Anderson Energy Announces 2013 Third Quarter Results

November 12, 2013 6:00 AM

CALGARY, ALBERTA–(Marketwired – Nov. 12, 2013) – Anderson Energy Ltd. (“Anderson” or the “Company”) (TSX:AXL) announces its operating and financial results for the third quarter ended September 30, 2013.

HIGHLIGHTS

Funds from operations in the third quarter of 2013 were $1.4 million. Production was 3,449 BOED. Oil and NGL production averaged 1,263 bpd in the third quarter of 2013. Oil represented 983 bpd of total production. Funds from operations for the first nine months of 2013 were $11.6 million.
The Company’s average oil price was $100.81 per bbl in the third quarter of 2013 ($83.09 per bbl after the loss on derivative contracts).
Oil and NGL revenue represented 79% of Anderson’s total oil and gas revenue in the third quarter of 2013.
The operating netback was $17.77 per BOE in the third quarter of 2013 compared to $20.54 per BOE in the third quarter of 2012. The operating netback for the Cardium properties averaged $49.73 per BOE in the third quarter of 2013. The realized loss on derivative contracts reduced the third quarter netback by $5.05 per BOE in 2013. All outstanding derivative contracts expire by the end of 2013.
In October 2013, the Company closed the sale of its Garrington and Ferrier Cardium oil and natural gas properties, repaid its bank debt, finalized a new revolving production loan facility for $28 million, and concluded its strategic alternatives review process. At the end of October 2013, the Company had approximately $24 million in cash deposits after repaying the bank debt.
The Company’s business plan is to grow its BOED production and the percentage of production derived from oil and NGL with light oil production from Cardium horizontal drilling using slickwater frac technology and the Company’s industry leading capital cost solution in the Cardium horizontal light oil play.
A seven gross well Cardium horizontal light oil winter drilling program has recently commenced. All seven wells are planned to be on production by the second quarter of 2014. The Company estimates it will spend approximately $33 million in field capital expenditures from now to the end of 2014, with approximately 90% spent on the drilling, completion and well tie-in of approximately 11 net Cardium wells. Based on this capital program, the Company currently estimates that 2014 average production will increase to approximately 2,600 BOED (33% oil and NGL) from the current post-asset disposition production of approximately 2,200 BOED (22% oil and NGL). The Company will update its business plan for 2014 at the end of the first quarter and provide updated 2014 capital and production guidance at that time.

FINANCIAL AND OPERATING HIGHLIGHTS

		Three months ended September 30								Nine months ended September 30
(thousands of dollars, unless otherwise stated)		2013			2012			% Change		2013			2012			% Change
Oil and gas sales*		$	13,287		$	17,013		(22	%)	$	45,766		$	62,532		(27	%)
Revenue, net of royalties*		$	11,949		$	15,284		(22	%)	$	41,562		$	56,019		(26	%)

Funds from operations		$	1,408		$	5,725		(75	%)	$	11,595		$	23,947		(52	%)
Funds from operations per share
	Basic and diluted	$	0.01		$	0.03		(67	%)	$	0.07		$	0.14		(50	%)

Earning (loss) before effect of impairment loss and deferred tax adjustment		$	(4,156	)	$	94		N/A		$	(12,941	)	$	(7,598	)	(70	%)
Earnings (loss) per share before effect of impairment loss and deferred tax adjustment, basic and diluted		$	(0.02	)	$	–		N/A		$	(0.07	)	$	(0.04	)	(75	%)

Earnings (loss)		$	(48,737	)	$	94		N/A		$	(103,156	)	$	(22,598	)	(356	%)
Earnings (loss) per share
	Basic and diluted	$	(0.28	)	$	–		N/A		$	(0.60	)	$	(0.13	)	(362	%)

Capital expenditures, net of proceeds on dispositions		$	229		$	(28,986	)	101	%	$	8,077		$	(12,110	)	167	%

Bank loans										$	53,945		$	88,922		(39	%)
Other working capital deficiency (surplus) **										$	(70,444	)	$	8,069		973	%

Convertible debentures										$	88,361		$	86,247		2	%

Shareholders’ equity										$	30,466		$	141,751		(79	%)

Average shares outstanding (thousands)
	Basic & Diluted		172,550			172,550		–			172,550			172,550		–
Ending shares outstanding (thousands)			172,550			172,550		–			172,550			172,550		–

Average daily sales:
	Oil (bpd)		983			1,274		(23	%)		1,235			1,632		(24	%)
	NGL (bpd)		280			576		(51	%)		260			676		(62	%)
	Natural gas (Mcfd)		13,119			23,519		(44	%)		14,157			25,799		(45	%)
	Barrels of oil equivalent (BOED)		3,449			5,770		(40	%)		3,854			6,607		(42	%)
Average prices:
	Oil ($/bbl)	$	100.81		$	80.44		25	%	$	90.71		$	84.03		8	%
	NGL ($/bbl)	$	52.97		$	51.59		3	%	$	53.62		$	58.06		(8	%)
	Natural gas ($/Mcf)	$	2.27		$	2.24		1	%	$	2.86		$	1.98		44	%
	Barrels of oil equivalent ($/BOE)*	$	41.87		$	32.05		31	%	$	43.49		$	34.54		26	%
Realized gain (loss) on derivative contracts ($/BOE)		$	(5.05	)	$	3.16		(260	%)	$	(2.71	)	$	1.77		(253	%)
Royalties ($/BOE)		$	4.22		$	3.26		29	%	$	3.99		$	3.60		11	%
Operating costs ($/BOE)		$	14.47		$	11.28		28	%	$	13.01		$	10.62		23	%
Transportation costs ($/BOE)		$	0.36		$	0.13		177	%	$	0.32		$	0.25		28	%
Operating netback ($/BOE)		$	17.77		$	20.54		(13	%)	$	23.46		$	21.84		7	%

Wells drilled (gross)			–			–		–			2			3		(33	%)

* Includes royalty and other income classified with oil and gas sales, but excludes realized and unrealized gains or losses on derivative contracts. 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 a energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

**Excludes unrealized gains or losses on derivative contracts. 2013 includes assets held for sale and decommissioning obligations held for sale.

SLICKWATER FRAC TECHNOLOGY

The average initial production (“IP”) performance for various calendar day averages of the wells drilled by the Company that were completed using slick water frac technology is shown below:

Average gross initial production (initial production days)	IP 30	IP 60	IP 90	IP 180	IP 270
Number of wells in average	7	7	7	7	6
Barrels of oil per day (BOPD)	301	225	184	116	101
Barrels of oil and NGL per day (BPD)	329	250	208	142	116
Barrels of oil equivalent per day (BOED)*	453	362	309	225	178

* 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.

PRODUCTION

Production in the third quarter of 2013 was 3,449 BOED, of which 1,263 bpd (37%) was derived from oil and natural gas liquids production. Overall production was lower in the third quarter of 2013 compared to the same period in 2012 due to property dispositions completed in 2012 and natural declines in other properties.

At various times during 2012 and 2013, as a result of fluctuating natural gas prices, certain natural gas production has been shut in. At the end of the third quarter, approximately 1.4 MMcfd of natural gas was still shut in. Natural gas pricing in the third quarter of 2013 was negatively impacted by changes in third party pipeline interruptible tolling practices in the quarter which compromised the export of Alberta gas and reduced natural gas pricing in the quarter.

FINANCIAL RESULTS

	Average oil and NGL price ($/bbl) *	Average wellhead natural gas price ($/Mcf)	Revenue ($/BOE)	Operating netback ($/BOE) *	Funds from operations ($/BOE)*
2011	86.53	3.60	42.13	25.89	19.40
2012	75.88	2.21	34.98	22.71	13.33
Nine months ended September 30, 2013	84.26	2.86	43.49	23.46	11.02

* Average prices exclude gains and losses on derivative contracts. These gains and losses increased (reduced) operating netback and funds from operations by $(5.05) per BOE in 2013, $2.44 per BOE in 2012 and $(0.22) per BOE in 2011.

Anderson’s funds from operations were $1.4 million in the third quarter of 2013 compared to $5.7 million in the third quarter of 2012. The Company’s average crude oil and natural gas liquids sales prices in the third quarter of 2013 were $100.81 and $52.97 per bbl respectively compared to $80.44 and $51.59 per bbl in the third quarter of 2012. During the third quarter of 2013, oil and NGL revenue represented 79% of Anderson’s total oil and gas revenue compared to 72% in the third quarter of 2012. The Company’s average natural gas sales price was $2.27 per Mcf in the third quarter of 2013 compared to $2.24 per Mcf in third quarter of 2012. The Company recorded a loss of $48.7 million in the third quarter of 2013 due to the impairment of assets held for sale. The Company’s operating netback was $17.77 per BOE in the third quarter of 2013 compared to $20.54 per BOE in the third quarter of 2012. The decrease in the operating netback was primarily due to higher operating costs resulting from increased transportation and equalization costs as well as the impact of fixed costs on lower sales volumes. Anderson’s netback for its Cardium horizontal properties in the third quarter of 2013 was $49.73 per BOE (exclusive of hedging). The Company has fixed price swap contracts on 800 bpd of crude oil production at an average price of $90.56 WTI Canadian per bbl for October 2013 and 500 bbls per day for November and December 2013 at an average price of $90.63 WTI Canadian per bbl. The mark-to-market loss on derivative contracts was $1.0 million at September 30, 2013.

Capital expenditures were $0.2 million in the third quarter of 2013. This compares to capital expenditures before dispositions of $1.7 million in the third quarter of 2012.

LIGHT OIL HORIZONTAL DRILLING INVENTORY

The Company’s undeveloped light oil horizontal drilling inventory (after the sale of Garrington and Ferrier properties that closed in October 2013) is outlined below:

Undeveloped drilling inventory as of October 31, 2013 (number of drilling locations)		Gross	Net *
	Willesden Green	102	76
	Pembina	37	9
	Total	139	85

* Net is net revenue interest. The December 31, 2012 reserves report includes proved plus probable reserves for 20 net undeveloped locations related to these properties.

STRATEGY AND OUTLOOK

Over the course of the strategic alternatives process, which began in February 2012, the Company has:

sold over $150 million in assets;
reduced bank debt from $106.7 million at March 31, 2012 to nil at the date hereof;
reduced total net 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 approximately $81 million at the end of October 2013;
restructured all of its shallow gas and Cardium drilling commitments so that by the end of January 2013, the Company had completed all of its drilling commitments;
demonstrated the improved production performance from slick water fracture stimulation; and
continued to be an industry leader in low capital costs in the Cardium horizontal light oil play.

As a result, the Board of Directors concluded the strategic alternatives review process in October 2013 and the Company will commence a horizontal light oil development program with cash flow, available cash and credit facilities. Current post-asset disposition production is approximately 2,200 BOED (22% oil and NGL).

The Company’s business plan is to grow its BOED production and the percentage of production derived from oil and NGL with light oil production from Cardium horizontal oil drilling. Accordingly, a seven gross well Cardium horizontal light oil winter drilling program commenced November 5, 2013, with all seven wells planned to be on production by the second quarter of 2014. The Company estimates that it will spend approximately $33 million in field capital expenditures from now to the end of 2014, with approximately 90% being spent on the drilling, completion and tie-in of approximately 11 net Cardium light oil wells. Based on this capital program, the Company estimates 2014 production will be approximately 2,600 BOED (33% oil and NGL). The Company has also embarked on a program to optimize, rationalize, consolidate and improve the profitability of its Edmonton Sands shallow gas assets. The Company will update its business plan for 2014 at the end of the first quarter and provide updated 2014 capital and production guidance at that time.

The disposition of the Garrington and Ferrier properties and the lack of drilling activity since the first quarter of 2013 will negatively impact funds from operations, particularly in the fourth quarter of 2013. However, the seven well drilling program will begin to contribute positively to increased oil production and funds from operations in the first and second quarters of 2014.

Further information is available on the Company’s website at www.andersonenergy.ca.

Brian H. Dau, President & Chief Executive Officer

November 12, 2013

Management’s Discussion and Analysis

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2013 AND 2012

The following management’s discussion and analysis (“MD&A”) is dated November 11, 2013 and should be read in conjunction with the unaudited condensed interim consolidated financial statements of Anderson Energy Ltd. (“Anderson” or the “Company”) for the three and nine months ended September 30, 2013 and the audited consolidated financial statements and management’s discussion and analysis of Anderson for the years ended December 31, 2012 and 2011.

Included in the discussion and analysis are references to terms commonly used in the oil and gas industry such as funds from operations, finding, development and acquisition (“FD&A”) costs, operating netback and barrels of oil equivalent (“BOE”). Funds from operations as used in this report represent cash from operating activities before changes in non-cash working capital and decommissioning expenditures. See “Review of Financial Results – Funds from Operations” for details of this calculation. Funds from operations represent both an indicator of the Company’s performance and a funding source for on-going operations. FD&A costs measure the cost of reserves additions and are an indicator of the efficiency of capital expended in the period. Operating netback is calculated as oil and gas sales plus 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, depletion and depreciation expenses, and gains or losses on sale of property, plant and equipment. Production volumes and reserves are commonly expressed on a BOE basis whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. Although the intention is to sum oil and natural gas measurement units into one basis for improved analysis of results and comparisons with other industry participants, BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 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. 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. These terms are not defined by International Financial Reporting Standards (“IFRS”) and therefore are referred to as additional GAAP measures.

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

Consistent with the results reported in the first and second quarters of 2013, revenue and production for the three and nine month periods ended September 30, 2013 were lower than the same periods last year primarily due to the sale of assets during the year ended December 31, 2012 and the impact of a curtailed drilling program on the replacement of natural production declines.

At various times during 2012 and 2013, as a result of fluctuating natural gas prices, certain natural gas production has been shut in. At the end of the third quarter of 2013, approximately 1.4 MMcfd of natural gas was still shut in.

Bank loans were $53.9 million and other working capital (excluding unrealized loss on derivative contracts) was $70.4 million at September 30, 2013. During the third quarter of 2013, the Company spent $0.2 million in capital expenditures, earned $1.4 million in funds from operations and reported a loss of $48.7 million. The reported loss includes an impairment of $44.6 million related to assets held for sale. The sale of these assets, comprised of Garrington and Ferrier Cardium oil and natural gas properties, closed in October 2013, at which time the Company repaid its bank debt, terminated its existing bank agreement, and entered into a new revolving production loan facility of $28 million.

PRODUCTION

	Three months ended September 30		Nine months ended September 30
	2013	2012	2013	2012
Oil (bpd)	983	1,274	1,235	1,632
NGL (bpd)	280	576	260	676
Natural gas (Mcfd)	13,119	23,519	14,157	25,799
Total (BOED)⁽³⁾	3,449	5,770	3,854	6,607

PRICES

	Three months ended September 30				Nine months ended September 30
	2013		2012		2013		2012
Oil ($/bbl)⁽¹⁾	$	100.81	$	80.44	$	90.71	$	84.03
NGL ($/bbl)		52.97		51.59		53.62		58.06
Natural gas ($/Mcf)		2.27		2.24		2.86		1.98
Total ($/BOE)^(1)(2)(3)	$	41.87	$	32.05	$	43.49	$	34.54

OIL AND NATURAL GAS SALES

	Three months ended September 30				Nine months ended September 30
(thousands of dollars)	2013		2012		2013		2012
Oil⁽¹⁾	$	9,117	$	9,432	$	30,580	$	37,568
NGL		1,363		2,733		3,808		10,754
Natural gas		2,740		4,707		11,068		13,869
Gain on fixed price natural gas contracts		–		136		–		136
Royalty and other		67		5		310		205
Total oil and gas sales⁽¹⁾	$	13,287	$	17,013	$	45,766	$	62,532

OPERATING NETBACK

	Three months ended September 30						Nine months ended September 30
(thousands of dollars)	2013			2012			2013			2012
Revenue⁽¹⁾⁽²⁾	$	13,287		$	17,013		$	45,766		$	62,532
Realized gain (loss) on derivative contracts		(1,603	)		1,680			(2,850	)		3,198
Royalties		(1,338	)		(1,729	)		(4,204	)		(6,513	)
Operating expenses		(4,593	)		(5,985	)		(13,693	)		(19,223	)
Transportation expenses		(115	)		(69	)		(338	)		(459	)
Operating netback	$	5,638		$	10,910		$	24,681		$	39,535
Sales volume (MBOE)⁽³⁾		317.3			530.9			1,052.3			1,810.4
Per BOE⁽³⁾
Revenue⁽¹⁾⁽²⁾	$	41.87		$	32.05		$	43.49		$	34.54
Realized gain (loss) on derivative contracts		(5.05	)		3.16			(2.71	)		1.77
Royalties		(4.22	)		(3.26	)		(3.99	)		(3.60	)
Operating expenses		(14.47	)		(11.28	)		(13.01	)		(10.62	)
Transportation expenses		(0.36	)		(0.13	)		(0.32	)		(0.25	)
Operating netback	$	17.77		$	20.54		$	23.46		$	21.84

The three months ended September 30, 2013 excludes the realized and unrealized gain (loss) on derivative contracts of ($1.6) million and $0.5 million respectively (September 30, 2012 – $1.7 million and ($2.7) million respectively). The nine months ended September 30, 2013 excludes the realized and unrealized gain (loss) on derivative contracts of ($2.9) million and $0.1 million respectively (September 30, 2012 – $3.2 million and $0.3 million respectively).
Includes royalty and other income classified with oil and gas sales.
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.

Production

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

	Three months ended September 30, 2013	Three months ended June 30, 2013
Oil (bpd)	983	1,199
NGL (bpd)	280	297
Natural gas (Mcfd)	13,119	14,611
Total (BOED)	3,449	3,931

Production in the third quarter of 2013 was 3,449 BOED of which 1,263 bpd (37%) was derived from oil and natural gas liquids production. In addition to natural decline, downtime as a result of various repair and maintenance projects resulted in a reduction of approximately 145 BOED from the second quarter of 2013.

Prices

World and North American benchmark prices for oil remain volatile and as described below, the Company has entered into certain derivative contracts to partially hedge WTI oil prices. Differentials between WTI oil prices and prices received in Alberta are affected by factors including refining demand and pipeline capacity and are also volatile. The average differential for the third quarter ended September 30, 2013 was $4.72 US per bbl. This differential has widened significantly in recent weeks.

The above noted oil prices do not include realized gains and losses on derivative contracts. For the three months ended September 30, 2013, the realized loss was $1.6 million (September 30, 2012 – $1.7 million gain). The average oil price including the realized gains or losses from derivative contracts was $83.09 per barrel for the third quarter of 2013 compared to $83.70 per barrel for the second quarter of 2013 and $94.76 for the third quarter of 2012. For the nine months ended September 30, 2013, the realized loss was $2.9 million (September 30, 2012 – $3.2 million gain). The average oil price including the realized gains or losses from derivative contracts was $82.26 per barrel for the first nine months of 2013 compared to $91.18 per barrel for the first nine months of 2012.

Natural gas pricing in the third quarter of 2013 was negatively impacted by changes in third party pipeline interruptible tolling practices in the quarter which compromised the export of Alberta gas and reduced natural gas pricing. The Company’s average natural gas sales price was $2.27 per Mcf for the three months ended September 30, 2013, 32% lower than the second quarter of 2013 price of $3.33 per Mcf and 1% higher than the third quarter of 2012 price of $2.24 per Mcf. Natural gas prices have improved since September 2013 due to a short term transport tolling change for October through March 2014. Tolls were trimmed between 50 – 75% along the mainline increasing volumes of AECO shipped and reducing inventories that were near full capacity. AECO natural gas spot prices averaged approximately $3.11 per GJ during October 2013 compared to approximately $2.30 per GJ in the second quarter of 2013 .

Commodity contracts

At September 30, 2013, the following derivative contracts were outstanding for crude oil and recorded at estimated fair value:

Period	Weighted average volume (bpd)		Weighted average WTI Canadian ($/bbl)
October 1, 2013 to December 31, 2013	800		$	90.56

By comparison, WTI Canadian averaged approximately $110 per bbl in the third quarter of 2013 and approximately $104 in October 2013. The Company will continue to evaluate the merits of commodity hedging as part of its price management strategy. The Company has not hedged any natural gas prices at this time.

In October 2013, the Company terminated the remaining two months of a 300 bpd contract at a cost of $0.2 million. Derivative contracts for 500 bpd at $90.63 WTI Canadian per bbl for November and December 2013 are still outstanding.

Derivative contracts had the following impact on operating results for the three and nine months ended September 30, 2013 and 2012:

	Three months ended September 30						Nine months ended September 30
(thousands of dollars)	2013			2012			2013			2012
Realized gain (loss) on derivative contracts	$	(1,603	)	$	1,680		$	(2,850	)	$	3,198
Unrealized gain (loss) on derivative contracts		485			(2,656	)		52			347
	$	(1,118	)	$	(976	)	$	(2,798	)	$	3,545

Royalties

For the third quarter of 2013, the average royalty rate was 10.1% of revenue compared to 8.1% in the second quarter of 2013 and 10.2% in the third quarter of 2012. For the first nine months of 2013, the average royalty rate was 9.2% of revenue compared to 10.4% in the first nine months of 2012. The increase in the average royalty rate for the quarter ended September 30, 2013 compared to the second quarter of 2013 was due to an increase in crown royalties as a result of the end of some lower royalty rate incentives and an increase in other royalties.

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. 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.

	Three months ended September 30						Nine months ended September 30
	2013			2012			2013			2012
Gross Crown royalties		6.6	%		7.0	%		5.7	%	8.3	%
Gas cost allowance		(3.2	%)		(2.5	%)		(2.6	%)	(3.9	%)
Other royalties		6.7	%		5.7	%		6.1	%	6.0	%
Total royalties		10.1	%		10.2	%		9.2	%	10.4	%
Total royalties ($/BOE)	$	4.22		$	3.26		$	3.99$		3.60

Operating expenses

Operating expenses were $14.47 per BOE for the three months ended September 30, 2013 compared to $12.85 per BOE in the second quarter of 2013 and $11.28 per BOE in the third quarter of 2012. For the nine months ended September 30, 2013, operating expenses were $13.01 per BOE compared to $10.62 per BOE in the first nine months of 2012. Operating expenses were higher in the third quarter of 2013 compared to the third quarter of 2012 due largely to equalization costs and other expenses received in the quarter that relate to prior periods (approximately $1.39 per BOE), as well as the impact of fixed costs on lower sales volumes.

Transportation expenses

For the third quarter of 2013, transportation expenses were $0.36 per BOE compared to $0.13 per BOE for the third quarter of 2012. For the nine months ended September 30, 2013, transportation expenses were $0.32 per BOE compared to $0.25 per BOE for the same period in 2012. In the third quarter of 2013, the Company incurred additional trucking costs related to moving Willesden Green NGL volumes to a new sales point.

Depletion and depreciation

Depletion and depreciation was $6.9 million ($21.74 per BOE) in the third quarter of 2013 compared to $8.1 million ($22.53 per BOE) in the second quarter of 2013 and $10.1 million ($19.01 per BOE) in the third quarter of 2012. The decrease in depletion and depreciation expense in the third quarter of 2013 as compared to the second quarter was due to lower overall production volumes. Proved plus probable reserves volumes are included in the determination of depletion and depreciation expense. In 2012, natural gas reserves volumes were reduced due to low natural gas prices, property dispositions, and the termination of the Edmonton Sands farm-in agreement, resulting in higher depletion and depreciation expense per BOE in recent quarters compared to last year.

Impairment loss

In the third quarter of 2013, certain oil and natural gas assets that were part of 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 value of the assets. Subsequent to the impairment test, the carrying value of the property, plant and equipment was transferred to assets held for sale.

There were no indicators of impairment in the Company’s Gas CGU at September 30, 2013. In 2012, forecasted natural gas commodity prices led to an impairment charge of $20 million against the Company’s Gas CGU.

Impairment loss on assets held for sale

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 agreement closed in October 2013. 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. 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. Decommissioning obligations related to the assets held for sale are $6.3 million and have been recorded separately as a current liability.

General and administrative expenses

General and administrative expenses excluding share-based compensation were $1.6 million ($5.19 per BOE) for the third quarter of 2013 compared to $1.7 million ($4.64 per BOE) in the second quarter of 2013 and $2.1 million ($3.88 per BOE) for the third quarter of 2012. For the nine months ended September 30, 2013, general and administrative expenses excluding share-based compensation were $5.4 million ($5.10 per BOE) compared to $6.7 million ($3.68 per BOE) for the same period in 2012. The decrease in gross general and administrative expenses is the result of lower employee compensation associated with reduced staff and decreased rent associated with the office move in the fourth quarter of 2012. Overhead recoveries are lower due to reduced capital spending in 2013 and capitalized overhead is lower due to reduced staff associated with capital activities.

	Three months ended September 30						Nine months ended September 30
(thousands of dollars)	2013			2012			2013			2012
General and administrative (gross)	$	2,175		$	3,152		$	7,188		$	10,110
Overhead recoveries		(269	)		(265	)		(788	)		(973	)
Capitalized		(258	)		(825	)		(1,037	)		(2,484	)
General and administrative (cash)	$	1,648		$	2,062		$	5,363		$	6,653
Net share-based compensation		54			143			439			573
General and administrative	$	1,702		$	2,205		$	5,802		$	7,226
General and administrative (cash) ($/BOE) ⁽¹⁾	$	5.19		$	3.88		$	5.10		$	3.68
% Capitalized		12	%		26	%		14	%		25	%

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.

Capitalized general and administrative costs are limited to compensation and benefits of staff involved in capital activities and associated office rent.

Share-based compensation

The Company accounts for share-based compensation plans using the fair value method of accounting. Share-based compensation expense was $0.2 million for the third quarter of 2013 ($0.1 million net of amounts capitalized) versus $0.2 million ($0.1 million net of amounts capitalized) in third quarter of 2012. For the nine months ended September 30, 2013, share-based compensation costs were $0.7 million ($0.5 million net of amounts capitalized) compared to $0.9 million ($0.6 million net of amounts capitalized) in the same period of 2012.

Finance expenses

Finance expenses were $3.4 million for the third quarter of 2013, compared to $3.3 million in the second quarter of 2013 and $3.9 million in the third quarter of 2012. For the nine months ended September 30, 2013, finance expenses were $10.0 million compared to $11.3 million in the same period of 2012. The decrease in finance expenses in the third quarter of 2013 compared with the third quarter of 2012 is the result of lower average balances outstanding under the Company’s credit facilities. The average effective interest rate on outstanding bank loans was 5.5% for the nine months ended September 30, 2013 compared to 4.5% for the comparable period in 2012.

	Three months ended September 30				Nine months ended September 30
(thousands of dollars)	2013		2012		2013		2012
Interest and accretion on convertible debentures	$	2,322	$	2,269	$	6,922	$	6,765
Interest expense on credit facilities and other		817		1,352		2,417		3,645
Accretion on decommissioning obligations		233		242		615		879
Finance expenses	$	3,372	$	3,863	$	9,954	$	11,289

Decommissioning obligations

The non-current decommissioning obligation at September 30, 2013 has decreased $8.9 million since December 31, 2012.

Decommissioning obligations related to assets held for sale in the amount of $6.3 million were reclassified as current liabilities at September 30, 2013 and these obligations will be removed from the Company’s accounts in the fourth quarter of 2013 because the transaction closed in October 2013.

Other significant decreases to decommissioning obligations relate to changes in estimates in the amount of $3.1 million for the nine month period ended September 30, 2013. In the first quarter of 2013, the Company lowered its estimated costs of decommissioning by $1.3 million after reviewing the Company’s estimated decommissioning costs in light of the recently updated estimated industry costs published by the ERCB. During the third quarter of 2013, the risk-free rates used to discount the estimated future decommissioning costs increased between 0.1% and 0.7% relative to those used in the second quarter as a result of changes in the Canadian bond market, thereby reducing the discounted estimated obligations by approximately $1.5 million.

Accretion expense was $0.2 million in the third quarter of 2013 consistent with the second quarter of 2013.

The risk-free discount rates used by the Company to measure the obligations at September 30, 2013 were between 1.1% and 2.9% (December 31, 2012 – 1.0% to 2.5%) depending on the timelines to reclamation.

Deferred tax asset

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 $1.7 million of deferred tax assets as of September 30, 2013. The Company has approximately $347 million of tax pools at September 30, 2013.

Funds from operations

Funds from operations of $1.4 million ($0.01 per share) for the third quarter of 2013 were 75% lower than the third quarter of 2012 ($5.7 million or $0.03 per share) and 70% lower than the second quarter of 2013 ($4.7 million or $0.03 per share) largely as a result of property sales in 2012, other reductions in production volumes and realized losses on financial instruments.

	Three months ended September 30						Nine months ended September 30
(thousands of dollars)	2013			2012			2013		2012
Cash from operating activities	$	1,626		$	5,845		$	10,750	$	22,863
Changes in non-cash working capital		(507	)		(147	)		469		692
Decommissioning expenditures		289			27			376		392
Funds from operations	$	1,408		$	5,725		$	11,595	$	23,947

Earnings

The Company reported a loss of $48.7 million in the third quarter of 2013 compared to loss of $49.3 million in the second quarter of 2013 and earnings of $0.1 million for the third quarter of 2012. The loss in the second quarter of 2013 included a derecognition of a deferred tax asset of $45.6 million related to material uncertainties affecting the assessment of the probability of future profits, while the loss in the third quarter of 2013 included an impairment loss on assets held for sale of $44.6 million.

CAPITAL EXPENDITURES

The Company spent $0.2 million on capital expenditures in the third quarter of 2013. The breakdown of expenditures is shown below:

	Three months ended September 30						Nine months ended September 30
(thousands of dollars)	2013			2012			2013			2012
Land, geological and geophysical costs	$	56		$	50		$	128		$	410
Proceeds on disposition		13			(30,710	)		(39	)		(36,909	)
Drilling, completion and recompletion		78			262			5,115			14,350
Facilities and well equipment		(176	)		457			1,927			7,584
Capitalized general and administrative expenses		258			825			1,037			2,484
Total finding, development & acquisition expenditures	$	229		$	(29,116	)	$	8,168		$	(12,081	)
Change in compressor and other inventory and equipment		–			131			(106	)		(54	)
Office equipment and furniture		–			(1	)		15			25
Total net cash capital expenditures	$	229		$	(28,986	)	$	8,077		$	(12,110	)

Drilling statistics are shown below:

Three months ended
September 30

Nine months ended
September 30

2013

2012

2013

2012

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Oil

–

1.8

2.5

Gas

–

Dry

–

Total

–

1.8

2.5

Success rate (%)

–

100

The Company did not drill any new wells in the third quarter of 2013 in order to reduce bank indebtedness. During the first quarter of 2013, the Company drilled 2 gross (1.8 net capital, 1.5 net revenue) Cardium horizontal light oil wells and brought 4 gross (3.0 net revenue) Cardium horizontal light wells on-stream.

SHARE INFORMATION

The Company’s shares have been listed on the Toronto Stock Exchange since September 7, 2005 under the symbol “AXL”. As of November 8, 2013, there were 172.5 million common shares outstanding, 12.4 million stock options outstanding, $50.0 million principal amount of convertible debentures which are convertible into common shares at a conversion price of $1.55 per common share and $46.0 million principal amount of convertible debentures which are convertible into common shares at a conversion price of $1.70 per common share. During the third quarter of 2013 and 2012, no common shares were issued under the employee stock option plan.

SHARE PRICE ON TSX

	Three months ended September 30				Nine months ended September 30
	2013		2012		2013		2012
High	$	0.22	$	0.35	$	0.25	$	0.68
Low	$	0.13	$	0.21	$	0.13	$	0.21
Close	$	0.14	$	0.23	$	0.14	$	0.23
Volume		16,128,197		8,042,349		27,421,378		32,883,171
Shares outstanding at September 30		172,549,701		172,549,701		172,549,701		172,549,701
Market capitalization at September 30	$	24,156,958	$	39,686,431	$	24,156,958	$	39,686,431

The statistics above include trading on the Toronto Stock Exchange only. Shares also trade on alternative platforms like Alpha, Chi-X, Pure and Omega. During the three months and nine months ended September 30, 2013 approximately 6.7 million and 12.2 million common shares traded on these alternative exchanges respectively. Including these exchanges, an average of 362,861 common shares traded per day in the three months ended September 30, 2013 (September 30, 2012 – 206,534), representing a quarterly turnover ratio of 13% (September 30, 2012 – 7%).

LIQUIDITY AND CAPITAL RESOURCES

At September 30, 2013, the Company had outstanding bank loans of $53.9 million, other working capital (excluding the unrealized loss on derivative contracts) of $70.4 million and convertible debentures of $96.0 million (principal). The working capital arose in the quarter due to the addition of assets held for sale net of decommissioning obligations which is based on the adjusted sales price contained within the purchase and sale agreement, net of expenses, in the amount of $77.9 million. The following table shows the changes in bank loans plus other working capital (deficiency):

	Three months ended September 30						Nine months ended September 30
(thousands of dollars)	2013			2012			2013			2012
Bank loans plus other working capital (deficiency), beginning of period	$	(62,279	)	$	(131,675	)	$	(64,531	)	$	(132,656	)
Funds from operations		1,408			5,725			11,595			23,947
Net cash capital proceeds (expenditures)		(229	)		28,986			(8,077	)		12,110
Assets held for sale		84,196			–			84,196			–
Decommissioning obligations held for sale		(6,308	)		–			(6,308	)		–
Decommissioning expenditures		(289	)		(27	)		(376	)		(392	)
Bank loans plus other working capital (deficiency), end of period	$	16,499		$	(96,991	)	$	16,499		$	(96,991	)

Bank loans, end of period	$	(53,945	)	$	(88,922	)	$	(53,945	)	$	(88,922	)
Other working capital (deficiency), end of period		70,444			(8,069	)		70,444			(8,069	)
Bank loans plus other working capital (deficiency), end of period	$	16,499		$	(96,991	)	$	16,499		$	(96,991	)

The continued development of the Company’s oil and gas assets is dependent on the ability of the Company to secure sufficient funds through operations, bank facilities and other sources. Short-term capital is required to finance accounts receivable and other similar short-term assets while the acquisition and development of oil and natural gas properties requires larger amounts of long-term capital.

At September 30, 2013, the Company had total credit facilities of $65 million, consisting of a $55 million revolving term credit facility and a $10 million working capital credit facility with a syndicate of Canadian banks. The Company had $10.7 million of credit available at September 30, 2013.

Subsequent to September 30, 2013, the Company closed the sale of its Garrington and Ferrier Cardium oil and natural gas properties, repaid its bank debt and terminated its existing bank agreement. The Company entered into a new revolving production loan facility of $28 million. Advances can be drawn in Canadian funds and bear interest at the bank’s prime lending rate or guaranteed note rates plus applicable margins. These margins vary from 2.25% to 3.60% depending on the borrowing option used. The facility expires May 31, 2014 and if not renewed, any amounts outstanding become repayable on May 31, 2015.

The Board of Directors has concluded its strategic alternatives review process. At the end of October 2013, the Company had approximately $24 million in cash deposits after repaying the bank debt.

The available lending limits under the new bank facilities are to be reviewed annually and are based on the bank’s interpretation of the Company’s reserves and future commodity prices. The next review will be conducted by May 2014 and there can be no assurance that the amount of the available facilities will not be adjusted at that review.

OFF BALANCE SHEET ARRANGEMENTS

The Company had no guarantees or off-balance sheet arrangements other than as described in the management’s discussion and analysis for the year ended December 31, 2012 under “Contractual Obligations” and amended below.

CHANGES TO CONTRACTUAL OBLIGATIONS

The Company enters into various contractual obligations in the course of conducting its operations. There were no material changes to the contractual obligations that were discussed in management’s discussion and analysis for the year ended December 31, 2012 other than the following:

Loan agreements – As described under “Liquidity and Capital Resources”, the Company’s existing credit facilities were terminated in October 2013 and were replaced with a new revolving loan facility in the amount of $28 million.
Cardium Horizontal Well Program (Oil) – At December 31, 2012 the Company had an obligation to drill one Cardium horizontal oil well. The commitment was fulfilled in the first quarter of 2013. The Company has no other drilling commitments as at September 30, 2013.
Crude oil transportation contract – Subsequent to September 30, 2013, the Company fulfilled its term volume commitment under a facilities construction and operation agreement entered into in 2011.

CHANGES IN ACCOUNTING POLICIES

On January 1, 2013, the Company adopted new standards with respect to consolidations (IFRS 10), joint arrangements (IFRS 11), disclosure of interests in other entities (IFRS 12), fair value measurements (IFRS 13) and amendments to financial instruments disclosures (IFRS 7). The adoption of these standards had no impact on the amounts recorded in the consolidated financial statements as at January 1, 2013 or on the comparative periods, but did result in additional disclosures with regards to IFRS 13 and IFRS 7. Refer to the unaudited condensed interim consolidated financial statements for the three and nine month period ended September 30, 2013.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements requires the Company to make estimates, assumptions and judgements in the application of IFRS that have a significant impact on the financial results of the Company. Actual results could differ from estimated amounts, and those differences may be material. A comprehensive discussion of the Company’s significant critical accounting estimates is contained in the MD&A and the audited consolidated financial statements for the year ended December 31, 2012.

CONTROLS AND PROCEDURES

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

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

The CEO and CFO are required to cause the Company to disclose any change in the Company’s ICOFR that occurred during the period beginning on July 1, 2013 and ending on September 30, 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 that a control system, including the Company’s DC&P and ICOFR, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objective of the control system will be met and it should not be expected that DC&P and ICOFR will prevent all errors or fraud.

BUSINESS RISKS

Oil and gas exploration and production is capital intensive and involves a number of business risks including, without limitation, the uncertainty of finding new reserves, the instability of commodity prices, weather and various operational risks. Commodity prices are influenced by local and worldwide supply and demand, OPEC actions, ongoing global economic concerns, the U.S. dollar exchange rate, transportation costs, political stability and seasonal and weather related changes to demand. The price of natural gas has weakened due to increasing U.S. gas production driven primarily by the U.S. shale gas plays. The large amount of gas in storage combined with strong U.S. gas production and financial market fears has continued to suppress the price of natural gas. Oil prices continue to remain volatile as they are a geopolitical commodity, affected by concerns about economic markets in the U.S. and Europe and continued instability in oil producing countries. Differentials between WTI oil prices and prices received in Alberta are volatile and dependent on factors including refining demand and pipeline capacity. The industry is subject to extensive governmental regulation with respect to the environment. Operational risks include well performance, uncertainties inherent in estimating reserves, timing of/ability to obtain drilling licences and other regulatory approvals, ability to obtain equipment, expiration of licences and leases, competition from other producers, sufficiency of insurance, ability to manage growth, reliance on key personnel, third party credit risk and appropriateness of accounting estimates. These risks are described in more detail in the Company’s most recent Annual Information Form filed with Canadian securities regulatory authorities on SEDAR.

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

The Company has a formal emergency response plan which details the procedures employees and contractors will follow in the event of an operational emergency. The emergency response plan is designed to respond to emergencies in an organized and timely manner so that the safety of employees, contractors, residents in the vicinity of field operations, the general public and the environment are protected. A corporate safety program covers hazard identification and control on the jobsite, establishes Company policies, rules and work procedures and outlines training requirements for employees and contract personnel.

The Company currently deals with a small number of buyers and sales contracts, and endeavors to ensure that those buyers are an appropriate credit risk. The Company continuously evaluates the merits of entering into fixed price or financial hedge contracts for price management.

The oil and natural gas business is subject to regulation and intervention by governments in such matters as the awarding of exploration and production interests, the imposition of specific drilling obligations, environmental protection controls, control over the development and abandonment of fields (including restrictions on production) and possibly expropriation or cancellation of contract rights. As well, governments may regulate or intervene with respect to prices, taxes, royalties and the exportation of oil and natural gas. Such regulation may be changed from time to time in response to economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for oil and natural gas, increase the Company’s costs or affect its future opportunities.

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation. Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations. Such legislation may also impose restrictions and prohibitions on water use or processing in connection with certain oil and gas operations. In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures and a breach of such requirements may result 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.

BUSINESS PROSPECTS

Over the course of the strategic alternatives process since February 2012, the Company has:

sold over $150 million in assets;
reduced bank debt from $106.7 million at March 31, 2012 to nil at the date hereof;
reduced total net 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 approximately $81 million at the end of October 2013;
restructured all of its shallow gas and Cardium drilling commitments so that by the end of January 2013, the Company had completed all of its drilling commitments;
demonstrated the improved production performance from slick water fracture stimulation; and
continued to be an industry leader in low capital costs in the Cardium horizontal light oil play.

The disposition of the Garrington and Ferrier properties and the lack of drilling activity since the first quarter of 2013 will negatively impact funds from operations, particularly in the fourth quarter of 2013. However, the seven well drilling program will begin to contribute positively to oil production and funds from operations in the first and second quarters of 2014.

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. Revenues, funds from operations and earnings (loss) over the last quarter of 2011 reflect the benefits from increased sales of crude oil volumes resulting from large oil-focused drilling programs that began in 2010. The Company drilled 51 gross (43.8 net capital, 38.7 net revenue) successful wells during 2011. 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 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 natural production declines contributed to lower production volumes in 2012 and the first nine months of 2013. This, combined with declines in commodity prices relative to 2011, led to decreases in revenue in 2012 and the first nine months of 2013.

Earnings were affected in the fourth quarter of 2011 and 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 2011, 2012 and into 2013. Bank loans were reduced by the proceeds from the sale of assets in 2012 and from cash from operating activities.

SELECTED QUARTERLY INFORMATION

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

		Q3 2013			Q2 2013			Q1 2013			Q4 2012
Revenue, net of royalties		$	11,949		$	14,345		$	15,268		$	13,796
Funds from operations		$	1,408		$	4,701		$	5,486		$	5,694
Funds from operations per share, basic and diluted		$	0.01		$	0.03		$	0.03		$	0.03
Loss before effect of impairment loss and deferred tax adjustment		$	(4,156	)	$	(3,672	)	$	(5,113	)	$	(8,895	)
Loss per share before effect of impairment loss and deferred tax adjustment, basic and diluted		$	(0.02	)	$	(0.02	)	$	(0.03	)	$	(0.05	)
Loss		$	(48,737	)	$	(49,306	)	$	(5,113	)	$	(8,895	)
Loss per share, basic and diluted		$	(0.28	)	$	(0.29	)	$	(0.03	)	$	(0.05	)
Capital expenditures, net of proceeds on dispositions		$	229		$	186		$	7,662		$	(26,880	)
Cash from operating activities		$	1,626		$	3,953		$	5,171		$	6,976
Bank loans		$	53,945		$	53,892		$	55,141		$	48,094
Daily sales
	Oil (bpd)		983			1,199			1,529			1,135
	NGL (bpd)		280			297			203			338
	Natural gas (Mcfd)		13,119			14,611			14,759			18,159
	BOE (BOED)⁽³⁾		3,449			3,931			4,191			4,500
Average prices
	Oil ($/bbl)⁽²⁾	$	100.81		$	89.76		$	84.83		$	79.73
	NGL ($/bbl)	$	52.97		$	48.73		$	61.77		$	52.02
	Natural gas ($/Mcf)	$	2.27		$	3.33		$	2.94		$	3.16
	BOE ($/BOE)^(1)(2)(3)	$	41.87		$	43.66		$	44.70		$	36.89

			Q3 2012			Q2 2012			Q1 2012			Q4 2011
Revenue, net of royalties		$	15,284		$	18,290		$	22,445		$	28,457
Funds from operations		$	5,725		$	7,606		$	10,616		$	16,997
Funds from operations per share, basic and diluted		$	0.03		$	0.04		$	0.06		$	0.10
Earnings (loss) before effect of impairment loss and deferred tax adjustment		$	94		$	(1,828	)	$	(5,864	)	$	(4,939	)
Earnings (loss) per share before effect of impairment loss and deferred tax adjustment, basic and diluted		$	–		$	(0.01	)	$	(0.03	)	$	(0.03	)
Earnings (loss)		$	94		$	(16,828	)	$	(5,864	)	$	(32,167	)
Earnings (loss) per share, basic and diluted		$	–		$	(0.10	)	$	(0.03	)	$	(0.19	)
Capital expenditures, net of proceeds on dispositions		$	(28,986	)	$	4,786		$	12,090		$	40,924
Cash from operating activities		$	5,845		$	7,712		$	9,306		$	16,462
Bank loans		$	88,922		$	119,686		$	106,655		$	88,682
Daily sales
	Oil (bpd)		1,274			1,669			1,956			2,122
	NGL (bpd)		576			750			703			715
	Natural gas (Mcfd)		23,519			26,438			27,463			30,576
	BOE (BOED)⁽³⁾		5,770			6,825			7,236			7,933
Average prices
	Oil ($/bbl)⁽²⁾	$	80.44		$	81.58		$	88.48		$	96.33
	NGL ($/bbl)	$	51.59		$	54.38		$	67.36		$	72.71
	Natural gas ($/Mcf)	$	2.24		$	1.72		$	2.01		$	3.20
	BOE ($/BOE)^(1)(2)(3)	$	32.05		$	32.70		$	38.28		$	44.70

Includes royalty and other income classified with oil and gas sales.
Excludes realized and unrealized hedging gains (losses) on derivative contracts as follows: 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; Q1 2012 – $0.2 million and ($1.7) million respectively; and Q4 2011 – ($0.3) million and ($7.9) million respectively.
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.

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; the estimated proceeds from the sale of assets, available cash deposits and total net debt; number of locations in drilling inventory and wells to be drilled; timing and location of drilling and tie-in of wells and the costs thereof; productive capacity of the wells; timing of and construction of facilities; expected production rates; percentage of production from oil and natural gas liquids; dates of commencement of production; amount of capital expenditures and the timing and method of financing thereof; value of undeveloped land; extent of reserves additions; ability to attain cost savings; drilling program success; impact of drilling programs on operating results; factors on which the continued development of the Company’s oil and gas assets are dependent; programs to optimize, rationalize, consolidate and improve the profitability of assets; commodity price outlook; and general economic outlook may constitute “forward-looking information” within the meaning of applicable securities legislation 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 value or failure to realize anticipated benefits of acquisitions and farm-ins; delays resulting from or inability to obtain required regulatory approvals; changes to government regulation; inability 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.

CONVERSION

Disclosure provided herein in respect of barrels of oil equivalent (“BOE”) may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

ANDERSON ENERGY LTD.
Consolidated Statements of Financial Position
(Stated in thousands of dollars)
(Unaudited)

		September 30, 2013			December 31, 2012

ASSETS
Current assets:
	Cash	$	–		$	1
	Restricted cash (note 3)		8,203			–
	Accounts receivable and accruals		7,981			9,881
	Prepaid expenses and deposits		1,482			1,788
	Assets held for sale (note 4)		84,196			–
Total current assets			101,862			11,670

Deferred tax asset (note 8)			1,700			45,634
Property, plant and equipment (notes 4 and 5)			139,278			286,174
Total assets		$	242,840		$	343,478

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
	Accounts payable and accruals (note 3)	$	25,110		$	28,107
	Unrealized loss on derivative contracts (note 14)		1,045			1,097
	Bank loans (note 6)		53,945			48,094
	Decommissioning obligations held for sale (notes 4 and 7)		6,308			–
Total current liabilities			86,408			77,298

Convertible debentures			88,361			86,753
Decommissioning obligations (notes 4 and 7)			37,605			46,467
Total liabilities			212,374			210,518
Shareholders’ equity:
	Share capital (note 9)		171,460			171,460
	Equity component of convertible debentures		5,019			5,019
	Contributed surplus		11,080			10,418
	Deficit		(157,093	)		(53,937	)
Total shareholders’ equity			30,466			132,960
Commitments and contingencies (note 15)
Subsequent events (notes 3, 4, 6, 8, 14, 15 and 16)
Total liabilities and shareholders’ equity		$	242,840		$	343,478

See accompanying notes to the condensed interim consolidated financial statements.

ANDERSON ENERGY LTD.
Consolidated Statements of Operations and Comprehensive Income (Loss)
(Stated in thousands of dollars, except per share amounts)
(Unaudited)

	Three months ended September 30						Nine months ended September 30
	2013			2012			2013			2012

Oil and gas sales	$	13,287		$	17,013		$	45,766		$	62,532
Royalties		(1,338	)		(1,729	)		(4,204	)		(6,513	)
Revenue, net of royalties		11,949			15,284			41,562			56,019
Other gains (losses) (note 11)		(1,131	)		7,104			(2,854	)		7,626
Total revenue, net of royalties and other gains (losses)		10,818			22,388			38,708			63,645

Operating expenses		4,593			5,985			13,693			19,223
Transportation expenses		115			69			338			459
Depletion and depreciation		6,898			10,093			23,570			35,411
Impairment loss (notes 4 and 5)		44,581			–			44,581			20,000
General and administrative expenses		1,702			2,205			5,802			7,226
Earnings (loss) from operating activities		(47,071	)		4,036			(49,276	)		(18,674	)

Finance income (note 12)		6			–			8			24
Finance expenses (note 12)		(3,372	)		(3,863	)		(9,954	)		(11,289	)
Net finance expenses		(3,366	)		(3,863	)		(9,946	)		(11,265	)

Earnings (loss) before taxes		(50,437	)		173			(59,222	)		(29,939	)
Deferred income tax expense (benefit) (note 8)		(1,700	)		79			43,934			(7,341	)
Earnings (loss) and comprehensive income (loss) for the period		(48,737	)		94			(103,156	)		(22,598	)

Basic and diluted earnings (loss) per share (note 10)	$	(0.28	)	$	–		$	(0.60	)	$	(0.13	)

See accompanying notes to the condensed interim consolidated financial statements

ANDERSON ENERGY LTD.
Consolidated Statements of Changes in Shareholders’ Equity
NINE MONTHS ENDED SEPTEMBER 30, 2013 AND 2012
(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	–		–		–		929		–			929
Loss for the period	–		–		–		–		(22,598	)		(22,598	)
Balance at September 30, 2012	172,549,701	$	171,460	$	5,019	$	10,314	$	(45,042	)	$	141,751

Balance at December 31, 2012	172,549,701	$	171,460	$	5,019	$	10,418	$	(53,937	)	$	132,960
Share-based payments	–		–		–		662		–			662
Loss for the period	–		–		–		–		(103,156	)		(103,156	)
Balance at September 30, 2013	172,549,701	$	171,460	$	5,019	$	11,080	$	(157,093	)	$	30,466

See accompanying notes to the condensed interim consolidated financial statements.

ANDERSON ENERGY LTD.
Consolidated Statements of Cash Flows

NINE MONTHS ENDED SEPTEMBER 30, 2013 AND 2012 (Stated in thousands of dollars) (Unaudited)
		2013			2012
CASH PROVIDED BY (USED IN)
OPERATIONS
Loss for the period		$	(103,156	)	$	(22,598	)
Adjustments for:
	Unrealized gain on derivative contracts (note 11)		(52	)		(347	)
	(Gain) loss on sale of property, plant and equipment (note 11)		56			(4,081	)
	Depletion and depreciation		23,570			35,411
	Impairment loss (notes 4 and 5)		44,581			20,000
	Share-based payments		439			573
	Accretion on decommissioning obligations (notes 4 and 7)		615			879
	Accretion on convertible debentures		1,608			1,451
	Deferred income tax expense (benefit)		43,934			(7,341	)
Decommissioning expenditures (note 7)			(376	)		(392	)
Changes in non-cash working capital (note 13)			(469	)		(692	)
Net cash provided by operations			10,750			22,863
FINANCING
Increase in bank loans			5,851			240
Changes in non-cash working capital (note 13)			–			(175	)
Net cash provided by financing			5,851			65
INVESTING
Property, plant and equipment expenditures			(8,116	)		(24,799	)
Proceeds from sale of property, plant and equipment			39			36,909
Changes in non-cash working capital (note 13)			(8,525	)		(35,039	)
Net cash used in investing			(16,602	)		(22,929	)

Decrease in cash			(1	)		(1	)
Cash, beginning of period			1			1
Cash, end of period		$	–		$	–

Interest received in cash		$	8		$	29
Interest paid in cash		$	(7,342	)	$	(10,355	)

See accompanying notes to the condensed interim consolidated financial statements.

ANDERSON ENERGY LTD.

Notes to the Condensed Interim Consolidated Financial Statements

THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2013 AND 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 – 7^th Avenue S.W., Calgary, Alberta, Canada, T2P 2Z1.

2. BASIS OF PREPARATION

(a) Statement of compliance

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

The condensed interim consolidated financial statements were authorized for issuance by the Board of Directors on November 11, 2013.

(b) Accounting policies, judgments, estimates and disclosures

In preparing these condensed interim consolidated financial statements, the accounting policies, methods of computation and significant judgements made by management in applying the Company’s accounting policies and key sources of estimation uncertainty were the same as those that applied to the audited consolidated financial statements as at and for the years ended December 31, 2012 and 2011 except as disclosed below.

The following disclosures are incremental to those included with the annual audited consolidated financial statements. Certain disclosures that are normally required in the notes to the annual audited consolidated financial statements have been condensed or omitted. These condensed interim consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto for the years ended December 31, 2012 and 2011.

3. RESTRICTED CASH

During the third quarter of 2013, the Company signed a purchase and sale agreement regarding the expected sale of certain oil and natural gas properties. A deposit in the amount of $8.2 million was received by the Company as security for performance by the purchaser of its obligations under the agreement. Accordingly, the deposit was not available for general use and has been classified as restricted cash. There is a corresponding amount of $8.2 million included in accounts payable and accrued liabilities relating to the restricted cash. Subsequent to September 30, 2013 the conditions allowing the Company to retain the deposit and related interest were satisfied.

4. ASSETS HELD FOR SALE

5. 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		5,436			15		5,451
Transfer to assets held for sale		(166,102	)		–		(166,102	)
Balance at September 30, 2013	$	432,382		$	1,919	$	434,301

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		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 period		23,490			80		23,570
Transfer to assets held for sale		(37,325	)		–		(37,325	)
Balance at September 30, 2013	$	293,416		$	1,607	$	295,023

Carrying amounts

	Oil and natural gas assets		Other equipment		Total
At December 31, 2012	$	285,797	$	377	$	286,174
At September 30, 2013	$	138,966	$	312	$	139,278

Capitalized overhead.

For the nine months ended September 30, 2013, additions to property, plant and equipment included internal overhead costs of $1.3 million (year ended December 31, 2012 – $3.4 million).

Impairment.

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 the property, plant and equipment was transferred to assets held for sale (see note 4). There were no indicators of impairment in the Company’s Gas CGU.

In 2012, forecasted natural gas commodity prices led to an impairment charge of $20 million against the Company’s Gas CGU.

6. BANK LOANS

At September 30, 2013, total bank facilities were $65 million, consisting of a $55 million revolving term credit facility and a $10 million working capital credit facility with a syndicate of Canadian banks. The revolving term credit facility and the working capital credit facility had a maturity date of October 31, 2013. Accordingly, at September 30, 2013 and December 31, 2012, the bank loans were classified as a current liability. Under the agreement, advances could be drawn in either Canadian or U.S. funds and bore interest at the bank’s prime lending rate, bankers’ acceptance or LIBOR loan rates plus applicable margins. These margins varied from 3% to 4%, depending on the borrowing option used. At September 30, 2013, no amounts were drawn in U.S. funds.

Subsequent to September 30, 2013, the Company repaid the balance owing in full and terminated its existing bank agreement. The Company has entered into a new revolving production loan facility for $28 million. Advances can be drawn in Canadian funds and bear interest at the bank’s prime lending rates or guaranteed note rates plus applicable margins. These margins vary from 2.25% to 3.6% depending on the borrowing option used. The facility expires May 31, 2014 and if not renewed, any amounts outstanding become repayable on May 31, 2015.

The average effective interest rate on advances under the facilities in 2013 was 5.5% (September 30, 2012 – 4.5%). The Company had $0.4 million in letters of credit outstanding at September 30, 2013 that reduce the amount of credit available to the Company.

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

7. DECOMMISSIONING OBLIGATIONS

	September 30, 2013			December 31, 2012
Balance at January 1	$	46,467		$	62,848
Provisions incurred		268			1,187
Decommissioning expenditures		(376	)		(506	)
Provisions disposed		–			(20,865	)
Change in estimates		(3,061	)		2,735
Transfer to assets held for sale		(6,308	)		–
Accretion expense		615			1,068
Ending balance	$	37,605		$	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 $37.6 million as at September 30, 2013 (December 31, 2012 – $46.5 million) and $6.3 million on assets held for sale (December 31, 2012 – nil), based on an undiscounted inflation-adjusted total future liability of $55.1 million (December 31, 2012 – $55.8 million). These payments are expected to be made over the next 25 years with the majority of costs to be incurred between 2013 and 2030. At September 30, 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 2.9% (December 31, 2012 – 1.0% to 2.5%) depending on the estimated timing of the future obligation and certain rates within the above range changed marginally from the start of the year as a result of changes in the Canadian bond market.

8. DEFERRED TAX ASSET

9. 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, 2011, 2012 and September 30, 2013	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. Changes in the number of options outstanding during the period ended September 30, 2013 and the year ended December 31, 2012 are as follows:

	September 30, 2013				December 31, 2012
	Number of options		Weighted average exercise price		Number of options		Weighted average exercise price
Outstanding at January 1	14,386,800		$	0.75	14,014,182		$	1.69
Granted during the period	–			–	5,745,500			0.31
Expired during the period	(1,039,017	)		2.14	(4,273,582	)		3.22
Forfeited during the period	(777,933	)		0.50	(1,099,300	)		0.80
Ending balance	12,569,850		$	0.65	14,386,800		$	0.75

Exercisable, end of period	6,442,150		$	0.92	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)

$0.31 to $0.46	5,291,300	$	0.31	4.1
$0.47 to $0.70	2,479,000		0.70	2.9
$0.71 to $1.06	4,413,450		0.92	1.4
$1.07 to $1.60	284,100		1.18	2.1
$2.42 to $3.63	9,000		2.44	–
$3.64 to $4.00	93,000		4.00	0.7
Total at September 30, 2013	12,569,850	$	0.65	2.8

No options have been exercised in the nine months ended September 30, 2013 and September 30, 2012.

No stock options were issued in the nine months ended September 30, 2013 (September 30, 2012 – 15,000). The fair value of the options issued in 2012 was estimated using the Black-Scholes model with the following weighted average inputs:

	September 30, 2012
Fair value at grant date	$	0.30
Common share price	$	0.57
Exercise price	$	0.57
Volatility		61	%
Option life		5 years
Dividends		0	%
Risk-free interest rate		1.28	%
Forfeiture rate		15	%

This estimated forfeiture rate is adjusted to the actual forfeiture rate when each tranche vests. Share-based compensation cost of $0.5 million (September 30, 2012 – $0.5 million) was expensed during the nine months ended September 30, 2013. Share-based compensation cost of $0.1 million (September 30, 2012 – $0.1 million) was expensed during the three months ended September 30, 2013. In addition, share-based compensation expense of $0.2 million (September 30, 2012 – $0.4 million) was capitalized during the nine months ended September 30, 2013. For the three months ended September 30, 2013, $0.1 million of share-based compensation was capitalized (September 30, 2012 – $0.1 million).

10. EARNINGS (LOSS) PER SHARE

Basic and diluted earnings (loss) per share were calculated as follows:

	Three months ended September 30					Nine months ended September 30
	2013			2012		2013			2012
Earnings (loss) for the period	$	(48,737	)	$	94	$	(103,156	)	$	(22,598	)
Weighted average number of common shares (basic) (in thousands of shares)		172,550			172,550		172,550			172,550
Basic and diluted earnings (loss) per share	$	(0.28	)	$	–	$	(0.60	)	$	(0.13	)

The average market value of the Company’s common shares for purposes of calculating the dilutive effect of stock options was based on quoted market prices for the period that the options were outstanding. For the three month and nine months ended September 30, 2013, 12,569,850 options (September 30, 2012 – 10,185,200 options) and 59,316,889 common shares reserved for convertible debentures (September 30, 2012 – 59,316,889) were excluded from calculating diluted loss per share as they were anti-dilutive.

11. OTHER GAINS (LOSSES)

Other gains (losses) include the following:

	Three months ended September 30						Nine months ended September 30
	2013			2012			2013			2012
Realized gain (loss) on derivative contracts	$	(1,603	)	$	1,680		$	(2,850	)	$	3,198
Unrealized gain (loss) on derivative contracts		485			(2,656	)		52			347
Gain (loss) on sale of property, plant and equipment		(13	)		8,080			(56	)		4,081
	$	(1,131	)	$	7,104		$	(2,854	)	$	7,626

12. FINANCE INCOME AND EXPENSES

		Three months ended September 30						Nine months ended September 30
		2013			2012			2013			2012
Income:
	Other		6			–			8			24
Expenses:
	Interest and financing costs on bank loans		(817	)		(1,319	)		(2,389	)		(3,603	)
	Interest on convertible debentures		(1,771	)		(1,771	)		(5,314	)		(5,314	)
	Accretion on convertible debentures		(551	)		(498	)		(1,608	)		(1,451	)
	Accretion on decommissioning obligations		(233	)		(242	)		(615	)		(879	)
	Other		–			(33	)		(28	)		(42	)
			(3,372	)		(3,863	)		(9,954	)		(11,289	)
Net finance expenses		$	(3,366	)	$	(3,863	)	$	(9,946	)	$	(11,265	)

13. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital is comprised of:

		September 30, 2013			September 30, 2012
Source (use) of cash
	Accounts receivable and accruals	$	1,900		$	3,234
	Prepaid expenses and deposits		306			330
	Accounts payable and accruals ⁽¹⁾		(11,200	)		(39,470	)
		$	(8,994	)	$	(35,906	)
Related to operating activities		$	(469	)	$	(692	)
Related to financing activities		$	–		$	(175	)
Related to investing activities ⁽¹⁾		$	(8,525	)	$	(35,039	)

Excludes $8,203 in accrued liabilities related to restricted cash.

14. FINANCIAL RISK MANAGEMENT

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

Level 1 – observable inputs such as quoted prices in active markets;
Level 2 – inputs, other than the quoted market prices in active markets, which are observable, either directly and/or indirectly; and
Level 3 – unobservable inputs for the asset or liability in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

The fair value of the derivative contracts used for risk management as shown in the condensed interim consolidated financial statements as at September 30, 2013 and the audited consolidated financial statements as at December 31, 2012 are measured using level 2.

Financial risk factors

(a) Liquidity risk

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

The following are the contractual maturities of financial liabilities, including associated interest payments on convertible debentures and excluding the impact of netting agreements at September 30, 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⁾		$	25,110	$	–	$	–	$	–	$	–
	Bank loans – principal ⁽²⁾			53,945		–		–		–		–
	Convertible debentures
		– Interest ⁽¹⁾		5,626		7,085		5,210		3,335		–
		– Principal		–		–		50,000		46,000		–
Total			$	84,681	$	7,085	$	55,210	$	49,335	$	–

Accounts payable and accruals includes $1.5 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.
Assumes the credit facilities are not renewed on October 31, 2013.

(b) Market risk

Market risk is the risk that changes in market prices, such as commodity prices, foreign exchange rates and interest rates will affect the Company’s 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.

Commodity price risk. Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for oil and natural gas are impacted by both the relationship between the Canadian and U.S. dollar and world economic events that dictate the levels of supply and demand.

At September 30, 2013, the Company had fixed price swap contracts for an average of 500 barrels per day of crude oil with a remaining term of October to December, 2013 at a NYMEX crude oil price of Canadian $90.63 per barrel and 300 barrels per day of crude oil with a remaining term of October to December, 2013 at a NYMEX crude oil price of Canadian $90.43 per barrel. Subsequent to September 30, 2013, the Company terminated the remaining two months of its contract at 300 barrels per day for a cost of $0.2 million.

The estimated fair value of the financial oil contracts has been determined on the amounts the Company would receive or pay to terminate the oil contracts. At September 30, 2013, the Company estimates that it would pay approximately $1.0 million to terminate these contracts (December 31, 2012 – $1.1 million).

The fair value of derivative contracts at September 30, 2013 would have been impacted as follows had the oil prices used to estimate the fair value changed by:

	Effect of an increase in price on earnings		Effect of a decrease in price on earnings
Canadian $1.00 per barrel change in oil prices	$74		$(74)

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 demand in Canada and the U.S., 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 September 30, 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. Had the borrowing rate on bank loans been 100 basis points higher (or lower) throughout the nine months ended September 30, 2013, earnings would have been affected by approximately $0.4 million (September 30, 2012 – $0.6 million) based on the average bank debt balance outstanding during the period.

(c) Capital management

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

The Company manages its capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of the underlying petroleum and natural gas assets. The Company’s capital structure includes shareholders’ equity of $30.5 million, bank loans of $53.9 million, convertible debentures with a face value of $96.0 million and the cash working capital deficiency of $7.4 million, which excludes the current portion of unrealized losses on derivative contracts and amounts related to the assets held for sale. In order to maintain or adjust the capital structure, the Company may from time to time issue shares, seek additional debt financing and adjust its capital spending to manage current and projected debt levels.

There were no changes in the Company’s approach to capital management during the three months ended September 30, 2013.

Neither the Company nor any of its subsidiaries are subject to externally imposed capital requirements. The credit facilities are subject to periodic review of the borrowing base which is directly impacted by the value of the oil and natural gas reserves.

15. COMMITMENTS AND CONTINGENCIES

At September 30, 2013, the Company had firm service gas transportation agreements in which the Company guarantees that certain minimum volumes of natural gas will be shipped on various gas transportation systems. The terms of the various agreements expire in one to eight 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:

	2013		2014		2015		2016		2017		Thereafter
Firm service commitment	$	221	$	825	$	699	$	112	$	97	$	205
Firm service committed volumes (MMcfd)		9		7		5		3		3		6

There are no material changes to other commitments and contingencies from those disclosed in the Company’s annual audited consolidated financial statements as at and for the years ended December 31, 2012 and 2011. Subsequent to September 30, 2013, the Company fulfilled its term volume commitment under a facilities construction and operation agreement entered into in 2011.

16. SUBSEQUENT EVENTS

During October 2013, the Company closed the sale of certain oil and natural gas properties for net proceeds of approximately $78 million, repaid its bank debt, terminated its existing bank agreement, agreed to a new bank facility of $28 million, and the Board of Directors concluded the strategic alternatives process.

Corporate Information

Head Office

2200, 333 – 7^th Avenue S.W.

Calgary, Alberta

Canada T2P 2Z1

Phone (403) 262-6307

Fax (403) 261-2792

Website 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

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

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

Abbreviations used

AECO – intra-Alberta Nova inventory transfer price bbl – barrel

bpd – barrels per day

Mstb – thousand stock tank barrels

Mbbls – thousand barrels

BOE – barrels of oil equivalent

MBOE – thousand barrels of oil equivalent

BOED – barrels of oil equivalent per day

BOPD – barrels of oil per day

Cdn – Canadian

GJ – gigajoule

LIBOR – London Interbank Offered Rate

Mcf – thousand cubic feet

Mcfd – thousand cubic feet per day

MMcf – million cubic feet

MMcfd – million cubic feet per day

NGL – natural gas liquids

WTI – West Texas Intermediate

US or U.S. – United States

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

Anderson Energy Announces 2013 Third Quarter Results

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