Anderson Energy Announces 2013 Second Quarter Results

August 14, 2013 4:13 PM

CALGARY, ALBERTA–(Marketwired – Aug. 14, 2013) – Anderson Energy Ltd. (“Anderson” or the “Company”) (TSX:AXL) announces its operating and financial results for the second quarter ended June 30, 2013.

HIGHLIGHTS

Funds from operations in the second quarter of 2013 were $4.7 million. Production was 3,931 BOED. Oil and NGL production averaged 1,496 bpd in the second quarter of 2013. Oil represented 1,199 bpd of total production. Funds from operations for the first half of 2013 were $10.2 million.
The Company’s average oil price was $89.76 per bbl in the second quarter of 2013. The Cardium oil production is light, sweet oil that was subject to an average price differential of $3.67 US per bbl in the second quarter.
Oil and NGL revenue represented 71% of Anderson’s total oil and gas revenue.
The operating netback was $25.00 per BOE in the second quarter of 2013 compared to $21.04 per BOE in the second quarter of 2012. The operating netback for the Cardium properties averaged $47.61 per BOE in the second quarter of 2013.
Anderson has 165 gross (90 net) sections of land prospective for Cardium light oil drilling and has a remaining drilling inventory of 232 gross (148 net) locations.
Anderson has 104 gross (46 net) sections of land prospective for the emerging new Second White Specks light oil play and has assembled a drilling inventory of 102 gross (59 net) drilling locations.
The Company continues to review a range of strategic alternatives to enhance shareholder value. In 2012, Anderson sold $74 million in non-strategic assets to reduce bank debt. In the first quarter of 2013, it completed all of its remaining drilling commitments. In the second and third quarters of 2013, it continues to pursue asset sales, joint ventures and other sources of liquidity to fund its fourth quarter drilling program and will provide additional information when available.

FINANCIAL AND OPERATING HIGHLIGHTS

		Three months ended June 30								Six months ended June 30
(thousands of dollars, unless otherwise stated)			2013			2012		% Change			2013			2012		% Change
Oil and gas sales*		$	15,616		$	20,311		(23	%)	$	32,479		$	45,519		(29	%)
Revenue, net of royalties*		$	14,345		$	18,290		(22	%)	$	29,613		$	40,735		(27	%)

Funds from operations		$	4,701		$	7,606		(38	%)	$	10,187		$	18,222		(44	%)
Funds from operations per share
	Basic and diluted	$	0.03		$	0.04		(25	%)	$	0.06		$	0.11		(45	%)

Loss before effect of deferred tax adjustment and impairment loss		$	(3,672	)	$	(1,828	)	(101	%)	$	(8,785	)	$	(7,692	)	(14	%)
Loss per share before effect of deferred tax adjustment and impairment loss Basic and diluted		$	(0.02	)	$	(0.01	)	(100	%)	$	(0.05	)	$	(0.04	)	(25	%)

Loss		$	(49,306	)	$	(16,828	)	(193	%)	$	(54,419	)	$	(22,692	)	(140	%)
Loss per share
	Basic and diluted	$	(0.29	)	$	(0.10	)	(190	%)	$	(0.32	)	$	(0.13	)	(146	%)

Capital expenditures, net of proceeds on dispositions		$	186		$	4,786		(96	%)	$	7,848		$	16,876		(53	%)

Bank loans plus cash working capital deficiency										$	62,279		$	131,675		(53	%)
Convertible debentures										$	87,810		$	85,749		2	%

Shareholders’ equity										$	79,057		$	141,427		(44	%)

Average shares outstanding (thousands)
	Basic		172,550			172,550		–			172,550			172,550		–
	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)		1,199			1,669		(28	%)		1,363			1,812		(25	%)
	NGL (bpd)		297			750		(60	%)		250			727		(66	%)
	Natural gas (Mcfd)		14,611			26,438		(45	%)		14,684			26,951		(46	%)
	Barrels of oil equivalent (BOED)		3,931			6,825		(42	%)		4,060			7,031		(42	%)
Average prices:
	Oil ($/bbl)	$	89.76		$	81.58		10	%	$	87.01		$	85.31		2	%
	NGL ($/bbl)	$	48.73		$	54.38		(10	%)	$	53.99		$	60.66		(11	%)
	Natural gas ($/Mcf)	$	3.33		$	1.72		94	%	$	3.13		$	1.87		67	%
	Barrels of oil equivalent ($/BOE)*	$	43.66		$	32.70		34	%	$	44.19		$	35.57		24	%
Realized gain (loss) on derivative contracts ($/BOE)		$	(1.85	)	$	2.10		(188	%)	$	(1.70	)	$	1.19		(243	%)
Royalties ($/BOE)		$	3.55		$	3.25		9	%	$	3.90		$	3.74		4	%
Operating costs ($/BOE)		$	12.85		$	10.06		28	%	$	12.39		$	10.34		20	%
Transportation costs ($/BOE)		$	0.41		$	0.45		(9	%)	$	0.30		$	0.31		(3	%)
Operating netback ($/BOE)		$	25.00		$	21.04		19	%	$	25.90		$	22.37		16	%

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.

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
Number of wells in average	7	7	7	7
Barrels of oil per day (BOPD)	301	225	184	116
Barrels of oil and NGL per day (BPD)	329	250	208	142
Barrels of oil equivalent per day (BOED)*	453	362	309	225

* 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.

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

PRODUCTION

Production in the second quarter of 2013 was 3,931 BOED of which 1,496 bpd (38%) was derived from oil and natural gas liquids production. All of the operated Cardium wells successfully drilled in the first quarter of 2013 have been placed on production. Overall production was lower in the second quarter of 2013 compared to the same period in 2012 due to property dispositions completed in 2012 and natural declines in other properties. Oil production in the second quarter represents a more stable production base than in the first quarter which was influenced by flush production from horizontal multi-staged fractured new oil wells.

With improving natural gas prices, 1.2 MMcfd of natural gas was brought back on production in the second quarter of 2013. This production is subject to shut-in again in a weaker price environment.

FINANCIAL RESULTS

Anderson’s funds from operations were $4.7 million in the second quarter of 2013 compared to $7.6 million in the second quarter of 2012. The Company’s average crude oil and natural gas liquids sales prices in the second quarter of 2013 were $89.76 and $48.73 per barrel respectively compared to $81.58 and $54.38 per barrel in the second quarter of 2012. During the second quarter of 2013, oil and NGL revenue represented 71% of Anderson’s total oil and gas revenue compared to 79% in the second quarter of 2012. The Company’s average natural gas sales price was $3.33 per Mcf in the second quarter of 2013 compared to $1.72 per Mcf in second quarter of 2012. The Company recorded a loss of $49.3 million in the second quarter of 2013 due to the derecognition of previously recorded deferred tax assets of $45.6 million. The Company’s operating netback was $25.00 per BOE in the second quarter of 2013 compared to $21.04 per BOE in the second quarter of 2012. The increase in the operating netback was primarily due to higher commodity prices. Anderson’s netback for its Cardium horizontal properties in the second quarter of 2013 was $47.61 per BOE (exclusive of hedging). The Company has fixed price swap contracts on an average of 850 bpd of crude oil production at an average price of $90.55 per barrel for the last six months of 2013. The mark-to-market loss on these contracts was $1.5 million at June 30, 2013.

	Average wellhead natural gas price ($/Mcf)	Average oil and NGL price ($/bbl)	Revenue ($/BOE)	Operating netback ($/BOE)	Funds from operations ($/BOE)
2011	3.60	86.53	42.13	25.89	19.40
2012	2.21	75.88	34.98	22.71	13.33
First quarter of 2013	2.94	82.13	44.70	26.78	14.54
Second quarter of 2013	3.33	81.62	43.66	25.00	13.14

Capital expenditures were $0.2 million in the second quarter of 2013. This compares to capital expenditures of $4.8 million in the second quarter of 2012. 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 from the strategic alternatives process. Anderson anticipates very little capital spending in the third quarter of the year. As such, a significant portion of cash flow from operations in the third quarter is expected to be applied to reduce bank debt plus working capital deficiency. The Company will revisit its 2013 capital program later in the second half of the year depending on the outcome of the strategic alternatives process.

LIGHT OIL HORIZONTAL DRILLING INVENTORY

The Company’s drilled and drill-ready light oil horizontal drilling inventory is outlined below:

Light Oil Horizontal Drilling Inventory (number of drilling locations)		Gross	Net *
Cardium Prospect Area
	Garrington	115	87
	Willesden Green	119	86
	Ferrier	27	17
	Pembina	50	17
	Total Cardium inventory	311	207
	Cardium oil wells drilled to June 30, 2013	79	59
	Remaining Cardium inventory	232	148
Other Zones		108	62
Remaining Cardium and other zone inventory, June 30, 2013		340	210

* Net is net revenue interest

The Company’s remaining Edmonton Sands shallow gas drilling inventory is now estimated to be 542 gross (307 net) locations.

CARDIUM ENHANCED OIL RECOVERY

Enhanced oil recovery continues to offer significant potential upside for Cardium development. Anderson has completed a computer reservoir simulation of the Garrington field to determine the most appropriate fluid and scheme for enhanced recovery of Cardium oil using horizontal oil drilling. The conclusion of the study is that a gas flood is the most economical scheme and could potentially double recovery in this oil pool. Uphole Edmonton Sands gas and/or Cardium solution gas could be used as an injection fluid to enhance recovery.

SECOND WHITE SPECKS

The Second White Specks (“2WS”) zone is 100 meters deeper than the Cardium formation and is the oil-source zone for the Cardium play and is oil-charged with similar quality light oil that is in the Cardium formation. To date, other operators have drilled six 2WS horizontal oil wells offsetting the Company lands. The Company believes this play can be exploited by drilling off existing Cardium drilling pads and handling the 2WS oil and solution gas at existing Cardium facilities. Anderson has 104 gross (46 net) sections of land prospective for the Second White Specks light oil play and has assembled a drilling inventory of 102 gross (59 net) drilling locations.

PEOPLE

Patrick O’Rourke, Vice President, Production will be leaving the Company effective August 31, 2013 to pursue other business opportunities. We wish Patrick well in his future endeavors. Steve Reisinger, Production Manager will assume Patrick’s responsibilities. Steve has been with the Company for the past two years and we congratulate him on his new responsibilities.

Glenn Hockley will not be standing for re-election as a director at the upcoming annual meeting of shareholders on September 16, 2013. We thank him for his eight years of service as a board member and wish him well in the future. J.C. Anderson will stand for re-election as a director but intends to retire as Chairman of the Board. A new Chairman will be appointed by the directors following the annual meeting of shareholders.

STRATEGIC ALTERNATIVES

The Company is continuing the process to identify, examine and consider a range of strategic alternatives available to the Company with a view to enhancing shareholder value. The strategic alternatives may include, but are not limited to, a sale of all or a material portion of the assets of Anderson, or a drilling joint venture, either in one transaction, or in a series of transactions, the outright sale of the Company, or a merger or other strategic transaction involving Anderson and a third party. The Board of Directors believes that the Company’s shares trade at a discount to the value of the underlying assets, especially given its high quality light oil production base, prospective horizontal light oil drilling inventory and significant tax pools. The Board of Directors has established a special committee comprised of independent directors of the Company to oversee the process and has retained BMO Capital Markets and RBC Capital Markets as its financial advisors to assist the Special Committee and the Board of Directors with the process.

It is Anderson’s current intention to not disclose developments with respect to the strategic alternatives process unless and until the Board of Directors has approved a specific transaction or otherwise determines that disclosure is necessary in accordance with applicable law. The Company cautions that there are no assurances or guarantees that the process will result in a transaction or, if a transaction is undertaken, the terms or timing of such a transaction or the impact it will have on the Company’s financial position. The Company has not set a definitive schedule to complete the evaluation. Subject to the outcome of the strategic alternatives process, the Company intends to continue to focus on converting its asset base so that more than 50% of its production is from oil and NGL.

Brian H. Dau, President & Chief Executive Officer

August 14, 2013

Management’s Discussion and Analysis

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2013 AND 2012

The following management’s discussion and analysis (“MD&A”) is dated August 13, 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 six months ended June 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 quarter, revenue and production for the second quarter ended June 30, 2013 was lower than the same period last year for two main reasons:

(1)	the sale of approximately $74 million in assets during the year ended December 31, 2012; and
(2)	the impact of a curtailed drilling program on the replacement of natural production declines.

The Company suspended its shallow gas drilling program in 2010 due to low natural gas prices, and curtailed its oil drilling program in 2012 and 2013 due to limited funds, 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. Accordingly, normal production declines in both natural gas and oil were not replaced. In addition, the Company shut-in 700 Mcfd of higher operating expense natural gas production in the first quarter of 2012 and an additional 900 Mcfd in the first quarter of 2013 that was uneconomical to produce in the existing price environment. With improving natural gas prices, 1.2 MMcfd of natural gas was brought back on production in the second quarter of 2013. This production is subject to shut-in again in a weaker price environment.

Bank loans plus cash working capital deficiency (excluding unrealized gains or losses on derivative contracts) decreased to $62.3 million at June 30, 2013 from $131.7 million at June 30, 2012 due to the assets sales in 2012. During the second quarter of 2013, the Company spent $0.2 million in capital expenditures, earned $4.7 million in funds from operations and reported a loss of $49.3 million. The reported loss includes income tax expense of $45.6 million related to the derecognition of the Company’s deferred tax asset.

PRODUCTION

	Three months ended June 30		Six months ended June 30
	2013	2012	2013	2012
Oil (bpd)	1,199	1,669	1,363	1,812
NGL (bpd)	297	750	250	727
Natural gas (Mcfd)	14,611	26,438	14,684	26,951
Total (BOED)⁽³⁾	3,931	6,825	4,060	7,031

PRICES

		Three months ended June 30				Six months ended June 30
		2013		2012		2013		2012
Oil ($/bbl)⁽¹⁾	$	89.76	$	81.58	$	87.01	$	85.31
NGL ($/bbl)		48.73		54.38		53.99		60.66
Natural gas ($/Mcf)		3.33		1.72		3.13		1.87
Total ($/BOE)^(1)(2)(3)	$	43.66	$	32.70	$	44.19	$	35.57

OIL AND NATURAL GAS SALES

		Three months ended June 30				Six months ended June 30
(thousands of dollars)		2013		2012		2013		2012
Oil⁽¹⁾	$	9,792	$	12,390	$	21,463	$	28,136
NGL		1,316		3,711		2,445		8,021
Natural gas		4,426		4,130		8,328		9,162
Royalty and other		82		80		243		200
Total oil and gas sales⁽¹⁾	$	15,616	$	20,311	$	32,479	$	45,519

OPERATING NETBACK

		Three months ended June 30						Six months ended June 30
(thousands of dollars)			2013			2012			2013			2012
Revenue⁽¹⁾⁽²⁾		$	15,616		$	20,311		$	32,479		$	45,519
Realized gain (loss) on derivative contracts			(661	)		1,305			(1,247	)		1,518
Royalties			(1,271	)		(2,021	)		(2,866	)		(4,784	)
Operating expenses			(4,597	)		(6,250	)		(9,100	)		(13,238	)
Transportation expenses			(146	)		(279	)		(223	)		(390	)
Operating netback		$	8,941		$	13,066		$	19,043		$	28,625
Sales volume (MBOE)⁽³⁾			357.7			621.1			734.9			1,279.6
Per BOE⁽³⁾
	Revenue⁽¹⁾⁽²⁾	$	43.66		$	32.70		$	44.19		$	35.57
	Realized gain (loss) on derivative contracts		(1.85	)		2.10			(1.70	)		1.19
	Royalties		(3.55	)		(3.25	)		(3.90	)		(3.74	)
	Operating expenses		(12.85	)		(10.06	)		(12.39	)		(10.34	)
	Transportation expenses		(0.41	)		(0.45	)		(0.30	)		(0.31	)
	Operating netback	$	25.00		$	21.04		$	25.90		$	22.37

(1)	The three months ended June 30, 2013 excludes the realized gain (loss) and unrealized gain on derivative contracts of ($0.7) million and $0.6 million respectively (June 30, 2012 – $1.3 million and $4.7 million respectively). The six months ended June 30, 2013 excludes realized and unrealized loss on derivative contracts of $1.2 million and $0.4 million respectively (June 30, 2012 – $1.5 million gain and $3.0 million gain respectively).
(2)	Includes royalty and other income classified with oil and gas sales.
(3)	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 second quarter of 2013 compared to the first quarter of 2013 were as follows:

	Three months ended June 30, 2013	Three months ended March 31, 2013
Oil (bpd)	1,199	1,529
NGL (bpd)	297	203
Natural gas (Mcfd)	14,611	14,759
Total (BOED)	3,931	4,191

Production in the second quarter of 2013 was 3,931 BOED of which 1,496 bpd (38%) was derived from oil and natural gas liquids production. Oil production declined 330 barrels per day from the first quarter of 2013. Oil production in the second quarter represents a more stable production base than the first quarter which was influenced by flush production from new horizontal multi-staged fractured oil wells.

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. Light, sweet oil differentials between Cushing, Oklahoma and Edmonton, Alberta continue to be affected by transportation and market factors. The average differential for the second quarter ended June 30, 2013 was $3.67 US per bbl.

The above noted oil prices do not include realized gains and losses on derivative contracts. For the three months ended June 30, 2013, the loss was $0.7 million (June 30, 2012 – $1.3 million gain). The average oil price including the realized gains or losses from derivative contracts was $83.70 per barrel for the second quarter of 2013 compared to $80.57 per barrel for the first quarter of 2013 and $90.18 for the second quarter of 2012. For the six months ended June 30, 2013, the realized loss was $1.2 million (June 30, 2012 – $1.5 million gain). The average oil price including the realized gains or losses from derivative contracts was $81.95 per barrel for the first half of 2013 compared to $89.91 per barrel for the first half of 2012.

In the second quarter of 2013, natural gas prices continued to recover from the 16 year lows experienced in 2012. The Company’s average natural gas sales price was $3.33 per Mcf for the three months ended June 30, 2013, 13% higher than the first quarter of 2013 price of $2.94 per Mcf and 94% higher than the second quarter of 2012 price of $1.72 per Mcf. However, natural gas prices have softened since June 2013. AECO natural gas spot prices averaged approximately $2.66 per GJ during July 2013.

Commodity contracts

At June 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)
July 1, 2013 to September 30, 2013	900	$	90.54
October 1, 2013 to December 31, 2013	800	$	90.56

By comparison, WTI Canadian averaged approximately $96.42 per bbl in the second quarter of 2013 and approximately $108.91 in July 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.

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

	Three months ended June 30					Six months ended June 30
(thousands of dollars)		2013			2012		2013			2012
Realized gain (loss) on derivative contracts	$	(661	)	$	1,305	$	(1,247	)	$	1,518
Unrealized gain (loss) on derivative contracts		638			4,692		(433	)		3,003
	$	(23	)	$	5,997	$	(1,680	)	$	4,521

Royalties

For the second quarter of 2013, the average royalty rate was 8.1% of revenue compared to 9.5% in the first quarter of 2013 and 10.0% in the second quarter of 2012. For the first half of 2013, the average royalty rate was 8.8% of revenue compared to 10.5% in the first half of 2012. The decrease in the average royalty rate for the quarter ended June 30, 2013 compared to the second quarter of 2012 is due to higher royalty rates on properties that were sold during 2012 and an annual adjustment to the 2012 gas cost allowance which was received in the second quarter of 2013.

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 June 30						Six months ended June 30
		2013			2012			2013			2012
Gross Crown royalties		5.3%			9.2%			5.3%			8.7%
Gas cost allowance		(3.3%	)		(4.3%	)		(2.3%	)		(4.3%	)
Other royalties		6.1%			5.1%			5.8%			6.1%
Total royalties		8.1%			10.0%			8.8%			10.5%
Total royalties ($/BOE)	$	3.55		$	3.25		$	3.90		$	3.74

Operating expenses

Operating expenses were $12.85 per BOE for the three months ended June 30, 2013 compared to $11.93 per BOE in the first quarter of 2013 and $10.06 per BOE in the second quarter of 2012. For the six months ended June 30, 2013, operating expenses were $12.39 per BOE compared to $10.34 per BOE in the first half of 2012. Operating expenses were higher in the second quarter of 2013 compared to the second quarter of 2012 due largely to equalization costs and other expenses received in the quarter that relate to prior periods (approximately $1.00 per BOE), as well as the impact of fixed costs on lower sales volumes. Also, processing revenues that reduce operating expenses were $0.38 per BOE lower in the second quarter of 2013 and $0.37 per BOE lower in the first half of 2013 compared to similar periods of 2012. The reduction was due to property dispositions in the third quarter of 2012, but was partially offset by increased processing revenue from the Garrington and Willesden Green facilities.

Transportation expenses

For the second quarter of 2013, transportation expenses were $0.41 per BOE compared to $0.45 per BOE for the second quarter of 2012. For the six months ended June 30, 2013, transportation expenses were $0.30 per BOE compared to $0.31 per BOE for the same period in 2012.

Depletion and depreciation

Depletion and depreciation was $8.1 million ($22.53 per BOE) in the second quarter of 2013 compared to $8.6 million ($22.83 per BOE) in the first quarter of 2013 and $12.3 million ($19.77 per BOE) in the second quarter of 2012. The decrease in depletion and depreciation expense in the second quarter of 2013 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.

In the second quarter of 2013, the ongoing strategic alternatives process was considered to be an indicator of impairment. As such, an impairment test was performed on the Company’s CGUs and it was concluded that no impairment existed at June 30, 2013. In the second quarter of 2012, forecasted natural gas commodity prices led to an impairment charge of $20 million against the Company’s gas-weighted CGUs.

General and administrative expenses

General and administrative expenses excluding share-based compensation were $1.7 million ($4.64 per BOE) for the second quarter of 2013 compared to $2.1 million ($5.45 per BOE) in the first quarter of 2013 and $2.4 million ($3.94 per BOE) for the second quarter of 2012. For the six months ended June 30, 2013, general and administrative expenses excluding share-based compensation were $3.7 million ($5.06 per BOE) compared to $4.6 million ($3.59 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 June 30						Six months ended June 30
(thousands of dollars)		2013			2012			2013			2012
General and administrative (gross)	$	2,249		$	3,539		$	5,013		$	6,958
Overhead recoveries		(278	)		(243	)		(519	)		(708	)
Capitalized		(311	)		(851	)		(779	)		(1,659	)
General and administrative (cash)	$	1,660		$	2,445		$	3,715		$	4,591
Net share-based compensation		188			203			385			430
General and administrative	$	1,848		$	2,648		$	4,100		$	5,021
General and administrative (cash) ($/BOE) ⁽¹⁾	$	4.64		$	3.94		$	5.06		$	3.59
% Capitalized		14%			24%			16%			24%

(1)	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 second quarter of 2013 ($0.2 million net of amounts capitalized) versus $0.3 million ($0.2 million net of amounts capitalized) in second quarter of 2012. For the six months ended June 30, 2013, share-based compensation costs were $0.5 million ($0.4 million net of amounts capitalized) compared to $0.7 million ($0.4 million net of amounts capitalized) in the same period of 2012.

Finance expenses

Finance expenses were $3.3 million for the second quarter of 2013, compared to $3.3 million in the first quarter of 2013 and $3.8 million in the second quarter of 2012. For the six months ended June 30, 2013, finance expenses were $6.6 million compared to $7.4 million in the same period of 2012. The decrease in finance expenses in the second quarter of 2013 compared with the second quarter of 2012 is the result of lower average balances outstanding under the Company’s credit facilities and lower accretion on decommissioning obligations due to the property sales in 2012. The average effective interest rate on outstanding bank loans was 5.5% for the six months ended June 30, 2013 compared to 4.2% for the comparable period in 2012.

	Three months ended June 30				Six months ended June 30
(thousands of dollars)		2013		2012		2013		2012
Interest and accretion on convertible debentures	$	2,305	$	2,252	$	4,600	$	4,496
Interest expense on credit facilities and other		809		1,251		1,600		2,293
Accretion on decommissioning obligations		194		319		382		637
Finance expenses	$	3,308	$	3,822	$	6,582	$	7,426

Decommissioning obligations

The decommissioning obligation at June 30, 2013 was lower than at December 31, 2012 due to changes in estimates. The Alberta Energy Resources Conservation Board (the “ERCB”) recently published updated estimated average costs for abandonment and reclamation of wells and facilities located in Alberta based on information it gathers from industry participants. The Company uses this information in formulating its own estimates of the costs related to abandonment and reclamation, and adjusts the estimates for specific situations related to the Company’s assets, as well as inflation rates reflective of expected increases in future costs (currently 2% per year). Upon reviewing the Company’s estimated decommissioning costs in light of the recently updated estimated costs published by the ERCB, the Company lowered its estimated costs of decommissioning at March 31, 2013 by $1.3 million.

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

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

Unrecognized deferred tax asset

During the period, the Company derecognized deferred tax assets of $45.6 million in respect of deductible temporary differences. The material uncertainties related to the outcome of the strategic alternative process were considered to affect the assessment of 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. The Company has approximately $425 million in tax pools at June 30, 2013.

Funds from operations

Funds from operations of $4.7 million ($0.03 per share) for the second quarter of 2013 were 38% lower than the second quarter of 2012 ($7.6 million or $0.04 per share) and 14% lower than the first quarter of 2013 ($5.5 million or $0.03 per share) largely as a result of reduced production volumes.

	Three months ended June 30					Six months ended June 30
(thousands of dollars)		2013		2012			2013		2012
Cash from operating activities	$	3,953	$	7,712		$	9,124	$	17,018
Changes in non-cash working capital		737		(164	)		976		839
Decommissioning expenditures		11		58			87		365
Funds from operations	$	4,701	$	7,606		$	10,187	$	18,222

Earnings

The Company reported a loss of $49.3 million in the second quarter of 2013 compared to loss of $5.1 million in the first quarter of 2013 and a loss of $16.8 million for the second quarter of 2012. The loss in the second quarter of 2013 included a derecognition of a deferred tax asset of $45.6 million, while the loss in the second quarter of 2012 included an impairment loss of $20 million.

CAPITAL EXPENDITURES

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

		Three months ended June 30						Six months ended June 30
(thousands of dollars)		2013			2012			2013			2012
Land, geological and geophysical costs	$	25		$	195		$	72		$	360
Proceeds on disposition		(52	)		–			(52	)		(6,199	)
Drilling, completion and recompletion		(287	)		1,815			5,037			14,088
Facilities and well equipment		273			1,991			2,103			7,127
Capitalized general and administrative expenses		311			851			779			1,659
Total finding, development & acquisition expenditures	$	270		$	4,852		$	7,939		$	17,035
Change in compressor and other inventory and equipment		(92	)		(85	)		(106	)		(185	)
Office equipment and furniture		8			19			15			26
Total net cash capital expenditures	$	186		$	4,786		$	7,848		$	16,876

Drilling statistics are shown below:

Three months ended June 30

Six months ended June 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%

Historically, the second quarter is not an active drilling quarter and the Company did not drill any new wells in the second quarter of 2013. 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 August 13, 2013, there were 172.5 million common shares outstanding, 14.1 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 second quarter of 2013 and 2012, no common shares were issued under the employee stock option plan.

SHARE PRICE ON TSX

		Three months ended June 30				Six months ended June 30
		2013		2012		2013		2012
High	$	0.22	$	0.58	$	0.25	$	0.68
Low	$	0.13	$	0.25	$	0.13	$	0.25
Close	$	0.14	$	0.34	$	0.14	$	0.34
Volume		4,932,747		8,589,542		11,293,181		24,840,822
Shares outstanding at June 30		172,549,701		172,549,701		172,549,701		172,549,701
Market capitalization at June 30	$	24,156,958	$	58,666,898	$	24,156,958	$	58,666,898

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 six months ended June 30, 2013 approximately 2.0 million and 5.3 million common shares traded on these alternative exchanges respectively. Including these exchanges, an average of 108,663 common shares traded per day in the three months ended June 30, 2013 (June 30, 2012 – 174,234), representing a quarterly turnover ratio of 4% (June 30, 2012 – 6%).

LIQUIDITY AND CAPITAL RESOURCES

At June 30, 2013, the Company had outstanding bank loans of $53.9 million, convertible debentures of $96.0 million (principal) and a cash working capital deficiency (excluding the unrealized loss on derivative contracts) of $8.4 million. The working capital deficiency is largely due to accruals associated with capital spending, operating and interest expenses and will be funded through the available credit facilities and future operating cash flows. The following table shows the changes in bank loans plus cash working capital deficiency:

	Three months ended June 30						Six months ended June 30
(thousands of dollars)		2013			2012			2013			2012
Bank loans plus cash working capital deficiency, beginning of period	$	(66,783	)	$	(134,437	)	$	(64,531	)	$	(132,656	)
Funds from operations		4,701			7,606			10,187			18,222
Net cash capital expenditures		(186	)		(4,786	)		(7,848	)		(16,876	)
Decommissioning expenditures		(11	)		(58	)		(87	)		(365	)
Bank loans plus cash working capital deficiency, end of period	$	(62,279	)	$	(131,675	)	$	(62,279	)	$	(131,675	)

Bank loans, end of period	$	(53,892	)	$	(119,686	)	$	(53,892	)	$	(119,686	)
Cash working capital deficiency, end of period		(8,387	)		(11,989	)		(8,387	)		(11,989	)
Bank loans plus cash working capital deficiency, end of period	$	(62,279	)	$	(131,675	)	$	(62,279	)	$	(131,675	)

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 from the strategic alternatives process. 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 June 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. Advances can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’ acceptance or LIBOR loan rates plus applicable margins. These margins vary from 3% to 4% depending on the borrowing option used. At June 30, 2013, no amounts were drawn in U.S. funds. The Company had $10.7 million of credit available at June 30, 2013. Anderson will prudently use its bank loan facilities to finance its operations as required.

Due to the strategic alternatives process, Anderson anticipates very little capital spending in the third quarter of the year. As such, a significant portion of cash flow from operations in the third quarter is expected to be applied to reduce bank debt plus working capital deficiency. The Company will revisit its 2013 capital program later in the second half of the year depending on the outcome of the strategic alternatives process. The Company continues to pursue asset sales, joint ventures and other sources of liquidity to fund its fourth quarter drilling program and will provide additional information when available.

The available lending limits under the bank facilities are reviewed periodically and are based on the bank syndicate’s interpretation of the Company’s reserves and future commodity prices. The last review was conducted in May 2013 and there can be no assurance that the amount of the available facilities will not be adjusted at the next scheduled review. The revolving term credit facility and the working capital credit facility have a maturity date of September 30, 2013 and, if the facility were not renewed, all outstanding advances would become repayable on September 30, 2013. Material uncertainties exist as to the outcome of the strategic alternative process and the terms at which the current bank debt facility may be renewed. The successful future operations of the Company are dependent on the ability of the Company to secure sufficient funds through operations, bank financing or other sources from the strategic alternatives process, and there are no assurances that such funding will be available when needed.

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.”

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:

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 June 30, 2013.

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 six month period ended June 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 April 1, 2013 and ending on June 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

The Company is a light oil horizontal development company focused almost exclusively on the Cardium with a stacked resource play in the Second White Specks. The Company’s assets are almost entirely west of the fifth meridian and within a two hour drive north of Calgary on predominantly year-round access land.

The Company has 165 gross (90 net) sections of land and an inventory of 232 gross (148 net revenue) future drilling locations in the Cardium horizontal light oil play of which only 32% of net locations are recognized by GLJ Petroleum Consultants in their evaluation of the Company’s reserves as at December 31, 2012. Newly drilled Cardium horizontal wells can be easily connected to existing gathering systems and facilities. Last winter’s drilling program demonstrated initial production results for slick water fracture stimulations that were vastly superior to previously used fracture stimulation techniques. In addition, enhanced oil recovery schemes have the potential to significantly increase the recovery factors in the Cardium.

The Company has 104 gross (46 net) sections of land prospective for the emerging new Second White Specks light oil play and has assembled a drilling inventory of 102 gross (59 net) drilling locations. This zone is 100 meters deeper than the Cardium formation, is the oil-source zone for the Cardium play and is oil-charged with similar quality light oil that is in the Cardium formation. The Company believes this play can be exploited by drilling off existing Cardium drilling pads and that the oil and solution gas produced can be handled at existing Cardium facilities.

While the Company remains focused on developing its light oil assets, it also still has a large inventory of low risk natural gas drilling locations that could be developed when natural gas prices recover. The Company’s remaining Edmonton Sands shallow gas drilling inventory is now estimated to be 542 gross (307 net) locations.

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 from the strategic alternative process. Subject to the outcome of the strategic alternatives process, the Company intends to continue to focus on converting its asset base so that more than 50% of its production is from oil and NGL.

STRATEGIC ALTERNATIVES

Since the process began in 2012, the Company has:

sold $74 million of non-strategic assets, which were primarily natural gas assets and other miscellaneous properties;
reduced bank debt to $53.9 million at June 30, 2013 from $106.7 million at March 31, 2012;
restructured all of its shallow gas and Cardium drilling commitments so that by the end of January 2013, Anderson had completed all of its drilling commitments;
reduced its head office staff count and head office leasing costs;
opened a confidential data room to assist with the process; and
been marketing various individual properties for sale or farm-out.

It is Anderson’s current intention to not disclose new developments with respect to the strategic alternatives process unless and until the Board of Directors has approved a specific transaction or otherwise determines that disclosure is necessary in accordance with applicable law. The Company cautions that there are no assurances or guarantees that the process will result in a transaction or, if a transaction is undertaken, the terms or timing of such a transaction or the impact it will have on the Company’s financial position. The Company has not set a definitive schedule to complete the evaluation.

On April 1, 2013, the Company renewed a retention plan for its employees as part of this process.

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 two quarters 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 half of 2013. This combined with declines in commodity prices relative to 2011 led to decreases in revenue in 2012 and the first half 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.

Bank loans plus cash working capital deficiency balances fluctuated in response to the capital spending programs related to the Cardium development through 2011, 2012 and into 2013, and were reduced by the proceeds from the sale of assets in 2012 and cash from operating activities.

SELECTED QUARTERLY INFORMATION

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

			Q2 2013			Q1 2013			Q4 2012			Q3 2012
Revenue, net of royalties		$	14,345		$	15,268		$	13,796		$	15,284
Funds from operations		$	4,701		$	5,486		$	5,694		$	5,725
Funds from operations per share, basic and diluted		$	0.03		$	0.03		$	0.03		$	0.03
Earnings (loss) before effect of deferred tax adjustment and impairment loss		$	(3,672	)	$	(5,113	)	$	(8,895	)	$	94
Earnings (loss) per share before effect of deferred tax adjustment and impairment loss, basic and diluted		$	(0.02	)	$	(0.03	)	$	(0.05	)	$	–
Earnings (loss)		$	(49,306	)	$	(5,113	)	$	(8,895	)	$	94
Earnings (loss) per share, basic and diluted		$	(0.29	)	$	(0.03	)	$	(0.05	)	$	–
Capital expenditures, net of proceeds on dispositions		$	186		$	7,662		$	(26,880	)	$	(28,986	)
Cash from operating activities		$	3,953		$	5,171		$	6,976		$	5,845
Bank loans plus cash working capital deficiency		$	62,279		$	66,783		$	64,531		$	96,991
Daily sales
	Oil (bpd)		1,199			1,529			1,135			1,274
	NGL (bpd)		297			203			338			576
	Natural gas (Mcfd)		14,611			14,759			18,159			23,519
	BOE (BOED)⁽³⁾		3,931			4,191			4,500			5,770
Average prices
	Oil ($/bbl)⁽²⁾	$	89.76		$	84.83		$	79.73		$	80.44
	NGL ($/bbl)	$	48.73		$	61.77		$	52.02		$	51.59
	Natural gas ($/Mcf)	$	3.33		$	2.94		$	3.16		$	2.24
	BOE ($/BOE)^(1)(2)(3)	$	43.66		$	44.70		$	36.89		$	32.05

			Q2 2012			Q1 2012			Q4 2011			Q3 2011
Revenue, net of royalties		$	18,290		$	22,445		$	28,457		$	24,970
Funds from operations		$	7,606		$	10,616		$	16,997		$	12,655
Funds from operations per share, basic and diluted		$	0.04		$	0.06		$	0.10		$	0.07
Earnings (loss) before effect of deferred tax adjustment and impairment loss		$	(1,828	)	$	(5,864	)	$	(4,939	)	$	6,667
Earnings (loss) per share before effect of deferred tax adjustment and impairment loss, basic and diluted		$	(0.01	)	$	(0.03	)	$	(0.03	)	$	0.04
Earnings (loss)		$	(16,828	)	$	(5,864	)	$	(32,167	)	$	7,472
Earnings (loss) per share, basic and diluted		$	(0.10	)	$	(0.03	)	$	(0.19	)	$	0.04
Capital expenditures, net of proceeds on dispositions		$	4,786		$	12,090		$	40,924		$	49,713
Cash from operating activities		$	7,712		$	9,306		$	16,462		$	11,893
Bank loans plus cash working capital deficiency		$	131,675		$	134,437		$	132,656		$	108,583
Daily sales
	Oil (bpd)		1,669			1,956			2,122			1,709
	NGL (bpd)		750			703			715			636
	Natural gas (Mcfd)		26,438			27,463			30,576			30,038
	BOE (BOED)⁽³⁾		6,825			7,236			7,933			7,351
Average prices
	Oil ($/bbl)⁽²⁾	$	81.58		$	88.48		$	96.33		$	89.05
	NGL ($/bbl)	$	54.38		$	67.36		$	72.71		$	66.07
	Natural gas ($/Mcf)	$	1.72		$	2.01		$	3.20		$	3.85
	BOE ($/BOE)^(1)(2)(3)	$	32.70		$	38.28		$	44.70		$	42.16

(1)	Includes royalty and other income classified with oil and gas sales.
(2)	Excludes realized and unrealized hedging gains (losses) on derivative contracts as follows: 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; Q4 2011 – ($0.3) million and ($7.9) million respectively; and Q3 2011 – $0.9 million and $6.4 million respectively.
(3)	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; number of locations in drilling inventory and wells to be drilled; timing and location of drilling and tie-in of wells and the costs thereof; productive capacity of the wells; timing of and construction of facilities; expected production rates; percentage of production from oil and natural gas liquids; dates of commencement of production; amount of capital expenditures and the timing and method of financing thereof; value of undeveloped land; extent of reserves additions; ability to attain cost savings; drilling program success; impact of changes in commodity prices on operating results; estimates of future operating netbacks; potential results of the strategic alternatives review process, including the possibility of further asset dispositions and use of proceeds therefrom, and enhancement of shareholder value; disclosure intentions with respect to the strategic alternatives review process; factors on which the continued development of the Company’s oil and gas assets and future operations are dependent; 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 the value of acquisitions and farm-ins; failure to realize the anticipated benefits of acquisitions and farm-ins; inability to complete property dispositions or to complete them at anticipated values; delays resulting from or inability to obtain required regulatory approvals; changes to government regulation; ability to access sufficient capital from internal and external sources; and other factors, many of which are beyond the Company’s control.
The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as the factors are interdependent, and management’s future course of action would depend on its assessment of all information at the time. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements and readers should not place undue reliance on the assumptions and forward-looking statements. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect Anderson’s operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) or at Anderson’s website (www.andersonenergy.ca).

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

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)

			June 30, 2013			December 31, 2012

ASSETS
Current assets:
	Cash	$	–		$	1
	Accounts receivable and accruals		8,183			9,881
	Prepaid expenses and deposits		1,109			1,788
Total current assets			9,292			11,670

Deferred tax asset (note 6)			–			45,634
Property, plant and equipment (note 3)			276,472			286,174
Total assets		$	285,764		$	343,478

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
	Accounts payable and accruals	$	17,679		$	28,107
	Unrealized loss on derivative contracts (note 12)		1,530			1,097
	Bank loans (note 4)		53,892			48,094
Total current liabilities			73,101			77,298

Convertible debentures			87,810			86,753
Decommissioning obligations (note 5)			45,796			46,467
Total liabilities			206,707			210,518
Shareholders’ equity:
	Share capital (note 7)		171,460			171,460
	Equity component of convertible debentures		5,019			5,019
	Contributed surplus		10,934			10,418
	Deficit		(108,356	)		(53,937	)
Total shareholders’ equity			79,057			132,960
Future operations (note 1)
Commitments and contingencies (note 13)
Total liabilities and shareholders’ equity		$	285,764		$	343,478

See accompanying notes to the condensed interim consolidated financial statements.

ANDERSON ENERGY LTD.

Consolidated Statements of Operations and Comprehensive Loss

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

(Unaudited)

		Three months ended June 30						Six months ended June 30
		2013			2012			2013			2012

Oil and gas sales	$	15,616		$	20,311		$	32,479		$	45,519
Royalties		(1,271	)		(2,021	)		(2,866	)		(4,784	)
Revenue, net of royalties		14,345			18,290			29,613			40,735
Other gains (losses) (note 9)		(60	)		4,608			(1,723	)		522
Total revenue, net of royalties and other gains (losses)		14,285			22,898			27,890			41,257

Operating expenses		4,597			6,250			9,100			13,238
Transportation expenses		146			279			223			390
Depletion and depreciation		8,059			12,276			16,672			25,318
Impairment loss (note 3)		–			20,000			–			20,000
General and administrative expenses		1,848			2,648			4,100			5,021
Loss from operating activities		(365	)		(18,555	)		(2,205	)		(22,710	)

Finance income (note 10)		1			8			2			24
Finance expenses (note 10)		(3,308	)		(3,822	)		(6,582	)		(7,426	)
Net finance expenses		(3,307	)		(3,814	)		(6,580	)		(7,402	)

Loss before taxes		(3,672	)		(22,369	)		(8,785	)		(30,112	)
Deferred income tax expense (benefit) (note 6)		45,634			(5,541	)		45,634			(7,420	)
Loss and comprehensive loss for the period		(49,306	)		(16,828	)		(54,419	)		(22,692	)

Basic and diluted loss per share (note 8)	$	(0.29	)	$	(0.10	)	$	(0.32	)	$	(0.13	)

See accompanying notes to the condensed interim consolidated financial statements.

ANDERSON ENERGY LTD.

Consolidated Statements of Changes in Shareholders’ Equity

SIX MONTHS ENDED JUNE 30, 2013 AND 2012

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

(Unaudited)

	Number of common shares		Share capital		Equity comp- onent of conver- tible debent- ures		Contri- buted surplus		Deficit			Total share- holders’ equity
Balance at December 31, 2011	172,549,701	$	171,460	$	5,019	$	9,385	$	(22,444	)	$	163,420
Share-based payments	–		–		–		699		–			699
Loss for the period	–		–		–		–		(22,692	)		(22,692	)
Balance at June 30, 2012	172,549,701	$	171,460	$	5,019	$	10,084	$	(45,136	)	$	141,427

Balance at December 31, 2012	172,549,701	$	171,460	$	5,019	$	10,418	$	(53,937	)	$	132,960
Share-based payments	–		–		–		516		–			516
Loss for the period	–		–		–		–		(54,419	)		(54,419	)
Balance at June 30, 2013	172,549,701	$	171,460	$	5,019	$	10,934	$	(108,356	)	$	79,057

See accompanying notes to the condensed interim consolidated financial statements.

ANDERSON ENERGY LTD.

Consolidated Statements of Cash Flows

SIX MONTHS ENDED JUNE 30, 2013 AND 2012 (Stated in thousands of dollars) (Unaudited)			2013			2012

CASH PROVIDED BY (USED IN)
OPERATIONS
Loss for the period		$	(54,419	)	$	(22,692	)
Adjustments for:
	Unrealized (gain) loss on derivative contracts (note 9)		433			(3,003	)
	Loss on sale of property, plant and equipment (note 9)		43			3,999
	Depletion and depreciation		16,672			25,318
	Impairment loss (note 3)		–			20,000
	Share-based payments		385			430
	Accretion on decommissioning obligations (note 5)		382			637
	Accretion on convertible debentures		1,057			953
	Deferred income tax expense (benefit)		45,634			(7,420	)
Decommissioning expenditures (note 5)			(87	)		(365	)
Changes in non-cash working capital (note 11)			(976	)		(839	)
Net cash provided by operations			9,124			17,018
FINANCING
Increase in bank loans			5,798			31,004
Changes in non-cash working capital (note 11)			–			(175	)
Net cash provided by financing			5,798			30,829
INVESTING
Property, plant and equipment expenditures			(7,900	)		(23,075	)
Proceeds from sale of property, plant and equipment			52			6,199
Changes in non-cash working capital (note 11)			(7,075	)		(30,972	)
Net cash used in investing			(14,923	)		(47,848	)

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

Interest received in cash		$	2		$	29
Interest paid in cash		$	(4,938	)	$	(7,377	)

See accompanying notes to the condensed interim consolidated financial statements.

ANDERSON ENERGY LTD.

Notes to the Condensed Interim Consolidated Financial Statements

THREE AND SIX MONTHS ENDED JUNE 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.

It is Anderson’s current intention to not disclose developments with respect to its strategic alternatives process unless and until the Board of Directors has approved a specific transaction or otherwise determines that disclosure is necessary in accordance with applicable law. The Company cautions that there are no assurances or guarantees that the process will result in a transaction or, if a transaction is undertaken, the terms or timing of such a transaction or the impact it will have on the Company’s financial position. The Company has not set a definitive schedule to complete the evaluation.

These condensed interim consolidated financial statements have been prepared on a going concern basis which assumes that the Company will be able to realize its assets and discharge its liabilities in the normal course of business. If this assumption were not appropriate, adjustments to these condensed interim consolidated financial statements may be necessary. When assessing the Company’s ability to continue on a going concern basis, material uncertainties as to the outcome of the strategic alternative process and the terms at which the current bank debt facility may be renewed, may cast significant doubt on the Company’s ability to continue as a going concern. The successful future operations of the Company are dependent on the ability of the Company to secure sufficient funds through operations, bank financing or other sources from the strategic alternatives process, and there are no assurances that such funding will be available when needed.

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 August 13, 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. 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		7,050			15		7,065
Disposals		(95	)		–		(95	)
Balance at June 30, 2013	$	600,003		$	1,919	$	601,922

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		16,620			52		16,672
Balance at June 30, 2013	$	323,871		$	1,579	$	325,450

Carrying amounts

		Oil and natural gas assets		Other equipment		Total
At December 31, 2012	$	285,797	$	377	$	286,174
At June 30, 2013	$	276,132	$	340	$	276,472

Capitalized overhead.

For the six months ended June 30, 2013, additions to property, plant and equipment included internal overhead costs of $0.9 million (year ended December 31, 2012 – $3.4 million).

Impairment.

4. BANK LOANS

At June 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 have a maturity date of September 30, 2013 and, if the facility were not renewed, all outstanding advances would become repayable on that date. Accordingly, at June 30, 2013 and December 31, 2012, the bank loans were classified as a current liability. Under the agreement, advances can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’ acceptance or LIBOR loan rates plus applicable margins. These margins vary from 3% to 4%, depending on the borrowing option used. At June 30, 2013, no amounts were drawn in U.S. funds.

The average effective interest rate on advances under the facilities in 2013 was 5.5% (June 30, 2012 – 4.2%). The Company had $0.4 million in letters of credit outstanding at June 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.

The available lending limits of the facilities are scheduled to be reviewed on or before September 30, 2013 and are based on the bank syndicate’s interpretations of the Company’s reserves and future commodity prices. There can be no assurance that the amount or terms of the available facilities will not be adjusted at the next review.

5. DECOMMISSIONING OBLIGATIONS

			June 30, 2013			December 31, 2012
Balance at January 1		$	46,467		$	62,848
	Provisions incurred		278			1,187
	Decommissioning expenditures		(87	)		(506	)
	Provisions disposed		–			(20,865	)
	Change in estimates		(1,244	)		2,735
	Accretion expense		382			1,068
Ending balance		$	45,796		$	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 $45.8 million as at June 30, 2013 (December 31, 2012 – $46.5 million) based on an undiscounted inflation-adjusted total future liability of $55.5 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 June 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 1.0% to 2.5% (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.

6. UNRECOGNIZED DEFERRED TAX ASSET

7. 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 June 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. Options are granted using an exercise price of stock options equal to the weighted average trading price of the Company’s common shares for the five trading days prior to the date of the grant. Options have terms of either five or ten years and vest equally over a three year period starting on the first anniversary date of the grant. Changes in the number of options outstanding during the period ended June 30, 2013 and the year ended December 31, 2012 are as follows:

	June 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	(208,500	)		2.50	(4,273,582	)		3.22
Forfeited during the period	(84,000	)		0.72	(1,099,300	)		0.80
Ending balance	14,094,300		$	0.72	14,386,800		$	0.75

Exercisable, end of period	5,587,817		$	1.10	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	5,808,500	$	0.31	4.4
$0.47 to $0.70	2,706,300		0.70	3.2
$0.71 to $1.06	4,422,450		0.92	1.7
$1.07 to $1.60	534,100		1.19	2.5
$2.42 to $3.63	529,950		2.68	0.2
$3.64 to $4.00	93,000		4.00	0.9
Total at June 30, 2013	14,094,300	$	0.72	3.0

No options have been exercised in the six months ended June 30, 2013 (June 30, 2012 – nil).

No stock options were issued in the six months ended June 30, 2013 (June 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:

		June 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		1.3%
Forfeiture rate		15%

This estimated forfeiture rate is adjusted to the actual forfeiture rate when each tranche vests. Share-based compensation cost of $0.4 million (June 30, 2012 – $0.4 million) was expensed during the six months ended June 30, 2013. Share-based compensation cost of $0.2 million (June 30, 2012 – $0.2 million) was expensed during the three months ended June 30, 2013. In addition, share-based compensation expense of $0.1 million (June 30, 2012 – $0.3 million) was capitalized during the six months ended June 30, 2013. For the three months ended June 30, 2013, $nil of share-based compensation was capitalized (June 30, 2012 – $0.1 million).

8. LOSS PER SHARE

Basic and diluted loss per share were calculated as follows:

		Three months ended				Six months ended
		June 30, 2013		June 30, 2012		June 30, 2013		June 30, 2012
Loss for the period	$	(49,306)	$	(16,828)	$	(54,419)	$	(22,692)
Weighted average number of common shares (basic) (in thousands of shares)		172,550		172,550		172,550		172,550
Basic and diluted loss per share	$	(0.29)	$	(0.10)	$	(0.32)	$	(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 six months ended June 30, 2013, 14,094,300 options (June 30, 2012 – 11,519,300 options) and 59,316,889 common shares reserved for convertible debentures (June 30, 2012 – 59,316,889) were excluded from calculating diluted loss as they were anti-dilutive.

9. OTHER GAINS (LOSSES)

Other gains (losses) include the following:

		Three months ended						Six months ended
		June 30, 2013			June 30, 2012			June 30, 2013			June 30, 2012
Realized gain (loss) on derivative contracts	$	(661	)	$	1,305		$	(1,247	)	$	1,518
Unrealized gain (loss) on derivative contracts		638			4,692			(433	)		3,003
Loss on sale of property, plant and equipment		(37	)		(1,389	)		(43	)		(3,999	)
	$	(60	)	$	4,608		$	(1,723	)	$	522

10. FINANCE INCOME AND EXPENSES

			Three months ended						Six months ended
			June 30, 2013			June 30, 2012			June 30, 2013			June 30, 2012
Income:
	Other		1			8			2			24
Expenses:
	Interest and financing costs on bank loans		(804	)		(1,244	)		(1,572	)		(2,284	)
	Interest on convertible debentures		(1,772	)		(1,772	)		(3,543	)		(3,543	)
	Accretion on convertible debentures		(533	)		(480	)		(1,057	)		(953	)
	Accretion on decommissioning obligations		(194	)		(319	)		(382	)		(637	)
	Other		(5	)		(7	)		(28	)		(9	)
			(3,308	)		(3,822	)		(6,582	)		(7,426	)
Net finance expenses		$	(3,307	)	$	(3,814	)	$	(6,580	)	$	(7,402	)

11. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital is comprised of:

			June 30, 2013			June 30, 2012
Source (use) of cash
	Accounts receivable and accruals	$	1,698		$	2,509
	Prepaid expenses and deposits		679			893
	Accounts payable and accruals		(10,428	)		(35,388	)
		$	(8,051	)	$	(31,986	)
Related to operating activities		$	(976	)	$	(839	)
Related to financing activities		$	–		$	(175	)
Related to investing activities		$	(7,075	)	$	(30,972	)

12. 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 June 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 June 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⁾		$	17,679	$	–	$	–	$	–	$	–
Bank loans – principal ⁽²⁾			53,892		–		–		–		–
Convertible debentures
	– Interest ⁽¹⁾		5,523		7,085		7,085		3,335		–
	– Principal		–		–		50,000		46,000		–
Total		$	77,094	$	7,085	$	57,085	$	49,335	$	–

⁽¹⁾	Accounts payable and accruals includes $1.6 million of interest relating to convertible debentures. The total cash interest payable in less than one year on the convertible debentures is $7.1 million.
⁽²⁾	Assumes the credit facilities are not renewed on September 30, 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 June 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 July to December, 2013 at a NYMEX crude oil price of Canadian $90.63 per barrel, 300 barrels per day of crude oil with a remaining term of July to December, 2013 at a NYMEX crude oil price of Canadian $90.43 per barrel and 100 barrels per day of crude oil with a remaining term of July to September, 2013 at a NYMEX crude oil price of Canadian $90.40 per barrel.

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 June 30, 2013, the Company estimates that it would pay approximately $1.5 million to terminate these contracts (December 31, 2012 – $1.1 million).

The fair value of derivative contracts at June 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	$	156	$	(156	)

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 both 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 June 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 six months ended June 30, 2013, earnings would have been affected by approximately $0.3 million (June 30, 2012 – $0.4 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 $79.1 million, bank loans of $53.9 million, convertible debentures with a face value of $96.0 million and the cash working capital deficiency of $8.4 million, which excludes the current portion of unrealized losses on derivative contracts. In order to maintain or adjust the capital structure, the Company may from time to time issue shares, seek additional debt financing and adjust its capital spending to manage current and projected debt levels.

Consistent with other companies in the oil and gas sector, Anderson monitors capital based on the ratio of total debt to funds from operations. This ratio is calculated by dividing total debt at the end of the period (comprised of the cash working capital deficiency, the liability component of convertible debentures and outstanding bank loans) by either the annualized current quarter funds from operations or the twelve-month trailing funds from operations (cash flow from operating activities before changes in non-cash working capital and decommissioning expenditures). This ratio may increase at certain times as a result of acquisitions, the timing of capital expenditures and market conditions. In order to facilitate the management of this ratio, the Company prepares annual capital expenditure budgets, which are updated as necessary depending on varying factors including current and forecast crude oil and natural gas prices, capital deployment and general industry conditions. The annual and updated budgets are approved by the Board of Directors. Funds from operations in the quarter, annualized current quarter funds from operations, twelve-month trailing funds from operations and total net debt to funds from operations are not defined by IFRS and therefore are referred to as additional GAAP measures.

			June 30, 2013			December 31, 2012
Bank loans		$	53,892		$	48,094
Current liabilities⁽¹⁾			17,679			28,107
Current assets			(9,292	)		(11,670	)
Net debt before convertible debentures		$	62,279		$	64,531
Convertible debentures (liability component)			87,810			86,753
Total net debt		$	150,089		$	151,284

Cash from operating activities in the quarter		$	3,953		$	6,976
Decommissioning expenditures in the quarter			11			114
Changes in non-cash working capital in the quarter			737			(1,396	)
Funds from operations in the quarter		$	4,701		$	5,694
Annualized current quarter funds from operations		$	18,804		$	22,776
Twelve-month trailing funds from operations		$	21,606		$	29,641

Net debt before convertible debentures to funds from operations
	– Annualized current quarter funds from operations		3.3			2.8
	– Twelve-month trailing funds from operations		2.9			2.2
Total net debt to funds from operations
	– Annualized current quarter funds from operations		8.0			6.6
	– Twelve-month trailing funds from operations		6.9			5.1

⁽¹⁾

Excludes unrealized gains (losses) on derivative contracts.

There were no changes in the Company’s approach to capital management during the three months ended June 30, 2013. The high ratios reflect the capital expenditures required to make the transition from a gas-weighted company to an oil-weighted company.

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.

13. COMMITMENTS AND CONTINGENCIES

At June 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	$	448	$	826	$	696	$	115	$	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.

Corporate Information	Contact Information

Head Office	Anderson Energy Ltd.
2200, 333 – 7^th Avenue S.W.	Brian H. Dau
Calgary, Alberta	President & Chief Executive Officer
Canada T2P 2Z1	(403) 262-6307
Phone (403) 262-6307	info@andersonenergy.ca
Fax (403) 261-2792
Website www.andersonenergy.ca	Officers

Directors	J.C. Anderson
	Chairman of the Board
J.C. Anderson⁽⁴⁾
Calgary, Alberta	Brian H. Dau
	President & Chief Executive Officer
Brian H. Dau
Calgary, Alberta	David M. Spyker
	Chief Operating Officer
Christopher L. Fong ^(1)(2)(3)(4)
Calgary, Alberta	M. Darlene Wong
	Vice President, Finance, Chief Financial
Glenn D. Hockley ⁽¹⁾⁽³⁾	Officer & Corporate Secretary
Calgary, Alberta
	Blaine M. Chicoine
David J. Sandmeyer ^(2)(3)(4)	Vice President, Drilling and Completions
Calgary, Alberta
	Sandra M. Drinnan
David G. Scobie ^(1)(2)(4)	Vice President, Land
Calgary, Alberta
	Philip A. Harvey
Member of:	Vice President, Exploitation
(1) Audit Committee
(2) Compensation & Corporate Governance Committee	Jamie A. Marshall
(3) Reserves Committee	Vice President, Exploration
(4) Special Committee
	Patrick M. O’Rourke
Auditors	Vice President, Production
KPMG LLP
	Abbreviations used
Independent Engineers	AECO – intra-Alberta Nova inventory transfer price
GLJ Petroleum Consultants Ltd.	bbl – barrel
	bpd – barrels per day
Legal Counsel	Mstb – thousand stock tank barrels
Bennett Jones LLP	Mbbls – thousand barrels
	BOE – barrels of oil equivalent
Registrar & Transfer Agent	MBOE – thousand barrels of oil equivalent
Valiant Trust Company	BOED – barrels of oil equivalent per day
	BOPD – barrels of oil per day
Stock Exchange	Cdn – Canadian
The Toronto Stock Exchange	GJ – gigajoule
Symbol AXL, AXL.DB, AXL.DB.B	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
403-261-2792 (FAX)
www.andersonenergy.ca

Anderson Energy Announces 2013 Second Quarter Results

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