Anderson Energy Announces 2014 Second Quarter Results

August 13, 2014 4:09 PM

CALGARY, ALBERTA–(Marketwired – Aug. 13, 2014) – Anderson Energy Ltd. (“Anderson” or the “Company”) (TSX:AXL) announces its operating and financial results for the second quarter ended June 30, 2014.

HIGHLIGHTS

The average initial production rate over the first 30 days for the eight Cardium horizontal wells drilled in the current program was 511 BOED.
The Company made a significant Cardium liquids-rich gas discovery. Based on various industry publications, the two wells drilled into this pool were in the top 10 new producing Cardium gas wells in Alberta in April and May 2014.
Production in the second quarter of 2014 was 3,414 BOED (30% oil, condensate and NGL) compared to 2,958 BOED (39% oil, condensate and NGL) for the first quarter of 2014, a 15% increase over the first quarter BOED production.
Funds from operations were $5.5 million in the second quarter of 2014, unchanged compared to funds from operations of $5.5 million in the first quarter of 2014.
The operating netback was $28.88 per BOE in the second quarter of 2014 compared to $34.51 per BOE in the first quarter of 2014 and $12.35 per BOE in the fourth quarter of 2013 (adjusted for properties sold in the quarter).
Operating expenses were $13.22 per BOE in the second quarter of 2014 compared to $13.28 per BOE in the first quarter of 2014.
The Company’s 2014 annual production guidance remains unchanged at 3,200 BOED (36% oil, condensate and NGL). Exit production guidance for 2014 remains unchanged at 3,700 BOED (42% oil, condensate and NGL).
In the second quarter of 2014, the Company undertook an expansion of the 100% owned 05-14-039-05W5 Willesden Green gas plant where the plant capacity was doubled to 10 MMcfd with additional compression.
The Company has commenced its planned 14 well horizontal drilling program in the Willesden Green area, which is expected to be completed by spring breakup 2015.
Since the Company’s last report on May 13, 2014, the horizontal drilling inventory has increased 10% to 127 gross (81.3 net) Cardium, Glauconite and Belly River locations.

FINANCIAL AND OPERATING HIGHLIGHTS

			Three months ended June 30								Six months ended June 30
(thousands of dollars, unless otherwise stated)			2014			2013		% Change			2014			2013		% Change
Oil and gas sales (1)		$	14,641		$	15,616		(6	%)	$	29,163		$	32,479		(10	%)
Revenue, net of royalties (1)		$	13,510		$	14,345		(6	%)	$	26,705		$	29,613		(10	%)
Funds from operations (2)		$	5,458		$	4,701		16	%	$	10,996		$	10,187		8	%
Funds from operations per share (2)
	Basic and diluted	$	0.03		$	0.03		–		$	0.06		$	0.06		–
Adjusted earnings (loss) before taxes (3)		$	(993	)	$	(3,672	)	73	%	$	(449	)	$	(8,785	)	95	%
Adjusted earnings (loss) before taxes
	per share – basic and diluted(3)	$	(0.01	)	$	(0.02	)	50	%	$	–		$	(0.05	)	100	%
Earnings (loss)		$	(993	)	$	(49,306	)	98	%	$	(449	)	$	(54,419	)	99	%
Earnings (loss) per share
	Basic and diluted	$	(0.01	)	$	(0.29	)	97	%	$	–		$	(0.32	)	100	%
Capital expenditures (net of proceeds on dispositions)		$	3,806		$	186		1946	%	$	19,838		$	7,848		153	%
Bank loans and other working capital (deficiency) (2)										$	656		$	(62,279	)	101	%
Convertible debentures										$	90,093		$	87,810		3	%
Shareholders’ equity										$	27,976		$	79,057		(65	%)
Average shares outstanding (thousands):
	Basic and diluted		172,550			172,550		–			172,550			172,550		–
Ending shares outstanding (thousands)											172,550			172,550		–
Average daily sales volumes:
	Oil & condensate (bpd)		839			1,260		(33	%)		928			1,429		(35	%)
	NGL (bpd)		189			236		(20	%)		155			184		(16	%)
	Natural gas (Mcfd)		14,317			14,611		(2	%)		12,628			14,684		(14	%)
	Barrels of oil equivalent (BOED) (4)		3,414			3,931		(13	%)		3,188			4,060		(21	%)
Average prices:
	Oil & condensate ($/bbl)	$	103.56		$	89.70		15	%	$	100.32		$	87.23		15	%
	NGL ($/bbl)	$	40.94		$	38.59		6	%	$	46.70		$	40.33		16	%
	Natural gas ($/Mcf)	$	4.59		$	3.33		38	%	$	4.77		$	3.13		52	%
	Barrels of oil equivalent ($/BOE) (4)	$	47.13		$	43.66		8	%	$	50.55		$	44.19		14	%
Realized loss on derivative contracts ($/BOE)		$	(0.89	)	$	(1.85	)	52	%	$	(1.18	)	$	(1.70	)	31	%
Royalties ($/BOE)		$	3.64		$	3.55		3	%	$	4.26		$	3.90		9	%
Operating costs ($/BOE)		$	13.22		$	12.85		3	%	$	13.24		$	12.39		7	%
Transportation costs ($/BOE)		$	0.50		$	0.41		22	%	$	0.38		$	0.30		27	%
Operating netback ($/BOE) (3)		$	28.88		$	25.00		16	%	$	31.49		$	25.90		22	%

Wells drilled (gross)			1.0			–		100	%		5.0			2.0		150	%

(1)	Includes royalty and other income classified with oil and gas sales, but excludes realized and unrealized gains or losses on derivative contracts.
(2)	Funds from operations, funds from operations per share, working capital and working capital (deficiency) are considered additional GAAP measures. Refer to the section entitled “Additional GAAP Measures” in the Management’s Discussion and Analysis (“MD&A”) for a more complete description of these additional GAAP measures. Bank loans of $nil (June 30, 2013 – $53.9 million) were included in working capital as defined therein.
(3)	Adjusted earnings (loss) before taxes, adjusted earnings (loss) before taxes per share and operating netback per BOE are considered non-GAAP measures. Refer to the section entitled “Non-GAAP Measures” in the MD&A for a more complete description of these non-GAAP terms, reconciliations to more closely related GAAP measures, and the purposes for which management uses the non-GAAP measures. These non-GAAP measures may not be comparable with the calculation of similar measures for other entities.
(4)	Barrels of oil equivalent (“BOE”) may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

STRATEGY

Anderson’s focus area and prospects are located in Willesden Green, Buck Lake and West Pembina in west central Alberta. The Company’s efforts are dedicated to drilling horizontal wells in the Cardium, Glauconite and Belly River formations. Since completion of the strategic alternatives process in the fourth quarter of 2013, the Company has been growing production from these zones, with the goal of increasing the percentage of oil, condensate and NGL (collectively, “liquids”) production to over 50% of total production. In 2014, the Company estimates that liquids will make up approximately 36% of total production and 66% of total revenue. By the end of 2015, the Company estimates that 50% of total production and over 75% of total revenue will come from liquids. A strategy of increasing liquids production will increase annual cash flow per share faster than BOED production per share, due to the higher prices associated with these products. Over time, it will also increase the Company’s asset value and borrowing base.

Anderson prides itself on being one of the lowest capital cost operators in the Cardium horizontal play, with drilling and completion costs of $2.3 to $2.5 million per well. The Company uses this capital cost measure to compare itself to other operators as it is well understood in the industry. Equipping and tie-in costs will vary much more from area to area. Currently, the Company has identified 81 net locations in the Cardium, Glauconite and Belly River formations, representing more than five years of drilling inventory. The Company’s goal is to continue to add to these locations in order to maintain this five to six year drilling inventory.

The Company has a goal of achieving an average horizontal well payout of one year by continuing to improve upon the profitability of the entire operation. Anderson will focus on keeping capital costs low, controlling infrastructure to keep operating costs low, and using available technology to pursue good reservoir rock and improve frac effectiveness. The Company is currently using one drilling rig in its operations, drilling nine months of the year and using the same crews that it has used in recent years. In the current capital program, management estimates that five of the eight wells drilled to date will pay out in one year or less.

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

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

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

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

The Company has no plans to buy back common shares or convertible debentures with normal course issuer bids. The Company’s business plan is to invest in its asset base, grow its asset base, cash flow and reserves and increase its financial flexibility. At June 30, 2014, the Company had $9.9 million in cash. Its bank line has increased to $31 million and it currently has no bank loans outstanding. The 2014 capital budget of $46 million is being funded with cash, cash flow and available bank lines.

DRILLING PROGRAM UPDATE

Anderson completed a seven-well drilling program during the first quarter of 2014. Anderson drilled one additional well in the second quarter of 2014. Results from the eight wells drilled to date in the program are shown in table below:

Average Gross Initial Production for the first 30 days (IP 30)
Barrels of oil and condensate per day (bpd)	240
Barrels of oil, condensate and NGL per day (bpd)	272
Barrels of oil equivalent per day (BOED)	511

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

In the second quarter of 2014, two horizontal Cardium wells drilled in 2014 were reclassified by the Alberta Energy Regulator from “oil” to “gas” wells. Based on various industry publications, these two liquids-rich wells were in the top 10 new producing Cardium gas wells in Alberta in April and May 2014.

WILLESDEN GREEN 05-14 PLANT EXPANSION

In the second quarter, the Company undertook an expansion of the 100% owned 05-14-039-05W5 Willesden Green gas plant where the plant capacity was doubled to 10 MMcfd with additional compression. In the third quarter of 2014, the Company is completing the liquids handling portion of the expansion and upgrading the plant gathering system to accommodate production from new discoveries, new production from planned drilling and the restoration of third party gas processing at the facility.

HORIZONTAL DRILLING INVENTORY

The Company’s undeveloped horizontal drilling inventory at July 31, 2014, is outlined below:

Prospect Area (number of drilling locations)	Gross	Net*
Willesden Green Cardium	90	63.2
West Pembina/Buck Lake Cardium	26	7.8
Willesden Green Glauconite Belly River	9 2	9.0 1.3
Total Horizontal Drilling Inventory	127	81.3

* Net is net revenue interest

GLJ booked undeveloped reserves to 22.4 net locations as of April 30, 2014. GLJ’s booked locations are included in the drilling inventory table above.

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

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

COMMODITY PRICES

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

CRUDE OIL AND CONDENSATE PRICES

		Three months ended June 30				Six months ended June 30
		2014		2013		2014		2013
WTI – $US	$	102.98	$	94.25	$	100.81	$	94.29
WTI – $Cdn	$	112.29	$	96.45	$	110.57	$	95.81
Differential from Cushing to Edmonton – $US per bbl	$	6.11	$	3.64	$	7.23	$	5.27
Edmonton Par – $Cdn per bbl	$	105.65	$	93.10	$	102.86	$	90.72

Anderson average oil price per bbl	$	102.22	$	89.76	$	99.56	$	87.01

Anderson average oil and condensate price per bbl*	$	103.56	$	89.70	$	100.32	$	87.23

*Condensate includes field condensate and plant C5.

The 2014 monthly WTI Canadian oil prices were approximately $109.96 per bbl in July and $106.70 per bbl to date in August. Differentials from Cushing, Oklahoma to Edmonton were approximately $7.17 US per bbl in July and $8.54 US per bbl in August.

A comparison of Anderson’s average plant gate natural gas price to various market prices is presented below. Average plant gate prices are before the impact of any financial derivative or fixed price contracts used for risk management. The difference between the AECO price and Anderson’s plant gate price is due to transportation costs and the heat content of the gas. Financial derivative and fixed price contracts reduced the average price received for natural gas to $4.43 per Mcf in the second quarter of 2014.

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

NATURAL GAS PRICES

		Three months ended June 30				Six months ended June 30
		2014		2013		2014		2013
NYMEX US$ per MMBtu	$	4.58	$	4.01	$	4.65	$	3.75
AECO $CAD per GJ	$	4.44	$	3.35	$	4.90	$	3.19
AECO $CAD per MMBtu	$	4.69	$	3.53	$	5.17	$	3.37

Anderson average plant gate price per Mcf	$	4.72	$	3.33	$	5.00	$	3.13

AECO natural gas prices were approximately $3.90 per GJ ($4.11 per MMBtu) in July and $3.80 per GJ ($4.01 per MMBtu) month to date in August.

FINANCIAL RESULTS

Funds from operations were $5.5 million in the second quarter of 2014 compared to $5.5 million in the first quarter of 2014. On a BOE basis, oil and gas sales averaged $47.13 per BOE in the second quarter of 2014 compared to $54.54 per BOE in the first quarter of 2014. During the second quarter of 2014, liquids revenue (oil, condensate and NGLs) represented 59% of total oil and gas sales. The Company’s operating netback was $28.88 per BOE in the second quarter of 2014 compared to $34.51 per BOE in the first quarter of 2014. The decrease in operating netback was due to lower natural gas prices and a lower percentage of liquids volumes in the second quarter. Anderson’s operating netback for Cardium properties in the second quarter of 2014 was $44.74 per BOE, exclusive of hedging.

	Average natural gas price ($/Mcf)	Average oil & condensate price ($/bbl)	Revenue ($/BOE)	Operating netback ($/BOE)	Funds from operations ($/BOE)
Q1 2014	5.01	97.62	54.54	34.51	20.80
Q2 2014	4.59	103.56	47.13	28.88	17.57

Capital expenditures, net of dispositions, were $19.8 million for the six months ended June 30, 2014. Field capital expenditures were $3.0 million in the second quarter of 2014 compared to $14.5 million in the first quarter of 2014. Capital investments in the first and second quarters of 2014 were focused primarily on the drilling, completion, equipping and tie-in of Cardium horizontal wells. The Company completed $2.2 million in net property acquisitions related to Cardium and Glauconite prospects, and the sale of $1.0 million in shallow gas and undeveloped land in the first half of 2014.

HEDGING

Derivative contracts

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

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

Period	Weighted average volume (GJ/d)		Weighted average AECO price ($/GJ)
July 1, 2014 to December 31, 2014	2,500	$	3.55

Crude oil – derivative contract based on WTI Canadian oil price:

Period	Weighted average volume (bpd)		Weighted average WTI Cdn price ($/bbl)
July 1, 2014 to December 31, 2014	500	$	110.00

Fixed price contracts

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

SUMMARY

The Company has made considerable progress in the last few months by demonstrating production growth, reserves growth and reserves value growth. Anderson is now embarking on a significant high impact Cardium and Glauconite horizontal drilling program. The Company continues to rationalize and improve the profitability of its shallow gas assets and add to its horizontal drilling inventory with farm-ins and property acquisitions. The management and staff are very excited about the future oil production growth drilling program and the Company’s prospects in the Willesden Green Cardium and Glauconite plays.

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

Brian H. Dau

President & Chief Executive Officer

August 13, 2014

Management’s Discussion and Analysis

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2014 AND 2013

The following management’s discussion and analysis (“MD&A”) is dated August 13, 2014 and should be read in conjunction with the unaudited condensed interim consolidated financial statements of Anderson Energy Ltd. (“Anderson” or the “Company”) for the three and six months ended June 30, 2014 and the audited consolidated financial statements and MD&A of Anderson for the years ended December 31, 2013 and 2012.

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

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

REVIEW OF FINANCIAL RESULTS

Overview

The Company ended the second quarter of 2014 with no bank debt and working capital(1) of $0.7 million (including $9.9 million in cash).

For the three-month period ended June 30, 2014, the Company generated $5.5 million in funds from operations(2) and reported a loss of $1.0 million. The Company invested $3.8 million in capital expenditures, net of minor property dispositions.

For the six-month period ended June 30, 2014, the Company generated $11.0 million in funds from operations(2) and reported a loss of $0.4 million. The Company invested $19.8 million in capital expenditures, net of minor property dispositions.

The Company’s financial results continue to benefit from the higher commodity prices experienced during the first two quarters of 2014 relative to 2013, and the successful seven-well winter drilling program completed in the first quarter of 2014. One additional well was drilled during the second quarter of 2014.

The 2014 capital budget is $46 million and is being funded with cash, cash flow and available bank lines.

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

In 2014, the Company has combined the disclosure of field condensate and plant C5 (collectively, “condensate”) volumes and revenue with crude oil under the new heading “Oil and condensate”. NGL volumes and revenue now exclude condensate volumes and revenue. Prior periods have been restated to conform to this presentation.

(1) Working capital or working capital (deficiency) are considered additional GAAP measures. Refer to the section entitled “Additional GAAP Measures” at the end of this MD&A.

(2) Funds from operations are considered an additional GAAP measure. Refer to “Funds from Operations” in this section and the section entitled “Additional GAAP Measures” at the end of this MD&A.

SUMMARY OF PRODUCTION, PRICES, REVENUE AND FUNDS FROM OPERATIONS

Production

	Three months ended June 30		Six months ended June 30
	2014	2013	2014	2013
Oil and condensate (bpd)⁽¹⁾	839	1,260	928	1,429
NGL (bpd)	189	236	155	184
Natural gas (Mcfd)	14,317	14,611	12,628	14,684
Total (BOED)⁽⁶⁾	3,414	3,931	3,188	4,060

Prices

		Three months ended June 30				Six months ended June 30
		2014		2013		2014		2013
Oil and condensate ($/bbl)⁽¹⁾⁽²⁾	$	103.56	$	89.70	$	100.32	$	87.23
NGL ($/bbl)		40.94		38.59		46.70		40.33
Natural gas ($/Mcf)⁽²⁾⁽³⁾		4.59		3.33		4.77		3.13
Total ($/BOE)⁽⁴⁾⁽⁶⁾	$	47.13	$	43.66	$	50.55	$	44.19

Oil and gas sales

		Three months ended June 30				Six months ended June 30
(thousands of dollars)		2014		2013		2014		2013
Oil and condensate⁽¹⁾⁽²⁾	$	7,908	$	10,278	$	16,842	$	22,566
NGL		704		830		1,314		1,342
Natural gas⁽²⁾⁽³⁾		5,980		4,426		10,900		8,328
Royalty and other		49		82		107		243
Total oil and gas sales	$	14,641	$	15,616	$	29,163	$	32,479

Funds from operations

		Three months ended June 30					Six months ended June 30
(thousands of dollars)		2014			2013		2014		2013
Cash from operating activities	$	8,094		$	3,953	$	10,469	$	9,124
Changes in non-cash working capital		(2,639	)		737		343		976
Decommissioning expenditures		3			11		184		87
Funds from operations	$	5,458		$	4,701	$	10,996	$	10,187

Condensate includes field condensate and plant C5.
Excludes realized and unrealized gains and losses on derivative contracts.
Includes loss on fixed price natural gas contracts of $0.1 million for the three months ended June 30, 2014 (June 30, 2013 – $nil) and $0.5 million for the six months ended June 30, 2014 (June 30, 2013 – $nil).
Includes royalty and other income classified with oil and gas sales.
Funds from operations are considered an additional-GAAP measure Refer to the section entitled “Additional GAAP Measures” at the end of this MD&A.
Barrels of oil equivalent (“BOE”) may be misleading, particularly if used in isolation. Refer to the section entitled “Conversion Measures” at the end of this MD&A.

Production

Average production volumes in the second quarter of 2014 were 3,414 BOED compared to 2,958 BOED in the first quarter of 2014 and 3,931 BOED in the second quarter in 2013. For the six-month period ended June 30, 2014, the average production volumes were 3,188 BOED compared to 4,060 BOED in the same period of 2013. The decrease in volume for the first half of 2014 relative to the first half of 2013 reflects the impact of property dispositions completed in the last half of 2013 and first half of 2014, which represented approximately 1,315 BOED of production at the time of the dispositions. That impact was partially offset by the new production from the last eight wells drilled.

Overall, production volumes in the second quarter were 13% lower than the second quarter of 2013, but were 15% higher than volumes reported in the first quarter of 2014.

The Company’s 2014 annual production guidance remains unchanged at approximately 3,200 BOED (36% oil, condensate and NGL), and 2014 exit production guidance remains unchanged at approximately 3,700 BOED (42% oil, condensate and NGL).

Prices

World and North American benchmark prices for oil remain volatile. Differentials between WTI oil prices and prices received in Alberta are also volatile due to factors including refining demand and pipeline capacity. Anderson sells its oil at monthly average Edmonton Par prices less quality differentials, transportation and marketing fees. Light, sweet oil differentials between Cushing, Oklahoma and Edmonton, Alberta are affected by transportation and market factors. Differentials in the second quarter of 2014 averaged $6.11 US discount per bbl (2013 – $3.64 US per bbl).

Natural gas prices improved significantly in the first few months of 2014 due to higher demand related to colder weather conditions in North America, but longer term markets have not seen the same increase. In the second quarter of 2014, AECO 5A prices averaged approximately $4.44 Cdn per GJ, down from the first quarter of 2014 average of $5.36 Cdn per GJ. Forward strip prices for AECO are approximately $3.70 Cdn per GJ for 2015 and 2016.

The Company’s average natural gas sales price was $4.59 per Mcf for the three months ended June 30, 2014, 8% lower than the first quarter of 2014 price of $5.01 per Mcf and 38% higher than the second quarter of 2013 price of $3.33 per Mcf. This price includes the effect of the physical fixed price contracts discussed below. The average price before the effect of these contracts was $4.72 per Mcf. The average price after the effect of both the physical fixed price contracts and the derivative contracts discussed below was $4.43 per Mcf.

Derivative contracts

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

Period	Weighted average volume (GJ/d)		Weighted average AECO price ($/GJ)
July 1, 2014 to December 31, 2014	2,500	$	3.55

By comparison, AECO 5A averaged $4.44 Cdn per GJ in the second quarter of 2014 and approximately $3.90 Cdn per GJ in July 2014.

At June 30, 2014, the following derivative contract was outstanding for crude oil and recorded at estimated fair value:

Period	Weighted average volume (bpd)		Weighted average WTI Cdn price ($/bbl)
July 1, 2014 to December 31, 2014	500	$	110.00

By comparison, WTI Canadian averaged approximately $112.29 per bbl in the second quarter of 2014 and approximately $109.96 in July 2014.

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

						Three months ended June 30
(thousands of dollars)		Crude oil			Natural gas			2014 Total			2013 Total
Realized loss on derivative contracts	$	(72	)	$	(203	)	$	(275	)	$	(661	)
Unrealized gain (loss) on derivative contracts		(36	)		277			241			638
	$	(108	)	$	74		$	(34	)	$	(23	)

						Six months ended June 30
(thousands of dollars)		Crude oil			Natural gas			2014 Total			2013 Total
Realized loss on derivative contracts	$	(72	)	$	(610	)	$	(682	)	$	(1,247	)
Unrealized loss on derivative contracts		(36	)		(187	)		(223	)		(433	)
	$	(108	)	$	(797	)	$	(905	)	$	(1,680	)

Fixed price contracts

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

Royalties

For the second quarter of 2014, the average rate for royalties was 7.6% of revenue compared to 8.9% of revenue in the first quarter of 2014 and 8.1% of revenue in the second quarter of 2013. Horizontal 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 for oil wells (18 months for gas wells), after which Crown royalties are expected to increase from current levels. Other royalties are lower than in the prior year due to the sale of properties subject to freehold royalties in the fourth quarter of 2013.

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

		Three months ended June 30						Six months ended June 30
		2014			2013			2014		2013
Gross Crown royalties		6.1%			5.3%			6.5%		5.3%
Gas cost allowance		(1.4%	)		(3.3%	)		(1.7%	)	(2.3%	)
Other royalties		2.9%			6.1%			3.5%		5.8%
Total royalties		7.6%			8.1%			8.3%		8.8%
Total royalties ($/BOE)	$	3.64		$	3.55		$	4.26	$	3.90

Operating expenses

Operating expenses were $4.1 million ($13.22 per BOE) in the second quarter of 2014 compared to $3.5 million ($13.28 per BOE) in the first quarter of 2014 and $4.6 million ($12.85 per BOE) in the second quarter of 2013. For the six months ended June 30, 2014, operating expenses were $7.6 million ($13.24 per BOE) compared to $9.1 million ($12.39 per BOE) in the first half of 2013.

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

Transportation expenses

For the second quarter of 2014, transportation expenses were $0.2 million ($0.50 per BOE) compared to $0.23 per BOE in the first quarter of 2014 and $0.41 per BOE in the second quarter of 2013. For the six months ended June 30, 2014, transportation expenses were $0.2 million ($0.38 per BOE) compared to $0.2 million ($0.30 per BOE) in the first half of 2013. The increase in transportation expenses in the second quarter of 2014 compared to the second quarter of 2013 was due to the cost of trucking clean oil from the recently-drilled oil wells to the point of sale.

OPERATING NETBACK

			Three months ended June 30						Six months ended June 30
(thousands of dollars)			2014			2013			2014			2013
Revenue^(1)(2)(3)		$	14,641		$	15,616		$	29,163		$	32,479
Realized loss on derivative contracts			(275	)		(661	)		(682	)		(1,247	)
Royalties			(1,131	)		(1,271	)		(2,458	)		(2,866	)
Operating expenses			(4,106	)		(4,597	)		(7,642	)		(9,100	)
Transportation expenses			(156	)		(146	)		(218	)		(223	)
Operating netback⁽⁴⁾		$	8,973		$	8,941		$	18,163		$	19,043
Sales volume (MBOE)⁽⁵⁾			310.6			357.7			576.9			734.9
Per BOE⁽⁵⁾
	Revenue^(1)(2)(3)	$	47.13		$	43.66		$	50.55		$	44.19
	Realized loss on derivative contracts		(0.89	)		(1.85	)		(1.18	)		(1.70	)
	Royalties		(3.64	)		(3.55	)		(4.26	)		(3.90	)
	Operating expenses		(13.22	)		(12.85	)		(13.24	)		(12.39	)
	Transportation expenses		(0.50	)		(0.41	)		(0.38	)		(0.30	)
	Operating netback⁽⁴⁾	$	28.88		$	25.00		$	31.49		$	25.90

Excludes realized and unrealized gains and losses on derivative contracts.
Includes loss on fixed price natural gas contracts of $0.1 million for the three months ended June 30, 2014 (June 30, 2013 – $nil). The six months ended June 30, 2013 excludes loss on fixed price natural gas contracts of $0.5 million (June 30, 2013 -$nil)
Includes royalty and other income classified with oil and gas sales.
Operating netback is considered a non-GAAP measure. Refer to the section entitled “Non-GAAP Measures” at the end of this MD&A.
Barrels of oil equivalent (“BOE”) may be misleading, particularly if used in isolation. Refer to the section entitled “Conversion Measures” at the end of this MD&A.

Depletion and depreciation

Depletion and depreciation was $6.5 million ($20.91 per BOE) in the second quarter of 2014 compared to $5.7 million ($21.23 per BOE) in the first quarter of 2014 and $8.1 million ($22.53 per BOE) in the second quarter of 2013. For the six months ended June 30, 2014, depletion and depreciation was $12.2 million ($21.06 per BOE) compared to $16.7 million ($22.68 per BOE) in the first half of 2013. The decrease in the amount of depletion and depreciation in 2014 compared to 2013 was primarily due to the asset sales in the fourth quarter of 2013 and lower overall production volumes. Proved plus probable reserves volumes are included in the determination of depletion expense.

Impairment losses

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

General and administrative expenses

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

G&A (cash) expenses were $1.7 million ($5.51 per BOE) in the second quarter of 2014 compared to $1.9 million ($6.98 per BOE) for the first quarter of 2014 and $1.7 million ($4.64 per BOE) for the second quarter of 2013. For the six months ended June 30, 2014, G&A (cash) expenses were $3.6 million ($6.19 per BOE) compared to $3.7 million ($5.06 per BOE) in the first half of 2013.

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

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

		Three months ended June 30						Six months ended June 30
(thousands of dollars)		2014			2013			2014			2013
Gross G&A (cash) expenses	$	2,269		$	2,249		$	4,728		$	5,013
Overhead recoveries		(175	)		(278	)		(320	)		(519	)
Capitalized		(384	)		(311	)		(839	)		(779	)
Net G&A (cash) expenses⁽¹⁾	$	1,710		$	1,660		$	3,569		$	3,715
Net share-based payments		93			188			175			385
General and administrative expenses	$	1,803		$	1,848		$	3,744		$	4,100
G&A (cash) expenses ($/BOE)⁽¹⁾	$	5.51		$	4.64		$	6.19		$	5.06
% Capitalized		17%			14%			18%			16%

General and administrative (cash) expenses is considered a non-GAAP measure. Refer to the section entitled “Non-GAAP Measures” at the end of this MD&A.

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

Share-based payments

Share-based payments expense was $0.1 million ($0.1 million net of amounts capitalized) for the second quarter of 2014 and $0.1 million ($0.1 million net of amounts capitalized) for the first quarter of 2014 versus $0.2 million ($0.2 million net of amounts capitalized) in the second quarter of 2013. For the six months ended June 30, 2014, share-based payments expense was $0.2 million ($0.2 million net of amounts capitalized) compared to $0.5 million ($0.4 million net of amounts capitalized) in the first half of 2013.

Finance expenses

Finance expenses were $2.6 million for the second quarter of 2014, compared to $2.6 million for the first quarter of 2014 and $3.3 million in the second quarter of 2013. For the six months ended June 30, 2014, finance expenses were $5.2 million compared to $6.6 million in the first half of 2013.

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

		Three months ended June 30				Six months ended June 30
(thousands of dollars)		2014		2013		2014		2013
Interest and accretion on convertible debentures	$	2,348	$	2,305	$	4,714	$	4,600
Interest expense on credit facilities and other		65		809		146		1,600
Accretion on decommissioning obligations		184		194		376		382
Finance expenses	$	2,597	$	3,308	$	5,236	$	6,582

Decommissioning obligations

The decommissioning liability at June 30, 2014 of $28.4 million was lower than at December 31, 2013 largely due to the disposition of certain natural gas and other minor properties in 2014.

For the six months ended June 30, 2014, decommissioning obligations decreased by a net $2.0 million (2013 – $0.7 million). Approximately $0.4 million (2013 – $0.3 million) incurred on development activities and $0.4 million of accretion expense (2013 – $0.4 million) increased the decommissioning obligation, whereas actual expenditures of $0.2 million (2013 – $0.1 million) and property dispositions of $3.5 million (2013 – $nil) reduced the decommissioning obligation. A net change in estimates of $0.8 million increased the obligation (2013 – $1.2 million decrease).

Changes in estimates were primarily due to discount rate variation at June 30, 2014 compared to December 31, 2013, in addition to other abandonment liability revisions. The risk-free discount rates used by the Company to measure the obligations at June 30, 2014 were between 1.0% and 3.1% (December 31, 2013 – 1.1% to 3.2%) depending on the timelines to reclamation and changed from the start of the year as a result of changes in the Canadian bond market.

Income taxes

The Company has recognized a deferred tax asset in the amount of $2.0 million as at June 30, 2014 and December 31, 2013. No additional deferred tax assets were recognized during the first six months of 2014. The Company has approximately $364 million of tax pools at June 30, 2014.

Funds from operations

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

Funds from operations were $5.5 million in the second quarter of 2014, compared to $5.5 million in the first quarter of 2014 and $4.7 million in the second quarter of 2013. For the six months ended June 30, 2014, funds from operations were $11.0 million compared to $10.2 million in 2013. Higher commodity prices, improved operating netbacks and lower financing costs more than offset the lower production from the 2013 property sales.

Earnings (loss)

The Company reported a loss of $1.0 million in the second quarter of 2014 compared to earnings of $0.5 million in the first quarter of 2014 and a loss of $49.3 million for the second quarter of 2013. For the six months ended June 30, 2014, the loss was $0.4 million compared to a loss of $54.4 million in the first half of 2013.

A gain on sale of property, plant and equipment of $0.7 million was recorded in the second quarter of 2014, compared to $2.0 million in the first quarter of 2014 and a negligible loss in the second quarter of 2013. For the six months ended June 30, 2014, the gain on sale of property, plant and equipment was $2.7 million. The loss in the three and six month periods ended June 30, 2013 included tax expense related to derecognizing a deferred asset of $45.6 million.

CAPITAL EXPENDITURES

The Company invested $3.8 million in capital expenditures, net of minor property dispositions, in the second quarter of 2014 ($19.8 million in the first six months of 2014). The breakdown of expenditures is shown below:

		Three months ended June 30					Six months ended June 30
(thousands of dollars)		2014		2013			2014		2013
Land, geological and geophysical costs	$	99	$	25		$	136	$	72
Acquisitions		1,111		–			2,192		–
Drilling, completion and recompletion		1,666		(287	)		12,636		5,037
Facilities and well equipment		1,383		273			4,911		2,103
Capitalized G&A		384		311			839		779
	$	4,643	$	322		$	20,714	$	7,991
Change in compressor and other equipment inventory		–		(92	)		–		(106	)
Office equipment and furniture		125		8			136		15
Proceeds on disposition		(962)		(52	)		(1,012	)	(52	)
Total net capital expenditures	$	3,806	$	186		$	19,838	$	7,848

In the second quarter, the Company drilled one gross (1.0 net) Cardium horizontal well and commenced the expansion of the 100% owned 05-14-039-05W5 Willesden Green gas plant. The Company also completed $1.1 million in net property acquisitions related to Cardium and Glauconite prospects and $1.0 million in dispositions of shallow gas and undeveloped lands.

Drilling statistics are shown below:

	Three months ended June 30				Six months ended June 30
	2014		2013		2014		2013
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Oil	–	–	–	–	3	3.0	2	1.8
Gas	1	1.0	–	–	2	2.0	–	–
Dry	–	–	–	–	–	–	–	–
Total	1	1.0	–	–	5	5.0	2	1.8
Success rate	100%	100%	–	–	100%	100%	100%	100%

The Company completed its winter drilling program with an additional 5 gross (5.0 net capital, 5.0 net revenue) wells drilled during the first six months of 2014. In the second quarter of 2014, two horizontal Cardium wells drilled in 2014 were reclassified by the Alberta Energy Regulator from “oil” to “gas” wells. The liquids produced by the two wells are considered to be condensate rather than oil due to the lighter density.

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, 2014, there were 172.5 million common shares outstanding, 15.2 million stock options outstanding, $50.0 million principal amount of convertible debentures which are convertible into common shares at a conversion price of $1.55 per common share and $46.0 million principal amount of convertible debentures which are convertible into common shares at a conversion price of $1.70 per common share. During the second quarter of 2013 and 2014, no common shares were issued through the exercise of employee stock options.

SHARE PRICE ON TSX

		Three months ended June 30				Six months ended June 30
		2014		2013		2014		2013
High	$	0.29	$	0.22	$	0.29	$	0.25
Low	$	0.20	$	0.13	$	0.13	$	0.13
Close	$	0.24	$	0.14	$	0.24	$	0.14
Volume		10,600,712		4,932,747		30,579,263		11,293,181
Shares outstanding at June 30		172,549,701		172,549,701		172,549,701		172,549,701
Market capitalization at June 30	$	40,549,180	$	24,156,958	$	40,549,180	$	24,156,958

The statistics above include trading on the Toronto Stock Exchange only. Shares also trade on alternative platforms like Alpha, Chi-X, CX2, Pure, Omega and TMX Select. During the three months and six months ended June 30, 2014, approximately 4.2 million and 16.7 million common shares traded on these alternative exchanges respectively. Including these exchanges, an average of 235,592 common shares traded per day in the three months ended June 30, 2014 (June 30, 2013 – 108,663), representing a quarterly turnover ratio of 9% (June 30, 2013 – 4%).

LIQUIDITY AND CAPITAL RESOURCES

At June 30, 2014, the Company had no outstanding bank loans, convertible debentures of $96.0 million (principal) and a working capital surplus of $0.7 million (including $9.9 million in cash). The following table shows the changes in bank loans plus working capital (deficiency):

		Three months ended June 30						Six months ended June 30
(thousands of dollars)		2014			2013			2014			2013
Bank loans plus working capital (deficiency), beginning of period	$	(993	)	$	(66,783	)	$	9,682		$	(64,531	)
Funds from operations		5,458			4,701			10,996			10,187
Net cash capital expenditures		(3,806	)		(186	)		(19,838	)		(7,848	)
Decommissioning expenditures		(3	)		(11	)		(184	)		(87	)
Bank loans plus working capital (deficiency), end of period	$	656		$	(62,279	)	$	656		$	(62,279	)

Bank loans, end of period	$	–		$	(53,892	)	$	–		$	(53,892	)
Working capital (deficiency), end of period		656			(8,387	)		656			(8,387	)
Bank loans plus working capital (deficiency), end of period	$	656		$	(62,279	)	$	656		$	(62,279	)

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

At June 30, 2014, the Company had a $31 million extendible committed term bank facility with a Canadian bank under which $30.9 million of credit was available with $0.1 million in letters of credit outstanding that reduce the amount of available credit. If this revolving operating loan facility is not extended at its term date of May 30, 2015, any outstanding advances would become repayable one year later on May 30, 2016.

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

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

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

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

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

OFF-BALANCE SHEET ARRANGEMENTS

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

CONTRACTUAL OBLIGATIONS

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

Cardium Horizontal Well Program – At June 30, 2014, the Company has an obligation under a farm-in agreement to drill one Cardium horizontal well prior to October 31, 2014 to earn a working interest in the farm-out lands. The minimum capital commitment associated with the well is $2.5 million. The Company also has an obligation under a separate farm-in agreement to spud an additional two gross (1.0 net) Cardium horizontal wells prior to December 31, 2014.
Office Lease – In the second quarter of 2014, the Company entered into an agreement to lease office space at a cost of approximately $0.4 million per year from July 1, 2014 to October 30, 2018.

CRITICAL ACCOUNTING ESTIMATES

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

NEW AND PENDING ACCOUNTING STANDARDS

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

IFRS 9 Financial Instruments. In November 2009, the IASB issued IFRS 9 Financial Instruments (“IFRS 9 (2009)”), and in October 2010, the IASB published amendments to IFRS 9 (“IFRS 9 (2010)”). In November 2013, the IASB issued a new general hedge accounting standard, which forms part of IFRS 9 Financial Instruments (“IFRS 9 (2013)”).

IFRS 9 (2013) includes a new general hedge accounting standard which will align hedge accounting more closely with risk management. This new standard does not fundamentally change the types of hedging relationships or the requirement to measure and recognize ineffectiveness; however, it will provide more hedging strategies that are used for risk management to qualify for hedge accounting and introduce more judgment to assess the effectiveness of a hedging relationship.

The amendments to IFRS 9 are applied retrospectively for annual periods beginning on or after January 1, 2018, with early adoption allowed. The Company is currently assessing the effect on its financial statements.

CHANGES IN ACCOUNTING POLICIES

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

Offsetting Financial Assets and Financial Liabilities (Amendments to IAS 32 Financial Instruments: Presentation (“IAS 32”). The amendments to IAS 32 clarify the requirements for offsetting financial instruments such as the accounts receivable and payable related to the Company’s commodity contracts. The amendments clarify when an entity has a legally enforceable right to offset and certain other requirements that are necessary to present a net financial asset or liability.
Levies (“IFRIC 21”). In May 2013, the International Accounting Standards Board (“IASB”) issued IFRIC 21 Levies which was developed by the IFRS Interpretations Committee (“IFRIC”). IFRIC 21 clarifies that an entity recognizes a liability for a levy when the activity that triggers payment, as identified by the relevant legislation, occurs. The interpretation also clarifies that no liability should be recognized before the specified minimum threshold to trigger that levy is reached.

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, 2014 and ending on June 30, 2014 that has materially affected, or is reasonably likely to materially affect, the Company’s ICOFR. No changes in ICOFR were identified during such period that have materially affected or are reasonably likely to materially affect the Company’s ICOFR.

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

BUSINESS RISKS

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

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

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

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

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

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

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

STRATEGY

2014 CAPITAL BUDGET

The Board of Directors has approved a 2014 capital budget of $46 million. Sixty-eight percent of the budget is directed at drilling and completion expenditures to drill 12 net Cardium and Glauconite horizontal drilling prospects. Twenty-four percent of the expenditures are directed at equipping, tie-in and facility expenditures and the remaining funds are directed at land, abandonments and capitalized G&A expenditures.

With this capital program, the annual production guidance for 2014 is approximately 3,200 BOED (36% oil, condensate and NGL). The Company estimates 2014 exit production to be approximately 3,700 BOED (42% oil, condensate and NGL).

The Company is planning to drill 14 gross (11.6 net) Cardium and Glauconite horizontal wells from the third quarter of 2014 to spring breakup 2015. The Company continues to evaluate farm-in and property acquisitions in its Cardium and Glauconite focus areas. Should the Company add additional farm-in commitments, it will substitute those commitments into its 2014 capital program and defer budgeted locations until 2015.

QUARTERLY INFORMATION

The following table provides financial and operating results for the last eight quarters. Commodity prices remained volatile, affecting funds from operations and earnings throughout those quarters. The Company curtailed its drilling program in 2012, drilling a modest number of wells in recent quarters.

The impact of the sale of properties in 2012 and in the last quarter of 2013, as well as natural production declines, contributed to lower production volumes and revenues in 2012 and 2013. Production improved significantly in the first two quarters of 2014 relative to the last quarter of 2013 due to the Cardium horizontal well winter drilling program that commenced in the last quarter of 2013 and was completed in the second quarter of 2014.

Earnings in the second quarter of 2013 were affected by the tax expense related to derecognizing a deferred tax asset. Earnings in the third quarter of 2013 were impacted by the impairment on the assets held for sale.

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

SELECTED QUARTERLY INFORMATION

($ amounts in thousands, except per share amounts and prices)			Q2 2014			Q1 2014			Q4 2013			Q3 2013
Revenue, net of royalties		$	13,510		$	13,195		$	7,288		$	11,949
Funds from operations⁽¹⁾		$	5,458		$	5,538		$	(306	)	$	1,408
Funds from operations per share, basic and diluted⁽¹⁾		$	0.03		$	0.03		$	–		$	0.01
Adjusted earnings (loss) before taxes⁽²⁾		$	(993	)	$	544		$	(2,745	)	$	(5,856	)
Adjusted earnings (loss) before taxes per share, basic and diluted⁽²⁾		$	(0.01	)	$	–		$	(0.02	)	$	(0.03	)
Earnings (loss)		$	(993	)	$	544		$	(2,445	)	$	(48,737	)
Earnings (loss) per share, basic and diluted		$	(0.01	)	$	–		$	(0.01	)	$	(0.28	)
Capital expenditures (net of proceeds on dispositions)		$	3,806		$	16,032		$	(71,972	)	$	229
Cash from operating activities		$	8,094		$	2,375		$	(230	)	$	1,626
Bank loans		$	–		$	–		$	–		$	53,945
Daily sales
	Oil and condensate (bpd)		839			1,017			619			1,061
	NGL (bpd)		189			122			84			202
	Natural gas (Mcfd)		14,317			10,920			10,467			13,119
	BOE (BOED)		3,414			2,958			2,448			3,449
Average prices
	Oil and condensate ($/bbl)⁽⁴⁾	$	103.56		$	97.62		$	83.28		$	100.14
	NGL ($/bbl)	$	40.94		$	55.74		$	46.45		$	38.14
	Natural gas ($/Mcf)⁽⁴⁾	$	4.59		$	5.01		$	3.19		$	2.27
	BOE ($/BOE)⁽³⁾⁽⁴⁾	$	47.13		$	54.54		$	36.49		$	41.87

			Q2 2013			Q1 2013			Q4 2012			Q3 2012
Revenue, net of royalties		$	14,345		$	15,268		$	13,796		$	15,284
Funds from operations⁽¹⁾		$	4,701		$	5,486		$	5,694		$	5,725
Funds from operations per share, basic and diluted⁽¹⁾		$	0.03		$	0.03		$	0.03		$	0.03
Adjusted earnings (loss) before taxes⁽²⁾		$	(3,672	)	$	(5,113	)	$	(11,799	)	$	173
Adjusted earnings (loss) before taxes per share, basic and diluted⁽²⁾		$	(0.02	)	$	(0.03	)	$	(0.07	)	$	–
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		$	53,892		$	55,141		$	48,094		$	88,922
Daily sales
	Oil and condensate (bpd)		1,260			1,601			1,286			1,453
	NGL (bpd)		236			131			187			397
	Natural gas (Mcfd)		14,611			14,759			18,159			23,519
	BOE (BOED)		3,931			4,191			4,500			5,770
Average prices
	Oil and condensate ($/bbl)⁽⁴⁾	$	89.70		$	85.28		$	79.62		$	81.83
	NGL ($/bbl)	$	38.59		$	43.51		$	30.29		$	33.57
	Natural gas ($/Mcf)	$	3.33		$	2.94		$	3.16		$	2.24
	BOE ($/BOE)⁽³⁾⁽⁴⁾	$	43.66		$	44.70		$	36.89		$	32.05

Funds from operations and funds from operations per share do not have standardized meanings prescribed by GAAP. Refer to the section entitled “Additional GAAP Measures” at the end of this MD&A.
Adjusted earnings (loss) before taxes, adjusted earnings (loss) before taxes per share and operating netback per BOE are considered non-GAAP measures. Refer to the section entitled “Non-GAAP Measures” at the end of this MD&A.
Includes royalty and other income classified with oil and gas sales.
Excludes realized and unrealized hedging gains (losses) on derivative contracts.

CONVERSION MEASURES

Production volumes and reserves are commonly expressed on a BOE basis whereby natural gas volumes are converted at the ratio of 6 thousand cubic feet to 1 barrel of oil. Although the intention is to sum oil and natural gas measurement units into one basis for improved analysis of results and comparisons with other industry participants, BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf to 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In recent years, the value ratio based on the price of crude oil as compared to natural gas has been significantly higher than the energy equivalency of 6:1, and utilizing a conversion of natural gas volumes on a 6:1 basis may be misleading as an indication of value.

NON-GAAP MEASURES

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

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

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

ADDITIONAL GAAP MEASURES

Funds from operations

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

Other additional GAAP measures

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

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

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

FORWARD-LOOKING STATEMENTS

Certain statements in this news release including, without limitation, management’s assessment of future plans and operations; benefits and valuation of the development prospects described herein; number of locations in drilling inventory and wells to be drilled; timing and location of drilling and tie-in of wells and the costs thereof; productive capacity of the wells; timing and construction of facilities; expected production rates; improved production from slick water fracture technology; percentage of production from oil and natural gas liquids; dates of commencement of production; amount of capital expenditures and the timing and method of financing thereof; value of undeveloped land; extent of reserves additions; ability to attain cost savings; drilling program success; impact of changes in commodity prices on operating results; expectations related to future operating netbacks; programs to optimize, rationalize, consolidate and improve profitability of assets; factors on which the continued development of the Company’s oil and gas assets are dependent; commodity price outlook; and general economic outlook may constitute “forward-looking information” within the meaning of applicable securities laws and necessarily involve risks and assumptions made by management of the Company including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation; loss of markets; volatility of commodity prices; currency fluctuations; imprecision of reserves estimates; environmental risks; competition from other producers; inability to retain drilling rigs and other services; adequate weather to conduct operations;
sufficiency of budgeted capital, operating and other costs to carry out planned activities; wells not performing as expected; incorrect assessment of the value of acquisitions and farm-ins; failure to realize the anticipated benefits of acquisitions and farm-ins; inability to complete property dispositions or to complete them at anticipated values; delays resulting from or inability to obtain required regulatory approvals; changes to government regulation; ability to access sufficient capital from internal and external sources; and other factors, many of which are beyond the Company’s control. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as the factors are interdependent, and management’s future course of action would depend on its assessment of all information at the time. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements and readers should not place undue reliance on the assumptions and forward-looking statements. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect Anderson’s operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) or at Anderson’s website (www.andersonenergy.ca).

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

ANDERSON ENERGY LTD.
Consolidated Statements of Financial Position

(Stated in thousands of dollars)(Unaudited)			June 30, 2014			December 31, 2013

ASSETS
Current assets:
	Cash and cash equivalents	$	9,878		$	25,111
	Accounts receivables and accruals		7,403			6,702
	Prepaid expenses and deposits		860			1,286
Total current assets			18,141			33,099
Deferred tax asset			2,000			2,000
Property, plant and equipment (note 3)			144,188			135,978
Total assets		$	164,329		$	171,077

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
	Accounts payable and accruals	$	17,485		$	23,417
	Unrealized loss on derivative contracts (note 11)		369			146
Total current liabilities			17,854			23,563
Convertible debentures			90,093			88,922
Decommissioning obligations (note 5)			28,406			30,413
Total liabilities			136,353			142,898
Shareholders’ equity:
	Share capital (note 6)		171,460			171,460
	Equity component of convertible debentures		5,019			5,019
	Contributed surplus		11,484			11,238
	Deficit		(159,987	)		(159,538	)
Total shareholders’ equity			27,976			28,179
Commitments and contingencies (note 12)
Total liabilities and shareholders’ equity		$	164,329		$	171,077

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
		2014			2013			2014			2013

Oil and gas sales	$	14,641		$	15,616		$	29,163		$	32,479
Royalties		(1,131	)		(1,271	)		(2,458	)		(2,866	)
Revenue, net of royalties		13,510			14,345			26,705			29,613
Other losses (note 8)		(34	)		(23	)		(905	)		(1,680	)
Total revenue, net of royalties and other losses		13,476			14,322			25,800			27,933

Operating expenses		4,106			4,597			7,642			9,100
Transportation expenses		156			146			218			223
Depletion and depreciation (note 3)		6,497			8,059			12,150			16,672
(Gain) loss on sale of property, plant and equipment (note 3)		(658	)		37			(2,650	)		43
General and administrative expenses		1,803			1,848			3,744			4,100
Earnings (loss) from operating activities		1,572			(365	)		4,696			(2,205	)

Finance income (note 9)		32			1			91			2
Finance expenses (note 9)		(2,597	)		(3,308	)		(5,236	)		(6,582	)
Net finance expenses		(2,565	)		(3,307	)		(5,145	)		(6,580	)

Loss before taxes		(993	)		(3,672	)		(449	)		(8,785	)
Deferred income tax expense		–			45,634			–			45,634
Loss and comprehensive loss for the period		(993	)		(49,306	)		(449	)		(54,419	)

Basic and diluted loss per share (note 7)	$	(0.01	)	$	(0.29	)	$	–		$	(0.32	)

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, 2014 AND 2013

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

	Number of common shares		Share capital		Equity component of convertible debentures		Contributed surplus		Deficit			Total shareholders’ equity
Balance at December 31, 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

Balance at December 31, 2013	172,549,701	$	171,460	$	5,019	$	11,238	$	(159,538	)	$	28,179
Share-based payments	–		–		–		246		–			246
Loss for the period	–		–		–		–		(449	)		(449	)
Balance at June 30, 2014	172,549,701	$	171,460	$	5,019	$	11,484	$	(159,987	)	$	27,976

See accompanying notes to the condensed interim consolidated financial statements.

ANDERSON ENERGY LTD.

Consolidated Statements of Cash Flows

SIX MONTHS ENDED JUNE 30, 2014 AND 2013

(Stated in thousands of dollars) (Unaudited)			2014			2013

CASH PROVIDED BY (USED IN)
OPERATIONS
Loss for the period		$	(449	)	$	(54,419	)
Adjustments for:
	Unrealized loss on derivative contracts (note 8)		223			433
	(Gain) loss on sale of property, plant and equipment (note 3)		(2,650	)		43
	Depletion and depreciation (note 3)		12,150			16,672
	Share-based payments		175			385
	Accretion on decommissioning obligations (note 5)		376			382
	Accretion on convertible debentures (note 9)		1,171			1,057
	Deferred income tax expense		–			45,634
Decommissioning expenditures (note 5)			(184	)		(87	)
Changes in non-cash working capital (note 10)			(343	)		(976	)
Net cash provided by operations			10,469			9,124
FINANCING
Increase in bank loans			–			5,798
Net cash provided by financing			–			5,798
INVESTING
Property, plant and equipment expenditures (note 3)			(20,850	)		(7,900	)
Proceeds from sale of property, plant and equipment (note 3)			1,012			52
Changes in non-cash working capital (note 10)			(5,864	)		(7,075	)
Net cash used in investing			(25,702	)		(14,923	)

Decrease in cash and cash equivalents			(15,233	)		(1	)
Cash and cash equivalents, beginning of period			25,111			1
Cash and cash equivalents, end of period		$	9,878		$	–

Interest received in cash		$	118		$	2
Interest paid in cash		$	(3,551	)	$	(4,938	)

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, 2014 WITH COMPARATIVE FIGURES FOR 2013

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

(Unaudited)

1. REPORTING ENTITY

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

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, 2014.

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

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

On January 1, 2014, the Company adopted new standards with respect to Offsetting Financial Assets and Financial Liabilities (Amendments to IAS 32 Financial Instruments: Presentation (“IAS 32”) and IFRIC 21 Levies (“IFRIC 21”). The amendments to IAS 32 clarify the requirements for offsetting financial instruments such as the amounts receivable and payable related to the Company’s commodity contracts. The amendments clarify when an entity has a legally enforceable right to offset and certain other requirements that are necessary to present a net financial asset or liability. IFRIC 21 clarifies that an entity recognizes a liability for a levy when the activity that triggers payment, as identified by the relevant legislation, occurs. The interpretation also clarifies that no liability should be recognized before the specified minimum threshold to trigger that levy is reached. The adoption of these standards had no impact on the amounts recorded in the consolidated financial statements as at January 1, 2014 or on the comparative periods.

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

3. PROPERTY, PLANT AND EQUIPMENT

Cost or deemed cost

		Oil and natural gas assets			Other equipment		Total
Balance at December 31, 2012	$	593,048		$	1,904	$	594,952
Additions		8,128			17		8,145
Disposals		(204,757	)		–		(204,757	)
Balance at December 31, 2013		396,419			1,921		398,340
Additions		22,073			136		22,209
Disposals		(10,705	)		–		(10,705	)
Balance at June 30, 2014	$	407,787		$	2,057	$	409,844

Accumulated depletion, depreciation and impairment losses

		Oil and natural gas assets			Other equipment		Total
Balance at December 31, 2012	$	307,251		$	1,527	$	308,778
Depletion and depreciation for the year		27,805			104		27,909
Impairment loss		44,581			–		44,581
Disposals		(118,906	)		–		(118,906	)
Balance at December 31, 2013	$	260,731		$	1,631	$	262,362
Depletion and depreciation for the period		12,104			46		12,150
Disposals		(8,856	)		–		(8,856	)
Balance at June 30, 2014	$	263,979		$	1,677	$	265,656

Carrying amounts

		Oil and natural gas assets		Other equipment		Total
At December 31, 2013	$	135,688	$	290	$	135,978
At June 30, 2014	$	143,808	$	380	$	144,188

Capitalized overhead

For the six months ended June 30, 2014, additions to property, plant and equipment included internal overhead costs of $0.9 million (year ended December 31, 2013 – $1.8 million).

Sale of property, plant and equipment

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

4. BANK LOANS

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

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

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

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

5. DECOMMISSIONING OBLIGATIONS

			June 30, 2014			December 31, 2013
Balance at January 1		$	30,413		$	46,467
	Provisions incurred		446			438
	Expenditures		(184	)		(971	)
	Provisions disposed		(3,487	)		(7,865	)
	Change in estimates		842			(8,470	)
	Accretion expense		376			814
Ending balance		$	28,406		$	30,413

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 $28.4 million as at June 30, 2014 (December 31, 2013 – $30.4 million) based on an undiscounted inflation-adjusted total future liability of $48.5 million (December 31, 2013 – $49.9 million). These payments are expected to be made over the next 30 years. At June 30, 2014, the liability has been calculated using an inflation rate of 2.0% (December 31, 2013 – 2.0%) and discounted using a risk-free rate of 1.0% to 3.1% (December 31, 2013 – 1.1% to 3.2%) depending on the estimated timing of the future obligation.

6. SHARE CAPITAL

Authorized share capital:

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

Issued share capital:

	Number of Common Shares		Amount
Balance at December 31, 2012, December 31, 2013 and June 30, 2014	172,549,701	$	171,460

Stock options:

The Company has an employee stock option plan under which employees, directors and consultants are eligible to purchase common shares of the Company. Options are granted using an exercise price of stock options equal to the weighted average trading price of the Company’s common shares for the five trading days prior to the date of the grant. Options have terms of either five or 10 years and vest equally over a two or three year period starting on the first anniversary date of the grant.

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

	June 30, 2014				December 31, 2013
	Number of options			Weighted average exercise price	Number of options			Weighted average exercise price
Opening balance	15,413,350		$	0.54	14,386,800		$	0.75
Granted during the period	57,600			0.21	3,160,100			0.13
Expired during the period	(209,000	)		2.21	(1,295,617	)		1.89
Forfeited during the period	(106,700	)		0.26	(837,933	)		0.49
Ending balance	15,155,250		$	0.52	15,413,350		$	0.54

Exercisable, end of period	7,792,517		$	0.75	7,951,817		$	0.79

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

Range of exercise prices	Number of options	Weighted average exercise price	Weighted average remaining life (years)

$0.13 to $0.20	3,127,000	$ 0.13	4.4
$0.21 to $0.32	5,069,300	0.31	3.3
$0.33 to $0.50	120,000	0.45	2.3
$0.51 to $0.77	2,379,600	0.70	2.2
$0.78 to $1.17	4,318,350	0.93	0.7
$1.18 to $1.77	141,000	1.21	1.5
Total at June 30, 2014	15,155,250	$ 0.52	2.6

There were no options exercised in the six months ended June 30 2014 (June 30, 2013 – nil).

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

This estimated forfeiture rate is adjusted to the actual forfeiture rate when each tranche vests. Share-based payments of $0.2 million (June 30, 2013 – $0.4 million) were expensed during the six months ended June 30, 2014. In addition, share-based payments of $0.1 million (June 30, 2013 – $0.1 million) were capitalized during the six months ended June 30, 2014.

		June 30, 2014
Fair value at grant date	$	0.12
Common share price	$	0.21
Exercise price	$	0.21
Volatility		68%
Option life		5 years
Dividends		0%
Risk-free interest rate		1.7%
Forfeiture rate		20%

7. LOSS PER SHARE

Basic and diluted loss per share was calculated as follows:

		Three months ended June 30						Six months ended June 30
		2014			2013			2014			2013
Loss for the period	$	(993	)	$	(49,306	)	$	(449	)	$	(54,419	)
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	$	(0.01	)	$	(0.29	)	$	–		$	(0.32	)

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, 2014, 15,155,250 options (June 30, 2013 – 14,094,300 options) and 59,316,889 common shares reserved for convertible debentures (June 30, 2013 – 59,316,889) were excluded from calculating diluted loss as they would not have been dilutive.

8. OTHER LOSSES

Other losses include the following:

		Three months ended June 30						Six months ended June 30
		2014			2013			2014			2013
Realized loss on derivative contracts	$	(275	)	$	(661	)	$	(682	)	$	(1,247	)
Unrealized gain (loss) on derivative contracts		241			638			(223	)		(433	)
	$	(34	)	$	(23	)	$	(905	)	$	(1,680	)

9. FINANCE INCOME AND EXPENSES

			Three months ended June 30						Six months ended June 30
			2014			2013			2014			2013
Income:
	Interest income on cash equivalents		30			–			85			1
	Other		2			1			6			1
			32			1			91			2
Expenses:
	Interest and financing costs on bank loans		(61	)		(804	)		(138	)		(1,572	)
	Interest on convertible debentures		(1,772	)		(1,772	)		(3,543	)		(3,543	)
	Accretion on convertible debentures		(576	)		(533	)		(1,171	)		(1,057	)
	Accretion on decommissioning obligations (note 5)		(184	)		(194	)		(376	)		(382	)
	Other		(4	)		(5	)		(8	)		(28	)
			(2,597	)		(3,308	)		(5,236	)		(6,582	)
Net finance expenses		$	(2,565	)	$	(3,307	)	$	(5,145	)	$	(6,580	)

10. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital is comprised of:

			June 30, 2014			June 30, 2013
Source (use) of cash
	Accounts receivable and accruals	$	(701	)	$	1,698
	Prepaid expenses and deposits		426			679
	Accounts payable and accruals		(5,932	)		(10,428	)
		$	(6,207	)	$	(8,051	)
Related to operating activities		$	(343	)	$	(976	)
Related to financing activities		$	–		$	–
Related to investing activities		$	(5,864	)	$	(7,075	)

11. FINANCIAL RISK MANAGEMENT

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

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

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

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, 2014:

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⁾		$	17,485	$	–	$	–	$	–	$	–
	Convertible debentures
		– Interest ⁽¹⁾		5,523		7,085		3,335		–		–
		– Principal		–		50,000		46,000		–		–
Total			$	23,008	$	57,085	$	49,335	$	–	$	–

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.

Market risk.

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

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

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

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

Interest rate risk. Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The interest charged on outstanding bank loans fluctuates with the interest rates posted by the 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. The Company had no bank loans outstanding during the six months ended June 30, 2014.

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

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

Type of Contract⁽¹⁾	Commodity	Volume		Weighted Average Fixed Price	Remaining Period
Financial swap	Crude oil	500 barrels per day	$	110.00 WTI Cdn per barrel	July 1, 2014 to December 31, 2014

Financial swap	Natural gas	2,500 GJ per day	$	3.55 per GJ	July 1, 2014 to December 31, 2014

Swap indicates fixed price payable to Anderson in exchange for floating price payable to counterparty.

The estimated fair value of the contracts has been determined as the amounts the Company would receive or pay to terminate the contracts. At June 30, 2014, the Company estimates that it would pay $0.4 million to terminate the contracts. The fair value would have been impacted as follows had the 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 WTI oil prices	$	(92	)	$	92

Canadian $0.50 per GJ change in AECO natural gas prices	$	(230	)	$	230

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

Capital management.

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

To assess capital and operating efficiency, the Company monitors its bank debt level and working capital. It also monitors the ratio of bank debt and other debt to funds from operations (defined as cash flow from operating activities before changes in non-cash working capital and decommissioning expenditures). The Company prepares annual operating and capital budgets, which are updated as necessary depending on varying factors including current and forecast crude oil and natural gas prices, capital deployment and general industry conditions. The annual and updated budgets are approved by the Board of Directors. Anderson does not pay dividends.

Anderson’s current capital structure is summarized below:

		June 30, 2014			December 31, 2013
Current liabilities⁽¹⁾	$	17,485		$	23,417
Current assets⁽¹⁾		(18,141	)		(33,099	)
Working capital surplus	$	(656	)	$	(9,682	)
Bank loans		–			–
Net debt before convertible debentures		(656	)		(9,682	)
Convertible debentures (liability component)⁽²⁾		90,093			88,922
Total net debt	$	89,437		$	79,240
Shareholders’ equity		27,976			28,179
Total capitalization	$	117,413		$	107,419

Excludes unrealized gains and losses on derivative contracts.
Face value of convertible debentures: Series A Debentures $50 million, Series B Debentures $46 million.

For the six months ended June 30, 2014, funds from operations were $11.0 million (June 30, 2013 – $10.2 million). Funds from operations are dependent on many factors, including the success of oil and natural gas acquisition, exploration and development activities, commodity prices including quality and basis differentials, royalties, operating, administrative and financing costs, and general market conditions.

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

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

12. COMMITMENTS AND CONTINGENCIES

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

		2014		2015		2016		2017		2018		Thereafter
Firm service commitment	$	412	$	757	$	169	$	137	$	118	$	136
Firm service committed volumes (MMcfd)		3		5		4		3		3		3

There are no material changes to other commitments and contingencies from those disclosed in the Company’s annual audited consolidated financial statements for the years ended December 31, 2013 and 2012 other than as described herein. At June 30, 2014, the Company has an obligation under a farm-in agreement to drill one Cardium horizontal well prior to October 31, 2014 to earn a working interest in the farm-out lands. The minimum capital commitment associated with the well is $2.5 million. The Company also has an obligation under a separate farm-in agreement to spud an additional two gross (1.0 net) Cardium horizontal wells prior to December 31, 2014. In May 2014, the Company entered into an agreement to lease office space at a cost of approximately $0.4 million per year from July 1, 2014 to October 30, 2018.

Corporate Information

Head Office
1000, 555 – 4^th Avenue S.W.
Calgary, Alberta
Canada T2P 3E7
Phone (403) 262-6307
Fax (403) 261-2792
Website http://www.andersonenergy.ca/

Directors

J.C. Anderson
Calgary, Alberta

Brian H. Dau
Calgary, Alberta

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

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

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

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

Officers

Brian H. Dau
President & Chief Executive Officer

David M. Spyker
Chief Operating Officer

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

Blaine M. Chicoine
Vice President, Drilling and Completions

Sandra M. Drinnan
Vice President, Land

Philip A. Harvey
Vice President, Exploitation

Jamie A. Marshall
Vice President, Exploration

Auditors
KPMG LLP

Independent Engineers
GLJ Petroleum Consultants Ltd.

Legal Counsel
Bennett Jones LLP

Registrar and Transfer Agent
Valiant Trust Company

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

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

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

Anderson Energy Ltd.
Brian H. Dau
President & Chief Executive Officer
(403) 262-6307

Anderson Energy Announces 2014 Second Quarter Results

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