ABBREVIATIONS AND CONVERSION FACTORS

 

ABBREVIATIONS

Oil and Natural Gas Liquids		Natural Gas
bbl	barrel	Bcf	billion cubic feet
bbls	barrels	CBM	coal bed methane
BOED	barrels of oil equivalent per day	GJ	gigajoule
bpd	barrels per day	Mcf	thousand cubic feet
Mstb	thousand stock tank barrels	Mcfd	thousand cubic feet per day
MBOE	thousand barrels of oil equivalent	Mcfe	thousand cubic feet equivalent
Mbbls	thousand barrels	MMcf	million cubic feet
NGL	natural gas liquids	MMcfd	million cubic feet per day
		MMBTU	Million British thermal units

 

BOE’s may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf to one BOE is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

 

 

 

ANDERSON ENERGY LTD. 2011 ANNUAL INFORMATION FORM

1

 

GLOSSARY OF TERMS

 

"ABCA" means the Business Corporations Act (Alberta) and the regulations promulgated thereunder, all as amended from time to time.

 

"Anderson" or the "Company" means Anderson Energy Ltd., a corporation amalgamated under the laws of the Province of Alberta.

 

"Aquest" means Aquest Energy Ltd., a corporation amalgamated pursuant to the laws of the Province of Alberta.  Aquest amalgamated with Anderson effective January 1, 2006.

 

"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.

 

"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.

 

"GLJ" means GLJ Petroleum Consultants Ltd., independent petroleum consultants of Calgary, Alberta.

 

"GLJ Report" means the independent engineering evaluation of Anderson's oil and gas interests prepared by GLJ, dated March 9, 2012 and effective December 31, 2011.

 

"Gross" or "gross" means:

(1)

in relation to the Company’s interest in reserves, Anderson’s working interest (operated and non-operated) share before deduction of royalties and without including any royalty interest owned by Anderson;

(2)

in relation to wells, the total number of wells in which Anderson has an interest; and

(3)

in relation to land, the total area in which Anderson has an interest.

 

"Net" or "net" means

(a)

in relation to the Company’s interest in reserves, Anderson’s working interest (operated and non-operated) share after deduction of royalty obligations, plus Anderson’s royalty interests in reserves;

(b)

in relation to wells, the total number of wells obtained by aggregating Anderson’s working interest in each of its gross wells; and

(c)

in relation to land, the total area in which Anderson has an interest multiplied by Anderson’s working interest.

 

"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.  At least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved Plus Probable Reserves is the targeted level of certainty.

 

"Proved Plus Probable Reserves" means the aggregate of Proved Reserves and Probable Reserves, before deduction of royalties.

 

"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.  At least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated Proved Reserves is the targeted level of certainty.

 

 

 

"Reserves" are the estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable 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.  Reserves are classified according to the degree of certainty associated with the estimates.

 

"Royalties" refers to royalties paid to others.  The royalties deducted from the reserves are based on the percentage royalty calculated by applying the applicable royalty rate or formula.  In the case of Crown sliding scale royalties which are dependent on selling prices, the price forecasts for the individual properties in question have been employed.

 

"Undeveloped Reserves" are those Reserves expected to be recovered from known accumulations where a significant expenditure (e.g., 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.

 

FORWARD LOOKING STATEMENTS

 

Certain statements in this Annual Information Form including, without limitation, management's growth strategy and management’s assessment of future plans and operations, management’s expectations regarding the percentage of production contributed from oil and natural gas liquids, capital expenditures including source, timing thereof and areas where such capital expenditures are expected to be made, reserves, net present values of future net revenue from reserves, commodity prices, development plans and programs, including number of wells expected to be drilled, tax horizon, abandonment and reclamation costs, government royalty rates, expiring acreage, ability to access skilled people, potential results of the strategic alternative review process and enhancement of shareholder value, disclosure intentions with respect to the strategic alternative review process and timing of conversion of probable reserves into proved developed producing reserves may constitute “forward-looking information” (within the meaning of applicable Canadian securities legislation) or “forward-looking statements” (within the meaning of the United States Private Securities Litigation Reform Act of 1995, as amended) and necessarily involve risks and assumptions made by management of the Company including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, adequate weather to conduct operations, capital expenditure costs, including drilling, completion and facilities costs, unexpected decline rates in wells, wells not performing as expected, incorrect assessment of the value of acquisitions and farm-ins, failure to realize the anticipated benefits of acquisitions and farm-ins, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources and other factors, many of which are beyond the Company’s control.  The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as the factors are interdependent, and management’s future course of action would depend on its assessment of all information at the time.  As a consequence, actual results may differ materially from those anticipated in the forward-looking statements and readers should not place undue reliance on the forward-looking statements contained herein.  Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect Anderson’s operations and financial results are included under the heading "Risk Factors" in this Annual Information Form and are included in reports on file with Canadian and U.S. securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), the EDGAR website (www.sec.gov/edgar) or at Anderson’s website (www.andersonenergy.ca).

 

 

 

 

 

The forward-looking statements contained in this Annual Information Form are made as at the date of this Annual Information Form and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

 

CORPORATE STRUCTURE

 

Anderson Energy Ltd. was incorporated under the ABCA on January 30, 2002.  On April 4, 2002, Anderson amended its articles to amend the rights, privileges, restrictions and conditions of the Class A common shares, Class B common shares and preferred shares of Anderson and remove the private company restrictions.  Anderson has conducted oil and gas exploration, development and acquisition activities in western Canada since completing its initial private placement in April 2002.

 

On June 27, 2005 the Company entered into an agreement with Aquest, a publicly traded oil and gas company, whereby they agreed to complete a plan of arrangement (the “Arrangement”) pursuant to which Anderson acquired all of the outstanding shares of Aquest.  The Arrangement was approved by the shareholders of Anderson and Aquest and received regulatory approval on August 31, 2005 and the transaction closed on September 1, 2005.  As a result of the Arrangement, Anderson became a public company effective September 7, 2005. 

 

Effective January 1, 2006, Anderson, Aquest, Eravista Explorations Ltd. (a subsidiary of Aquest) and 1022864 Alberta Ltd. (a subsidiary of Anderson) amalgamated under a short form vertical amalgamation to form Anderson Energy Ltd.

 

Effective January 1, 2009, Anderson and 1347662 Alberta Ltd. (a subsidiary of Anderson) amalgamated under a short form vertical amalgamation.  1347662 Alberta Ltd. was incorporated on March 1, 2007 as 3210700 Nova Scotia Company, was acquired by Anderson in a transaction completed on September 1, 2007 and was continued into Alberta as 1347662 Alberta Ltd. on September 12, 2007.

 

Anderson has one wholly-owned subsidiary, 1023095 Alberta Ltd.  1023095 Alberta Ltd. was incorporated under the ABCA on December 20, 2002.  Anderson and 1023095 Alberta Ltd. are partners of Anderson Energy Partnership, a general partnership under the laws of Alberta.

 

The registered office and head office of Anderson is located at 700 Selkirk House, 555 4th Avenue S.W. Calgary, Alberta, Canada T2P 3E7.

 

BUSINESS AND STRATEGY

 

Development of the Business. Anderson was formed as a private company in 2002 and became a public company in 2005.  The Company has grown through acquisition and development of conventional oil and gas reserves.  Since 2010, the focus has been on Cardium horizontal oil wells.  Prior to that, the focus was on natural gas development.

On January 29, 2009, the Company executed a farm-in agreement on lands near its existing core operations.  Under the farm-in agreement, the Company has access to 388 gross (205 net) sections of land.  During the commitment phase of the transaction, the Company is committed to drill, complete and equip 200 wells to earn an interest in up to 120 sections.  The Company is obligated to complete the drilling of the wells on or before March 31, 2013.  As of March 16, 2012, the Company has drilled 126 wells in connection with the farm-in.  The Company has an option to continue the farm-in transaction until March 1, 2014 by committing to drill a minimum of 100 additional wells under similar terms as in the commitment phase to earn a minimum of 50 sections of land.  Following the commitment and/or option phases, the parties to the agreement can then jointly elect to develop the lands on denser drilling spacing under terms of an operating agreement.

 

 

On May 28, 2009, the Company issued 63.2 million common shares at a price of $0.95 per common share for gross proceeds to the Company of $60.0 million ($56.5 million after commission and expenses).

 

In February 2010, the Company issued 21.9 million common shares at a price of $1.45 per common share for gross proceeds to the Company of $31.8 million ($29.8 million after commission and expenses).

 

On December 31, 2010, the Company issued 50,000 convertible unsecured subordinated debentures for gross proceeds of $50.0 million ($47.7 million after commission and expenses).  The convertible debentures are due January 31, 2016 and have a principal amount of $50.0 million bearing interest at a rate of 7.5%.  These convertible debentures have a conversion price of $1.55 per common share.

 

On June 8, 2011, the Company issued 46,000 convertible unsecured subordinated debentures for gross proceeds of $46.0 million ($43.9 million after commission and expenses).  The convertible debentures are due June 30, 2017 and have a principal amount of $46.0 million bearing interest at a rate of 7.25%.  These convertible debentures have a conversion price of $1.70 per common share.

 

Stated Business Objectives.   Anderson is a resource-based oil and gas development company. The business plan of Anderson is to focus on sustainable and profitable per share growth in both net asset value and cash flow from operations.  To accomplish this, Anderson focuses on enhancing its asset base through land acquisitions and farm-ins, seismic interpretation, exploratory and development drilling and strategic acquisitions within its core project areas in western Canada.

 

Anderson’s principal property is in Central Alberta, proximal to the Garrington, Willesden Green and Pembina fields. The Company’s development strategy is currently focused on drilling Cardium horizontal oil wells that are stimulated with multi-stage fracturing technology.

Anderson intends to generate exploration and development opportunities possessing low to medium risk and multi-zone potential.  Anderson intends to pursue exploration, development and exploitation drilling, combined with acquisition opportunities that meet Anderson's business parameters.  Management of Anderson believes in controlling the timing and costs of its projects wherever possible.  Anderson will seek to become the operator of its properties to the greatest extent possible.  Further, to minimize competition within its geographic areas of interest, Anderson will strive to maximize its working interest ownership in its properties where reasonably possible.  Participation in exploration and development in the oil and natural gas industry has a number of inherent risks beyond the direct control of company personnel.  Among these risks are those associated with exploration, development and production, economic conditions, commodity prices, capital requirements, financing requirements, industry competition, ability to attract key personnel, government regulation and royalties, the environment, foreign exchange rates and interest rates.  See “Risk Factors”.

 

In reviewing potential drilling or acquisition opportunities, Anderson generally considers the following:

In general, Anderson intends to use a portfolio approach in developing opportunities with a balance of risk profiles and commodity exposure, in an attempt to generate sustainable levels of profitable production and financial growth.  The board of directors of Anderson may, in its discretion, approve acquisitions that do not conform to these guidelines based upon its consideration of the qualitative aspects of the subject properties including risk profile, technical upside, reserves life and asset quality.

 

 

 

STRATEGY

 

The Company is focused on converting its asset base to be more than 50% oil and NGL production.  Proceeds from disposition of minor properties are being directed to the reduction of bank debt.  Crude oil pricing remains strong, but volatile and Anderson has increased its hedge position with a view to protecting its capital program and its shareholders from volatile oil markets.

 

In response to low natural gas prices, the Company plans to shut-in approximately 500 Mcfd of production from natural gas properties with higher operating costs.   In a higher price environment, these natural gas wells could easily be returned to production.

 

Anderson has substantially grown its Cardium drilling inventory in the last two years and with the recent completion of certain infrastructure projects, newly drilled Cardium horizontal wells can easily be connected to these gathering systems.  Unlike natural gas markets, oil prices continue to remain strong and the economics of the Cardium oil drilling programs are excellent.

 

Strategic Alternatives.   The Board of Directors has initiated a process to identify, examine and consider a range of strategic alternatives available to the Company with a view to enhancing shareholder value.  The strategic alternatives considered may include, but are not limited to, a sale of all or a material portion of the assets of Anderson, either in one transaction or in a series of transactions, the outright sale of the Company, or a merger or other strategic transaction involving Anderson and a third party. The Board of Directors believes that the Company’s shares trade at a significant discount to the value of the underlying assets, especially given its high quality Cardium oil production base, prospective Cardium horizontal oil drilling inventory and significant tax pools.  The Board of Directors has established a special committee comprised of independent directors of the Company to oversee this process and has retained financial advisors to assist the Special Committee and the Board of Directors with the process. The process was not initiated as a result of any particular offer.  There are no assurances or guarantees that the process will result in a transaction or, if a transaction is undertaken, the terms or timing of such a transaction. The Company has not set a definitive schedule to complete its evaluation.

 

Business Cycle and Seasonality . Anderson's business is generally cyclical.  Light oil prices fluctuate with the balance between world supply and demand, levels of inventory, OPEC policy and other geopolitical events.  Natural gas prices are influenced by North American levels of inventory and storage, estimates of current and forecast supply and weather expectations.

 

The exploration for and development of oil and natural gas reserves is dependent on access to areas where exploration and exploitation is to be conducted.  Seasonal weather variations, including freeze-up and break-up affect access to various properties in certain circumstances.

 

Trends . Crude oil and natural gas prices are volatile and subject to a number of external factors.  Natural gas prices are influenced by the weather and the economy in North America.  Crude oil prices are influenced by geopolitical events and global economic factors.  The Canadian/U.S. currency exchange rate also influences commodity prices received by Canadian producers as oil and natural gas production is ultimately priced in U.S. dollars.

 

The level of natural gas in storage in the United States continued to remain at very high levels throughout 2011 and into 2012.  The large amount of gas in storage combined with strong U.S. gas production driven primarily by U.S. shale gas plays and financial market fears is suppressing the price of natural gas.  The future price for natural gas is at a level that should not support most drilling projects on either side of the border.  However, drilling continues in U.S. shale gas plays, partly due to lease retention and partly due to the large number of U.S. shale gas joint venture projects where third parties are obligated to drill to earn

 

 

 

lands owned by U.S. shale gas producers.  In Canada, drilling continues primarily in areas where the gas target is liquids rich.

 

Central Alberta.   The Company has one core area: Central Alberta.     The focus of Anderson’s current Central Alberta operations runs from the Garrington area centered approximately 100 kilometres north of Calgary, Alberta to the Pembina area less than 100 kilometres southwest of Edmonton, Alberta. This area is a combination of several subsidiary operated fields including West Pembina, Buck Lake, Willesden Green, Leedale, Wilson Creek, Garrington, and Ferrier.  The Central Alberta area consists of 61,003 gross (29,487 net) acres of undeveloped land.

 

The majority of Anderson’s oil production in the area is from new horizontal multi-staged fractured wells in the Cardium formation. Anderson’s natural gas production in the Central Alberta area is split between multiple Edmonton Sands pools at depths of less than 1,000 metres and deeper Mannville and Jurassic liquids rich gas pools at depths up to 2,700 metres.  Anderson has an interest in 1,003 gross (581.7 net) natural gas wells and 205 gross (100.2 net) oil wells in the Central Alberta area.

 

Working interest positions of 100% are held in oil batteries at 15-34-035-03 W5, 05-29-37-07 W5 and 08-10-039-02 W5 as well as associated satellite facilities. A 45% working interest is held in an oil battery at 01-27-040-06 W5 as well as a 44% interest is in an oil battery at 15-16-039-28W4 and a 20.9% working interest in the 16-14-039-01W5 oil battery. Varying working interests up to 100% are held in single well and two well oil batteries in Buck Lake, Pembina West, Willesden Green and Garrington.  Anderson has ownership in gas plants at 04-18-032-22 W4, 05-10-033-26 W4, 14-32-037-03 W5, 11-35-037-09 W5, 01-21-038-02 W5, 06-16-038-04 W5, 05-14-039-05 W5 and 10-05-046-06 W5.  Natural gas produced in the Central Alberta area is also processed in third party facilities and the most significant facilities are located at 15-22-040-03 W5, 10-07-051-09 W5 and 11-22-049-12 W5. Anderson has working interests up to 100% in numerous well site and intermediate field booster compression facilities in Central Alberta from 60 to 1,000 horsepower. This includes a 75% and 100% working interest in fit for purpose shallow gas batteries at 05-26-043-05 W5 and 08-20-041-04 W5 respectively.

 

 

 

 

natural gas, 3.3 Mstb of NGL and 7.4 Mstb of oil.  In 2011, Anderson drilled 51 gross (44.7 net) wells (including 1 gross (1.0 net) dry hole) in the area.

 

STATEMENT OF RESERVES DATA AND OTHER INFORMATION

 

The statement of reserves data and other oil and gas information set forth below (the "Statement of Reserves") has an effective date of December 31, 2011 and was prepared as of March 9, 2012.

 

Disclosure of Reserves Data

 

The reserves data in the Statement of Reserves summarizes the estimated oil, NGL and natural gas reserves of Anderson and the net present values of future net revenue for these reserves using forecast prices and costs.  The evaluations were prepared in accordance with procedures and standards contained in the COGE Handbook.  The reserves definitions used in preparing the GLJ Report are those contained in the COGE Handbook and the Canadian Securities Administrators National Instrument 51-101 ("NI 51-101"). Anderson engaged GLJ to provide an evaluation of proved and proved plus probable reserves and no attempt was made to evaluate possible reserves.

 

The results of the evaluations of GLJ, contained in the GLJ Report based on forecast price and cost assumptions are summarized in the tables below.  All evaluations of future revenue are after the deduction of future income tax expenses (unless otherwise noted in the tables), royalties, development costs, production costs and well abandonment costs, but before consideration of indirect costs such as administrative, overhead and other miscellaneous expenses.  The estimated future net revenue contained in the following tables does not necessarily represent the fair market value of Anderson's reserves.  There is no assurance that the forecast price and cost assumptions contained in the GLJ Report will be attained and variances could be material.  Other assumptions and qualifications relating to costs and other matters are summarized in the notes to the following tables.  The recovery and reserves estimates on Anderson's properties described herein are estimates only.  The actual reserves on Anderson's properties may be greater or less than those calculated.

 

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 effects of aggregation.

 

The Report on Reserves Data by GLJ in Form 51-101F2 and the Report of Management and Directors on Reserves Data and Other Information in Form 51-101F3 are included in Schedules 1 and 2 to this Annual Information Form.

 

All of Anderson’s reserves are in Canada, in the province of Alberta.  As of December 31, 2011, Anderson has both heavy oil reserves and quantities of CBM reserves which have been segregated in the accompanying tables.

 

 

 

 

 

 

The negative net present value for proved undeveloped reserves at 20% discount rate is related to the development of undeveloped natural gas reserves and implies that the return is less than 20% for these reserves at current price forecasts.  See further discussion under “Additional Information Related to Reserves Data – Undeveloped Reserves”.

 

 

Notes:

(i)

Including solution gas and other by-products.

(ii)

Including by-products but excluding solution gas.

(iii)

Other Company revenue and costs not related to a specific production group have been allocated proportionately to production groups.  Unit values are based on net reserves.

 

 

 

 

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS

As of January 1, 2012

GLJ Forecast Prices and Costs

 

Notes:

(1)	Columns may not add due to rounding.

 

(2)	“Gross” or “gross” means Anderson’s working interest (operated and non-operated) share before deduction of royalties and without including any royalty interest owned by Anderson.

 

“Net” or “net” means Anderson’s working interest (operated and non-operated) share after deduction of royalty obligations, plus Anderson’s royalty interests in reserves.

 

“Royalties” refers to royalties paid to others.  The royalties deducted from the reserves are based on the percentage royalty calculated by applying the applicable royalty rate or formula.  In the case of Crown sliding scale royalties which are dependent on selling prices, the price forecasts for the individual properties in question have been employed.

 

“Reserves” are the estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on: analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable.  Reserves are classified according to the degree of certainty associated with the estimates.

 

“Proved Plus Probable Reserves” means the aggregate of Proved Reserves and Probable Reserves.

 

“Proved Reserves” are those Reserves that can be estimated with a high degree of certainty to be recoverable.  It is likely that the actual remaining quantities recovered will exceed the estimated Proved Reserves.  At least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated Proved Reserves is the targeted level of certainty.

 

“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.  At least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved Plus Probable Reserves is the targeted level of certainty.

 

“Proved Developed Reserves” are those Reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g., when compared to the cost of drilling a well) to put the Reserves on production.  The developed category may be subdivided into producing and non-producing.

 

“Developed Producing Reserves” are those Reserves that are expected to be recovered from completion intervals open at the time of the estimate.  These Reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

 

“Developed Non-Producing Reserves” 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 (e.g., 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.

 

(3)

The forecast cost and price assumptions assume the continuance of current laws and regulations and increases in wellhead selling prices, and take into account inflation with respect to future operating and capital costs.  In the GLJ Report, operating costs are assumed to escalate at 2% per annum.  Crude oil and natural gas base case prices as forecast by GLJ effective December 31, 2011 consider the following:

 

 

 

(4)	Future net revenue is attributed to a product group based on each field’s primary producing product.

 

(5)	Substantially all of the proved producing reserves evaluated in the GLJ Report were on production at December 31, 2011.

 

(6)

The extent and character of all factual data supplied to GLJ were accepted by GLJ as represented. The crude oil and natural gas reserves calculations and any projections upon which the GLJ Report is based were determined in accordance with generally accepted evaluation practices. No field inspections were conducted.

 

(7)	GLJ includes well abandonment costs for all wells with reserves at the property level.  Additional abandonment costs associated with non-reserves wells, lease reclamation costs and facility abandonment and reclamation expenses have not been included in the analysis.

 

(8)	Unit values for future net revenue are calculated using net reserves.

 

Reconciliation of Reserves .   The following table provides a summary of the changes in the Company’s reserves which occurred in the most recent fiscal year, based upon escalated price and cost assumptions, net of applicable royalties.