The Company embarked on a new 13-well horizontal drilling program in the third quarter of 2014 that is expected to be completed by the first quarter of 2015. Production from the 13-well program started six weeks later than expected due to delays in obtaining Crown surface access approvals, as well as winter-like weather conditions in early September. Consequently, these wells will not impact the Company's operating results until the fourth quarter of 2014 and the first quarter of 2015. Initial production from the new drilling program was recorded late in October 2014.

As of November 10, 2014, six gross (5.5 net capital, 5.1 net revenue) wells have been drilled, of which three gross (3.0 net) wells have been completed and placed on continuous production. Of the wells completed for production, two are Cardium and one is Glauconitic. Due to the lateness of the program, only one well has surpassed seven days of production and its initial rate for 16 days has been 576 BOED (78% oil, condensate and NGL). The remaining three gross (2.1 net revenue) wells that have been drilled are scheduled to be completed in the next two weeks, one of which is a 32 stage horizontal frac completion of a Cardium long-reach well. The drilling and completion costs for typical Cardium wells continue to average approximately $2.3 to $2.5 million per well.

The capital budget for 2014 has been increased to $52 million from the previously announced $46 million. The increase in the capital budget is attributable to the acquisition of partner interests through penalty account pick-up and farm-in transactions that increased Cardium net well counts, the unbudgeted expansion of the Willesden Green 5-14 gathering system to accommodate a significant condensate and NGL-rich gas discovery, the upgrade of the 5-14 liquids handling system, undeveloped land acquisitions and a cost overrun on the Company's first Glauconite well. Also, some capital budget expenditures have been shifted from the first quarter of 2015 to the fourth quarter of 2014. Overall, the Company's net well count has not changed for the fall/winter 2014/2015 program. However, the number of net wells planned to be drilled in the last half of 2014 has increased and the number of net wells planned to be drilled in the first quarter of 2015 has decreased from original budget expectations due to drilling higher working interest wells in the fourth quarter of 2014. The 2015 capital budget will be released in early 2015.

The Company's guidance for 2014 annual and exit BOED production remains unchanged at 3,200 and 3,700 BOED respectively. However, due to delays in beginning the 13-well drilling program, the percentage contribution from oil, condensate and NGL has been reduced from 36% to 34%. The Company maintains its 2014 exit percentage contribution from oil, condensate and NGL at 42%.

STRATEGY

Anderson's focus area and prospects are located in Willesden Green, Buck Lake and West Pembina in west central Alberta. The Company's efforts are dedicated to drilling horizontal wells in the Cardium, Glauconite and Belly River formations. Since completion of the strategic alternatives process in the fourth quarter of 2013, the Company has been growing production from these zones, with the goal of increasing the percentage of oil, condensate and NGL (collectively, "liquids") production to over 50% of total production. In 2014, the Company estimates that liquids will make up approximately 34% of total production and over 60% of total revenue. By the end of 2015, the Company estimates that approximately 50% of total production and over 70% of total revenue will come from liquids(1). A strategy of increasing liquids production will increase annual cash flow per share faster than BOED production per share, due to the higher prices associated with these products. Over time, it will also increase the Company's asset value and borrowing base.

Anderson prides itself on being one of the lowest capital cost operators in the Cardium horizontal play, with drilling and completion costs of $2.3 to $2.5 million per well for typical horizontal wells. The Company uses this capital cost measure to compare itself to other operators as it is well understood in the industry. Equipping and tie-in costs will vary much more from area to area. Currently, the Company has identified 79.7 net locations in the Cardium, Glauconite and Belly River formations, representing more than five years of drilling inventory. The Company's goal is to continue to add to these locations in order to maintain this five to six year drilling inventory.

The Company has a goal of achieving an average horizontal well payout of one year by continuing to improve upon the profitability of the entire operation. Anderson will focus on keeping capital costs low, controlling infrastructure to keep operating costs low, and using available technology to pursue good reservoir rock and improve frac effectiveness. The Company plans to continue to use commodity price hedging to protect its capital program when it is considered prudent to do so.

Recent technological changes include repositioning the trajectory of horizontal wells within the Cardium zone to maximize frac effectiveness and using dissolvable frac balls.

The horizontal portion, or length, of a typical horizontal well is generally confined to one section of land, or one square mile. A typical horizontal well will have approximately 1,200 meters to 1,400 meters as its horizontal length. In contrast, the Company has recently drilled its first "long-reach" horizontal well which traversed approximately 2,600 meters of horizontal well length for a total well measured depth of 4,676 meters. The long-reach horizontal well is expected to access Cardium reserves in two sections of land once the well is completed, which is scheduled for later this month. This well was drilled and cased in 20 days, compared to 10 to 12 days for a typical horizontal well.

There is a capital cost benefit to drilling a long-reach well over two sections as compared to drilling two typical horizontal wells, each confined to one section of land. There also is a reserves benefit with longer horizontal wells due to additional reservoir contact. Typical horizontal well densities in Willesden Green vary from three to six wells per section of land.

Where it can, the Company strives to operate its own oil and gas infrastructure and attract third parties to utilize this infrastructure on a processing fee basis to reduce overall operating costs. Currently, the Company operates over 90% of its production and all of its current drilling operations.

Anderson has commenced drilling on its Glauconite oil shoreface play in the Willesden Green area. While this play is new to the Company, other operators have been successfully drilling horizontal oil wells into the Glauconite oil shoreface in Willesden Green.

The Company has approximately 1,000 BOED of legacy shallow gas production and will continue to look for ways to optimize, rationalize, consolidate and improve the profitability of the shallow gas business. Anderson has an extensive drilling inventory of shallow gas opportunities and may sell some or all of these shallow gas assets.

The Company has no plans to buy back common shares or convertible debentures with normal course issuer bids. The Company's business plan is to invest in its asset base, grow its asset base, cash flow and reserves and increase its financial flexibility. At September 30, 2014, the Company had $8.0 million in cash. Its bank line is $31 million and it currently has no bank loans outstanding. The 2014 capital budget of $52 million is being funded with cash, cash flow and available bank lines.

DRILLING PROGRAM UPDATE

The Company originally planned to drill 14 gross (11.5 net capital, 11.1 net revenue) wells from the third quarter of 2014 through the first quarter of 2015. With the changes in working interests due to farm-ins and the acquisition of additional interests from partners, the plan has been amended to drill 13 gross (11.3 net capital, 10.2 net revenue) wells over the same period of time.

As of November 10, 2014, Anderson has drilled six wells under this 2014/2015 drilling program, of which three have been recently completed. None of the wells have been on-stream long enough to have 30 days of initial production history.

In the second quarter of 2014, the Company completed the eighth well of the previous 2013/2014 drilling program, and the 30 day initial production ("IP") results from those eight wells are shown in table below:

Short-term production rates can be influenced by flush production effects from fracture stimulations in horizontal wellbores and may not be indicative of longer-term production performance. Individual well performance may vary.

HORIZONTAL DRILLING INVENTORY

The Company's undeveloped horizontal drilling inventory at November 10, 2014, is outlined below:

* Net is net revenue interest

GLJ Petroleum Consultants Ltd. ("GLJ") booked undeveloped reserves to 22.4 net locations as of April 30, 2014. GLJ's booked locations are included in the drilling inventory table above.

The Company has a potential drilling inventory of 95 gross (58 net) horizontal locations in the Second White Specks light oil play. Offsetting industry activity, although encouraging, has not demonstrated the play to be commercially viable at this time and, therefore, these locations are not included in the above table.

The Company has an extensive shallow gas drilling inventory in the Edmonton Sands formation. At the present time, the Company's business strategy does not include any near-term plans for shallow gas drilling.

COMMODITY PRICES

A comparison of Anderson's average oil and condensate price to various market prices is presented below. Average prices are before the impact of any financial derivative contracts used for risk management. The difference between Anderson's realized price and WTI Canadian is due to the price differential between Cushing, Oklahoma and Edmonton, Alberta, product transportation costs from the field to Edmonton, and adjustments for product quality.

CRUDE OIL AND CONDENSATE PRICES

*Condensate includes field condensate and plant condensate.

The 2014 monthly WTI Canadian oil prices were approximately $94.57 per bbl in October and $88.75 per bbl to date in November. Differentials from Cushing, Oklahoma to Edmonton, Alberta were approximately $4.54 US per bbl in October and $5.30 US per bbl in November.

A comparison of Anderson's average plant gate natural gas price to various market prices is presented below. Average plant gate prices are before the impact of any financial derivative or fixed price contracts used for risk management. The difference between the AECO price and Anderson's plant gate price is due to transportation costs and the heat content of the gas. Financial derivative and fixed price contracts reduced the average price received for natural gas to $3.88 per Mcf in the third quarter of 2014.

The average heat content of the Company's natural gas has increased from 1,018 Btu/scf in the fourth quarter of 2013 and 1,026 Btu/scf in the first quarter of 2014 to 1,061 Btu/scf in the second quarter of 2014 and 1,065 Btu/scf in the third quarter of 2014 due to the new Cardium gas having higher heat content than the legacy shallow gas production. Natural gas is sold on the basis of heat content; therefore, higher heat content gas will yield higher prices per unit of measured volume.

NATURAL GAS PRICES

AECO natural gas prices were approximately $3.48 per GJ ($3.68 per MMBtu) in October and $3.60 per GJ ($3.80 per MMBtu) to date in November.

FINANCIAL RESULTS

Financial results compared to the prior year reflect the progress made to date since completion of the strategic alternatives process in the fourth quarter of 2013. However, production and revenue results in third quarter of 2014 were lower than the second quarter of 2014 due to less drilling activity, anticipated declines in flush production rates from the eight wells drilled in late 2013 and early 2014, lower commodity prices, and various shut-ins for plant maintenance over the summer months. Third quarter production on a BOED basis was in line with budget estimates as stronger than expected natural gas production from Cardium gas discoveries in the second quarter offset the impact of the delayed 13-well drilling program.

Funds from operations were $2.3 million in the third quarter of 2014 compared to $1.4 million in the third quarter of 2013 and $5.5 million in the second quarter of 2014.

On a BOE basis, oil and gas sales averaged $39.54 per BOE in the third quarter of 2014 compared to $41.87 per BOE in the third quarter of 2013 and $47.13 per BOE in the second quarter of 2014. During the third quarter of 2014, liquids revenue (oil, condensate and NGLs) represented 56% of total oil and gas sales. The Company's operating netback was $22.58 per BOE in the third quarter of 2014 compared to $17.77 per BOE in the third quarter of 2013 and $28.88 per BOE in the second quarter of 2014. The decrease from the second quarter of 2014 was due to lower natural gas prices and a lower percentage of liquids volumes in the third quarter. Anderson's operating netback for Cardium properties in the third quarter of 2014 was $41.09 per BOE, exclusive of hedging, compared to $44.74 per BOE in the second quarter of 2014, and $49.73 per BOE in the third quarter of 2013.

Capital expenditures, net of dispositions, were $29.2 million for the nine months ended September 30, 2014. Field capital expenditures were $8.6 million in the third quarter of 2014 compared to $3.0 million in the second quarter of 2014. Capital investments in the second and third quarters of 2014 were focused primarily on the drilling, completion, equipping and tie-in of Cardium horizontal wells, the drilling of one Glauconite horizontal well, and the completion of the Willesden Green plant and gathering system upgrade. In the first nine months of 2014, the Company completed $2.5 million in net property acquisitions related to Cardium and Glauconite prospects, and the sale of $1.0 million in shallow gas assets and undeveloped land.

HEDGING

Derivative contracts

At September 30, 2014, the following derivative contracts were outstanding and recorded at estimated fair value:

Natural gas - fixed price swap contract based on the AECO 5A natural gas price:

Crude oil - fixed price swap contract based on WTI Canadian oil price:

Fixed price contracts

The Company entered into physical contracts to sell 2,500 GJs per day of natural gas for January 1, 2014 to December 31, 2014 at an average AECO price of $3.72 per GJ. All of the remaining natural gas production is being sold at the monthly average of AECO 5A daily index prices.

SUMMARY

Recent dramatic oil price downswings and the negative impact on financial markets have pushed the Company's share price lower, but have not had a negative impact on its business strategy as a whole. The Company's wellhead oil price per barrel in the fourth quarter to date is very similar to what the Company experienced in the fourth quarter of 2013, which is still an economic oil price for the Company's business.

Anderson is continuing with its significant high impact Cardium and Glauconite horizontal drilling program. The Company continues to rationalize and improve the profitability of its shallow gas assets and add to its horizontal drilling inventory with farm-ins and property acquisitions. The management and staff are very excited about the results to date of the fall/winter 13-well drilling program, the remainder of this drilling program and the expected future oil production growth in the fourth quarter of 2014 and first quarter of 2015.

For further information on the Company, please refer to the investor presentation at www.andersonenergy.ca.

Brian H. Dau, President & Chief Executive Officer

November 12, 2014

Management's Discussion and Analysis

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2014 AND 2013

The following management's discussion and analysis ("MD&A") is dated November 10, 2014 and should be read in conjunction with the unaudited condensed interim consolidated financial statements of Anderson Energy Ltd. ("Anderson" or the "Company") for the three and nine months ended September 30, 2014 and the audited consolidated financial statements and MD&A of Anderson for the years ended December 31, 2013 and 2012.

In addition to generally accepted accounting principles ("GAAP") measures, this MD&A contains additional conversion measures, non-GAAP measures, additional GAAP measures and forward-looking statements. Readers are cautioned that the MD&A should be read in conjunction with Anderson's disclosure under the headings "Conversion Measures", "Non-GAAP Measures", "Additional GAAP Measures", and "Forward-Looking Statements" included at the end of this MD&A.

All references to dollar values are to Canadian dollars unless otherwise stated. Production volumes are measured upon sale unless otherwise noted. Definitions of the abbreviations used in this discussion and analysis are located on the last page of this document.

REVIEW OF FINANCIAL RESULTS

Overview

The Company ended the third quarter of 2014 with an adjusted working capital deficiency⁽¹⁾ of $6.6 million (including $8.0 million in cash) and no bank debt.

For the three-month period ended September 30, 2014, the Company generated $2.3 million in funds from operations⁽²⁾ and reported a loss of $3.0 million. The Company invested $9.4 million in capital expenditures in the third quarter of 2014.

For the nine-month period ended September 30, 2014, the Company generated $13.3 million in funds from operations⁽²⁾ and reported a loss of $3.4 million. The Company invested $29.2 million in capital expenditures, net of minor property dispositions.

The Company's financial results continued to benefit from the higher natural gas prices experienced during the first three quarters of 2014 relative to 2013, and the successful eight-well winter drilling program completed in the second quarter of 2014. During the third quarter of 2014, the Company began a fall/winter program that is expected to include the drilling of 13 gross (11.3 net capital, 10.2 net revenue) wells and to extend into the first quarter of 2015.

The following table provides a comparison of production, prices, revenue and funds from operations for the three and nine-month periods ended September 30, 2014 compared to the same periods in 2013.

In 2014, the Company has combined the disclosure of field condensate and plant condensate (collectively, "condensate") volumes and revenue with crude oil under the new heading "Oil and condensate". NGL volumes and revenue now exclude condensate volumes and revenue. Prior periods have been reclassified to conform to this presentation.

Production

Average production volumes in the third quarter of 2014 were 2,793 BOED compared to 3,414 BOED in the second quarter of 2014 and 3,449 BOED in the third quarter of 2013. For the nine-month period ended September 30, 2014, the average production volumes were 3,055 BOED compared to 3,854 BOED in the same period of 2013. The decrease in volumes for the first nine months of 2014 relative to the first nine months of 2013 reflects the impact of property dispositions completed in the last three months of 2013 and first three months of 2014, which represented approximately 1,315 BOED of production at the time of the dispositions. That impact was partially offset by the new production from the last eight wells drilled. Production volumes in the third quarter of 2014 were 18% lower than the second quarter of 2014 due to less drilling activity, the anticipated declines following the flush initial production from the wells drilled earlier in 2014, and various shut-ins for plant maintenance over the summer months. Third quarter production on a BOED basis was in line with budget estimates as stronger than expected natural gas production from Cardium gas discoveries in the second quarter offset the impact of the delayed 13-well drilling program.

The Company's guidance for 2014 annual and exit BOED production remains unchanged at 3,200 and 3,700 BOED respectively. However, due to delays in beginning the 13-well drilling program, the percentage contribution from oil, condensate and NGL has been reduced from 36% to 34%. The Company maintains its 2014 exit percentage contribution from oil, condensate and NGL at 42%.

Prices

World and North American benchmark prices for oil remain volatile. Differentials between WTI oil prices and prices received in Alberta are also volatile due to factors including refining demand and pipeline capacity. Anderson sells its oil at monthly average Edmonton Par prices less quality differentials, transportation, and marketing fees. Light, sweet oil differentials between Cushing, Oklahoma and Edmonton, Alberta are affected by transportation and market factors. Differentials in the third quarter of 2014 averaged $7.92 US discount per bbl (2013 - $4.70 US per bbl).

Natural gas prices improved significantly in the first few months of 2014 due to higher demand related to colder weather conditions in North America, but later months and longer-term markets have not seen the same increase. In the third quarter of 2014, AECO 5A prices averaged approximately $3.81 Cdn per GJ, down from the second quarter of 2014 average of $4.44 Cdn per GJ. Forward strip prices for AECO are approximately $3.65 Cdn per GJ for 2015 and 2016.

The Company's average natural gas sales price was $3.93 per Mcf for the three months ended September 30, 2014, 14% lower than the second quarter of 2014 price of $4.59 per Mcf and 73% higher than the third quarter of 2013 price of $2.27 per Mcf. This price includes the effect of the physical fixed price contracts discussed below. The average price before the effect of these contracts was $3.95 per Mcf. The average price after the effect of both the physical fixed price contracts and the derivative contracts discussed below was $3.88 per Mcf.

Derivative contracts

At September 30, 2014, the following fixed price swap contract based on the AECO 5A natural gas price was outstanding and recorded at estimated fair value:

By comparison, AECO 5A averaged $3.81 Cdn per GJ in the third quarter of 2014 and approximately $3.48 Cdn per GJ in October 2014.

At September 30, 2014, the following fixed price swap contract based on the WTI oil price converted to Canadian dollars was outstanding for crude oil and recorded at estimated fair value:

By comparison, WTI Canadian averaged approximately $105.76 per bbl in the third quarter of 2014 and approximately $94.57 in October 2014.

Derivative contracts on crude oil and natural gas had the following impact on the unaudited consolidated statements of operations for the three and nine months ended September 30, 2014 (the comparative numbers for 2013 were on crude oil derivative contracts):

Fixed price contracts

The Company entered into physical contracts to sell 2,500 GJs per day of natural gas for January 1, 2014 to December 31, 2014 at an average AECO price of $3.72 Cdn per GJ. All of the remaining natural gas production is being sold at the monthly average of AECO 5A daily index prices.

Royalties

For the third quarter of 2014, the average rate for royalties was 9.6% of revenue compared to 7.6% of revenue in the second quarter of 2014 and 10.1% of revenue in the third quarter of 2013. Horizontal wells drilled on Crown lands qualify for royalty incentives that reduce average Crown royalties for periods of up to 36 months from initial production for oil wells (18 months for gas wells), after which Crown royalties are expected to increase from current levels. Other royalties are lower than in the prior year due to the sale of properties in the fourth quarter of 2013 that were subject to higher-rate freehold royalties.

Royalties as a percentage of total oil and gas sales are highly sensitive to prices and adjustments to gas cost allowance; hence, royalty rates can fluctuate from quarter to quarter and year to year.

Operating expenses

Operating expenses were $3.5 million ($13.52 per BOE) in the third quarter of 2014 compared to $4.1 million ($13.22 per BOE) in the second quarter of 2014 and $4.6 million ($14.47 per BOE) in the third quarter of 2013. For the nine months ended September 30, 2014, operating expenses were $11.1 million ($13.33 per BOE) compared to $13.7 million ($13.01 per BOE) in the first nine months of 2013.

Operating expenses on a per BOE basis were affected by the impact of property sales on the product sales mix of the Company. The oil properties sold by the Company during the fourth quarter of 2013 generally contributed to lower operating costs per BOE than many of the Company's natural gas properties. The operating costs of $13.52 per BOE in the third quarter ($13.22 in the second quarter) of 2014 compared to $14.31 per BOE in the fourth quarter of 2013 reflect that the Cardium drilling programs and the disposition of high operating cost natural gas properties to date in 2014 are starting to reverse the impact of the 2013 property sales on operating costs.

Transportation expenses

For the third quarter of 2014, transportation expenses were $0.1 million ($0.13 per BOE) compared to $0.2 million ($0.50 per BOE) per BOE in the second quarter of 2014 and $0.1 million ($0.36 per BOE) per BOE in the third quarter of 2013. For the nine months ended September 30, 2014, transportation expenses were $0.3 million ($0.30 per BOE) compared to $0.3 million ($0.32 per BOE) in the first nine months of 2013. Transportation expenses in the third quarter of 2014 were reduced by approximately $0.12 per BOE due to adjustments to second quarter estimates.

OPERATING NETBACK

Depletion and depreciation

Depletion and depreciation was $5.1 million ($19.74 per BOE) in the third quarter of 2014 compared to $6.5 million ($20.91 per BOE) in the second quarter of 2014 and $6.9 million ($21.74 per BOE) in the third quarter of 2013. For the nine months ended September 30, 2014, depletion and depreciation was $17.2 million ($20.65 per BOE) compared to $23.6 million ($22.40 per BOE) in the first nine months of 2013. The decrease in the amount of depletion and depreciation in 2014 compared to 2013 was primarily due to the asset sales in the fourth quarter of 2013 and lower overall production volumes. Proved plus probable reserves volumes are included in the determination of depletion expense.

Impairment losses

At September 30, 2014, there were no indicators of impairment or reversals of impairment in the Company's cash generating units ("CGUs"); thus, no impairment test or reversal of impairment calculation was performed.

Impairment loss on assets held for sale

There were no assets held for sale, or impairment loss on assets held for sale recorded at September 30, 2014. For the comparative period ended September 30, 2013, certain oil and gas properties were classified as assets held for sale and these assets were recorded on the consolidated statement of financial position at the lower of carrying value and management's best estimate of their fair value less costs to sell, resulting in an impairment loss of $44.6 million.

General and administrative expenses

As detailed at the end of this MD&A, general and administrative (cash) ("G&A (cash)") expenses is a term that does not have any standardized meaning under GAAP. Refer to the section entitled "Non-GAAP Measures" found at the end of this MD&A.

G&A (cash) expenses were $1.7 million ($6.61 per BOE) in the third quarter of 2014 compared to $1.7 million ($5.51 per BOE) for the second quarter of 2014 and $1.6 million ($5.19 per BOE) for the third quarter of 2013. For the nine months ended September 30, 2014, G&A (cash) expenses were $5.3 million ($6.32 per BOE) compared to $5.4 million ($5.10 per BOE) in the first nine months of 2013.

Decreases in gross G&A (cash) expenses in 2014 compared to 2013 were offset by decreases in overhead recoveries due to the asset sales in the fourth quarter of 2013. Capitalized general and administrative costs consist of salaries, benefits and office rent associated with staff involved in capital activities.

The following table is a reconciliation of the Company's G&A (cash) expenses to general and administrative expenses:

At the end of June 2014, the Company moved to new office space at a cost of approximately two-thirds of renewing at the office space previously occupied.

Share-based payments

Share-based payments expense was $0.1 million ($0.1 million net of amounts capitalized) for the third quarter of 2014 and $0.1 million ($0.1 million net of amounts capitalized) for the second quarter of 2014 versus $0.2 million ($0.1 million net of amounts capitalized) in the third quarter of 2013. For the nine months ended September 30, 2014, share-based payments expense was $0.3 million ($0.2 million net of amounts capitalized) compared to $0.7 million ($0.5 million net of amounts capitalized) in the first nine months of 2013.

Finance expenses

Finance expenses were $2.6 million for the third quarter of 2014, compared to $2.6 million for the second quarter of 2014 and $3.4 million in the third quarter of 2013. For the nine months ended September 30, 2014, finance expenses were $7.8 million compared to $10.0 million in the first nine months of 2013.

The decrease in finance expenses from 2013 is the result of lower interest and other financing charges associated with bank credit facilities. Proceeds from the disposition of assets in the fourth quarter of 2013 were used to repay bank debt, and the Company has had no outstanding bank loans since October 2013. Interest expense on credit facilities in 2014 includes stand-by and other fees associated with maintaining the existing bank line of $31 million.

Decommissioning obligations

The decommissioning liability at September 30, 2014 of $29.0 million was $1.4 million lower than the December 31, 2013 balance of $30.4 million largely due to the disposition of certain natural gas and other minor properties in 2014.

During the nine months ended September 30, 2014, items that increased decommissioning obligations included $0.5 million (2013 - $0.3 million) incurred on development activities, $0.6 million of accretion expense (2013 - $0.6 million), and a net change in estimates of $1.4 million (2013 - $3.1 million decrease), whereas items that reduced decommissioning obligations included actual expenditures of $0.4 million (2013 - $0.4 million) and property dispositions of $3.5 million (2013 - $6.3 million).

Changes in estimates were primarily due to discount rate variation at September 30, 2014 compared to December 31, 2013, in addition to other abandonment liability revisions. The risk-free discount rates used by the Company to measure the obligations at September 30, 2014 were between 1.0% and 2.9% (December 31, 2013 - 1.1% to 3.2%) depending on the timelines to reclamation and changed from the start of the year as a result of changes in the Canadian bond market.

Income taxes

The Company has recognized a deferred tax asset in the amount of $2.0 million as at September 30, 2014 and December 31, 2013. No additional deferred tax assets were recognized during the first nine months of 2014. The Company has approximately $371 million of tax pools at September 30, 2014.

Funds from operations

As detailed at the end of this MD&A, "funds from operations" is a term that does not have any standardized meaning under GAAP. Funds from operations is calculated as cash flow from operating activities before changes in non-cash working capital and decommissioning obligations incurred. Refer to the section entitled "Additional GAAP Measures" found at the end of this MD&A. A table providing a reconciliation of the Company's cash flow from operating activities to funds from operations is included in the section entitled "Overview" near the beginning of this MD&A.

Funds from operations were $2.3 million in the third quarter of 2014, compared to $5.5 million in the second quarter of 2014 and $1.4 million in the third quarter of 2013. For the nine months ended September 30, 2014, funds from operations were $13.3 million compared to $11.6 million in 2013. Higher commodity prices, improved operating netbacks and lower financing costs more than offset the lower production due to the 2013 property sales.

Loss

The Company reported a loss of $3.0 million in the third quarter of 2014 compared to a loss of $1.0 million in the second quarter of 2014 and a loss of $48.7 million for the third quarter of 2013. For the nine months ended September 30, 2014, the loss was $3.4 million compared to a loss of $103.2 million in the first nine months of 2013.

The loss in the three and nine month periods ended September 30, 2013 included an impairment loss of $44.6 million related to assets held for sale and the de-recognition of the deferred tax asset of $45.6 million.

The Company completed its strategic alternatives process in the fourth quarter of 2013, and is in the process of reestablishing production volumes and cash flows from conducting new drilling operations. The Company is focused on controlling operating and capital costs in addition to improving production rates and sales product mix; however, commodity prices will continue to have a direct bearing on the determination of earnings or loss.

CAPITAL EXPENDITURES

The Company invested $9.4 million in capital expenditures, net of minor property dispositions, in the third quarter of 2014 ($29.2 million in the first nine months of 2014). The breakdown of expenditures is shown below:

The Company started its 2014/2015 winter drilling program in the third quarter of 2014 with the drilling of two gross (2.0 net) wells, one of which was a Glauconite horizontal well and the other a horizontal Cardium well. Neither well was completed and equipped as at September 30, 2014 but both have been included in the drilling statistics shown below:

Also during the third quarter of 2014, the Company completed the expansion of the 100% owned 05-14-039-05W5 Willesden Green gas plant. The Company also completed $0.3 million in net property acquisitions related to Cardium and Glauconite prospects.

SHARE INFORMATION

The Company's shares have been listed on the Toronto Stock Exchange since September 7, 2005 under the symbol "AXL". As of November 10, 2014, there were 172.5 million common shares outstanding, 16.6 million stock options outstanding, $50.0 million principal amount of convertible debentures which are convertible into common shares at a conversion price of $1.55 per common share, and $46.0 million principal amount of convertible debentures which are convertible into common shares at a conversion price of $1.70 per common share. During the third quarter of 2013 and 2014, no common shares were issued through the exercise of employee stock options.

SHARE PRICE ON TSX

The statistics above include trading on the Toronto Stock Exchange only. Shares also trade on alternative platforms like Alpha, Chi-X, CX2, Pure, Omega and TMX Select. During the three months and nine months ended September 30, 2014, approximately 5.2 million and 21.9 million common shares traded on these alternative exchanges respectively. Including these exchanges, an average of 326,879 common shares traded per day in the three months ended September 30, 2014 (September 30, 2013 - 374,406), representing a quarterly turnover ratio of 12% (September 30, 2013 - 14%).

LIQUIDITY AND CAPITAL RESOURCES

At September 30, 2014, the Company had convertible debentures of $96.0 million (principal) and an adjusted working capital deficiency of $6.6 million (including $8.0 million in cash), and no outstanding bank loans. The following table shows the changes in bank loans plus adjusted working capital (deficiency):

The continued development of the Company's oil and gas assets is dependent on the ability of the Company to secure sufficient funds through operations, bank facilities, and other sources. 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 September 30, 2014, the Company had a $31 million extendible committed term bank facility with a Canadian bank under which $30.9 million of credit was available with $0.1 million in letters of credit outstanding that reduce the amount of available credit. If this revolving operating loan facility is not extended at its term date of May 30, 2015, any outstanding advances would become repayable one year later on May 30, 2016.

Under the agreement, advances can be drawn in Canadian funds and bear interest at the bank's prime lending rate or guaranteed notes discount rates plus applicable margins. These margins vary from 2.25% to 3.25% depending on the borrowing option chosen by the Company.

Anderson will prudently use its bank loan facility to finance its operations as required.

Loans are secured by general security agreements providing security interests over all assets and by guarantees of material subsidiaries.

Under the terms of the bank facility, the Company has provided a financial covenant that the amount of its current liabilities shall not exceed the sum of its current assets and the undrawn availability under the facility at the end of each fiscal quarter. Unrealized gains (losses) on derivative contracts are excluded from the above amounts. The Company was in compliance with this financial covenant as at September 30, 2014.

As of today's date, the Company has no outstanding bank loans.

OFF-BALANCE SHEET ARRANGEMENTS

The Company had no guarantees or off-balance sheet arrangements other than as described either below or in the management's discussion and analysis for the year ended December 31, 2013 under "Contractual Obligations".

CONTRACTUAL OBLIGATIONS

The Company enters into various contractual obligations in the course of conducting its operations. There were no material changes to the contractual obligations that were discussed in management's discussion and analysis for the year ended December 31, 2013 other than the following:

• Cardium Horizontal Well Program - At September 30, 2014, the Company had various obligations under farm-in agreements to drill four gross Cardium horizontal wells to earn working interests in the farm-out lands once it has fulfilled its commitments. Subsequent to September 30, 2014, the Company entered into a pooling and farm-in agreement to drill one additional well. The deadlines to fulfill these commitments range from October 31, 2014 to January 31, 2015. As of November 10, 2014, the Company had drilled two of these wells.

• Office Lease - In the second quarter of 2014, the Company entered into an agreement to lease office space at a cost of approximately $0.4 million per year from July 1, 2014 to October 30, 2018.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements requires the Company to make estimates, assumptions and judgments in the application of IFRS that have a significant impact on the financial results of the Company. Actual results could differ from estimated amounts, and those differences may be material. A comprehensive discussion of the Company's significant critical accounting estimates is contained in the MD&A and the audited consolidated financial statements for the year ended December 31, 2013.

NEW AND PENDING ACCOUNTING STANDARDS

Standards that are issued and that the Company reasonably expects to be applicable at a future date are listed below.

IFRS 9 Financial Instruments. In July 2014, the IASB issued IFRS 9, "Financial Instruments" to replace IAS 39, "Financial Instruments: Recognition and Measurement". The new standard replaces the current multiple classification and measurement models for financial asset and liabilities with a single model that has only two classification categories: amortized cost and fair value. As of January 1, 2018, the Company will be required to adopt the standard. The Company is currently assessing the impact that this standard may have on its financial statements.

CHANGES IN ACCOUNTING POLICIES

On January 1, 2014, the Company adopted the following new IFRS standards and amendments in accordance with the transitional provisions of each standard. The adoption of these standards did not have a material impact on the Company's financial statements. A brief description of each new standard follows below:

CONTROLS AND PROCEDURES

The Chief Executive Officer ("CEO") and the Chief Financial Officer ("CFO") have designed, or caused to be designed under their supervision, disclosure controls and procedures ("DC&P") and internal controls over financial reporting ("ICOFR") as defined in National Instrument 52-109 Certification of Disclosure in Issuer's Annual and Interim Filings in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with IFRS.

The DC&P have been designed to provide reasonable assurance that material information relating to the Company is made known to the CEO and CFO by others and that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by the Company under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation.

The CEO and CFO are required to cause the Company to disclose any change in the Company's ICOFR that occurred during the period beginning on July 1, 2014 and ending on September 30, 2014 that has materially affected, or is reasonably likely to materially affect, the Company's ICOFR. No changes in ICOFR were identified during such period that have materially affected or are reasonably likely to materially affect the Company's ICOFR.

It should be noted that a control system, including the Company's DC&P and ICOFR, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objective of the control system will be met and it should not be expected that DC&P and ICOFR will prevent all errors or fraud.

BUSINESS RISKS

Oil and gas exploration and production is capital intensive and involves a number of business risks including, without limitation, the uncertainty of finding new reserves, the instability of commodity prices, weather and various operational risks. Commodity prices are influenced by local and worldwide supply and demand, OPEC actions, ongoing global economic concerns, the US dollar exchange rate, transportation costs, political stability and seasonal and weather-related changes to demand. The price of natural gas had strengthened in late 2013 due to weather-related changes to demand and continues to be higher than the first nine months of 2013; however, the concern over increasing US gas production, driven primarily by the US shale gas plays, continues to depress the natural gas futures market. Oil prices continue to remain volatile as they are a geopolitical commodity, affected by concerns about global economic markets, continued instability in oil producing countries and increases in production from US shale oil plays. Differentials between WTI oil prices and prices received in Alberta are volatile. The industry is subject to extensive governmental regulation with respect to the environment. Operational risks include well performance, uncertainties inherent in estimating reserves, timing of/ability to obtain and maintain drilling licences and other regulatory approvals, ability to obtain equipment, expiration of licences and leases, competition from other producers, third-party transportation and processing disruption issues, sufficiency of insurance, ability to manage growth, reliance on key personnel, third party credit risk and appropriateness of accounting estimates. These risks are described in more detail in the Company's most recent Annual Information Form filed with certain Canadian securities regulatory authorities on SEDAR at www.sedar.com.

The Company makes substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves. As the Company's revenues may decline as a result of decreased commodity pricing, it may be required to reduce capital expenditures. In addition, uncertain levels of near-term industry activity coupled with the present global economic concerns exposes the Company to additional access-to-capital risk. There can be no assurance that debt or equity financing, or funds generated by operations, will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Company. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on the Company's business, financial condition, results of operations and prospects.

Anderson manages these risks by employing competent and professional staff, following sound operating practices and using capital prudently. The Company generates its exploration and development prospects internally and performs extensive geological, geophysical, engineering, and environmental analysis before committing to the drilling of new prospects. Anderson seeks out and employs new technologies where possible. With the Company's extensive drilling inventory and advance planning, the Company believes it can manage the slower pace of regulatory approvals and the requirements for extensive landowner consultation.

The Company has a formal emergency response plan which details the procedures employees and contractors will follow in the event of an operational emergency. The emergency response plan is designed to respond to emergencies in an organized and timely manner so that the safety of employees, contractors, residents in the vicinity of field operations, the general public and the environment are protected. A corporate safety program covers hazard identification and control on the jobsite, establishes 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 endeavours 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, transportation 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, impact the Company's ability to get its product to market, 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 in, amongst other things, suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, and the imposition of material fines and penalties.

STRATEGY

Anderson's focus area and prospects are located in Willesden Green, Buck Lake and West Pembina in west central Alberta. The Company's efforts are dedicated to drilling horizontal wells in the Cardium, Glauconite and Belly River formations. Since completion of the strategic alternatives process in the fourth quarter of 2013, the Company has been growing production from these zones, with the goal of increasing the percentage of oil, condensate and NGL (collectively, "liquids") production to over 50% of total production. In 2014, the Company estimates that liquids will make up approximately 34% of total production and over 60% of total revenue. By the end of 2015, the Company estimates that approximately 50% of total production and over 70% of total revenue will come from liquids(1). A strategy of increasing liquids production will increase annual cash flow per share faster than BOED production per share, due to the higher prices associated with these products. Over time, it will also increase the Company's asset value and borrowing base.

Anderson prides itself on being one of the lowest capital cost operators in the Cardium horizontal play, with drilling and completion costs of $2.3 to $2.5 million per well for typical horizontal wells. The Company uses this capital cost measure to compare itself to other operators as it is well understood in the industry. Equipping and tie-in costs will vary much more from area to area. Currently, the Company has identified 79.7 net locations in the Cardium, Glauconite, and Belly River formations, representing more than five years of drilling inventory. The Company's goal is to continue to add to these locations in order to maintain this five to six year drilling inventory.

The Company has a goal of achieving an average horizontal well payout of one year by continuing to improve upon the profitability of the entire operation. Anderson will focus on keeping capital costs low, controlling infrastructure to keep operating costs low, and using available technology to pursue good reservoir rock and improve frac effectiveness. The Company plans to continue to use commodity price hedging to protect its capital program when it is considered prudent to do so.

Recent technological changes include repositioning the trajectory of the horizontal well within the Cardium zone to maximize frac effectiveness and using dissolvable frac balls.

The horizontal portion, or length, of a typical horizontal well is generally confined to one section of land, or one square mile. A typical horizontal well will have approximately 1,200 meters to 1,400 meters as its horizontal length. In contrast, the Company has recently drilled its first "long-reach" horizontal well which traversed approximately 2,600 meters of horizontal well length for a total well measured depth of 4,676 meters. The long-reach horizontal well is expected to access Cardium reserves in two sections of land once the well is completed, which is scheduled for later this month. This well was drilled and cased in 20 days, compared to 10 to 12 days for a typical horizontal well.

There is a capital cost benefit to drilling a long-reach well over two sections as compared to drilling two typical horizontal wells, each confined to one section of land. There also is a reserves benefit with longer horizontal wells due to additional reservoir contact. Typical horizontal well densities in Willesden Green vary from three to six wells per section of land.

Where it can, the Company strives to operate its own oil and gas infrastructure and attract third parties to utilize this infrastructure on a processing fee basis to reduce overall operating costs. Currently, the Company operates over 90% of its production and all of its current drilling operations.

Anderson has commenced drilling on its Glauconite oil shoreface play in the Willesden Green area. While this play is new to the Company, other operators have been successfully drilling horizontal oil wells into the Glauconite oil shoreface in Willesden Green.

The Company has approximately 1,000 BOED of legacy shallow gas production and will continue to look for ways to optimize, rationalize, consolidate and improve the profitability of the shallow gas business. Anderson has an extensive drilling inventory of shallow gas opportunities and may sell some or all of these shallow gas assets.

The Company has no plans to buy back common shares or convertible debentures with normal course issuer bids. The Company's business plan is to invest in its asset base, grow its asset base, cash flow and reserves and increase its financial flexibility. At September 30, 2014, the Company had $8.0 million in cash. Its bank line is $31 million and it currently has no bank loans outstanding. The 2014 capital budget is being funded by cash, cash flow and available bank lines.

2014 CAPITAL BUDGET

The capital budget for 2014 has been increased to $52 million from the previously announced $46 million. The increase in the capital budget is attributable to the acquisition of partner interests through penalty account pick-up and farm-in transactions that increased Cardium net well counts, the unbudgeted expansion of the Willesden Green 5-14 gathering system to accommodate a significant condensate and NGL-rich gas discovery, the upgrade of the 5-14 liquids handling system, undeveloped land acquisitions, and a cost overrun on the Company's first Glauconite well. Also, some capital budget expenditures have shifted from the first quarter of 2015 to the fourth quarter of 2014. Overall, the Company's net well count has not changed for the fall/winter 2014/2015 program. However, the number of net wells planned to be drilled in the last half of 2014 has increased and the number of net wells planned to be drilled in the first quarter of 2015 has decreased from original budget expectations due to drilling higher working interest wells in the fourth quarter of 2014. The 2015 capital budget will be released in early 2015.

The Company is planning to drill 13 gross (11.3 net capital, 10.2 net revenue) Cardium and Glauconite horizontal wells from the third quarter of 2014 to the first quarter of 2015. The Company continues to evaluate farm-in and property acquisitions in its Cardium and Glauconite focus areas.

The Company's guidance for 2014 annual and exit BOED production remains unchanged at 3,200 and 3,700 BOED respectively. However, due to delays in beginning the 13-well drilling program, the percentage contribution from oil, condensate and NGL has been reduced from 36% to 34%. The Company maintains its 2014 exit percentage contribution from oil, condensate and NGL at 42%.

QUARTERLY INFORMATION

The following table provides financial and operating results for the last eight quarters. Commodity prices remained volatile, affecting funds from operations and earnings throughout those quarters.

The impact of the sale of properties in 2012 and in the last quarter of 2013, as well as natural production declines, contributed to lower production volumes and revenues in 2013. Production improved significantly in the first two quarters of 2014 relative to the last quarter of 2013 due to the winter drilling program that commenced in the last quarter of 2013 and was completed in the second quarter of 2014. Initial flush production rates in the first half of 2014 declined following the completion of the 2013/2014 drilling program which led to an expected decrease in production during the third quarter of 2014.

Earnings in the second quarter of 2013 were affected by the tax expense related to derecognizing a deferred tax asset. Earnings in the third quarter of 2013 were impacted by the impairment on the assets held for sale. Bank loan balances fluctuated in response to the Cardium oil development capital spending programs, and were reduced by the proceeds from the sale of assets, and cash from operating activities in 2013.

SELECTED QUARTERLY INFORMATION

CONVERSION MEASURES

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. Although 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, BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of six Mcf to one 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. In recent years, the value ratio based on the price of crude oil as compared to natural gas has been significantly higher than the energy equivalency of 6:1, and utilizing a conversion of natural gas volumes on a 6:1 basis may be misleading as an indication of value.

NON-GAAP MEASURES

Included in this document are references to the terms "adjusted earnings (loss) before taxes", "adjusted earnings (loss) before taxes per share", "operating netback", "operating netback per BOE" and "general and administrative (cash) expenses". Management believes these measures are helpful supplementary measures of financial performance and provide users with information that is commonly used by other oil and gas companies. These terms do not have any standardized meaning prescribed by GAAP and should not be considered an alternative to, or more meaningful than, "earnings (loss) before taxes" or "earnings (loss) and comprehensive income (loss)" as determined in accordance with GAAP as a measure of the Company's performance.

Adjusted earnings (loss) before taxes is calculated as earnings (loss) before taxes per the Consolidated Statement of Operations and Comprehensive Income (Loss), excluding impairment loss, and provides supplemental information on the Company's before income tax performance, excluding the impact of impairment losses. Operating netback is calculated as oil and gas sales plus applicable realized gains/losses on derivative contracts less royalties, operating expenses and transportation expenses and is a measure of the profitability of operations before administrative, financing and other non-cash items.

General and administrative (cash) expenses are general and administrative costs excluding non-cash share-based payments and provides supplemental information regarding the impact of general and administrative costs on the Company's cash flows.

ADDITIONAL GAAP MEASURES

Funds from operations

This document, including the accompanying financial statements, contain the term "funds from operations" which does not have any standardized meaning prescribed by GAAP and should not be considered an alternative to, or more meaningful than, "cash flow from operating activities" as determined in accordance with GAAP as a measure of the Company's performance. Funds from operations or funds from operations per share may not be comparable with the calculation of similar measures for other entities. Funds from operations as used in this report represent cash from operating activities before changes in non-cash working capital and decommissioning expenditures. See "Funds from operations" under "Review of Financial Results" for details of this calculation. Management believes that funds from operations represent both an indicator of the Company's performance and a funding source for ongoing operations.

Other additional GAAP measures

This document including the accompanying financial statements also contain the terms "adjusted working capital" or "adjusted working capital (deficiency)", "net debt before convertible debentures", "total net debt" and "total capitalization" which do not have any standardized meaning prescribed by GAAP and may not be comparable with the calculation of similar measures for other entities.

Working capital is defined as the difference between current assets and current liabilities. Working capital (deficiency) is the term used when the difference between current assets and current liabilities is a negative number. The unrealized gains on derivative contracts are excluded from current assets and the unrealized losses on derivative contracts are excluded from current liabilities in the calculation of "adjusted working capital" and "adjusted working capital (deficiency)". Adjusted working capital and adjusted working capital (deficiency) represent operating liquidity available to the business and are included in the definition of the additional GAAP term "net debt".

Net debt before convertible debentures is calculated as long-term debt plus adjusted working capital or adjusted working capital (deficiency). Total net debt is calculated as net debt before convertible debentures plus the liability component of convertible debentures. Management believes these measures are useful supplementary measures of the total amount of current and long-term debt. Total capitalization is calculated as total net debt plus shareholders' equity. Management believes this measure is a useful supplementary measure of the Company's managed capital.

FORWARD-LOOKING STATEMENTS

Certain statements in this news release 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 and construction of facilities; expected production rates; improved production from slick water fracture technology; percentage of production from oil and natural gas liquids; dates of commencement of production; amount of capital expenditures and the timing and method of financing thereof; value of undeveloped land; extent of reserves additions; ability to attain cost savings; drilling program success; ability to achieve capital payout targets; impact of changes in commodity prices on operating results; expectations related to future operating netbacks; programs to optimize, rationalize, consolidate and improve profitability of assets; factors on which the continued development of the Company's oil and gas assets are dependent; commodity price outlook; and general economic outlook may constitute "forward-looking information" within the meaning of 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; adequate weather to conduct operations; sufficiency of budgeted capital, operating and other costs to carry out planned activities; 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; inability to complete property dispositions or to complete them at anticipated values; delays resulting from or inability to obtain required regulatory approvals; changes to government regulation; ability to access sufficient capital from internal and external sources; and other factors, many of which are beyond the Company's control. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as the factors are interdependent, and management's future course of action would depend on its assessment of all information at the time. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements and readers should not place undue reliance on the assumptions and forward-looking statements. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect Anderson's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) or at Anderson's website (www.andersonenergy.ca).

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

ANDERSON ENERGY LTD.

Consolidated Statements of Financial Position

See accompanying notes to the condensed interim consolidated financial statements.

ANDERSON ENERGY LTD.

Consolidated Statements of Operations and Comprehensive Loss

See accompanying notes to the condensed interim consolidated financial statements.

ANDERSON ENERGY LTD.

Consolidated Statements of Changes in Shareholders' Equity

NINE MONTHS ENDED SEPTEMBER 30, 2014 AND 2013

(Stated in thousands of dollars, except number of common shares)

(Unaudited)

See accompanying notes to the condensed interim consolidated financial statements.

ANDERSON ENERGY LTD.

Consolidated Statements of Cash Flows

NINE MONTHS ENDED SEPTEMBER 30, 2014 AND 2013

See accompanying notes to the condensed interim consolidated financial statements.

ANDERSON ENERGY LTD.

Notes to the Condensed Interim Consolidated Financial Statements

THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2014 WITH COMPARATIVE FIGURES FOR 2013

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

(Unaudited)

1. REPORTING ENTITY

Anderson Energy Ltd. and its wholly-owned subsidiaries (collectively "Anderson" or the "Company") are engaged in the acquisition, exploration and development of oil and gas properties in western Canada. Anderson is a public company incorporated and domiciled in Canada. Anderson's common shares and convertible debentures are listed on the Toronto Stock Exchange. The Company's registered office and principal place of business is 1000, 555 - 4^th Avenue SW, Calgary, Alberta, Canada, T2P 3E7.

Effective October 1, 2014, Anderson Energy Ltd. and its wholly-owned subsidiaries were reorganized into a single entity named Anderson Energy Ltd. The reorganization did not result in any changes to the beneficial ownership or operations of the Company.

2. BASIS OF PREPARATION

(a) Statement of compliance:

The condensed interim consolidated financial statements comply with International Accounting Standard 34 Interim Financial Reporting and do not include all of the information required for full annual financial statements.

The condensed interim consolidated financial statements were authorized for issuance by the Board of Directors on November 10, 2014.

(b) Accounting policies, judgments, estimates and disclosures:

In preparing these condensed interim consolidated financial statements, the accounting policies, methods of computation and significant judgments made by management in applying the Company's accounting policies and key sources of estimation uncertainty were the same as those that applied to the audited consolidated financial statements as at and for the years ended December 31, 2013 and 2012 except as disclosed below.

On January 1, 2014, the Company adopted new standards with respect to Offsetting Financial Assets and Financial Liabilities (Amendments to IAS 32 Financial Instruments: Presentation ("IAS 32") and IFRIC 21 Levies ("IFRIC 21"). The adoption of these standards had no impact on the amounts recorded in the consolidated financial statements as at January 1, 2014 or on the comparative periods.

The following disclosures are incremental to those included with the annual audited consolidated financial statements. Certain disclosures that are normally required in the notes to the annual audited consolidated financial statements have been condensed or omitted. These condensed interim consolidated financial statements should be read in conjunction with the Company's audited consolidated financial statements and notes thereto for the years ended December 31, 2013 and 2012.

3. PROPERTY, PLANT AND EQUIPMENT

Capitalized overhead

For the nine months ended September 30, 2014, additions to property, plant and equipment included internal overhead costs of $1.4 million (year ended December 31, 2013 - $1.8 million).

Sale of property, plant and equipment

For the nine months ended September 30, 2014, the Company sold interests in properties for total consideration of $1.0 million (year ended December 31, 2013 - $80.1 million). Provisions for decommissioning obligations related to assets sold were $3.5 million (year ended December 31, 2013 - $7.9 million), and the gain on sale of assets was $2.7 million (year ended December 31, 2013 - $1.8 million).

4. BANK LOANS

At September 30, 2014, the Company has a $31 million extendible committed term bank facility with a Canadian bank. If this revolving operating loan facility is not extended at its term date of May 30, 2015, any outstanding advances would become repayable one year later on May 30, 2016.

Under the agreement, advances can be drawn in Canadian funds and bear interest at the bank's prime lending rate or guaranteed notes discount rates plus applicable margins. These margins vary from 2.25% to 3.25% depending on the borrowing option chosen by the Company.

The Company had no operating loans outstanding as at and during the nine months ended September 30, 2014. The average effective interest rate on advances under the Company's operating loan facilities during the nine months ended September 30, 2013 was 5.5%. The Company had $0.1 million in letters of credit outstanding at September 30, 2014 that reduce the amount of credit available to the Company.

Loans are secured by general security agreements providing security interests over all assets and by guarantees of material subsidiaries.

At September 30, 2014, the Company was in compliance with its financial covenant that the amount of its current liabilities shall not exceed the sum of its current assets and the undrawn availability under the facility at the end of each fiscal quarter. Pursuant to the terms of the bank facility, unrealized gains (losses) on derivative contracts and the current portion of any bank debt, convertible debentures and capital leases, if any, are excluded from the above amounts.

5. DECOMMISSIONING OBLIGATIONS

The Company's decommissioning obligations result from its ownership interest in oil and natural gas assets including well sites and gathering systems. The Company has estimated the net present value of the decommissioning obligations to be $29.0 million as at September 30, 2014 (December 31, 2013 - $30.4 million) based on an undiscounted inflation-adjusted total future liability of $48.0 million (December 31, 2013 - $49.9 million). These payments are expected to be made over the next 30 years. At September 30, 2014, the liability has been calculated using an inflation rate of 2.0% (December 31, 2013 - 2.0%) and discounted using a risk-free rate of 1.0% to 2.9% (December 31, 2013 - 1.1% to 3.2%) depending on the estimated timing of the future obligation.

6. SHARE CAPITAL

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.

Issued share capital:

Stock options:

The Company has an employee stock option plan under which employees, directors and consultants are eligible to purchase common shares of the Company. Options are granted using an exercise price of stock options equal to the weighted average trading price of the Company's common shares for the five trading days prior to the date of the grant. Options have terms of five year and vest equally over a two or three year period starting on the first anniversary date of the grant.

Changes in the number of options outstanding during the period ended September 30, 2014 and the year ended December 31, 2013 are as follows:

The range of exercise prices of the outstanding options is as follows:

There were no options exercised in the nine months ended September 30, 2014 (September 30, 2013 - nil).

The fair value of the options was estimated using the Black-Scholes model with the following weighted average inputs for the nine months ended September 30, 2014 (there were no options issued during the nine months ended September 30, 2013):

This estimated forfeiture rate is adjusted to the actual forfeiture rate when each tranche vests. Share-based payments of $0.2 million (September 30, 2013 - $0.5 million) were expensed during the nine months ended September 30, 2014. In addition, share-based payments of $0.1 million (September 30, 2013 - $0.2 million) were capitalized during the nine months ended September 30, 2014.

7. LOSS PER SHARE

Basic and diluted loss per share was calculated as follows:

The average market value of the Company's common shares for purposes of calculating the dilutive effect of stock options was based on quoted market prices for the period that the options were outstanding. For the three month and nine months ended September 30, 2014, 16,611,350 options (September 30, 2013 - 12,569,850 options) and 59,316,889 common shares reserved for convertible debentures (September 30, 2013 - 59,316,889) were excluded from calculating diluted loss as they would not have been dilutive.

8. OTHER GAINS (LOSSES)

Other gains (losses) include the following:

9. FINANCE INCOME AND EXPENSES

10. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital is comprised of:

11. FINANCIAL RISK MANAGEMENT

The Company classified the fair value of its financial instruments measured at fair value according to the following hierarchy based on the amount of observable inputs used to value the instrument:

• 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.

The fair value of the derivative contracts used for risk management as shown in the condensed interim consolidated financial statements as at September 30, 2014 and the audited consolidated financial statements as at December 31, 2013 are measured using level 2.

(a) Liquidity risk.

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. The Company's objective is to ensure, as far as possible, that it will always have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions, without incurring unacceptable losses or risking damage to the Company's reputation.

The following are the contractual maturities of financial liabilities, including associated interest payments on convertible debentures and excluding the impact of netting agreements at September 30, 2014:

(b) Market risk.

Market risk is the risk that changes in market prices, such as commodity prices, foreign exchange rates and interest rates, will affect the Company's earnings or the value of the financial instruments. The objective of market risk management is to manage and control market risk exposures within acceptable parameters, while optimizing the return.

The Company may use both financial derivatives and physical delivery sales contracts to manage market risks. All such transactions are conducted within risk management tolerances that are reviewed by the Board of Directors.

Currency risk. Prices for oil are determined in global markets and generally denominated in United States dollars. Natural gas prices are influenced by both U.S. and Canadian supply and demand. The exchange rate effect cannot be quantified, but generally an increase in the value of the Canadian dollar as compared to the U.S. dollar will reduce the prices received by the Company for its petroleum and natural gas sales.

There were no financial instruments denominated in U.S. dollars at September 30, 2014 or December 31, 2013.

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 interest charged on outstanding bank loans fluctuates with the interest rates posted by the lender. The Company has not entered into any mitigating interest rate hedges or swaps, however the Company has $50 million and $46 million of convertible debentures with fixed interest rates of 7.5% and 7.25% respectively, maturing January 31, 2016 and June 30, 2017. The Company had no bank loans outstanding during the nine months ended September 30, 2014.

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 oil and natural gas are impacted by both the relationship between the Canadian and U.S. dollar and world economic events that dictate the levels of supply and demand.

At September 30, 2014 the following derivative contracts were outstanding and recorded at estimated fair value:

The estimated fair value of the contracts has been determined as the amounts the Company would receive or pay to terminate the contracts. At September 30, 2014, the Company estimates that the fair value of this contract is $0.3 million. The fair value would have been impacted as follows had the prices used to estimate the fair value changed by:

In December 2013, the Company entered into a physical sales contract to sell 2,500 GJ per day of natural gas between January 1, 2014 and December 31, 2014 at a weighted average AECO price of $3.72 per GJ. This contract remained in effect at September 30, 2014.

(c) Capital management.

Anderson's objective in managing its capital structure is to safeguard its ability to meet its financial obligations and to fund the future development of its business. The current capital management strategy is designed so that anticipated cash flow from operating activities combined with available credit facilities will fund continued oil and natural gas acquisition, exploration and development activities to grow the value of its asset base for its shareholders. The Company manages its capital structure and makes adjustments to it in the light of changes in economic conditions, the risk characteristics of the underlying assets and its growth opportunities. The Company's capital structure includes adjusted working capital, bank loans, convertible debentures, and shareholders' equity. In order to maintain or adjust the capital structure, the Company may, at different times, adjust its capital spending, dispose of certain assets, hedge future commodity prices, buy back convertible debentures or seek other forms of debt or equity financing.

To assess capital and operating efficiency, the Company monitors its bank debt level and adjusted working capital. It also monitors the ratio of bank debt and other debt to funds from operations (defined as cash flow from operating activities before changes in non-cash working capital and decommissioning expenditures). The Company prepares annual operating and capital 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. Anderson does not pay dividends.

Anderson's current capital structure is summarized below:

For the nine months ended September 30, 2014, funds from operations were $13.3 million (September 30, 2013 - $11.6 million). Funds from operations are dependent on many factors, including the success of oil and natural gas acquisition, exploration and development activities, commodity prices including quality and basis differentials, royalties, operating, administrative and financing costs, and general market conditions.

Funds from operations, adjusted working capital, adjusted working capital deficiency, net debt before convertible debentures, total net debt and total capitalization are not defined by IFRS and therefore are referred to as additional GAAP measures.

The Company is subject to a financial covenant associated with its existing credit facility. See note 4. The Company has complied with this financial covenant for the nine months ended September 30, 2014. The credit facility is subject to an annual review of the borrowing base which is directly impacted by the value of the oil and natural gas reserves.

12. COMMITMENTS AND CONTINGENCIES

At September 30, 2014, the Company has firm service gas transportation agreements in which the Company guarantees that certain minimum volumes of natural gas will be shipped on various gas transportation systems. The terms of the various agreements expire in two to six years. If no volumes were shipped pursuant to the agreements, the maximum amounts payable under the guarantees based on current tariff rates are as follows:

At September 30, 2014, the Company had various obligations under farm-in agreements to drill four gross Cardium horizontal wells to earn working interests in the farm-out lands once it has fulfilled its commitments. Subsequent to September 30, 2014, the Company entered into a pooling and farm-in agreement to drill one additional well. The deadlines to fulfill these commitments range from October 31, 2014 to January 31, 2015. As of November 10, 2014, the Company had drilled two of these wells.

During the second quarter, the Company entered into an agreement to lease office space at a cost of approximately $0.4 million per year from July 1, 2014 to October 30, 2018. The previous office space lease expired on June 30, 2014.