appendix A: | Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor in Form 51-101F2; and |
| | |
| Appendix B: | Report of Management and Directors on Reserves Data and Other Information in Form 51-101F3. |
Definitions used for reserve categories in the Chapman Report are attached as Appendix C hereto.
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For the purposes herein, and unless otherwise noted, “Gross” means: (a) in relation to the Corporation’s interest in production or reserves, its “company gross reserves”, which are its working interest (operating or non-operating) share before deduction of royalties and without including any royalty interest of the Corporation; (b) in relation to wells, the total number of wells in which the Corporation has an interest; and (c) in relation to properties, the total area of properties in which the Corporation has an interest.
For the purposes herein, and unless otherwise noted, “Net” means: (a) in relation to the Corporation’s interest in production or reserves, the Corporation’s working interest (operating or non-operating) share after deduction or royalty obligations, plus the Corporation’s royalty interest in production or reserves; (b) in relation to the Corporation’s interest in wells, the number of wells obtained by aggregating the Corporation’s working interest in each of its gross wells; and (c) in relation to a Corporation’s interest in a property, the total area in which the Corporation has an interest multiplied by the working interest owned by the Corporation.
The following tables summarize certain information related to Alberta Star’s oil and gas reserves as of November 30, 2010 based on forecast price and cost assumptions:
| | | | | | | | | | |
SUMMARY OF OIL AND GAS RESERVES
as of November 30, 2010
FORECAST PRICES AND COSTS |
|
|
| Reserves Category | Reserves |
Light and Medium
Oil | Heavy Oil | Natural Gas(1) | Natural Gas
Liquids | Coalbed Methane |
Gross
(MSTB) | Net
(MSTB) | Gross
(MSTB) | Net
(MSTB) | Gross
(MMscf) | Net
(MMscf) | Gross
(Mbbl) | Net
(Mbbl) | Gross
(MMscf) | Net
(MMscf) |
| PROVED | | | | | | | | | | |
| Developed Producing | 0 | 0 | 114 | 101 | 0 | 0 | 0 | 0 | 0 | 0 |
| Developed Non-Producing | 0 | 0 | 30 | 25 | 0 | 0 | 0 | 0 | 0 | 0 |
| Undeveloped | 0 | 0 | 47 | 38 | 0 | 0 | 0 | 0 | 0 | 0 |
| TOTAL PROVED | 0 | 0 | 190 | 164 | 0 | 0 | 0 | 0 | 0 | 0 |
| Probable | 0 | 0 | 343 | 294 | 0 | 0 | 0 | 0 | 0 | 0 |
| TOTAL PROVED PLUSPROBABLE | 0 | 0 | 533 | 457 | 0 | 0 | 0 | 0 | 0 | 0 |
Note:
| |
| (1) | Natural gas volumes include associated, non-associated and solution gas but not coalbed methane. |
| | | | | | | | | | |
SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE
as of November 30, 2010 |
|
| Reserves Category | Net Present Values of Future Net Revenue |
Before Income Tax
Discounted at | After Income Tax
Discounted at |
0%/yr
$M | 5%/yr.
$M | 10%/yr.
$M | 15%/yr.
$M | 20%/yr.
$M | 0%/yr
$M | 5%/yr.
$M | 10%/yr.
$M | 15%/yr.
$M | 20%/yr.
$M |
| | | | | | | | | | | |
| PROVED | | | | | | | | | | |
| Developed Producing | 4,237 | 3,666 | 3,246 | 2,925 | 2,671 | 4,237 | 3,666 | 3,246 | 2,925 | 2,671 |
| | | | | | | | | | | |
| Developed Non-Producing | 1,274 | 1,175 | 1,094 | 1,026 | 969 | 1,274 | 1,175 | 1,094 | 1,026 | 969 |
| Undeveloped | 1,004 | 792 | 623 | 487 | 376 | 1,004 | 792 | 623 | 487 | 376 |
| TOTAL PROVED | 6,515 | 5,633 | 4,963 | 4,438 | 4,017 | 6,515 | 5,633 | 4,963 | 4,438 | 4,017 |
| TOTAL PROBABLE | 14,383 | 10,719 | 8,309 | 6,626 | 5,400 | 13,080 | 9,842 | 7,699 | 6,190 | 5,080 |
| TOTAL PROVED +PROBABLE | 20,899 | 16,352 | 13,272 | 11,065 | 9,417 | 19,595 | 15,476 | 12,662 | 10,629 | 9,097 |
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| | | | | | | | |
| TOTAL FUTURE NET REVENUE (UNDISCOUNTED) |
| As of November 30, 2010 |
| FORECAST PRICES AND COSTS |
| | | | | | | | | Future |
| | | | | | | Future | | Net |
| | | | | | | Net | | Revenue |
| | | | | | Well | Revenue | Future | After |
| | | | | Operating | Abandonment | Before | Income | Deducting |
| | | | | Development | Reclamation | Income | Taxes and | Income |
| | Revenue | Royalties | Costs | Costs | and Costs | Taxes | Expenses | Taxes |
| Reserves Category | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) |
| PROVED | | | | | | | | |
| Developed Producing | 9,157 | 1,151 | 3,316 | 10 | 492 | 4,238 | 0 | 4,238 |
| Developed Non-Producing | 2,192 | 364 | 476 | 34 | 44 | 1,274 | 0 | 1,274 |
| Undeveloped | 3,658 | 660 | 971 | 916 | 108 | 1,003 | 0 | 1,003 |
| TOTAL PROVED | 15,007 | 2,175 | 4,763 | 960 | 594 | 6,515 | 0 | 6,515 |
| Probable | 28,392 | 4,021 | 7,581 | 2,106 | 301 | 14,385 | (1,303) | 13,080 |
| TOTAL PROVED PLUS PROBABLE | 43,399 | 6,196 | 12,344 | 3,066 | 895 | 20,899 | (1,303) | 19,595 |
| | | |
| FUTURE NET REVENUE BY PRODUCTION GROUP |
| as of November 30, 2010 |
| FORECAST PRICES AND COSTS |
| | | FUTURE NET | FUTURE NET |
| | | REVENUE | REVENUE BEFORE |
| | | BEFORE | INCOME TAXES |
| | | INCOME TAXES | (discounted at |
| | | (discounted at | 10%/year) |
| RESERVES | | 10%/year) | ($/MCF) |
| CATEGORY | PRODUCTION GROUP | (M$) | ($/BBL) |
| PROVED | Light and Medium Oil (including solution gas and associated by products) | 0 | 0 |
| | | | |
| | Heavy Oil (including solution gas and other associated by products) | 4,963 | 26.06 |
| | | | |
| | Natural Gas (including associated by-products but excluding solution gas and by-products from oil wells) | 0 | 0 |
| | | | |
| | Coalbed Methane (including associated by-products) | 0 | 0 |
| | | | |
| | Non-Conventional Oil & Gas Activities (excluding coalbed methane) | 0 | 0 |
| | | | |
| | Total | | |
| PROVED PLUS PROBABLE | Light and Medium Oil (including solution gas and associated by products) | 0 | 0 |
| | | | |
| | Heavy Oil (including solution gas and associated by-products) | 13,272 | 24.90 |
| | | | |
| | Natural Gas (including associated by-products but excluding solution gas and by-products from oil wells) | 0 | 0 |
| | | | |
| | Coalbed Methane (including associated by-products) | 0 | 0 |
| | | | |
| | Non-Conventional Oil & Gas Activities (excluding coalbed methane) | 0 | 0 |
| | | | |
| | Total | 13,272 | 0 |
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PRICING ASSUMPTIONS
Chapman employed the following pricing, exchange rate and inflation rate assumptions in estimating Alberta Star’s reserves data using forecast prices and costs as of December 1, 2010.
| | | | | | |
| | | Alberta | Alberta | Sask. | Sask. | B.C. |
| | WTI [1] | Par Price [2] | Heavy [3] | Light [4] | Heavy [5] | Light [6] |
| Date | $US/STB | $CDN/STB | $CDN/STB | $CDN/STB | $CDN/STB | $CDN/STB |
| HISTORICAL PRICES | | | | | | |
| 2000 | 30.39 | 44.90 | 34.51 | 43.37 | 40.12 | n/a |
| 2001 | 25.98 | 39.66 | 25.41 | 35.57 | 31.84 | n/a |
| 2002 | 26.09 | 40.63 | 32.20 | 37.67 | 34.57 | n/a |
| 2003 | 30.84 | 43.57 | 32.65 | 40.13 | 37.64 | n/a |
| 2004 | 41.48 | 52.89 | 37.52 | 48.96 | 45.74 | n/a |
| 2005 | 56.62 | 69.16 | 43.25 | 62.04 | 56.53 | n/a |
| 2006 | 65.91 | 72.88 | 50.40 | 66.77 | 61.23 | n/a |
| 2007 | 70.61 | 75.57 | 53.17 | 71.42 | 64.55 | n/a |
| 2008 | 99.70 | 102.98 | 83.88 | 98.02 | 92.45 | n/a |
| 2009 | 61.64 | 68.91 | 58.48 | 65.15 | 63.48 | n/a |
| 2010 (11 mos) | 81.01 | 79.97 | 66.18 | 76.27 | 72.19 | n/a |
| CONSTANT PRICES | | | | | | |
| November 30, 2010 [7] | 84.11 | 85.10 | 71.50 | 85.55 | 79.82 | 82.97 |
| CURRENT YEAR FORECAST | | | | | | |
| 2010 (1 mos) | 80.00 | 83.21 | 70.31 | 78.38 | 75.17 | 81.13 |
| FUTURE FORECAST | | | | | | |
| 2011 | 83.00 | 86.37 | 72.98 | 81.36 | 78.02 | 84.21 |
| 2012 | 86.00 | 89.53 | 75.65 | 84.33 | 80.88 | 87.29 |
| 2013 | 90.00 | 93.74 | 79.21 | 88.30 | 84.68 | 91.39 |
| 2014 | 93.00 | 96.89 | 81.88 | 91.27 | 87.53 | 94.47 |
| 2015 | 96.00 | 100.05 | 84.54 | 94.25 | 90.39 | 97.55 |
| 2016 | 98.00 | 102.16 | 86.32 | 96.23 | 92.29 | 99.60 |
| 2017 | 100.00 | 104.26 | 88.10 | 98.22 | 94.19 | 101.66 |
| 2018 | 102.00 | 106.37 | 89.88 | 100.20 | 96.09 | 103.71 |
| 2019 | 104.04 | 108.52 | 91.70 | 102.22 | 98.03 | 105.80 |
| 2020 | 106.12 | 110.71 | 93.55 | 104.29 | 100.01 | 107.94 |
| 2021 | 108.24 | 112.94 | 95.43 | 106.39 | 102.03 | 110.12 |
| 2022 | 110.41 | 115.22 | 97.36 | 108.54 | 104.09 | 112.34 |
| 2023 | 112.62 | 117.54 | 99.32 | 110.73 | 106.19 | 114.60 |
| 2024 | 114.87 | 119.91 | 101.33 | 112.96 | 108.33 | 116.92 |
| 2025 | 117.17 | 122.33 | 103.37 | 115.24 | 110.51 | 119.27 |
| Constant thereafter | | | | | | |
| |
| Notes: | |
| (1) | West Texas Intermediate quality (D2/S2) crude landed in Cushing, Oklahoma. |
| (2) | Equivalent price for Light Sweet Crude (D2/S2) landed in Edmonton, Alberta after exchange of 0.95US$/C$ from 2010to 2025 during forecasting period and transportation differential of $1.00 CDN/STB. |
| (3) | Bow River at Hardisty, Alberta (905 kg/m3, 2.1% sulphur). |
| (4) | Light Sour Blend at Cromer, Saskatchewan (880 kg/m3, 2.0% sulphur). |
| (5) | Midale at Cromer, Saskatchewan (880 kg/m3, 2.0% sulphur). |
| (6) | B.C. Light at Taylor, British Columbia (825 kg/m3, 0.5% sulphur). |
| (7) | November 30, 2010 is the last trading day of November 2010. |
Alberta Star’s weighted average realized sales prices for the year ended November 30, 2010 were $56.90 /bbl for heavy oil.
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RECONCILIATION OF CHANGES IN RESERVES
Reserves Reconciliation
The following tables set forth a reconciliation of Alberta Star’s total gross proved, probable and proved plus probable reserves as at November 30, 2010 against such reserves as at November 30, 2009 based on forecast price and cost assumptions:
| | | | | | | | | |
| | LIGHT AND MEDIUM OIL | | HEAVY OIL | | NATURAL GAS(1) |
| | | | Gross | | | Gross | | | |
| | | | Proved | | | Proved | | | |
| | Gross | Gross | Plus | Gross | Gross | Plus | Gross | Gross | Gross Proved |
| | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Plus Probable |
| FACTORS | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (MMcf) | (MMcf) | (MMcf) |
| November 30, 2009 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 |
| Acquisitions | | | | 203 | 447 | 649 | | | |
| Discoveries | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 |
| Dispositions | 0 | 0 | 0 | 0 | (120) | (120) | 0 | 0 | 0 |
| Extensions and Improved Recovery | 0 | 0 | 0 | 20 | 40 | 60 | 0 | 0 | 0 |
| Technical Revisions(2) | 0 | 0 | 0 | 12 | (23) | (10) | 0 | 0 | 0 |
| Economic Factors | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 |
| Gross Production | 0 | 0 | 0 | 43 | 0 | 43 | 0 | 0 | 0 |
| November 30, 2010 | 0 | 0 | 0 | 192 | 344 | 536 | 0 | 0 | 0 |
| |
| Notes: | |
| (1) | Natural gas volumes include associated, non-associated and solution gas but does not include coalbed methane. |
| (2) | Technical revisions to reserve volumes for November 30, 2010. |
ADDITIONAL INFORMATION RELATING TO RESERVES DATA
Proved Undeveloped Reserves and Probable Undeveloped Reserves
Proved undeveloped reserves are generally those reserves related to wells that have been tested and not yet tied-in, wells drilled near the end of the fiscal year or wells further away from Alberta Star gathering systems. In addition, such reserves may relate to planned infill drilling locations. These reserves are planned to be on stream within a two year timeframe.
Probable undeveloped reserves are generally those reserves tested or indicated by analogy to be productive, infill drilling locations and lands contiguous to production. These reserves are planned to be on stream within a two year timeframe.
The following provides the gross volumes of proved undeveloped reserves and probable undeveloped reserves of Alberta Star that were first attributed and booked in each of the most recent three financial years of Alberta Star ending on the date of the Chapman Report, and in the aggregate, before that time:
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| | | | | | | | | | | | | | | | | | | | |
| TOTAL CORPORATION |
TIME
PERIOD | LIGHT AND MEDIUM
OIL
(Mbbl) | HEAVY OIL
(Mbbl) | NATURAL GAS
LIQUIDS
(Mbbl) | NATURAL GAS
(Mmcf) | COAL BED
METHANE
(Mmcf) |
|
|
| | PROVED | PROBABLE | PROVED | PROBABLE | PROVED | PROBABLE | PROVED | PROBABLE | PROVED | PROBABLE |
| A* | B* | A* | B* | A* | B* | A* | B* | A* | B* | A* | B* | A* | B* | A* | B* | A* | B* | A* | B* |
| 2010 | 0 | 0 | 0 | 0 | 47 | 47 | 343 | 343 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 |
| 2009 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 |
| 2008 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 |
| Prior to 2007 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 |
| |
| Notes: | |
| (1) | “A*” - First Attributed |
| (2) | “B*” - Booked |
Significant Factors or Uncertainties Affecting Reserves Data
The process of estimating reserves is complex. It requires significant judgment 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 and as economic conditions impacting oil and gas prices and costs change. The reserve estimates contained herein are based on current production forecasts, commodity prices and economic conditions. Alberta Star’s reserves are evaluated by Chapman, an independent engineering firm.
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, commodity 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. Alberta Star’s actual production, revenues, taxes, development and operating expenditures with respect to its reserves may vary from such estimates, and such variances could be material.
Future Development Costs
The following table outlines development costs deducted in the estimation of future net revenue attributable to proved reserves and proved plus probable reserves using forecast prices and costs:
| | |
| | Canada |
| | | Proved Plus Probable |
| | Proved Reserves | Reserves |
| Year | (M$) | (M$) |
| 2011 | 950 | 2,606 |
| 2012 | 0 | 0 |
| 2013 | 0 | 0 |
| 2014 | 0 | 0 |
| 2015 | 0 | 0 |
| Remaining Years | 0 | 0 |
| Total Undiscounted | 950 | 2,606 |
Alberta Star has established a $2.5 million capital program (the “2011 Capital Program”) to fund its exploration and development activities for 2011 of which $2.1 million is budgeted for drilling, completing and equipping an estimated 10-12 wells (5-6 net to the Company) in Alberta and
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Saskatchewan. The 2011 Capital Program does not include any new acquisition opportunities, which Alberta Star believes will likely be financed through debt or equity financings.
Alberta Star estimates that its internally generated cash flow and unused bank credit facilities are sufficient to fund the future development costs disclosed above. Alberta Star typically has available three sources of funding to finance its capital expenditure program: internally generated cash flow from operating activities, debt financing when appropriate and new equity issues, if available on favourable terms.
OTHER OIL AND GAS INFORMATION
Properties
Alberta Star has interests in 4 core Canadian properties. These areas are the subjects of the Chapman Report. The following provides a description of Alberta Star’s properties. All of Alberta Star’s properties are located on-shore in the Provinces of Alberta and Saskatchewan, Canada.
Alberta
Lloydminster (Western Plains Acquisition August 2010)
The Lloydminster properties consisted of 14 shut in wells on 27 LSD’s is located in close proximity to the city of Lloydminster in east central Alberta in townships 06-24-50-2W4 and 06-50-1W4 when purchased in August 2010. As of November 30th, 2010, the property consisted of 7 producing oil wells and 3 shut-in, 3 wells to be completed and with Alberta Star having a 33 1/3% working interest in 1,420 acres of land in this area. A combined total of 10 oil wells are now producing medium-heavy oil from the Sparky formation. Oil is transported by a tanker truck to the terminal at the Lloydminster Blackfoot battery facility and then to Husky upgrader and pipeline system.
Lloydminster (Western Plains Property)
The Lloydminster property is located in close proximity to the city of Lloydminster in east central Alberta in townships 12-22-49-1W4, 11-12-50-3W4 and 12-04-49-1W4. As of November 30th, 2010, the property consisted of 6 producing oil wells and 3 non-producing wells with Alberta Star having a 50% working interest in approximately 440 acres of land in this area. A combined total of 7 oil wells produce medium- heavy oil from the Sparky formation. In 2010, this area averaged 40 bbls day (20 net). Oil is transported by a tanker truck to the terminal Lloydminster Blackfoot battery facility and then to the Husky upgrader and pipeline system.
Saskatchewan
Landrose
The Landrose property is located in close proximity to the city of Lloydminster in west central Saskatchewan in township 6-50-25-W4M. As of November 30th, 2010, the property consisted of 2 producing oil wells with Alberta Star having a 50% working interest and 1 producing oil well with 25% working interest in 560 acres of land situated in this area. A combined total of 6 oil wells now produce medium-heavy oil from the McClaren formation. Oil is transported by a tanker truck to the Blackfoot or Marwain battery’s and then to the terminal Lloydminster Husky upgrader and pipeline system.
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Dee Valley
The Dee Valley property is located in close proximity to the city of Lloydminster in west central Saskatchewan in township 32-48-22-W3. As of November 30, 2011 the property consisted of 1 producing oil well and 3 non-producing wells with Alberta Star having a 50% working interest in 280.0 acres of land in this area. The single well produces medium- heavy oil from the Sparky formation. In 2010, this area averaged 12 bbls day (6 net). Oil is transported by a tanker truck to the Blackfoot & Marwain battery’s and then to the Husky upgrader and pipeline system.
Hillmond
The Hillmond property is located in close proximity to the city of Lloydminster in east central Alberta in township 06-51-25-W3. As of November 30, 2011 the property consisted of 1 producing oil well with Alberta Star having a 50% working interest in 40.25 acres of land in this area. The single well produces medium-heavy oil from the Sparky formations. In 2010, this area averaged 12 bbls day (6 net). Oil is transported by a tanker truck to the Balckfoot or Marwain terminal Lloydminster and then to the Husky upgrader and pipeline system.
Maidstone
The Maidstone property is located in close proximity to the city of Lloydminster in west central Saskatchewan in township 01-48-24-W3. As of November 30, 2011 the property consisted of 4 producing oil wells with Alberta Star having a 50% working interest in 160 acres of land in this area. A combined total of 4 oil wells now produce 35 bbls day of medium-heavy oil from the Sparky formation. In 2010, this area averaged 35 bbls day (17.5 net). Oil is transported by a tanker truck to the Blackfoot or Marwain Battery and then to the Lloydminster Husky upgrader and pipeline system.
Wells
As at November 30, 2010, Alberta Star had an interest in 18 gross (7 net) producing and 14 gross (9 net) non producing oil and natural gas wells and 0 gross (0 net) service wells as follows:
| | | | | | | | | | |
| | PRODUCING | NON-PRODUCING | SERVICE |
| | Oil | Natural Gas | Oil | Natural Gas | WELLS |
| Location | Gross(1) | Net(2) | Gross(1) | Net(2) | Gross(1) | Net(2) | Gross(1) | Net(2) | Gross(1) | Net(2) |
| Alberta | 14 | 5 | 0 | 0 | 7 | 3 | 0 | 0 | 0 | 0 |
| Saskatchewan | 4 | 2 | 0 | 0 | 7 | 6 | 0 | 0 | 0 | 0 |
| TOTAL | 18 | 7 | 0 | 0 | 14 | 9 | 0 | 0 | 0 | 0 |
Properties With No Attributed Reserves
Alberta Star does not have any properties with no attributed reserves.
There are no costs or work commitments associated with Alberta Star’s non-producing properties except for annual lease rental payments and abandonment costs.
Forward Contracts
Alberta Star may use certain financial instruments to hedge its exposure to commodity price fluctuations on a portion of its crude oil and natural gas production, however Alberta Star does not currently have any hedging transactions.
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Additional Information Concerning Abandonment and Reclamation Costs
Alberta Star estimates the costs associated with well abandonment and reclamation cost for surface leases, wells, facility and pipeline based on its previous experience, current regulations, costs, technology and industry standards. Alberta Star expects to incur abandonment and reclamation costs on 32 gross wells (16 net), including 2 net non-producing and 0 net service wells. Alberta Star’s share of the expected total abandonment and reclamation costs for wells with assigned reserves, non-producing and service wells and facilities, net of salvage value are summarized, without discount and using a discount rate of 10%, in the following table:
| | | | |
| | | Forecast Pricing (M$) | |
| | | | Proved Plus | Proved Plus |
| Category | Proved 0% | Proved 10% | Probable 0% | Probable NPV 10% |
| Wells with reserves assigned(1) | 594 | 316 | 895 | 334 |
| Wells with no reserves assigned and facilities(2) | 0 | 0 | 0 | 0 |
| Total abandonment and reclamation cost provision | 594 | 316 | 895 | 334 |
| Portion forecast to be paid during the next three years | 27 | 21 | 14 | 11 |
| |
| Notes: | |
| (1) | Abandonment and reclamation costs were estimated by Chapman and included in the Chapman Report for all wellsassigned reserves. |
| (2) | Alberta Star has estimated the timing and the costs associated with the abandonment and reclamation for wells with noreserves assigned and for facilities. This represents the total abandonment and reclamation costs that were not deductedin computing future net revenue. |
Tax Horizon
As of November 30, 2010, Alberta Star had estimated income tax deductions of approximately $16,523,767 available to reduce future taxable income. Alberta Star did not incur current income taxes in 2010.
Costs Incurred
The following table summarizes Alberta Star’s property acquisition costs, exploration costs and development costs (before property dispositions) incurred during the financial year ended November 30, 2010:
| |
| | Property Acquisitions and Capital Expenditures |
| | |
| | Amount |
| Nature of Cost | (M$) |
| Property Acquisition Costs | |
Proved | 3,165 |
Unproved | |
| Exploration Costs | 441 |
| Development Costs | 0 |
| Total | 3,606 |
Exploration and Development Activities
The following table summaries the results of exploration and development activities in Canada during the financial year ended November 30, 2010:
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| | |
| | CANADA |
| | | |
| Wells Completed in 2010 | Gross | Net |
| Development | | |
Oil | Nil | Nil |
Unsuccessful | Nil | Nil |
Service | Nil | Nil |
| Exploratory | | |
Oil | Nil | Nil |
Unsuccessful | Nil | Nil |
Service | Nil | Nil |
| Total | | |
The 2011 Capital Program has now been established at $2.5 million and it is to be funded from cash flow from operating activities and bank debt. Approximately $2.1 million has been (5-6 net to the Company) allocated to exploration and development programs, focused primarily on drilling 10-12 vertical heavy oil wells. The remaining CDN $400,000 has been allocated to upgrade facilities, optimize workovers –improve production efficiencies and to acquire land.
Production Estimates
The following tables disclose the estimated average daily production for 2011 for each product type associated with the first year of the gross proved reserves and gross probable reserves reported in the Chapman Report effective November 30, 2010, based on forecast prices and costs:
| | | | | | |
| | Light/Medium | | | Natural Gas | Coal-Bed | |
| | Oil | Heavy Oil | Natural Gas(1) | Liquids | Methane | Combined |
| Corporation | (Bbl/d) | (Bbl/d) | (Mcf/d) | (Bbl/d) | (Mcf/d) | (BOE/d) |
| Proved | | | | | | |
| Developed Producing | - | 188 | - | - | - | 188 |
| Developed Non-Producing and | - | 13 | - | - | - | 13 |
| Undeveloped | | | | | | |
| Total Proved | - | 201 | - | - | - | 201 |
| Probable | - | 44 | - | - | - | 44 |
| Total Proved Plus Probable | - | 245 | - | - | - | 245 |
| |
| Note: | |
| (1) | Natural gas volume includes associated and non-associated gas. |
Production History
The following table summarizes the share of Alberta Star’s average daily production in Canada, before deduction of royalties, for the periods indicated:
| | | | | |
| Product | 2010 |
| Year | Q4 | Q3 | Q2 | Q1 |
| Heavy Oil (Bbl/d) | | 55 | 23 | - | - |
| Total (BOE/d) | | 55 | 23 | - | - |
| |
| Note: | |
| (1) | Natural gas volume includes associated, non-associated and solution gas. |
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Netback History
The following table sets forth information respecting average net product prices received, royalties paid, production expenses and operating netbacks received by Alberta Star in respect of Alberta Star’s Canadian production for the periods indicated.
| | | |
| | | 2010 | |
| Category | Year | Q4 | Q3 |
Selling Prices | | | |
| Heavy Oil ($/Bbl) | | 64.39 | 56.83 |
| Royalties | | | |
| Heavy Oil ($/Bbl) | | 6.75 | 7.78 |
Production Expenses(2) | | | |
| Heavy Oil ($/Bbl) | | 43.64 | 29.22 |
Operating Netbacks | | | |
| Heavy Oil ($/Bbl) | | $14.00 | $18.83 |
| Total (BOE/d) | | 55 | 23 |
| |
| Notes: | |
| (1) | Natural gas volume includes associated, non-associated and solution gas and coalbed methane. |
| (2) | Production expenses include petroleum and surface lease rentals, transportation costs, property taxes and expenses |
| | related to the operation and maintenance of wells, production facilities and gathering systems. |
Production Volume by Field
The following table discloses for each important field, and in total, Alberta Star’s production volumes for the financial year ended November 30, 2010 for each product type:
| |
| | Heavy Oil |
| Field | (Bbl/d) |
| | |
| Alberta | |
| Lloydminster | 106 |
| Total Alberta | 106 |
| Saskatchewan | |
| Lloydminster | 4 |
| Landrose | 33 |
| Maidstone | 20 |
| Other | |
| Total Saskatchewan | 57 |
| Total | 163 |
| |
| Note: | |
| (1) | Includes associated, non-associated and solution gas and coalbed methane. |
APPENDIX A
FORM 51-101F2-
REPORT ON RESERVES DATA
BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR
To the Board of Directors of Alberta Star Development Corp. (the “Company”):
| 1. | We have evaluated the Company’s reserves data as at November 30, 2010. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at November 30, 2010, estimated using forecast prices and costs. |
| |
| 2. | The reserves data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation. |
| |
| | We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society). |
| |
| 3. | Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook. |
| |
| 4. | The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year ended November 30, 2010 and identifies the respective portions thereof that we have evaluated and reported on to the Company’s management and board of directors: |
| | | | | | |
| | | | Net Present Value of Future Net Revenue
($M, before income taxes, 10% discount rate) |
Independent
Qualified
Reserves
Evaluator or
Auditor | Alberta Star
Development Corp.
Reserve and Economic
Evaluation | Location of
Reserves
(Country or
Foreign
Geographic Area) | Audited | Evaluated | Reviewed | Total |
Chapman
Petroleum
Engineering Ltd. | March 14, 2011 | Canada | - | $13,272 | - | $13,272 |
| 5. | In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook. We express no opinion on the reserves data that we reviewed but did not audit or evaluate. |
| |
| 6. | We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates. |
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| 7. | Because the reserves data are based on judgments regarding future events, actual events will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery. |
Executed as to our report referred to above:
| |
| Chapman Petroleum Engineering Ltd. | |
| 445, 708 – 11thAvenue S.W. | |
| Calgary, Alberta | |
| | “M. Stromer” |
| | M. Stromer, M. Sc., P. Eng. |
| | Execution date: March 14, 2011 |
APPENDIX B
FORM 51-101F3
REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHERINFORMATION
Management of Alberta Star Development Corp. (the “Company”) are responsible for the preparation and disclosure of information with respect to the Company’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which are estimates of proved reserves and probable reserves and related future net revenue as at November 30, 2010, estimated using forecast prices and costs.
An independent qualified reserves evaluator has evaluated the Company’s reserves data. The report of the independent qualified reserves evaluator will be filed with securities regulatory authorities concurrently with this report.
The Reserves Committee of the board of directors of the Company has:
| | (a) | reviewed the Company’s procedures for providing information to the independent qualified reserves evaluator; |
| | |
| (b) | met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and |
| | |
| (c) | reviewed the reserves data with management and the independent qualified reserves evaluator. |
The Reserves Committee of the board of directors has reviewed the Company’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has, on the recommendation of the Reserves Committee, approved:
| | (d) | the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information; |
| | |
| (e) | the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluator on the reserves data; and |
| | |
| (f) | the content and filing of this report. |
Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.
| |
| “Tim Coupland” | “Gord Steblin” |
| Tim Coupland | Gord Steblin |
| President and Chief Executive Officer | Chief Financial Officer |
| |
| “Robert Hall” | “Stuart Rogers” |
| Robert Hall | Stuart Rogers |
| Director | Director |
APPENDIX C
OIL & GAS DEFINITIONS
The following definitions form the bases of the classification of reserves and values presented in the CHAPMAN Report. They have been prepared by the Standing Committee on Reserves Definitions of the Petroleum Society of the CIM (“CIM”), incorporated in the Society of Petroleum Evaluation Engineers (“SPEE”) Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and specified by NI 51-101.
Reserve Categories
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recovered from known accumulations, from a given date forward, based on:
analysis of drilling, geological, geophysical and engineering data:
the use of established technology; and
specified economic conditions, 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 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 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 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.
Development and Production Starts
Each of the reserves categories (proved, probable, and possible) may be divided into developed and undeveloped categories.
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.
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| |
| 2. | 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.
| |
| 3. | 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 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 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 contained in the definitions above are applicable to individual reserves entitles (which refer 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:
| 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; and |
| | |
| | | at least 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 will be 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.
