Anderson Energy (AXLFF) 40FR12B Initial registration of securities (Canada)

Exhibit 99.4

Management’s Discussion and Analysis

and

Consolidated Financial Statements

DECEMBER 31, 2009 AND 2008

Management’s Discussion and Analysis

DECEMBER 31, 2009 AND 2008

1 2009 MANAGEMENT’S DISCUSSION AND ANALYSIS

Management’s Discussion and Analysis

FOR THE YEARS ENDED DECEMBER 31, 2009 AND 2008

The following discussion and analysis of financial results should be read in conjunction with the audited consolidated financial statements of Anderson Energy Ltd. (“Anderson Energy” or the “Company”) for the years ended December 31, 2009 and 2008 and is based on information available as of March 19, 2010.

The following information is based on financial statements prepared by management in accordance with Canadian generally accepted accounting principles (“GAAP”). Production and reserves numbers are stated before deducting Crown or lessor royalties.

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 asset retirement 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 less royalties and operating 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 Canadian GAAP and therefore are referred to as non-GAAP measures.

All references to dollar values are to Canadian dollars unless otherwise stated.

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, 2009, funds from operations were $31.3 million ($0.25 per share) down 61% from 2008 due to significant declines in commodity prices. The effect of lower revenues was partially offset by significant reductions in royalties and operating expenses. Sales volumes averaged 7,603 BOED, 2% lower than the previous year due to the cuts in capital spending made in response to lower prices.

Capital expenditures were $33.6 million, net of drilling incentive credits of $6.0 million, and included the drilling of 118 gross (89.5 net) wells with a success rate of 92%. In May 2009, the Company completed a bought deal equity financing for net proceeds after commission and expenses of $56.5 million. Net proceeds were used to pay down bank indebtedness and finance a significant farm-in drilling program in its core Edmonton Sands shallow gas play. The Company drilled 106 wells under the farm-in in the fourth quarter of 2009 and achieved a finding, development and acquisition cost, net of the change in future development capital and net of revisions and drilling incentive credits of $7.97 per BOE on a proved plus probable basis for the year.

ANDERSON ENERGY     2

Debt, net of working capital deficiency was $72.5 million at December 31, 2009. Total bank lines are currently $100 million. In February 2010, the Company completed a bought deal share financing for net proceeds after commission and expenses of $29.8 million. Proceeds were initially used to pay down bank debt. The availability created in the credit facilities was used to increase the Company’s 2010 capital budget from $75 million to $87 million in order to expand its Cardium horizontal light oil drilling program.

Revenue and Production. Gas sales comprised 84% of Anderson Energy’s total oil and gas sales volumes for the year ended December 31, 2009, consistent with the prior year.

Gas sales volumes for the year ended December 31, 2009 decreased marginally to an average of 38.5 MMcfd from 39.0 MMcfd last year. 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 36.7 MMcfd (33.9 MMcfd during 2008). Due to low commodity prices and the need to conserve funds for the farm-in drilling program in the fourth quarter, new wells were not drilled and brought on production during the year to offset natural production decline. The Company also chose to shut-in higher cost wells for a significant portion of the year due to the low prices. Property dispositions in the fourth quarter of 2008 also affected volumes compared to the prior year.

Gas sales volumes averaged 34.9 MMcfd in the fourth quarter of 2009. This compares to 36.3 MMcfd in the third quarter of 2009 and 38.1 MMcfd in the fourth quarter of 2008. Production from the wells drilled in the fourth quarter of 2009 will not have a significant impact on sales volumes until the second quarter of 2010.

Oil sales for the year ended December 31, 2009 averaged 395 bpd compared to 487 bpd for the year ended December 31, 2008. Oil production averaged 351 bpd in the fourth quarter of 2009 compared to 376 bpd in the third quarter of 2009 and 491 bpd in the fourth quarter of 2008. The majority of the Company’s current oil production is from Central and Eastern Alberta. The decrease in 2009 is due to natural production decline, property sales in 2008 and workovers being deferred due to the low price environment. New capital initiatives for oil did not commence until the first quarter of 2010.

Natural gas liquids sales for the year ended December 31, 2009 averaged 794 bpd compared to 806 bpd for the year ended December 31, 2008. Natural gas liquids sales averaged 906 bpd in the fourth quarter of 2009 compared to 637 bpd in the third quarter of 2009 and 850 bpd in the fourth quarter of 2008. Natural gas liquids volumes were affected by reductions in ethane sales due to the deep cut facility not operating at Bigoray for approximately half of the year. This facility resumed operations in the fourth quarter of 2009.

The following tables outline production revenue, volumes and average sales prices for the years and for the fourth quarters ended December 31, 2009 and 2008.

OIL AND NATURAL GAS REVENUE

	Three months ended Dec. 31				Year ended Dec. 31
(thousands of dollars)	2009		2008		2009		2008
Natural gas	$	13,754	$	23,706	$	55,426	$	117,237
Loss on fixed price natural gas contracts		—		—		—		(1,341	)
Oil		2,247		2,511		8,540		16,441
NGL		3,973		3,469		12,375		21,170
Royalty and other		465		416		652		2,738
Total	$	20,439	$	30,102	$	76,993	$	156,245

3 2009 MANAGEMENT’S DISCUSSION AND ANALYSIS

PRODUCTION

	Three months ended Dec. 31				Year ended Dec. 31
	2009		2008		2009		2008
Natural gas (Mcfd)		34,938		38,090		38,489		38,968
Oil (bpd)		351		491		395		487
NGL (bpd)		906		850		794		806
Total (BOED)		7,080		7,689		7,603		7,787

PRICES

	Three months ended Dec. 31				Year ended Dec. 31
	2009		2008		2009		2008
Natural gas ($/Mcf)	$	4.28	$	6.76	$	3.95	$	8.13
Oil ($/bbl)		69.60		55.63		59.26		92.27
NGL ($/bbl)		47.67		44.37		42.73		71.78
Total ($/BOE)*	$	31.38	$	42.55	$	27.74	$	54.82

^*  Includes royalty and other income classified with oil and gas sales.

Anderson Energy’s average gas sales price was $3.95 per Mcf for the year ended December 31, 2009 compared to $8.13 per Mcf for the year ended December 31, 2008. For the three months ended December 31, 2009, the gas sales price was $4.28 per Mcf. This compares to $2.81 per Mcf realized in the third quarter of 2009 and $6.76 per Mcf realized in the fourth quarter of 2008. Gas prices were significantly affected by increased supply and lower industrial consumption of natural gas in the United States. Prices improved in the last quarter of 2009, but volatility in the marketplace continues. The natural gas price in 2008 includes a hedging loss of $1.3 million. The 2008 gas price before the hedging loss was $8.22 per Mcf.

Historically, Anderson Energy has sold most of its gas at Alberta spot market prices. From November 2008 to October 2009, the Company was selling approximately 30% of its production at the average monthly index price, and the balance at the average daily index price. The Company is currently selling all of its unhedged gas production at the average daily index price. The Company has classified all transportation costs as an offset to gas sales revenue as title transfers prior to transport on the applicable sales pipelines and transportation is being held by and charged by the gas purchasers. The Company has arranged firm service transportation agreements covering approximately 25 MMcfd of natural gas sales for various terms ranging from one to ten years.

Fixed Price Contracts. In December 2009, 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 20,000 GJ per day of natural gas for each of January, February and March 2010 at an average AECO price of $5.41 per GJ. As of December 31, 2009, there were no gains or losses recognized in association with these physical contracts.

In January 2008, the Company had physical contracts to sell 25,000 GJ per day of natural gas for February and March 2008 at an average AECO price of $6.89 per GJ. The Company realized a $1.3 million loss on this risk management contract.

ANDERSON ENERGY     4

Royalties. Royalties were 11% of revenue for the year ended December 31, 2009 compared to 22% of revenue for the year ended December 31, 2008. Royalties were 9% of revenue in the fourth quarter of 2009 compared to 6% of revenue in the third quarter of 2009 and 22% of revenue in the fourth quarter of 2008. During the year, the Company received $2.8 million more in gas cost allowance adjustments than had previously been accrued relating to 2008 and prior periods as a result of changes to the corporate average effective royalty rate and net additions to eligible costs. Royalty rates would have been 14% for the year and 10% for the fourth quarter without these adjustments. On January 1, 2009, the Alberta government’s New Royalty Framework came into effect. While royalties increased in some areas, overall, the changes reduced royalties due to the Company’s focus on shallow gas, lower productivity wells and due to lower natural gas prices. In addition, when prices and corresponding revenues are lower, gas cost allowance becomes more significant to the overall royalty rate.

On March 3, 2009, new royalty initiatives were announced by the Alberta government that focused on future drilling activity. Two measures were announced. The first was a $200 per meter drilling credit based on drilling activity from April 1, 2009 to March 31, 2011. The credit is capped at 50% of Crown royalties payable from April 1, 2009 to March 31, 2011. These drilling credits are accounted for as reductions in the associated drilling costs. The second measure announced was that new wells tied in for production on Crown lands from the period April 1, 2009 to March 31, 2011 would pay a reduced Crown royalty rate of 5% for the first year on up to 500 MMcf of gas production or up to 50 Mstb of oil production. All of these changes have benefited the Company. On March 11, 2010, the Alberta government announced that the 5% Crown royalty rate for new wells tied in for production on Crown lands would become a permanent measure. The Alberta government also announced reducing the maximum royalty paid on oil from 50% to 40% and on natural gas from 50% to 36%. The new royalty curves are to be made available on May 31, 2010. At this time, the Company anticipates that the royalty curve changes will benefit production from its new Cardium oil drilling program.

	Three months ended Dec. 31						Year ended Dec. 31
	2009			2008			2009			2008
Royalties (%)		9	%		22	%		11	%		22	%
Royalties ($/BOE)	$	2.66		$	9.46		$	2.97		$	11.94

Operating Expenses. Operating expenses were $9.70 per BOE for the year ended December 31, 2009 compared to $11.27 per BOE for the year ended December 31, 2008. The Company completed three large plant construction projects in mid 2008 at Willesden Green, Wilson Creek and Buck Lake that helped to reduce reliance on third party processing and lower operating costs per BOE. Approximately 200 BOED of production was shut-in on marginal properties during 2009 due to lower prices which also contributed to the reduction in operating expenses per BOE. The Company has also been negotiating with service providers to reduce costs. Operating expenses were $10.49 per BOE in the fourth quarter of 2009 compared to $7.72 per BOE in the third quarter of 2009 and $11.51 per BOE in the fourth quarter of 2008. The $7.72 per BOE reported in the third quarter of 2009 reflects the reversal of some prior quarter accruals where the effect of cost reductions had previously been underestimated. Operating expenses in the third quarter would have been $9.68 per BOE without these adjustments, closer to the average for the year. The Company also incurred additional costs in the fourth quarter of 2009 for workovers and compressor maintenance as well as the costs associated with the resumption of previously shut-in higher operating cost production.

5 2009 MANAGEMENT’S DISCUSSION AND ANALYSIS

OPERATING NETBACK

	Three months ended Dec. 31						Year ended Dec. 31
(thousands of dollars)	2009			2008			2009			2008
Revenue	$	20,439		$	30,102		$	76,993		$	156,245
Royalties		(1,731	)		(6,694	)		(8,253	)		(34,038	)
Operating expenses		(6,831	)		(8,140	)		(26,906	)		(32,110	)
	$	11,877		$	15,268		$	41,834		$	90,097
Sales (MBOE)		651.4			707.4			2,775.2			2,850.1
Per BOE
Revenue	$	31.38		$	42.55		$	27.74		$	54.82
Royalties		(2.66	)		(9.46	)		(2.97	)		(11.94	)
Operating expenses		(10.49	)		(11.51	)		(9.70	)		(11.27	)
	$	18.23		$	21.58		$	15.07		$	31.61

General and Administrative Expenses. General and administrative expenses were $7.0 million or $2.52 per BOE for the year ended December 31, 2009 compared to $6.4 million or $2.24 per BOE for the year ended December 31, 2008. General and administrative expenses were $2.94 per BOE in the fourth quarter of 2009 compared to $2.18 per BOE in the third quarter of 2009 and $1.40 per BOE in the fourth quarter of 2008. General and administrative costs increased in 2009 as a result of lower overhead recoveries due to lower capital spending in 2009. A bonus accrual was also included in the fourth quarter of 2009 in recognition of the success of the winter drilling program. In 2009, fourth quarter costs were higher than the previous quarter and the fourth quarter of last year due to unusual adjustments in those comparative quarters. Prior period overhead adjustments were recorded in the third quarter of 2009 and a bonus accrual was reversed in the fourth quarter of 2008 due to market conditions. On a BOE basis, G&A costs were also affected by lower production volumes.

	Three months ended Dec. 31						Year ended Dec. 31
(thousands of dollars)	2009			2008			2009			2008
General and administrative (gross)	$	3,276		$	2,324		$	12,284		$	11,986
Overhead recoveries		(437	)		(720	)		(1,721	)		(2,114	)
Capitalized		(924	)		(612	)		(3,565	)		(3,495	)
General and administrative (net)	$	1,915		$	992		$	6,998		$	6,377
General and administrative ($/BOE)	$	2.94		$	1.40		$	2.52		$	2.24
% Capitalized		28	%		26	%		29	%		29	%

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 $2.1 million in 2009 ($1.1 million net of amounts capitalized) versus $2.0 million ($1.1 million net of amounts capitalized) in 2008. The minimal increase is a result of additional stock options being granted to new and existing staff members, offset partially by options reaching their full vesting terms.

Interest Expense. Interest expense was $3.7 million for the year ended December 31, 2009 compared to $4.5 million in 2008. In the fourth quarter of 2009, interest expense was $0.8 million compared to $0.8 million in the third quarter of 2009 and $1.1 million in the fourth quarter of 2008. The decrease in interest expense is due to the lower debt levels and lower interest rates. Bank loans were $62 million at December 31, 2009 as compared to $85 million at December 31, 2008. The average effective interest rate on outstanding bank loans was 4.2%

ANDERSON ENERGY     6

in 2009 compared to 5.0% in 2008. Lower prime and bankers acceptance interest rates on borrowings have been offset in part by higher margins applied to the banking facilities.

Depletion and Depreciation. Depletion and depreciation was $28.33 per BOE for the year ended December 31, 2009 compared to $22.26 per BOE in 2008. Depletion and depreciation was $26.39 per BOE in the fourth quarter of 2009 compared to $29.09 per BOE in the third quarter of 2009 and $28.46 per BOE in the fourth quarter of 2008. Depletion and depreciation expense is calculated based on proved reserves only. Fourth quarter depletion and depreciation is calculated using the new reserves evaluation and incorporates an increase in total proved reserves. In addition, future development costs decreased in the new reserve report, reflecting measures taken in the 2009/2010 winter drilling program to reduce drilling and completion costs.

Asset Retirement Obligation. As a result of new drilling, the Company recorded $1.3 million in additional asset retirement obligations in the fourth quarter of 2009 and $1.5 million for the year ended December 31, 2009. Revisions to estimated reclamation costs and timelines added $0.7 million to the obligation in the year. Accretion expense was $2.3 million for 2009 compared with $1.9 million for 2008. Accretion expense was included in depletion and depreciation expense and increased due to the higher obligations.

Income Taxes. Anderson Energy is not currently taxable. The Company does not anticipate paying current income tax in 2010. The estimated tax pool balances at December 31, 2009 are summarized below. Tax pool classifications are estimates as some new wells have not yet had their status as exploratory or development confirmed. The balances below have been reduced for the effect of income recorded in 2009 that will not be taxed until 2010.

Canadian Exploration Expenses (CEE)	$	62 million
Canadian Development Expenses (CDE)		95 million
Undepreciated Capital Cost (UCC)		95 million
Canadian Oil and Gas Property Expenses (COGPE)		16 million
Non-Capital Losses and Other		41 million
Total	$	309 million

Funds from Operations. Funds from operations decreased by 61% to $31.3 million in 2009 compared to $79.3 million in 2008. On a per share basis, funds from operations were $0.25 per share in 2009 compared to $0.91 per share in 2008. For the three months ended December 31, 2009, funds from operations were $9.2 million or $0.06 per share, an increase of 38% over the previous quarter of $6.6 million or $0.04 per share, and a decrease of 31% from the fourth quarter of 2008 of $13.2 million or $0.15 per share. The decrease in funds from operations in 2009 is a result of lower commodity prices in 2009, with the low for natural gas prices coming in the third quarter of the year. This was partially offset by lower royalties and lower operating expenses. Cash from operating activities decreased year over year for similar reasons. Commodity prices, particularly for natural gas, remain volatile in 2010.

	Three months ended Dec. 31				Year ended Dec. 31
(thousands of dollars)	2009		2008		2009		2008
Cash from operating activities	$	5,361	$	11,261	$	23,820	$	82,688
Changes in non-cash working capital		3,246		1,464		5,956		(4,492	)
Asset retirement obligations		544		479		1,482		1,132
Funds from operations	$	9,151	$	13,204	$	31,258	$	79,328

7 2009 MANAGEMENT’S DISCUSSION AND ANALYSIS

Earnings. The Company reported a $6.5 million loss in the fourth quarter of 2009 and a $36.5 million loss for the year ended December 31, 2009. In 2008, the Company determined that the carrying amount of goodwill exceeded its fair value and a non-cash impairment loss of $35.4 million was recognized. Earnings before this charge were $8.5 million in 2008. The loss in 2009 resulted from low commodity prices and higher depletion and depreciation charges partially offset by a reduction in royalties and operating expenses and a future income tax recovery.

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:

SENSITIVITIES

	Funds from Operations				Earnings
(thousands of dollars)	Millions		Per Share		Millions		Per Share
$0.50/Mcf in price of natural gas	$	7.2	$	0.06	$	5.1	$	0.04
US $5.00/bbl in the WTI crude price	$	1.8	$	0.01	$	1.3	$	0.01
US $0.01 in the US/Cdn exchange rate	$	0.7	$	0.01	$	0.5	$	0.00
1% in short-term interest rate	$	0.8	$	0.01	$	0.5	$	0.00

This sensitivity analysis was calculated by applying different pricing, interest rate and exchange rate assumptions to the 2009 actual results related to production, prices, royalty rates, operating costs and capital spending.

CAPITAL EXPENDITURES

The Company spent $11.3 million in capital expenditures, net of dispositions and anticipated drilling incentive credits, in the fourth quarter and $33.6 million for the year ended December 31, 2009. The breakdown of expenditures is shown below:

	Three months ended Dec. 31						Year ended Dec. 31
(thousands of dollars)	2009			2008			2009			2008
Land, geological and geophysical costs	$	(15	)		167		$	173		$	1,211
Acquisitions, net of dispositions		—			(17,186	)		(54	)		(18,043	)
Drilling, completion and recompletion		15,492			25,713			23,952			68,075
Drilling incentive credits		(6,000	)		—			(6,000	)		—
Facilities and well equipment		3,642			17,958			11,349			51,174
Capitalized G&A		924			611			3,565			3,494
Total finding, development & acquisition expenditures		14,043			27,263			32,985			105,911
Change in compressor and other equipment inventory		(2,736	)		(101	)		542			295
Office equipment and furniture		5			308			31			463
Total capital expenditures		11,312			27,470			33,558			106,669
Non-cash asset retirement obligations and capitalized stock-based compensation		2,003			2,800			3,220			6,421
Total cash and non-cash capital additions	$	13,315			30,270		$	36,778		$	113,090

ANDERSON ENERGY     8

Drilling statistics are shown below:

	Three months ended Dec. 31												Year ended Dec. 31
	2009						2008						2009						2008
	Gross			Net			Gross			Net			Gross			Net			Gross			Net
Gas		98			73.6			86			59.5			109			81.9			196			134.7
Oil		—			—			—			—			—			—			6			2.9
Dry		9			7.6			5			2.5			9			7.6			15			10.6
Total		107			81.2			91			62.0			118			89.5			217			148.2
Success rate (%)		92	%		91	%		95	%		96	%		92	%		92	%		93	%		93	%

Capital expenditures included $16.5 million spent on wells drilled under the farm-in agreement and $2.8 on pre-expenditures for equipping and tie-in related to this program. An additional $2.4 million was spent on fit-for purpose processing facilities expected to be commissioned in 2010. Other significant expenditures in the year relate to completion of the prior winter’s Edmonton Sands drilling program in the first quarter of 2009 and the tie-in of several standing gas wells in the third and fourth quarters of 2009.

The Company drilled 118 gross (89.5 net) Edmonton Sands wells in 2009 of which 107 gross (81.2 net) wells were drilled in the fourth quarter. Well tie-ins are proceeding in the field with most of the new production coming on-stream in late March or April 2010. Some well tie-ins have been deferred until after spring breakup as the flush production from new wells tied-in in the first quarter will initially be enough to fill available plant capacity.

The Company accrued $6.0 million for drilling incentive credits in 2009. Drilling credits earned are capped at 50% of crown royalties paid between April 1, 2009 and March 31, 2011 and the Company estimates that it will earn more drilling credits than it will be able to claim. These credits were earned through drilling in the fourth quarter of 2009 but are expected to be paid out between 2009 and 2011 as crown royalties are paid. The estimate is highly dependent on commodity prices, production levels, crown royalty rates and gas cost allowance earned over this period. To the extent that crown royalties paid are lower or higher, drilling credits will be lower or higher as well. In March 2010, the Company received $2.6 million in proceeds on the sale of some of its surplus credits.

CEILING TEST/GOODWILL IMPAIRMENT

At December 31, 2009, the ceiling test resulted in the discounted cash flows from proved plus probable reserves being in excess of the carrying value of the underlying petroleum and natural gas assets and as such no ceiling test write-down was required. See “Reserves – Summary of Pricing and Inflation Rate Assumptions” for the prices used in the 2009 ceiling test.

At December 31, 2008, the Company wrote off $35.4 million of goodwill recorded as a result of acquisitions made in 2005 and 2008 due to a decline in the Company’s fair value as represented by its market capitalization at that time. There was no impairment to the carrying amount of the Company’s petroleum and natural gas assets and no write down of petroleum and natural gas assets has been recorded in any period.

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, 2009. 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, 2009 (“AIF”) as the Company’s NI 51-101 annual required filings.

9 2009 MANAGEMENT’S DISCUSSION AND ANALYSIS

SUMMARY OF GROSS OIL AND GAS RESERVES

As at December 31, 2009

	Natural Gas (Bcf)(1)		Oil (Mbbls) (1)		Natural Gas Liquids (Mbbls)		Total BOE (MBOE)
Proved developed producing		45,562		542		1,087		9,223
Proved developed non-producing		15,466		52		82		2,712
Proved undeveloped		66,937		219		305		11,680
Total proved		127,965		813		1,474		23,615
Probable		59,030		647		796		11,281
Total proved plus probable		186,995		1,460		2,270		34,896

Notes: (1) 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.

NET PRESENT VALUE BEFORE INCOME TAXES

As at December 31, 2009

(GLJ December 31, 2009 Price Forecast, Escalated Prices)

(thousands of dollars)	0%		5%		10%		15%		20%
Proved developed producing		218,089		181,508		156,423		138,174		124,293
Proved developed non-producing		50,755		43,065		37,265		32,764		29,183
Proved undeveloped		110,307		73,429		48,827		32,002		20,266
Total proved		379,151		298,002		242,515		202,940		173,742
Probable		255,607		170,723		121,575		90,761		70,270
Total proved plus probable		634,758		468,725		364,090		293,701		244,012

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, 2009

GLJ Forecast Prices and Costs

	Oil				Natural Gas		Edmonton Liquids Prices
Year	WTI Cushing ($US/bbl)		Light, Sweet Crude Edmonton ($Cdn/bbl)		AECO Gas Price ($Cdn/Mcf)		Propane ($Cdn/bbl)		Butane ($Cdn/bbl)		Pentanes Plus ($Cdn/bbl)		Inflation Rate %		Exchange rate (US$/Cdn)
2010		80.00		83.26		5.96		52.46		64.11		84.93		2.0		0.95
2011		83.00		86.42		6.79		54.45		66.54		88.15		2.0		0.95
2012		86.00		89.58		6.89		56.43		68.98		91.37		2.0		0.95
2013		89.00		92.74		6.95		58.42		71.41		94.59		2.0		0.95
2014		92.00		95.90		7.05		60.42		73.84		97.82		2.0		0.95
2015		93.84		97.84		7.16		61.64		75.33		99.79		2.0		0.95
2016		95.72		99.81		7.42		62.88		76.85		101.81		2.0		0.95
2017		97.64		101.83		7.95		64.15		78.41		103.86		2.0		0.95
2018		99.59		103.88		8.52		65.45		79.99		105.96		2.0		0.95
2019		101.58		105.98		8.69		66.77		81.60		108.10		2.0		0.95
Thereafter 2%

Total future development costs included in the reserves evaluation were $197.6 million for total proved reserves and $260.1 million for total 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 2009 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

	Natural Gas (Bcf) (1)									Oil & Natural Gas Liquids (Mbbls)
	Proved			Probable			Total			Proved			Probable		Total
Opening balance December 31, 2008		125.4			47.5			172.9			2,498			980		3,478
Extensions and improved recovery		17.9			8.1			26.0			288			369		657
Net acquisitions (2)		16.6			5.7			22.3			47			15		62
Revisions		(17.9	)		(2.3	)		(20.2	)		(112	)		79		(33	)
Dispositions		—			—			—			—			—		—
Production		(14.0	)		—			(14.0	)		(434	)		—		(434	)
Closing balance December 31, 2009		128.0			59.0			187.0			2,287			1,443		3,730

Note: (1)    Closing balance for natural gas includes 5.5 Bcf of proved and 3.0 Bcf of probable Coal Bed Methane reserves.

(2) There were no property acquisitions during the year. The acquisition additions in this continuity table relate to the reserve additions associated with the Edmonton Sands farm-in.

The Company’s reserves life indices are 9.1 years total proved and 13.5 years total proved plus probable, based on 2009 fourth quarter production. Reserves additions, net of revisions, were 3.0 MMBOE total proved and 5.4 MMBOE total proved plus probable. The Company replaced 194% of its production with new proved plus probable reserves additions, net of revisions, in 2009. A large portion of the negative revisions were due to a significant reduction in GLJ’s price deck for natural gas.

FINDING, DEVELOPMENT AND ACQUISITION COSTS

Year Ended December 31, 2009

(in thousands of dollars)	Proved			Proved plus Probable
Finding, development & acquisition expenditures	$	32,985		$	32,985
Change in future development costs		(7,131	)		12,467
Sale of surplus drilling incentive credits		(2,613	)		(2,613	)
Total costs	$	23,241		$	42,839
Reserve additions, net of revisions (MBOE)		2,996			5,378
2009 finding, development & acquisition costs ($/BOE)	$	7.76		$	7.97

The Company’s FD&A costs in 2009 were $7.76 per BOE on a proved basis and $7.97 per BOE on a proved plus probable basis. Reserve additions related to the Edmonton Sands farm-in have been classified as acquisitions by GLJ in the reserve report. There were no property acquisitions in the year and dispositions were negligible, so a separate calculation of finding and development costs excluding acquisitions and dispositions has not been presented. FD&A costs in 2008 were negative due to downward revisions to reserves. The three year average FD&A costs were $29.53 total proved and $25.37 proved plus probable, including the effects of these revisions as well as large central facility expenditures incurred in 2008. 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 December 31, 2009, there were 150.5 million common shares outstanding and 10.3 million stock options outstanding. During 2009, no shares were issued under the employee stock option plan.

11 2009 MANAGEMENT’S DISCUSSION AND ANALYSIS

SHARE PRICE ON TSX

	2009		2008
High	$	1.48	$	5.45
Low	$	0.65	$	0.87
Close	$	1.16	$	1.15
Volume		125,408,442		76,653,637
Shares outstanding at December 31		150,500,401		87,300,401
Market capitalization at December 31	$	174,580,465	$	100,395,461

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 21.4 million common shares traded on these alternative exchanges in the year. Including these exchanges, an average of 584,790 common shares traded per day in 2009, representing a turnover ratio of 117%.

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 TRANSACTION

On May 28 2009, the Company issued 4,992,034 common shares to management and directors and 3,377,966 common shares to family of management and directors of the Company at a price of $0.95 per share for total gross proceeds of $8.0 million as part of a $60.0 million bought deal offering of common shares.

LIQUIDITY AND CAPITAL RESOURCES

At December 31, 2009, the Company had outstanding bank loans of $62.4 million and a working capital deficiency of $10.1 million. The working capital deficiency is due to accruals associated with the capital program in the last quarter of the year.

The Company’s current capital budget for 2010 is $87 million with $47 million budgeted for the first quarter of 2010, in order to fulfill its farm-in commitments and commence its horizontal multistage frac drilling. In February 2010, the Company completed a common share equity issue for net proceeds of $29.8 million after commission and expenses. The financing allowed the Company to expand its Cardium horizontal light oil drilling program in 2010.

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, 2009, the Company has a $90 million extendible revolving term credit facility and a $10 million working capital credit facility with a syndicate of Canadian banks. Anderson Energy will prudently use its bank loan facilities to finance its operations as required. 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 2009. 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 13, 2010. As a result of the current economic climate and changes to global credit markets, the Company has incurred increased margins and fees. The Company will continue to fund its ongoing operations from a combination of cash flow, debt, asset dispositions and equity financing as needed.

ANDERSON ENERGY     12

CONTRACTUAL OBLIGATIONS

The Company enters into various contractual obligations in the course of conducting its operations. These obligations include:

• Loan agreements – The reserves-based credit facilities in the amount of $100 million have a revolving period ending July 13, 2010 extendible at the option of the lenders, followed by a term period with three equal quarterly principal repayments commencing 180 days from the term date.

• Lease for office space – This lease expires on November 30, 2012. Future minimum lease payments are expected to be $1.8 million per year in 2010 and 2011, and $1.6 million in 2012.

• Firm service transportation commitments – The Company has entered into firm service transportation agreements for approximately 25 million cubic feet per day of gas sales for various terms expiring between 2010 and 2020. Based on rate schedules announced to date, the payments in each of the next five years and thereafter are estimated to be $1.6 million in 2010, $1.5 million in 2011, $1.1 million in 2012, $0.8 million in 2013, $0.6 million in 2014 and $1.2 million thereafter.

• Farm-in – On January 30, 2009, the Company announced a farm-in agreement with a large international oil and gas company on lands near its existing core operations. Under the farm-in agreement, the Company has access to 388 gross (205 net) sections of land. During the commitment phase of the transaction, the Company is committed to drill, complete and equip 200 wells to earn an interest in up to 120 sections. The Company drilled 106 wells under the commitment to December 31, 2009 and a further 20 wells in the first quarter of 2010. The Company is obligated to complete the drilling of the wells on or before December 31, 2010. The commitment is subject to various guarantees. The Company estimates that it will spend approximately $50 million in 2010 on the farm-in to drill, complete and equip farm-in wells, which has been included in the $87 million capital budget for 2010.

These obligations are described further in other parts of this discussion and analysis and in notes 6 and 14 to the consolidated financial statements.

CRITICAL ACCOUNTING ESTIMATES

The Company’s significant accounting policies are disclosed in note 1 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.

Proved Oil and Gas Reserves. Proved oil and gas reserves, as defined by the Canadian Securities Administrators in NI 51-101 with reference to the Canadian Oil and Gas Evaluation Handbook, are those reserves that can be estimated with a high degree of certainty to be recoverable. 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.

13 2009 MANAGEMENT’S DISCUSSION AND ANALYSIS

Independent reserves evaluators have prepared the Company’s oil and gas reserves estimate. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes, reservoir performance, methodology of booking undeveloped reserves, or a change in the Company’s development plans. The effect of changes in proved oil and gas reserves on the financial results and financial position of the Company is described below under the heading “Full Cost Accounting” and “Full Cost Accounting Ceiling Test”.

Full Cost Accounting. The Company follows the full cost method of accounting for petroleum and natural gas properties, whereby all costs of exploring for and developing petroleum and natural gas properties and related reserves are capitalized. The capitalized costs are depleted and depreciated using the unit-of-production method based on estimated proved reserves. Reserves estimates can have a significant impact on earnings, as they are a key component in the calculation of depletion and depreciation. Downward revisions in reserves estimates or upward revisions in future development cost estimates could result in a higher depletion and depreciation charge to earnings. In addition, if net capitalized costs are determined to be in excess of the calculated ceiling, which is based largely on reserves estimates (see “Full Cost Accounting Ceiling Test”), the excess must be written off as an expense charged against earnings. In the event of property dispositions, proceeds are normally deducted from the full cost pool without recognition of gain or loss unless there is a change in the depletion rate of 20% or greater.

Unproved Properties. Certain costs related to unproved properties are excluded from costs subject to depletion until proved reserves have been determined or their value is impaired. These properties are reviewed quarterly and any impairment is transferred to the costs being depleted. The costs relating to unproved properties are also excluded from the book value subject to the ceiling test measurement.

Full Cost Accounting Ceiling Test. Petroleum and natural gas assets are evaluated in each reporting period to determine that the carrying amount in a cost centre is recoverable and does not exceed the fair value of the properties in the cost centre.

Impairment is indicated if the carrying value of the oil and gas cost centre is not recoverable by the future undiscounted cash flows. If impairment is indicated, the amount by which the carrying value exceeds the estimated fair value of the oil and gas assets is charged to earnings. The ceiling test is based on estimates of reserves, production rates, petroleum and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material.

Asset Retirement Obligations. The Company is required to provide 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 & 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, review of potential abandonment methods and salvage/usage of tangible equipment.

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

ANDERSON ENERGY     14

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.

Goodwill. The process of accounting for the purchase of a company results in recognizing the fair value of the acquired company’s assets on the balance sheet of the acquiring company. Any excess of the purchase price over fair value is recorded as goodwill. Since goodwill results from the culmination of a process that is inherently imprecise, the determination of goodwill is also imprecise. Goodwill is assessed periodically for impairment. Impairment is indicated if the fair value of the Company falls below the book value of its equity.

CHANGES IN ACCOUNTING POLICIES

In February 2008, the CICA issued Section 3064, Goodwill and Intangible Assets. Effective for fiscal years beginning on or after October 1, 2008, this section provides guidance on the recognition, measurement, presentation and disclosure for goodwill and intangible assets, other than the initial recognition of goodwill or intangible assets acquired in a business combination. The Company adopted the new standard for the year ended December 31, 2009. Adoption of the standard did not have any impact on the Company’s results of operations or financial position.

In May 2009, the Canadian Institute of Chartered Accountants amended Section 3862, Financial Instruments – Disclosures, to include additional disclosure requirements about fair value measurement for financial instruments and liquidity risk disclosures. These amendments require a three level hierarchy that reflects the significance of the inputs used in making the fair value measurements. Fair values of assets and liabilities included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Assets and liabilities in Level 2 include valuations using inputs other than quoted prices for which all significant outputs are observable, either directly or indirectly. Level 3 valuations are based on inputs that are unobservable and significant to the overall fair value measurement. These disclosures are included in note 12 of the consolidated financial statements.

FUTURE ACCOUNTING POLICIES

In January 2009, the CICA issued Section 1582, Business Combinations. This section is effective January 1, 2011 and applies prospectively to business combinations for which the acquisition date is on or after the first annual reporting period beginning on or after January 1, 2011 for the Company. Early adoption is permitted. This section replaces Section 1581, Business Combinations and harmonizes the Canadian standards with International Financial Reporting Standards (“IFRS”).

In 2009, the CICA issued Section 1601, Consolidated Financial Statements and Section 1602, Non-controlling Interests which replace the existing guidance under Section 1600, Consolidated Financial Statements. These standards provide guidance for preparing consolidated financial statements and for accounting for a non-controlling interest in a subsidiary. These standards are effective for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2011, with early adoption permitted.

INTERNATIONAL FINANCIAL REPORTING STANDARDS

In February 2008, the CICA Accounting Standards Board (“AcSB”) confirmed the changeover to IFRS from Canadian Generally Accepted Accounting Principles (“GAAP”) will be required for publicly accountable enterprises for interim and annual financial statements effective for fiscal years beginning on or after January 1, 2011, including comparatives for 2010.

15 2009 MANAGEMENT’S DISCUSSION AND ANALYSIS

In response, the Company has completed its high-level IFRS changeover plan and established a preliminary timeline for the execution and completion of the conversion project. The changeover plan was determined following a preliminary assessment of the differences between Canadian GAAP and IFRS and the potential effects of IFRS to accounting and reporting processes, information systems, business processes and external disclosures. This assessment has provided insight into what are anticipated to be the most significant areas of difference applicable to the Company.

During the next phase of the project, the Company is performing an in-depth review of the significant areas of difference identified during the preliminary assessment, in order to identify all specific Canadian GAAP and IFRS differences and select ongoing IFRS policies. Key areas addressed will also be reviewed to determine any information technology issues, the impact on internal controls over financial reporting and the impact on business activities including the effect, if any, on covenants and compensation arrangements. External advisors have been retained and will assist management with the project on an as needed basis to ensure IFRS readiness by January 1, 2011.

Below is a summary of the Company’s preliminary views of the key areas where changes in accounting policies are expected that may impact the Company’s consolidated financial statements. The list and comments below should not be regarded as a complete list of changes that will result from the transition to IFRS. It is intended to highlight those areas the Company believes to be most significant; however, analysis of changes is still in progress and not all decisions have been made where choices of accounting policies are available. At this stage, the Company has not quantified the impacts expected on its consolidated financial statements for these differences.

Note that most adjustments required on transition to IFRS will be made retrospectively, against opening retained earnings in the first comparative balance sheet. Transitional adjustments relating to those standards where comparative figures are not required to be restated because they are applied prospectively will only be made as of the first day of the year of transition.

IFRS 1 “First-Time Adoption of International Financial Reporting Standards” provides entities adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions, in certain areas, to the general requirement for full retrospective application of IFRS. The Company is analyzing the various accounting policy choices available and will implement those determined to be the most appropriate in the Company’s circumstances.

Property, Plant and Equipment. International Accounting Standard (IAS) 16 “Property, Plant & Equipment” and Canadian GAAP contain the same basic principles, however there are some differences. IFRS requires that significant parts of an asset be depreciated separately and depreciation commences when the asset is available for use. There will be more depreciable components than the current single full cost pool. IFRS also permits property, plant equipment to be measured using the fair value model or the historical cost model. The Company is not planning on adopting the fair value measurement model for property, plant and equipment.

IFRS 1 contains an exemption where by a company may apply IFRS prospectively by utilizing its current reserves (volumes or values) at the transition date to allocate the Company’s full cost pool, with the provision that an impairment test, under IFRS standards, be conducted at the transition date. The Company intends to use this exemption and is currently evaluating the impact of allocating the net book values based on reserve volumes or values.

ANDERSON ENERGY     16

Provisions. Under IFRS, similar to Canadian GAAP, the Company is required to record obligations relating to the retirement of its wells and facilities where a legal or contractual obligation currently exists. Upon the adoption of IFRS, the Company will also need to evaluate if there are any constructive obligations where the decommissioning liability would also need to be recognized. Currently, the Company has not identified any constructive obligations.

Upon transition, the Company intends to apply the IFRS 1 exemption whereby the decommissioning liability provision is recalculated at January 1, 2010 using the IFRS methodology and any adjustments would be offset against opening retained earnings.

The Company is in the process of evaluating the methodology by which its decommissioning liabilities will be calculated including the future cash flows as well as the appropriateness of the discount rate. It is anticipated the liability will increase due to a lower rate being utilized.

Impairment of Assets. IAS 36 “Impairment of Assets” requires that impairments be determined based on discounted cash flows. This differs from the current two step practice where the asset’s carrying value is initially compared to the estimated undiscounted future cash flows, and only if the carrying value exceeds the undiscounted future cash flows is a discounted analysis, step two, required. There is no undiscounted test under IFRS. This may result is more frequent write-downs upon transition.

In addition, under IFRS, an entity must also evaluate whether there are changes in circumstances that would support an impairment reversal, which is not allowable under GAAP.

Another difference arises in the level at which an impairment test is performed. Under IFRS, impairment testing will be performed on cash generating units. The Company has identified its cash generating units. There are more cash generating units than the current single full cost pool.

Income taxes. Under IAS 12 “Income Taxes”, current and deferred tax are normally recognized in the income statement, except to the extent that tax arises from (1) an item that has been recognized directly in equity, whether in the same or a different period, (2) a business combination or (3) a share based payment transaction. If a deferred tax asset or liability is re-measured subsequent to initial recognition, the impact of re-measurement is recorded in earnings, unless it relates to an item originally recognized in equity, in which case the change would also be recorded in equity. The practice of tracking the re-measurement of taxes back to the item which originally triggered the recognition is commonly referred to as “backwards tracing.” Canadian GAAP prohibits backwards tracing except on business combinations and financial reorganizations.

Share based payments. Under IFRS 2 “Share-Based Payments”, graded vested options are required to be separated into their vesting tranches and valued and accounted for separately. This differs from Canadian GAAP, where graded vested options are valued at grant date and expensed using the straight line method. IFRS 1 provides an exemption on IFRS 2 for equity instruments which vested before the transition date and does not require them to be retroactively restated. All unvested options at transition date will be required to be retroactively restated with the adjustment going through opening retained earnings on transition. The Company intends to use this exemption and is currently evaluating the transitional impact.

Throughout 2010, the Company will continue to document and define its IFRS accounting policies and the Company will start to evaluate the financial impact of IFRS on its financial statements. Staff training programs have continued in 2009 and will be ongoing as the project unfolds.

17 2009 MANAGEMENT’S DISCUSSION AND ANALYSIS

The Company will also continue to monitor standards development as issued by the International Accounting Standards Board (“IASB”) and the AcSB as well as regulatory developments as issued by the Canadian Securities Administrators, which may affect the timing, nature or disclosure of its adoption of IFRS.

CONTROLS AND PROCEDURES

The Chief Executive Officer and the Chief Financial Officer have evaluated and tested the effectiveness of Anderson Energy’s disclosure controls and procedures as of December 31, 2009 and have concluded that such disclosure controls and procedures were effective.

The Chief Executive Officer and the Chief Financial Officer have evaluated and tested the design and operating effectiveness of Anderson Energy’s internal controls over financial reporting as of December 31, 2009 and have concluded that, these internal controls are designed properly and are effective in the preparation of financial statements for external purposes in accordance with Canadian GAAP. There were no material changes in the Company’s internal controls over financial reporting in the last quarter of the Company’s fiscal year.

Because of inherent limitations, internal controls over financial reporting may not prevent or detect all misstatements, errors or fraud. Control systems, no matter how well designed, only provide reasonable, not absolute, assurance that the objectives of the controls systems are met.

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. Natural gas prices in particular have weakened on fears of reduced industrial use due to the continued U.S. recession and increased supply from U.S. natural gas shale plays. 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 Annual Information Form for the year ended December 31, 2009 to be 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 ENERGY     18

Anderson Energy 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 Energy seeks out and employs new technologies where possible. With the Company’s extensive drilling inventory and advance planning, the Company 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 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.

Canada is a signatory to the United Nations Framework Convention on Climate Change. The Canadian federal government previously released the Regulatory Framework for Air Emissions, updated March 10, 2008 by Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions (collectively, the “Regulatory Framework”), for regulating greenhouse gas (“GHG”) emissions by proposing mandatory emissions intensity reduction obligations on a sector by sector basis. Legislation to implement the Regulatory Framework had been expected to be put in place this year, but the federal government has delayed the release of any such legislation and potential federal requirements in respect of GHG emissions are unclear. On January 30, 2010, the Canadian federal government announced its new target to reduce overall Canadian GHG emissions by 17% below 2005 levels by 2020, from the

19 2009 MANAGEMENT’S DISCUSSION AND ANALYSIS

previous target of 20% from 2006 levels by 2020, to align itself with U.S. policy. In 2009, the Canadian federal government announced its commitment to work with the provincial governments to implement a North American-wide cap and trade system for GHG emissions, in cooperation with the United States. Canada would have its own cap-and-trade market for Canadian-specific industrial sectors that could be integrated into a North American market for carbon permits. 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 by reducing specific 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 and which imposes duties to report. The accompanying regulation, the Specified Gas Emitters Regulation, effective July 1, 2007, requires mandatory emissions reductions through the use of emissions intensity targets. 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.

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 new framework, the formula for conventional oil and natural gas royalties uses a sliding rate formula, dependant on the market price and production volumes. Royalty rates for conventional oil range from 0% to 50%. Natural gas royalty rates range from 5% to 50%.

In November 2008, the Government of Alberta announced that companies drilling new natural gas and conventional oil wells at depths between 1,000 and 3,500 meters, which are spudded between November 19, 2008 and December 31, 2013, will have a one-time option of selecting new transitional royalty rates or the new royalty framework rates. The transition option provides lower royalties in the initial years of a well’s life. For example, under the transition option, royalty rates for natural gas wells will range from 5% to 30%. The election must be made prior to the end of the first calendar month in which the leased substance is produced. All wells using the transitional royalty rates must shift to the new royalty framework rates on January 1, 2014.

On March 3, 2009, the Government of Alberta announced a three-point incentive program. Amendments to the program were announced on June 11 and June 25, 2009. This incentive program includes a drilling credit for new oil and natural gas wells drilled between April 1, 2009 and March 31, 2011, providing a $200 per meter drilled royalty credit to companies. The credit is limited to 50% of Crown royalties payable over the same period. 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. The province of Alberta will also invest $30 million in a fund committed to abandonment and reclamation projects where there is no legally responsible or financially able party to deal with the clean-up of the wells.

On March 11, 2010, the Alberta government announced amendments to the new oil and gas royalty framework, which come into effect January 1, 2011. Under the most recent amendments, the maximum royalty paid was reduced from 50% to 40% on oil and from 50% to 36% on natural gas. In addition, according to the announced amendments, the new well incentive program is to become a permanent feature to the new oil and gas royalty framework.

ANDERSON ENERGY     20

Further refinements to the amendments are anticipated to be announced by the Government of Alberta within 60 days of March 11, 2010 including, without limitation, the royalty curves that are to be utilized to determine the applicable royalty rates.

The changes to the royalty regime in the Province of Alberta are subject to certain risks and uncertainties. There may be modifications introduced to the royalty structure and such changes may be adverse to the business of the Company. There can be no assurance that the Government of Alberta or the Government of Canada will not adopt new royalty regimes which may render the Company’s projects uneconomic or otherwise adversely affect the business of the Company.

BUSINESS PROSPECTS

The Company believes it has an excellent future drilling inventory, including several years of vertical development drilling locations, particularly in the Edmonton Sands and West Pembina Rock Creek plays. The Company has also identified high impact multistage frac horizontal drilling opportunities targeting Cardium light oil and Whitemud Sands gas in Central Alberta.

During periods of price weakness, the Company’s business strategy is to grow its assets and reduce its costs. The Company previously announced a significant farm-in transaction in the Edmonton Sands project area. Anderson Energy believes the transaction will deliver significant benefits to the Company and will define it as the major Edmonton Sands resource player in Central Alberta. The Company drilled 118 gross Edmonton Sands wells in 2009, 106 of which were part of the farm-in. In the first quarter of 2010, the Company drilled an additional 20 gross wells, resulting in 126 wells drilled to date under the farm-in agreement.

The equity financings completed during the second quarter of 2009 and the first quarter of 2010, along with the Company’s available bank lines, provide the Company with the financial flexibility to take advantage of the opportunities provided by the farm-in and expand its drilling program on its Cardium lands.

The Company’s annual production guidance for 2010 is 8,000 to 8,500 BOED. Risks associated with this guidance include continued low prices which may restrict capital spending, gas plant capacity, gas plant turnaround duration, regulatory issues, weather problems and access to industry services.

QUARTERLY INFORMATION

The following table provides financial and operating results for the last eight quarters. Earnings were negatively impacted in the fourth quarter of 2008 by a $35.4 million charge for impairment of goodwill. Prices declined from the second quarter of 2008 to the third quarter of 2009 and remain volatile, resulting in lower funds from operations and earnings throughout most of 2009.

21 2009 MANAGEMENT’S DISCUSSION AND ANALYSIS

SELECTED QUARTERLY INFORMATION

($ amounts in thousands, except per share amounts and prices)

	Q4 2009			Q3 2009			Q2 2009			Q1 2009
Oil and gas revenue before royalties	$	20,439		$	14,617		$	17,508		$	24,429
Funds from operations	$	9,151		$	6,623		$	6,692		$	8,792
Funds from operations per share
Basic	$	0.06		$	0.04		$	0.06		$	0.10
Diluted	$	0.06		$	0.04		$	0.06		$	0.10
Loss	$	(6,457	)	$	(9,432	)	$	(10,410	)	$	(10,159	)
Loss per share
Basic	$	(0.04	)	$	(0.06	)	$	(0.09	)	$	(0.12	)
Diluted	$	(0.04	)	$	(0.06	)	$	(0.09	)	$	(0.12	)
Capital expenditures, including acquisitions net of dispositions	$	11,312		$	6,571		$	2,130		$	13,545
Cash from operating activities	$	5,361		$	6,689		$	2,472		$	9,298
Daily sales
Natural gas (Mcfd)		34,938			36,282			40,495			42,344
Liquids (bpd)		1,257			1,013			1,040			1,448
BOE (BOED)		7,080			7,060			7,789			8,505
Average prices
Natural gas ($/Mcf)	$	4.28		$	2.81		$	3.43		$	5.15
Liquids ($/bbl)	$	53.79		$	53.84		$	49.00		$	38.69
BOE ($/BOE)*	$	31.38		$	22.50		$	24.70		$	31.91
	Q4 2008			Q3 2008			Q2 2008			Q1 2008
Oil and gas revenue before royalties	$	30,102		$	39,427		$	49,021		$	37,695
Funds from operations	$	13,204		$	21,212		$	27,321		$	17,591
Funds from operations per share
Basic	$	0.15		$	0.24		$	0.31		$	0.20
Diluted	$	0.15		$	0.24		$	0.31		$	0.20
Earnings (loss) before goodwill impairment	$	(5,865	)	$	4,160		$	8,509		$	1,696
Earnings (loss) before goodwill impairment per share
Basic	$	(0.07	)	$	0.05		$	0.10		$	0.02
Diluted	$	(0.07	)	$	0.05		$	0.10		$	0.02
Earnings (loss)	$	(41,229	)	$	4,160		$	8,509		$	1,696
Earnings (loss) per share
Basic	$	(0.47	)	$	0.05		$	0.10		$	0.02
Diluted	$	(0.47	)	$	0.05		$	0.10		$	0.02
Capital expenditures, including acquisitions net of dispositions	$	27,470		$	27,068		$	16,772		$	35,359
Cash from operating activities	$	11,261		$	26,351		$	27,660		$	17,416
Daily sales
Natural gas (Mcfd)		38,090			38,703			39,881			39,210
Liquids (bpd)		1,341			1,221			1,265			1,345
BOE (BOED)		7,689			7,671			7,912			7,879
Average prices
Natural gas ($/Mcf)	$	6.76		$	7.86		$	10.26		$	7.55
Liquids ($/bbl)	$	48.49		$	90.19		$	97.61		$	83.91
BOE ($/BOE)*	$	42.55		$	55.87		$	68.08		$	52.57

^*  Includes royalty and other income classified with oil and gas sales.

ANDERSON ENERGY     22

SELECTED ANNUAL INFORMATION

YEARS ENDED DECEMBER 31

(in thousands, except per share amounts)

	2009			2008			2007
Total oil and gas revenues	$	76,993		$	156,245		$	83,585
Total oil and gas revenues, net of royalties	$	68,740		$	122,207		$	67,827
Earnings (loss) before goodwill impairment	$	(36,458	)	$	8,500		$	2,184
Earnings (loss) before goodwill impairment per share
Basic	$	(0.29	)	$	0.10		$	0.03
Diluted	$	(0.29	)	$	0.10		$	0.03
Earnings (loss)	$	(36,458	)	$	(26,864	)	$	2,184
Earnings (loss) per share
Basic	$	(0.29	)	$	(0.31	)	$	0.03
Diluted	$	(0.29	)	$	(0.31	)	$	0.03
Total assets	$	497,169		$	543,533		$	531,324
Total long-term debt	$	62,404		$	85,314		$	67,981

ADVISORY

Certain information regarding Anderson Energy Ltd. 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, dates of commencement of production, amount of capital expenditures and timing thereof, value of undeveloped land, extent of reserves additions, ability to attain cost savings, drilling program success, impact of changes to the royalty regime applicable to the Company, including payment of drilling incentive credits, commodity price outlook and general economic outlook may constitute forward-looking statements under applicable securities laws 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, capital expenditure costs, including drilling, completion and facilities costs, unexpected decline rates in wells, wells not performing as expected, incorrect assessment of the value of acquisitions and farm-ins, failure to realize the anticipated benefits of acquisitions and farm-ins, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources. As a consequence, actual results may differ materially from those anticipated in the 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 Energy’s operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) and at Anderson Energy’s website (www.andersonenergy.ca).

Furthermore, 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 Anderson Energy 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.

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.

23 2009 MANAGEMENT’S DISCUSSION AND ANALYSIS

Abbreviations used

AECO – intra-Alberta Nova inventory transfer price

bbl – barrel

bpd – barrels per day

Mbbls – thousand barrels

Mstb – thousand stock tank barrels

BOE – barrels of oil equivalent

BOED – barrels of oil equivalent per day

MBOE – thousand barrels of oil equivalent

MMBOE – million barrels of oil equivalent

GJ – gigajoule

Mcf – thousand cubic feet

Mcfd – thousand cubic feet per day

MMcf – million cubic feet

MMcfd – million cubic feet per day

Bcf – billion cubic feet

Consolidated Financial Statements

DECEMBER 31, 2009 AND 2008

Table of Contents

Management’s Report	1
Auditors’ Report to the Shareholders	1
Consolidated Balance Sheets	2
Consolidated Statements of Operations, Comprehensive Loss and Deficit	3
Consolidated Statements of Cash Flows	4
Notes to the Consolidated Financial Statements	5

ANDERSON ENERGY     1

Management’s Report

Management is responsible for the preparation of the consolidated financial statements and the consistent presentation of all other financial information that is publicly disclosed. The consolidated financial statements have been prepared in accordance with the accounting policies detailed in the notes to the consolidated financial statements and in accordance with Canadian generally accepted accounting policies and include estimates and assumptions based on management’s best judgement. Management maintains a system of internal controls to provide reasonable assurance that assets are safeguarded and that relevant and reliable financial information is produced in a timely manner. Independent auditors appointed by the shareholders have examined the consolidated financial statements. Their report is presented below. The Audit Committee, consisting of independent members of the Board of Directors, have reviewed the consolidated financial statements with management and the independent auditors. The Board of Directors has approved the consolidated financial statements on the recommendation of the Audit Committee.

(signed) Brian H.Dau (signed) M. Darlene Wong

Brian H. Dau M. Darlene Wong

President & Chief Executive Officer Vice President, Finance,

Chief Financial Officer & Secretary

March 19, 2010

Auditors’ Report to the Shareholders

We have audited the consolidated balance sheets of Anderson Energy Ltd. as at December 31, 2009 and 2008 and the consolidated statements of operations, comprehensive loss and deficit and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2009 and 2008 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

(signed) KPMG LLP

Chartered Accountants

Calgary, Canada

March 19, 2010

2 2009 FINANCIAL STATEMENTS

ANDERSON ENERGY LTD.

Consolidated Balance Sheets

DECEMBER 31, 2009 AND 2008

(Stated in thousands of dollars)

	2009			2008
ASSETS
Current assets:
Cash	$	1		$	1
Accounts receivable and accruals (note 12)		22,990			28,960
Prepaid expenses and deposits		3,778			2,692
		26,769			31,653
Property, plant and equipment (note 4)		470,400			511,880
	$	497,169		$	543,533
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accruals	$	36,889		$	71,619
Bank loans (note 6)		62,404			85,314
Asset retirement obligations (note 7)		33,879			30,820
Future income taxes (note 8)		31,278			46,168
		164,450			233,921
Shareholders’ equity:
Share capital (note 9)		391,637			334,176
Contributed surplus (note 9)		6,104			4,000
Deficit		(65,022	)		(28,564	)
		332,719			309,612
Commitments (note 14)
Subsequent events (note 15)
	$	497,169		$	543,533

See accompanying notes to the consolidated financial statements.

On behalf of the Board:

(signed) J.C. Anderson (signed) Brian H. Dau

Director Director

ANDERSON ENERGY     3

ANDERSON ENERGY LTD.

Consolidated Statements of Operations, Comprehensive Loss and Deficit

YEARS ENDED DECEMBER 31, 2009 AND 2008

(Stated in thousands of dollars, except per share amounts)

	2009			2008
REVENUES
Oil and gas sales	$	76,993		$	156,245
Royalties		(8,253	)		(34,038	)
Interest income		155			67
		68,895			122,274
EXPENSES
Operating		26,906			32,110
General and administrative		6,998			6,377
Stock-based compensation		1,092			1,065
Interest and other financing charges		3,733			4,459
Depletion, depreciation and accretion		80,940			65,373
Impairment of goodwill (note 5)		—			35,364
		119,669			144,748
Loss before taxes		(50,774	)		(22,474	)
Future income tax expense (reduction) (note 8)		(14,316	)		4,390
Loss and comprehensive loss for the year		(36,458	)		(26,864	)
Deficit, beginning of year		(28,564	)		(1,700	)
Deficit, end of year	$	(65,022	)	$	(28,564	)
Loss per share (note 9)
Basic	$	(0.29	)	$	(0.31	)
Diluted	$	(0.29	)	$	(0.31	)

See accompanying notes to the consolidated financial statements.

4 2009 FINANCIAL STATEMENTS

ANDERSON ENERGY LTD.

Consolidated Statements of Cash Flows

YEARS ENDED DECEMBER 31, 2009 AND 2008

(Stated in thousands of dollars)

	2009			2008
CASH PROVIDED BY (USED IN)
OPERATIONS
Loss for the year	$	(36,458	)	$	(26,864	)
Items not involving cash:
Depletion, depreciation and accretion		80,940			65,373
Future income tax expense (reduction)		(14,316	)		4,390
Impairment of goodwill		—			35,364
Stock-based compensation		1,092			1,065
Asset retirement expenditures		(1,482	)		(1,132	)
Changes in non-cash working capital:
Accounts receivable and accruals		3,201			1,553
Prepaid expenses and deposits		(1,036	)		(591	)
Accounts payable and accruals		(8,121	)		3,530
		23,820			82,688
FINANCING
Increase (decrease) in bank loans		(22,910	)		17,333
Issue of common shares, net of issue costs		56,538			25
Changes in non-cash working capital:
Accounts payable and accruals		115			—
		33,743			17,358
INVESTMENTS
Additions to property, plant and equipment		(33,612	)		(124,712	)
Proceeds on disposition of properties		54			18,043
Changes in non-cash working capital:
Accounts receivable and accruals		2,769			1,027
Prepaid expenses and deposits		(50	)		421
Accounts payable and accruals		(26,724	)		5,174
		(57,563	)		(100,047	)
Decrease in cash		—			(1	)
Cash, beginning of year		1			2
Cash, end of year	$	1		$	1

See note 11 for additional cash information.

See accompanying notes to the consolidated financial statements.

ANDERSON ENERGY     5

ANDERSON ENERGY LTD.

Notes to the Consolidated Financial Statements

YEARS ENDED DECEMBER 31, 2009 AND 2008

(Tabular amounts in thousands of dollars, unless otherwise stated)

Anderson Energy Ltd. (“Anderson Energy” or the “Company”) was incorporated under the laws of the province of Alberta on January 30, 2002. Anderson Energy is engaged in the acquisition, exploration and development of oil and gas properties in western Canada.

1. SIGNIFICANT ACCOUNTING POLICIES

(a) Basis of presentation. These consolidated financial statements include the accounts of Anderson Energy Ltd. and its wholly owned subsidiaries and a partnership and have been prepared by management in accordance with accounting principles generally accepted in Canada. All inter-entity transactions and balances have been eliminated. Management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenue and expenses during the reported period. Actual results could differ from these estimates. Specifically, the amounts recorded for depletion and depreciation of oil and gas properties and the accretion of asset retirement obligations are based on estimates. The ceiling test is based on estimates of reserves, production rates, oil and gas prices, future costs and other relevant assumptions. The amounts for stock-based compensation are based on estimates of risk-free rates, expected lives, forfeitures and volatility. Future income taxes are based on estimates as to the timing of the reversal of temporary differences and tax rates currently substantively enacted. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be significant.

(b) Cash. Cash is defined as cash in the bank, less outstanding cheques.

(c) Property, plant and equipment. The Company follows the full cost method of accounting for oil and gas properties. Under this method, all costs relative to the exploration for and development of oil and gas reserves are capitalized. Capitalized costs include lease acquisitions, geological and geophysical costs, lease rentals on non-producing properties, costs of drilling productive and non-productive wells, plant and production equipment costs, asset retirement costs and that portion of general and administrative expenses directly attributable to exploration and development activities. Proceeds received from disposals of oil and gas properties and equipment are credited against capitalized costs unless the disposal would alter the rate of depletion and depreciation by more than 20%, in which case a gain or loss on disposal is recorded.

Oil and gas capitalized costs are depleted and depreciated using the unit of production method based on total proved reserves before royalties. Natural gas sales and reserves are converted to equivalent units of crude oil using their relative energy content. The costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations until it is determined whether or not proved reserves are attributable to the property or impairment occurs. Office equipment and furniture are being depreciated over their useful lives using the declining balance method at rates between 20% and 30% per annum.

6 2009 FINANCIAL STATEMENTS

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

A detailed impairment calculation is performed when events or circumstances indicate a potential impairment of the carrying amount of oil and gas properties may have occurred, and at least annually in the fourth quarter. An impairment loss is recognized when the carrying amount of a cost centre is not recoverable and exceeds its fair value. The carrying amount is assessed to be recoverable when the sum of the undiscounted cash flows expected from proved reserves plus the cost of unproved properties, net of impairments, exceeds the carrying amount of the cost centre. When the carrying amount is assessed not to be recoverable, an impairment loss is recognized to the extent that the carrying amount of the cost centre exceeds the sum of the discounted cash flows from proved and probable reserves plus the cost of unproved properties, net of impairments, of the cost centre. The cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate.

(d) Asset retirement obligations. The Company records the fair value of asset retirement obligations as a liability in the period in which it incurs a legal obligation to restore an oil and gas property, typically when a well is drilled, equipment is put in place or in the event of an acquisition. The fair value is discounted using the Company’s credit adjusted, risk-free rate with the associated asset retirement costs capitalized as part of the carrying amount of property, plant and equipment and depleted and depreciated using the unit of production method based on total proved reserves before royalties. Subsequent to the initial measurement of the obligations, the obligations are increased at the end of each period to reflect the passage of time resulting in an accretion charge to earnings. The obligations are also adjusted for changes in the estimated future cash flows underlying the obligation. Actual costs incurred upon settlement of the retirement obligation are charged against the obligation to the extent of the liability recorded.

(e) Goodwill. Goodwill is the excess purchase price over the fair value of identifiable assets and liabilities acquired in a business combination. Goodwill is not amortized and is tested for impairment annually in the fourth quarter or more frequently if events or changes in circumstances indicate that the asset might be impaired. To assess impairment, the fair value of the Company, deemed to be the reporting unit, is determined and compared to the book value of the Company. If the fair value of the Company is less than the book value, then a second test is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the individual assets and liabilities from the fair value of the Company to determine the implied fair value of goodwill. An impairment loss is recognized for the excess of the carrying value of goodwill over the implied fair value.

(f) Income taxes. The Company follows the asset and liability method of accounting for income taxes. Under this method, income tax assets and liabilities are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements and their respective tax bases, using income tax rates that are substantively enacted and expected to apply in the periods when the temporary differences are expected to reverse. The effect of a change in rates on future income tax assets and liabilities is recognized in the period that the change occurs.

(g) Flow-through shares. The resource expenditure deductions for income tax purposes related to exploratory and development activities funded by flow-through share

ANDERSON ENERGY     7

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

arrangements are renounced to investors in accordance with income tax legislation. An estimate of the additional tax liability to be incurred and included in the future tax provision is recognized and charged to share capital at the time the resource expenditure deductions for income tax purposes are renounced to investors.

(h) Stock-based compensation plans. The Company accounts for stock options granted to employees and directors using the fair value method of accounting for stock-based compensation plans. Under this method, the Company recognizes compensation costs, with a corresponding increase to contributed surplus, based on the fair value of the options over the vesting period of the grant. The Company uses a Black-Scholes option pricing model to determine the fair value of options at the date of grant. When exercised, the consideration paid together with the amount previously recognized in contributed surplus is recorded as an increase to share capital.

(i) Revenue recognition. Revenue from the sale of oil and gas is recognized when title passes from the Company to the purchaser.

(j) Financial instruments. A financial instrument is any contract that gives rise to a financial asset to one entity and a financial liability or equity instrument to another entity. Upon initial recognition, all financial instruments, including all derivatives, are recognized on the balance sheet at fair value. Subsequent measurement is then based on the financial instruments being classified into one of five categories: held for trading, held to maturity, loans and receivables, available for sale and other liabilities. The Company has designated its cash as held for trading which is measured at fair value. Accounts receivable are classified as loans and receivables which are measured at amortized cost. Accounts payable and accrued liabilities and bank loans are classified as other liabilities which are measured at amortized cost determined using the effective interest rate.

The Company is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations. A variety of derivative instruments may be used by the Company to reduce its exposure to fluctuations in commodity prices, foreign exchange rates, and interest rates. The Company does not use these derivative instruments for speculative purposes. The Company considers all of these transactions to be economic hedges, however, the Company’s contracts do not qualify or have not been designated as hedges for accounting purposes. As a result, derivative contracts are classified as held for trading and are recorded on the balance sheet at fair value, with changes in the fair value recognized in earnings.

The Company has elected to account for its physical delivery sales contracts for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts on an accrual basis rather than as non-financial derivatives.

The Company measures and recognizes embedded derivatives separately from the host contracts when the economic characteristics and risks of the embedded derivative are not closely related to those of the host contract, when it meets the definition of a derivative and when the entire contract is not measured at fair value. Embedded derivatives are recorded at fair value.

8 2009 FINANCIAL STATEMENTS

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

The Company nets all transaction costs incurred, in relation to the acquisition of a financial asset or liability, against the related financial asset or liability. Bank loans are presented net of deferred interest payments, with interest recognized in earnings on an effective interest basis.

The Company applies trade-date accounting for the recognition of a purchase or sale of cash equivalents and derivative contracts.

(k) Interests in joint operations. A substantial portion of the Company’s oil and gas exploration and development activities are conducted jointly with others, and accordingly, the consolidated financial statements reflect only the Company’s proportionate interest in such activities.

(l) Per share amounts. Basic per share amounts are calculated using the weighted average number of common shares outstanding during the period. Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common shares were exercised to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments. Under the treasury stock method, only options for which the exercise price is less than the market value impact the dilution calculations.

(m) Comparative figures. Certain comparative figures have been reclassified to conform to the current year’s presentation.

2. CHANGES IN ACCOUNTING POLICIES

Goodwill and intangible assets. In February 2008, the CICA issued Section 3064, Goodwill and Intangible Assets. Effective for fiscal years beginning on or after October 1, 2008, this section provides guidance on the recognition, measurement, presentation and disclosure for goodwill and intangible assets, other than the initial recognition of goodwill or intangible assets acquired in a business combination. The Company adopted the new standard for the year ended December 31, 2009. Adoption of the standard did not have any impact on the Company’s results of operations or financial position.

Financial Instruments – Disclosures. In May 2009, the Canadian Institute of Chartered Accountants amended Section 3862, Financial Instruments – Disclosures, to include additional disclosure requirements about fair value measurement for financial instruments and liquidity risk disclosures. These amendments require a three level hierarchy that reflects the significance of the inputs used in making the fair value measurements. Fair values of assets and liabilities included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Assets and liabilities in Level 2 include valuations using inputs other than quoted prices for which all significant outputs are observable, either directly or indirectly. Level 3 valuations are based on inputs that are unobservable and significant to the overall fair value measurement. These disclosures are included in note 12.

3. FUTURE ACCOUNTING PRONOUCEMENTS

Business combinations. In January 2009, the CICA issued Section 1582, Business Combinations. This section is effective January 1, 2011 and applies prospectively to

ANDERSON ENERGY     9

3. FUTURE ACCOUNTING PRONOUCEMENTS (Continued)

business combinations for which the acquisition date is on or after the first annual reporting period beginning on or after January 1, 2011 for the Company. Early adoption is permitted. This section replaces Section 1581, Business Combinations and harmonizes the Canadian standards with International Financial Reporting Standards.

Consolidated financial statements and non-controlling interests. In 2009, the CICA issued Section 1601, Consolidated Financial Statements and Section 1602, Non-controlling Interests which replace the existing guidance under Section 1600, Consolidated Financial Statements. These standards provide guidance for preparing consolidated financial statements and for accounting for a non-controlling interest in a subsidiary. These standards are effective for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2011, with early adoption permitted.

4. PROPERTY, PLANT AND EQUIPMENT

	2009			2008
Cost	$	723,549		$	686,420
Less accumulated depletion and depreciation		(253,149	)		(174,540	)
Net book value	$	470,400		$	511,880

At December 31, 2009, unproved property costs of $6.2 million (December 31, 2008 – $8.5 million) have been excluded from the full cost pool for depletion and depreciation calculations. Future development costs of proved, undeveloped reserves of $197.6 million (December 31, 2008 – $204.7 million) have been included in the depletion and depreciation calculation.

For the year ended December 31, 2009, $4.6 million (December 31, 2008 – $4.4 million) of general and administrative costs including $1.0 million (December 31, 2008 – $0.9 million) of stock-based compensation costs were capitalized. The future tax liability of $0.3 million (December 31, 2008 – $0.3 million) associated with the capitalized stock-based compensation has also been capitalized. Capitalized general and administrative costs consist of salaries and associated office rent of staff involved in capital activities.

No impairment was recognized under the ceiling test at December 31, 2009. The future commodity prices used in the ceiling test were based on commodity price forecasts of the Company’s independent reserves engineers adjusted for differentials specific to the Company’s reserves. Factors used in the ceiling test calculation are as follows:

	AECO Gas Price ($Cdn/Mcf)		WTI Cushing ($US/bbl)		Exchange rate (US$/Cdn)
2010		5.96		80.00		0.95
2011		6.79		83.00		0.95
2012		6.89		86.00		0.95
2013		6.95		89.00		0.95
2014		7.05		92.00		0.95
2015		7.16		93.84		0.95
2016		7.42		95.72		0.95
2017		7.95		97.64		0.95
2018		8.52		99.59		0.95
2019		8.69		101.58		0.95
Thereafter 2%

10 2009 FINANCIAL STATEMENTS

4. PROPERTY, PLANT AND EQUIPMENT (Continued)

After 2019, only inflationary growth of 2% was considered. Natural gas liquids prices were tied to crude oil prices based on historical trends and analysis. Exchange rates were expected to remain constant beyond 2019.

5. GOODWILL

The Company reviewed the valuation of goodwill as of December 31, 2008 and determined that the fair value of the reporting entity had declined. Based upon this review, an impairment of goodwill of $35.4 million has been recorded as a non-cash charge to earnings as of December 31, 2008.

6. BANK LOANS

At December 31, 2009, the Company has a $90 million extendible, revolving term credit facility and a $10 million working capital credit facility (the “Facilities”) with a syndicate of Canadian banks. At December 31, 2009, the Company has $0.9 million of letters of credit outstanding, which reduces the amount of credit available to the Company.

The reserves-based Facilities have a revolving period ending on July 13, 2010, extendible at the option of the lenders, followed by a term period with three equal quarterly principal repayments commencing 180 days from the term date. The average effective interest rate on advances in 2009 was 4.2% (December 31, 2008 – 5.0%). Advances under the Facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’ acceptance or LIBOR loan rates plus applicable margins. The margins vary depending on the borrowing option used and the Company’s financial ratios. At December 31, 2009, there were no advances in U.S. funds.

Loans are secured by a floating charge debenture over all assets and guarantees by material subsidiaries.

The available lending limits of the Facilities are reviewed semi-annually and are based on the bank syndicate’s interpretations of the Company’s reserves and future commodity prices. There can be no assurance that the amount of the available Facilities or the applicable margins will not be adjusted at the next scheduled review on or before July 13, 2010.

7. ASSET RETIREMENT OBLIGATIONS

The Company estimates the total undiscounted cash flows required to settle its asset retirement obligations is approximately $70.1 million (December 31, 2008 – $63.4 million), including expected inflation of 2% (December 31, 2008 – 2%) per annum. The majority of the costs will be incurred between 2010 and 2020. A credit adjusted risk-free rate of 8% to 10% (December 31, 2008 – 8% to 10%) was used to calculate the fair value of the asset retirement obligations. A reconciliation of the asset retirement obligations is provided below:

ANDERSON ENERGY     11

7. ASSET RETIREMENT OBLIGATIONS (Continued)

	2009			2008
Balance, beginning of year	$	30,820		$	24,526
Liabilities incurred during the year		1,544			3,951
Liabilities settled during the year		(1,482	)		(1,132	)
Liabilities settled on disposition		—			(1,234	)
Change in estimate		666			2,770
Accretion expense		2,331			1,939
Balance, end of year	$	33,879		$	30,820

8. TAXES

The temporary differences that gave rise to the Company’s future income tax liabilities (assets) at December 31, 2009 and 2008 were as follows:

	2009			2008
Future income tax liabilities (assets):
Property, plant and equipment	$	50,210		$	53,264
Non-capital losses		(9,289	)		(13,395	)
Asset retirement obligations		(8,470	)		(7,705	)
Share issue costs		(1,985	)		(1,841	)
Current income deferred		812			15,845
Balance, end of year	$	31,278		$	46,168

The provision for income taxes differs from the result that would have been obtained by applying the combined federal and provincial tax rates to the loss before taxes. The difference results from the following items:

	2009			2008
Loss before taxes	$	(50,774	)	$	(22,474	)
Combined federal and provincial tax rates		29.0	%		29.6	%
Expected future income tax reduction		(14,724	)		(6,652	)
Increase in income taxes resulting from:
Non-deductible impairment of goodwill		—			10,468
Non-deductible stock-based compensation and other		408			574
Future income tax expense (reduction)	$	(14,316	)	$	4,390

At December 31, 2009, the Company has loss carryforwards of $36 million that will expire between 2011 and 2029. The Company expects to be able to fully utilize these losses.

9. SHARE CAPITAL AND CONTRIBUTED SURPLUS

Authorized share capital. The Company is authorized to issue an unlimited number of common and preferred shares. The preferred shares may be issued in one or more series.

12 2009 FINANCIAL STATEMENTS

9. SHARE CAPITAL AND CONTRIBUTED SURPLUS (Continued)

Issued share capital.

	Number of Common Shares		Amount
Balance at December 31, 2007		87,294,401	$	334,147
Stock options exercised		6,000		25
Transferred from contributed surplus on stock option exercise		—		4
Balance at December 31, 2008		87,300,401	$	334,176
Issued pursuant to prospectus(1)		63,200,000		60,040
Share issue costs		—		(3,502	)
Tax effect of share issue costs		—		923
Balance at December 31, 2009		150,500,401	$	391,637

(1) Includes 4,992,034 common shares issued to management and directors and 3,377,966 common shares issued to family of management and directors for total gross proceeds of $8.0 million.

Stock options. The Company has an employee stock option plan under which employees, directors and consultants are eligible to receive grants. The exercise price of stock options equals the weighted average trading price of the Company’s shares for the five trading days prior to the date of the grant. Options have terms of either five or ten years and vest equally over a three year period starting on the first anniversary date of the grant. Changes in the number of options outstanding during the years ended December 31, 2009 and December 31, 2008 are as follows:

	Number of options			Weighted average exercise price
Balance at December 31, 2007		6,297,306		$	4.65
Granted		1,468,300			3.21
Exercised		(6,000	)		4.13
Expirations		(48,800	)		4.80
Forfeitures		(115,950	)		4.28
Balance at December 31, 2008		7,594,856		$	4.37
Granted		3,316,200			0.80
Expirations		(252,300	)		6.47
Forfeitures		(400,000	)		3.01
Balance at December 31, 2009		10,258,756		$	3.22
Exercisable at December 31, 2009		5,809,539		$	4.52

	Options outstanding						Options exercisable
Range of exercise prices	Number of options		Weighted average exercise price		Weighted average remaining life (years)		Number of options		Weighted average exercise price
$0.79 to $0.99		3,145,200	$	0.79		4.6		—	$	—
$1.00 to $1.50		89,100		1.07		2.4		2,700		1.35
$2.26 to $3.35		842,700		2.68		3.7		280,900		2.68
$3.36 to $5.00		5,100,656		4.01		2.5		4,450,839		4.00
$5.01 to $7.50		440,100		6.02		1.6		434,100		6.03
$7.51 to $9.01		641,000		7.93		0.9		641,000		7.93
Total at December 31, 2009		10,258,756	$	3.22		3.1		5,809,539	$	4.52

ANDERSON ENERGY     13

9. SHARE CAPITAL AND CONTRIBUTED SURPLUS (Continued)

The fair value of the options issued during the year ended December 31, 2009 was $0.42 per option (December 31, 2008 – $1.62 per option). The weighted average assumptions used in arriving at the values were: a risk-free interest rate of 2.40% (December 31, 2008 – 3.13%), expected option life of five years (December 31, 2008 – five years), expected volatility of 60% (December 31, 2008 – 57%) and a dividend yield of 0% (December 31, 2008 – 0%).

Per share amounts. During the year ended December 31, 2009 there were 125,047,250 weighted average shares outstanding (December 31, 2008 – 87,298,057). On a diluted basis, there were 125,047,250 weighted average shares outstanding (December 31, 2008 – 87,298,057) after giving effect to dilutive stock options. At December 31, 2009, there were 10,258,756 options that were anti-dilutive (December 31, 2008 – 7,594,856).

Contributed surplus

	Amount
Balance at December 31, 2007	$	2,005
Stock-based compensation		1,999
Transferred from contributed surplus on stock option exercise		(4	)
Balance at December 31, 2008	$	4,000
Stock-based compensation		2,104
Balance at December 31, 2009	$	6,104

Employee stock savings plan. Effective July 1, 2008, the Company initiated an Employee Stock Savings Plan (“ESSP”). Employees could contribute up to 5% of their base salaries towards the purchase of Company shares and the Company matched these contributions. The ESSP was suspended effective April 1, 2009. The Company’s matching contribution, prior to the suspension of the plan, for the year ended December 31, 2009 was $77,000 (December 31, 2008 – $149,000) and is included in general and administrative expenses. The Company plans to reinstate the plan effective April 1, 2010.

10. MANAGEMENT OF CAPITAL STRUCTURE

Anderson Energy’s capital management policy is to maintain a strong, but flexible capital structure that optimizes the cost of capital and maintains investor, creditor and market confidence while sustaining the future development of the business.

The Company manages its capital structure and makes adjustments to it in the light of changes in economic conditions and the risk characteristics of the underlying petroleum and natural gas assets. The Company’s capital structure includes shareholders’ equity of $332.7 million, bank loans of $62.4 million and the working capital deficiency of $10.1 million. In order to maintain or adjust the capital structure, the Company may from time to time issue shares, seek additional debt financing and adjust its capital spending to manage current and projected debt levels.

Consistent with other companies in the oil and gas sector, Anderson Energy monitors capital based on the ratio of total debt to funds from operations. This ratio is calculated by dividing total debt at the end of the period (comprised of the working capital deficiency and outstanding bank loans) by the annualized current quarter funds from operations (cash flow from operating activities before changes in non-cash working capital and asset retirement expenditures). This ratio may increase at certain times as a result of

14 2009 FINANCIAL STATEMENTS

10. MANAGEMENT OF CAPITAL STRUCTURE (Continued)

acquisitions, the timing of capital expenditures and market conditions. In order to facilitate the management of this ratio, the Company prepares annual capital expenditure budgets, which are updated as necessary depending on varying factors including current and forecast crude oil and natural gas prices, capital deployment and general industry conditions. The annual and updated budgets are approved by the Board of Directors.

	2009			2008
Bank loans	$	62,404		$	85,314
Current liabilities		36,889			71,619
Current assets		(26,769	)		(31,653	)
Total debt	$	72,524		$	125,280
Cash from operating activities in quarter	$	5,361		$	11,261
Changes in non-cash working capital		3,246			1,464
Asset retirement expenditures		544			479
Funds from operations in quarter	$	9,151		$	13,204
Annualized current quarter funds from operations	$	36,604		$	52,816
Total debt to funds from operations		2.0			2.4

At December 31, 2009, the Company’s total debt to annualized funds from operations was 2.0. During the fourth quarter of 2008 and the first nine months of 2009, commodity prices decreased significantly, adversely affecting the Company’s cash flow. Management restricted capital and administrative spending until commodity prices started to recover. Commodity prices continue to be volatile. On May 28, 2009, the Company closed an equity financing for net proceeds of $56.5 million (note 9) and renewed its banking facilities at an available limit of $100 million (note 6) to provide funding for its farm-in commitments (note 14) and other capital spending planned for the 2010 winter drilling season. This decreased the ratio from the 2.4 at December 31, 2008. Additionally, subsequent to year end, the Company closed an equity financing for net proceeds of $29.8 million (note 15).

The Company’s share capital is not subject to external restrictions, however, the Facilities are petroleum and natural gas reserves based (see note 6). Anderson Energy has not paid or declared any dividends since the date of incorporation and does not contemplate doing so in the foreseeable future.

11. CASH PAYMENTS

The following cash payments were made (received):

	2009			2008
Interest paid	$	2,835		$	3,765
Interest received		(155	)		(69	)

12. FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT

The Company’s financial instruments include cash, accounts receivable and accruals, The Company’s financial instruments include cash, accounts receivable and accruals, accounts payable and accruals and bank loans. The carrying value of accounts receivable and accruals and accounts payable and accruals approximate their fair value due to their

ANDERSON ENERGY     15

12. FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Continued)

demand nature or relatively short periods to maturity. The fair value of bank loans approximates the carrying value as they bear interest at a floating rate.

The Company’s risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company’s activities.

The Company has exposure to credit risk, liquidity risk and market risk as a result of its use of financial instruments. This note presents information about the Company’s exposure to each of the above risks and the Company’s objectives, policies and processes for measuring and managing these risks. Further quantitative disclosures are included throughout these financial statements.

The Board of Directors has overall responsibility for the establishment and oversight of the Company’s risk management framework. The Board has implemented and monitors compliance with risk management policies.

Fair value of financial assets and financial liabilities. Section 3862, Financial Instruments – Disclosures, requires an explanation about how fair value is determined for assets and liabilities measured in the financial statements at fair value and establishes a hierarchy for which these assets and liabilities must be grouped, based on significant levels of input as follows:

• Level 1 – observable inputs such as quoted prices in active markets;

• Level 2 – inputs, other than the quoted market prices in active markets, which are observable, either directly and/or indirectly; and

• Level 3 – unobservable inputs for the asset or liability in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

Cash as shown in the consolidated balance sheet as at December 31, 2009 and 2008, is measured using level 1. The Company does not have any financial instruments that are measured using level 2 or level 3 inputs.

During the years ended December 31, 2009 and 2008, there were no transfers between level 1, level 2 and level 3 classified assets and liabilities.

Cash. The fair value of cash approximates its carrying value due to its short-term nature.

Accounts receivable and accruals, accounts payable and accruals. The carrying amount of accounts receivable and accruals and accounts payable and accruals approximate their fair values due to the short-term nature of the instruments.

Bank loans. The fair value of the Company’s variable-rate bank loans approximates its carrying value, as it is at a floating market rate of interest.

Credit risk. Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations. A substantial portion of the Company’s accounts receivable are with natural gas and liquids marketers and joint venture partners in the oil and gas industry and are subject to normal industry credit risks. Purchasers of the Company’s natural gas and liquids are subject to credit review to minimize the risk of non-payment. As at December 31, 2009, the maximum credit exposure is the carrying amount of the accounts receivable and accruals of $23.0

16 2009 FINANCIAL STATEMENTS

12. FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Continued)

million (December 31, 2008 – $29.0 million). As at December 31, 2009, the Company’s receivables consisted of $14.4 million (December 31, 2008 – $17.3 million) from joint venture partners and other trade receivables and $8.6 million (December 31, 2008 – $11.7 million) of revenue accruals and other receivables from petroleum and natural gas marketers.

Receivables from petroleum and natural gas marketers are typically collected on the 25th day of the month following production. The Company’s policy to mitigate credit risk associated with these balances is to establish marketing relationships with large purchasers. The Company historically has not experienced any significant collection issues with its petroleum and natural gas marketers. Of the $8.6 million of revenue accruals and receivables from petroleum and natural gas marketers, $7.8 million was received on or about January 25, 2010. The balance is expected to be received in subsequent months through joint venture billings from partners.

Joint venture receivables are typically collected within one to three months of the joint venture bill being issued to the partner. The Company mitigates the risk from joint venture receivables by obtaining partner approval of capital expenditures prior to starting a project. However, the receivables are from participants in the petroleum and natural gas sector, and collection is dependent on typical industry factors such as commodity price fluctuations, escalating costs and the risk of unsuccessful drilling. Further risks exist with joint venture partners, as disagreements occasionally arise that increase the potential for non-collection. For properties that are operated by Anderson Energy, production can be withheld from joint venture partners who are in default of amounts owing. In addition, the Company often has offsetting amounts payable to joint venture partners from which it can net receivable balances. As at December 31, 2009, the largest amount owing from one partner is $1.6 million.

The Company is from time to time exposed to credit risk associated with possible non-performance by counterparties to derivative financial instrument contracts. The Company believes these risks to be minimal as the counterparties are major financial institutions.

The Company’s allowance for doubtful accounts as at December 31, 2009 is $1.6 million (December 31, 2008 – $1.4 million). This allowance was mostly created in prior years and is associated with prior corporate acquisitions and potential joint venture billing disputes. The Company provided for an additional $0.2 million in allowance and did not write-off any receivables during the year ended December 31, 2009. The Company would only choose to write-off a receivable balance (as opposed to providing an allowance) after all reasonable avenues of collection had been exhausted.

As at December 31, the Company considers it receivables, net of allowance for doubtful accounts, to be aged as follows:

Aging	2009		2008
Not past due	$	22,402	$	24,036
Past due by less than 120 days		537		2,197
Past due by more than 120 days		51		2,727
Total	$	22,990	$	28,960

These amounts are before offsetting amounts owing to joint venture partners that are included in accounts payable and accrued liabilities.

ANDERSON ENERGY     17

12. FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Continued)

Liquidity risk. Liquidity risk is the risk that the Company will incur difficulties meeting its financial obligations as they are due. The Company’s approach to managing liquidity is to ensure, as far as possible, that it will have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions without incurring unacceptable losses or risking harm to the Company’s reputation.

The Company prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary. The Company uses authorizations for expenditures on both operated and non-operated projects to further manage capital expenditures. To facilitate the capital expenditure program, the Company has revolving reserves based credit facilities, as outlined in note 6, which are reviewed at least annually by the lenders. The Company monitors its total debt position monthly. The Company also attempts to match its payment cycle with collection of petroleum and natural gas revenues on the 25th of each month. The Company anticipates it will have adequate liquidity to fund its financial liabilities through its future cash flows.

The following are the contractual maturities of financial liabilities and associated interest payments as at December 31, 2009:

Financial Liabilities	< 1 Year		1 -2 Years
Accounts payable and accruals	$	36,889	$	—
Bank loans – principal		—		62,404
Total	$	36,889	$	62,404

Please refer to note 14 for additional details on commitments.

Market risk. Market risk consists of currency risk, commodity price risk and interest rate risk. The objective of market risk management is to manage and control market risk exposures within acceptable limits, while maximizing returns.

The Company may use both financial derivatives and physical delivery sales contracts to manage market risks. All such transactions are conducted in accordance with a risk management policy that has been approved by the Board of Directors.

Currency risk. Foreign currency exchange rate risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in foreign exchange rates. Substantially all of the Company’s petroleum and natural gas sales are denominated in Canadian dollars, however, the underlying market prices in Canada for petroleum and natural gas are impacted by changes in the exchange rate between the Canadian and United States dollar. From time to time in 2008, the Company chose to sell a portion of its oil in United States dollars.

The Company had no outstanding forward exchange rate contracts in place at December 31, 2009.

Commodity price risk. Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for petroleum and natural gas are impacted by world economic events that dictate the levels of supply and demand as well as the relationship between the Canadian and United States dollar, as outlined above. The Company may mitigate commodity price risk

18 2009 FINANCIAL STATEMENTS

12. FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Continued)

through the use of financial derivatives and physical delivery fixed price sales contracts. All such contracts require approval of the Board of Directors.

In December 2009, the Company entered into physical sales contracts to sell 20,000 GJ per day of natural gas for each of January, February and March 2010 at an average AECO price of $5.41 per GJ. As of December 31, 2009, there have been no gains or losses recognized in association with these physical sales contracts.

On January 10, 2008, the Company entered into physical sales contracts to sell 25,000 GJ per day for February and March 2008 at an average AECO price of $6.89 per GJ. The losses realized to December 31, 2008 were $1.3 million and have been included in oil and gas sales.

Interest rate risk. Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Company is exposed to interest rate fluctuations on its bank debt which bears interest at a floating rate. For the year ended December 31, 2009, if interest rates had been 1% lower with all other variables held constant, earnings for the year would have been $0.5 million (December 31, 2008 – $0.5 million) higher, due to lower interest expense. An equal and opposite impact would have occurred had interest rates been higher by the same amounts.

The Company had no interest rate swap or financial contracts in place at December 31, 2009.

13. RELATED PARTY TRANSACTION

In May 2009, the Company issued 4,992,034 common shares to management and directors and 3,377,966 common shares to family of management and directors of the Company at a price of $0.95 per share for total gross proceeds of $8 million as part of a $60 million bought deal offering of common shares.

14. COMMITMENTS

The Company has entered into an agreement to lease office space until November 30, 2012. Future minimum lease payments are expected to be $1.8 million in 2010 through 2011 and $1.6 million in 2012.

The Company entered into firm service transportation agreements for approximately 25 million cubic feet per day of gas sales in central Alberta for various terms expiring in one to ten years. Based on rate schedules announced to date, the payments in each of the next five years and thereafter are estimated as follows:

	Committed volume (MMcfd)		Committed amount
2010		25	$	1,634
2011		22	$	1,509
2012		14	$	1,109
2013		7	$	795
2014		1	$	640
Thereafter		17	$	1,183

ANDERSON ENERGY     19

14. COMMITMENTS (Continued)

On January 29, 2009, the Company executed a farm-in agreement with a large international oil and gas company (the “Farmor”) on lands near its existing core operations. Under the farm-in agreement, the Company has access to 388 gross (205 net) sections of land. During the commitment phase of the transaction, the Company is committed to drill, complete and equip 200 wells to earn an interest in up to 120 sections. The Company is obligated to complete the drilling of the wells on or before December 31, 2010. The Company’s equipping obligation is up to, but does not include, multi-well gathering systems downstream of field compression and/or gas plants. The Company has an option to continue the farm-in transaction until April 30, 2012 by committing to drill a minimum of 100 additional wells under similar terms as in the commitment phase to earn a minimum of 50 sections of land. Following the commitment and/or option phases, the parties to the agreement can then jointly develop the lands on denser drilling spacing under terms of an operating agreement.

The Company estimates that the average working interest of the 200 well capital commitment will be approximately 80 to 85%, based on partner participation identified to date and started drilling in the fourth quarter of 2009. The Company’s commitment was to drill 75 wells by December 31, 2009, a further 50 wells by April 30, 2010 and a further 75 wells by December 31, 2010. The Company earns its interest in each well as the well is put on production. As of December 31, 2009, the Company has drilled 106 wells under the farm-in agreement.

After December 31, 2009 and April 30, 2010 respectively, the Farmor has the ability to request a letter of credit from the Company in the amount of $550,000 per well not drilled under the minimum commitment at that date. At December 31, 2010, the $550,000 penalty is payable for each well not drilled, subject to certain reductions due to unavoidable events beyond the Company’s control and rights of first refusal. The Company estimates that it will spend approximately $50 million in 2010 on the farm-in, before drilling incentive credits earned.

15. SUBSEQUENT EVENTS

On February 3, 2010, the Company issued, pursuant to a prospectus, 19,250,000 common shares at a price of $1.45 per common share for gross proceeds of $27.9 million ($26.1 million, net of commission and expenses).

On February 22, 2010, the underwriters purchased an additional 2,650,000 common shares for additional gross proceeds of approximately $3.8 million under the over-allotment option ($3.7 million, net of commission).

Subsequent to year end, the Company entered into an agreement to sell a portion of its excess drilling incentive credits to a third party for total proceeds of $2.6 million. The agreement closed on March 19, 2010.

700 Selkirk House

555 Fourth Avenue S.W., Calgary, Alberta T2P 3E7

Tel: (403) 262-6307 Fax: (403) 261-2792

www.andersonenergy.ca