EXHIBIT 99.3




Management’s Discussion and Analysis
 
 DECEMBER 31, 2011 AND 2010















The following management’s discussion and analysis is dated March 16, 2012 and should be read in conjunction with the audited consolidated financial statements of Anderson Energy Ltd. (“Anderson” or the “Company”) for the years ended December 31, 2011 and 2010.  The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”).  Previously, the Company prepared its 2010 annual consolidated financial statements in accordance with Canadian Generally Accepted Accounting Principles (“CGAAP”).  The impact of the transition to IFRS on the Company’s previously reported financial position and financial results for 2010 is discussed below under the caption “Adoption of IFRS”.  The adoption of IFRS had no material impact the Company’s strategic decisions, business practices or prospects, operations, key agreements including debt agreements and covenants or cash flow from operations, before changes in non-cash working capital.
  Included in the discussion and analysis are references to terms commonly used in the oil and gas industry such as funds from operations, finding, development and acquisition (“FD&A”) costs, operating netback and barrels of oil equivalent (“BOE”).  Funds from operations as used in this report represent cash from operating activities before changes in non-cash working capital and decommissioning expenditures.  See “Review of Financial Results – Funds from Operations” for details of this calculation.  Funds from operations represent both an indicator of the Company’s performance and a funding source for on-going operations.  FD&A costs measure the cost of reserves additions and are an indicator of the efficiency of capital expended in the period.  Operating netback is calculated as oil and gas revenues and the realized gains/losses on derivative contracts less royalties, operating and transportation expenses and is a measure of the profitability of operations before administrative and financing expenditures.  Production volumes and reserves are commonly expressed on a BOE basis whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil.  The intention is to sum oil and natural gas measurement units into one basis for improved analysis of results and comparisons with other industry participants.  These terms are not defined by IFRS and therefore are referred to as non-GAAP measures.
  All references to dollar values are to Canadian dollars unless otherwise stated.  Production volumes are measured upon sale unless otherwise noted and reserves numbers are stated before deducting Crown or lessor royalties.
  Definitions of the abbreviations used in this discussion and analysis are located on the last page of this document.
  REVIEW OF FINANCIAL RESULTS
  Overview.For the year ended December 31, 2011, funds from operations were $54.5 million ($0.32 per share), up 49% from 2010 as a result of the Company’s focus on Cardium light oil drilling.  Sales volumes averaged 7,692 BOED, slightly higher than in the previous year.
  Capital additions, net of dispositions were $159.3 million for the year ended December 31, 2011.  During the year, the Company drilled 51 gross (43.8 net capital) successful oil wells and one dry hole.  During the fourth quarter of 2011, the Company drilled 10 gross (9.6 net capital) successful Cardium light oil wells in addition to the one 100% dry hole.  The Company also tied in 12 gross (9.3 net revenue) Cardium light oil wells in the fourth quarter of 2011 and completed battery and solution gas compression projects at Garrington, Ferrier, Willesden Green and other areas.  The Company’s finding, development and acquisition costs, including changes in future development capital, additions, dispositions and technical revisions but excluding natural gas related economic factors were $26.26 per BOE on a proved plus probable basis for 2011.
  1
2011 MANAGEMENT’S DISCUSSION & ANALYSIS
  Bank loans plus cash working capital deficiency (excludes unrealized gain on derivative contracts) was $132.7 million at December 31, 2011.  On June 8, 2011, the Company completed a convertible subordinated debenture financing for proceeds, net of commission and expenses, of $43.9 million.  Proceeds were initially used to pay down bank debt.  The availability created in the credit facilities, along with cash flows, was used to finance the Company’s capital programs.
  Revenue and Production.In 2010, the Company changed its focus to developing oil prospects in light of the continued depressed natural gas market and increased oil sales from development activities has positively affected revenues during 2011.  Oil sales and natural gas liquids, which have higher sales prices and netbacks than natural gas, have taken a larger role in the Company’s sales mix.  For the 2011 financial year, oil and natural gas liquids revenue represented 65% of total revenue (2010 – 37%) whereas in the fourth quarter of 2011, oil and natural gas liquids revenue represented 72% of total revenue (2010 – 48%).
  Oil sales for the year ended December 31, 2011 averaged 1,743 bpd compared to 601 bpd for the year ended December 31, 2010.  Oil sales averaged 2,122 bpd in the fourth quarter of 2011 compared to 1,709 bpd in the third quarter of 2011 and 992 bpd in the fourth quarter of 2010.  The increase in 2011 fourth quarter volumes is due to new oil production from 12 gross (9.3 net) Cardium horizontal light oil wells, which were brought on-stream during the quarter.
  The Company suspended its shallow gas drilling program after the first quarter of 2010 because of low natural gas prices.  Accordingly, natural production declines were not replaced, resulting in decreases in gas sales throughout 2011.  Gas sales volumes for the year ended December 31, 2011 decreased to an average of 31.6 MMcfd from 37.1 MMcfd last year due to the suspension of shallow gas drilling after the first quarter of 2010.  The central Alberta area, centered around the Sylvan Lake area and northwest to Pembina, remains the Company’s largest area of production, with gas sales averaging 30.2 MMcfd (35.6 MMcfd during 2010).  Gas sales volumes averaged 30.6 MMcfd in the fourth quarter of 2011 compared to 30.0 MMcfd in the third quarter of 2011 and 38.5 MMcfd in the fourth quarter of 2010.
  Natural gas liquids sales for the year ended December 31, 2011 averaged 679 bpd compared to 778 bpd for the year ended December 31, 2010.  Natural gas liquids sales averaged 715 bpd in the fourth quarter of 2011 compared to 636 bpd in the third quarter of 2011 and 823 bpd in the fourth quarter of 2010.  Natural gas liquids volumes were affected by natural declines, consistent with declines in gas production.
  The following tables outline production revenue, volumes and average sales prices for the three and twelve months ended December 31, 2011 and 2010.
  OIL AND NATURAL GAS SALES
  Three months ended

December 31


Year ended

December 31(thousands of dollars)

2011


2010


2011


2010Natural gas

$
8,589


$
12,320


$
40,377


$
52,304Gain on fixed price natural gas contracts


410



-



1,228



1,302Total natural gas


8,999



12,320



41,605



53,606Oil(1)


18,807



7,081



59,184



16,142NGL


4,785



4,459



17,302



15,672Royalty and other


36



86



201



1,037Total oil and gas sales(1)

$
32,627


$
23,946


$
118,292


$
86,457
 (1)
The three month numbers exclude the realized and unrealized losses on derivative contracts of $0.3 million and $7.9 million respectively during 2011 (2010 – $0.1 million and $1.9 million losses respectively).  The yearly numbers exclude the realized loss of $0.6 million and unrealized gain on derivative contracts of $3.3 million during 2011 (2010 – $0.1 million loss and $1.9 million loss respectively).
 
  ANDERSON ENERGY
2
 
  PRODUCTION
  Three months ended

December 31


Year ended

December 312011


2010


2011


2010Natural gas(Mcfd)


30,576



38,479



31,620



37,124Oil(bpd)


2,122



992



1,743



601NGL(bpd)


715



823



679



778Total(BOED)


7,933



8,228



7,692



7,566
  PRICES
  Three months ended

December 31


Year ended

December 312011


2010


2011


2010Natural gas($/Mcf)(1)

$
3.20


$
3.48


$
3.60


$
3.96Oil($/bbl)(2)


96.33



77.62



93.05



73.62NGL($/bbl)


72.71



58.87



69.81



55.22Total($/BOE)(2)(3)

$
44.70


$
31.63


$
42.13


$
31.31
 (1)
Includes gain on fixed price natural gas contracts of $1.2 million in 2011 (2010 - $1.3 million).
 (2)
The three month numbers exclude the realized and unrealized losses on derivative contracts of $0.3 million and $7.9 million respectively during 2011 (2010 – $0.1 million and $1.9 million losses respectively).  The yearly numbers exclude the realized loss of $0.6 million and unrealized gain on derivative contracts of $3.3 million during 2011 (2010 – $0.1 million loss and $1.9 million loss respectively).
 (3)
Includes royalty and other income classified with oil and gas sales.
  World and North American benchmark prices for oil have improved dramatically since 2010, and have positively impacted the oil and natural gas liquids prices realized by the Company in 2011 relative to 2010.  However, crude oil prices remain volatile and as described below, the Company has entered into certain derivative contracts to partially hedge recent oil price levels to protect its capital program.  Natural gas prices remained low throughout 2011 as well as 2010, and current market conditions including high supply and low demand for natural gas in North America have continued to negatively impact the prices for natural gas.
  The above noted oil price in 2011 does not include a realized loss on derivative contracts of $0.6 million (December 31, 2010 – $0.1 million loss).  The realized oil price including this losswas $94.94 per barrel for the fourth quarter of 2011 and $92.06 per barrel for the year ended December 31, 2011 compared to $76.18 per barrel for the fourth quarter of 2010 and $73.02 per barrel for the year ended December 31, 2010.
  The natural gas price in 2011 includes a gain on fixed price natural gas contracts of $1.2 million (December 31, 2010 – $1.3 million).  The 2011 natural gas price before the gain was $3.50 per Mcf (December 31, 2010 – $3.86 per Mcf).  The fixed price natural gas contracts concluded at the end of October 2011 which contributed to the drop in prices realized during the fourth quarter of 2011 ($3.20 per Mcf) relative to the third quarter of 2011 ($3.85 per Mcf) and the fourth quarter of 2010 ($3.48 per Mcf).  The Company is currently selling all of its gas production at the average daily index price.  Average natural gas prices realized by the Company to date during 2012 have been less than $2.50 per Mcf.
  Commodity Contracts.At December 31, 2011, the following derivative contracts were outstanding and recorded at estimated fair value:
  Period

Weighted

average volume

(bpd)


Weighted average

WTI Canadian

($/bbl)January 1, 2012 to March 31, 2012


1,500



104.63April 1, 2012 to December 31, 2012


1,000



103.93
   3
2011 MANAGEMENT’S DISCUSSION & ANALYSIS
  Derivative contracts had the following impact on the consolidated statements of operations:
  Three months ended December 31


Year ended December 31(thousands of dollars)

2011


2010


2011


2010Realized loss on derivative contracts

$
(271
)

$
(131
)

$
(624
)

$
(131
)Unrealized gain (loss) on derivative

contracts


(7,864
)


(1,918
)


3,302



(1,918
)Total gain (loss) on derivative

contracts

$
(8,135
)

$
(2,049
)

$
2,678


$
(2,049
)
  In January 2012, the Company entered into fixed price swap contracts for an average of 500 barrels per day of crude oil for February to December 2012 at a weighted average NYMEX crude oil price of Canadian $103.75 per barrel.
  In June 2011, as part of its risk management program, the Company entered into fixed price natural gas contracts to manage commodity price risk.  The Company entered into physical contracts to sell 15,000 GJ per day of natural gas from July 1, 2011 to October 31, 2011 at an average AECO price of $4.06 per GJ.  The Company recognized a gain of $1.2 million on these contracts during the year ended December 31, 2011.  The Company had no fixed price natural gas contracts in place at December 31, 2011.
  Royalties.For the year ended December 31, 2011, the average rate for royalties was 11.8% (December 31, 2010 – 10.4%) of revenue.  For the fourth quarter of 2011, the average rate for royalties was 12.8% of revenue compared to 12.4% of revenue in the third quarter of 2011 and 9.4% of revenue in the fourth quarter of 2010.  The increase in the average royalty rate for the year and quarter ended December 31, 2011 is due to the following: (i) an estimated reduction in gas cost allowance for 2011 due to lower crown royalties as a result of lower natural gas prices, production and expenditures and (ii) new production from non-crown properties that carry higher royalty rates.  Offsetting this, oil wells drilled on Crown lands during 2011 qualified for royalty incentives that reduced average Crown royalties during the year.  These incentives reduce Crown royalties for periods of up to 30 months from initial production, after which Crown royalties are expected to increase from current levels.
  Royalties as a percentage of total oil and gas sales are highly sensitive to prices and adjustments to gas cost allowance and so royalty rates can fluctuate from quarter to quarter.
  Three months ended December 31


Year ended December 312011


2010


2011


2010Gross Crown royalties


8.0
%


10.9
%


9.2
%


12.5
%Gas cost allowance


(1.5
%)


(3.7
%)


(4.2
%)


(7.2
%)Other royalties


6.3
%


2.2
%


6.8
%


5.1
%Total royalties


12.8
%


9.4
%


11.8
%


10.4
%Total royalties($/BOE)

$
5.71


$
2.98


$
4.92


$
3.26
 
 Operating Expenses.Operating expenses were $10.52 per BOE for the year ended December 31, 2011 compared to $10.34 per BOE for the year ended December 31, 2010.  Operating expenses were $8.30 per BOE in the fourth quarter of 2011 compared to $11.22 per BOE in the thirdquarter of 2011 and $11.32 per BOE in the fourth quarter of 2010.  The decrease in operating expenses for the fourth quarter of 2011 is primarily due to a reduction in estimated accrued liabilities related to certain gas plant processing fees from earlier periods.
  Transportation Expenses.For the year ended December 31, 2011, transportation expenses were $0.58 per BOE (December 31, 2010 – $0.22 per BOE).  For the fourth quarter of 2011, transportation expenses were $0.44 per BOE compared to $0.89 per BOE in the third quarter of 2011 and $0.30 per BOE in the fourth quarter of 2010.  The increase in transportation expenses in 2011 relative to 2010 is the result of the costs of trucking higher volumes of clean oil to the point of sale.  Oil production was 23% of total production
 
 ANDERSON ENERGY
4
 
 in 2011 compared with 8% in 2010.Although higher in 2011 than 2010,transportation costs decreased in the fourth quarter of 2011 relative to the third quarter of 2011 due to the direct tie-in of the Garrington battery to a newly constructed lateral pipeline in October, thereby replacing the trucking charges with a pipeline tariff.  Also, certain actual costs in excess of estimated costs for prior periods were recorded in the third quarter of 2011, representing approximately $0.25 per BOE during that quarter.
  OPERATING NETBACK
  Three months ended December 31


Year ended December 31(thousands of dollars)

2011


2010


2011


2010Revenue(1)

$
32,627


$
23,946


$
118,292


$
86,457Realized loss on derivative contracts


(271
)


(131
)


(624
)


(131
)Royalties


(4,170
)


(2,256
)


(13,806
)


(9,011
)Operating expenses


(6,060
)


(8,575
)


(29,533
)


(28,537
)Transportation expenses


(322
)


(224
)


(1,626
)


(611
)Operating netback

$
21,804


$
12,760


$
72,703


$
48,167Sales volume (MBOE)


729.9



757.0



2,807.5



2,761.5Per BOERevenue(1)

$
44.70


$
31.63


$
42.13


$
31.31Realized loss on derivative contracts


(0.37
)


(0.17
)


(0.22
)


(0.05
)Royalties


(5.71
)


(2.98
)


(4.92
)


(3.26
)Operating expenses


(8.30
)


(11.32
)


(10.52
)


(10.34
)Transportation expenses


(0.44
)


(0.30
)


(0.58
)


(0.22
)Operating netback per BOE

$
29.88


$
16.86


$
25.89


$
17.44
 (1)
Includes royalty and other income classified with oil and gas sales.  Excludes unrealized loss on derivative contracts of $7.9 million for the three months ended December 31, 2011 and a $3.3 million gain pertaining to fixed price crude oil swaps for the twelve months ended December 31, 2011 (December 31, 2010 - $1.9 million loss and $1.9 million loss respectively).
  Depletion and Depreciation.Depletion and depreciation was $52.9 million ($18.85 per BOE) for the year ended December 31, 2011 compared to $45.7 million ($16.53 per BOE) in 2010.  Depletion and depreciation was $15.0 million ($20.49 per BOE) in the fourth quarter of 2011 compared to $12.3 million ($18.16 per BOE) in the third quarter of 2011 and $13.2 million ($17.45 per BOE) in the fourth quarter of 2010.  The increase in depletion and depreciation for the year and the fourth quarter of 2011 compared to the same periods of 2010 is due to higher capital costs associated with oil properties and increased production from these properties.
  Impairment of property, plant and equipment.At January 1, 2010, the effective transition date to IFRS, the Company elected to use the IFRS 1 deemed cost exemption whereby the costs under CGAAP were allocated to CGUs based on reserves volumes and then tested for impairment.  As a result, the Company recognized an impairment of $67.2 million at January 1, 2010 in the Shallow Gas CGU with a corresponding reduction in opening retained earnings.  For the year ended December 31, 2010, the Company recognized additional impairments of $153.2 million with a corresponding reduction in property, plant and equipment for the Shallow Gas, Deep Gas and Non-core CGUsdue to declines in the future price forecasts used by the Company’s independent qualified reserves evaluators for natural gas prices.
  Additional impairment charges were recognized at September 30, 2011 and December 31, 2011 as a result of changes in natural gas and natural gas liquids prices and the impact on the fair value of the Company’s Shallow Gas, Deep Gas and Non-Core CGUs. In aggregate, the Company recognized $35.2 million of impairments during the year ended December 31, 2011 in the following CGUs: Shallow Gas $25.8 million, Deep Gas $2.6 million (net of impairment reversals of $9.7 million) and Non-Core $6.8 million.  The forward price outlook for natural gas dropped significantly at December 31, 2011 compared to the outlook
 
 5
2011 MANAGEMENT’S DISCUSSION & ANALYSIS
 at September 30, 2011 which led to the recognition of impairment charges for the Shallow Gas, Deep Gas and Non-Core CGUs in the fourth quarter of 2011 as follows: $22.6 million, $12.3 million and $1.4 million respectively.
  General and Administrative Expenses.For the year ended December 31, 2011, general and administrative expenses, excluding stock-based compensation were $9.4 million or $3.36 per BOE (December 31, 2010 – $8.4 million or $3.04 per BOE) and for the fourth quarter of 2011 were $2.2 million or $3.03 per BOE (December 31, 2010 – $2.4 million or $3.18 per BOE).  Gross general and administrative expenses increased for the year ended December 31, 2011 over 2010 due to higher levels of employee compensation and higher audit fees related to the implementation of IFRS, whereas the lower costs in the fourth quarter of 2011 relative to 2010 is a reflection of the timing of recognition of year end compensation costs.
  Three months ended December 31


Year ended December 31(thousands of dollars)

2011


2010


2011


2010General and administrative (gross)

$
3,376


$
4,082


$
14,816


$
13,742Overhead recoveries


(490
)


(570
)


(1,802
)


(1,751
)Capitalized


(674
)


(1,106
)


(3,569
)


(3,594
)General and administrative (cash)

$
2,212


$
2,406


$
9,445


$
8,397Net stock-based compensation


230



235



960



1,020General and administrative (net)

$
2,442


$
2,641


$
10,405


$
9,417General and administrative (cash) ($/BOE)

$
3.03


$
3.18


$
3.36


$
3.04% Capitalized


20%



27%



24%



26%
  Capitalized general and administrative costs are limited to salaries and associated office rent of staff involved in capital activities.
  Stock-Based Compensation.The Company accounts for stock-based compensation plans using the fair value method of accounting.  Stock-based compensation expense was $1.5 million in 2011 ($1.0 million net of amounts capitalized) versus $1.6 million ($1.0 million net of amounts capitalized) in 2010.  Stock-based compensation costs were $0.3 million for the fourth quarter of 2011 ($0.2 million net of amounts capitalized) versus $0.4 million ($0.2 million net of amounts capitalized) in the fourth quarter of 2010.
  Finance Expenses.Finance expenses were $3.4 million for the fourth quarter of 2011, compared to $3.3 million in the third quarter of 2011 and $1.5 million in the fourth quarter of 2010.  Finance expenses were $11.9 million for the year ended December 31, 2011, compared to $5.0 million in the comparable period of 2010.  The increase in finance expenses from 2010 is the result of higher interest and accretion on the $96 million (principal) of convertible debentures issued on December 31, 2010 and June 8, 2011 at 7.5% and 7.25% respectively.  The average effective interest rate on outstanding bank loans was 5.3% for the year ended December 31, 2011 compared to 4.9% for the comparable period in 2010.
  Three months ended December 31


Year ended December 31(thousands of dollars)

2011


2010


2011


2010Interest and accretion on convertible

debentures

$
2,234


$
13


$
7,065


$
13Interest expense on credit facilities and

other


853



1,085



3,247



3,339Accretion on decommissioning obligations


335



423



1,630



1,654Finance expenses

$
3,422


$
1,521


$
11,942


$
5,006
  Decommissioning obligations.In the fourth quarter of 2011, the Company recorded an increase in decommissioning obligations of $2.8 million.  The increase is the result of additional decommissioning obligations relating to current drilling and new infrastructure construction in the fourth quarter of 2011.
 ANDERSON ENERGY
6
 
 Accretion expense was $0.3 million for the fourth quarter of 2011 compared to $0.4 million in the third quarter of 2011 and $0.4 million in the fourth quarter of 2010 and was included in finance expenses.
  The risk-free discount rates used by the Company to measure the obligations at December 31, 2011 were between 0.9% and 3.1% depending on the timelines to reclamation and decreased from the start of the year as a result of changes in the Canadian bond market.
  Income Taxes.Anderson is not currently taxable and has the following estimated tax pool balances at December 31, 2011.  Non-capital losses are estimated assuming certain discretionary claims related to tax pools are made in the current year.  Tax pool classifications are estimates as some new wells have not yet had their status as exploratory or development confirmed.
  Canadian Exploration Expenses (CEE)

$
72

millionCanadian Development Expenses (CDE)


184

millionUndepreciated Capital Cost (UCC)


112

millionCanadian Oil and Gas Property Expenses (COGPE)


5

millionNon-Capital Losses


119

millionShare issue costs


5

millionTotal

$
497

million
 
 Funds from Operations.Funds from operations increased by 49% to $54.5 million in 2011 compared to $36.5 million in 2010.  On a per share basis, funds from operations were $0.32 per share in 2011 compared to $0.21 per share in 2010.  For the three months ended December 31, 2011, funds from operations were $17.0 million or $0.10 per share, an increase of 34% over the previous quarter of $12.7 million or $0.07 per share, and an increase of 83% from the fourth quarter of 2010 of $9.3 million or $0.05 per share.  Funds from operations increased as the Company refocused its capital initiatives on oil prospects, which are brought on production at significantly higher expected operating margins.  In the fourth quarter of 2011, oil and NGLs accounted for $23.6 million or 72% of oil and gas sales compared to $17.9 million or 63% in the third quarter of 2011 and $11.5 million or 48% in the fourth quarter of 2010.
  Three months ended December 31


Year ended December 31(thousands of dollars)

2011


2010


2011


2010Cash from operating activities

$
16,462


$
10,488


$
54,309


$
40,332Changes in non-cash working capital


389



(1,324
)


(94
)


(5,365
)Decommisioning expenditures


146



118



249



1,549Funds from operations

$
16,997


$
9,282


$
54,464


$
36,516
 Earnings.  The Company reported a $32.2 million loss in the fourth quarter of 2011 compared to earnings of $7.5 million in the third quarter of 2011 and a loss of $36.5 million in the fourth quarter of 2010.  Earnings were lower in the fourth quarter of 2011 compared to the previous quarter as a result of higher depletion, impairments recognized on the Company’s Shallow Gas, Deep Gas and Non-core CGUs and unrealized losses on the Company’s derivative oil contracts recognized in the fourth quarter of 2011.  The Company reported a loss of $22.4 million in 2011 compared to a loss of $124.8 million in 2010.  As with funds from operations, earnings continue to be impacted by low natural gas prices.  The change in the Company’s focus to crude oil, with its currently higher operating margins, is expected to improve future earnings.
  The Company’s funds from operations and earnings are highly sensitive to changes in factors that are beyond its control.  An estimate of the Company’s sensitivities to changes in commodity prices, exchange rates and interest rates is summarized below:
     7
2011 MANAGEMENT’S DISCUSSION & ANALYSIS
 
 SENSITIVITIES
  Funds from Operations


EarningsMillions


Per Share


Millions


Per Share$0.50/Mcf in price of natural gas

$
4.7


$
0.03


$
3.5


$
0.02US $5.00/bbl in the WTI crude price

$
3.3


$
0.02


$
2.5


$
0.01US $0.01 in the US/Cdn exchange rate

$
1.0


$
0.01


$
0.7


$
0.001% in short-term interest rate

$
0.6


$
0.00


$
0.4


$
0.00
 
 This sensitivity analysis was calculated by applying different pricing, interest rate and exchange rate assumptions to the 2011 actual results related to production, prices, royalty rates, operating costs and capital spending.  As the contribution of oil production continues to increase as a percentage of total production, the impact of oil prices will be more significant and the impact of natural gas prices will be less significant to funds from operations and earnings than is shown in the table above.
   CAPITAL EXPENDITURES
 The Company spent $40.9 million in capital expenditures, net of dispositions and drilling incentive credits, in the fourth quarter of 2011 and $159.3 million for the year ended December 31, 2011.  The breakdown of expenditures is shown below:
  Three months ended

December 31


Year ended

December 31(thousands of dollars)

2011


2010


2011


2010Land, geological and geophysical costs

$
642


$
58


$
4,609


$
683Acquisitions


66



298



66



1,736Proceeds on disposition


(61
)


(68
)


(11,631
)


(2,467
)Drilling, completion and recompletion


32,196



19,336



127,456



72,873Drilling incentive credits


-



162



(400
)


(3,455
)Facilities and well equipment


7,417



6,297



35,418



40,079Capitalized G&A


674



1,106



3,569



3,594Total finding, development & acquisition

expenditures


40,934



27,189



159,087



113,043Change in compressor and other equipment

inventory


(24
)


(957
)


104



(1,601
)Office equipment and furniture


14



8



84



67Total net cash capital expenditures

$
40,924


$
26,240


$
159,275


$
111,509
 
 Drilling statistics are shown below:
  Three months ended December 31


Year ended December 312011


2010


2011


2010Gross


Net


Gross


Net


Gross


Net


Gross


NetGas


-



-



-



-



-



-



23



19.0Oil


10



9.6



6



5.1



51



43.8



22



16.3Dry


1



1.0



-



-



1



1.0



4



2.8Total


11



10.6



6



5.1



52



44.8



49



38.1Success rate (%)


91
%


91
%


100
%


100
%


98
%


98
%


92
%


93
%
  For the year ended December 31, 2011, the Company drilled 51 gross (44.7 net capital) Cardium horizontal wells.  Of the total 52 gross wells drilled, the Company drilled 10 gross (9.6 net capital) successful Cardium
   ANDERSON ENERGY
8
 
 
 horizontal wells and one 100% dry hole in the fourth quarter of 2011.  The Company has not drilled any vertical Edmonton Sands shallow gas wells since the first quarter of 2010.  Approximately $7.4 million was spent on facilities and well equipment during the fourth quarter of 2011.  Actual capital expenditures net of dispositions in 2011 exceeded budget primarily due to the deferral of expected dispositions to 2012.  In addition, the Company participated in one gross (0.5 net capital) well more than budgeted, accelerated certain Cardium facility expenditures and experienced some cost overruns on wells drilled near year end.
  During 2011 the Company sold non-core, heavy oil and other assets for proceeds of $11.6 million, which represented approximately 83 BOPD (89 BOED).  Subsequent to December 31, 2011, the Company sold or has entered into agreements to sell minor properties for $6.3 million in gross proceeds (subject to adjustments).
  RESERVES
  The Company’s reserves were evaluated by GLJ Petroleum Consultants (“GLJ”) in accordance with National Instrument 51-101 (“NI 51-101”) as of December 31, 2011, prepared in accordance with procedures and standards contained in the Canadian Oil and Gas Evaluation (“COGE”) Handbook.  The reserves definitions used in preparing the report are those contained in the COGE Handbook and the Canadian Securities Administrators National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities(“NI 51-101”).  The tables in this section are an excerpt from what will be contained in the Company’s Annual Information Form for the year ended December 31, 2011 (“AIF”) as the Company’s NI 51-101 annual required filings.
  At December 31, 2011, the Company’s proved developed producing (“PDP”), total proved (“TP”) and proved plus probable (“P&P”) reserves were 12.6 MMBOE, 20.9 MMBOE and 34.3 MMBOE respectively.
  Oil and NGL reserves now represent 33% of the Company's PDP, 29% of TP and 31% of the P&P reserves as compared to 23%, 19% and 21% respectively at December 31, 2010.  The Company increased PDP, TP and P&P oil and NGL reserves by 53%, 57% and 63% in the past year.
  SUMMARY OF GROSS OIL AND GAS RESERVES(1)
 As at December 31, 2011
 
 Oil (2)

(Mbbls)


Natural Gas (2)

(MMcf)


Natural Gas

Liquids (Mbbls)


Total BOE

(MBOE)Proved developed producing


2,576



50,783



1,534



12,573Proved developed non-producing


41



6,532



22



1,151Proved undeveloped


1,507



31,727



426



7,221Total proved


4,124



89,042



1,982



20,945Probable


3,320



52,347



1,335



13,379Total proved plus probable


7,444



141,389



3,316



34,325
 (1)
Columns may not add due to rounding.
 (2)
Coal Bed Methane is not material to report separately and is included in the Natural Gas category. Heavy Oil is not material to report separately and is included in the Oil category.
 9
2011 MANAGEMENT’S DISCUSSION & ANALYSIS
  NET PRESENT VALUE BEFORE INCOME TAXES(1)
 As at December 31, 2011
 GLJ December 31, 2011 Price Forecast, Escalated Prices
 
 (thousands of dollars)


0%



5%



10%



15%



20%Proved developed producing


308,576



247,604



207,906



180,236



159,918Proved developed non-producing


13,942



10,000



7,366



5,541



4,240Proved undeveloped


78,161



40,082



17,806



4,082



(4,713
)Total proved


400,679



297,687



233,078



189,858



159,445Probable


346,038



195,982



122,234



81,541



56,965Total proved plus probable


746,717



493,669



355,311



271,399



216,410
 (1)
Columns may not add due to rounding.
  The estimated net present value of future net revenues presented in the table above does not necessarily represent the fair market value of the Company’s reserves.
  SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
 As at December 31, 2011
 GLJ Forecast Prices and Costs
  Oil


Natural Gas


Edmonton Liquids PricesYear

WTI Cushing ($US/bbl)


Light, Sweet

Crude

Edmonton

($Cdn/bbl)


AECO Gas

Price ($Cdn/MMBTU)


Propane

($Cdn/bbl)


Butane

($Cdn/bbl)


Pentanes

Plus

($Cdn/bbl)


Inflation

Rate %


Exchange

rate

(US$/Cdn)2012


97.00



97.96



3.49



58.78



76.41



107.76



2.0



0.982013


100.00



101.02



4.13



60.61



78.80



108.09



2.0



0.982014


100.00



101.02



4.59



60.61



78.80



105.06



2.0



0.982015


100.00



101.02



5.05



60.61



78.80



105.06



2.0



0.982016


100.00



101.02



5.51



60.61



78.80



105.06



2.0



0.982017


100.00



101.02



5.97



60.61



78.80



105.06



2.0



0.982018


101.35



102.40



6.21



61.44



79.87



106.49



2.0



0.982019


103.38



104.47



6.33



62.68



81.49



108.65



2.0



0.982020


105.45



106.58



6.46



63.95



83.13



110.84



2.0



0.982021


107.56



108.73



6.58



65.24



84.81



113.08



2.0



0.98Thereafter 2%
 
 Total future development costs included in the reserves evaluation were $149.8 million for total proved reserves and $264.9 million for proved plus probable reserves.  Further details related to future development costs, including assumptions regarding the timing of the expenditures, will be included in the Company’s AIF for the 2011 fiscal year.  Future development costs are associated with the reserves as disclosed in the GLJ report and do not necessarily represent the Company’s current exploration and development budget.
    ANDERSON ENERGY
10
 
  CONTINUITY OF GROSS RESERVES (1)
  Natural Gas (Bcf)


Oil and Natural Gas Liquids (Mbbls)Proved


Probable


Total


Proved


Probable


TotalOpening balance

December 31, 2010


97.3



53.3



150.6



3,899



2,685



6,584Extensions and

improved recovery


9.3



9.0



18.2



3,150



2,336



5,485Technical revisions


4.6



0.2



4.8



137



(226
)


(89
)Economic factors


(9.7
)


(9.8
)


(19.5
)


-



-



-Dispositions


(0.8
)


(0.4
)


(1.2
)


(196
)


(140
)


(336
)Production


(11.5
)


-



(11.5
)


(884
)


-



(884
)Closing balance

December 31, 2011(2)


89.0



52.3



141.4



6,106



4,655



10,760
 (1)
Columns and rows may not add due to rounding.
 (2)
The closing balance for natural gas includes 2.7 Bcf of proved and 2.4 Bcf of probable Coal Bed Methane reserves. The closing balance for oil and natural gas liquids includes 35 Mbbls of proved and 36 Mbbls of probable Heavy Oil reserves.
  The Company’s reserves life indices are 7.5 years total proved and 12.2 years proved plus probable, based on 2011 annual production.  With an average $0.97 per MMBTU reduction in GLJ’s natural gas price outlook in the years 2012 to 2020, the Company experienced a negative revision for economic factors of 1.6 MMBOE for total proved and 3.3 MMBOE for proved plus probable reserves.  The economic factors negative revision was almost entirely related to the Company’s undeveloped gas reserves in the Edmonton Sands and CBM properties.  Offsetting the economic factors were positive technical revisions of 0.9 MMBOE total proved and 0.7 MMBOE proved plus probable reserves.  The Company experienced positive proved developed producing technical revisions of 0.3 MMBOE in the Edmonton Sands, indicative of improved performance.  Reserves additions before revisions were 4.7 MMBOE total proved and 8.5 MMBOE proved plus probable, predominantly from Cardium oil horizontal drilling.  The Company replaced 310% of its production with new proved plus probable reserves additions in 2011.  The Company replaced 572% of its 2011 oil and NGL production with new P&P oil and NGL reserves.
  FINDING, DEVELOPMENT AND ACQUISITION COSTS
 Year Ended December 31, 2011
  (in thousands of dollars)

Proved


Proved plus

ProbableFinding, development & acquisition expenditures

$
159,087


$
159,087Change in future development costs


12,797



25,015$
171,884


$
184,102Adjustment to change in future development costs for natural gas

economic factors


23,400



44,405$
195,284


$
228,507Reserve additions(MBOE)


4,692



8,526Dispositions (MBOE)


(337
)


(537
)Technical revisions (MBOE)


901



7145,256



8,7032011 finding, development & acquisition costs – additions and

technical revisions, including change in future development

costs, excluding economic factors and the change in future

development costs related to economic factors($/BOE)

$
37.15


$
26.26
  The Company experienced a significant revision for economic factors in 2011 which not only reduced
   11
2011 MANAGEMENT’S DISCUSSION & ANALYSIS
 
 reserves but also reduced future development capital.  To measure FD&A costs excluding the impact of economic factors, the future development capital was also adjusted upwards to exclude the effect of removing these reserves.  FD&A costs including future development costs for additions and technical revisions, but excluding economic factors were $37.15 per BOE total proved and $26.26 per BOE for proved plus probable.  Economic factors are influenced by consultant price forecasts and changes in natural gas price forecasts may cause economic factors to be positive in future years.  Calculated on a similar basis, the Company’s FD&A costs in 2010 were $22.30 per BOE on a proved basis and $22.35 per BOE on a proved plus probable basis and FD&A costs in 2009 were $8.64 per BOE on a proved basis and $8.46 per BOE on a proved plus probable basis.  The three year average FD&A costs was $24.78 per BOE total proved and $20.32 per BOE total proved plus probable.  The aggregate of the exploration, development and acquisition costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total finding, development and acquisition costs related to reserves additions for that year.
  SHARE INFORMATION
  The Company’s shares have been listed on the Toronto Stock Exchange since September 7, 2005 under the symbol “AXL”.  As of March 16, 2012, there were 172.5 million common shares outstanding, 13.9 million stock options outstanding, $50.0 million principal amount of convertible debentures which are convertible into common shares at a conversion price of $1.55 per common share and $46.0 million principal amount of convertible debentures which are convertible into common shares at a conversion price of $1.70 per common share.  During 2011, 64,400 common shares (2010 – 84,900) were issued under the employee stock option plan.
  SHARE PRICE ON TSX
 
 2011


2010High

$
1.36


$
1.57Low

$
0.35


$
0.95Close

$
0.54


$
1.05Volume


141,911,562



120,489,236Shares outstanding at December 31


172,549,701



172,485,301Market capitalization at December 31

$
93,176,839


$
181,109,566
 
 The statistics above include trading on the Toronto Stock Exchange only.  Shares also trade on alternative platforms like Alpha, Chi-X, Pure and Omega.  Approximately 99.7 million common shares traded on these alternative exchanges in 2011 (2010 – 65.0 million).  Including these exchanges, an average of 966,254 common shares traded per day in 2011 (2010 – 736,212), representing a turnover ratio of 140% (2010 – 109%).
  In February 2010, the Company issued 21.9 million common shares at a price of $1.45 per share pursuant to a short form prospectus.
  RELATED PARTY TRANSACTIONS
  On June 8, 2011, the Company issued 1,575 Series B Convertible Debentures to management and directors at a price of $1,000 per convertible debenture for total gross proceeds of $1.6 million as part of a $46.0 million bought deal offering of convertible debentures.
  On December 31, 2010, the Company issued 1,000 Series A Convertible Debentures to directors at a price of $1,000 per convertible debenture for total gross proceeds of $1.0 million as part of a $50.0 million bought deal offering of convertible debentures.
  In February 2010, the Company issued 352,466 common shares to directors at a price of $1.45 per share for total gross proceeds of $0.5 million as part of a $31.8 million bought deal offering of common shares.
   ANDERSON ENERGY
12
 
  ELIMINATION OF DEFICIT
  On May 16, 2011, the Company’s shareholders approved an ordinary resolution to eliminate the Company’s accumulated deficit at January 1, 2011 against share capital without reduction to stated capital or paid up capital.  The Company's accumulated deficit at January 1, 2011 was largely the result of the implementation of IFRS combined with the significant reduction in natural gas prices in recent years which reduced profitability and resulted in write downs of historical costs.  The Company believes that the elimination of the consolidated accounting deficit, in connection with the implementation of IFRS, is beneficial on a go-forward basis.  The accounting adjustment should allow shareholders to better evaluate the Company’s performance under IFRS reporting as well as measure the success of the Company’s response to detrimental changes in the natural gas business by transitioning to a more oil-weighted company.
  LIQUIDITY AND CAPITAL RESOURCES
  At December 31, 2011, the Company had outstanding bank loans of $88.7 million, convertible debentures of $96.0 million (principal) and a cash working capital deficiency (excludes unrealized gain on derivative contracts) of $44.0 million.  The working capital deficiency is largely due to accruals associated with the capital program in the last quarter of the year and will be funded through the available credit facilities, future operating cash flows and minor property sales.  The following table shows the changes in bank loans plus cash working capital deficiency:
  Three months ended

December 31


Year ended

December 31(thousands of dollars)

2011


2010


2011


2010Bank loans plus cash working capital deficiency,

beginning of period

$
(108,583
)

$
(102,198
)

$
(71,507
)

$
(72,524
)Funds from operations


16,997



9,282



54,464



36,516Net cash capital expenditures


(40,924
)


(26,240
)


(159,275
)


(111,509
)Proceeds from issue of convertible debentures,

net of issue costs


-



47,700



43,860



47,700Proceeds from issue of share capital,

net of issue costs


-



-



-



29,792Proceeds from exercise of stock options


-



67



51



67Decommissioning expenditures


(146
)


(118
)


(249
)


(1,549
)Bank loans plus cash working capital deficiency,

end of period

$
(132,656
)

$
(71,507
)

$
(132,656
)

$
(71,507
)
  The Company is committed to drill 74 gross (53.5 net capital) Edmonton Sands gas wells under its farm-in agreement by March 31, 2013.  The Company does not plan to drill any additional Edmonton Sands gas wells until the first quarter of 2013.
  The Company’s need for capital will be both short-term and long-term in nature.  Short-term capital is required to finance accounts receivable and other similar short-term assets while the acquisition and development of oil and natural gas properties requires larger amounts of long-term capital.  At December 31, 2011, the Company had total credit facilities of $135 million, consisting of a $110 million extendible revolving term credit facility, a $10 million working capital credit facility and a $15 million supplemental credit facility with a syndicate of Canadian banks.  The Company had $46.2 million of credit available at December 31, 2011.  On June 8, 2011, the Company completed a convertible subordinated debenture financing for proceeds, net of commission and expenses, of $43.9 million.  The net proceeds were initially used to pay down bank debt.  The availability created in the credit facilities, along with cash flows, was used to finance the Company’s capital programs.  Anderson will prudently use its bank loan facilities to
 
 13
2011 MANAGEMENT’S DISCUSSION & ANALYSIS
 
 finance its operations as required.  Capital spending for the first half of 2012 is expected to be approximately $12.0 million net of proceeds on dispositions of approximately $6.3 million and will be funded by cash flow from operations.  Remaining cash flow will be used to pay down bank debt.  The available lending limits under the bank facilities are reviewed twice a year and are based on the bank syndicate’s interpretation of the Company’s reserves and future commodity prices.  The last review was conducted in November 2011.  There can be no assurance that the amount of the available bank lines will not be adjusted at the next scheduled review to be completed prior to July 11, 2012.  The Company plans to fund its 2012 capital program from a combination of cash flow, existing credit facilities and asset dispositions.  Oil and natural gas prices will impact the level of capital spending in 2012.
  OFF BALANCE SHEET ARRANGEMENTS
  The Company had no guarantees or off-balance sheet arrangements other than as described below under “Contractual Obligations.”
  CONTRACTUAL OBLIGATIONS
  The Company enters into various contractual obligations in the course of conducting its operations.  At December 31, 2011, these obligations include:
  ●
Loan agreements – The reserves-based extendible, revolving term credit facility and working capital credit facility have a revolving period ending on July 11, 2012, extendible at the option of the lenders.  If not extended, the facilities cease to revolve and all outstanding advances thereunder become repayable one year from the term date of July 11, 2012.  The supplemental facility is available on a revolving basis and expires on July 11, 2012 with any amounts outstanding due in full at that time.  No amounts were drawn under the supplemental facility at December 31, 2011.
 ●
Letters of credit– Letters of credit of approximately $0.1 million had been issued in the normal course of business as at December 31, 2011 (December 31, 2010 – $0.1 million).
 ●
Convertible debentures – The Company has $96.0 million (principal) in convertible debentures outstanding at December 31, 2011, of which $50.0 million bears interest at 7.5% (“Series A Convertible Debentures”) and $46.0 million bears interest at 7.25% (“Series B Convertible Debentures”).  Each convertible debenture has a face value of $1,000 with interest payable semi-annually.  The Series A Convertible Debentures mature on January 31, 2016 with interest payable on the last day of July and January, commencing July 31, 2011.  These convertible debentures are convertible at the holder’s option at a conversion price of $1.55 per common share, subject to adjustment in certain events and are not redeemable by the Company before January 31, 2014.  The Series B Convertible Debentures mature on June 30, 2017 with interest payable on the last day of June and December, commencing December 31, 2011.  These convertible debentures are convertible at the holder’s option at a conversion price of $1.70 per common share, subject to adjustment in certain events and are not redeemable by the Company before June 30, 2014.
 ●
Firm service transportation commitments– The Company has entered into firm service transportation agreements for approximately 19 million cubic feet per day of gas sales for various terms expiring between 2012 and 2020.
 ●
Cardium Horizontal Well Program (Oil) – The Company has farm-in obligations to drill six gross (4.5 net capital) horizontal wells in the Cardium geological formation prior to dates ranging from August 1, 2012 to September 30, 2012.  One agreement has a $100,000 non-performance fee clause should the Company fail to drill the well.  Another agreement pertains to two wells; there is a $100,000 non-performance fee should the Company fail to drill both wells, and if only one well is drilled, the Company would also forfeit fifty per cent of the interest in the first well drilled under the agreement.
 ●
Edmonton Sands Well Program (Natural Gas)– In 2009, the Company committed to a 200 well drilling and completion program in the Edmonton Sands geological formation (the “Program”) under a farm-in agreement with a large international oil and gas company (the “Farmor”) from which the
    ANDERSON ENERGY
14
    As at December 31, 2011 the Company had the following minimum contractual obligations including long-term debt:
  Contractual obligations

Payments due by year

(in thousands of dollars)2012


2013


2014


2015


2016


ThereafterAccounts payable(3)

$
60,573


$



$



$



$



$Bank loans(1)


-



88,682



-



-



-



-Convertible debentures(2)(3)


5,523



7,085



7,085



7,085



55,210



47,667Non-cancellable operating leases


1,952



332



135



-



-



-Crude oil transportation contract


257



257



257



257



257



1,291Gas gathering contract


244



244



244



244



244



467Other capital commitments


505



-



-



-



-



-Farm-in commitments


200



10,000



-



-



-



-Firm service


1,255



871



679



608



95



299Total

$
70,509


$
107,471


$
8,400


$
8,194


$
55,806


$
49,724
 (1)
Assumes the credit facilities are not renewed on July 11, 2012.
 (2)
Includes the associated interest payments.
 (3)
Accounts payable and accruals includes $3.4 million of interest relating to convertible debentures.  The total cash interest payable in 2012 on the convertible debentures is $9.0 million.
 
 These obligations are described further in note 21 to the consolidated financial statements for the years ended December 31, 2011 and 2010.
  CRITICAL ACCOUNTING ESTIMATES
  The Company’s significant accounting policies are disclosed in note 3 to the consolidated financial statements.  Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses.  These accounting policies are discussed below and are included to aid the reader in assessing the critical accounting policies and practices of the Company and the likelihood of materially different results than reported.  The Company’s management reviews its estimates regularly.  The emergence of new information and changed circumstances may result in actual results that differ materially from current estimates.
  Oil and Gas Reserves.Proved and probable reserves, as defined by the Canadian Securities Administrators in NI 51-101 with reference to the Canadian Oil and Gas Evaluation Handbook, are estimated using independent reserves evaluator reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible.  There should be a 50 percent statistical probability that the actual
 
 15
2011 MANAGEMENT’S DISCUSSION & ANALYSIS
 
 quantity of recoverable reserves will be more than the amount estimated as proved and probable and a 50 percent statistical probability that it will be less.  The equivalent statistical probabilities for the proved component of proved and probable reserves are 90 percent and 10 percent, respectively.  Determination of reserves is a complex process involving judgments, estimates and decisions based on available geological, engineering, production and any other relevant data.  These estimates are subject to material change as economic conditions change and ongoing production and development activities provide new information.
  Purchase price allocations, depletion and depreciation and amounts used in impairment calculations are based on estimates of oil and gas reserves.  Reserves estimates are based on engineering data, estimated future prices, expected future rates of production and timing of future capital expenditures.  By their nature, these estimates are subject to measurement uncertainties and interpretations and the impact on the financial statements could be material.  The Company expects that over time, its reserves estimates will be revised upward or downward based on updated information such as the results of future drilling, testing and production levels and may be affected by changes in commodity prices.
  Decommissioning Obligations.The Company is required to set up a provision for future removal and site restoration costs.  The Company must estimate these costs in accordance with existing laws, contracts or other policies.  These estimated costs are charged to property, plant and equipment and the appropriate liability account over the expected service life of the asset.  The estimate of future removal and site restoration costs involves a number of estimates related to timing of abandonment, determination of the economic life of the asset, costs associated with abandonment and site restoration, discount rates and review of potential abandonment methods.
  Income Taxes.The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions.  All tax filings are subject to audit and potential reassessment after the lapse of considerable time.  Accordingly, the actual income tax liability may differ from that estimated and recorded by management.  The Company estimates its future income tax rate in calculating its future income tax liability.  Various assumptions are made in assessing when temporary differences will reverse and this will impact the rate used.
  Stock-Based Compensation.In order to recognize stock-based compensation costs, the Company estimates the fair value of stock options granted using assumptions related to interest rates, expected life of the option, forfeitures, volatility of the underlying security and expected dividend yields.  These assumptions may vary over time.
  ADOPTION OF IFRS
  International Financial Reporting Standards.  The Company adopted IFRS effective January 1, 2011. As a result, the Company's financial results for the year ended December 31, 2011 and comparative periods are reported under IFRS while selected historical data before 2010 continues to be reported under CGAAP.  Refer to note 23 of the consolidated financial statements for the years ended December 31, 2011 and 2010 for complete disclosure of the Company’s assessment of the impacts of the transition to IFRS.
  Summary of impact to the Company’s business and cash flows under IFRS.The reconciling items discussed below between CGAAP and IFRS policies have had no material impact on the Company’s strategic decisions, business practices or prospects, operations, key agreements including debt agreements and covenants, or cash flow from operations before changes in non-cash working capital.    However, there has been a significant impact on individual components of the consolidated statement of financial position (formerly known as the “balance sheet”), shareholders’ equity, and on earnings (loss), as well as substantially changing the form and content of certain disclosures.
  The Company restated its statement of financial position using IFRS and reconciled the significant changes from the amounts previously reported under CGAAP.
   ANDERSON ENERGY
16
 The following provides summary reconciliations of Anderson’s January 1, 2010 CGAAP to IFRS transitional statement of financial position and December 31, 2010 statement of financial position as well as an earnings reconciliation for the year ended December 31, 2010 and a discussion of the significant IFRS accounting policy changes:
  Summarized statement of financial position at January 1, 2010:
  (in thousands of dollars)

CGAAP


Effect of

Transition to IFRS


IFRSASSETSCurrent assets

$
26,769


$
-


$
26,769Property, plant and equipment (notes a and b)


470,400



(67,193
)


403,207$
497,169


$
(67,193
)

$
429,976LIABILITIES AND EQUITYCurrent liabilities

$
36,889


$
-


$
36,889Bank loans


62,404



-



62,404Decommissioning obligations (note d)


33,879



13,778



47,657Deferred tax liability  (note h)


31,278



(20,358
)


10,920Share capital (notes f and h)


391,637



4,887



396,524Contributed surplus (note e)


6,104



234



6,338Deficit (note i)


(65,022
)


(65,734
)


(130,756
)$
497,169


$
(67,193
)

$
429,976
  Summarized statement of financial position at December 31, 2010:
  (in thousands of dollars)

CGAAP


Effect of

Transition to IFRS


IFRSASSETSCurrent assets

$
28,582


$
(508
)

$
28,074Property, plant and equipment (notes a and b)


506,533



(185,860
)


320,673$
535,115


$
(186,368
)

$
348,747LIABILITIES AND EQUITYCurrent liabilities

$
48,780


$
-


$
48,780Bank loans


52,719



-



52,719Convertible debentures


43,460



-



43,460Decommissioning obligations (note d)


36,320



15,230



51,550Deferred tax liability  (note h)


20,045



(49,702
)


(29,657
)Share capital (notes f and h)


422,038



4,887



426,925Equity component of convertible debentures

(note g)


4,242



(1,650
)


2,592Contributed surplus (note e)


8,164



(243
)


7,921Deficit (note i)


(100,653
)


(154,890
)


(255,543
)$
535,115


$
(186,368
)

$
348,747
   17
2011 MANAGEMENT’S DISCUSSION & ANALYSIS
 Summarized net earnings reconciliations for 2010:
  (in thousands of dollars)

YTD 2010



Q4 2010



Q3 2010



Q2 2010



Q1 2010Loss under CGAAP

$
(35,631
)

$
(11,741
)

$
(9,046
)

$
(8,891
)

$
(5,953
)Increase (decrease) in earnings under IFRS:General and administrative (note c)


(664
)


(233
)


(150
)


(81
)


(200
)Stock-based payments (note e)


155



(1
)


102



23



31Depletion and depreciation (note c)


33,071



9,028



8,306



8,392



7,345Accretion on decommissioning

obligations (note d)


888



230



228



219



211Gain on sale of property, plant and

equipment (note c)


389



69



(388
)


35



673Impairment of property, plant and

equipment (note b)


(153,165
)


(42,196
)


(48,317
)


(3,112
)


(59,540
)Deferred tax (note h)


30,170



8,299



10,236



(1,354
)


12,989Impact of IFRS


(89,156
)


(24,804
)


(29,983
)


4,122



(38,491
)Loss under IFRS

$
(124,787
)

$
(36,545
)

$
(39,029
)

$
(4,769
)

$
(44,444
)
  Notes to reconciliations:
  (a)
IFRS 1 Exemptions:
  Deemed Cost.The Company applied the IFRS 1 exemption whereby the value of its opening plant, property and equipment at January 1, 2010 was deemed to be equal to the net book value as determined under Canadian GAAP and the corresponding CGUs were tested for impairment.  The Company chose to allocate its costs to its CGUs based on proved plus probable reserves volumes.
  Business Combinations.The Company applied the IFRS 1 exemption and did not retrospectively revalue business combinations that occurred before January 1, 2010 in accordance with IFRS 3, Business Combinations.  Accordingly, there were no adjustments made to the Company’s January 1, 2010 financial statements as a result of this exemption.
  Borrowing Costs.The Company applied the IFRS 1 exemption which allowed first-time adopters to use the transitional provisions set out in IAS 23, Borrowing Costs and set the effective date of the standard as January 1, 2010, which is the date of the Company’s transition to IFRS.  Accordingly, there were no adjustments made to the Company’s January 1, 2010 financial statements as a result of this exemption.
  Refer to notes (d) and (e) below for further discussion on IFRS 1 exemptions taken for decommissioning obligations and share-based payments.
  (b)  IAS 36 Adjustments – Impairment of Assets.Under Canadian GAAP, impairment of non-financial assets is assessed on the basis of an asset’s estimated undiscounted future cash flows compared with the asset’s carrying amount and if impairment is indicated, discounted cash flows are prepared to quantify the amount of the impairment. Under IFRS, impairment is assessed based on the recoverable amount (greater of value in use or fair value less costs to sell) compared with the asset’s carrying amount to measure the amount of the impairment.  In addition, under IFRS, where a non-financial asset does not generate largely independent cash inflows, the Company is required to perform its test at a cash generating unit level, which is the smallest identifiable grouping of assets that generates largely independent cash inflows. Canadian GAAP impairment was based on undiscounted cash flows using asset groupings with both independent cash inflows and cash outflows.
  As a result of applying the deemed cost exemption at January 1, 2010, the Company recorded an impairment of $67.2 million with a corresponding reduction in property, plant and equipment.  For the year
 
 ANDERSON ENERGY
18
  ended December 31, 2010, the Company recognized additional impairments of $153.2 million respectively with a corresponding reduction in property, plant and equipment as a result of declines in the forward natural gas price curves.
  (c)
IAS 16 Adjustments – Property, Plant and Equipment.
  Depletion and depreciation.Upon transition to IFRS, the Company adopted a policy of depleting and depreciating oil and natural gas interests on a unit of production basis over proved plus probable reserves.  The depletion and depreciation policy under Canadian GAAP was based on unit of production over proved reserves.  Depletion and depreciation was calculated on the Canadian full cost pool under Canadian GAAP.  IFRS requires depletion and depreciation to be calculated based on individual components.
  At January 1, 2010, there were no amounts recorded as a result of the policy differences as discussed above.  For the year ended December 31, 2010, the use of proved plus probable reserves in conjunction with lower net book values due to impairments in the Company’s Shallow Gas, Deep Gas and Non-core CGUs resulted in a decrease to depletion and depreciation of $33.1 million with a corresponding increase to property, plant and equipment.
  Other adjustments.IFRS requires that gains or losses be reported on the disposition of property, plant and equipment.  Under Canadian GAAP, gains or losses on disposition of property, plant and equipment were only reported when the disposition resulted in more than a 20 percent change in the depletion rate.  As a result of this requirement, the Company reported a gain of $0.4 million during the year ended December 31, 2010 with an increase in property, plant and equipment where the proceeds were originally recorded under Canadian GAAP and a net increase to decommissioning obligations that were assumed as part of an asset exchange of $0.2 million.
  IFRS also requires that the capitalization of general and administrative costs be limited to directly attributable costs.  Under Canadian GAAP, a reasonable allocation of general and administrative costs to property, plant and equipment was acceptable.  As a result of the change in the capitalization criteria, the Company increased its general and administrative expense by $0.7 million during the year ended December 31, 2010 with a corresponding decrease in property, plant and equipment.
  Under Canadian GAAP, a deferred tax adjustment was recorded related to stock-based compensation costs capitalized.  No such adjustment is made under IFRS.  As a result of this change, property, plant and equipment was reduced by $0.3 million at December 31, 2010 with a corresponding decrease to the deferred tax liability.
  (d)  IAS 37 Adjustments – Provisions, Contingent Liabilities and Contingent Assets.Consistent with IFRS, decommissioning obligations (asset retirement obligations under Canadian GAAP) were measured under Canadian GAAP based on the estimated cost of decommissioning, discounted to their net present value upon initial recognition.  Under Canadian GAAP, asset retirement obligations were discounted at a credit adjusted risk fee rate of eight to 10 percent.  Under IFRS, decommissioning obligations are discounted at a risk free rate of one to four percent depending upon the estimated timelines to reclamation.  Under IFRS, decommissioning obligations are also required to be re-measured at each reporting period to incorporate changes in future cash flow estimates, timelines to reclamation as well as discount rates used in present valuing the obligations.
  The IFRS 1 exemption was utilized for asset retirement obligations associated with oil and gas properties and the Company re-measured asset retirement obligations as at January 1, 2010 under IAS 37 with a corresponding adjustment to opening retained earnings. Upon transition to IFRS, this resulted in a $13.8 million increase in the decommissioning obligations with a corresponding decrease in retained earnings.
  At December 31, 2010, the Company increased its decommissioning obligations by $15.1 million from Canadian GAAP.  The Company also increased the value of its plant, property and equipment for December 31, 2010 by $2.2 million for new obligations incurred during 2010.
  For the year ended December 31, 2011, accretion expense decreased by $0.9 million under IFRS compared to Canadian GAAP as a result of higher initial decommissioning obligations being recognized
   19
2011 MANAGEMENT’S DISCUSSION & ANALYSIS
 
 under IFRS and lower discount rates being used.  Under IFRS, accretion on decommissioning obligations is included in finance expenses as opposed to Canadian GAAP where these amounts were included in depletion, depreciation and accretion.
  (e)  IFRS 2 Adjustments – Share-based Payments.  Under Canadian GAAP, the Company recognized stock-based compensation expense on a straight-line basis through the date of full vesting and incorporated a forfeiture rate, which was optional under Canadian GAAP.  Under IFRS, the Company is required to recognize the expense over the individual vesting periods for the graded vesting awards and estimating a forfeiture rate is no longer optional.
  The Company applied the IFRS 1 exemption for equity instruments which vested before the transition date and did not retroactively restate them.  All unvested options at transition date were retroactively restated in accordance with IFRS 2 with the adjustment going through opening retained earnings.  As a result, the Company recorded an additional $0.2 million in contributed surplus at January 1, 2010 for unvested options with the offset going to opening retained earnings.
  For the year ended December 31, 2010, the Company reduced contributed surplus by $0.5 million and reduced the amount of stock-based compensation capitalized by $0.3 million for a net reduction in stock-based compensation expense of $0.2 million.  Under Canadian GAAP, stock-based compensation expense was disclosed separately on the consolidated statement of operations and comprehensive loss.  Under IFRS, stock-based compensation expense is included in general and administrative expenses.
  (f)   Flow Through Shares.  Under Canadian GAAP, the Company recorded the deferred tax impact on renouncement of flow through shares against share capital.  Under IFRS, the Company is required to record a premium liability when the flow through shares are issued, which is relieved upon renouncement, with the difference going to deferred tax expense.  As a result of this change in the treatment of deferred taxes, at January 1, 2010, the Company recorded an additional $5.3 million to share capital with a corresponding reduction in retained earnings for flow through shares that had been previously issued and fully renounced at transition.
  (g)  Convertible Debentures.  Under Canadian GAAP, the Company did not record a deferred tax difference on its convertible debentures.  Under IFRS, the Company is required to record the deferred tax difference between the fair value of the liability component of the convertible debentures and the tax value of the convertible debentures with the difference being booked against the equity component of convertible debentures.  As a result, the Company recorded $1.7 million in deferred tax against the equity component of convertible debentures at December 31, 2010.
  (h)  IAS 12 Adjustments – Income Taxes.The aforementioned changes increased (decreased) the net deferred tax liability as follows based on a tax rate of 25 percent:
  December 31, 2010


January 1, 2010Impairment of plant, property and equipment (note b)

$
(55,407
)

$
(16,914
)Depletion and depreciation (note c)


8,268



-Decommissioning obligation (note d)


(3,222
)


(3,444
)Convertible debentures (note g)


1,650



-Other adjustments (note c)


(483
)


-Decrease in deferred tax liability

$
(49,194
)

$
(20,358
)
  IFRS requires that adjustments to the future tax rates used to calculate deferred taxes be traced and recorded against the original source of the timing difference as opposed to through earnings as was done under Canadian GAAP.  As a result of this change at January 1, 2010, the Company reclassified $0.5 million in deferred taxes previously recorded in income against share issue costs.
  Under Canadian GAAP, the Company was required to disclose future income taxes in the same current or long-term classification from which the timing differences arose.  As such at December 31, 2010, the Company reported $0.5 million as a current asset related to timing differences that would reverse in one
   ANDERSON ENERGY
20
 
 year.  There is no such requirement under IFRS, therefore the Company removed the separate disclosure of current deferred taxes.
  The effect on the consolidated statements of operations and comprehensive loss for the year ended December 31, 2010 was to decrease the previously reported tax charge by $30.2 million.
  (i)   Retained Earnings Adjustments.The aforementioned changes increased (decreased) retained earnings as follows on an after-tax basis:
  December 31, 2010


January 1, 2010Impairment of plant, property and equipment (note b)

$
(164,951
)

$
(50,279
)Decommissioning obligations (note d)


(9,668
)


(10,334
)Flow through shares (note f)


(5,336
)


(5,336
)Depletion and depreciation (note c)


24,803



-General and administrative expenses (note c)


(497
)


-Gain on sale of plant, property and equipment (note c)


389



-Deferred taxes on share issue costs(note h)


449



449Stock-based compensation (note e)


(79
)


(234
)Decrease in retained earnings

$
(154,890
)

$
(65,734
)
  (j)   Adjustments to the Company’s Statements of Cash Flows under IFRS.  The reconciling items discussed above between Canadian GAAP and IFRS policies have no material impact on the cash flows generated by the Company.  As a result of the change in capitalized general and administrative expenses, there was a reduction of $0.7 million to operating cash flows, with and equal and opposite effect on investing cash flows for the year ended December 31, 2010.
  NEW AND PENDING ACCOUNTING STANDARDS
  The IASB has issued the following new standards and amendments, all of which are effective for annual periods beginning on or after January 1, 2013.  Although early adoption is permitted, the Company has not done so as of December 31, 2011.
  IFRS 9 – Financial Instruments.  In November 2009, the IASB published IFRS 9 “Financial Instruments" which covers the classification and measurement of financial assets as part of its project to replace IAS 39 “Financial Instruments: Recognition and Measurement.” IFRS 9 uses a single approach to determine whether a financial asset is measured at amortized cost or fair value, replacing the multiple rules in IAS 39.  The approach in IFRS 9 is based on how an entity managed its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets.  The new standard also requires a single impairment method to be used, replacing the multiple impairment methods in IAS 39.
  In October 2010, additional requirements for classifying and measuring financial liabilities were added to IFRS 9. Under this guidance, entities have the option to recognize financial liabilities at fair value through profit or loss. If this option is elected, entities would be required to reverse the portion of the fair value change due to own credit risk out of profit or loss and recognize the change in other comprehensive income.
  On August 4, 2011, the IASB issued an exposure draft proposing to change the mandatory effective date of IFRS 9 to annual periods beginning on or after January 1, 2015 from the original effective date of January 1, 2013. Early adoption is permitted and the standard is required to be applied retrospectively. The comment period for this exposure draft closed on October 21, 2011.  The implementation of the issued standard is not expected to have a significant impact on the Company’s financial position or results.
  21
2011 MANAGEMENT’S DISCUSSION & ANALYSIS
  Reporting Entity.  In May 2011, the IASB issued IFRS 10 Consolidated Financial Statement, IFRS 11 Joint Arrangements, IFRS 12 Disclosures of Interests in Other Entities, and amendments to IAS 27 Separate Financial Statements and IAS 28 Investments in Associates and Joint Ventures.
  IFRS 10 creates a single consolidation model by revising the definition of control in order to apply the same control criteria to all types of entities, including joint arrangements, associates and special purpose vehicles. IFRS 11 establishes a principle-based approach to the accounting for joint arrangements by focusing on the rights and obligations of the arrangement and limits the application of proportionate consolidation accounting to arrangements that meet the definition of a joint operation. IFRS 12 is a comprehensive disclosure standard for all forms of interests in other entities, including joint arrangements, associates and special purpose vehicles.
  Retrospective application of these standards with relief for certain transactions is effective for fiscal years beginning on or after January 1, 2013, with earlier application permitted if all five standards are collectively adopted.  The implementation of the issued standard is not expected to have a significant impact on the Company’s financial position or results.
  IAS 12 – Income Taxes.  IAS 12 “Income Taxes” was amended on December 20, 2010 to remove subjectivity in determining on which basis an entity measures the deferred tax relating to an asset.  The amendment introduces a presumption that an entity will assess whether the carrying value of an asset will be recovered through the sale of the asset.  The amendment to IAS 12 is effective for reporting periods beginning on or after January 1, 2012.  The implementation of the issued standard is not expected to have a significant impact on the Company’s financial position or results.
  IFRS 13 – Fair Value Measurement.  In May 2011, the IASB issued IFRS 13 Fair Value Measurement, which establishes a single source of guidance for all fair value measurements; clarifies the definition of fair value; and enhances the disclosures on fair value measurement. Prospective application of this standard is effective for fiscal years beginning on or after January 1, 2013, with early application permitted.  The implementation of the issued standard is not expected to have a significant impact on the Company’s financial position or results.
  CONTROLS AND PROCEDURES
  The Chief Executive Officer (“CEO”) and the Chief Financial Officer (“CFO”) have designed, or caused to be designed under their supervision, disclosure controls and procedures (“DC&P")and internal controls over financial reporting (“ICOFR”) as defined in National Instrument 52-109 Certification of Disclosure in Issuer’s Annual and Interim Filings in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with IFRS.
  The DC&P have been designed to provide reasonable assurance that material information relating to the Company is made known to the CEO and CFO by others and that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by the Company under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation. The Company’s CEO and CFO have concluded, based on their evaluation at the financial year end of the Company, that the Company’s disclosure controls and procedures are effective to provide reasonable assurance that material information related to the issuer is made known to them by others within the Company.
  The ICOFR have been designed to provide reasonable assurance that all assets are safeguarded, transactions are appropriately authorized and to facilitate the preparation of relevant, reliable and timely information. The CEO and CFO have evaluated and tested the design and operating effectiveness of Anderson’s ICOFR as of December 31, 2011 and have concluded that, these internal controls are designed properly and are effective in the preparation of financial statements for external purposes in
 
 ANDERSON ENERGY
22
 
 accordance with IFRS.  The CEO and CFO are required to cause the Company to disclose any change in the Company’s ICOFR that occurred during the period beginning on October 1, 2011 and ending on December 31, 2011 that has materially affected, or is reasonably likely to materially affect, the Company’s ICOFR. No changes in ICOFR were identified during such period that have materially affected or are reasonably likely to materially affect the Company’s ICOFR. There were no changes to ICOFR as a result of the transition to IFRS.
  It should be noted a control system, including the Company’s DC&P and ICOFR, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objective of the control system will be met and it should not be expected that DC&P and ICOFR will prevent all errors or fraud.
  BUSINESS RISKS
  Oil and gas exploration and production is capital intensive and involves a number of business risks including, without limitation, the uncertainty of finding new reserves, the instability of commodity prices, weather and various operational risks.  Commodity prices are influenced by local and worldwide supply and demand, OPEC actions, ongoing global economic concerns, the U.S. dollar exchange rate, transportation costs, political stability and seasonal and weather related changes to demand.  The price of natural gas has weakened due to increasing U.S. gas production driven primarily by the U.S. shale gas plays.  The large amount of gas in storage combined with strong U.S. gas production and financial market fears has continued to suppress the price of natural gas.  Oil prices continue to remain volatile as they are a geopolitical commodity, affected by concerns about economic markets in the U.S. and Europe and continued instability in oil producing countries. Differentials between WTI oil prices and prices received in Alberta have widened and also remain volatile. The industry is subject to extensive governmental regulation with respect to the environment.  Operational risks include well performance, uncertainties inherent in estimating reserves, timing of/ability to obtain drilling licences and other regulatory approvals, ability to obtain equipment, expiration of licences and leases, competition from other producers, sufficiency of insurance, ability to manage growth, reliance on key personnel, third party credit risk and appropriateness of accounting estimates.  These risks are described in more detail in the Company’s most recent Annual Information Form filed with Canadian securities regulatory authorities on SEDAR.
  The Company anticipates making substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future. As the Company's revenues may decline as a result of decreased commodity pricing, it may be required to reduce capital expenditures. In addition, uncertain levels of near term industry activity coupled with the present global economic concerns exposes the Company to additional access to capital risk. There can be no assurance that debt or equity financing, or funds generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Company. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on the Company's business, financial condition, results of operations and prospects.
  Anderson manages these risks by employing competent professional staff, following sound operating practices and using capital prudently.  The Company generates its exploration prospects internally and performs extensive geological, geophysical, engineering, and environmental analysis before committing to the drilling of new prospects.  Anderson seeks out and employs new technologies where possible. With the Company’s extensive drilling inventory and advance planning, the Company believes it can manage the slower pace of regulatory approvals and the requirements for extensive landowner consultation.
  The Company has a formal emergency response plan which details the procedures employees and contractors will follow in the event of an operational emergency.  The emergency response plan is designed to respond to emergencies in an organized and timely manner so that the safety of employees, contractors, residents in the vicinity of field operations, the general public and the environment are protected.  A corporate safety program covers hazard identification and control on the jobsite, establishes
 
 23
2011 MANAGEMENT’S DISCUSSION & ANALYSIS
 
 Company policies, rules and work procedures and outlines training requirements for employees and contract personnel.
  The Company currently deals with a small number of buyers and sales contracts, and endeavors to ensure that those buyers are an appropriate credit risk.  The Company continuously evaluates the merits of entering into fixed price or financial hedge contracts for price management.
  The oil and natural gas business is subject to regulation and intervention by governments in such matters as the awarding of exploration and production interests, the imposition of specific drilling obligations, environmental protection controls, control over the development and abandonment of fields (including restrictions on production) and possibly expropriation or cancellation of contract rights.  As well, governments may regulate or intervene with respect to prices, taxes, royalties and the exportation of oil and natural gas.  Such regulation may be changed from time to time in response to economic or political conditions.  The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for oil and natural gas, increase the Company’s costs or affect its future opportunities.
  The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation.  Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations.  Such legislation may also impose restrictions and prohibitions on water use or processing in connection with certain oil and gas operations.  In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities.  Compliance with such legislation can require significant expenditures and a breach of such requirements may result, amongst other things in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, and the imposition of material fines and penalties.
  Internationally, Canada is a signatory to the United Nations Framework Convention on Climate Change and previously ratified the Kyoto Protocol established thereunder, which set legally binding targets to reduce nation-wide emissions of carbon dioxide, methane, nitrous oxide, and other greenhouse gases ("GHGs").  The first commitment period under the Kyoto Protocol is the five year period from 2008 to 2012. In December 2011, the Canadian federal government announced that it would not agree to a second commitment period under the Kyoto Protocol after 2012.  Domestically, the Canadian federal government released in 2007 its Regulatory Framework for Air Emissions, which was updated in March 2008 in a document entitled "Turning the Corner: Regulatory Framework for Industrial Greenhouse Emissions".  Canada's previous GHG emission reduction target was 20% from 2006 levels by 2020, but on January 30, 2010 the Canadian federal government announced a new GHG emission reduction target consistent with the Copenhagen Accord to reduce GHG emissions to 17% below 2005 levels by 2020.  Canada's framework proposes mandatory emissions intensity reduction obligations on a sector-by-sector basis.  It is uncertain whether or when either Canadian federal GHG regulations for the oil and gas industry will be implemented, or what obligations might be imposed under any such systems.  As the details of the implementation of any federal legislation for GHGs that is applicable to the oil and gas industry have not been announced, the effect on Anderson's operations cannot be determined at this time.
  Additionally, regulation can take place at the provincial and municipal level.  For example, Alberta introduced the Climate Change and Emissions Management Act, which provides a framework for managing GHG emissions and establishes a target of reducing specified gas emissions relative to gross domestic product to an amount that is equal to or less than 50% of 1990 levels by December 31, 2020.  The accompanying regulations, the Specified Gas Emitters Regulation and the Specified Gas Emitters Reporting Regulation require mandatory emissions reductions through the use of emissions intensity targets and impose duties to report.  The Canadian federal government proposes to enter into equivalency agreements with provinces that establish a regulatory regime to ensure consistency with the federal plan, but the success of any such plan is doubtful in the current political climate, leaving multiple overlapping levels of regulation.
   ANDERSON ENERGY
24
  The Government of Alberta implemented a new oil and gas royalty framework effective January 2009.  The new framework establishes new royalties for conventional oil, natural gas and bitumen that are linked to price and production levels and apply to both new and existing conventional oil and gas activities and oil sands projects.  Under the framework, the formula for conventional oil and natural gas royalties uses a sliding rate formula, dependent on the market price and production volumes.  On March 3, 2009, June 11, 2009 and June 25, 2009, the Government of Alberta announced amendments to the framework.  This incentive program included a drilling credit for new oil and natural gas wells drilled between April 1, 2009 and March 31, 2011, providing a $200 per metre drilled royalty credit to companies.  The credit was used to offset up to 50% of Crown royalties paid after the wells have been drilled up until March 31, 2011.  There is also a new well incentive program that provides a maximum 5% royalty rate for the first 12 months of production from new wells that begin producing oil or natural gas between April 1, 2009 and March 31, 2011 to a maximum of 50,000 barrels of oil or 500 million cubic feet of natural gas.
  On March 11, 2010, the Alberta government announced adjustments to the royalty rates which became effective January 1, 2011. This adjustment included making the incentive program royalty rate of 5% on new natural gas and conventional oil wells a permanent feature of the royalty system with the time and volume limits discussed above. The maximum royalty rate was reduced from 50% to 40% for conventional oil and to 36% for natural gas.
  BUSINESS PROSPECTS
  The Company believes it has an excellent future drilling inventory in the Cardium light oil horizontal oil play and is focused on growing its production and reserves with Cardium horizontal drilling.  The Company has 131 gross (81 net) sections in the Cardium fairway and has identified an inventory of 260 gross (166 net revenue) drill-ready Cardium horizontal oil locations, of which 75 gross (56 net revenue) have been drilled to March 16, 2012.  The Company continues to add to its land position and drilling inventory through a combination of acquisitions, property swaps and farm-ins, and continues to implement new technologies to control and reduce its costs in this project.
  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 dedicated to reduce bank debt.  Crude oil pricing remains strong, but volatile and Anderson has increased its hedge position to help protect its capital program and its shareholders from volatile oil markets.  The Company will revisit its 2012 capital budget after spring breakup.
  The Company is in the process of reviewing the contributions of its natural gas assets to the Company’s cash flows in the current low price environment.  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 three months and with the completion of the infrastructure projects, newly drilled Cardium horizontal wells can be easily 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 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
 
 25
2011 MANAGEMENT’S DISCUSSION & ANALYSIS
 
 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. This process has not been initiated as a result of any particular offer.
  It is Anderson’s current intention to not disclose developments with respect to its strategic alternatives process unless and until the Board of Directors has approved a specific transaction or otherwise determines that disclosure is necessary in accordance with applicable law. The Company cautions that 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.
  QUARTERLY INFORMATION
  The following table provides financial and operating results for the last eight quarters.  Commodity prices remain volatile, affecting funds from operations and earnings throughout those quarters.  In 2010, the Company changed its focus to oil projects in light of the continued depressed natural gas market, and suspended its shallow gas drilling program until natural gas prices improve.  Revenues, funds from operations and earnings (loss) over the past year reflect the benefits from increased sales of crude oil volumes.  Also, earnings were affected in each of the four quarters in 2010 by impairments in the value of property, plant and equipment related to natural gas reserves values.  With continued volatility in commodity prices, Anderson’s earnings were impacted by impairment reversals in the third quarter of 2011 and impairments in the fourth quarter of 2011.
 
           ANDERSON ENERGY
26
  SELECTED QUARTERLY INFORMATION
 ($ amounts in thousands, except per share amounts and prices)
 Q4 2011



Q3 2011



Q2 2011



Q1 2011Revenue, net of royalties

$
28,457


$
24,970


$
27,776


$
23,283Funds from operations

$
16,997


$
12,655


$
13,944


$
10,868Funds from operations per share, basic and diluted

$
0.10


$
0.07


$
0.08


$
0.06Earnings (loss) before effect of impairments or reversals

thereof

$
(4,939
)

$
6,667


$
5,932


$
(3,681
)Earnings (loss) per share before effect of impairments or

reversals thereofBasic and diluted

$
(0.03
)

$
0.04


$
0.03


$
(0.02
)Earnings (loss)

$
(32,167
)

$
7,472


$
5,932


$
(3,681
)Basic and diluted

$
(0.19
)

$
0.04


$
0.03


$
(0.02
)Capital expenditures, including acquisitions net of

proceeds on dispositions

$
40,924


$
49,713


$
26,284


$
42,354Cash from operating activities

$
16,462


$
11,893


$
14,953


$
11,001Daily salesNatural gas (Mcfd)


30,576



30,038



31,990



33,931Oil (bpd)


2,122



1,709



1,759



1,372NGL (bpd)


715



636



667



699BOE (BOED)


7,933



7,351



7,758



7,726Average pricesNatural gas ($/Mcf)

$
3.20


$
3.85


$
3.79


$
3.58Oil ($/bbl)

$
96.33


$
89.05


$
99.39


$
84.71NGL ($/bbl)

$
72.71


$
66.07


$
74.24


$
65.97BOE ($/BOE)(1)(2)

$
44.70


$
42.16


$
44.71


$
36.80Q4 2010



Q3 2010



Q2 2010



Q1 2010Revenue, net of royalties

$
21,690


$
17,263


$
18,622


$
19,871Funds from operations

$
9,282


$
7,876


$
8,923


$
10,435Funds from operations per share, basic and diluted

$
0.05


$
0.05


$
0.05


$
0.06Earnings (loss) before effect of impairment

$
(4,864
)

$
(3,057
)

$
(2,450
)

$
256Earnings (loss) per share before effect of impairmentBasic and diluted

$
(0.03
)

$
(0.02
)

$
(0.01
)

$
-Loss

$
(36,545
)

$
(39,029
)

$
(4,769
)

$
(44,444
)Loss per share, basic and diluted

$
(0.21
)

$
(0.23
)

$
(0.03
)

$
(0.27
)Capital expenditures, including acquisitions net of

dispositions

$
26,240


$
39,378


$
12,664


$
33,227Cash from operating activities

$
10,488


$
8,287


$
8,811


$
12,746Daily salesNatural gas (Mcfd)


38,479



35,778



38,998



35,221Oil (bpd)


992



568



491



345NGL (bpd)


823



761



741



785BOE (BOED)


8,228



7,292



7,732



7,000Average pricesNatural gas ($/Mcf)

$
3.48


$
3.43


$
3.78


$
5.22Oil ($/bbl)

$
77.62


$
68.24


$
70.45


$
75.47NGL ($/bbl)

$
58.87


$
51.41


$
53.55


$
56.68BOE ($/BOE)(1)(2)

$
31.63


$
28.21


$
28.88


$
36.93
 (1) Includes royalty and other income classified with oil and gas sales.
 (2) Excludes realized and unrealized gains (losses) on derivative contracts as follows: Q4 2011 – ($0.3) million and ($7.9) million respectively; Q3 2011 – $0.9 million and $6.4 million respectively; Q2 2011 – ($0.8) million and $7.7 million respectively; Q1 2011 – ($0.4) million and ($2.8) million respectively; and Q4 2010 – ($0.1) million and ($1.9) million respectively.
   27
2011 MANAGEMENT’S DISCUSSION & ANALYSIS
 SELECTED ANNUAL INFORMATION
  YEARS ENDED DECEMBER 31
 (in thousands, except per share amounts)
 
 IFRS


CGAAP2011


2010


2009Total oil and gas sales(1)

$
118,292


$
86,457


$
76,993Total revenue, net of royalties(1)

$
104,486


$
77,446


$
68,740Earnings (loss) before effect of impairment

$
3,979


$
(10,115
)

$
(36,458
)Earnings (loss) before effect of impairment per shareBasic

$
0.02


$
(0.06
)

$
(0.29
)Diluted

$
0.02


$
(0.06
)

$
(0.29
)Loss

$
(22,444
)

$
(124,787
)

$
(36,458
)Loss per shareBasic

$
(0.13
)

$
(0.73
)

$
(0.29
)Diluted

$
(0.13
)

$
(0.73
)

$
(0.29
)Total assets

$
460,319


$
378,404


$
497,169Total bank loans

$
88,682


$
52,719


$
62,404Total convertible debentures, liability component

$
84,796


$
43,460


$
-
 (1)
Includes royalty and other income classified with oil and gas sales.  Excludes the realized loss and unrealized gain on derivative contracts in 2011 of ($0.6) million and $3.3 million (2010 – ($0.1) million realized loss and ($1.9) million unrealized loss).
  Total oil and gas sales and total revenue, net of royalties have grown year over year as shown above due to the focus on increasing oil production, as well as increased oil prices.  However, loss and loss per share have increased due to impairment charges.  These impairment charges have also reduced total assets.
  Long-term debt including convertible debentures has grown since 2009 reflecting the financing related to the capital programs to develop oil properties.
  ADDITIONAL INFORMATION
  Additional information regarding Anderson and its business and operation, including its most recently filed annual information form is available on the Company’s profile on SEDAR at www.sedar.com.  This information is also available on the Company’s website at www.andersonenergy.ca.
  ANDERSON ENERGY
28
 FORWARD-LOOKING STATEMENTS
  Certain statements in this management’s discussion and analysis including, without limitation, management’s assessment of future plans and operations; benefits and valuation of the development prospects described herein; number of locations in drilling inventory and wells to be drilled; timing and location of drilling and tie-in of wells and the costs thereof; productive capacity of the wells; timing of and construction of facilities; expected production rates; percentage of production from oil and natural gas liquids; dates of commencement of production; amount of capital expenditures and the timing and method of financing thereof; value of undeveloped land; extent of reserves additions; ability to attain cost savings; drilling program success; impact of changes in commodity prices on operating results; estimates of future revenues, costs, netbacks, funds from operations and debt levels; potential results of the strategic alternative review process and enhancement of shareholder value, disclosure intentions with respect to the strategic alternative review process; commodity price outlook and general economic outlook 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 reserves estimates; environmental risks; competition from other producers; inability to retain drilling rigs and other services; adequate weather to conduct operations; sufficiency of budgeted capital, operating and other costs to carry out planned activities; 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; changes to government regulation; 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 assumptions and forward-looking statements.  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 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 management’s discussion and analysis are made as at the date of this management’s discussion and analysis 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.
  CONVERSION
  Disclosure provided herein in respect of barrels of oil equivalent (BOE) may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
 Abbreviations used
  bbl
barrel
AECO
intra-Alberta Nova inventory transfer pricebbls
barrels
CBM
coal bed methaneBOE
barrel of oil equivalent
GJ
gigajouleBOED
barrels of oil equivalent per day
Mcf
thousand cubic feetbpd
barrels per day
Mcfd
thousand cubic feet per dayMstb
thousand stock tank barrels
Mcfe
thousand cubic feet equivalentMBOE
thousand barrels of oil equivalent
MMcf
million cubic feetMMBOE
million barrels of oil equivalent
MMcfd
million cubic feet per dayMbbls
thousand barrels
Bcf
billion cubic feetNGL
natural gas liquids
MMBTU
million British thermal unitsWTI
West Texas Intermediate
 29
2011 MANAGEMENT’S DISCUSSION & ANALYSIS