Anderson Energy Ltd.
TSX : AXL

Anderson Energy Ltd.

March 31, 2014 09:00 ET

Anderson Energy Announces 2013 Fourth Quarter and Year End Results

CALGARY, ALBERTA--(Marketwired - March 31, 2014) - Anderson Energy Ltd. ("Anderson" or the "Company") (TSX:AXL) announces its operating and financial results for the fourth quarter and year ended December 31, 2013.

HIGHLIGHTS

  • Anderson commenced a Cardium horizontal light oil winter drilling program using slick water frac technology in November 2013. The average initial production rate over the first 30 days for the first five wells in the program was 458 BOED per well. The best performing well from this winter's drilling program averaged 697 bpd of oil, 755 bpd of oil and NGL and 1,119 BOED in its first 30 days of production.
  • The Company closed all previously announced property dispositions prior to year end. Approximately $80 million in properties were sold during 2013.
  • In October 2013, the Company repaid its bank debt, finalized a new revolving production loan facility for $28 million and concluded its strategic alternatives review process.
  • Production in the fourth quarter of 2013 was 2,448 BOED. Net of production from the sold properties, the Company produced 2,112 BOED, of which 26% was oil and NGL. The Company estimates 2014 production of approximately 2,600 BOED (33% oil and NGL).
  • Proved plus probable ("P&P") BOE reserves were 8.8 MMBOE at December 31, 2013.
  • Cardium P&P reserves were 5.3 MMBOE representing 60% of total P&P reserves volumes and 80% of total P&P reserves value on a pre-tax 10% net present value ("NPV 10") basis.
  • Oil and NGL represent 29% of the Company's proved developed producing ("PDP") reserves, 36% of total proved ("TP") reserves and 42% of P&P reserves on a BOE basis.
  • Anderson's total P&P pre-tax NPV 10 reserves value at December 31, 2013 was $100.3 million. Undeveloped land has been valued at $3.4 million.
  • 118 gross (74.7 net) light oil horizontal drilling locations have been identified. Only 25% of the net locations are recognized as P&P locations in the year end reserve report. Approximately 97% of the net locations are Company operated.

FINANCIAL AND OPERATING HIGHLIGHTS

Three months ended December 31 Year ended December 31
(thousands of dollars, unless otherwise stated) 2013 2012 %
Change
2013 2012 %
Change
Oil and gas sales (1) $ 8,217 $ 15,274 (46% ) $ 53,983 $ 77,806 (31% )
Revenue, net of royalties (1) $ 7,288 $ 13,796 (47% ) $ 48,850 $ 69,815 (30% )
Funds from operations (2) $ (306 ) $ 5,694 (105% ) $ 11,289 $ 29,641 (62% )
Funds from operations per share
Basic and diluted (2) $ - $ 0.03 (100% ) $ 0.07 $ 0.17 (59% )
Adjusted loss before taxes (3) $ (2,745 ) $ (11,799 ) 23% $ (17,386 ) $ (21,738 ) 33%
Adjusted loss before taxes per share(3)
Basic and diluted $ 0.02 $ (0.07 ) 100% $ (0.10 ) $ (0.13 ) 25%
Loss $ (2,445 ) $ (8,895 ) 73% $ (105,601 ) $ (31,493 ) (235% )
Loss per share
Basic and diluted $ (0.01 ) $ (0.05 ) 80% $ (0.61 ) $ (0.18 ) (239% )
Capital expenditures (net of proceeds on dispositions) $ (71,972 ) $ (26,880 ) (168% ) $ (63,895 ) $ (38,990 ) (64% )
Working capital (deficiency) (2) $ 9,682 $ (64,531 ) 115%
Convertible debentures $ 88,922 $ 86,753 3%
Shareholders' equity $ 28,179 $ 132,960 (79% )
Average shares outstanding (thousands):
Basic & Diluted 172,550 172,550 - 172,550 172,550 -
Ending shares outstanding (thousands) 172,550 172,550 -
Average daily sales:
Oil (bpd) 537 1,135 (53% ) 1,059 1,507 (30% )
NGL (bpd) 166 338 (51% ) 237 591 (60% )
Natural gas (Mcfd) 10,467 18,159 (42% ) 13,227 23,878 (45% )
Barrels of oil equivalent (BOED) (4) 2,448 4,500 (46% ) 3,500 6,078 (42% )
Average prices:
Oil ($/bbl) $ 84.26 $ 79.73 6% $ 89.89 $ 83.21 8%
NGL ($/bbl) $ 61.60 $ 52.02 18% $ 55.04 $ 57.20 (4% )
Natural gas ($/Mcf) $ 3.19 $ 3.16 1% $ 2.93 $ 2.21 33%
Barrels of oil equivalent ($/BOE) (4) $ 36.49 $ 36.89 (1% ) $ 42.26 $ 34.98 21%
Realized gain (loss) on derivative contracts ($/BOE) (5) $ (2.96 ) $ 5.39 (155% ) $ (2.75 ) $ 2.44 (213% )
Royalties ($/BOE) $ 4.13 $ 3.57 16% $ 4.02 $ 3.59 12%
Operating costs ($/BOE) $ 14.31 $ 12.11 18% $ 13.25 $ 10.90 22%
Transportation costs ($/BOE) $ 0.28 $ 0.10 180% $ 0.31 $ 0.22 41%
Operating netback ($/BOE) (3)(5) $ 14.81 $ 26.50 (44% ) $ 21.93 $ 22.71 (3% )
Reserves (MBOE): (4)
Total proved 5,311 10,297 (48% )
Total proved plus probable 8,822 17,770 (50% )
Wells drilled (gross) 3 4 (25% ) 5 7 (29% )
(1) Includes royalty and other income classified with oil and gas sales, but excludes realized and unrealized gains or losses on derivative contracts.
(2) Funds from operations, funds from operations per share, working capital and working capital (deficiency) are considered additional GAAP measures. Refer to the section entitled "Additional GAAP Measures" in the Management's Discussion and Analysis ("MD&A") for a more complete description of these additional GAAP measures.
(3) Adjusted loss before taxes, adjusted loss before taxes per share and operating netback per BOE are considered non-GAAP measures. Refer to the section entitled "Non-GAAP Measures" in the MD&A for a more complete description of these non-GAAP terms, reconciliations to more closely related GAAP measures, and the purposes for which management uses the non-GAAP measures. These non-GAAP measures may not be comparable with the calculation of similar measures for other entities.
(4) 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.
(5) Excludes realized loss of $0.2 million related to derivative contracts settled upon the sale of the Garrington and Ferrier Cardium assets.

COMPLETION OF STRATEGIC REVIEW PROCESS

In October 2013, the Company announced that it had concluded its strategic alternatives review process. Over the prior year and a half, a Special Committee of the Board of Directors had investigated various options to enhance shareholder value, including the sale of the Company. At the conclusion of the process, the Company had achieved the following:

  • sold over $150 million in assets;
  • reduced bank debt from $106.7 million at March 31, 2012 to nil at December 31, 2013;
  • reduced overall debt (defined for this purpose as bank debt plus other working capital before unrealized gains and losses on derivative contracts, plus the face value of convertible debentures) from $230.4 million at March 31, 2012 to $86.3 million at December 31, 2013;
  • reduced decommissioning obligations from $59.2 million at March 31, 2012 to $30.4 million at December 31, 2013, and by a further $3.0 million subsequent to year end;
  • restructured its shallow gas and Cardium drilling commitments so that by the end of January 2013, the Company had completed all of these drilling commitments;
  • demonstrated the improved production performance from slick water fracture stimulation; and
  • continued to be an industry leader in keeping drilling and completion costs low in the Cardium horizontal light oil play.

Asset sales during the strategic alternatives process were driven by a desire to reduce bank debt. By the fourth quarter of 2013, bank debt was reduced to zero, the Company had surplus cash and a $28 million unused bank line. The completion of the asset sale in October 2013 ended the strategic alternatives process and forged a new single bank relationship with Alberta Treasury Branches who had been part of the previous three bank syndicate.

STRATEGY

Coming out of the strategic alternatives process, the Company is substantially smaller in terms of production, has cash in the bank and has an unused bank operating line. The Company has also lost its analyst coverage and has an admittedly weak share price. The overall market for public junior oil and gas companies has been very weak in the past 18 months. Although Anderson has no bank debt, it does have convertible debentures maturing in 2016 and 2017. The Company's business plan is to pursue growth of its asset base and cash flow, and increase its financial flexibility to meet its obligations when they become due. A strategy of increasing oil assets, production and cash flow should support a higher borrowing base over time.

The current share price reflects the uncertainty associated with the recently completed strategic alternatives process, the lack of drilling activity during the process and a debt to cash flow ratio that is currently too high. With the bank debt issues resolved, Anderson intends to focus on rebuilding its asset base by drilling Cardium horizontal light oil wells, and growing its Cardium horizontal oil drilling inventory in the Willesden Green, West Pembina and Buck Lake areas. The Company expects it will take time to foster new investor interest in the stock, until it can demonstrate consistent growth in annual oil production. The longer term debenture maturities give the Company time to rebuild its asset base. By resuming a drilling program and controlling the infrastructure in its Cardium oil properties where feasible, the Company should be able to increase oil production and operating netbacks.

Anderson will continue to optimize, rationalize, consolidate and improve the profitability of its shallow gas business. The Company is not planning any significant new investments in the shallow gas business, and may dispose of some or all of the shallow gas assets.

In the fourth quarter of 2013 and the first quarter of 2014, the Company disposed of its unprofitable shallow gas assets. The Company's remaining shallow gas properties are profitable at current natural gas prices.

The Company has no plans to dispose of its Cardium oil assets.

Anderson continues to implement new approaches in Cardium horizontal drilling and completion technology to improve the profitability of its Cardium oil operation. Recent technological changes include repositioning the trajectory of the horizontal well within the Cardium zone to maximize frac effectiveness and using dissolvable frac balls. In 2014, the Company plans to drill its first long reach horizontal oil well that is expected to traverse up to 3,000 metres of horizontal Cardium net pay. It is anticipated that this well will access Cardium reserves in two sections of land as opposed to the current one section of land per horizontal well. There is a capital cost benefit to drilling an extended reach well over two sections as compared to two wells traversing one section of land each. There is also a reserves benefit with longer horizontal wells due to additional reservoir contact.

The goal is to have Cardium wells payout in approximately one year on average. Currently, Anderson has drilled several wells that have or will payout in a year and will continue to focus on driving the average well payout down. The Company operates over 90% of its production and almost all of its drilling operations. 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 in order to reduce overall operating costs.

Anderson is developing new light oil horizontal plays on its existing acreage in the Mannville and Belly River and is planning to drill one of these plays in the remainder of 2014.

TIMING OF STRATEGY

As a result of the 2012 and 2013 asset dispositions, the financial results for the fourth quarter 2013 and for the year ended December 31, 2013 are not indicative of future operations. The current winter drilling program is expected to have a positive impact on the first and second quarters of 2014, as operating netbacks on Cardium drilling operations were approximately $40 per BOE in the fourth quarter of 2013. The Company drilled 7 gross (7.0 net) wells this winter that are expected to materially add to its production in 2014. The Company will be reviewing its capital program at the end of the first quarter.

WINTER DRILLING PROGRAM

This winter, Anderson embarked on a seven well drilling program. The program started a few weeks later than planned in order to use the same drilling rig that was used last year, which helped to keep drilling costs low. Two of the seven wells in the program were originally planned to be on-stream in late January, however the solution gas from these two wells was destined to go to a third party natural gas plant that suffered a plant outage which lasted almost a month. This outage is now over and these oil wells and their solution gas are on-stream. The other five wells in the program were unaffected by the third party plant outage.

The best performing well from this winter's drilling program averaged 697 bpd of oil, 755 bpd of oil and NGL and 1,119 BOED in its first 30 days of production.

Results from the program to date are shown in table below:

Average Gross Initial Production for first 30 days (IP 30) (1)
Number of wells in average 5
Barrels of oil per day (BOPD) 297
Barrels of oil and NGL per day (BPD) 320
Barrels of oil equivalent per day (BOED) (2) 458
(1) Short term production rates can be influenced by flush production effects from fracture stimulation in horizontal wellbores and may not be indicative of longer term production performance. Individual well performance can vary.
(2) 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.

The remaining two wells in the winter program were brought on production late in the first quarter and do not have 30 days of production history. The Company will have IP30 data for all the wells in its winter drilling program by the time it reports its first quarter results for 2014.

The comparable IP 30 data for the slick water drilling programs from last year was 301 bpd of oil, 329 bpd of oil and NGL and 453 BOED for seven wells. Last winter's program included four wells drilled and completed with slick water fracture stimulation in Garrington and Ferrier which were sold in October 2013.

DRILLING AND COMPLETION COSTS

Drilling and completion costs for this year's drilling program averaged $2.3 million per well and were very similar to the prior year.

LIGHT OIL HORIZONTAL DRILLING INVENTORY

The Company's undeveloped light oil horizontal drilling inventory at March 28, 2014, after completion of the winter drilling program, is outlined below:

Prospect Area (number of drilling locations) Gross Net*
Willesden Green Cardium 84 59.7
West Pembina/Buck Lake Cardium 26 7.7
Mannville/Belly River 8 7.3
Total Light Oil Horizontal Drilling Inventory, March 28, 2014 118 74.7
* Net is net revenue interest

GLJ booked undeveloped reserves to 23.3 net locations at December 31, 2013, of which 4.0 net locations were drilled in the first quarter of 2014 and the remaining 19.3 net locations are included in the table above. The locations booked by GLJ include 1.8 net locations related to the Mannville / Belly River prospect area.

Four gross (2.2 net) locations are on lands where the Company's development plan is to drill extended reach horizontal wells traversing two sections of land.

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 has not yet proved this play to be commercial and therefore it is not included in the drilling inventory table above.

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

ACQUISITIONS, DISPOSITIONS AND FARM-INS

As part of the rationalization of its natural gas portfolio, the Company completed two additional property dispositions after the conclusion of the strategic alternatives process.

On November 28, 2013, the Company sold 860 Mcfd of shallow gas production for proceeds of $2.1 million. Approximately 88% of the production from this property was scheduled to be shut-in on December 1, 2013, as the outside operated downstream sales gas system was being converted into a liquids rich high pressure gathering system. Although this property had been profitable when it was producing, the capital cost and time lag required to bring it back on-stream was significant and the Company elected to sell the asset as opposed to spending the additional dollars to resume production. This sale reduced the Company's decommissioning obligation by $1.3 million.

On February 28, 2014, the Company closed a transaction whereby it disposed of 107 wellbores, 31 compressor stations and 880 Mcfd of forecasted 2014 shallow gas production. This property had a historical operating cost of approximately $4.00 per Mcf and average royalties of approximately 10%. This non-operated property has generated negative cash flow in the past two years and was expected to have negative cash flow in 2014 if not sold. This transaction is accretive on a cash flow basis to the Company as it reduces annualized operating expenses by $1.3 million and reduces decommissioning obligations by $3.0 million. These lands have no further development potential.

In the first quarter of 2014, the Company also committed to three property acquisitions and two minor property dispositions for a net cost of $0.8 million, which resulted in 6.0 gross (4.5 net) drilling locations. The Company considers the newly acquired lands to be very prospective for Cardium and Mannville drilling.

2014 CAPITAL PROGRAM

The Company commenced a 14 month, $33 million capital program in November 2013, of which 90% is directed toward the drilling, completion, equipping and tie-in of 11 net Cardium wells. Approximately $7.5 million of those funds were spent in 2013 to drill and complete one Cardium well, drill two additional Cardium wells, acquire surface leases and tangible equipment, and commence construction on the remainder of the winter program.

In November 2013, the Company estimated 2014 production to average 2,600 BOED. This estimate was made assuming the Company would only drill in the winter months of the year. The Company will be reviewing its capital program and guidance when it releases its financial and operating results for the first quarter of 2014. The Company will be reviewing whether greater production efficiency can be achieved by increasing the capital program to drill eight to nine months per year.

On March 24, 2014, Anderson received notice from TransCanada Pipelines Ltd. ("TransCanada") that as a result of an Order by the National Energy Board to reduce maximum operating pressure on the Nova Gas Transmission Ltd. system, transportation service at certain meter stations where the Company delivers natural gas will be fully restricted. The Company currently delivers approximately 1 MMcfd to these meter stations and has been advised that it will be required to shut in this production starting on or about April 24, 2014. TransCanada has not announced an estimate of the duration of the interruption. The Company is currently in the process of assessing the direct and indirect implications of the Order on its operations.

COMMODITY PRICES

The 2013 WTI oil price averaged $97.95 US per bbl ($100.95 Canadian per bbl). Differentials from Cushing, Oklahoma to Edmonton averaged $7.57 US per bbl. Anderson's average wellhead price was $89.89 Canadian per bbl. This compares to a 2012 WTI average oil price of $94.20 US per bbl ($94.10 Canadian per bbl), a differential of $7.87 US per bbl and an average Anderson wellhead price of $83.21 Canadian per bbl. Average wellhead prices are before hedging. The difference between Anderson's wellhead price and WTI Canadian is due to the price differential between Cushing, Oklahoma and Edmonton, oil transportation costs from the field to Edmonton and adjustments for oil quality.

The average 2013 NYMEX gas price was $3.73 US per MMBtu compared to $2.82 US per MMBtu in 2012. The 2013 AECO gas price averaged $3.01 per GJ ($3.17 per MMbtu) in 2013 compared to $2.26 per GJ ($2.38 per MMbtu) in 2012. Anderson's average plant gate price in 2013 was $2.93 per Mcf compared to $2.21 per Mcf in 2012. The difference between the AECO price and Anderson's plant gate price is due to transportation costs and the heat content of the gas.

The 2014 monthly WTI Canadian oil prices were $103.80 in January and $111.30 per bbl in February. Differentials from Cushing, Oklahoma to Edmonton were $13.07 US per bbl in January and $5.07 US per bbl in February. March prices to date have averaged approximately $111.60 WTI Canadian per bbl. AECO natural gas prices were $4.06 per GJ ($4.28 per MMBtu) in January and $7.19 per GJ ($7.58 per MMBtu) in February. March prices to date have averaged approximately $5.08 per GJ ($5.36 per MMBtu). Anderson's average plant gate price would be approximately $0.24 per MMBtu less than AECO excluding hedging.

Going forward, Anderson estimates that light oil prices will stay strong but will be volatile and will be influenced by geopolitical events. Cushing, Oklahoma to Edmonton differentials will continue to be volatile, as well as movements in the US dollar exchange rate.

In the first quarter of 2014, North American winter weather has contributed to much stronger natural gas pricing than we have seen in recent years. The winter weather has also reduced North American natural gas storage to levels we have not seen for many years. This should contribute to stronger natural gas pricing this summer compared to recent prior years. However, the forward strip pricing for natural gas remains disappointing. The Company currently has no plans to commence drilling operations for shallow natural gas as the current futures prices are inadequate to generate a competitive economic return. The Company has not drilled a shallow gas well since January 2010. The economics for horizontal light oil drilling are superior to any natural gas drilling available on Company's lands. With stronger natural gas pricing this winter, the Company has returned all of its operated shut-in gas to production. However, this production could be shut-in again if natural gas prices decline.

Natural gas prices are influenced by weather events and are tempered by the increasing supply of new shale gas. Until meaningful exports of natural gas commence from North America through liquefied natural gas projects, the Company believes that natural gas prices will be range-bound by weather events.

COMMODITY HEDGING CONTRACTS

Natural Gas

The Company has entered into fixed price physical contracts to sell 2,500 GJs per day for January 1, 2014 to December 31, 2014 at an average AECO price of $3.72 per GJ. The Company has entered into fixed price derivative contracts to sell 2,500 GJs per day for January 1, 2014 to December 31, 2014 at an average AECO price of $3.55 per GJ.

Crude Oil

The Company has not hedged any crude oil volumes at this time.

The Company enters into hedging contracts to protect its capital program and continues to evaluate the merits of additional commodity hedging as part of a price management strategy.

RESERVES

GLJ Petroleum Consultants ("GLJ"), an independent evaluator, has completed a reserves report (the "GLJ Report") of all the Company's oil and natural gas properties effective December 31, 2013, prepared in accordance with procedures and standards contained in National Instrument 51-101 of the Canadian Securities Administrators ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook"). The reserves definitions used in preparing the report are those contained in the COGE Handbook and NI 51-101. As of December 31, 2013, the Company had 3,447 MBOE PDP reserves (29% oil & NGL), 5,311 MBOE TP reserves (36% oil & NGL) and 8,822 MBOE P&P reserves (42% oil & NGL). The GLJ price forecast used in the evaluation is shown in Management's Discussion and Analysis for the year ended December 31, 2013.

The reserves report reflects the disposition of approximately $80 million in properties in 2013. The Cardium formation represents approximately 39%, 49% and 60% respectively of PDP, TP and P&P total BOE reserves volumes and 74%, 77% and 80% respectively of the total Company PDP, TP and P&P NPV 10 value. The Edmonton Sands shallow gas project represents approximately 9% of the total Company P&P NPV 10 value.

Of the seven wells drilled in the 2013 / 2014 winter drilling program, GLJ recognized one well as proved developed producing, two wells as proved developed non-producing, one well as proved undeveloped and one well as probable undeveloped. The two remaining wells were not recognized by GLJ in the year end reserves report.

The shut-in gas volumes that were returned to production in the first quarter are recognized by GLJ as proved developed non-producing in the year end reserves report.

SUMMARY OF OIL AND GAS RESERVES

December 31, 2013 December 31, 2012
Gross Working Interest Oil and Gas Reserves Oil (Mbbls ) NGL
(Mbbls
) Gas (MMcf ) Total (MBOE ) Pre-tax
NPV 10
($M
) Oil (Mbbls ) NGL
(Mbbls
) Gas (MMcf ) Total (MBOE ) Pre-tax
NPV 10
($M
)
Proved developed producing 792 216 14,639 3,447 43,153 2,089 595 25,150 6,875 114,369
Proved developed non-producing 128 25 3,683 767 7,527 69 45 4,635 887 7,438
Total proved 1,608 313 20,336 5,311 61,608 3,480 964 35,118 10,297 143,960
Proved plus probable 3,150 565 30,642 8,822 100,312 6,709 1,814 55,475 17,770 224,826
CONTINUITY OF GROSS WORKING INTEREST RESERVES
Total Proved Developed Producing
(MBOE
) Total Proved (MBOE ) Total Proved
Plus Probable
(MBOE
)
Opening Balance, December 31, 2012 6,875 10,297 17,770
Extensions and improved recovery 173 412 332
Technical revisions 140 261 (84 )
Acquisitions 24 114 164
Dispositions (2,488 ) (4,496 ) (8,083 )
Production (1,277 ) (1,277 ) (1,277 )
Closing Balance, December 31, 2013 3,447 5,311 8,822

The Company will provide more detailed information from its current reserves report in its Annual Information Form for the year ended December 31, 2013.

UNDEVELOPED LAND

Anderson has 226,343 gross (132,355 net) developed acres and 65,048 gross (27,988 net) undeveloped acres of land at December 31, 2013. Undeveloped land has been valued at $3.4 million by management.

OWNERSHIP

The management team of Anderson has been together for the last 12 years in the Company's private and public phases. They currently own 5.9 million shares, adding 0.9 million shares in 2013. Including current Board members, insiders own 18.2 million shares. Both management and the Board are long term shareholders. We have a vested interest in making this Company work and although we have had difficult times in the past couple of years, we believe that we can work things out and resurrect the stock price. We admit that it will take time, but we have a business plan in the Cardium light oil resource play that we believe will accomplish our goals and objectives.

I appreciate the support of the Board of Directors, the Company employees and our patient shareholders through a difficult year. We have repositioned ourselves to be more operationally active in 2014 which should benefit all of our shareholders.

SUMMARY

In summary, our winter program achieved the planned operational results. The Company continues to add to its Cardium drilling inventory and continues to make progress in rationalizing its legacy shallow gas asset base. More production data on the winter program will be available by the time we present our financial and operating results for the first quarter of 2014. A more fulsome discussion on remaining capital spending for 2014 will also be available at that time.

Brian H. Dau

President & Chief Executive Officer

March 31, 2014

Management's Discussion and Analysis

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

The following management's discussion and analysis ("MD&A") is dated March 28, 2014 and should be read in conjunction with the audited consolidated financial statements of Anderson Energy Ltd. ("Anderson" or the "Company") for the years ended December 31, 2013 and 2012. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") and interpretations of the IFRS Interpretations Committee ("IFRIC").

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

Anderson focused on improving its overall financial position and revitalizing its strategy during 2013. The Company initiated a strategic review process in February 2012 and concluded the process in October 2013. During this time, the Company:

  • sold over $150 million in assets ($80.1 million during 2013);
  • reduced bank debt to nil at December 31, 2013 (from $106.7 million at March 31, 2012);
  • reduced decommissioning obligations from $59.2 million at March 31, 2012 to $30.4 million at December 31, 2013;
  • restructured its shallow gas and Cardium drilling commitments so that by the end of January 2013, the Company had completed all of these commitments;
  • demonstrated the improved production performance from slick water fracture stimulation; and
  • continued to be an industry leader in keeping drilling and completion costs low in the Cardium horizontal light oil play.

Consistent with the results reported in the first three quarters of 2013, revenue and production for the three-month period and year ended December 31, 2013 were lower than the same periods last year, primarily due to the sale of assets in 2012 and 2013 and the impact of a curtailed drilling program on the replacement of natural declines. Total production sold was approximately 1.1 MBOED (2012 - 2.3 MBOED).

The Company ended 2013 with no bank debt and positive working capital(1) of $9.7 million at December 31, 2013, compared to bank loans plus a working capital (deficiency) of $64.5 million at December 31, 2012. During the 2013 financial year, the Company generated $11.3 million in funds from operations(2) and reported a loss of $105.6 million. The reported loss includes an impairment of $44.6 million related to assets sold in the fourth quarter of 2013 and income tax expense of $45.6 million related to the derecognition of the Company's deferred tax asset in the second quarter of 2013. The Company also spent $16.2 million in capital expenditures and sold assets for total consideration of $80.1 million.

(1) Working capital or working capital (deficiency) are considered additional GAAP measures. Refer to the section entitled "Additional GAAP measures" at the end of this MD&A.
(2) Funds from operations are considered an additional GAAP measure. Refer to "Funds from Operations" in this section and the section entitled "Additional GAAP Measures" at the end of this MD&A.

In October 2013, the Company sold its Garrington and Ferrier Cardium oil and natural gas properties for net proceeds of $78.0 million after closing adjustments and fees and expenses. These properties produced approximately 1,000 BOED (65% oil and NGL). In November 2013, the Company sold 860 Mcfd of shallow gas production for net proceeds of $2.1 million.

PRODUCTION
Three months ended
December 31
Year ended
December 31
2013 2012 2013 2012
Oil (bpd) 537 1,135 1,059 1,507
NGL (bpd) 166 338 237 591
Natural gas (Mcfd) 10,467 18,159 13,227 23,878
Total (BOED)(6) 2,448 4,500 3,500 6,078
PRICES
Three months ended
December 31
Year ended
December 31
2013 2012 2013 2012
Oil ($/bbl)(1) $ 84.26 $ 79.73 $ 89.89 $ 83.21
NGL ($/bbl) 61.60 52.02 55.04 57.20
Natural gas ($/Mcf)(2) 3.19 3.16 2.93 2.21
Total ($/BOE)(3)(6) $ 36.49 $ 36.89 $ 42.26 $ 34.98
OIL AND NATURAL GAS SALES
Three months ended
December 31
Year ended
December 31
(thousands of dollars) 2013 2012 2013 2012
Oil(1) $ 4,162 $ 8,328 $ 34,742 $ 45,896
NGL 943 1,619 4,751 12,373
Natural gas(2) 3,067 5,277 14,135 19,282
Royalty and other 45 50 355 255
Total oil and gas sales $ 8,217 $ 15,274 $ 53,983 $ 77,806
OPERATING NETBACK
Three months ended
December 31
Year ended
December 31
(thousands of dollars) 2013 2012 2013 2012
Revenue(1)(3) $ 8,217 $ 15,274 $ 53,983 $ 77,806
Realized gain (loss) on derivative contracts(4) (666 ) 2,231 (3,516 ) 5,429
Royalties (929 ) (1,478 ) (5,133 ) (7,991 )
Operating expenses (3,222 ) (5,016 ) (16,915 ) (24,239 )
Transportation expenses (63 ) (39 ) (401 ) (498 )
Operating netback(4)(5) $ 3,337 $ 10,972 $ 28,018 $ 50,507
Sales volume (MBOE)(6) 225.2 414.0 1,277.5 2,224.4
Per BOE(6)
Revenue(1)(3) $ 36.49 $ 36.89 $ 42.26 $ 34.98
Realized gain (loss) on derivative contracts(4) (2.96 ) 5.39 (2.75 ) 2.44
Royalties (4.13 ) (3.57 ) (4.02 ) (3.59 )
Operating expenses (14.31 ) (12.11 ) (13.25 ) (10.90 )
Transportation expenses (0.28 ) (0.10 ) (0.31 ) (0.22 )
Operating netback(4)(5) $ 14.81 $ 26.50 $ 21.93 $ 22.71
  1. The three-month numbers exclude the realized loss of $0.9 million and unrealized gain of $0.9 million on derivative contracts, respectively during 2013 (2012 - $2.2 million gain and $2.8 million loss, respectively). The yearly numbers exclude the realized loss of $3.7 million and unrealized gain on derivative contracts of $1.0 million during 2013 (2012 - $5.4 million gain and $2.5 million loss, respectively).
  2. Includes gain on fixed price natural gas contracts of nil in 2013 (2012 - $0.1 million).
  3. Includes royalty and other income classified with oil and gas sales.
  4. Excludes realized loss of $0.2 million related to derivative contracts settled upon the sale of the Garrington and Ferrier Cardium assets.
  5. Operating netback is considered a non-GAAP measure. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.
  6. Barrels of oil equivalent ("BOE") may be misleading, particularly if used in isolation. Refer to the section entitled "Conversion Measures" at the end of this MD&A.

Production

Average production volumes in the fourth quarter of 2013 compared to the third quarter of 2013 were as follows:

Three months ended
December 31, 2013 September 30, 2013
Oil (bpd) 537 983
NGL (bpd) 166 280
Natural gas (Mcfd) 10,467 13,119
Total (BOED) 2,448 3,449

Approximately 1.1 MBOED of total production was sold in the fourth quarter of 2013, contributing to the decline in production from 3,449 BOED in the third quarter to 2,448 BOED in the fourth quarter of 2013. As the properties were sold part way through the fourth quarter, there was still 336 BOED of production from these properties reported in the fourth quarter of 2013.

Overall, production volumes in the fourth quarter decreased 46% in 2013 compared to the fourth quarter of 2012; whereas production volumes for 2013 decreased by 42% compared to 2012.

The Company estimates 2014 production will be approximately 2,600 BOED of which 33% is estimated to be from oil and natural gas liquids production. The first and second quarters of 2014 will benefit from increased oil production as a result of the 2013 / 2014 winter drilling program. One of the seven wells in the winter drilling program came on-stream in December 2013 and the remaining six wells came on-stream at various times during the first quarter of 2014.

On March 24, 2014, Anderson received notice from TransCanada Pipelines Ltd. ("TransCanada") that as a result of an Order by the National Energy Board to reduce maximum operating pressure on the Nova Gas Transmission Ltd. system, transportation service at certain meter stations where the Company delivers natural gas will be fully restricted. The Company currently delivers approximately 1 MMcfd to these meter stations and has been advised that it will be required to shut in this production starting on or about April 24, 2014. TransCanada has not announced an estimate of the duration of the interruption. The Company is currently in the process of assessing the direct and indirect implications of the Order on its operations.

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. These differentials averaged $6.95 US per bbl discount in the first quarter of 2013, improved to $3.67 and $4.72 US per bbl in the second and third quarters, respectively, then widened significantly to average $14.93 US per bbl in the fourth quarter of 2013. The average differential for the year ended December 31, 2013 was a $7.57 US discount per bbl (2012 - $7.87 US per bbl). Going into 2014, light, sweet oil differentials are expected to remain volatile depending on supply, transportation alternatives and refining demand. Differentials in the first quarter of 2014 averaged $8.25 US discount per bbl.

Natural gas prices remained low throughout most of 2013. Prices have improved significantly in the first few months of 2014 due to higher demand related to colder weather conditions in North America, but longer term markets have not seen the same increase. To date in the first quarter of 2014, AECO 5A prices have averaged approximately $5.40 per GJ. Forward strip prices for AECO are approximately $4.00 per GJ for 2015 and $3.75 per GJ for 2016.

The Company's average natural gas sales price was $3.19 per Mcf for the three months ended December 31, 2013, 41% higher than the third quarter of 2013 price of $2.27 per Mcf and 1% higher than the fourth quarter of 2012 price of $3.16 per Mcf. For the year ended December 31, 2013, the Company's average natural gas sales price was $2.93 per Mcf compared to $2.21 per Mcf for 2012.

Derivative contracts

At December 31, 2013, the following fixed price swap contract based on the AECO 5A natural gas price was outstanding and recorded at estimated fair value:

Period Weighted
average volume
(GJ/d
) Weighted average
Canadian
($/GJ
)
January 1, 2014 to December 31, 2014 2,500 3.55

By comparison, AECO 5A averaged $3.35 per GJ in the fourth quarter of 2013 and $2.31 per GJ in the third quarter of 2013. To date in 2014, AECO 5A has averaged $4.06 per GJ for January, $7.19 per GJ for February and approximately $5.08 per GJ in March to date.

Derivative contracts had the following impact on the consolidated statements of operations:

Three months ended
December 31
Year ended
December 31
(thousands of dollars) 2013 2012 2013 2012
Realized gain (loss) on derivative contracts $ (868 ) $ 2,231 $ (3,718 ) $ 5,429
Unrealized gain (loss) on derivative contracts 899 (2,828 ) 951 (2,481 )
Total gain (loss) on derivative contracts $ 31 $ (597 ) $ (2,767 ) $ 2,948

The outstanding natural gas fixed price swap contract resulted in an unrealized loss of $0.1 million at December 31, 2013. The remaining realized and unrealized losses on derivate contracts related to crude oil fixed price swap contracts that expired at the end of 2013.

After closing the sale of the Garrington and Ferrier Cardium assets in October 2013, the Company settled 300 bpd of derivative contracts for the months of November and December 2013 for a loss of $0.2 million. Although this loss was reflected in the financial results for the fourth quarter of 2013, it was excluded from the calculation of the realized oil price for the fourth quarter and year ended December 31, 2013.

The realized oil price including the impact of the applicable realized gains and losses on derivative contracts was $70.77 per barrel for the fourth quarter of 2013 and $80.79 per barrel for the year, compared to $101.08 per barrel for the fourth quarter of 2012 and $93.06 for the year ended December 31, 2012.

Fixed price contracts

The Company had no fixed price natural gas contracts for the year ended December 31, 2013 (2012 - realized gains on fixed price natural gas contracts of $0.1 million). 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 AECO 5A average daily index price.

Royalties

For the year ended December 31, 2013, the average rate for royalties was 9.5% of revenue (December 31, 2012 - 10.3%). For the fourth quarter of 2013, the average rate for royalties was 11.3% of revenue compared to 10.1% of revenue in the third quarter of 2013 and 9.7% of revenue in the fourth quarter of 2012. Oil wells drilled by the Company on Crown lands qualify for royalty incentives that reduce average Crown royalties for periods of up to 36 months from initial production, after which Crown royalties are expected to increase from current levels.

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

Three months ended
December 31
Year ended
December 31
2013 2012 2013 2012
Gross Crown royalties 8.9% 9.4% 6.1% 8.5%
Gas cost allowance (3.1% ) (3.8% ) (2.6% ) (3.8% )
Other royalties 5.5% 4.1% 6.0% 5.6%
Total royalties 11.3% 9.7% 9.5% 10.3%
Total royalties ($/BOE) $ 4.13 $ 3.57 $ 4.02 $ 3.59

Operating expenses

For the year ended December 31, 2013, operating expenses were $13.25 per BOE (December 31, 2012 - $10.90 per BOE). For the fourth quarter of 2013, operating expenses were $14.31 per BOE compared to $14.47 per BOE in the third quarter of 2013 and $12.11 per BOE in the fourth quarter of 2012. Operating expenses on a per BOE basis were affected by the impact of the 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. Following the sale of the oil properties, the Company had a larger proportion of natural gas properties that contributed to higher operating costs per BOE; however the Company expects the winter drilling program in the Cardium formation to result in a greater proportion of operating costs and volumes from the Cardium areas, thereby lowering the Company's average operating costs on a per BOE basis.

Transportation expenses

For the year ended December 31, 2013, transportation expenses were $0.31 per BOE (December 31, 2012 - $0.22 per BOE). For the fourth quarter of 2013, transportation expenses were $0.28 per BOE compared to $0.36 per BOE in the third quarter of 2013 and $0.10 per BOE in the fourth quarter of 2012. The increase in transportation expenses in 2013 was due to higher NGL trucking costs. Also, following the sale of the Garrington and Ferrier properties in the fourth quarter of 2013, the remainder of the Company's oil properties is being trucked to the point of sale.

Depletion and depreciation

Depletion and depreciation was $27.9 million ($21.85 per BOE) for the year ended December 31, 2013 compared to $44.4 million ($19.96 per BOE) in 2012. Depletion and depreciation was $4.3 million ($19.27 per BOE) in the fourth quarter of 2013 compared to $6.9 million ($21.74 per BOE) in the third quarter of 2013 and $9.0 million ($21.70 per BOE) in the fourth quarter of 2012. The decrease in the amount of depletion and depreciation was due to lower overall production volumes. Proved plus probable reserves volumes are included in the determination of depletion expense.

Impairment losses

At December 31, 2013, there were no indicators of impairment in the Company's CGUs; thus, no impairment test was performed.

During the third quarter of 2013, the Company signed a purchase and sale agreement on certain oil and natural gas properties held within the Company's Horizontal Cardium CGU. At September 30, 2013, these properties were classified as assets held for sale as it was highly probable that their carrying amount would be received through a sales transaction rather than through continuing use. The transaction closed in October 2013.

Immediately prior to classifying these properties as assets held for sale, an impairment test was performed on the Company's Horizontal Cardium CGU and it was concluded that no impairment existed, as the value-in-use exceeded the carrying value of the assets. Subsequent to the impairment test, the carrying value of the property, plant and equipment for these certain oil and natural gas properties was transferred to assets held for sale.

At September 30, 2013, 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, for an amount of $84.2 million. Decommissioning obligations related to the assets held for sale were $6.3 million and were recorded separately as a current liability. The determination of fair value was based on the adjusted sales price contained within the signed purchase and sale agreement, net of expenses, of $77.9 million plus the decommissioning obligations assumed by the purchaser. The carrying value of property, plant and equipment transferred to assets held for sale was $44.6 million higher than the fair value less costs to sell and an impairment loss was recorded.

During 2012, declines in forecasted natural gas commodity prices led to an impairment charge of $20 million against the Company's Gas CGU.

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 $1.5 million ($6.54 per BOE) for the fourth quarter of 2013 compared to $1.6 million ($5.19 per BOE) in the third quarter of 2013 and $2.5 million ($6.07 per BOE) for the fourth quarter of 2012. For the year ended December 31, 2013, G&A (cash) expenses were $6.8 million ($5.35 per BOE) compared to $9.2 million ($4.12 per BOE) for 2012. The decrease was due to staff-level reductions in 2012 and decreased rent associated with the office move in the fourth quarter of 2012. Capitalized general and administrative costs were lower for similar reasons. Capitalized general and administrative costs consist of salaries, benefits and office rent associated with staff involved in capital activities.

Costs associated with the strategic alternatives process amounted to $1.7 million over a two year period, of which $0.9 million was offset against proceeds of asset dispositions and $0.8 million was recorded as G&A (cash) expenses in 2012 and 2013 ($0.3 million in 2013 and $0.5 million in 2012).

Although G&A (cash) expenses decreased by 41% for the three months ended December 31, 2013 and by 25% for the year ended relative to the same periods for 2012, the Company's production volumes decreased by greater percentages (46% and 42%, respectively); thus, the G&A (cash) expenses per BOE increased over the comparative periods.

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

Three months ended
December 31
Year ended
December 31
(thousands of dollars) 2013 2012 2013 2012
Gross G&A (cash) expenses $ 2,129 $ 3,264 $ 9,317 $ 13,374
Overhead recoveries (251 ) (234 ) (1,039 ) (1,207 )
Capitalized (406 ) (515 ) (1,443 ) (2,999 )
Net G&A (cash) expenses(1) $ 1,472 $ 2,515 $ 6,835 $ 9,168
Net share-based compensation 108 3 183 547 756
General and administrative expenses $ 1,580 $ 2,698 $ 7,382 $ 9,924
G&A (cash) expenses ($/BOE)(1) $ 6.54 $ 6.07 $ 5.35 $ 4.12
% Capitalized 19 % 16 % 15 % 22 %
  1. General and administrative (cash) expenses is considered a non-GAAP measure. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.

Share-based compensation

The Company accounts for share-based compensation using the fair value method of accounting, and share-based compensation (net of amounts capitalized) is included in the determination of general and administrative expenses. Share-based compensation costs were $0.1 million for the fourth quarter of 2013 (nil net of amounts capitalized) versus $0.1 million ($0.2 million net of amounts capitalized) in the fourth quarter of 2012. Share-based compensation expense was $0.8 million in 2013 ($0.5 million net of amounts capitalized) versus $1.0 million ($0.8 million net of amounts capitalized) in 2012.

The decreases in this non-cash compensation in the three months and year ended December 31, 2013 compared to the same periods in 2012 was due to staffing reductions in 2012 and lower Black-Scholes values used for new stock option grants.

Finance expenses

Finance expenses were $2.9 million for the fourth quarter of 2013, compared to $3.4 million in the third quarter of 2013 and $3.5 million in the fourth quarter of 2012. Finance expenses were $12.8 million for the year ended December 31, 2013, compared to $14.8 million in the comparable period of 2012. The decrease in finance expenses from 2012 is the result of lower interest and other financing charges associated with the credit facilities. Proceeds from the disposition of assets in the fourth quarter of 2013 were used to repay bank debt, and the Company had no outstanding bank loans in November and December 2013. The average effective interest rate on outstanding bank loans was 5.5% for the year ended December 31, 2013 compared to 4.7% for the comparable period in 2012.

Three months ended
December 31
Year ended
December 31
(thousands of dollars) 2013 2012 2013 2012
Interest and accretion on convertible debentures $ 2,332 $ 2,277 $ 9,254 $ 9,042
Interest expense on credit facilities and other 354 1,017 2,771 4,662
Accretion on decommissioning obligations 199 189 814 1,068
Finance expenses $ 2,885 $ 3,483 $ 12,839 $ 14,772

Decommissioning obligations

The Company's disposition of properties in 2013 and 2012 resulted in significant changes to the Company's decommissioning obligations (2013 - $7.9 million; 2012 - $20.9 million).

Other significant changes included changes in estimates of the Company's decommissioning obligations in the fourth quarter of 2013 due to revised cost estimates, updated discount rates, and revised estimated dates of incurring decommissioning costs.

At each reporting period, the Company updates its current abandonment and reclamation cost estimates based on available information, including available industry information and the Company's specific cost experience. At various times throughout the year, the Company updated the estimated discount rates used to measure the obligations. The risk-free discount rates used by the Company to measure the obligations at December 31, 2013 were between 1.1% and 3.2% (December 31, 2012 - 1.0% to 2.5%) depending on the timelines to reclamation and increased from the start of the year as a result of changes in the Canadian bond market. As of December 31, 2013, a change of 0.1% in discount rates would affect the estimated present value of decommissioning obligations by $0.5 million. The combined impact of updating estimated costs and discount rates contributed a decrease of $4.7 million to the change in estimate for 2013 (2012 - increase $2.7 million).

With the conclusion of the strategic alternatives process and the sale of a significant number of properties over the past two years, at December 31, 2013 the Company updated the estimated future dates for the abandonment and reclamation of its assets. Overall, extending the estimated dates of decommissioning contributed $3.8 million to the overall changes in estimates.

Income taxes

During the second quarter of 2013, the Company derecognized deferred tax assets of $45.6 million in respect of deductible temporary differences due to the material uncertainties related to the outcome of the strategic alternative process.

With the conclusion of the strategic alternative process, the Company assessed the probability that future taxable profit will be available against which the Company can utilize the benefits of tax pools in excess of the carrying amount of assets and recorded $2.0 million of deferred tax assets as of December 31, 2013.

Anderson is not currently taxable and has the following estimated tax pool balances at December 31, 2013. Non-capital losses are estimated assuming certain discretionary claims related to tax pools are made in the current year.

Canadian Exploration Expenses (CEE) $79 million
Canadian Development Expenses (CDE) 29 million
Undepreciated Capital Cost (UCC) 48 million
Non-capital losses 196 million
Share issue costs 3 million
Total $355 million

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.

The following table is a reconciliation of the Company's cash flow from operating activities to funds from operations:

Three months ended
December 31
Year ended
December 31
(thousands of dollars) 2013 2012 2013 2012
Cash from operating activities $ (230 ) $ 6,976 $ 10,520 $ 29,839
Changes in non-cash working capital (671 ) (1,396 ) (202 ) (704 )
Decommissioning expenditures 595 114 971 506
Funds from operations $ (306 ) $ 5,694 $ 11,289 $ 29,641

As expected, following the asset dispositions in the fourth quarter of 2013, funds from operations were a negative outflow of $0.3 million. Funds from operations were $1.4 million in the third quarter of 2013 and $5.7 million in the fourth quarter of 2012. Funds from operations for the year ended December 31, 2013 were $11.3 million, down 62% from the $29.6 million recorded for 2012. The production declines in oil, NGL and natural gas of 30%, 60% and 45%, respectively in the year ended December 31, 2013 compared to December 31, 2012, largely as a result of the asset sales in 2012 and 2013, contributed to the decrease in funds from operations. Losses realized on derivative contracts also contributed to the decrease in funds from operations during the 2013 financial year compared to 2012. The 2013-2014 winter drilling program is expected to contribute positively to oil production and funds from operations in 2014.

Adjusted earnings (loss) before taxes

As detailed at the end of this MD&A, "adjusted earnings (loss) before taxes" is a term that does not have any standardized meaning under GAAP. Adjusted earnings (loss) before taxes is calculated as earnings (loss) before taxes per the Consolidated Statement of Operations and Comprehensive Loss, excluding impairment loss. Refer to the section entitled "Non-GAAP Measures" found at the end of this MD&A.

The following table is a reconciliation of the Company's loss before taxes to adjusted loss before taxes:

Three months ended
December 31
Year ended
December 31
(thousands of dollars) 2013 2012 2013 2012
Loss before taxes $ (2,745 ) $ (11,799 ) $ (61,967 ) $ (41,738 )
Impairment loss - - 44,581 20,000
Adjusted loss from operating activities $ (2,745 ) $ (11,799 ) $ (17,386 ) $ (21,738 )

Earnings

The Company reported a loss of $2.4 million in the fourth quarter of 2013 compared to a loss of $8.9 million in the fourth quarter of 2012. In the fourth quarter of 2013, earnings included a $1.8 million gain on the sale of natural gas properties, while in the fourth quarter of 2012, earnings include a $4.8 million loss on the sale of natural gas properties. The Company reported a loss of $105.6 million for the year ended December 31, 2013 (2012 - $31.5 million loss). The loss included an impairment of $44.6 million related to assets sold in the fourth quarter of 2013 and income tax expense of $45.6 million related to the derecognition of the Company's deferred tax asset in the second quarter of 2013.

SENSITIVITIES

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:

Funds from Operations Earnings
Millions Per Share Millions Per Share
$0.50/Mcf in price of natural gas $ 2.2 $ 0.01 $ 2.2 $ 0.01
US $5.00/bbl in the WTI crude price $ 2.0 $ 0.01 $ 2.0 $ 0.01
US $0.01 in the US/Cdn exchange rate $ 0.5 $ 0.00 $ 0.5 $ 0.00
1% in short-term interest rate $ 0.4 $ 0.00 $ 0.4 $ 0.00

This sensitivity analysis was calculated by applying different pricing, interest rate and exchange rate assumptions to 2013 actual production, prices, royalty rates, operating costs, capital spending and debt levels. As the contribution of oil production increases as a percentage of total production, the impact of oil prices will be more significant and the impact of natural gas prices will be less significant to funds from operations and earnings than is shown in the table above.

CAPITAL EXPENDITURES

The Company spent $8.1 million on capital expenditures and proceeds on dispositions were $80.0 million in the fourth quarter of 2013. Capital expenditures were $16.2 million for the year ended December 31, 2013 and proceeds on disposition were $80.1 million. The breakdown of expenditures is shown below:

Three months ended
December 31
Year ended
December 31
(thousands of dollars) 2013 2012 2013 2012
Land, geological and geophysical costs $ 7 $ 101 $ 135 $ 511
Acquisitions 205 - 205 -
Drilling, completion and recompletion 6,115 8,333 11,230 22,683
Facilities and well equipment 1,320 1,300 3,247 8,884
Capitalized G&A 406 515 1,443 2,999
$ 8,053 $ 10,249 $ 16,260 $ 35,077
Change in compressor and other equipment inventory - (162 ) (106 ) (217 )
Office equipment and furniture 2 15 17 41
Proceeds on disposition (80,027 ) (36,982 ) (80,066 ) (73,891 )
Total net capital expenditures $ (71,972 ) $ (26,880 ) $ (63,895 ) $ (38,990 )
Drilling statistics are shown below:
Three months ended
December 31
Year ended
December 31
2013 2012 2013 2012
Gross Net Gross Net Gross Net Gross Net
Gas - - - - - - - -
Oil 3 3.0 4 4.0 5 4.8 7 6.5
Dry - - - - - - - -
Total 3 3.0 4 4.0 5 4.8 7 6.5
Success rate 100 % 100 % 100 % 100 % 100 % 100 % 100 % 100 %

For the year ended December 31, 2013, the Company drilled 5 gross (4.8 net capital) Cardium horizontal wells. Of the total 5 gross wells drilled, the Company drilled 3 gross (3.0 net capital) Cardium horizontal wells in the fourth quarter of 2013. The Company completed its winter drilling program with an additional 4 gross (4.0 net capital, 4.0 net revenue) wells drilled during the first quarter of 2014.

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, 2013, prepared in accordance with procedures and standards contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook"). The reserves definitions used in preparing the report are those contained in the COGE Handbook and NI 51-101. The tables in this section are excerpts from what will be contained in the Company's Annual Information Form for the year ended December 31, 2013 ("AIF") as the Company's NI 51-101 annual required filings.

At December 31, 2013, the Company's proved developed producing ("PDP"), total proved ("TP") and proved plus probable ("P&P") reserves were 3.4 MMBOE, 5.3 MMBOE and 8.8 MMBOE, respectively.

Oil and NGL reserves represent 29% of PDP, 36% of TP and 42% of the P&P reserves on a BOE basis at December 31, 2013 compared to 39%, 43% and 48%, respectively at December 31, 2012.

GROSS WORKING INTEREST OIL AND GAS RESERVES(1)
As at December 31, 2013
Oil
(Mbbls)
Natural Gas(2)
(MMcf)
Natural Gas Liquids (Mbbls) Total BOE(3)
(MBOE)
Proved developed producing 792 14,639 216 3,447
Proved developed non-producing 128 3,683 25 767
Proved undeveloped 688 2,015 72 1,097
Total proved 1,608 20,336 313 5,311
Probable 1,541 10,307 252 3,512
Total proved plus probable 3,150 30,642 565 8,822
  1. Columns may not add due to rounding.
  2. Coal Bed Methane is not material to report separately and is included in the Natural Gas category.
  3. Barrels of oil equivalent ("BOE") may be misleading, particularly if used in isolation. Refer to the section entitled "Conversion Measures" at the end of this MD&A.
NET PRESENT VALUE BEFORE INCOME TAXES(1)(2)
As at December 31, 2013
GLJ Price Forecast, Escalated Prices
(thousands of dollars) 0% 5% 10% 15% 20%
Proved developed producing 60,295 50,130 43,153 38,049 34,144
Proved developed non-producing 11,116 9,030 7,527 6,408 5,551
Proved undeveloped 28,213 17,413 10,927 6,783 3,992
Total proved 99,624 76,573 61,608 51,239 43,686
Probable 106,479 61,110 38,705 26,221 18,562
Total proved plus probable 206,103 137,683 100,312 77,460 62,248
  1. Columns may not add due to rounding.
  2. The estimated future annual cash flows determined by the independent reserves evaluators include assumptions and estimates related to future revenues, royalties, other items of income, operating costs, net capital investments and well abandonment costs for all wells with reserves at the property level. Additional abandonment costs associated with non-reserves wells, lease reclamation costs and facility abandonment and reclamation expenses have not been included in the analysis. Refer to the Company's Annual Information Form for a more complete description of the determination of the reserves values.

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.

Total future development costs included in the reserves evaluation were $32.8 million for total proved reserves and $68.6 million for proved plus probable reserves. Further details related to future development costs, including assumptions regarding the timing of the expenditures, will be included in the Company's AIF for the 2013 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.

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
As at December 31, 2013
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 ($Cdn/MMBtu ) Propane ($Cdn/bbl ) Butane ($Cdn/bbl ) Pentanes Plus ($Cdn/bbl ) Inflation Rate
%
Exchange rate ($US/$Cdn )
2014 97.50 92.76 4.03 57.83 73.22 105.20 2.0 0.950
2015 97.50 97.37 4.26 58.42 75.95 107.11 2.0 0.950
2016 97.50 100.00 4.50 60.00 78.00 107.00 2.0 0.950
2017 97.50 100.00 4.74 60.00 78.00 107.00 2.0 0.950
2018 97.50 100.00 4.97 60.00 78.00 107.00 2.0 0.950
2019 97.50 100.00 5.21 60.00 78.00 107.00 2.0 0.950
2020 98.54 100.77 5.33 60.46 78.60 107.82 2.0 0.950
2021 100.51 102.78 5.44 61.67 80.17 109.97 2.0 0.950
2022 102.52 104.83 5.55 62.90 81.77 112.17 2.0 0.950
2023 104.57 106.93 5.66 64.16 83.40 114.41 2.0 0.950
Thereafter 2%
CONTINUITY OF GROSS RESERVES(1)
Natural Gas (Bcf) Oil and Natural Gas Liquids (Mbbls)
Proved Probable Total Proved Probable Total
Opening balance December 31, 2012 35.1 20.4 55.5 4,444 4,081 8,523
Extensions and improved recovery 0.7 - 0.6 303 (74 ) 230
Technical revisions 1.1 (.7 ) .4 72 (222 ) (150 )
Acquisitions 0.2 0.1 0.3 86 36 122
Dispositions (11.9 ) (9.4 ) (21.3 ) (2,511 ) (2,027 ) (4,538 )
Production (4.8 ) - (4.8 ) (473 ) - (473 )
Closing balance December 31, 2013(2) 20.3 10.3 30.6 1,921 1,793 3,715
  1. Columns and rows may not add due to rounding.
  2. The closing balance for natural gas includes 38 MMcf of proved and 15 MMcf of probable Coal Bed Methane reserves.

The Company's reserves life indices are 6.9 years total proved and 11.5 years proved plus probable, based on December 2013 monthly average production.

SHARE INFORMATION

The Company's shares have been listed on the Toronto Stock Exchange since September 7, 2005 under the symbol "AXL." As of March 28, 2014, there were 172.5 million common shares outstanding, 15.2 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. No shares were issued through the exercise of employee stock options in 2013 or 2012.

SHARE PRICE ON TSX

2013 2012
High $ 0.25 $ 0.68
Low $ 0.11 $ 0.21
Close $ 0.15 $ 0.24
Volume 44,989,660 45,207,571
Shares outstanding at December 31 172,549,701 172,549,701
Market capitalization at December 31 $ 25,019,707 $ 40,549,180

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 26.5 million common shares traded on these alternative exchanges in 2013 (2012 - 20.2 million). Including these exchanges, an average of 284,737 common shares traded per day in 2013 (2012 - 260,556), representing a turnover ratio of 41% (2012 - 38%).

RELATED PARTY TRANSACTIONS

There were no related party transactions in 2012 and 2013.

LIQUIDITY AND CAPITAL RESOURCES

At December 31, 2013, the Company had no outstanding bank loans, convertible debentures of $96.0 million (principal) and positive working capital of $9.7 million. Proceeds from property dispositions in the fourth quarter of 2013 were used to repay the credit facilities, and the excess cash will be used to help fund the 2013 / 2014 drilling program. The following table shows the changes in bank loans plus working capital (deficiency):

Three months ended
December 31
Year ended
December 31
(thousands of dollars) 2013 2012 2013 2012
Bank loans plus working capital (deficiency), beginning of period $ 16,499 $ (96,991 ) $ (64,531 ) $ (132,656 )
Funds from operations (306 ) 5,694 11,289 29,641
Proceeds on disposition of assets, net of capital expenditures 71,972 26,880 63,895 38,990
Change in assets held for sale included in working capital (deficiency) (84,196 ) - - -
Change in decommissioning obligations held for sale included in working capital (deficiency) 6,308 - - -
Decommissioning expenditures (595 ) (114 ) (971 ) (506 )
Bank loans plus working capital (deficiency), end of period $ 9,682 $ (64,531 ) $ 9,682 $ (64,531 )

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 December 31, 2013, the Company had a $28 million extendible committed term bank facility with a Canadian bank under which $27.9 million of credit was available with $0.1 million in letters of credit outstanding that reduce the amount of available credit. This revolving operating loan facility has a term date of May 31, 2014, and if not extended, any outstanding advances would become repayable one year later on May 31, 2015. 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 3.6% depending on the borrowing option used.

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 December 31, 2013.

The available lending limit of the facility is scheduled to be reviewed on or before May 31, 2014 and is based on the bank's interpretation of the Company's reserves and future commodity prices. There can be no assurance that the amount or terms of the available facility will not be adjusted at the next review.

OFF-BALANCE SHEET ARRANGEMENTS

The Company had no guarantees or off-balance sheet arrangements other than as described below under "Contractual Obligations."

CONTRACTUAL OBLIGATIONS

The Company enters into various contractual obligations in the course of conducting its operations. At December 31, 2013, these obligations include:

  • Loan agreement - The reserves-based extendable committed term bank facility has a term date of May 31, 2014. If not extended, any outstanding advances would become repayable on May 31, 2015.
  • Firm service transportation commitments - The Company has entered into firm service transportation agreements for approximately 7 million cubic feet per day of gas sales for various terms expiring between 2014 and 2020.

As at December 31, 2013 the Company had the following minimum contractual obligations:

Contractual obligations Payments due by year
(in thousands of dollars) 2014 2015 2016 2017 2018 Thereafter
Accounts payable(2) $ 23,417 $ - $ - $ - $ - $ -
Convertible debentures(1)(2) 5,523 7,085 55,210 47,667 - -
Non-cancellable operating leases(3) 491 36 36 3 - -
Other capital commitments(4) 1,000 - - - - -
Firm service(5) 878 748 158 127 117 136
Total $ 31,309 $ 7,869 $ 55,404 $ 47,797 $ 117 $ 136
  1. Includes the associated principal repayments.
  2. Accounts payable and accruals includes $1.6 million of interest relating to convertible debentures. The total interest payable in 2014 on the convertible debentures is $7.1 million.
  3. Includes the head office and field office leases, and computer software leases.
  4. Includes $1 million for capital expenditures expected to be incurred in the first quarter of 2014.
  5. These transportation charges are netted from revenue received from purchasers. The independent reserves report includes the cost of product transportation in the determination of reserves values.

Subsequent to December 31, 2013, the Company entered into a farm-in agreement to drill one Cardium oil well prior to October 31, 2014 to earn a working interest in the farm-out lands. The capital commitment associated with the well is $2.5 million.

These obligations are described further in notes 19 and 21 to the consolidated financial statements for the years ended December 31, 2013 and 2012.

CRITICAL ACCOUNTING ESTIMATES

The Company's significant accounting policies are disclosed in note 3 to the consolidated financial statements. Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. These accounting policies are discussed below and are included to aid the reader in assessing the critical accounting policies and practices of the Company and the likelihood of materially different results than reported. The Company's management reviews its estimates regularly. The emergence of new information and changed circumstances may result in actual results that differ materially from current estimates.

Oil and gas reserves

Proved and probable reserves, as defined by the Canadian Securities Administrators in NI 51-101 with reference to the Canadian Oil and Gas Evaluation Handbook, are estimated using independent reserves evaluator reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. There should be a 50% statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as proved and probable and a 50% statistical probability that it will be less. The equivalent statistical probabilities for the proved component of proved and probable reserves are 90% and 10%, respectively. Determination of reserves is a complex process involving judgments, estimates and decisions based on available geological, engineering, production and any other relevant data. These estimates are subject to material change as economic conditions change and ongoing production and development activities provide new information.

Purchase price allocations and calculations of depletion and depreciation, impairment and deferred income tax assets are based on estimates of oil and gas reserves. Reserves estimates are based on engineering data, estimated future prices, expected future rates of production and timing of future capital expenditures. By their nature, these estimates are subject to measurement uncertainties and interpretations and the impact on the financial statements could be material. The Company expects that over time, its reserves estimates will be revised upward or downward based on updated information such as the results of future drilling, testing and production levels and may be affected by changes in commodity prices.

Recoverable amounts of CGUs

The recoverable amount of a CGU used in the assessment of impairment is the greater of its value-in-use ("VIU") and its fair value less costs to sell ("FVLCTS"). VIU is determined by estimating the present value of the future net cash flows from the continued use of the CGU, and is subject to the risks associated with estimating the value of reserves. FVLCTS refers to the amount obtainable from the sale of a CGU in an arm's length transaction between knowledgeable, willing parties, less costs of disposal. The criteria used in the estimation of this amount are discussed in note 5 to the consolidated financial statements.

Both VIU and FVLCTS estimates include the estimated reserves values in their determination. The key assumptions and estimates of the value of oil and gas reserves and the existing and potential markets for the Company's oil and gas assets are made at the time of reserves estimation and market assessment and are subject to change as new information becomes available. Changes in international and regional factors, including supply and demand of commodities, inventory levels, drilling activity, currency exchange rates, weather, geopolitical and general economic environment factors, may result in significant changes to the estimated recoverable amounts of CGUs.

Decommissioning obligations

The Company is required to set up a provision for future removal and site restoration costs. The Company must estimate these costs in accordance with existing laws, contracts or other policies. These estimated costs are charged to property, plant and equipment and the appropriate liability account over the expected service life of the asset. The estimate of future removal and site restoration costs involves a number of estimates related to timing of abandonment, determination of the economic life of the asset, costs associated with abandonment and site restoration, discount rates and review of potential abandonment methods.

Income taxes

The determination of the Company's income and other tax assets and 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 asset or liability may differ from that estimated and recorded by management. The Company estimates its future income tax rate in calculating its future income tax asset or liability. Various assumptions are made in assessing when temporary differences will reverse and this may impact the rate used.

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.

Offsetting Financial Assets and Financial Liabilities (Amendments to IAS 32 Financial Instruments: Presentation ("IAS 32"). The amendments to IAS 32 clarify the requirements for offsetting financial instruments such as the accounts receivable and payable related to the Company's commodity contracts. The amendments clarify when an entity has a legally enforceable right to offset and certain other requirements that are necessary to present a net financial asset or liability.

The amendments to IAS 32 are applied retrospectively for annual periods beginning on or after January 1, 2014, with early adoption allowed. The Company is currently assessing the impact of this amendment on the presentation of its accounts receivable and payable related to commodity contracts.

Levies (IFRIC 21). In May 2013, the International Accounting Standards Board ("IASB") issued IFRIC 21 "Levies," which was developed by the IFRS Interpretations Committee ("IFRIC"). IFRIC 21 clarifies that an entity recognizes a liability for a levy when the activity that triggers payment, as identified by the relevant legislation, occurs. The interpretation also clarifies that no liability should be recognized before the specified minimum threshold to trigger that levy is reached. IFRIC 21 is required to be adopted retrospectively for fiscal years beginning January 1, 2014, with earlier adoption permitted. IFRIC 21 will be applied by the Company on January 1, 2014 and the adoption may have an impact on the Company's accounting for production and similar taxes, which do not meet the definition of an income tax in IAS 12 "Income Taxes." The Company is currently assessing and quantifying the effect on its financial statements.

CHANGES IN ACCOUNTING POLICIES

As of January 1, 2013, the Company adopted several 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:

  1. IFRS 7 "Financial Instruments Disclosures." The amendments to IFRS 7, "Financial Instruments: Disclosures" develop common disclosure requirements for financial assets and financial liabilities that are offset in the financial statements, or that are subject to enforceable master netting arrangements or similar agreements.
  2. IFRS 10 "Consolidated Financial Statements" supersedes IAS 27 "Consolidation and Separate Financial Statements" and SIC-12 "Consolidation - Special Purpose Entities." This standard provides a single model to be applied in control analysis for all investees, including special purpose entities.
  3. IFRS 11 "Joint Arrangements" divides joint arrangements into two types, joint operations and joint ventures, each with its own accounting model. All joint arrangements are required to be reassessed on transition to IFRS 11 to determine their type to apply the appropriate accounting.
  4. IFRS 12 "Disclosure of Interests in Other Entities" combines in a single standard the disclosure requirements for subsidiaries, associates and joint arrangements, as well as unconsolidated structured entities.
  5. IFRS 13 "Fair Value Measurement" defines fair value, establishes a framework for measuring fair value, and sets out disclosure requirements for fair value measurements. This standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The adoption of this standard requires the revaluation of certain derivative financial liabilities on the Company's consolidated balance sheets to reflect an appropriate amount of risk of non-performance by the Company. The standard also requires additional annual fair value disclosures as well as additional interim disclosures, as per IAS 34.

CONTROLS AND PROCEDURES

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

The DC&P have been designed to provide reasonable assurance that material information relating to the Company is made known to the CEO and CFO by others and that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by the Company under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation. The Company's CEO and CFO have concluded, based on their evaluation at the financial year end of the Company, that the Company's disclosure controls and procedures are effective to provide reasonable assurance that material information related to the issuer is made known to them by others within the Company.

The ICOFR have been designed to provide reasonable assurance that all assets are safeguarded and transactions are appropriately authorized, and to facilitate the preparation of relevant, reliable and timely information. The CEO and CFO have evaluated and tested the design and operating effectiveness of Anderson's ICOFR as of December 31, 2013 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 IFRS. The CEO and CFO are required to cause the Company to disclose any change in the Company's ICOFR that occurred during the period beginning on October 1, 2013 and ending on December 31, 2013 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 a control system, including the Company's DC&P and ICOFR, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objective of the control system will be met, and it should not be expected that DC&P and ICOFR will prevent all errors or fraud.

BUSINESS RISKS

Oil and gas exploration and production is capital intensive and involves a number of business risks including, without limitation, the uncertainty of finding new reserves, the instability of commodity prices, weather and various operational risks. Commodity prices are influenced by local and worldwide supply and demand, OPEC actions, ongoing global economic concerns, the U.S. dollar exchange rate, transportation costs, political stability and seasonal and weather related changes to demand. The price of natural gas has recently strengthened due to weather-related changes to demand; however, the concern over increasing U.S. gas production, driven primarily by the U.S. 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 and continued instability in oil producing countries. 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.

Internationally, Canada is a signatory to the United Nations Framework Convention on Climate Change and previously ratified the Kyoto Protocol established thereunder, which set legally binding targets to reduce nation-wide emissions of carbon dioxide, methane, nitrous oxide, and other greenhouse gases ("GHGs"). The first commitment period under the Kyoto Protocol is the five-year period from 2008 to 2012. In December 2011, the Canadian federal government announced that it would not agree to a second commitment period under the Kyoto Protocol after 2012. The federal government instead endorsed the Durban Platform, a broad agreement reached among the 194 countries that are party to the United Nations Framework Convention on Climate Change, during a conference held in Durban, South Africa, in December 2011. The Durban Platform sets forth a process for negotiating a new climate change treaty that would create binding commitments for all major GHG emitters. The Canadian government expressed cautious optimism that agreement on a new treaty could be reached by 2015. The Durban Platform followed the Copenhagen Accord reached in December 2009 as government representatives met in Copenhagen, Denmark, to negotiate a successor to the Kyoto Protocol. The Copenhagen Accord represents a broad political consensus and reinforces commitments to reducing GHG emissions but is not a binding international treaty. Although Canada had committed under the Copenhagen Accord to reduce its GHG emissions by 17% from 2005 levels by 2020, the target is not legally binding. As the details of the implementation of any federal legislation for GHGs that is applicable to the oil and gas industry have not been announced, the effect on Anderson's operations cannot be determined at this time.

Additionally, regulation can take place at the provincial and municipal level. For example, Alberta introduced the Climate Change and Emissions Management Act, which provides a framework for managing GHG emissions and establishes a target of reducing specified gas emissions relative to gross domestic product to an amount that is equal to or less than 50% of 1990 levels by December 31, 2020. The accompanying regulations, the Specified Gas Emitters Regulation and the Specified Gas Emitters Reporting Regulation, require mandatory emissions reductions through the use of emissions intensity targets and impose duties to report.

The Government of Alberta implemented a new oil and gas royalty framework effective January 2009. The new framework, including subsequent amendments, established new royalties for conventional oil, natural gas and bitumen that are linked to price and production levels and apply to both new and existing conventional oil and gas activities and oil sands projects. Under the framework, the formula for conventional oil and natural gas royalties uses a sliding rate formula, dependent on the market price and production volumes. Royalty rates for conventional oil currently range from 0% to 40% and royalty rates for natural gas currently range from 5% to 36%. The Alberta government has also introduced a number of royalty reduction and incentive programs to encourage oil and gas exploration and development in Alberta, including a new well royalty program, which has become a permanent feature of the royalty system, that provides a maximum 5% royalty rate for the first 12 months of production from new wells producing oil or natural gas to a maximum of 50,000 barrels of oil or 500 million cubic feet of natural gas. In addition, there is a 5% front end royalty rate for horizontal oil wells spud on or after May 1, 2010. Based on measured depth of the well, the 5% rate can be extended to 18 to 48 months on 50 MBOE to 100 MBOE of raw production. The majority of the Company's horizontal wells on Crown lands would qualify for 30 months of 5% royalty for up to 70 MBOE of raw production.

STRATEGY

Coming out of the strategic alternatives process, the Company is substantially smaller in terms of production, has cash in the bank and has an unused bank operating line. Although the Company has no bank debt, it does have convertible debentures maturing in 2016 and 2017. The Company's business plan is to pursue growth of its asset base and cash flow and increase its financial flexibility to meet its obligations when they become due. A strategy of increasing oil assets, production and cash flow should support a higher borrowing base over time.

With the bank debt issues resolved, the Company intends to focus on rebuilding its asset basis by drilling Cardium horizontal light oil wells and growing its Cardium horizontal oil drilling inventory in the Willesden Green, West Pembina and Buck Lake areas. The longer term debenture maturities give the Company time to rebuild its asset base. Resuming a drilling program on the Cardium oil properties in areas where the Company controls the infrastructure expects to increase production that generates stronger netbacks.

The Company will continue to optimize, rationalize, consolidate and improve the profitability of its shallow gas business. The Company is not planning any significant new investments in the shallow gas business, and may dispose of some or all of the shallow gas assets.

In the fourth quarter of 2013 and the first quarter of 2014, the Company disposed of its unprofitable shallow gas assets. The Company's remaining shallow gas properties are profitable at current natural gas prices.

The Company has no plans to dispose of its Cardium oil assets.

The Company continues to implement new changes in Cardium horizontal drilling and completion technology to improve the profitability of its Cardium oil operation. Recent technological changes include repositioning the trajectory of the horizontal well within the Cardium zone to maximize frac effectiveness and using dissolvable frac balls. In 2014, the Company plans to drill its first long reach horizontal oil well that is expected to traverse up to 3,000 metres of horizontal Cardium net pay. It is anticipated that this well will access Cardium reserves in two sections of land as opposed to the current one section of land per horizontal well. There is a capital cost benefit to drilling an extended reach well over two sections as compared to two wells traversing one section of land each. There is also a reserves benefit with the longer horizontal wells due to additional reservoir contact.

The Company plans to continue to focus on reducing average well payouts. The Company operates over 90% of its production and almost all of its drilling operations. Where it can, the Company strives to operate its own oil and gas infrastructure and attract third parties to utilize the Company's infrastructure on a processing fee basis in order to reduce overall operating costs.

The Company is developing new light oil horizontal plays on its existing acreage in the Mannville and Belly River and is planning to drill one of these plays in the remainder of 2014.

TIMING OF STRATEGY

As a result of the 2012 and 2013 asset dispositions, the financial results for the fourth quarter 2013 and for the year ended December 31, 2013 are not indicative of where the Company is going in the future. The Company's current winter drilling program is expected to have a positive impact on the first and second quarters of 2014, as operating netbacks on Cardium drilling operations were approximately $40 per BOE in the fourth quarter of 2013. The Company drilled 7 gross (7.0 net) wells this winter that are expected to materially add to its production in the first and second quarters of 2014. The Company will be reviewing its capital program at the end of the first quarter and may look to revise its capital program at that time.

QUARTERLY INFORMATION

The following table provides financial and operating results for the last eight quarters. Commodity prices remain volatile, affecting funds from operations and earnings throughout those quarters. The Company curtailed its drilling program in 2012, drilling only 2 gross wells (1.8 net capital and 1.5 net revenue) in the first quarter of 2013, 4 gross wells (4.0 net capital, 2.8 net revenue) in the last quarter of 2012 and 3 gross wells (2.5 net capital and revenue) in the first quarter of 2012. 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 2012 and 2013.

Earnings were affected in the second quarter of 2012 by impairments in the value of natural gas properties, whereas earnings in the second quarter of 2013 were affected by the tax expense related to derecognizing the 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 capital spending programs related to Cardium oil development through 2012 and into 2013. Bank loans were reduced by the proceeds from the sale of assets and from cash from operating activities in 2012 and 2013.

SELECTED QUARTERLY INFORMATION

($ amounts in thousands, except per share amounts and prices) Q4 2013 Q3 2013 Q2 2013 Q1 2013
Revenue, net of royalties $ 7,288 $ 11,949 $ 14,345 $ 15,268
Funds from operations(1) $ (306 ) $ 1,408 $ 4,701 $ 5,486
Funds from operations per share, basic and diluted(1) $ - $ 0.01 $ 0.03 $ 0.03
Adjusted earnings (loss) before taxes(2) $ (2,745 ) $ (5,856 ) $ (3,672 ) $ (5,113 )
Adjusted earnings (loss) before taxes per share, basic and diluted(2) $ (0.02 ) $ (0.03 ) $ (0.02 ) $ (0.03 )
Loss $ (2,445 ) $ (48,737 ) $ (49,306 ) $ (5,113 )
Loss per share, basic and diluted $ (0.01 ) $ (0.28 ) $ (0.29 ) $ (0.03 )
Capital expenditures, net of proceeds on dispositions $ (71,972 ) $ 229 $ 186 $ 7,662
Cash from operating activities $ (230 ) $ 1,626 $ 3,953 $ 5,171
Bank loans $ - $ 53,945 $ 53,892 $ 55,141
Daily sales
Oil (bpd) 537 983 1,199 1,529
NGL (bpd) 166 280 297 203
Natural gas (Mcfd) 10,467 13,119 14,611 14,759
BOE (BOED) 2,448 3,449 3,931 4,191
Average prices
Oil ($/bbl)(2) $ 84.26 $ 100.81 $ 89.76 $ 84.83
NGL ($/bbl) $ 61.60 $ 52.97 $ 48.73 $ 61.77
Natural gas ($/Mcf) $ 3.19 $ 2.27 $ 3.33 $ 2.94
BOE ($/BOE)(1)(2) $ 36.49 $ 41.87 $ 43.66 $ 44.70
Q4 2012 Q3 2012 Q2 2012 Q1 2012
Revenue, net of royalties $ 13,796 $ 15,284 $ 18,290 $ 22,445
Funds from operations(1) $ 5,694 $ 5,725 $ 7,606 $ 10,616
Funds from operations per share, basic and diluted(1) $ 0.03 $ 0.03 $ 0.04 $ 0.06
Adjusted earnings (loss) before taxes(2) $ (11,799 ) $ 173 $ (2,369 ) $ (7,743 )
Adjusted earnings (loss) before taxes per share, basic and diluted(2) $ (0.07 ) $ - $ (0.01 ) $ (0.04 )
Earnings (loss) $ (8,895 ) $ 94 $ (16,828 ) $ (5,864 )
Earnings (loss) per share, basic and diluted $ (0.05 ) $ - $ (0.10 ) $ (0.03 )
Capital expenditures, net of proceeds on dispositions $ (26,880 ) $ (28,986 ) $ 4,786 $ 12,090
Cash from operating activities $ 6,976 $ 5,845 $ 7,712 $ 9,306
Bank loans $ 48,094 $ 88,922 $ 119,686 $ 106,655
Daily sales
Oil (bpd) 1,135 1,274 1,669 1,956
NGL (bpd) 338 576 750 703
Natural gas (Mcfd) 18,159 23,519 26,438 27,463
BOE (BOED) 4,500 5,770 6,825 7,236
Average prices
Oil ($/bbl)(4) $ 79.73 $ 80.44 $ 81.58 $ 88.48
NGL ($/bbl) $ 52.02 $ 51.59 $ 54.38 $ 67.36
Natural gas ($/Mcf) $ 3.16 $ 2.24 $ 1.72 $ 2.01
BOE ($/BOE)(3)(4) $ 36.89 $ 32.05 $ 32.70 $ 38.28
  1. Funds from operations and funds from operations per share do not have standardized meanings prescribed by GAAP. Refer to the sections entitled "Funds from Operations" and "Additional GAAP Measures" at the end of this MD&A.
  2. Adjusted earnings (loss) before taxes, adjusted earnings (loss) before taxes per share and operating netback per BOE are considered non-GAAP measures. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.
  3. Includes royalty and other income classified with oil and gas sales.
  4. Excludes realized and unrealized hedging gains (losses) on derivative contracts as follows: Q4 2013 - ($0.9) million and $0.9 million, respectively; Q3 2013 - $(1.6) million and $0.5 million, respectively; Q2 2013 - ($0.7) million and $0.6 million, respectively; Q1 2013 - ($0.6) million and ($1.1) million, respectively; Q4 2012 - $2.2 million and ($2.8) million, respectively; Q3 2012 - $1.7 million and ($2.7) million, respectively; Q2 2012 - $1.3 million and $4.7 million, respectively and Q1 2012 - $0.2 million and ($1.7) million, respectively.
SELECTED ANNUAL INFORMATION
Years ended December 31
(in thousands, except per share amounts) 2013 2012 2011
Total oil and gas sales(1) $ 53,983 $ 77,806 $ 118,292
Total revenue, net of royalties(1) $ 48,850 $ 69,815 $ 104,486
Adjusted earnings (loss) before taxes(2) $ (17,386 ) $ (21,738 ) $ 5,523
Adjusted earnings (loss) before taxes per share,(2) basic and diluted $ (0.10 ) $ (0.13 ) $ 0.03
Loss $ (105,601 ) $ (31,493 ) $ (22,444 )
Loss per share, basic and diluted $ (0.61 ) $ (0.18 ) $ (0.13 )
Total assets $ 171,077 $ 343,478 $ 460,319
Total bank loans $ - $ 48,094 $ 88,682
Total convertible debentures, liability component $ 88,922 $ 86,753 $ 84,796
  1. Includes royalty and other income classified with oil and gas sales. Excludes the realized loss of $3.7 million and unrealized gain of $1.0 million on derivative contracts in 2013 (2012 - $5.4 million realized gain and $2.5 million unrealized loss and 2011 - $0.6 million realized loss and $3.3 unrealized gain).
  2. Adjusted earnings (loss) before taxes and adjusted earnings (loss) before taxes per share are considered non-GAAP measures. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.

Total oil and gas sales and total revenue, net of royalties decreased significantly from 2011 to 2013 as a result of the sale of properties during 2012 and 2013 and the curtailment of drilling in 2012 due to the now completed strategic alternatives process. Adjusted earnings before taxes declined from 2011 primarily due to decreased commodity prices, fewer assets and lower activity levels. Loss and loss per share were impacted by an impairment loss on assets held for sale in 2013 ($44.6 million), the tax expense related to derecognizing the deferred tax asset in the second quarter of 2013 ($45.6 million), and impairment charges in 2012 ($20.0 million) and 2011 ($35.2 million). These impairment charges and the dispositions reported in 2011, 2012 and 2013 have also reduced total assets. Approximately $80.1 million in proceeds from dispositions in 2013, $73.9 million in 2012 and $11.6 million in 2011 were used to pay down bank debt.

ADDITIONAL INFORMATION

Additional information regarding Anderson and its business and operation, including its most recently filed annual information form, is available on the Company's profile on SEDAR at www.sedar.com. This information is also available on the Company's website at www.andersonenergy.ca.

CONVERSION MEASURES

Production volumes and reserves are commonly expressed on a BOE basis whereby natural gas volumes are converted at the ratio of 6 thousand cubic feet to 1 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 6 Mcf to 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. 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 share" 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, "loss before taxes" or "loss and comprehensive loss" as determined in accordance with GAAP as a measure of the Company's performance.

Adjusted earnings (loss) before taxes is calculated as loss before taxes per the Consolidated Statement of Operations and Comprehensive 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 compensation 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 "working capital or 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 unrealized losses on derivative contracts are excluded from current liabilities in the calculation of working capital and working capital (deficiency). Working capital and 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 working capital or 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; 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.

Consolidated Statements of Financial Position
(Stated in thousands of dollars)
(unaudited)
December 31, 2013 December 31, 2012
ASSETS
Current assets:
Cash and cash equivalents (note 19) $ 25,111 $ 1
Accounts receivables and accruals (note 19) 6,702 9,881
Prepaid expenses and deposits 1,286 1,788
Total current assets 33,099 11,670
Deferred tax asset (note 11) 2,000 45,634
Property, plant and equipment (note 6) 135,978 286,174
Total assets $ 171,077 $ 343,478
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accruals (note 19) $ 23,417 $ 28,107
Unrealized loss on derivative contracts (note 19) 146 1,097
Bank loans (note 8) - 48,094
Total current liabilities 23,563 77,298
Convertible debentures (note 9) 88,922 86,753
Decommissioning obligations (note 10) 30,413 46,467
Total liabilities 142,898 210,518
Shareholders' equity:
Share capital (note 12) 171,460 171,460
Equity component of convertible debentures (note 9) 5,019 5,019
Contributed surplus 11,238 10,418
Deficit (159,538 ) (53,937 )
Total shareholders' equity 28,179 132,960
Commitments and contingencies (note 21)
Total liabilities and shareholders' equity $ 171,077 $ 343,478
See accompanying notes to the consolidated financial statements.
Consolidated Statements of Operations and Comprehensive Loss
YEARS ENDED DECEMBER 31, 2013 AND DECEMBER 31, 2012
(Stated in thousands of dollars, except per share amounts)(unaudited) 2013 2012
Oil and gas sales $ 53,983 $ 77,806
Royalties (5,133 ) (7,991 )
Revenue, net of royalties 48,850 69,815
Other gains (losses) (note 14) (2,767 ) 2,948
Total revenue, net of royalties and other gains (losses) 46,083 72,763
Operating expenses (note 15) 16,915 24,239
Transportation expenses 401 498
Depletion and depreciation (note 6) 27,909 44,396
Impairment loss (note 7) 44,581 20,000
(Gain) loss on sale of property, plant and equipment (1,813 ) 721
General and administrative expenses (notes 15 and 16) 7,382 9,924
Loss from operating activities (49,292 ) (27,015 )
Finance income (note 17) 164 49
Finance expenses (note 17) (12,839 ) (14,772 )
Net finance expenses (12,675 ) (14,723 )
Loss before taxes (61,967 ) (41,738 )
Deferred income tax expense (benefit) (note 11) 43,634 (10,245 )
Loss and comprehensive loss for the year (105,601 ) (31,493 )
Basic and diluted loss per share (note 13) $ (0.61 ) $ (0.18 )
See accompanying notes to the consolidated financial statements.
Consolidated Statements of Changes in Shareholders' Equity
(Stated in thousands of dollars, except number of common shares)
(unaudited)


Number of Common Shares

Share capital
Equity component
of convertible debentures
Contributed surplus Deficit Total shareholders' equity
Balance at December 31, 2011 172,549,701 $ 171,460 $ 5,019 $ 9,385 $ (22,444 ) $ 163,420
Share-based payments (note 12) - - - 1,033 - 1,033
Loss for the year - - - - (31,493 ) (31,493 )
Balance at December 31, 2012 172,549,701 171,460 5,019 10,418 (53,937 ) 132,960
Share-based payments (note 12) - - - 820 - 820
Loss for the year - - - - (105,601 ) (105,601 )
Balance at December 31, 2013 172,549,701 $ 171,460 $ 5,019 $ 11,238 $ (159,538 ) $ 28,179
See accompanying notes to the consolidated financial statements.
Consolidated Statements of Cash Flows
YEARS ENDED DECEMBER 31, 2013 AND DECEMBER 31, 2012
(Stated in thousands of dollars) (unaudited) 2013 2012
CASH PROVIDED BY (USED IN)
OPERATIONS
Loss for the year $ (105,601 ) $ (31,493 )
Adjustments for:
Unrealized (gain) loss on derivative contracts (note 14) (951 ) 2,481
(Gain) loss on sale of property, plant and equipment (1,813 ) 721
Depletion and depreciation (note 6) 27,909 44,396
Impairment loss (note 7) 44,581 20,000
Share-based payments (note 12) 547 756
Accretion on decommissioning obligations (note 10) 814 1,068
Accretion on convertible debentures (note 9) 2,169 1,957
Deferred income tax expense (benefit) 43,634 (10,245 )
Decommissioning expenditures (note 10) (971 ) (506 )
Changes in non-cash working capital (note 18) 202 704
Net cash provided by operations 10,520 29,839
FINANCING
Decrease in bank loans (48,094 ) (40,588 )
Changes in non-cash working capital (note 18) - (175 )
Net cash used in financing (48,094 ) (40,763 )
INVESTING
Property, plant and equipment expenditures (note 6) (16,171 ) (34,901 )
Proceeds from sale of property, plant and equipment (note 6) 80,066 73,891
Changes in non-cash working capital (note 18) (1,211 ) (28,066 )
Net cash provided by investing 62,684 10,924
Increase in cash and cash equivalents 25,110 -
Cash and cash equivalents, beginning of year 1 1
Cash and cash equivalents, end of year $ 25,111 $ 1
Interest received in cash $ 136 $ 54
Interest paid in cash $ (9,292 ) $ (12,848 )

See accompanying notes to the consolidated financial statements.

Notes to the Consolidated Financial Statements

DECEMBER 31, 2013 AND DECEMBER 31, 2012

(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 2200, 333 - 7th Avenue SW, Calgary, Alberta, Canada, T2P 2Z1.

2. BASIS OF PREPARATION

(a) Statement of compliance. These consolidated financial statements comply with International Financial Reporting Standards ("IFRS").

The consolidated financial statements were approved and authorized for issuance by the Board of Directors on March 28, 2014.

(b) Basis of measurement. The consolidated financial statements have been prepared on the historical cost basis except for derivative financial instruments, which are measured at fair value. The methods used to measure fair values are discussed in note 5.

(c) Functional and presentation currency. These consolidated financial statements are presented in Canadian dollars, which is the Company's functional currency.

(d) Function and nature of expenses. Expenses in the consolidated statements of operations and comprehensive loss are presented as a combination of function and nature in conformity with industry practice. Transportation expenses, depletion and depreciation, and impairment of property, plant and equipment are presented in separate lines by their nature, while operating expenses and general and administrative expenses are presented on a functional basis. Significant operating and general and administrative expenses are presented by their nature in note 15.

3. SIGNIFICANT ACCOUNTING POLICIES

The accounting policies set out below have been applied consistently to all periods presented in these consolidated financial statements.

(a) Basis of consolidation:

(i) Subsidiaries. Subsidiaries are entities controlled by the Company. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases.

(ii) Jointly controlled operations and jointly controlled assets. Many of the Company's oil and natural gas activities involve jointly controlled assets. The consolidated financial statements include the Company's share of these jointly controlled assets and the proportionate share of the relevant revenue and related costs.

(iii) Transactions eliminated on consolidation. Intercompany balances and transactions, and any unrealized income and expenses arising from intercompany transactions, are eliminated in preparing the consolidated financial statements.

(b) Financial instruments:

(i) Non-derivative financial instruments. Non-derivative financial instruments comprise cash and cash equivalents, accounts receivable and accruals, accounts payables and accruals, bank loans and convertible debentures. Non-derivative financial instruments are recognized initially at fair value, plus, for instruments not classified as "fair value through profit or loss", any directly attributable transaction costs. Subsequent to initial recognition, non-derivative financial instruments are measured as described below.

Cash and cash equivalents. Cash and cash equivalents comprise cash on hand, term deposits and other short-term highly liquid investments with original maturities of three months or less and are measured similar to other non-derivative financial instruments.

Other. Other non-derivative financial instruments, comprising accounts receivable and accruals, accounts payable and accruals, bank loans and convertible debentures, are measured at amortized cost using the effective interest method, less any impairment losses. 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 and convertible debentures are recorded net of issue costs and are presented net of deferred interest payments, with interest recognized in earnings on an effective interest basis.

(ii) Derivative financial instruments. The Company has entered into certain financial derivative contracts in order to manage the exposure to market risks from fluctuations in commodity prices. These instruments are not used for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, and thus has not applied hedge accounting, even though the Company considers all commodities contracts to be economic hedges. As a result, all financial derivative contracts are classified as "fair value through profit or loss" and are recorded on the statement of financial position at fair value. Transaction costs are recognized in profit or loss when incurred.

The Company accounts for forward physical delivery sales contracts, which are entered into and held for the purpose of delivery or receipt of non-financial items in accordance with expected sale or usage requirements as executory contracts. As such, these contracts are not considered to be derivative financial instruments and have not been recorded at fair value on the statement of financial position. Settlements on these physical sales contracts are recognized in oil and natural gas revenue.

Embedded derivatives are separated from the host contract and accounted for separately if the economic characteristics and risks of the host contract and the embedded derivative are not closely related. Changes in the fair value of separable embedded derivatives are recognized immediately in profit or loss.

(iii) Share capital. Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares and stock options are recognized as a deduction from equity, net of any tax effects.

(c) Property, plant and equipment: Development and production costs. Items of property, plant and equipment, which include oil and gas development and production assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses. All costs directly associated with the development of oil and natural gas reserves are recognized as oil and natural gas interests if they extend or enhance the recoverable reserves of the underlying assets. Such costs include property acquisitions, drilling and completion costs, gathering and processing infrastructure, capitalized decommissioning obligations, directly attributable internal costs and major overhaul and turnaround activities that maintain property, plant and equipment. Repairs and maintenance and operational costs that do not extend or enhance the recoverable reserves are charged to profit or loss when incurred.

Oil and natural gas assets are grouped into cash generating units ("CGUs") for impairment testing. The Company had previously grouped its development and production assets into the following CGUs: Horizontal Oil, Deep Gas, Shallow Gas and Non-Core. In 2012, a significant portion of the assets in the Deep Gas and Non-core CGUs were sold and the remaining assets were regrouped into the following CGUs: Gas and Horizontal Cardium. The Horizontal Cardium CGU retained the same group of assets, but was renamed to better reflect the nature of those assets. The remaining assets in the Deep Gas and Non-core CGUs more closely resembled the operational, management and monitoring, product composition, and cash inflows of the assets within the Shallow Gas CGU. Accordingly, those remaining Deep Gas and Non-core assets were grouped with the Shallow Gas assets to form the Gas CGU.

When significant parts of an item of property, plant and equipment, including oil and natural gas interests, have different useful lives, they are accounted for as separate items (components).

Gains and losses on the sale of property, plant and equipment, including oil and natural gas interests, are determined by comparing the proceeds received to the carrying amount of property, plant and equipment and are recognized as a separate line item in other income.

(d) Depletion and depreciation. The net carrying value of development or production assets is depleted using the unit of production method by reference to the ratio of production in the quarter to the related proved plus probable reserves, taking into account estimated future development and decommissioning costs necessary to bring those reserves into production. For other assets, depreciation is recognized in profit or loss over the estimated useful lives of each part of an item of property, plant and equipment using the declining balance method at rates between 20% and 30% per annum. Leased assets are depreciated over the shorter of the lease term and their useful lives unless it is reasonably certain that the Company will obtain ownership by the end of the lease term.

The costs of major overhaul and turnaround activities that are capitalized are depreciated on a straight-line basis over the period to the next recurrence of that set of activities, which varies from two to five years.

Depreciation methods, useful lives and residual values are reviewed at each reporting date.

(e) Impairment:

(i) Financial assets. A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset.

An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate.

Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics.

All impairment losses are recognized in profit or loss.

An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost the reversal is recognized in profit or loss.

(ii) Non-financial assets. The aggregate carrying amounts of the Company's non-financial assets net of decommissioning liabilities, other than deferred tax assets are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the asset's recoverable amount is estimated.

For the purpose of impairment testing, assets are grouped together into CGUs; the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets. The recoverable amount of an asset or a CGU is the greater of its value-in-use and its fair value less costs to sell.

An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in profit or loss. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the units and then to reduce the carrying amounts of the other assets in the unit on a pro rata basis.

Impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset's carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation, if no impairment loss had been recognized.

(f) Share-based payments. The grant date fair value of equity-settled options granted to employees is recognized as share-based compensation expense, within general and administrative expenses, with a corresponding increase in contributed surplus over the vesting period. A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of options that vest.

(g) Provisions. A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability. Provisions are not recognized for future operating losses.

Decommissioning obligations. The Company's activities give rise to dismantling, decommissioning and site disturbance remediation activities. Provision is made for the estimated cost of site restoration and capitalized in the relevant asset category.

Decommissioning obligations are measured at the present value of management's expectation of the expenditures required to settle the present obligation at the reporting date. Subsequent to the initial measurement, the obligation is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation, including changes in the discount rate used to calculate the obligation. The increase in the provision due to the passage of time is recognized as finance costs whereas increases/decreases due to changes in the estimated future cash flows are capitalized. Actual costs incurred upon settlement of the decommissioning obligations are charged against the provision to the extent the provision was established, with any difference being recognized in profit or loss under gain or loss on sale of property, plant and equipment.

(h) Revenue. Revenue from the sale of oil and natural gas is recorded when the significant risks and rewards of ownership of the product is transferred to the buyer, which is usually when legal title passes to the external party. Oil and gas sales are presented before royalty obligations, whereas revenue is presented net of royalties.

Royalty income is recognized as it accrues in accordance with the terms of the overriding royalty agreements.

Fees charged to other entities for the use of pipelines, compressors and facilities owned by the Company are recognized as operating expense recoveries for use of transportation and processing assets when the usage is incurred.

Fees charged to other entities to recover overhead costs pursuant to capital and operating agreements are recognized as a reduction of general and administrative expenses in accordance with the terms of the capital and operating agreements.

(i) Transportation expenses. Transportation expenses include third-party pipeline and trucking costs incurred to transport oil, natural gas and natural gas liquids from processing and treating facilities to the point of sale.

(j) Finance income and expenses. Finance expenses comprise interest expense on borrowings, accretion of the discount on decommissioning obligations and accretion on convertible debentures recognized as financial liabilities.

Interest income is recognized as it accrues in profit or loss, using the effective interest method.

(k) Income tax. Income tax expense comprises current and deferred tax. Income tax expense is recognized in profit or loss except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.

Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

Deferred tax is recognized using the balance sheet method, providing for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination. In addition, deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously.

A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

(l) Earnings per share. Basic earnings per share is calculated by dividing the profit or loss attributable to common shareholders of the Company by the weighted average number of common shares outstanding during the period. Diluted earnings per share is determined by adjusting the profit or loss attributable to common shareholders and the weighted average number of common shares outstanding for the effects of dilutive instruments such as options granted to employees.

(m) New standards and interpretations not yet adopted: Standards that are issued but not yet effective and that the Company reasonably expects to be applicable at a future date are listed below.

Offsetting Financial Assets and Financial Liabilities (Amendments to IAS 32 Financial Instruments: Presentation ("IAS 32"). The amendments to IAS 32 clarify the requirements for offsetting financial instruments such as the amounts receivable and payable related to the Company's commodity contracts. The amendments clarify when an entity has a legally enforceable right to offset and certain other requirements that are necessary to present a net financial asset or liability.

The amendments to IAS 32 are applied retrospectively for annual periods beginning on or after January 1, 2014, with early adoption allowed. The Company is currently assessing the impact of this amendment on the presentation of its accounts receivable and payable related to commodity contracts.

In May 2013, the International Accounting Standards Board ("IASB") issued IFRIC 21 "Levies", which was developed by the IFRS Interpretations Committee ("IFRIC"). IFRIC 21 clarifies that an entity recognizes a liability for a levy when the activity that triggers payment, as identified by the relevant legislation, occurs. The interpretation also clarifies that no liability should be recognized before the specified minimum threshold to trigger that levy is reached. IFRIC 21 is required to be adopted retrospectively for fiscal years beginning January 1, 2014, with earlier adoption permitted. IFRIC 21 will be applied by the Company on January 1, 2014 and the adoption may have an impact on the Company's accounting for production and similar taxes, which do not meet the definition of an income tax in IAS 12 "Income Taxes." The Company is currently assessing and quantifying the effect on its financial statements.

(n) Changes in accounting policies: As of January 1, 2013, the Company adopted several 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:

  1. IFRS 7 "Financial Instruments Disclosures". The amendments to IFRS 7, "Financial Instruments: Disclosures" develop common disclosure requirements for financial assets and financial liabilities that are offset in the financial statements, or that are subject to enforceable master netting arrangements or similar agreements.
  2. IFRS 10 "Consolidated Financial Statements" supersedes IAS 27 "Consolidation and Separate Financial Statements" and SIC-12 "Consolidation - Special Purpose Entities." This standard provides a single model to be applied in control analysis for all investees, including special purpose entities.
  3. IFRS 11 "Joint Arrangements" divides joint arrangements into two types, joint operations and joint ventures, each with their own accounting model. All joint arrangements are required to be reassessed on transition to IFRS 11 to determine their type to apply the appropriate accounting.
  4. IFRS 12 "Disclosure of Interests in Other Entities" combines in a single standard the disclosure requirements for subsidiaries, associates and joint arrangements, as well as unconsolidated structured entities.
  5. IFRS 13 "Fair Value Measurement" defines fair value, establishes a framework for measuring fair value, and sets out disclosure requirements for fair value measurements. This standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The adoption of this standard requires the revaluation of certain derivative financial liabilities on the Company's consolidated balance sheets to reflect an appropriate amount of risk of non-performance by the Company. The standard also requires additional annual fair value disclosures as well as additional interim disclosures, as per IAS 34.

4. MANAGEMENT JUDGEMENTS AND ESTIMATES

The preparation of the consolidated financial statements in accordance with IFRS requires management to make judgements, estimates, and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income, and expenses. Actual results ultimately may differ from these estimates.

(a) Judgements. The key judgements made in applying accounting policies that have the most significant effect on the amounts recognized in these consolidated financial statements are as follows:

  1. Identification of cash generating units. Cash generating units are defined as the lowest grouping of integrated assets that generate identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The classification of assets into cash generating units requires significant judgement and interpretations with respect to shared infrastructure, geographical proximity, petroleum type and similar exposure to market risk and materiality. The Company had previously grouped its development and production assets into the following CGUs: Horizontal Oil, Deep Gas, Shallow Gas and Non-Core. In 2012, the Deep Gas and Non-core assets were grouped with the Shallow Gas assets to form the Gas CGU, and the Horizontal Oil CGU was renamed the Horizontal Cardium CGU. See note 3 (c).
  2. Fair value of derivatives. The fair value of financial instruments that are not traded in an active market is determined using valuation techniques. The Company uses its judgement to select a variety of methods and makes assumptions that are primarily based on market conditions existing at the end of each reporting period. The Company uses directly and indirectly observable inputs in measuring the value of financial instruments that are not traded in active markets, including quoted commodity prices and volatility. See note 19(d).
  3. Impairment / reversal of impairment. Judgments are required to assess when impairment indicators exist and impairment testing is required in determining the recoverable amount of assets, in the absence of quoted market prices, impairment tests are based on estimate of reserves, production rates, future oil and natural gas prices, future costs, discount rates, market value of land and other relevant assumptions.

(b) Use of estimates. Information about assumptions and estimation uncertainties that have a significant risk of resulting in a material adjustment within the next financial year are as follows:

  1. Estimates of oil and natural gas reserves. Depletion and depreciation as well as the amounts used in impairment calculations are based on estimates of oil and natural gas reserves. Reserves estimates are based on engineering data, estimated future prices, expected future rates of production and the timing of future capital expenditures, all of which are subject to many uncertainties and interpretations. At least once per year, a reserves estimate is prepared by independent qualified reserves evaluators. The Company expects that, over time, its reserves estimates will be revised upward or downward based on updated information such as the results of future drilling, testing and production levels, and may be affected by changes in commodity prices. See notes 6 and 7.
  2. Recoverable amounts of CGUs. The recoverable amount of a CGU used in the assessment of impairment is the greater of its value-in-use and its fair value less costs to sell.

Value-in-use is determined by estimating the present value of the future net cash flows from the continued use of the CGU, and is subject to the risks associated with estimating the value of reserves.

Fair value less costs to sell refers to the amount obtainable from the sale of a CGU in an arm's length transaction between knowledgeable, willing parties, less costs of disposal.

Note 5 outlines the factors considered in estimating these amounts.

The key assumptions and estimates of the value of oil and gas reserves and the existing and potential markets for the Company's oil and gas assets are made at the time of reserves estimation and market assessment and are subject to change as new information becomes available. Changes in international and regional factors including supply and demand of commodities, inventory levels, drilling activity, currency exchange rates, weather, geopolitical and general economic environment factors may result in significant changes to the estimated recoverable amounts of CGUs. See note 7.

  1. Decommissioning obligations. The total decommissioning obligation is estimated based on the Company's net ownership interest in all wells and facilities, estimated costs to reclaim and abandon these wells and facilities and the estimated timing of the costs to be incurred in future years, based on current legal and constructive requirements and technology. The estimated obligations and actual costs may change significantly due to changes in regulations, technology, timing of the expenditure and the discount rates used to determine the net present value of the obligations. See note 10.
  2. Deferred taxes. Deferred tax assets and liabilities are measured using enacted or substantively enacted tax rates at the reporting date in effect for the period in which the temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as part of the provision for income taxes in the period that includes the enactment date. The recognition of deferred tax assets is based on the assumption that it is probable that taxable profit will be available against which the deductible temporary differences can be utilized.

Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the year in which the estimates are revised and in any future years affected.

5. DETERMINATION OF FAIR VALUE

A number of the Company's accounting policies and disclosures require the determination of fair value, for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability.

(a) Property, plant and equipment. Property, plant and equipment are recognized at fair value in a business combination. The fair value of property, plant and equipment is the estimated amount for which property, plant and equipment could be exchanged on the acquisition date between a willing buyer and a willing seller in an arm's length transaction after proper marketing wherein the parties had each acted knowledgeably, prudently and without compulsion.

The value-in-use of a CGU is estimated based on consideration of the following:

  1. net present value of proved plus probable reserves using a pre-tax discount rate of 10% as determined by independent qualified reserves evaluators; and
  2. management's estimate of net present value of additional asset development not included in (i) above, using a pre-tax discount rate of 10%.

The fair value less costs to sell of a CGU is estimated based on consideration of the following:

  1. net present value of proved plus probable reserves using a pre-tax discount rate of 10% as determined by independent qualified reserves evaluators;
  2. management's estimate of the fair value of undeveloped land;
  3. a review of the values indicated by the metrics of recent market transactions of similar assets within the oil and gas industry; and
  4. management's estimate of additional fair value from asset development not included in (i) above.

The fair value less costs to sell of assets held for sale in the third quarter of 2013 was on the adjusted sales price contained within the signed purchase and sale agreement, net of expenses, plus the decommissioning obligations assumed by the purchaser. See note 7.

The market value of other items of property, plant and equipment is based on the quoted market prices for similar items.

(b) Cash and cash equivalents, accounts receivable and accruals and accounts payable and accruals. The fair value of cash and cash equivalents, accounts receivable and accruals and accounts payable and accruals is estimated as the present value of future cash flows, discounted at the market rate of interest at the reporting date. At December 31, 2013 and December 31, 2012, the fair value of these balances approximated their carrying value due to their short term to maturity.

(c) Bank loans. The fair value of bank loans approximates their carrying value, as they bear interest at floating rates and the premium charged at December 31, 2012 was indicative by the Company's current credit spreads. The Company had no bank loans outstanding at December 31, 2013.

(d) Derivatives. The fair value of forward contracts and swaps is derived from quoted prices received from financial institutions and is based on published forward price curves as at the measurement date, using the remaining contracted oil and natural gas volumes.

(e) Stock options. The fair value of employee stock options is measured using a Black-Scholes option pricing model. Measurement inputs include share price on measurement date, exercise price of the instrument, expected volatility (based on weighted average historic volatility adjusted for changes expected due to publicly available information), weighted average expected life of the instruments and forfeiture rate (both based on historical experience and general option holder behaviour), expected dividends, and the risk-free interest rate (based on government bonds).

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 consolidated statements of financial position as at December 31, 2013 and December 2012 is measured using level 2.

During the years ended December 31, 2013 and 2012, there were no transfers between level 1, level 2 and level 3 classified assets and liabilities.

6. PROPERTY, PLANT AND EQUIPMENT
Cost or deemed cost
Oil and natural gas assets Other equipment Total
Balance at December 31, 2011 $ 753,875 $ 1,863 $ 755,738
Additions 40,732 41 40,773
Disposals (201,559 ) - (201,559 )
Balance at December 31, 2012 593,048 1,904 594,952
Additions 8,128 17 8,145
Disposals (204,757 ) - (204,757 )
Balance at December 31, 2013 $ 396,419 $ 1,921 $ 398,340
Accumulated depletion, depreciation and impairment losses
Oil and natural gas assets Other equipment Total
Balance at December 31, 2011 $ 347,413 $ 1,378 $ 348,791
Depletion and depreciation for the year 44,247 149 44,396
Impairment loss (note 7) 20,000 - 20,000
Disposals (104,409 ) - (104,409 )
Balance at December 31, 2012 $ 307,251 $ 1,527 $ 308,778
Depletion and depreciation for the year 27,805 104 27,909
Impairment loss (note 7) 44,581 - 44,581
Disposals (118,906 ) - (118,906 )
Balance at December 31, 2013 $ 260,731 $ 1,631 $ 262,362
Carrying amounts
Oil and natural gas assets Other equipment Total
At December 31, 2012 $ 285,797 $ 377 $ 286,174
At December 31, 2013 135,688 290 135,978

Capitalized overhead. For the year ended December 31, 2013, additions to property, plant and equipment included internal overhead costs of $1.8 million (December 31, 2012 - $3.4 million).

Depletion, depreciation and impairment charges. Depletion and depreciation, impairment of property, plant and equipment, and any reversal thereof, are recognized as separate line items in the consolidated statements of operations (see note 7). The Company included $68.6 million in future development costs and $2.3 million in abandonment costs related to undeveloped reserves (December 31, 2012 - $145.3 million, $4.5 million respectively).

Sale of property, plant and equipment. For the year ended December 31, 2013, the Company sold interests in properties for total consideration of $80.1 million (December 31, 2012 - $73.9 million).

7. IMPAIRMENT LOSS AND IMPAIRMENT REVERSAL

At December 31, 2013 there were no indicators of impairment in the Company's CGUs; thus no impairment test was performed.

In 2012, declines in forecasted commodity prices were indicators of impairment. Accordingly, the Company tested its gas-weighted CGUs for impairment and determined that the aggregate carrying value of these CGUs was $20 million higher than the recoverable amounts and impairments were recorded. The recoverable amounts of the CGUs were estimated based on the fair value less costs to sell. See notes 4 and 5.

In the third quarter of 2013, certain oil and natural gas assets from the Company's Horizontal Cardium CGU were transferred to assets held for sale. As such, an impairment test was performed on the Company's Horizontal Cardium CGU and it was concluded that no impairment existed, as the value-in-use exceeded the carrying amount of the assets. Subsequent to the impairment test, the carrying amount of certain oil and gas assets within the property, plant and equipment was transferred to assets held for sale and 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. The carrying value of property, plant and equipment transferred to assets held for sale was $44.6 million higher than the fair value less costs to sell and an impairment loss was recorded. The property disposition transaction was completed in October 2013.

8. BANK LOANS

At December 31, 2013, the Company has a $28 million extendible committed term bank facility with a Canadian bank. This revolving operating loan facility has a term date of May 31, 2014, and if not extended, any outstanding advances would become repayable one year later on May 31, 2015. 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 3.6% depending on the borrowing option used.

The average effective interest rate on advances under these and prior operating loan facilities in 2013 was 5.5% (December 31, 2012 - 4.7%). The Company had $0.1 million in letters of credit outstanding at December 31, 2013 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.

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 and the current portion of any bank debt, convertible debentures and capital leases, if any, are excluded from the above amounts.

The available lending limit of the facility is scheduled to be reviewed on or before May 31, 2014 and is based on the bank's interpretation of the Company's reserves and future commodity prices. There can be no assurance that the amount or terms of the available facility will not be adjusted at the next review.

At December 31, 2012, the Company had total bank facilities of $65 million with a syndicate of Canadian banks under which bank loans of $48.1 million were outstanding. The bank loans were repaid with proceeds from the disposition of assets in the fourth quarter of 2013, and the bank facilities were terminated.

9. CONVERTIBLE DEBENTURES

On December 31, 2010, the Company issued $50 million of convertible unsecured subordinated debentures (the "Series A Debentures") on a bought deal basis. The Series A Debentures have a face value of $1,000, bear interest at the rate of 7.5% per annum payable semi-annually in arrears on the last day of January and July of each year commencing on July 31, 2011 and mature on January 31, 2016 (the "Maturity Date"). The Series A Debentures are convertible at the holder's option at a conversion price of $1.55 per common share (the "Conversion Price"), subject to adjustment in certain events. The Series A Debentures are not redeemable by the Company before January 31, 2014. On or after January 31, 2014 and prior to the Maturity Date, the Series A Debentures are redeemable at the Company's option, in whole or in part, at a price equal to their principal amount plus accrued and unpaid interest if the weighted average trading price of the common shares on the Toronto Stock Exchange for the 20 consecutive trading days preceding the date on which the notice of redemption is given is not less than 125% of the Conversion Price. The Series A Debentures are listed and posted for trading on the TSX under the symbol "AXL.DB".

On June 8, 2011, the Company issued $46 million of convertible unsecured subordinated debentures (the "Series B Debentures") on a bought deal basis. The Series B Debentures have a face value of $1,000, bear interest at the rate of 7.25% per annum payable semi-annually in arrears on the last day of June and December of each year commencing on December 31, 2011 and mature on June 30, 2017 ("Maturity Date"). The Series B Debentures are convertible at the holder's option at a conversion price of $1.70 per common share (the "Conversion Price"), subject to adjustment in certain events. The Series B Debentures are not redeemable by the Company before June 30, 2014. On and after June 30, 2014 and prior to June 30, 2016, the Series B Debentures are redeemable at the Company's option, in whole or in part, at a price equal to their principal amount plus accrued and unpaid interest if the weighted average trading price of the common shares on the Toronto Stock Exchange for the 20 consecutive trading days preceding the date on which the notice of redemption is given is not less than 125% of the Conversion Price. On or after June 30, 2016 and prior to the Maturity Date, the Series B Debentures may be redeemed in whole or in part at the option of the Company on not more than 60 days and not less than 30 days prior notice at a price equal to their principal amount plus accrued and unpaid interest. The Series B Debentures are listed and posted for trading on the TSX under the symbol "AXL.DB.B".

Both the Series A and the Series B Debentures were determined to be compound instruments. As the Series A and Series B Debentures are convertible into common shares, the liability and equity components are presented separately. The initial carrying amount of the financial liability is determined by discounting the stream of future payments of interest and principal. Using the residual method, the carrying amount of the conversion feature is the difference between the principal amount and the carrying value of the financial liability. The Series A and Series B Debentures, net of the equity component and issue costs are accreted using the effective interest rate method over the term of the Series A and Series B Debentures, such that the carrying amount of the financial liability will equal the $50 million and $46 million principal balance at maturity respectively.

The following table indicates the convertible debenture activities:


Proceeds

Debt component

Equity component
Balance, December 31, 2011 $ 91,560 $ 84,796 $ 5,019
Accretion expense - 1,957 -
Balance, December 31, 2012 $ 91,560 $ 86,753 $ 5,019
Accretion expense - 2,169 -
Balance, December 31, 2013 $ 91,560 $ 88,922 $ 5,019
10. DECOMMISSIONING OBLIGATIONS
December 31, 2013 December 31, 2012
Balance at January 1 $ 46,467 $ 62,848
Provisions incurred 438 1,187
Total abandonment expenditures (971 ) (506 )
Provisions disposed (7,865 ) (20,865 )
Change in estimates (8,470 ) 2,735
Accretion expense 814 1,068
Ending balance $ 30,413 $ 46,467

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 $30.4 million as at December 31, 2013 (December 31, 2012 - $46.5 million) based on an undiscounted inflation-adjusted total future liability of $49.9 million (December 31, 2012 - $55.8 million). These payments are expected to be made over the next 30 years with the majority of costs to be incurred between 2015 and 2028. At December 31, 2013, the liability has been calculated using an inflation rate of 2.0% (December 31, 2012 - 2.0%) and discounted using a risk-free rate of 1.1% to 3.2% (December 31, 2012 - 1.0% to 2.5%) depending on the estimated timing of the future obligation.

11. TAXES

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 income taxes. The difference results from the following items:

December 31, 2013 December 31, 2012
Loss before taxes $ (61,968 ) $ (41,738 )
Combined federal and provincial tax rates 25.0 % 25.0 %
Expected deferred income tax benefit (15,492 ) (10,434 )
Increase in income taxes resulting from:
Derecognition of previously recognized deferred tax asset 45,634 -
Other temporary differences not recognized 13,370 -
Non-deductible share-based compensation and other 122 189
Deferred income tax expense (benefit) $ 43,634 $ (10,245 )

During the second quarter of 2013, the Company derecognized deferred tax assets of $45.6 million in respect of deductible temporary difference due to the material uncertainties related to the outcome of the strategic alternatives process. With the conclusion of the strategic alternatives process, the Company assessed the probability that future taxable profit will be available against which the Company can utilize the benefits of tax pools in excess of the carrying amount of assets and recorded $2.0 million of deferred tax assets as of December 31, 2013. The Company has approximately $355 million of tax pools at December 31, 2013, which include loss carry forwards of approximately $196 million that will expire between 2025 and 2033.

The components of the deferred tax asset are as follows:

December 31, 2013 December 31, 2012
Deductible (taxable) temporary differences:
Property, plant and equipment $ 2,000 $ (3,573 )
Decommissioning obligations - 11,617
Convertible debentures - (2,312 )
Non-capital losses - 38,484
Share issue costs and other - 1,418
Deferred income tax asset $ 2,000 $ 45,634
A continuity of the net deferred income tax asset is detailed in the following table:
December 31, 2013 December 31, 2012
Deferred income tax asset, beginning of the year $ 45,634 $ 35,389
Recognized in profit and loss (43,634 ) 10,245
Deferred income tax asset, end of the year $ 2,000 $ 45,634
Deferred tax assets have not been recognized in respect of the following deductible (taxable) temporary differences:
December 31, 2013 December 31, 2012
Property, plant and equipment $ 12,468 $ -
Decommissioning obligations 30,413 -
Derivative contracts 146 -
Convertible debentures (7,078 ) -
Share issue costs 2,667 -
Non-capital losses 196,316 -
$ 234,932 $ -

12. 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.

Number of Common Shares
Amount
Balance at December 31, 2013 and 2012 172,549,701 $ 171,460

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 either five or 10 years 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 years ended December 31, 2013 and 2012 are as follows:

December 31, 2013 December 31, 2012
Number of options Weighted average exercise price Number of options Weighted average exercise price
Opening balance 14,386,800 $ 0.75 14,014,182 $ 1.69
Granted during the year 3,160,100 0.13 5,745,500 0.31
Expired during the year (1,295,617 ) 1.89 (4,273,582 ) 3.22
Forfeited during the year (837,933 ) 0.49 (1,099,300 ) 0.80
Ending balance 15,413,350 $ 0.54 14,386,800 $ 0.75
Exercisable, end of year 7,951,817 $ 0.79 5,629,583 $ 1.15
The range of exercise prices of the outstanding options is as follows:
Range of exercise prices Number of options Weighted average exercise
price
Weighted average remaining life (years )
$0.13 to $0.20 3,160,100 $ 0.13 4.8
$0.21 to $0.32 5,099,300 0.31 3.8
$0.33 to $0.50 120,000 0.45 2.8
$0.51 to $0.77 2,409,600 0.70 2.6
$0.78 to $1.17 4,390,350 0.93 1.2
$1.18 to $1.77 141,000 1.21 2.0
$2.68 to $4.00 93,000 4.00 0.4
Total at December 31, 2013 15,413,350 $ 0.54 3.0
There were no options exercised in 2013 or 2012.
The fair value of the options was estimated using the Black-Scholes model with the following weighted average inputs:
December 31, 2013 December 31, 2012
Fair value at grant date $ 0.07 $ 0.17
Common share price $ 0.13 $ 0.31
Exercise price $ 0.13 $ 0.31
Volatility 68 % 65 %
Option life 5 years 5 years
Dividends 0 % 0 %
Risk-free interest rate 1.8 % 1.3 %
Forfeiture rate 20 % 15 %

This estimated forfeiture rate is adjusted to the actual forfeiture rate when each tranche vests. Share-based compensation of $0.5 million (December 31, 2012 - $0.8 million) was expensed during the year ended December 31, 2013. In addition, share-based compensation of $0.3 million (December 31, 2012 - $0.3 million) was capitalized during the year ended December 31, 2013.

13. LOSS PER SHARE

Basic and diluted loss per share was calculated as follows:

December 31, 2013 December 31, 2012
Loss for the year $ (105,601 ) $ (31,493 )
Weighted average number of common shares (basic), beginning and end of year (in thousands of shares) 172,550 172,550
Basic and diluted loss per share $ (0.61 ) $ (0.18 )

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 year ended December 31, 2013, 15,413,350 options (December 31, 2012 - 14,386,800 options) and 59,316,889 common shares reserved for convertible debentures (December 31, 2012 - 59,316,889) were excluded from calculating dilutive earnings as they were anti-dilutive.

14. OTHER GAINS (LOSSES)

Revenues for all product sales and services and expense recoveries are as follows:

December 31, 2013 December 31, 2012
Revenue from oil and gas sales, net of royalties $ 48,850 $ 69,815
Other income (expense):
Realized gain (loss) on derivative contracts $ (3,718 ) $ 5,429
Unrealized gain (loss) on derivative contracts 951 (2,481 )
$ (2,767 ) $ 2,948
Expenses recovered from third parties:
Operating expense recoveries for use of transportation and processing assets $ 2,638 $ 3,551
General and administrative overhead expense recoveries 477 450
$ 3,115 $ 4,001

Major customers. The revenues derived from external customers who individually amounted to 10 per cent or more of the Company's revenues are as follows: $28.7 million (December 31, 2012 - $31.6 million), $13.2 million (December 31, 2012 - $13.7 million) and $0.3 million (December 31, 2012 - $10.9 million).

15. EXPENSES BY NATURE

December 31, 2013 December 31, 2012
Third-party gathering, processing and treating services $ 5,983 $ 9,328
External services(1) 5,434 8,248
Employee benefit expenses (note 16) 5,736 7,504
Operating leases and equipment rents(2) 2,535 4,272
Repairs and maintenance 2,143 2,940
Materials and supplies 1,799 2,254
Other expenses 667 (383 )
Expenses by nature $ 24,297 $ 34,163
Above costs allocated to the following functions:
Operating $ 16,915 $ 24,239
General and administrative 7,382 9,924
Total operating and general and administrative expenses $ 24,297 $ 34,163
(1) External services include professional fees, contract operators, consulting fees, design fees and other operating and administrative services.
(2) Operating leases and equipment rents include office leases, surface leases, and equipment rents.
16. EMPLOYEE BENEFIT EXPENSES
General and administrative expenses include employee benefit expense as follows:
December 31, 2013 December 31, 2012
Short-term employee benefits $ 6,583 $ 9,368
Share-based payments 820 1,033
Total employee remuneration 7,403 10,401
Capitalized portion of employee remuneration (1,667 ) (2,897 )
$ 5,736 $ 7,504
Employees include all staff and directors of the Company. Personnel expenses directly attributed to capital activities have been capitalized and included in property, plant and equipment.
17. FINANCE INCOME AND EXPENSES
December 31, 2013 December 31, 2012
Income:
Interest income on cash equivalents $ 62 $ 1
Other interest income 102 48
Expenses:
Interest and financing costs on bank loans (2,651 ) (4,610 )
Interest on convertible debentures (7,085 ) (7,085 )
Accretion on convertible debentures (note 9) (2,169 ) (1,957 )
Accretion on decommissioning obligations (note 10) (814 ) (1,068 )
Other (120 ) (52 )
Net finance expenses $ (12,675 ) $ (14,723 )
18. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in non-cash working capital is comprised of:
December 31, 2013 December 31, 2012
Source (use) of cash
Accounts receivable and accruals $ 3,179 $ 4,391
Prepaid expenses and deposits 502 538
Accounts payable and accruals (4,690 ) (32,466 )
$ (1,009 ) $ (27,537 )
Related to operating activities $ 202 $ 704
Related to financing activities $ - $ (175 )
Related to investing activities $ (1,211 ) $ (28,066 )

19. FINANCIAL RISK MANAGEMENT

(a) Overview. The Company's activities expose it to a variety of financial risks that arise as a result of its exploration, development, production, and financing activities such as:

  • credit risk;
  • liquidity risk; and
  • market risk.

This note presents information about the Company's exposure to each of the above risks, the Company's objectives, policies and processes for measuring and managing risk, and the Company's management of capital. Further quantitative disclosures are included throughout these consolidated financial statements.

The Board of Directors oversees management's establishment and execution of the Company's risk management framework. Management has implemented, and monitors compliance with risk management policies. 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.

(b) 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, and arises principally from the Company's receivables from joint venture partners and oil and natural gas customers. The maximum exposure to credit risk is as follows:

December 31, 2013 December 31, 2012
Cash and cash equivalents $ 25,111 $ 1
Accounts receivable and accruals 6,702 9,881
$ 31,813 $ 9,882

Accounts receivable and accruals. All of the Company's operations are conducted in Canada. The Company's exposure to credit risk is influenced mainly by the individual characteristics of each customer or joint venture partner.

A substantial portion of the Company's accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. Receivables from oil and natural gas customers are normally collected on the 25th day of the month following the related sale of oil and gas production. The Company's policy to mitigate credit risk associated with these balances is to establish commercial relationships with large customers. The Company historically has not experienced any significant collection issues with its oil and natural gas customers. Receivables from joint venture partners are typically collected within ninety days.

The Company attempts to mitigate the risk from joint venture receivables by obtaining venturer pre-approval of significant capital expenditures. However, the receivables are from participants in the oil and natural gas sector, and collection of the outstanding balances is dependent on industry factors such as commodity price fluctuations, escalating costs and the risk of unsuccessful drilling. In addition, further risk exists with joint venturers as disagreements occasionally arise that increase the potential for non-collection.

The Company does not typically obtain collateral from oil and natural gas customers or joint venturers; however, the Company does have the ability to withhold production from joint venturers in the event of non-payment.

The Company's allowance for doubtful accounts as at December 31, 2013 was $0.9 million (December 31, 2012 - $0.9 million). This allowance was mostly created in prior years and is associated with prior corporate acquisitions and potential joint venture billing disputes.

The maximum exposure to credit risk for accounts receivable and accruals, net of allowance for doubtful accounts at the reporting date by type of customer was:

Carrying Amount
December 31, 2013 December 31, 2012
Oil and natural gas customers $ 1,584 $ 4,290
Joint venture partners 4,724 5,220
Other 394 371
$ 6,702 $ 9,881
As of December 31, 2013 and December 31, 2012, the Company's accounts receivable and accruals, net of allowance for doubtful accounts was aged as follows:
Aging December 31, 2013 December 31, 2012
Not past due $ 6,244 $ 8,947
Past due by less than 120 days 182 837
Past due by more than 120 days 276 97
Total $ 6,702 $ 9,881

These amounts exclude offsetting amounts owing to joint venture partners that are included in accounts payable and accruals.

(c) 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.

To achieve this objective, 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 provide capital when needed, the Company has a revolving reserves-based credit facility which is reviewed annually by its lender. This facility is described in note 8. The Company also attempts to match its payment cycle with collection of oil and natural gas revenue on the 25th of each month.

The following are the contractual maturities of financial liabilities, including associated interest payments on convertible debentures and excluding the impact of netting agreements at December 31, 2013:

Financial Liabilities Less than
one year
One to
two years
Two to
three years
Three to four years Four to
five years
Non-derivative financial liabilities
Accounts payable and accruals (1) $ 23,417 $ - $ - $ - $ -
Convertible debentures
- Interest (1) 5,523 7,085 5,210 1,667 -
- Principal - - 50,000 46,000 -
Total $ 28,940 $ 7,085 $ 55,210 $ 47,667 $ -
  1. Accounts payable and accruals includes $1.6 million of interest relating to convertible debentures. The total cash interest payable in less than one year on the convertible debentures is $7.1 million.
The following table shows the Company's accounts payable and accruals:
Carrying Amount
December 31, 2013 December 31, 2012
Trade payables $ 7,585 $ 8,791
Accruals (1) 15,832 19,316
$ 23,417 $ 28,107
(1) Accruals include amounts for goods and services that have been received or supplied but have not been paid, invoiced or formally agreed with the supplier as of the reporting date. These accruals relate to both operating and capital activities.

(d) Market risk. Market risk is the risk that changes in market prices, such as commodity prices, foreign exchange rates and interest rates that will affect the Company's income 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 obtained by the Company are influenced by both U.S. and Canadian demand and the corresponding North American supply, and recently, by imports of liquefied natural gas. 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 December 31, 2013 or December 31, 2012.

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 the outstanding bank loans fluctuates with the interest rates posted by the lenders. 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 (see note 9). Had the borrowing rate on bank loans been 100 basis points higher (or lower) throughout the year ended December 31, 2013, earnings would have been affected by $0.3 million (December 31, 2012 - $0.6 million) based on the average bank debt balance outstanding during the year.

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.

It is the Company's policy to economically hedge some oil and natural gas sales through the use of various financial derivative forward sales contracts and physical sales contracts. The Company does not apply hedge accounting for these contracts. The Company's production is usually sold using "spot" or near term contracts, with prices fixed at the time of transfer of custody or on the basis of a monthly average market price. The Company, however, may give consideration in certain circumstances to the appropriateness of entering into long term, fixed price sales contracts. The Company does not enter into commodity contracts other than to meet the Company's expected sale requirements.

At December 31, 2013 the following derivative contracts were outstanding and recorded at estimated fair value:

Type of Contract(1) Commodity
Volume
Weighted Average
Fixed Price

Remaining Period
Financial swap Natural gas 2,500 GJ/d $ 3.55/GJ January 1, 2014 to December 31, 2014
  1. Swap indicates fixed price payable to Anderson in exchange for floating price payable to counterparty.

The estimated fair value of the financial gas contract has been determined on the amounts the Company would receive or pay to terminate the gas contract. At December 31, 2013, the Company estimates that it would pay $0.1 million to terminate this contract.

The fair value of the financial commodity risk management contracts have been allocated to current and non-current liabilities on a contract by contract basis as follows:

December 31, 2013 December 31, 2012
Current liability $ (146 ) $ (1,097 )
Net liability position $ (146 ) $ (1,097 )
The fair value of derivative contracts at December 31, 2013 would have been impacted as follows had the gas prices used to estimate the fair value changed by:
Effect of an increase in price on after-tax earnings Effect of a decrease in price on after-tax earnings
Canadian $0.50 per GJ change in the gas price $ (342 ) $ 342

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.

(e) 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 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 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:

December 31, 2013 December 31, 2012
Current liabilities(1) $ 23,417 $ 28,107
Current assets(1) (33,099 ) (11,670 )
Working capital deficiency (surplus) $ (9,682 ) $ 16,437
Bank loans - 48,094
Net debt before convertible debentures (9,682 ) 64,531
Convertible debentures (liability component)(2) 88,922 86,753
Total net debt $ 79,240 $ 151,284
Shareholders' equity 28,179 132,960
Total capitalization $ 107,419 $ 284,244
  1. Excludes unrealized gains (losses) on derivative contracts.
  2. Face value of convertible debentures: Series A Debentures $50 million, Series B Debentures $46 million.

Proceeds from the disposition of assets in 2012 and 2013 were used to repay all outstanding bank loans. At December 31, 2013, the Company had a $9.7 million working capital surplus and a $28 million unused bank credit facility. The Series A Debentures mature on January 31, 2016 and the Series B Debentures mature on June 30, 2017. Upon maturity, the Company may settle the principal in cash or by the issuance of additional common shares.

Funds from operations were $11.3 million for the year ended December 31, 2013 ($29.6 million for the year ended December 31, 2012). Historical funds from operations will not be indicative of future funds from operations as a result of the asset sales and future drilling programs. 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, 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 8. The Company has complied with this financial covenant for the year ended December 31, 2013. 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.

20. RELATED PARTY TRANSACTIONS

Key management personnel are comprised of all officers and directors of the Company.

Compensation of key management personnel was as follows:

December 31, 2013 December 31, 2012
Salaries and other short-term employee benefits $ 2,602 $ 2,720
Share-based payments 658 629
$ 3,260 $ 3,349
Capitalized portion of key management personnel compensation (1,462 ) (1,340 )
$ 1,798 $ 2,009

21. COMMITMENTS

(a) Capital commitments. As of December 31, 2013, the Company had commitments for future capital expenditures of $1.0 million that are expected to be incurred during the first quarter of 2014. Subsequent to December 31, 2013, the Company entered into a farm-in agreement to drill one Cardium oil well prior to October 31, 2014 to earn a working interest in the farm-out lands. The capital commitment associated with the well is $2.5 million.

(b) Operating lease commitments. The Company leases various equipment, vehicles, and surface land locations under cancellable operating lease agreements. Surface lease arrangements may be cancelled at any time following reclamation of any site used in the Company's operations. For equipment and vehicle leases, the Company may terminate the leases at any time, subject to certain immaterial conditions and guarantees.

The Company leases various offices and computer software under non-cancellable operating lease agreements. The head office lease terminates on June 30, 2014, while other lease terms are between one and four years, and the majority of lease agreements are renewable at the end of the lease period at the prevailing market rate.

The minimum future payments under non-cancellable operating leases are as follows:

December 31, 2013
Less than one year $ 491
Between one year and four years 75
$ 566

The total operating lease expenditure charged to the income statement during the year is disclosed in note 15.

(c) Other commitments. The Company has entered into firm service gas transportation agreements in which the Company guarantees certain minimum volumes of natural gas will be shipped on various gas transportation systems. The terms of the various agreements expire in one to seven 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:

2014 2015 2016 2017 2018 Thereafter
Firm service commitment $ 878 $ 748 $ 158 $ 127 $ 117 $ 136
Firm service committed volumes (MMcfd) 7 5 4 3
3
3

Corporate Information
Head Office
2200, 333 - 7th Avenue S.W.
Calgary, Alberta
Canada T2P 2Z1
Phone (403) 262-6307
Fax (403) 261-2792
Website http://www.andersonenergy.ca/

Directors
J.C. Anderson
Calgary, Alberta

Brian H. Dau
Calgary, Alberta

Christopher L. Fong (1)(2)(3)
Calgary, Alberta

David J. Sandmeyer (1)(2)(3)
Calgary, Alberta
Chairman of the Board

David G. Scobie (1)(2)(3)
Calgary, Alberta

Member of:
(1) Audit Committee
(2) Compensation & Corporate Governance Committee
(3) Reserves Committee

Officers
Brian H. Dau
President & Chief Executive Officer

David M. Spyker
Chief Operating Officer

M. Darlene Wong
Vice President, Finance, Chief Financial
Officer & Corporate Secretary

Blaine M. Chicoine
Vice President, Drilling and Completions

Sandra M. Drinnan
Vice President, Land

Philip A. Harvey
Vice President, Exploitation

Jamie A. Marshall
Vice President, Exploration

Auditors
KPMG LLP

Independent Engineers
GLJ Petroleum Consultants Ltd.

Legal Counsel
Bennett Jones LLP

Registrar & Transfer Agent
Valiant Trust Company

Stock Exchange
The Toronto Stock Exchange
Symbol AXL, AXL.DB, AXL.DB.B

Investor Relations Contact
Anderson Energy Ltd.
Brian H. Dau
President & Chief Executive Officer
(403) 262-6307
info@andersonenergy.ca

Abbreviations
bbl - barrel
bpd - barrels per day
BOE - barrels of oil equivalent
BOED - barrels of oil equivalent per day
BOPD - barrels of oil per day
m3 - cubic meters
Mbbls - thousand barrels
MBOE - thousand barrels of oil equivalent
MMBOE - million barrels of oil equivalent
Mstb - thousand stock tank barrels
WTI - West Texas Intermediate
AECO - intra-Alberta Nova inventory transfer price
Bcf - billion cubic feet
GJ - gigajoule
Mcf - thousand cubic feet
Mcfd - thousand cubic feet per day
MMBtu - million British thermal units
MMcf - million cubic feet
MMcfd - million cubic feet per day
NGL - natural gas liquids
Cdn - Canadian
US - United States

Contact Information