Connacher Oil and Gas Ltd. Progress Evident in Q2 2011; Record Bitumen Sales in June at 15,400 Bbl/D; Great Divide Joint Ve by 24hgold

Mots clés associés : Canada | Dollar | Swaps |

CALGARY, Aug. 11, 2011 /CNW/ - Connacher Oil and Gas Limited (TSX: CLL), a Calgary-based company emphasizing both heavy gravity and light gravity crude oil resource exploitation opportunities, made considerable progress in the second quarter 2011 ("Q2 2011"). Bitumen production at Great Divide more than doubled over last year's levels and despite the impact of a scheduled turnaround at Algar during May 2011, exceeded Q1 2011 levels at improved prices. Record bitumen sales of 15,400 bbl/d were recorded in June 2011. Refer to our Interim Report and Management's Discussion and Analysis ("MD&A) for more detailed information on our operating and financial results. These are filed on SEDAR and on our website at www.connacheroil.com.

These results will be the subject of a Conference Call at 8:00 AM MT on August 12, 2011. To listen to or participate in the live conference call please dial either 1-647-427-7450 or 1-888-231-8191. A replay of the event will be available from Friday, August 12, 2011 at 12:00 MT until 21:59 MT on Friday, August 19, 2011. To listen to the replay please dial either 1-416-849-0833 or Toll Free at 1-855-859-2056 and enter the pass code 89823115. You can also listen to the conference call online, through the following webcast link: http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=3625380

HIGHLIGHTS

Great Divide bitumen production more than doubled; June 2011 sales were 15,400 bbl/d, a record
Great Divide 24,000 bbl/d expansion application advancing through regulatory process; Pad 104 for Pod One approved by regulators, to be built in 2012 with new wells planned; diluent recovery unit ("DRU") for Pod One also approved and to be installed with two new pumps in September 2011
SAGD+™ steam plus solvent project initiated at Algar
Engaged an advisor and advanced joint venture process
Streamlined and strengthened our balance sheet with refinancing of long-term debt
Advanced our asset rationalization process while expanding involvement in two light gravity crude oil resource plays at Twining (Pekisko) and Penhold (Viking) in central Alberta
Refinery results near record levels; strong results expected for full year
Adjusted EBITDA more than doubled and cash flow was up 375 percent over Q1 2011 levels and, respectively, up 86 percent and 83 percent over last year's results

Our financial and operating summary results below underscore the progress made during the quarter and year-to-date. Revenue, upstream and downstream net operating income, adjusted EBITDA, Q2 2011 cash flow and realized prices were all considerably higher than last year as well as Q1 2011 results. This primarily reflects the positive impact of Algar and of our refinery results. During the period, we continued our property rationalization efforts and redirected our focus to higher return light gravity crude oil resource projects in central Alberta. Wet weather forestalled a more aggressive program. While we reported a loss after expensing the majority of costs related to the successful refinancing of our long term debt during Q2 2011, the refinancing process significantly lowered prospective annual interest payments, improved our corporate liquidity and extended the term to maturity without any principal repayment requirements to 2018 and 2019, thus freeing up cash flow for growth expenditures. This improved liquidity was supplemented by our continuing access to an upsized syndicated bank revolving credit facility in the amount of $100 million, on which the only draws are minimal amounts for Letters of Credit, generally of short duration.

Subsequent to the reporting period, we initiated SAGD+™ on a trial basis in two wells on Pad 203 at Algar. We anticipate both steam: oil ratio ("SOR") reductions and improved bitumen productivity from this initiative, which will be expanded if our expectations are confirmed to be in line with laboratory and simulation results. We also engaged an advisor and initiated a formal process to negotiate a Great Divide joint venture to assist us in accelerating our planned 24,000 bbl/d expansion at Algar, upon regulatory approval. We also received regulatory approval to proceed with construction of Pad 104 on Pod One, which will be undertaken as part of our 2012 capital program. This provides visibility for continuing improvement in Pod One production performance as we will be able to access better reservoir with the new wells on Pad 104 than has proven to be the case with some of our older northern wells. Our oil sands assets continue to be the primary focus of our company's activity.

Our conventional light gravity crude oil drilling program was delayed by wet weather conditions but we are pleased to report that drilling is now underway at both Twining and Penhold, both in central Alberta, where we hold extensive exploitation acreage prospective for high netback light gravity crude oil production and reserves. This potential is being accessed by horizontal wells which are completed with multifrac technology. These are internally-generated projects which expose the company to the prospect of high netbacks with immediate production growth potential, a nice counterbalance to the longer-term appeal of our oil sands activity. We have produced over 10 million barrels of bitumen since our startup of Pod One in late 2007.

Our refinery is experiencing a near-record year thus far in 2011. Healthy sales and strong margins contributed significantly to our Q2 2011 results and we anticipate this performance will continue during the balance of 2011. Connacher is aggressively pursuing its clearly-defined growth and value enhancement strategy. The foundation of this approach is stable and growing bitumen production and sales at Great Divide with near term expansion potential from our well-established pipeline of projects, supported by over 500 million barrels of proved and probable ("2P") reserves, including over 180 million barrels of proved reserves and 320 million barrels of probable reserves, as estimated by GLJ Petroleum Consultants Ltd. at December 31, 2010 in their February 18, 2011 report. We anticipate our Algar expansion application to be approved by regulators before year-end 2011, by which time we anticipate our joint venture search process will either be at or near completion. This, we anticipate, will facilitate continued and timely growth of our bitumen exploitation program at limited cash cost to the company. In the interim, we are aggressively pursuing the exploitable potential of our high netback light gravity crude oil projects in central Alberta, on low-cost lands we successfully accumulated during the past eighteen months, primarily at Crown sales. We are also continuing our asset rationalization and enhancement program with the sale of non-core or non cash generating assets so we can clearly focus on the oil sands and new light gravity crude oil resource opportunities we own. Having refinanced our long-term debt, all of which is at fixed rates, with no principal repayments to maturity and with no ongoing financial maintenance covenants, we have an extended runway to capitalize on opportunities. Our crude oil hedging program also provides us with solid crude oil protection during periods of extreme volatility, such as has emerged in recent times.

SUMMARY RESULTS ⁽²⁾


FINANCIAL ($000 except per share amounts)		Q2 2011	Q1 2011	%	Q2 2010	%	YTD 2011	YTD 2010	%
Revenues, net of royalties		$234,556	$178,990	31	$132,877	77	$413,546	$253,972	63
Adjusted EBITDA ⁽¹⁾		$37,608	$15,845	137	$20,173	86	$53,453	$34,613	54
Cash flow ⁽¹⁾		$15,873	$(5,770)	375	$8,669	83	$10,103	$12,476	(19)
	Per share, basic and diluted ⁽¹⁾	$0.04	$(0.01)	500	$0.02	100	$0.02	$0.03	(33)
Net loss		$(44,169)	$(14,101)	213	$(31,717)	39	$(58,270)	$(23,212)	151
	Per share, basic and diluted ⁽¹⁾	$(0.10)	$(0.03)	233	$(0.07)	43	$(0.13)	$(0.05)	160
Capital expenditures		$38,988	$40,830	(5)	$59,176	(34)	$79,818	$177,448	(55)
Cash on hand		$31,525	$42,865	(26)	$69,412	(55)	$31,525	$69,412	(55)
Working capital		$18,954	$80,902	(77)	$100,202	(81)	$18,954	$100,202	(81)
Long-term debt		$829,310	$834,089	(1)	$889,797	(7)	$829,310	$889,797	(6)
Shareholders' equity		$467,057	$515,941	(9)	$530,086	(12)	$467,057	$530,086	(12)


OPERATIONAL		Q2 2011	Q1 2011	%	Q2 2010	%	YTD 2011	YTD 2010	%
Daily production volumes ⁽³⁾
	Bitumen (bbl/d)	13,720	13,200	4	6,211	121	13,461	6,572	105
	Crude oil (bbl/d)	398	540	(26)	906	(56)	468	921	(49)
	Natural gas (Mcf/d)	3,755	6,805	(45)	9,278	(60)	5,271	9,469	(44)
	Barrels of oil equivalent (boe/d) ⁽⁴⁾	14,744	14,874	(1)	8,663	70	14,808	9,071	63
Upstream pricing ⁽⁵⁾
	Bitumen ($/bbl)	54.49	41.78	30	43.13	26	48.23	47.77	1
	Crude oil ($/bbl)	90.93	71.70	27	61.90	47	79.91	66.54	20
	Natural gas ($/Mcf)	3.94	3.57	10	3.78	4	3.70	4.33	(15)
	Barrels of oil equivalent ($/boe) ⁽⁴⁾	54.15	41.31	31	41.44	31	47.68	45.89	4
Downstream
	Throughput - Crude charged (bbl/d)	9,860	9,764	1	9,373	5	9,812	9,360	5
	Refinery utilization (%)	104	103	1	99	5	103	99	4
	Margins (%)	10	6	67	13	(23)	8	5	60

(1)	A non-GAAP measure which is defined in the Advisory section of the MD&A
(2)	Effective October 1, 2010, the capitalized costs relating to the company's second oil sands project, Algar, were subjected to depletion and the revenues, expenses and finance charges associated with the project were reported in the statement of operations. Prior thereto, Algar was considered a major development project under construction and all costs, including related financing costs and internal operating expenses net of revenue, were capitalized. Accordingly, the above table does not include production and sales volumes for Algar prior to October 1, 2010
(3)	Represents bitumen, crude oil and natural gas produced in the period. Actual sales volumes may be different due to inventory changes during the period. Actual volumes sold were 14,340 boe/d in Q2 2011, 14,732 boe/d in Q1 2011 and 14,535 boe/d in YTD 2011 (Q2 2010 - 8,663 boe/d and YTD 2010 - 9,071 boe/d)
(4)	All references to barrels of oil equivalent (boe) are calculated on the basis of 6 Mcf: 1 bbl. This conversion is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Boes may be misleading, particularly if used in isolation
(5)	Before royalties and risk management contract gains or losses and after applicable diluent and transportation costs divided by actual sales volumes

We have maintained our 2011 capital expenditure budget at $162 million with modest immaterial change to previous allocations among our principal business units. As detailed in our MD&A, we have modified our full year 2011 bitumen production guidance for Great Divide, after taking into account actual production in year to date 2011, which reflected the significant contribution from Algar, offset by adverse market and weather conditions, leading to curtailments in Q1 2011 and our decision to construct and install a diluent recovery unit ("DRU") at Pod One during September 2011, during which time we will also conduct other activities. We did not conduct a turnaround at Pod One when we did our work at Algar so this event provides us with the opportunity to conduct certain remedial work including pump installations. The DRU is expected to give Connacher more marketing flexibility for its Great Divide bitumen in future years and improve overall economic returns. We also have reduced our anticipated rampup pace at Algar for 2H 2011 to allow us to overcome some header pressure constraints and to reduce reservoir pressure in order to increase steam injection to desired rates and position us for the introduction of additional low pressure downhole pumps in 2012, which over time should increase production while optimizing the efficiency of the steam assisted gravity drainage ("SAGD") process. Offsetting this modification, we now anticipate conventional production will be considerably higher for the full year 2011, such that our total mid-point outlook for production is within nine percent of our earlier estimates. Results will also be buoyed by the stronger than expected contribution from our refining division. Our solid hedging program also provides us with protection against the downside risk in crude oil pricing against the backdrop of very volatile market conditions.

Forward Looking Information

This press release contains forward‐looking information including but not limited to, anticipated future operating and financial results, forecast netbacks, expectations of future production, anticipated capital expenditures for 2011, future development and exploration activities, including the planned installation of a DRU at Pod One and new pumps in two Pod One wells and the timing of building Pad 104 for Pod One, anticipated impact of technical innovations on productivity and SORs and possible expansion of the application of SAGD+^TMon additional well pairs, future possible joint venture arrangements, timing of receipt of regulatory approvals for future expansion at oil sands properties and further rationalization activity. Forward‐looking information is based on management's expectations regarding future growth, results of operations, production, future commodity prices and foreign exchange rates, future capital and other expenditures (including the amount, nature and sources of funding thereof), plans for and results of drilling activity, environmental matters, business prospects and opportunities and future economic conditions.

Forward‐looking information involves significant known and unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated. These risks include, but are not limited to operational risks in development, exploration, production and start‐up activities; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve and resource estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks; the risk of commodity price and foreign exchange rate fluctuations; risks associated with the impact of general economic conditions; sales volumes and risks and uncertainties associated with securing and maintaining the necessary regulatory approvals and financing to proceed with the continued expansion of the Great Divide oil sands project. Additional risks and uncertainties are described in further detail in Connacher's Annual Information Form ("AIF") for the year ended December 31, 2010 which is available at www.sedar.com.

Although Connacher believes that the expectations in such forward‐looking information are reasonable, there can be no assurance that such expectations shall prove to be correct. The forward‐looking information included in this press release is expressly qualified in its entirety by this cautionary statement. The forward‐looking information included in this press release is made as of August 11, 2011 and Connacher assumes no obligation to update or revise any forward‐looking information to reflect new events or circumstances, except as required by law.

In addition, design capacity is not necessarily indicative of the stabilized production levels that may ultimately be achieved at Connacher's SAGD facilities. Moreover, reported average or instantaneous production levels may not be reflective of sustainable production rates and future production rates may differ materially from the production rates reflected in this report due to, among other factors, difficulties or interruptions encountered during the production of bitumen or other hydrocarbons.

Statements relating to "reserves" are deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future. Certain information and assumptions relating to the reserves reported herein are set forth in Connacher's AIF which is available at www.sedar.com.  The reserves estimates of Connacher's properties described herein are estimates only. The actual reserves on Connacher's properties may be greater or less than those calculated.

Per barrel of oil equivalent (boe) amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil (6:1). The conversion is based on an energy equivalency conversion method primarily applicable to the burner tip and does not represent a value equivalency at the wellhead. Boes may be misleading, particularly if used in isolation.

MANAGEMENT'S DISCUSSION AND ANALYSIS

This Management's Discussion and Analysis ("MD&A") for Connacher Oil and Gas Limited ("Connacher" or the "company") is dated August 11, 2011 and should be read in conjunction with Connacher's condensed interim consolidated financial statements for the three months ended June 30, 2011 ("Q2 2011") and three months ended June 30, 2010 ("Q2 2010") and six months ended June 30, 2011 ("YTD 2011") and six months ended June 30, 2010 ("YTD 2010") and the MD&A and the audited consolidated financial statements for the year ended December 31, 2010 and 2009.

The interim consolidated financial statements and comparative information have been prepared in accordance with International Financial Reporting Standard ("IFRS") 1, "First-time Adoption of International Financial Reporting Standards" and with International Accounting Standard 34, "Interim Financial Reporting", as issued by the International Accounting Standards Board. Previously, the company prepared its interim and annual consolidated financial statements in accordance with Canadian generally accepted accounting principles ("previous GAAP"). Unless otherwise noted, 2010 comparative information has been prepared in accordance with IFRS. Canadian GAAP now comprises IFRS. The adoption of IFRS has not had an impact on the company's operations, strategic decisions and cash flow. The most significant area of impact was the adoption of the IFRS upstream oil and gas accounting principles. Further information on the IFRS impacts is provided in the Accounting Policies and Estimates Section of this MD&A.

Please read the Advisory section of the MD&A which provides information on Forward-Looking Statements, Non-GAAP measurements and other information. Additional information relating to Connacher, including Connacher's Annual Information Form ("AIF"), can be found on SEDAR at www.sedar.com or on the company's website at www.connacheroil.com.

FINANCIAL AND OPERATING REVIEW

UPSTREAM - CANADA

PRODUCTION AND SALES VOLUMES ⁽¹⁾


	Three months ended June 30			Six months ended June 30
	2011	2010	% Change	2011	2010	% Change
Dilbit sales - bbl/d ⁽²⁾	17,023	8,294	105	17,109	8,770	95
Diluent used - bbl/d ⁽²⁾	(3,707)	(2,083)	78	(3,921)	(2,198)	78
Bitumen sold - bbl/d ⁽²⁾	13,316	6,211	114	13,188	6,572	101
Change in inventory and other ⁽³⁾ - bbl/d	404	-	100	273	-	100
Bitumen produced - bbl/d ⁽²⁾	13,720	6,211	121	13,461	6,572	105
Crude oil produced and sold - bbl/d	398	906	(56)	468	921	(49)
Natural gas produced and sold - Mcf/d	3,755	9,278	(60)	5,271	9,469	(44)
Total production volumes - boe/d	14,744	8,663	70	14,808	9,071	63
Total sales volumes- boe/d ⁽³⁾	14,340	8,663	66	14,535	9,071	60

⁽²⁾ Bitumen produced at our oil sands project is mixed with purchased diluent and sold as "dilbit". Diluent is a light hydrocarbon that improves the marketing and transportation quality of bitumen. Diluent volumes used have been deducted in calculating bitumen production and sales volumes

⁽³⁾ The company's sales volumes differ from its production volumes due to changes in inventory and other product losses

Bitumen production increased by 121 percent in Q2 2011 compared to Q2 2010 and 105 percent in YTD 2011 compared to YTD 2010, primarily due to the completion and startup of the company's second oil sands project, Algar in 2010. Results from Algar were recorded in the company's statement of operations effective October 1, 2010.

In Q2 2011 and YTD 2011, conventional crude oil production and sales volumes decreased by 56 percent and 49 percent, compared to Q2 2010 and YTD 2010, respectively, primarily due to the sale of our crude oil properties at Battrum in Southwest Saskatchewan in February 2011. Natural gas production and sales volumes decreased by 60 percent in Q2 2011 and 44 percent in YTD 2011 compared to Q2 2010 and YTD 2010 respectively, primarily due to the sale of our natural gas properties at Marten Creek in April 2011.

COMMODITY PRICES AND RISK MANAGEMENT


	Three months ended June 30			Six months ended June 30
	2011	2010	%	2011	2010	%
*Average benchmark prices*
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing	$102.34	$77.88	31	$98.50	$78.35	26
Western Canadian Select (WCS) C$/bbl	84.70	63.96	32	78.25	66.89	17
Differential -WCS to WTI C$/bbl	17.64	14.09	25	20.25	11.57	75
Natural Gas (Alberta spot) C$/Mcf at AECO	3.54	3.90	(9)	3.56	4.41	(19)
*Average realized prices* *⁽¹⁾*
Bitumen - C$/bbl	54.49	43.13	26	48.23	47.77	1
Crude oil - C$/bbl	90.93	61.90	47	79.91	66.54	20
Natural gas - C$/Mcf	3.94	3.78	4	3.70	4.33	(15)
Weighted average sales price - C$/boe ⁽²⁾	$54.15	$41.44	31	$47.68	$45.89	4

⁽¹⁾ Before royalties and risk management contract gains or losses and after applicable diluent and transportation costs divided by actual sales volumes
⁽²⁾ Boe are defined in the Advisory section of the MD&A

Connacher's bitumen production slate is a heavy gravity crude. Consequently, the bitumen selling prices realized by the company are lower than the WTI reference price. This difference is commonly referred to as the "heavy oil differential" as applied to crude oil prices. Actual realized bitumen prices are a calculated amount derived by deduction from diluted bitumen ("dilbit") sales prices of such items as the cost of diluent, transportation charges for both diluent from purchase points to our Great Divide site and for dilbit from our Great Divide site to market. Other factors which influence calculated bitumen prices include the relative value of the Canadian dollar and the blend ratio of diluent to bitumen.

Realized bitumen and crude oil prices were higher in each of Q2 2011 and YTD 2011 relative to comparative periods in 2010, primarily due to increased benchmark industry pricing, offset somewhat by higher transportation charges necessitated by the need to seek out transportation alternatives and new distant markets because of pipeline apportionment issues. Higher crude oil pricing in 2011 also resulted from higher product pricing of light gravity crude from our new Twining production. The heavy oil differential discount widened in 2011 due to market demand and supply issues for heavy crude relative to lighter crude, in part attributed to refinery needs and pipeline disruptions that limited the transportation capacity for heavy crude oil. Lower realized natural gas prices in YTD 2011 compared to YTD 2010 were due to lower benchmark prices.

Dilbit, crude oil and natural gas are generally sold on month-to-month sales contracts at prices negotiated with major Canadian or U.S. marketers, refiners, regional upgraders or other end users, by reference to benchmark prices or at prices subject to commodity contracts which are also based on WTI market prices for crude oil and AECO market prices for natural gas. In this regard, Connacher maintains various short-term contracts for the sale of dilbit to a variety of heavy oil purchasers in central and northern Alberta. In order to secure diluent supplies, Connacher also utilizes short-term diluent purchase contracts and acquires certain volumes from its own refinery at Great Falls, Montana. As a means of managing the risk of commodity price volatility, Connacher enters into risk management commodity sales contracts from time to time. Consequently, our reported results in 2011 and 2010 were also influenced by the following WTI crude oil price risk management contracts:

January 1, 2010 - December 31, 2010 - 2,500 bbl/d at WTI US$78.00/bbl;
February 1, 2010 - April 30, 2010 - 2,500 bbl/d at WTI US$79.02/bbl;
May 1, 2010 - December 31, 2010 - 2,500 bbl/d at a minimum of WTI US$75.00/bbl and a maximum of WTI US$95.00/bbl;
January 1, 2011 - March 31, 2011 - 1,000 bbl/d at WTI US$86.10/bbl;
January 1, 2011 - March 31, 2011 - 1,000 bbl/d at WTI US$88.10/bbl;
January 1, 2011 - December 31, 2011 - 2,000 bbl/d at WTI US$90.60/bbl and the counterparty has a right, on December 30, 2011, to extend the maturity of the contract for one additional year at the same price;
January 1, 2011 - March 31, 2011 - 2,000 bbl/d at a minimum of WTI US$80.00/bbl and a maximum of WTI US$100.25/bbl;
April 1, 2011 - June 30, 2011 - 2,000 bbl/d at WTI US$85.25/bbl;
April 1, 2011 - March 31, 2012 - 2,000 bbl/d at a minimum of WTI US$80.00/bbl and a maximum of WTI US$96.00/bbl;
July 1, 2011 - June 30, 2012 - 2,000 bbl/d at a minimum of WTI US$80.00/bbl and a maximum of WTI US$100.00/bbl; and
January 1, 2012 - December 31, 2012 - 2,000 bbl/d at a minimum of WTI US$80.00 bbl/d and a maximum of WTI US $120.00/bbl.

The company recorded an unrealized gain and a realized loss of $31.2 million and $6.3 million, respectively, in Q2 2011 (Q2 2010 - an unrealized gain and a realized loss of $10.4 million and $0.3 million, respectively) on the above risk management contracts. The company recorded an unrealized gain and a realized loss of $0.2 million and $8.3 million, respectively, in YTD 2011 (YTD 2010 - an unrealized gain and a realized loss of $9.7 million and $0.5 million, respectively) on the above risk management contracts.

UPSTREAM REVENUE ⁽¹⁾


Three months ended June 30	2011				2010
($000 except per unit amounts)	Oil sands	Crude oil	Natural gas	Total	Oil sands	Crude oil	Natural gas	Total
Gross upstream revenues ⁽²⁾	$118,334	$3,320	$1,347	$123,001	$44,616	$5,132	$3,195	$52,943
Diluent costs ⁽³⁾	(41,207)	-	-	(41,207)	(17,067)	-	-	(17,067)
Transportation costs	(11,100)	(27)	-	(11,127)	(3,170)	(30)	-	(3,200)
Revenues	$66,027	$3,293	$1,347	$70,667	$24,379	$5,102	$3,195	$32,676
Price ($ per bbl / Mcf / boe)⁽⁴⁾	$54.49	$90.93	$3.94	$54.15	$43.13	$61.90	$3.78	$41.44


Six months ended June 30	2011				2010
($000 except per unit amounts)	Oil sands	Crude oil	Natural gas	Total	Oil sands	Crude oil	Natural gas	Total
Gross upstream revenues ⁽²⁾	$217,752	$6,822	$3,533	$228,107	$99,789	$11,131	$7,425	$118,345
Diluent costs ⁽³⁾	(80,144)	-	-	(80,144)	(36,584)	-	-	(36,584)
Transportation costs	(22,479)	(46)	-	(22,525)	(6,379)	(35)	-	(6,414)
Revenues	$115,129	$6,776	$3,533	$125,438	$56,826	$11,096	$7,425	$75,347
Price ($ per bbl / Mcf / boe)⁽⁴⁾	$48.23	$79.91	$3.70	$47.68	$47.77	$66.54	$4.33	$45.89

⁽¹⁾ Effective October 1, 2010, the capitalized costs relating to the company's second oil sands project, Algar, were subjected to depletion and the revenues, expenses and finance charges associated with the project were reported in the statement of operations. Prior thereto, Algar was considered a major development project under construction and all costs, including related financing costs and operating expenses net of revenue were capitalized. Accordingly, the above table does not include operating results for Algar prior to October 1, 2010
⁽²⁾ Bitumen produced at our oil sands project is mixed with purchased diluent and sold as "dilbit". Gross revenues represent sales of dilbit, crude oil and natural gas and are presented before royalties. In the consolidated financial statements, upstream revenues are presented net of royalties
⁽³⁾ The cost of diluent has been deducted from gross revenues in calculating revenues, above, whereas the diluent costs have been included in "Purchased products and operating costs" in the consolidated financial statements. Diluent costs, above, include purchases of $3.6 million and $8.8 million from our subsidiary, MRCI in Q2 2011 and YTD 2011, respectively (Q1 2010 and YTD 2010 - $3.6 million and $7.6 million, respectively) at market prices. These intercompany transactions have been eliminated in our consolidated financial statements
⁽⁴⁾ Per unit prices are calculated using revenues divided by bitumen, crude oil and natural gas actual volumes sold

Gross upstream revenues increased by 132 percent in Q2 2011 compared to Q2 2010 and 93 percent in YTD 2011 compared to YTD 2010, primarily due to higher bitumen revenue, partially offset by wider differentials and lower crude oil and natural gas revenue. Higher bitumen revenue in Q2 2011 and YTD 2011 was primarily due to higher bitumen sales volumes resulting from Algar and higher benchmark pricing.

Diluent used represented approximately 22 percent of the dilbit barrel sold in Q2 2011 and 24 percent of the dilbit barrel sold in YTD 2011 (25 percent in Q2 2010 and YTD 2010). Total diluent costs increased by 141 percent in Q2 2011 compared to Q2 2010 and by 119 percent in YTD 2011 compared to YTD 2010, primarily due to the increase in bitumen sales volumes in Q2 2011 and YTD 2011 (as a result of bringing on Algar) and an increase in diluent price due to higher benchmark prices.

Transportation costs represent costs to transport dilbit and crude oil to customers. Transportation costs increased by 248 percent in Q2 2011 compared to Q2 2010 and 251 percent in YTD 2011 compared to YTD 2010, due to increased bitumen sales volumes, higher trucking costs and increased sales travel distances to markets in 2011 arising from the pipeline disruptions. Additionally, we recently commenced railing some dilbit to new USA markets to alleviate downstream barriers, to access new sales markets that are less connected to current WTI/WCS pricing levels and which give evidence of being more aligned with higher Brent oil pricing. In conjunction with our goal of optimizing netbacks, railing is a part of our marketing diversification strategy, primarily aimed at mitigating the risk of plant shut-down due to an inability to sell production in congested markets combined with minimal on-site storage facilities.

ROYALTIES ⁽¹⁾


Three months ended June 30	2011				2010
($ 000 except per unit amounts)	Oil sands	Crude oil	Natural gas	Total	Oil sands	Crude oil	Natural gas	Total
Royalties	$4,948	$768	$(505)	$5,211	$965	$1,317	$(128)	$2,154
Royalties ($ per bbl / Mcf / boe) ⁽²⁾	$4.08	$21.20	$(1.48)	$3.99	$1.71	$15.98	$(0.15)	$2.73


Six months ended June 30	2011				2010
($ 000 except per unit amounts)	Oil sands	Crude oil	Natural gas	Total	Oil sands	Crude oil	Natural gas	Total
Royalties	$7,333	$1,574	$(844)	$8,063	$2,350	$2,886	$(33)	$5,203
Royalties ($ per bbl / Mcf / boe) ⁽²⁾	$3.07	$18.56	$(0.88)	$3.06	$1.98	$17.31	$(0.02)	$3.17

Royalties represent charges against production or revenue by governments and landowners. From period to period, royalties vary due to changes in the product mix, the components of which are subject to different royalty rates. Additionally, royalty rates are applied on a sliding scale to commodity prices. Royalties in Q2 2011 and YTD 2011 increased by 142 percent and 55 percent compared to Q2 2010 and YTD 2010, respectively, primarily due to higher sales volumes and WTI benchmark prices by which royalties are calculated, partially offset by Alberta gas cost allowance recoveries.

OPERATING COSTS ⁽¹⁾


Three months ended June 30	2011				2010
($ 000 except per unit amounts)	Oil sands	Crude oil	Natural gas	Total	Oil sands	Crude oil	Natural gas	Total
Operating costs	$23,776	$676	$646	$25,098	$12,770	$928	$1,473	$15,171
Operating costs ($ per bbl / Mcf / boe) ⁽²⁾	$19.62	$18.67	$1.89	$19.23	$22.59	$11.26	$1.75	$19.25


Six months ended June 30	2011				2010
($ 000 except per unit amounts)	Oil sands	Crude oil	Natural gas	Total	Oil sands	Crude oil	Natural gas	Total
Operating costs	$49,801	$1,577	$1,809	$53,187	$24,811	$2,041	$3,232	$30,084
Operating costs ($ per bbl / Mcf / boe) ⁽²⁾	$20.86	$18.60	$1.90	$20.22	$20.86	$12.24	$1.89	$18.32

Total operating costs in Q2 2011 were 65 percent higher than in Q2 2010 and were 77 percent higher in YTD 2011 compared to YTD 2010 but were virtually unchanged at $19.23 per boe on a per unit basis in Q2 2011 compared to Q2 2010. Total oil sands operating costs increased by 86 percent in Q2 2011 compared to Q2 2010 and increased by 100 percent in YTD 2011 compared to YTD 2010. The primary explanation for all of these variances was the new incremental production at Algar.

The continued ramp-up of bitumen production at Algar in 2011 and continued increases in the volume and reliability of production at Pod One, accompanied by a continuous cost control program, results in spreading our fixed operating costs over a larger production base and, hence, bitumen unit operating costs in Q2 2011 were 13 percent lower compared to Q2 2010. Continued reduction in per unit costs are anticipated with higher production and sales volumes.

The table below summarizes information related to our oil sands operating costs:


	Three months ended June 30				Six months ended June 30
	2011		2010		2011		2010
	($000)	%	($000)	%	($000)	%	($000)	%
Natural gas costs ⁽¹⁾	$7,611	32	$3,185	75	$15,124	30	$7,698	69
Other operating costs	16,165	68	9,585	25	34,677	70	17,113	31
Total oil sands operating costs	$23,776	100	$12,770	100	$49,801	100	$24,811	100

⁽¹⁾ Excluding risk management contract gains and losses. Includes natural gas consumed by boilers at the Co-gen and by other vessels at Great Divide

In Q2 2011, the combined steam: oil ratio ("SOR") from Pod One and Algar was 3.56; in Q2 2010, when only Pod One was in operation, it was 3.79. On a YTD basis, SOR was 3.68 in 2011 compared to 3.69 in 2010. SORs are an indicator of operational steam efficiency. Lower SORs mean less steam (and, therefore, less natural gas costs) are required to produce bitumen. As production continues to increase from both sites, we anticipate lower SORs. New technologies such as SAGD+^TM recently initiated at Algar, are also anticipated to lower SORs and improve individual well and overall productivity.

We commissioned our 13 megawatt Cogeneration plant in September 2010 and as a consequence have experienced the benefits of improved power stability in our oil sands operations. Although this will result in higher natural gas utilization and related costs, we anticipate improved operational reliability which should translate into incremental and more reliable bitumen production at both Pod One and Algar.

The company also recorded risk management contract losses of $61,000 in Q2 2011 and $253,000 in YTD 2011 relating to the following AECO natural gas purchase contracts. These losses are not included in the calculation of operating costs noted in the table above.

September 1, 2010 - August 31, 2011 - 4,000 GJ/d at AECO CAD$3.87/GJ;
October 1, 2010 - September 30, 2011 - 4,000 GJ/d at AECO CAD$4.20/GJ; and
January 1, 2012 - December 31, 2012 - 5,000 GJ/d a minimum of AECO CAD$3.70/GJ and a maximum of AECO CAD$4.30/GJ.

Total conventional crude oil and natural gas operating costs were slightly lower in Q2 2011 and YTD 2011, due to the sale of our Battrum and Marten Creek properties in 2011; on a per unit basis, they were higher, primarily reflecting the fixed cost component and lower production volumes in Q2 2011 and YTD 2011.

UPSTREAM NETBACKS ⁽¹⁾


Three months ended June 30, 2011	Bitumen *$ 000*	Bitumen *($ per* *bbl)*	Crude oil $ *000*	Crude oil *($ per* *bbl)*	Natural gas *$ 000*	Natural gas *($ p*er Mcf)	Total *$ 000*	Total *($ per boe)***
Revenues ⁽²⁾	$66,027	$54.49	$3,293	$90.93	$1,347	$3.94	$70,667	$54.15
Royalties	(4,948)	(4.08)	(768)	(21.20)	505	1.48	(5,211)	(3.99)
Operating costs	(23,776)	(19.62)	(676)	(18.67)	(646)	(1.89)	(25,098)	(19.23)
Netbacks ⁽³⁾	$37,303	$30.79	$1,849	$51.06	$1,206	$3.53	$40,358	$30.93

Three months ended June 30, 2010	Bitumen $ 000	Bitumen ($ per bbl)	Crude oil $ 000	Crude oil ($ per bbl)	Natural gas $ 000	Natural gas ($ per Mcf)	Total $ 000	Total ($ per boe)
Revenues ⁽²⁾	$24,379	$43.13	$5,102	$61.90	$3,195	$3.78	$32,676	$41.44
Royalties	(965)	(1.71)	(1,317)	(15.98)	128	0.15	(2,154)	(2.73)
Operating costs	(12,770)	(22.59)	(928)	(11.26)	(1,473)	(1.75)	(15,171)	(19.25)
Netbacks ⁽³⁾	$10,644	$18.83	$2,857	$34.66	$1,850	$2.18	$15,351	$19.46


Six months ended June 30, 2011	Bitumen *$ 000*	Bitumen *($ per bbl)*	Crude oil *$ 000*	Crude oil *($ per bbl)*	Natural gas *$ 000*	Natural gas *($ per Mcf)*	Total *$ 000*	Total *($ per boe)*
Revenues ⁽²⁾	115,129	$48.23	6,776	$79.91	3,533	$3.70	125,438	$47.68
Royalties	(7,333)	(3.07)	(1,574)	(18.56)	844	0.88	(8,063)	(3.06)
Operating costs	(49,801)	(20.86)	(1,577)	(18.60)	(1,809)	(1.90)	(53,187)	(20.22)
Netbacks ⁽³⁾	$57,995	$24.30	$3,625	$42.75	$2,568	$2.68	$64,188	$24.40

Six months ended June 30, 2010	Bitumen $ 000	Bitumen ($ per bbl)	Crude oil $ 000	Crude oil ($ per bbl)	Natural gas $ 000	Natural gas ($ per Mcf)	Total $ 000	Total ($ per boe)
Revenues ⁽²⁾	$56,826	$47.77	$11,096	$66.54	$7,425	$4.33	$75,347	$45.89
Royalties	(2,350)	(1.98)	(2,886)	(17.31)	33	0.02	(5,203)	(3.17)
Operating costs	(24,811)	(20.86)	(2,041)	(12.24)	(3,232)	(1.89)	(30,084)	(18.32)
Netbacks ⁽³⁾	$29,665	$24.93	$6,169	$36.99	$4,226	$2.46	$40,060	$24.40

Netbacks were 163 percent higher in Q2 2011 compared to Q2 2010 and were 60 percent higher in YTD 2011 compared to YTD 2010, due to higher realized bitumen and crude oil prices and higher bitumen sales volumes offset by higher royalties and operating costs. Netbacks per unit increased by 60 percent in Q1 2011 compared to Q1 2010 primarily due to higher netbacks per unit in our oil sands operations which were driven by higher realized bitumen prices.

DOWNSTREAM - USA

Connacher's wholly-owned subsidiary, Montana Refinery Company, Inc. ("MRCI") owns a 9,500 bbl/d heavy oil refinery located in Great Falls, Montana (the "Refinery") which is strategically aligned with our oil sands business. It primarily processes Canadian heavy crude oil (similar in quality and price to Great Divide dilbit) into a range of higher value refined petroleum products, including regular and premium gasoline, jet fuel, diesel and asphalt. Accordingly, the Refinery provides a physical hedge for our bitumen revenue by recovering a portion of the heavy oil differential in its netbacks under normal operating conditions. The Refinery also is a source of supply for a portion of our diluent requirements for oil sands operations. These intercompany purchases and sales have been eliminated on consolidation.

The Refinery is complex and includes reforming, isomerization and alkylation processes for formulation of gasoline blends, hydro-treating for sulphur removal and fluid catalytic cracking for conversion of heavy gas oils to gasoline and distillate products. Also, it is a major supplier of paving grade asphalt, polymer modified grades and asphalt emulsions for road construction. The Refinery delivers products in Montana and to neighboring regions, including, Alberta, Canada, by truck and rail transport.

The operating results of our Refinery are subject to a number of seasonal factors which cause product sales revenues to vary throughout the year. The Refinery's primary asphalt market is paving for road construction, which is in greater demand during the summer. Consequently, prices and volumes for our asphalt sales tend to be higher in the summer and lower in the colder seasons. During the winter, most of the Refinery's asphalt production is stored in tankage for sale in the subsequent summer. Seasonal factors also affect the production and sale of gasoline, which has a higher demand in summer months and the production and sale of diesel, which has a higher winter demand. As a result, inventory levels, sales volumes and prices can be expected to fluctuate on a seasonal basis.

REFINERY THROUGHPUT


	Three months ended June 30		Six months ended June 30
	2011	2010	2011	2010
Crude charged - bbl/d⁽¹⁾	9,860	9,373	9,812	9,360
Refinery production - bbl/d ⁽²⁾	10,740	10,546	10,865	10,679
Sales of refined petroleum products - bbl/d⁽³⁾	12,026	10,076	10,699	9,274
Refinery utilization ⁽⁴⁾	104%	99%	103%	99%

⁽¹⁾ Crude charged represents the barrels per day of crude oil processed at the Refinery
⁽²⁾ Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstock
⁽³⁾ Includes refined products purchased for resale and blending
⁽⁴⁾Represents crude charged divided by total crude capacity of the Refinery of 9,500 bbl/d.

In Q2 2011, the total sales volumes of refined petroleum products increased by 19 percent compared to Q2 2010 (and increased by 15 percent in YTD 2011 compared to YTD 2010), primarily due to the improved stability of refining operations and increased demand for refined petroleum products in 2011. A significant portion of our Refinery sales are derived from gasoline, diesel, jet fuel and asphalt. Diesel and asphalt sales volumes in Q2 2011 increased by 44 percent and 49 percent, respectively, compared to Q2 2010. In YTD 2011, diesel and asphalt sales volumes were up 41 percent and 35 percent, respectively, from YTD 2010.

COMMODITY PRICES


	Three months ended June 30			Six months ended June 30
	2011	2010	%	2011	2010	%
*Average benchmark prices*
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing	$102.34	$77.88	31	$98.50	$78.35	26
*Average realized prices* *⁽¹⁾*
Gasoline - US$/bbl	122.49	88.41	39	110.43	86.59	28
Diesel - US$/bbl	124.60	94.32	32	120.51	91.34	32
Asphalt - US$/bbl	93.43	90.22	4	84.08	71.79	17
Jet fuel - US$/bbl	$140.24	$96.28	46	$133.50	$95.32	40

⁽¹⁾ Before risk management contracts gains and losses and after transportation costs

Higher benchmark prices for refined products in Q2 2011 and YTD 2011 compared to Q2 2010 and YTD 2010 resulted in higher realized weighted average sales prices for our refined petroleum products. Sales of refined petroleum products are generally made on sales contracts negotiated with wholesalers, retailers and large end-users for gasoline, jet fuel and diesel and with construction contractors and road builders for asphalt. Frequently, sales contracts are for periods in excess of one month. As at June 30, 2011, MRCI had agreements to sell approximately 560,000 barrels of asphalt at a weighted average price approximating US$94.00 per barrel.

DOWNSTREAM REVENUE


	Three months ended June 30		Six months ended June 30
	2011	2010	2011	2010
Gross revenue ⁽¹⁾($ 000)	$120,333	$85,693	$202,285	$148,473
Transportation cost ⁽²⁾ ($ 000)	(2,387)	(1,705)	(4,279)	(2,896)
Revenue ($ 000)	$117,946	$83,988	$198,006	$145,577
Weighted average sales price ($ per bbl) ⁽³⁾	$107.50	$91.60	$102.25	$86.72

⁽¹⁾ Includes intersegment sales of $3.6 million in Q2 2011 and $8.8 million in YTD 2011 ($3.6 million in Q2 2010 and $7.6 million in YTD 2010), which were transacted at prevailing market prices and have been eliminated from the consolidated financial statements. The costs of these sales were $3.2 million in Q2 2011 and $8.0 million in YTD 2011 ($3.1 million in Q2 2010 and $7.2 million in YTD 2010)
⁽²⁾ Transportation cost is deducted in calculating above revenue whereas it is included in expenses in the consolidated statements of operations
⁽³⁾ Per unit prices are calculated using revenue divided by volumes of refined products sold

In Q2 2011 and YTD 2011, downstream revenue increased by 40 percent and 36 percent compared to Q2 2010 and YTD 2010, respectively. Higher revenue was primarily due to larger diesel and asphalt sales volumes and higher weighted average realized sales prices for all products were driven by stronger economic conditions in our sales market.

CRUDE OIL PURCHASES AND OPERATING COSTS


	Three months ended June 30		Six months ended June 30
	2011	2010	2011	2010
Crude oil purchases and operating costs ($ 000)	$106,216	$73,008	$181,589	$138,464
Crude oil purchases and operating costs ($ per bbl) ⁽¹⁾	$97.06	$79.63	$93.77	$82.49

⁽¹⁾ Per unit costs are calculated using crude oil purchases and operations costs divided by volumes of refined products sold

In Q2 2011, crude oil purchases and operating costs increased by 45 percent compared to levels in Q2 2010 (31 percent in YTD 2011 compared to YTD 2010), primarily due to higher refined crude oil volumes and higher benchmark crude oil input costs.

REFINING NETBACKS ⁽¹⁾


	Three months ended June 30		Six months ended June 30
	2011	2010	2011	2010
Refining netbacks ⁽¹⁾ ($ 000)	$11,730	$10,980	$16,417	$7,113
Refining netbacks (weighted average $ per bbl)	$10.44	$11.97	$8.48	$4.23
Refining netbacks (% of revenue)	10%	13%	8%	5%

⁽¹⁾ Refining netbacks is a non-GAAP measure and defined in the Advisory section of the MD&A. Refining netbacks are calculated by deducting crude oil purchases and operating costs from revenue. Refining netbacks are calculated before eliminating inter-segment sales and related costs of sales

Refining netbacks were seven percent higher in Q2 2011 compared to Q2 2010 and increased by 131 percent in YTD 2011 compared to YTD 2010. This increase was due to higher sales volumes of refined petroleum products and higher realized prices despite higher feedstock costs and wider heavy oil differentials in 2011. However, in Q2 2011, refining netbacks per unit and as a percentage of revenue were lower than in Q2 2010 primarily due to higher input costs (crude oil) in the current year period compared to the prior year period.

CORPORATE REVIEW

GAIN (LOSS) ON DISPOSITION OF PROPERTY, PLANT AND EQUIPMENT

In Q2 2011, the company realized a loss of $1.4 million primarily from the sale of the Marten Creek, Alberta natural gas properties. In YTD 2011, the company realized a gain of $27.9 million (YTD 2010 - $0.4 million), primarily from the sale of the Battrum, Saskatchewan crude oil properties.

GENERAL AND ADMINISTRATIVE EXPENSES

In Q2 2011, general and administrative ("G&A") expenses were $7.9 million ($18.4 million in YTD 2011), compared to $5.2 million in Q2 2010 ($11.6 million in YTD 2010), primarily due to personnel costs of an expanded staff required to support corporate growth. Additionally, the year to date increase reflects the timing of payment of 2010 bonuses in accordance with the company's compensation program.

FINANCE CHARGES

Finance charges include interest expense relating to the Convertible Debentures, First and Second Lien Senior Notes and the Revolving Credit Facility (the "Facility"), amortization of the Facility transaction costs, standby fees associated with the Facility and fees on letters of credit issued. Finance charges also include non-cash accretion charges with respect to the Convertible Debentures and First and Second Lien Senior Notes. Finance charges of $22.5 million in Q2 2011 (Q2 2010 - $11.9 million) and $49.0 million in YTD 2011 ($26.3 million in YTD 2010) were higher in 2011 than in 2010, because no amounts were capitalized in 2011, as they were in the comparative 2010 periods when Algar was still under construction.

COSTS OF REFINANCING LONG-TERM DEBT

As a result of the issuance of new Second Lien Senior Notes (the "New Notes") and the purchase and redemption of old First and Second Lien Senior Notes during Q2 2011, the company performed an analysis to determine whether the transaction was to be accounted for as a modification or an extinguishment of debt. The company determined that this transaction resulted partially in a modification and partially as an extinguishment. Accordingly, based on the information currently available, the company recorded $33.7 million as a discount on the New Notes and approximately $64.3 million was expensed as costs of refinancing long-term debt in the interim consolidated statement of operations. The final allocation has yet to be determined and adjustments, if necessary, will be reflected in future periods. The repayment of US dollar denominated Senior Notes in Q2 2011 also resulted in the realization of a foreign exchange gain of $11.5 million.

FOREIGN EXCHANGE GAINS

The value of the Canadian dollar relative to the U.S. dollar has risen throughout 2011. This had a significant impact on Connacher's results, upon settling US dollar-denominated transactions and translating its US dollar-denominated long-term debt and US dollar cash balances into Canadian dollars for financial reporting purposes. As a result of the higher Canadian dollar, we recorded foreign exchange gains of $18.5 million in YTD 2011 (YTD 2010 -foreign exchange loss of $8.6 million). These amounts are volatile in occurrence and can vary significantly from reporting period to reporting period.

SHARE BASED COMPENSATION


	Three months ended June 30		Six months ended June 30
($ in 000)	2011	2010	2011	2010
Charged to expense	$948	$1,121	$2,013	$3,006
Capitalized to property, plant and equipment	101	519	170	1,072
Total	$1,049	$1,640	$2,183	$4,078

The decrease in share based compensation charges in 2011 is primarily due to a lower number of options being granted in 2011 compared to 2010.

DEPLETION, DEPRECIATION AND AMORTIZATION ("DD&A")


	Three months ended June 30		Six months ended June 30
($ in 000)	2011	2010	2011	2010
Depletion and amortization expense on upstream property, plant and equipment	$20,120	$12,168	$35,474	$24,133
Depreciation expense on downstream property, plant and equipment	2,286	2,500	4,348	4,846
Depreciation on corporate property, plant and equipment	556	607	857	1,143
Amortization expense on exploration and evaluation assets	895	1,119	1,652	2,129
Total	$23,857	$16,394	$42,331	$32,251

Depletion expense is calculated using the unit-of-production method, based on estimated total proved and probable ("2P") reserves. Provision is made for future capital costs, which are estimated to be required to realize production from the company's 2P reserve base. Depletion expense was higher in the 2011 periods as a result of increased product sales volumes. Depletion equated to $12.31/boe of production in Q2 2011 (Q2 2010 - $15.73/boe of production). Downstream and corporate property, plant and equipment are depreciated over their estimated useful lives.

SHARE OF INTEREST IN AND LOSS ON ASSOCIATE

In March 2011, Petrolifera Petroleum Limited was acquired by Gran Tierra Energy Inc. ("Gran Tierra Energy"). Under the terms of the sale, Connacher's holding in Petrolifera were exchange for 3.3 million common shares and 841,000 common share purchase warrants of Gran Tierra Energy. As a result, the company recognized a loss of $2.3 million and transferred a loss of $4.5 million to the consolidated statement of operations which was previously recognized in other comprehensive loss. The company carries its investment in Gran Tierra Energy common shares and warrants at fair value on the balance sheet.

INCOME TAXES

The total income tax provision of $1.4 million in Q2 2011 and the income tax recovery of $5.5 million in YTD 2011 (Q2 2010 - $3.7 million recovery and YTD 2010 - $7.6 million recovery) included a current income tax provision of $119,000 in Q2 2011 and $189,000 in YTD 2011 (Q2 2010 - $150,000 and YTD 2010 - $356,000). The future income tax provision of $1.3 million in Q2 2011 and income tax recovery of $5.7 million in YTD 2011 (Q2 2010 -$3.8 million and YTD 2010 - $7.9 million) reflected the change in tax pools during the periods.

ADJUSTED EBITDA, CASH FLOW AND NET EARNINGS (LOSS)

Connacher realized improved operational performance in 2011 as a result of higher upstream and downstream sales volumes and higher product selling prices.

Upstream netbacks in Q2 2011 at $40.4 million were 163 percent higher than in Q2 2010; were 69 percent higher than in Q1 2011 and at $64.2 million for YTD 2011, were up 60 percent on a year to date basis. Downstream netbacks in Q2 2011 were up seven percent to $11.7 million compared to Q2 2010, were up 150 percent over Q1 2011 and for the YTD 2011 were $16.4 million, an increase of 130 percent over YTD 2010.

This improved performance resulted in higher reported cash flows and higher adjusted EBITDA.

Cash flow in Q2 2011 of $15.9 million ($0.04 per basic and diluted share outstanding) was 83 percent higher than the $8.7 million reported in Q2 2010 ($0.02 per basic and diluted share outstanding). Adjusted EBITDA of $37.6 million in Q2 2011 was up 90 percent from Q2 2010, was up 143 percent from Q1 2011 and at $53.4 million, was up 57 percent for YTD 2011. These much improved benchmarks underscore the operating progress realized in the reporting period largely related to a much expanded production base, combined with the benefit of improved pricing for crude oil, successively and year over year.

The company incurred a net loss of $44.2 million in Q2 2011 and $58.3 million in YTD 2011 compared to a loss of $31.7 million in Q2 2010 and a loss of $23.2 million YTD 2010, primarily due to higher finance charges, the cost of refinancing long-term debt and the impact of non-cash charges, including higher depletion, depreciation and amortization offset by foreign exchange gains.

LIQUIDITY

In Q2 2011, a significant development was the streamlining of our balance sheet through the successful sale, in both US and Canadian capital markets, of Senior Secured Second Lien Notes. Proceeds were used to fund a tender offer, pay associated costs to acquire previously outstanding high coupon debt which had been placed in the US high yield market during 2007 and 2009, with a modest balance added to working capital. We were able to reduce interest rates significantly, such that even with a higher level of overall indebtedness, we anticipate considerable annual savings as a consequence. Furthermore, we reduced our exposure to currency fluctuations with the placement of a portion of the new notes in the Canadian market with payment in Canadian dollars, our reporting currency.

Our market timing appears to have been excellent, affording us access, preferred rates and improved terms. Since the closing of this financing, the market has deteriorated considerably in a more risk-averse world. We successfully extended our maturities to 2018 and 2019, thereby avoiding the risk of not being able to access the market in 2014 and 2015, when our old indebtedness was scheduled to mature, coincident with a large amount of competing maturities at that time in the high yield market. This successful financing did not result in any new restrictive financial maintenance covenants or other limitations. Our financial condition is much more streamlined and less layered, with cash flow available to fund higher-return growth expenditures rather than being diverted to a less productive reduction of low cost debt. Additionally, our overall and prospective liquidity has improved, buoyed by the continued availability of an upsized syndicated revolving credit facility in the amount of $100 million, on which there are minimal current draws for letters of credit.

This streamlining of our balance sheet and expansion of our credit facility strengthened our financial position considerably.

The company intends to redeem the 4 ¾ percent $100 million Convertible Debentures when due on June 30, 2012.

In May 2011, the company issued at par US$550 million 8.5% Senior Secured Second Lien Notes due August 1, 2019 and CAD$350 million 8.75% Senior Secured Second Lien Notes due August 1, 2018 (the "New Notes") and capitalized transaction costs of $17.9 million relating to their issuance. Interest is payable semi-annually on February 1 and August 1 each year these notes are outstanding. These notes are secured on a second priority basis by liens on all of the company's existing and future property, excluding certain pipeline assets in the USA. The proceeds from the issuance of these notes were used to repurchase the old Senior Notes described in the following paragraph with a modest balance added to working capital.

The company repurchased US$783.5 million face value of the outstanding 11 ¾% First Lien Senior Notes and 10 ¼% Second Lien Senior Notes (the "Old Notes") (representing 99% of the Old Notes outstanding) for cash consideration of US$854.7 million (CAD$835.9 million). The company determined that this transaction resulted partially in a modification and partially as an extinguishment of debt. Accordingly, based on the information currently available, the company recorded $33.7 million as a discount on the New Notes and approximately $64.3 million was expensed as costs of refinancing long-term debt in the interim consolidated statement of operations. The final allocation has yet to be determined and adjustments, if necessary, will be reflected in future periods. The repayment of US-dollar denominated Senior Notes in Q2 2011 also resulted in the realization of a foreign exchange gain of $11.5 million.

In May 2011, the Revolving Credit Facility (the "Facility") was amended to increase the borrowing limit to $100 million and the maturity was extended to May 31, 2014. The company capitalized transaction costs of $470,000 with respect to the amendment of the Facility. At June 30, 2011, letters of credit of $5.7 million were issued under the Facility.

Higher accounts receivable balances as at June 30, 2011 compared to December 31, 2010 are primarily due to increases in revenue for the period. Inventory balances increased as at June 30, 2011 compared to December 31, 2010, primarily due to higher dilbit inventory volumes and increases in the value of our refined petroleum products. Lower accounts payable and accrued liabilities as at June 30, 2011, compared to December 31, 2010, reflect decreased liabilities associated with our capital program and decreases in accrued interest expense as a result of the recent debt refinancing.

In light of the current volatility of commodity prices, the US:Canadian dollar exchange rate and their combined significance to the company's operating performance and results, management constantly assesses alternative hedging strategies to protect the company's cash flow from the risk of severe downturns in crude oil prices, refined product pricing and adverse foreign exchange rate fluctuations. Although the company's integrated business model provides some risk mitigation, it does not provide a complete hedge, particularly against commodity price volatility. The purpose of any hedging activity undertaken is to ensure more predictable cash flow availability to supplement cash balances. This allows us to continue to service indebtedness, complete capital projects and protect the credit capacity of Connacher's oil and gas reserves in an uncertain or volatile commodity price environment.

As at June 30, 2011, the company had WTI risk management contracts on a portion of its crude oil sales and AECO risk management contracts on a portion of its natural gas consumption requirements. Details of these risk management contracts were provided earlier in this MD&A.

At June 30, 2011, the company had net working capital of $18.9 million (December 31, 2010 - $138.6 million), including $31.5 million of cash (December 31, 2010 - $19.5 million). As at June 30, 2011, about one-half of the year's capital expenditure program had been completed and, as most of the company's indebtedness is long-term in nature except for the Convertible Debentures, management believes that the company has sufficient liquidity and anticipated financial capacity, in combination with anticipated cash to be generated from operations in 2011 and net proceeds of the company's asset rationalization program, to fund its ongoing capital program and to continue to satisfy its financial obligations.

CAPITAL EXPENDITURES

Capital expenditures incurred are presented below:


	Three months ended June 30		Six months ended June 30
($000)	2011	2010	2011	2010
Upstream	$29,478	$50,354	$77,964	$165,870
Downstream	5,283	1,259	8,958	2,398
Cash-related capital expenditures	34,761	51,613	86,922	168,268
Non-cash related capital expenditures	4,227	7,563	(7,104)	9,180
Total capital expenditures	$38,988	$59,176	$79,818	$177,448

During Q2 2011, cash capital expenditures for maintenance and sustaining activities was $13 million, including $8 million at our oil sands operations to install down hole pumps, facility enhancements and for costs related to the mandatory turnaround at Algar; $4 million at our refinery related to boiler replacement, substation upgrade and other projects; and $1 million in our conventional operations and head office. Q2 2011 growth and special projects cash capital expenditures totaled $22 million, including $17 million in our conventional operations to purchase land and infrastructure related to our light gravity crude oil play at Penhold and completion and tie-in costs of our third Pekisko well at Twining; $4 million at our oil sands operations including the outright purchase of a personnel camp at Algar which was previously leased; and $1 million at our refinery.

YTD 2011 cash capital expenditures for maintenance and sustaining activities was $25 million including $14 million at our oil sands operations; $2 million in our conventional operations; $2 million for corporate and head office requirements; and $7 million at our refinery. First half 2011 growth and special projects cash capital expenditures of $62 million included $29 million related to our Twining and Penhold light gravity crude oil plays; $4 million at our oil sands operations; $27 million related to oil sands exploration activities; and $2 million at our refinery.

Non-cash related capital expenditures include asset retirement obligations accrued and revision for changes in estimated costs and rates of discount.

In Q2 2010, expenditures of $16 million were incurred on the Algar project; $8 million was incurred at Pod One for facility enhancement and pump installation expenditures; $6 million of capital expenditures were incurred for co-generation, pipeline facilities and the Great Divide expansion project; $20 million was capitalized interest, G&A costs and asset retirement costs and $8 million was capitalized for Algar pre-production expenditures.

For the YTD 2010, expenditures of $64 million were incurred on the Algar project, $18 million was incurred on Pod One to finish drilling and completing two additional steam-assisted gravity drainage ("SAGD") well pairs and for other facility enhancement and pump installation expenditures; $21 million was incurred in drilling 68 exploratory core holes at Great Divide, 13 (6.5 net) exploratory core holes at Halfway Creek and for seismic expenditures related to the 2010 winter exploration program; $17 million of capital expenditures were incurred for co-generation, pipeline facilities and the Great Divide Expansion project; $35 million was for capitalized interest, G&A and asset retirement costs; and $8 million of Algar pre-production costs was capitalized. Additionally, $12 million was incurred for conventional drilling, land acquisitions, seismic, well workovers, facilities and corporate and administrative assets. Included in the YTD 2010 expenditures were $10 million of non-cash capitalized items.

CAPITAL RESOURCES

Connacher's objectives in managing its cash, debt, equity, balance sheet and future capital expenditure programs are to safeguard its ability to meet its financial obligations, to maintain a flexible capital structure that allows financing options when a financing need arises and to optimize its use of short-term and long-term debt and equity at an appropriate level of risk. The company manages its capital structure and follows a financial strategy that considers economic and industry conditions, the risk characteristics and long-term nature of its underlying assets and its growth opportunities. It strives to continuously improve its credit rating and reduce its cost of capital. The company reported the following debt outstanding:


($ 000)	June 30, 2011	December 31, 2010
Convertible Debentures, 4 ¾%, due June 30, 2012	$97,764	$96,548
First Lien Senior Notes, 11 ¾%, due July 15, 2014	88	184,176
Second Lien Senior Notes, 10 ¼%, due December 15, 2015	3,671	566,663
Second Lien Senior Notes, 8.75%, due August 1, 2018	342,762	-
Second Lien Senior Notes, 8.5%, due August 1, 2019	486,548	-
Total	$930,833	$847,387

Connacher's capital structure and certain financial ratios are noted below:


($ 000)	June 30, 2011	December 31, 2010
Long-term debt ⁽¹⁾	$829,310	$847,387
Shareholders' equity	467,057	526,985
Total Long-term debt plus Equity ("capitalization")	$1,296,367	$1,374,372
Long-term debt to capitalization ⁽²⁾	64%	62%

⁽¹⁾ Long-term debt is stated at its carrying value, which is net of transaction costs including current portion
⁽²⁾ Calculated as long-term debt divided by the book value of shareholders' equity plus long-term debt

As at June 30 2011, the company's net long-term debt (long-term debt, net of cash on hand) was $798 million. Net long-term debt to capitalization was 62 percent. The long-term debt agreements contain certain provisions, which restrict the company's ability to incur additional indebtedness, pay dividends, to make certain payments and to dispose of collateralized assets. At June 30, 2011, the company was in compliance with all of the terms of its debt agreements.

OUTLOOK

We anticipate stronger financial results in 2011 compared to 2010, due to higher bitumen production and sales volumes, as a result of more stable operating performance at Pod One and due to a full year contribution from Algar. We also anticipate strong results from our refining operations. Our focus in 2011 continues to be on optimizing our production at Great Divide, rationalizing non-core conventional and non-cash generating assets, expanding our new resource plays in central Alberta areas with drilling success, securing a joint venture partner to assist in developing non-producing oil sands assets at Great Divide and delivering successive and sustained improvement in operating and financial results. We have already completed the successful refinancing of our long-term secured senior notes in Q2 2011 as noted above and have advanced the other integral aspects of our growth and value enhancement strategy, the foundation of which is strong and reliable production from our oil sands operations employing technical innovations to improve productivity and efficiency.

Future cash flows will be substantially sheltered from current cash taxes by the company's tax pools, which currently exceed $1.2 billion and which will be augmented by future capital expenditures.

Production Guidance

The company's 2011 revised production guidance and cash capital expenditure budget follows. We have adjusted our full year bitumen production guidance after taking into account actual production in YTD 2011, which reflected the significant contribution from Algar, offset by adverse market and weather conditions, leading to curtailments in Q1 2011. Going forward, we anticipate a modest slowdown in the originally estimated ramp-up at Algar, arising in part from wells coming on stream later than anticipated, less than planned steam injectivity at one well pad due to header pressure constraints and a recent decision to reduce reservoir pressure in order to increase steam injection to desired rates and position for the introduction of additional low pressure down-hole pumps in 2012. Over time, we anticipate this decision will result in increased production while optimizing the efficiency of our SAGD process. Also, having just received regulatory approval, we are scheduling the installation of a diluent recovery unit ("DRU") at Pod One in September 2011. The downtime required to install the DRU, not anticipated when we last prepared our guidance, will impact short term production levels but we believe will improve long term economics. During this downtime, we also plan to install new pumps in two Pod One wells and conduct other maintenance activity as Pod One did not undergo a turnaround this year. Offsetting the downward adjustments to forecast bitumen production, we do expect our conventional production will exceed our original forecasts. This will be a mitigating factor both in respect of volumes and netbacks as new volumes are added from our central Alberta drilling on a risk adjusted basis to our guidance levels.


2011 revised production guidance
Bitumen Production (bbl/d)		13,000 - 14,500
Conventional Production (boe/d) ⁽¹⁾		1,300 - 1,600
Total Upstream Production (boe/d)		14,300 - 16,100

⁽¹⁾ Excludes production from Battrum and Marten Creek/Randall properties from the respective closing dates of the sale of such properties

We anticipate exiting 2011 at, or above the higher ranges of the full year production guidance.

Capital Expenditure Budget

There have been modest immaterial changes to individual categories within our total budget for capital expenditures and although we have the financial wherewithal to incur more outlays, we believe it is prudent in the current environment to be cautious in our programs until there is increased evidence of less volatility in product pricing and conditions affecting market access for our heavy oil production volumes. We have established a solid land position on our major projects with no impending expiries or obligations. We intend to explore joint venture alternatives to assist in funding future expansion at Great Divide but we have no deadlines or other requirements of an obligatory nature in respect of having to complete new projects by any specific date.

The company's cash capital spending budget for full year 2011 remains unchanged at $162 million.


2011 capital budget on a cash basis		($ in millions)
Sustaining and maintenance capital		$37
	Oil sands
	Conventional	2
	Refining	12
	Corporate	5
Total sustaining and maintenance		56
Growth capital and special projects
	Oil sands	6
	Conventional	61
	Refining	5
	Exploration	26
	EIA and Algar expansion engineering	8
Total growth capital and special projects		106
Total 2011 capital budget on cash basis		$162

Actual production achieved and capital expenditures incurred during 2011 could differ materially from these estimates - please see "Forward-Looking Information" in the Advisory section and "Risk Factors".

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

In the normal course of business, the company is obligated to make future payments. These obligations represent contracts and other commitments that are known and non-cancellable. Refer to the company's 2010 annual MD&A which summarizes contractual obligations and commitments as at December 31, 2010. At June 30, 2011, the company did not have any additional material contractual obligation and commitments. There were no material changes to the commitments noted during Q2 2011.

SHARES OUTSTANDING

As at June 30, 2011, the number of common shares issued and outstanding was 448.1 million (December 31, 2010 - 447.2 million). The increase in 2011 was due to shares issued in respect of share option exercises and shares issued to non-employee directors in respect of director share awards.

As at August 11, 2011, the company had the following securities issued and outstanding.

448,259,991 common shares;
25,403,193 stock options under the company's Stock Option Plan; and
312,500 share units under the Share Award Incentive Plan.

Additionally, the company's $100 million of outstanding Convertible Debentures are convertible at the option of the holder at a conversion price of $5.00 per common share into common shares of the company.

RISK FACTORS AND RISK MANAGEMENT

Connacher is engaged in the oil and gas exploration, development, production, and refining industry. This business is inherently risky and there is no assurance that hydrocarbon reserves will be discovered and economically produced. Operational risks include competition, reservoir performance uncertainties, production reliability, performance of third party services and supplies, environmental factors, and regulatory and safety concerns. Financial risks associated with the petroleum industry include fluctuations in commodity prices, interest rates, currency exchange rates and the costs of goods and services.

Connacher's financial and operating performance is potentially affected by a number of factors including, but not limited to, risks associated with the oil and gas industry, commodity prices and exchange rates, the impacts of varying weather conditions on product sales, operating performance, environmental legislation, changes to royalty and income tax legislation, credit and capital market conditions, credit risk for failure of performance of third parties and other risks and uncertainties described in more detail in Connacher's AIF for the year ended December 31, 2010 filed with securities regulatory authorities.

Connacher employs highly qualified people, uses sound operating and business practices and evaluates all potential and existing wells using the latest applicable technology. The company has designed policies and procedures for compliance with government regulations and has in place an up-to-date emergency response program. Connacher monitors and seeks to adhere to environment and safety policies and standards. Asset retirement obligations are recognized upon acquisition, construction and development of the assets. Connacher maintains property and liability insurance coverage. The coverage provides a reasonable amount of protection from risk of loss; however, not all risks are foreseeable or insurable.

ACCOUNTING POLICIES AND ESTIMATES

Adoption of International Financial Reporting Standards

On January 1, 2011, the company adopted International Financial Reporting Standards ("IFRS") for financial reporting purposes, using a transition date of January 1, 2010. The financial statements for the six months ended June 30, 2011, including required comparative information, have been prepared in accordance with International Financial Reporting Standards 1, First-time Adoption of International Financial Reporting Standards, and with International Accounting Standard ("IAS") 34, Interim Financial Reporting, as issued by the International Accounting Standards Board ("IASB"). Previously, the company prepared its interim and annual consolidated financial statements in accordance with Canadian generally accepted accounting principles ("previous GAAP"). Canadian GAAP now comprises IFRS.

The following provides a summary reconciliation of Connacher's 2010 net loss before taxes calculated in accordance with previous GAAP and Connacher's 2010 net loss after taxes in accordance with IFRS, along with a discussion of the significant IFRS accounting policy changes.

Summary Net Earnings Reconciliation


(Canadian dollar in thousands)		Q2 2010	YTD 2010
Net loss before taxes per previous GAAP		$(37,963)	$(34,941)
	Exploration and evaluation expense	-	(140)
	Depletion, depreciation, amortization and impairment	884	2,967
	Gain on disposition of oil and gas properties	-	432
	Compensation	16	22
	Unwinding of discount on decommissioning liabilities	243	450
	Interest in associate	(1,597)	(1,686)
	Unrealized loss on revaluation of Convertible Debentures	3,043	2,085
	Income taxes	3,657	7,599
Net loss after taxes per IFRS		$(31,717)	$(23,212)

Accounting Policy Changes

The following discussion explains the significant differences between Connacher's previous GAAP accounting policies and those applied by the company under IFRS. IFRS policies have been retrospectively and consistently applied except where specific IFRS 1 optional and mandatory exemptions permitted an alternative treatment upon transition to IFRS for first-time adopters. IFRS 1 requires the presentation of comparative information as at the January 1, 2010 ("transition date") and subsequent comparative periods as well as the consistent and retrospective application of IFRS accounting policies. To assist with the transition, the provisions of IFRS 1 allow for certain mandatory and optional exemptions for first-time adopters. The significant exemptions applied under IFRS 1 in preparing the interim consolidated financial statements are set out below followed by a discussion regarding the impact of individually significant items.

Deemed cost election for oil and gas properties

Under previous GAAP, the company followed the "full cost accounting" method for accounting of oil and gas activities, in which all costs directly associated with the acquisition of, the exploration for, and the development of oil and natural gas reserves were capitalized on a country-by-country cost centre basis (Upstream in Canada). Costs accumulated within each country cost centre were depleted using the unit-of-production method, based on proved reserves, determined using estimated future prices and costs. Upon transition to IFRS, the company was required to adopt new accounting policies for upstream activities, including exploration and evaluation costs and development costs. Under IFRS, exploration and evaluation costs are those expenditures for an area where technical feasibility and commercial viability has not yet been determined. They are presented separately on the balance sheet as exploration and evaluation assets and may or may not be amortized based on the company's accounting policy. Development costs include those expenditures for areas where technical feasibility and commercial viability has been determined. They are presented as a part of property, plant and equipment on the balance sheet and are depleted and depreciated on an area-by-area level. The company adopted the IFRS 1 exemption whereby the company deemed its January 1, 2010 IFRS upstream asset costs to be equal to its previous GAAP historical upstream property, plant and equipment net book value. Accordingly, exploration and evaluation costs were deemed equal to the unproved properties balance and the development costs were deemed equal to the balance of the upstream full cost pool balance. The development costs were allocated to the underlying property, plant and equipment assets on a pro rata basis, using proved reserves values at the transition date.

Leases

The company has elected not to reassess whether an arrangement contains a lease under International Financial Reporting Interpretations Committee Interpretation 4 for contracts that were assessed under previous GAAP.

Business Combinations

IFRS 3, "Business Combinations" has not been applied to business combinations that occurred before the transition date.

Borrowing Costs

Borrowing costs directly attributable to the acquisition or construction of qualifying assets were not retrospectively restated prior to transition date.

Additional exemptions applied

The company applied additional exemptions for cumulative foreign currency translation differences, compensation and decommissioning liabilities, which are explained in the respective paragraphs below.

Exploration and Evaluation

As explained above under "Deemed cost election for oil and gas properties", the company reclassified $111.0 million to exploration and evaluation assets at June 30, based on the deemed carrying amounts representing unproved properties balance as determined under previous GAAP.

Additionally, under IFRS, costs incurred prior to obtaining the legal rights to explore are expensed whereas under previous GAAP these costs were capitalized as a part of property, plant and equipment. Accordingly, the company recognized exploration and evaluation expense in the consolidated statement of operations of $nil and $140,000 in the three and six months ended June 30, 2010, respectively, and recorded the corresponding decrease to the property, plant and equipment. This adjustment also resulted in a decrease of the cash flow from operating activities with the same amounts for the periods under IFRS compared to the reported amounts under previous GAAP.

The effect of the above adjustment on retained earnings was a reduction of $105,000 after tax benefits of $35,000 for the six months ended June 30, 2010.

Depletion, Depreciation and Amortization

Under previous GAAP, the development costs were depleted using the unit-of-production method calculated for each country cost centre. Under IFRS, development costs are depleted using the unit-of-production method based on estimated proved and probable reserves determined using estimated future prices and costs calculated at the established area level. Further, as permitted under IFRS, the company elected to adopt the accounting policy of amortizing certain exploration and evaluation assets (undeveloped land) over the lease term. Under previous GAAP, undeveloped land was only tested for impairment and any resulting impairment was included in the full cost pool for depletion purposes. As a result, depletion and amortization expense decreased by $884,000 and $3.0 million in the three and six month periods ended June 30, 2010, respectively, with a corresponding increase to exploration and evaluation assets and property, plant and equipment.

The effect of the above adjustment on retained earnings was an increase of $660,000 and $2.2 million after tax expense of $220,000 and $743,000 for the three and six month periods ended June 30, 2010, respectively.

Impairment

Under previous GAAP, capitalized costs of oil and gas properties and goodwill were tested for impairment separately, as explained below. Under IFRS, capitalized costs of oil and gas properties and goodwill are allocated to cash-generating units for the purpose of the impairment tests, as explained below.

Under previous GAAP, oil and gas property impairments were recognized if their carrying amount exceeded the undiscounted cash flows from proved reserves for a country cost centre. Impairment was measured as the amount by which the carrying value exceeded the sum of the fair value of the proved and probable reserves and the costs of unproved properties. The company did not report any impairment under previous GAAP on December 31, 2009 and December 31, 2010.

Under previous GAAP, goodwill was tested with reference to the reporting unit. Under IFRS, impairment is recognized if the carrying value exceeds the recoverable amount for a cash-generating unit. A cash-generating unit is defined as the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. The company performed an impairment test by allocating all capitalized costs of oil and gas properties, goodwill and directly related liabilities in applicable cash-generating units based on their ability to generate largely independent cash flows (smaller level than previous GAAP) and determined an impairment charge of $113.9 million on January 1, 2010 relating to its Northwest Alberta cash-generating unit (included in the upstream segment). An impairment charge, amounting to $103.7 million, was allocated to goodwill and $10.2 million was allocated to oil and gas properties, with the corresponding decrease to retained earnings of $111.3 million, net of a tax benefit of $2.6 million. The recoverable amount used in the impairment calculation was determined using the fair value less costs to sell, based on a cash flow valuation model.

Asset and Liabilities Held For Sale and Disposition of Oil and Gas Properties

Under previous GAAP, proceeds from dispositions of oil and gas properties were deducted from the full cost pool without recognition of a gain or loss and the accounting standard for classification of assets and liabilities as held for sale was not applicable to the disposition of oil and gas properties unless the deduction resulted in a change to the country cost centre depletion rate of 20 percent or greater, in which case a gain or loss was recorded and assets and liabilities were classified as held for sale.

Under IFRS, gains or losses are recorded on dispositions and are calculated as the difference between the proceeds and the net book value of the asset disposed and the requirements of the classification of assets and liabilities as held for sale are applicable to all oil and gas properties.

The company classified its assets and liabilities relating to certain oil and gas properties (part of the Northern Alberta and Southwest Saskatchewan cash-generating units) as held for sale on December 31, 2010 and recorded them at lower of their carrying amount or fair value less costs to sell. The adjustment resulted in a classification of carrying amount of property, plant and equipment totaling $54.3 million, exploration and evaluation assets totaling $5.7 million and asset retirement obligation totaling $10.9 million to asset and liabilities classified as held for sale. At December 31, 2010, the impairment charge of $4.5 million was recognized based on the difference between the December 31, 2010 net book value of the assets prior to classification and the recoverable amount. The recoverable amount was determined using fair value less costs to sell which was derived from the sale price agreed under the binding sale agreement with the third party.

In the six months ended June 30, 2010, the company recognized a gain of $432,000 on sale of certain oil and gas properties under IFRS with a corresponding decrease of the carrying amount of property, plant and equipment. There were no dispositions in the three months ended June 30, 2010. The effect of the adjustments on retained earnings was an increase of $324,000 after tax benefit of $108,000 for the six months ended June 30, 2010.

Foreign Currency

In accordance with IFRS 1, the company has elected to deem all foreign currency translation differences that arose prior to the transition date in respect of foreign operations and the company's share of associate's translation differences to be nil and reclassified amounts recorded in other comprehensive loss as determined in accordance with previous GAAP to retained earnings. As a result, accumulated other accumulated comprehensive loss was decreased by $16.2 million with a corresponding decrease to retained earnings as at January 1, 2010.

Compensation - Defined Benefit Plan

The company elected to use the IFRS 1 exemption whereby the cumulative unamortized net actuarial gains and losses of the company's defined benefit plan are charged to retained earnings on January 1, 2010. This resulted in a decrease of $722,000 to the accrued benefit obligation and a corresponding increase to retained earnings.

Asset Retirement Obligation

Under previous GAAP, the asset retirement obligation was measured at the estimated fair value of the retirement and decommissioning expenditures expected to be incurred. Liabilities were not remeasured to reflect period end discount rates. Under IFRS, the asset retirement obligation is measured as the best estimate of the expenditure to be incurred and requires that the asset retirement obligation be remeasured using the period end discount rate.

In conjunction with the IFRS 1 exemption regarding oil and gas properties discussed above, the company was required to remeasure its decommissioning liabilities upon transition to IFRS and recognize the difference in retained earnings. The application of this exemption resulted in a $20.9 million increase to the decommissioning liabilities on the company's consolidated balance sheet as at January 1, 2010 and a charge to retained earnings of $15.6 million net of tax benefit of $5.2 million. Subsequent IFRS remeasurements of the obligation are recorded through property, plant and equipment with an offsetting adjustment to the decommissioning liabilities. As at June 30, 2010 and December 31, 2010, excluding the January 1, 2010 adjustment, the company's decommissioning liabilities increased by $10.7 million and $10.9 million, respectively, which primarily reflects the remeasurement of the obligation using the company's discount rate of 3.2 percent as at June 30, 2010 and 3.2 percent as at December 31, 2010. The use of the lower discount rate resulted in a decrease in the unwinding of the discount amounting to $243,000 and $450,000 in the three and six month periods ended June 30, 2010, respectively.

Investment in Associate

As at June 30, 2010 and December 31, 2010, the company owned 26.9 million Petrolifera common shares, representing 18.5 percent of Petrolifera's issued and outstanding common shares and 6.8 million Petrolifera share purchase warrants. Petrolifera was accounted for as an equity investment in associate. The following are the key differences in IFRS compared to previous GAAP.

As a part of the company's transition to IFRS, the company recorded the adjustments to its share of loss, other comprehensive loss and dilution loss with a corresponding effect on the investment account balance and retained earnings reflecting the adjustments to comply Petrolifera's financial position and results in accordance with IFRS and the accounting policies adopted by the company on its transition date.
Under previous GAAP, the company did not record the investment in share purchase warrants separately and allocated the total cost of $11.9 million for additional shares purchased in 2009 to an investment in equity-accounted investments on the consolidated balance sheet whereas under IFRS, common share purchase warrants meet the definition of the derivative asset that needs to be bifurcated from the host contract (investment in associate) and recorded at the fair value at the end of each reporting period, with changes recorded in the statement of operations. As a result, the company recorded the fair value of common share purchase warrants on January 1, 2010 by increasing other assets and retained earnings.
Under IFRS, assets relating to the investment in Petrolifera were classified as assets held for sale on December 31, 2010. Equity accounting ceased on December 31, 2010 and the carrying amount of investment in associate was classified as assets held for sale and recorded at the lower of its carrying amount and fair value less costs to sell. Under previous GAAP, the accounting standard for classification of assets and liabilities as held for sale was not applicable to the disposition of investment in associate and accordingly, no classification of assets held for sale was reported. However, under previous GAAP, the company recognized impairment to record the investment at its fair value.

Taxes

The company recorded the differences to the amounts reported for deferred taxes under previous GAAP compared to IFRS for flow-through shares, discount on issue of long-term debt, inter-company capital losses and the effects of IFRS transition adjustments.

Debt

Under previous GAAP, the Convertible Debentures were treated as a compound financial instrument with a debt and equity component. Under IFRS, the equity component is considered an embedded derivative. As permitted under IFRS, the company designated the Convertible Debentures as "fair value through profit and loss" and accordingly, recorded Convertible Debentures at fair value at each reporting end with changes reported within the consolidated statement of operations. As a result, the equity portion of Convertible Debentures was reduced by $16.8 million with a corresponding increase to retained earnings on January 1, 2010, June 30, 2010 and December 31, 2010. In addition, the adjustment resulted in removal of previously recorded accretion expense and recognition of unrealized gains and losses on revaluation. Accordingly, a decrease in finance charges of $3 million and $2 million in the three and six month periods ended June 30, 2010 was recorded with a corresponding change to long-term debt.

Reclassifications

In order to comply with the presentation of consolidated statement of operations adopted by the company under IFRS, in downstream segment, the company classified certain transportation costs totaling $1.7 million and $2.9 million to revenue for the three and six month periods ended June 30, 2010, respectively. In addition, the company also classified $942,000 and $1.8 million from operating expenses to general and administrative expenses during the three and six month periods ended June 30, 2010, respectively.

Further, under previous GAAP, the unwinding of the discount on decommissioning liabilities was included as a part of depletion, depreciation and accretion expense in the consolidated statements of operations and comprehensive loss. Under IFRS this amount has been reclassified to finance costs ($748,000 and $1.4 million in the three and six months ended June 30, 2010, respectively).

Changes to the Statement of Cash flow

The following is a reconciliation of the company's cash from operating and investing activities reported in accordance with previous GAAP to cash from operating and investing activities reported in accordance with IFRS for the six months ended June 30, 2010:


(Canadian dollar in thousands)		Six months ended June 30, 2010
Cash from operating activities under previous GAAP		$1,102
	Exploration and evaluation expenses	(140)
Cash from operating activities under IFRS		$962

Cash used in investing activities under previous GAAP		$(187,344)
	Exploration and evaluation expenses	140
Cash used in investing activities under IFRS		$(187,204)

There was no difference between previous GAAP and IFRS related to cash from financing activities.

Earnings (loss) per share

Basic and diluted earnings (loss) per share under IFRS were impacted by the IFRS earnings (loss) adjustments discussed above.

Critical Accounting Estimates

Upstream assets and reserves

Reserve estimates can have a significant impact on earnings, as they are a key input to the company's DD&A calculations and impairment tests. Costs accumulated within each area are depleted using the unit-of-production method based on proved and probable reserves, using estimated future prices and costs. Costs subject to depletion include estimated future costs to be incurred in developing proved and probable reserves. A downward revision in reserves estimates or an increase in estimated future development costs could result in the recognition of a higher DD&A charge.

Upstream assets, including exploration and evaluation costs and development costs, are aggregated into cash generating units based on their ability to generate largely independent cash flows. If the carrying value of the cash-generating unit exceeds the recoverable amount, the cash-generating unit is written down with an impairment recognized in net earnings. The recoverable amount of an asset or cash-generating unit is the greater of its fair value, less costs to sell and its value in use. Fair value less costs to sell may be determined using discounted future net cash flows of proved and probable reserves, using forecast prices and costs. A downward revision in reserves estimates could result in the recognition of impairments charged to net earnings. Reversals of impairments are recognized when there has been a subsequent increase in the recoverable amount. In this event, the carrying amount of the asset or cash-generating unit is increased to its revised recoverable amount with an impairment reversal recognized in net earnings.

The process of estimating reserves is complex. It involves significant interpretations of and judgments on available geological, geophysical, engineering and economic data. To estimate economically recoverable reserves and the related future cash flows, many factors and assumptions are incorporated such as expected reservoir characteristics, future production rates based on historical performance, expected future operating and investment activities, future dilbit, diluent, crude oil and natural gas prices and quality differentials and assumed effects of regulation by government agencies.

Forecasts of future rates of production, commodity prices, operating and capital cost structures and the timing of future expenditures are subject to numerous uncertainties and significant judgment. In addition, properties will, over a period of time, actually deliver bitumen, crude oil and natural gas in quantities different than originally estimated due to changes in reservoir performance. Reserve estimates can be revised upward or downward and such adjustments can be material.

Asset retirement obligations

The company is required to provide for future removal and site restoration costs by estimating these costs in accordance with existing laws, contracts or other policies. These estimated costs are charged to earnings and the appropriate liability account over the expected service life of the asset. When the future removal and site restoration costs cannot be reasonably determined, a contingent liability may exist. Contingent liabilities are charged to earnings only when management is able to determine the amount and the likelihood of the future obligation. The company estimates future retirement costs based on current costs, as estimated by the company's engineers, adjusted for inflation and credit risk. These estimates are subjective.

Legal and other contingent matters

In respect of these matters, the company is required to determine whether a loss is probable based on judgment and interpretation of laws and regulations and determine if such a loss can be estimated. When any such loss is determined, it is charged to earnings. Management continually monitors known and potential contingent matters and makes appropriate provisions by charges to earnings when warranted by circumstance.

Income taxes

The company follows the liability method of accounting for income taxes. Under this method, deferred income taxes are recorded for the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates. Current income taxes for the current and prior periods are measured at the amount expected to be recoverable from or payable to the taxation authorities based on the income tax rates enacted or substantively enacted at the end of the reporting period. The deferred income tax assets and liabilities are adjusted to reflect changes in enacted or substantively enacted income tax rates that are expected to apply, with the corresponding adjustment recognized in net earnings or in shareholders' equity depending on the item to which the adjustment relates.

Tax interpretations, regulations and legislation in the various jurisdictions in which the company and its subsidiaries operate are subject to change. As such, income taxes are subject to measurement uncertainty and the interpretations can impact net earnings through the income tax expense arising from the changes in deferred income tax assets or liabilities.

Derivative financial instruments

We may use derivative financial instruments to manage exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. Derivative financial instruments are not used for speculative purposes. We enter into financial transactions to help reduce exposure to price fluctuations with respect to commodity purchase and sale transactions to achieve targeted investment returns and growth objectives, while maintaining prescribed financial metrics. These transactions generally are swaps, collars or options and are generally entered into with major financial institutions or commodities trading institutions as counterparties. We may also use derivative financial instruments, such as interest rate swap agreements, to manage the fixed interest rate debt and related cost of borrowing. Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using the mark-to-market method of accounting whereby instruments are recorded in the Consolidated Balance Sheet as either an asset or liability, with changes in fair value recognized in net earnings. Realized gains or losses from financial derivatives related to crude oil and natural gas prices are recognized in revenues as the related sales occur. Unrealized gains and losses are recognized in revenues at the end of each respective reporting period. The estimate of fair value of all derivative instruments is based on quoted market prices or, in their absence, third-party market indications and forecasts. The estimated fair value of financial assets and liabilities, by their very nature, is subject to measurement uncertainty.

DISCLOSURE CONTROLS AND PROCEDURES

The company's Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO") have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to the company is made known to the company's CEO and CFO by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by the company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation.

INTERNAL CONTROLS OVER FINANCIAL REPORTING

The CEO and CFO have designed, or caused to be designed under their supervision, internal controls over financial reporting to provide reasonable assurance regarding the reliability of the company's financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP.

The company's CEO and CFO are required to cause the company to disclose any change in the company's internal controls over financial reporting that occurred during the company's most recent interim period that has materially affected, or is reasonably likely to materially affect, the company's internal controls over financial reporting. No changes in the company's internal controls over financial reporting were identified during such period that have materially affected, or are reasonably likely to materially affect, the company's internal controls over financial reporting.

It should be noted that no matter how well conceived, a control system, including the company's disclosure and internal controls and procedures, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud. In reaching a reasonable level of assurance, management necessarily is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

ADVISORY SECTION

FORWARD-LOOKING INFORMATION

This report, including the Letter to Shareholders and the 2011 outlook contained in the MD&A, contains forward‐looking information including but not limited to, anticipated future operating and financial results, forecast netbacks, expectations of future production, anticipated sales volumes, anticipated reductions in operating costs, expected operational reliability at Pod One, future SORs, anticipated capital expenditures for 2011, anticipated sources of funding for capital expenditures and current and future financial obligations, future liquidity, future development and exploration activities, including the planned installation of a DRU at Pod One and new pumps in two Pod One wells and the timing of building Pad 104 for Pod One, anticipated impact of using rail to transport dilbit to new markets, anticipated impact of technical innovations on productivity and SORs and possible expansion of the application of SAGD^+TM on additional well pairs, anticipated savings resulting from the Corporation's refinancing activities, future plant capacity utilization, future possible joint venture arrangements, timing of receipt of regulatory approvals for future expansion at oil sands properties, the proposed sale of Connacher's interest at Halfway Creek, the possible future redemption of Connacher's Convertible Debentures and further rationalization activity. Forward‐looking information is based on management's expectations regarding future growth, results of operations, production, future commodity prices and foreign exchange rates, future capital and other expenditures (including the amount, nature and sources of funding thereof), plans for and results of drilling activity, environmental matters, business prospects and opportunities and future economic conditions.

The 2011 outlook contained in the MD&A is based on certain assumptions regarding operational performance including, among others, steam generation levels and SORs, timing and duration of planned maintenance activities and results thereof, unplanned operational upsets, well productivity, realized netbacks which may accelerate or delay our capital program, including planned facility optimization programs and future market conditions and is subject to risk and uncertainties, including those risk and uncertainties described above. Additional risks and uncertainties are described in further detail in Connacher's Annual Information Form ("AIF") for the year ended December 31, 2010 which is available at www.sedar.com.

Although Connacher believes that the expectations in such forward‐looking information are reasonable, there can be no assurance that such expectations shall prove to be correct. The forward‐looking information included in this report is expressly qualified in its entirety by this cautionary statement. The forward‐looking information included in this report is made as of August 11, 2011 and Connacher assumes no obligation to update or revise any forward‐looking information to reflect new events or circumstances, except as required by law.

Statements relating to "reserves" and "resources" are deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future. Certain information and assumptions relating to the reserves and resources reported herein are set forth in Connacher's AIF which is available at www.sedar.com. The reserves and resources estimates of Connacher's properties described herein are estimates only. The actual reserves and resources on Connacher's properties may be greater or less than those calculated. In addition, reference should be made to Connacher's AIF for additional information pertaining to Connacher's resources, including the risks and level of uncertainty associated with the recovery thereof.

Contingent resources means those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingent resources disclosed herein were assigned in regions with lower core-hole drilling density than the reserve regions and are outside Connacher's current areas of application for development. These resource estimates are not classified as reserves at this time, pending further reservoir delineation, project application, facility and reservoir design work, preparation of firm development plans and company approvals. Contingent resources entail additional commercial risk than reserves. Adjustments for commercial risks were not incorporated in the estimates of contingent resources set forth herein. Additional information relating to the estimate of contingent resources included in this report is included in the AIF. Best estimate contingent resources were assigned to mapped regions of oil-in-place of identified accumulations outside areas of application for development with at least 10 m of continuous bitumen pay along with a best estimate recovery factor. There is no certainty that it will be commercially viable to produce any portion of the contingent resources. Prospective resources means those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective resources disclosed herein were assigned in unexplored regions of Connacher's acreage. Prospective resources entail commercial risk not applicable to reserves. The prospective resource estimate set forth herein has been risked for the chance of discovery but not for the chance of development and hence are considered partially risked estimates. There is no certainty that any portion of the prospective resources will be discovered. If a discovery is made, there is no certainty that it will be commercially viable to produce any portion of the prospective resources. Additional information relating to the estimate of prospective resources included herein is included in the AIF. "Best Estimate" is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability that the quantity actually recovered will equal or exceed the best estimate.

NON-GAAP MEASUREMENTS

The MD&A contains terms commonly used in the oil and gas industry, such as cash flow, cash flow per share, netback, refinery margins or netback and adjusted earnings before interest, taxes, depreciation and amortization ("adjusted EBITDA"). These terms are not defined by the financial measures used by Connacher to prepare its financial statements and are referred to herein as non-GAAP measures. These non-GAAP measures should not be considered an alternative to, or more meaningful than, cash provided by operating activities or net earnings (loss) as determined in accordance with Canadian GAAP as an indicator of Connacher's performance. Management believes that in addition to net earnings (loss), cash flow, netbacks or net margins and adjusted EBITDA are useful financial measurements which assist in demonstrating the company's ability to fund capital expenditures necessary for future growth or to repay debt. Connacher's determination of cash flow, netbacks, margins and adjusted EBITDA may not be comparable to that reported by other companies.

CASH FLOW

Cash flow and cash flow per share do not have standardized meanings prescribed by Canadian GAAP and therefore may not be comparable to similar measures used by other companies. Cash flow includes all cash flow from operating activities and is calculated before changes in non-cash working capital, pension funding and decommissioning liabilities settled. The most comparable measure calculated in accordance with Canadian GAAP is cash flow from operating activities. Cash flow from operating activities is reconciled with the cash flow for six months ended June 30, 2011 and 2010 below. Cash flow per share is calculated by dividing cash flow by the calculated weighted average number of shares outstanding. Management uses this non-GAAP measurement (which is a common industry parameter) for its own performance measure and to provide its shareholders and investors with a measurement of the company's efficiency and its ability to fund future growth expenditures.

NETBACKS

Upstream netbacks, including by product, are calculated by deducting the related diluent, transportation, field operating costs and royalties from upstream revenues. Downstream netbacks are calculated by deducting crude oil purchases and operating and transportation costs from refining sales revenues.

ADJUSTED EBITDA

Adjusted EBITDA is calculated as net earnings (loss) before finance charges, current and deferred income tax provisions and recoveries, depletion, depreciation and amortization, exploration and evaluation expense, share-based compensation, foreign exchange gains/losses, unrealized gains/losses on risk management contracts, interest and other income, gain (loss) on disposition of property, plant and equipment, defined benefit plan expense, share of interest in and loss on associate and costs of refinancing long-term debt.

RECONCILIATIONS OF NON-GAAP MEASURES

Cash flow is reconciled to cash flow from operating activities and upstream and downstream netbacks and adjusted EBITDA are reconciled to net earnings (loss) herein.

RECONCILIATIONS OF CASH FLOW TO CASH FLOW FROM OPERATING ACTIVITIES


		Three months ended June 30		Six months ended June 30
($000)		2011	2010	2011	2010
Cash flow		$15,873	$8,669	$10,103	$12,476
	Non-cash working capital changes	(25,378)	832	(15,385)	(11,046)
	Decommissioning liabilities settled	(30)	(100)	(813)	(468)
Cash flow from operating activities		$(9,535)	$9,401	$(6,095)	$962

RECONCILIATIONS OF UPSTREAM AND DOWNSTREAM NETBACKS TO NET LOSS


(Canadian dollar in thousands)	Three months ended June 30		Six months ended June 30
	2011	2010	2011		2010
Upstream netbacks	$40,358	$15,351	$64,188	$40,060
Downstream netbacks	11,730	10,980	16,417	7,113
Interest and other income	194	49	541	120
Gain (loss) on sale of assets	(1,369)	-	27,947	432
Gain (loss) on risk management contracts	24,816	10,049	(8,413)	8,485
General and administrative	(7,987)	(5,220)	(18,410)	(11,605)
Stock-based compensation	(948)	(1,121)	(2,013)	(3,006)
Finance charges	(22,472)	(11,905)	(49,038)	(26,332)
Foreign exchange gain (loss)	1,144	(32,545)	18,544	(8,602)
Depletion, depreciation and amortization	(23,857)	(16,394)	(42,331)	(32,251)
Income tax recovery (provision)	(1,429)	3,657	5,475	7,599
Share of interest in and loss on disposition of associate	-	(4,618)	(6,828)	(5,085)
Exploration and evaluation expenses	(71)	-	(71)	(140)
Costs of refinancing long-term debt	(64,278)	-	(64,278)	-
Net loss	$(44,169)	$(31,717)	$(58,270)	$(23,212)

RECONCILIATIONS OF ADJUSTED EBITDA TO NET LOSS


	Three months ended June 30			Six months ended June 30
(Canadian dollar in thousands)	2011		2010	2011	2010
Adjusted EBITDA		$37,608	$20,173	$53,453	$34,613
Interest and other income		194	49	541	120
Defined benefit plan expense		(145)	(154)	(293)	(309)
Unrealized gain on risk management contracts		31,454	11,141	622	9,749
Gain (loss) on disposition of property, plant and equipment		(1,369)	-	27,947	432
Share-based compensation		(948)	(1,121)	(2,013)	(3,006)
Finance charges		(22,472)	(11,905)	(49,038)	(26,332)
Foreign exchange gain (loss)		1,144	(32,545)	18,544	(8,602)
Depletion, depreciation and amortization		(23,857)	(16,394)	(42,331)	(32,251)
Income tax recovery (provision)		(1,429)	3,657	5,475	7,599
Share of interest in and loss on disposition of associate		-	(4,618)	(6,828)	(5,085)
Costs of refinancing long-term debt		(64,278)	-	(64,278)	-
Exploration and evaluation expenses		(71)	-	(71)	(140)

Net loss		$(44,169)	$(31,717)	$(58,270)	$(23,212)

CRUDE OIL, NGLs AND NATURAL GAS CONVERSIONS

In this document, certain natural gas volumes have been converted to barrels of oil equivalent ("BOE") on the basis of one barrel to six thousand cubic feet. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent value equivalency at the well head.

QUARTERLY HIGHLIGHTS

Fluctuations in results over the previous eight quarters are due principally to variations in oil and gas prices, production and sales volumes and foreign exchange rates relative to U.S. dollar denominated debt.


FINANCIAL ($000 except per share amounts)		2009	2009	2010	2010	2010	2010	2011	2011
Three Months Ended		Sept 30⁽⁵⁾	Dec 31⁽⁵⁾	Mar 31	June 30	Sept 30⁽⁵⁾	Dec 31⁽⁵⁾	Mar 31	June 30
Revenues, net of royalties		$142,729	$123,991	$121,095	$132,877	$156,616	$182,239	$178,990	$234,556
Cash flow ⁽¹⁾		10,410	(2,766)	3,807	8,669	15,178	9,090	(5,770)	15,873
Basic, per share (1)		0.03	(0.07)	0.01	0.02	0.04	0.02	(0.01)	0.04
Diluted, per share (1)		0.03	(0.07)	0.01	0.02	0.04	0.02	(0.01)	0.04
Adjusted EBITDA ⁽¹⁾		16,724	4,513	14,440	20,173	25,642	31,951	15,845	37,608
Net earnings (loss)		47,767	(14,731)	8,505	(31,717)	7,946	(19,164)	(14,101)	(44,169)
Basic per share		0.12	(0.03)	0.02	(0.07)	0.02	(0.04)	(0.03)	(0.10)
Diluted per share		0.11	(0.03)	0.02	(0.07)	0.02	(0.04)	(0.03)	(0.10)
Capital expenditures		100,727	116,846	118,272	59,176	49,842	20,548	40,830	38,988
Cash on hand		333,634	256,787	118,382	69,412	51,120	19,532	42,865	31,525
Working capital surplus		347,139	245,067	127,416	100,202	61,543	65,375	80,902	18,954
Long-term debt		889,113	876,181	856,495	889,797	867,650	843,601	843,089	829,310
Shareholders' equity		$658,336	$671,588	$554,328	$530,086	$648,543	$650,183	$515,941	$467,057
OPERATIONAL
Upstream: Daily production volumes ⁽²⁾
	Bitumen - bbl/d	6,551	6,090	6,936	6,211	6,758	13,238	13,200	13,720
	Crude oil - bbl/d	993	880	937	906	819	873	540	398
	Natural gas - Mcf/d	10,377	10,319	9,662	9,278	9,158	8,318	6,805	3,755
	Equivalent - boe/d ⁽³⁾	9,274	8,690	9,483	8,663	9,103	15,498	14,874	14,744
Product sales prices ⁽⁴⁾
	Bitumen - $/bbl	45.30	48.23	51.98	43.13	42.68	45.08	41.78	54.49
	Crude oil - $/bbl	60.58	67.24	71.08	61.90	62.45	66.72	71.70	90.93
	Natural gas - $/Mcf	2.91	4.34	4.86	3.78	3.42	3.44	3.57	3.94
Selected highlights - $/boe ⁽³⁾
	Weighted average sales price ⁽⁴⁾	41.74	45.76	49.99	41.44	40.74	44.09	41.31	54.15
	Royalties	2.13	2.45	3.57	2.73	2.72	2.76	2.15	3.99
	Operating costs	15.43	20.61	17.47	19.25	18.08	17.91	21.18	19.23
	Netback ⁽¹⁾	24.18	22.70	28.95	19.46	19.94	23.42	17.97	30.93
Downstream: Refining
	Crude charged - bbl/d	7,076	8,188	9,347	9,373	9,903	10,137	9,764	9,860
	Refining utilization - %	75	86	98	99	104	107	103	104
	Margins - %	8	(7)	(8)	12	12	9	6	10
COMMON SHARES
Shares outstanding end of period (000)		403,567	427,031	428,246	429,103	429,120	447,168	447,858	448,058
Weighted average shares outstanding for the period
	Basic (000)	403,565	421,804	427,830	429,023	429,106	442,941	448,457	447,992
	Diluted (000)	424,058	422,344	430,077	429,023	431,487	442,941	448,457	447,992
Volume traded (000)		129,206	207,978	167,483	182,419	98,105	137,128	180,297	127,468
Common share price ($)
	High	1.15	1.33	1.65	1.88	1.52	1.35	1.66	1.59
	Low	0.76	0.94	1.16	1.20	1.15	1.10	1.26	1.03
	Close (end of period)	1.10	1.28	1.49	1.29	1.20	1.33	1.43	1.05

⁽¹⁾ A non-GAAP measure which is defined in the Advisory section of the MD&A
⁽²⁾Represents bitumen, crude oil and natural gas produced in the period. Actual sales volumes may be different due to the inventory at the period end
⁽³⁾ All references to barrels of oil equivalent (boe) are calculated on the basis of 6 Mcf: 1 bbl. This conversion is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Boes may be misleading, particularly if used in isolation
⁽⁴⁾ Before royalties and risk management contract gains or losses and after applicable diluent and transportation costs divided by actual sales volumes
⁽⁵⁾ Quarterly information is presented in accordance with previous GAAP as reported earlier in the respective financial statements.

CONNACHER OIL AND GAS LIMITED
Condensed Interim Consolidated Financial Statements
(Unaudited)

For the three months and six months ended June 30, 2011

Condensed Consolidated Balance Sheet
(Unaudited)


(Canadian dollar in thousands)	Note	June 30, 2011	December 31, 2010
ASSETS
CURRENT ASSETS
Cash		$31,525	$19,532
Trade and accrued receivables	4	72,707	57,419
Inventories		61,824	57,144
Investment in equity securities	5	21,197	-
Other assets	6	10,560	17,653
Assets held for sale	7	11,275	88,157
		209,088	239,905
NON-CURRENT ASSETS
Other assets	6	898	615
Exploration and evaluation assets	8	116,707	110,949
Property, plant and equipment	9	1,239,960	1,222,773
		1,357,565	1,334,337
		$1,566,653	$1,574,242

LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Trade and accrued payables	10	$75,206	$81,370
Current portion of long-term debt	12	101,523	-
Risk management contracts	11	13,405	8,984
Liabilities relating to assets held for sale	7	-	10,907
		190,134	101,261

NON-CURRENT LIABILITIES
Long-term debt	12	829,310	847,387
Decommissioning liabilities	13	52,399	60,038
Deferred income taxes		22,462	28,499
Risk management contracts	11	4,837	9,879
Employee benefits		454	193
		909,462	945,996

SHAREHOLDERS' EQUITY
Share capital	14	620,049	618,628
Contributed surplus	15.4	37,404	36,107
Deficit		(174,076)	(115,806)
Accumulated other comprehensive loss		(16,320)	(7,452)
Accumulated other comprehensive loss on assets held for sale	7	-	(4,492)
		467,057	526,985
		$1,566,653	$1,574,242

The accompanying notes to the condensed interim consolidated financial statements are an integral part of these statements.

Condensed Consolidated Statements of Operations and Comprehensive Loss
(Unaudited)


			Three months	ended June 30	Six months	ended June 30
(Canadian dollar in thousands)		Notes	2011	2010	2011	2010

REVENUE, NET OF ROYALTIES		20.1	$234,556	$132,877	$413,546	$253,972
EXPENSES
	Purchases of crude oil and products	20.1	137,574	79,513	239,741	153,094
	Production and operating expenses	20.1	31,380	22,128	66,396	44,395
	Transportation and handling costs	20.1	13,514	4,905	26,804	9,310
	General and administrative		7,987	5,220	18,410	11,605
	Share-based compensation	15.3	948	1,121	2,013	3,006
	Exploration and evaluation expenses		71	-	71	140
	Depletion, depreciation and amortization		23,857	16,394	42,331	32,251
			215,331	129,281	395,766	253,801
Earnings before undernoted			19,225	3,596	17,780	171

FINANCIAL AND OTHER ITEMS
	Finance charges	16	22,472	11,905	49,038	26,332
	Interest and other income		(194)	(49)	(541)	(120)
	Foreign exchange loss (gain)	17	(1,144)	32,545	(18,544)	8,602
	(Gain) loss on risk management contracts	11	(24,816)	(10,049)	8,413	(8,485)
	(Gain) loss on disposition of property, plant and equipment	7.1	1,369	-	(27,947)	(432)
	Share of interest in and loss on associate	7.2	-	4,618	6,828	5,085
	Costs of refinancing long-term debt	12.3	64,278	-	64,278	-
			61,965	38,970	81,525	30,982
LOSS BEFORE INCOME TAX			(42,740)	(35,374)	(63,745)	(30,811)
Income tax (provision) recovery		18	(1,429)	3,657	5,475	7,599
NET LOSS			(44,169)	(31,717)	(58,270)	(23,212)

OTHER COMPREHENSIVE INCOME (LOSS) AFTER TAX		18
Items that may be recycled to statement of operations:
	Exchange differences on translating foreign operations		(1,066)	6,074	(4,395)	1,424
	Available for sale financial asset	5	(4,853)	-	(4,473)	-
	Share of other comprehensive loss of associate		-	(1,509)	-	(2,728)
	Share of other comprehensive loss of associate recycled to statement of operations	7.2	-	422	4,492	422
OTHER COMPREHENSIVE INCOME (LOSS) AFTER TAX			(5,919)	4,987	(4,376)	(882)
TOTAL COMPREHENSIVE LOSS			$(50,088)	$(26,730)	$(62,646)	$(24,094)

NET LOSS PER SHARE - basic and diluted		14	$(0.10)	$(0.07)	$(0.13)	$(0.05)

The accompanying notes to the condensed interim consolidated financial statements are an integral part of these statements.

Condensed Consolidated Statements of Changes in Shareholders' Equity
(Unaudited)


	Six months	ended June 30
(Canadian dollar in thousands)	2011	2010
SHARE CAPITAL
Balance, beginning of period	$618,628	$593,119
Cash received on shares issued upon exercise of stock options	595	1,379
Transfer from contributed surplus - stock options exercised	352	748
Transfer from contributed surplus - share awards issued	534	480
Share issue costs, net of tax	(60)	(59)
Balance, end of period	$620,049	$595,667

CONTRIBUTED SURPLUS
Balance, beginning of period	$36,107	$31,040
Share-based compensation	2,183	4,078
Transfer to share capital - stock options exercised	(352)	(748)
Transfer to share capital - share awards issued	(534)	(295)
Balance, end of period	$37,404	$34,075

DEFICIT
Balance, beginning of period	$(115,806)	$(74,935)
Net loss	(58,270)	(23,212)
Balance, end of period	$(174,076)	$(98,147)

ACCUMULATED OTHER COMPREHENSIVE LOSS
Balance, beginning of period (including classified as held for sale)	$(11,944)	$(627)
Exchange differences on translating foreign operations	(4,395)	1,424
Available for sale financial asset	(4,473)	-
Share of other comprehensive loss of associate	-	(2,728)
Share of other comprehensive loss of associate recycled to statement of operations	4,492	422
Balance, end of period	$(16,320)	$(1,509)
Total Shareholders' equity	$467,057	$530,086

The accompanying notes to the condensed interim consolidated financial statements are an integral part of these statements.

Condensed Consolidated Statements of Cash Flow
(Unaudited)


			Three months ended June 30		Six months ended June 30
(Canadian dollar in thousands)		Note	2011	2010	2011	2010
OPERATING
Net loss			$(44,169)	$(31,717)	$(58,270)	$(23,212)
Adjustments for:
	Depletion, depreciation and amortization		23,857	16,394	42,331	32,251
	Share-based compensation - equity-settled	15.3	948	1,121	2,013	3,006
	Finance charges - non-cash portion		826	137	5,067	3,271
	Defined benefit plan expense		145	154	293	309
	Deferred income tax	18	1,310	(3,807)	(5,664)	(7,955)
	Unrealized gain on risk management contracts	11	(31,454)	(11,141)	(622)	(9,749)
	Share of interest in and loss on associate	7.2	-	4,618	6,828	5,085
	Unrealized foreign exchange (gain) loss	17	10,355	32,910	(6,612)	9,902
	Loss (gain) on disposition of property, plant and equipment		1,369	-	(27,947)	(432)
	Costs of refinancing long-term debt	12.3	64,278	-	64,278	-
	Realized foreign exchange gain on settlement of long-term debt		(11,592)	-	(11,592)	-
			15,873	8,669	10,103	12,476
Changes in non-cash working capital			(25,378)	832	(15,385)	(11,046)
Decommissioning liabilities settled		13	(30)	(100)	(813)	(468)
Cash flow from (used in) operating activities			(9,535)	9,401	(6,095)	962

INVESTING
Expenditures on property, plant and equipment			(23,789)	(51,835)	(50,249)	(153,393)
Exploration and evaluation expenditures			(10,972)	222	(36,673)	(14,875)
Proceeds on disposition of assets held for sale		7	21,340	-	78,275	1,205
Changes in non-cash working capital			(23,643)	(8,434)	(8,354)	(20,141)
Cash flow used in investing activities			(37,064)	(60,047)	(17,001)	(187,204)

FINANCING
Proceeds on issue of common shares		14	193	(154)	595	1,379
Share issue costs		14	(38)	-	(60)	(80)
Proceeds on issue of long-term debt		12	945,912	-	945,912	-
Repayment of long-term debt		12	(893,798)	-	(893,798)	-
Long-term debt issue cost		12	(16,452)	-	(16,452)	-
Cash flow from financing activities			35,817	(154)	36,197	1,299

NET INCREASE (DECREASE) IN CASH			(10,782)	(50,800)	11,802	(184,943)

Foreign exchange loss on cash balances held in foreign currency			(558)	1,830	(1,108)	(2,432)
CASH, BEGINNING OF PERIOD			42,865	118,382	19,532	256,787

CASH, END OF PERIOD			$31,525	$69,412	$31,525	$69,412

SUPPLEMENTARY CASH FLOW INFORMATION:
Interest paid			$27,610	$33,237	$39,270	$47,237

The accompanying notes to the condensed interim consolidated financial statements are an integral part of these statements.

Notes to the Condensed Interim Consolidated Financial Statements
(Unaudited)

Three and six months ended June 30, 2011 and 2010

1. Nature of Operations and Segment Reporting

Connacher Oil and Gas Limited ("Connacher") is a publicly traded integrated energy company headquartered in Calgary, Alberta, Canada. The address of the Company's registered office is Suite 900, 322 - 6th Avenue S.W., Calgary, Alberta. The condensed interim consolidated financial statements ("interim consolidated financial statements"), as at June 30, 2011 and for the three and six months then ended, comprises those of Connacher and its subsidiaries (collectively referred to as the "company").

These interim consolidated financial statements were approved and authorized for issuance by the Board of Directors on August 11, 2011.

Management has segmented the company's business based on differences in products and services and management responsibility. The company's business is conducted predominantly through two major business segments - upstream in Canada and downstream in USA, through a wholly-owned subsidiary, Montana Refining Company, Inc. (''MRCI''). Upstream includes exploration for and the development and production of bitumen, crude oil and natural gas. Downstream includes refining of primarily crude oil to produce and market gasoline, jet fuel, diesel fuels, asphalt and ancillary products.

2. Basis of Preparation

In conjunction with the company's annual audited consolidated financial statements to be issued under International Financial Reporting Standards ("IFRS") for the year ending December 31, 2011, these interim consolidated financial statements present the company's financial results of operations and financial position under IFRS, as at and for the three and six months ended June 30, 2011, including 2010 comparative periods. As a result, they have been prepared in accordance with IFRS 1, "First-time Adoption of International Financial Reporting Standards" and International Accounting Standard ("IAS") 34, "Interim Financial Reporting". Prior to 2011, the company prepared its interim and annual consolidated financial statements in accordance with Canadian generally accepted accounting principles ("previous GAAP"). The company's change over date to IFRS was January 1, 2010 and the opening IFRS balance sheet was presented in the interim consolidated financial statements for the three months ended March 31, 2011 ("March 2011 Interim Consolidated Financial Statements").

The preparation of these interim consolidated financial statements resulted in changes to the company's accounting policies as compared to those disclosed in the company's annual audited consolidated financial statements for the year ended December 31, 2010 issued under previous GAAP. A summary of the significant changes to the company's accounting policies is disclosed in note 21 along with reconciliations presenting the impact of the transition to IFRS for the comparative periods as at June 30, 2010 and for the three and six months ended June 30, 2010. These policies have been retrospectively and consistently applied except where specific exemptions permitted an alternative treatment upon transition to IFRS in accordance with IFRS 1 as disclosed in note 21.

These interim consolidated financial statements do not include all disclosures required by IFRS for annual financial statements. Accordingly, these interim consolidated financial statements should be read in conjunction with the company's audited consolidated financial statements as at and for the year ended December 31, 2010 ("2010 Annual Consolidated Financial Statements") and the March 2011 Interim Consolidated Financial Statements.

3. Significant Accounting Policies

These interim consolidated financial statements follow the same accounting principles and methods of application as those disclosed in note 3 to the company's March 2011 Interim Consolidated Financial Statements. Subject to certain elections made on transition to IFRS as disclosed in note 21, these accounting policies have been consistently applied throughout all periods presented in these interim consolidated financial statements.

3.1 Recent accounting pronouncements issued but not yet adopted

The company has reviewed new and revised accounting pronouncements that have been issued but are not yet effective and determined that the following may have an impact on the company:

IAS 1 Presentation of Financial Statements ("IAS 1")

IAS 1 was amended in June 2011 to provide guidance on the presentation of items contained in other comprehensive income ("OCI") and their classification within OCI. The amendments are to be applied for annual periods beginning on or after July 1, 2012 with earlier adoption permitted. The amendments are not expected to have a significant impact on the company's consolidated financial statements.

IAS 19 Employee Benefits ("IAS 19")

IAS 19 was amended in June 2011 to change the accounting for defined benefit plans and termination benefits. The amendments require the immediate recognition of actuarial gains or losses. The amendments also mandate additional presentation and disclosure requirements. The amendments are be applied for annual periods beginning on or after January 1, 2013 with earlier adoption permitted. The company is currently evaluating the impact of this standard on its consolidated financial statements.

4. Trade and Accrued Receivables


(Canadian dollar in thousands)	June 30, 2011	December 31, 2010
Trade receivables	$32,613	$16,904
Accrued revenue	39,792	39,942
Other receivables	302	527
Due from associate	-	46
	$72,707	$57,419

5. Investment In Equity Securities

Upon completion of the exchange of an investment in associate as described in note 7.2, in March 2011, the company acquired 3.3 million common shares of a public company, Gran Tierra Energy Inc. ("Gran Tierra Energy"). The investment in equity securities is classified as an available for sale financial asset and is carried at fair value on initial recognition. An unrealized loss of $4.9 million and $4.5 million in the three and six month period ended June 30, 2011, respectively, was recorded in other comprehensive loss.

6. Other Assets


(Canadian dollar in thousands)	June 30, 2011	December 31, 2010
Prepayments	$9,105	$5,754
Deposits	198	10,779
Unamortized transaction costs relating to the credit facility (note 12.4)	1,366	939
Income taxes refundable	772	796
Derivative financial asset (note 6.1)	17	-
Total	11,458	18,268
Less: non-current portion	(898)	(615)
Current portion	$10,560	$17,653

6.1

Upon completion of the exchange of an investment in associate as described in note 7.2, in March 2011, the company acquired 841,000 common share purchase warrants of Gran Tierra Energy. Each common share purchase warrant entitles the company to purchase one common share of Gran Tierra Energy for $9.62 per common share before August 28, 2011. The common share purchase warrants are classified as held for trading and have been recorded at fair value with changes in the fair value included in finance charges

7. Assets and Liabilities Classified as Held For Sale


Canadian dollar in thousands)		Notes	June 30, 2011	December 31, 2010
*Assets classified as held for sale*
	Property, plant and equipment	7.1	$-	$54,348
	Exploration and evaluation assets	7.1	11,275	5,652
	Investment in associate	7.2	-	27,683
	Investment in derivative financial instrument	7.2	-	474
Assets classified as held for sale			$11,275	$88,157

*Liabilities associ*ated with assets classified as held for sale
	Decommissioning liabilities	7.1	$-	$10,907

*Equity associated with assets* *classified as held for sal*e
	Accumulated other comprehensive loss	7.2	$-	$4,492

7.1 Oil and gas properties

As a part of the company's program to rationalize its assets, on June 22, 2011, the company committed to a plan to sell certain exploration and evaluation assets (part of the upstream segment) and accordingly, such assets have been classified as assets held for sale on the balance sheet as at June 30, 2011. The company expects to complete the sale process within a year.

Under the same asset rationalization program, the company classified certain of its conventional oil and gas properties as held for sale on December 31, 2010. The company realized cash proceeds of $78.3 million in the six months ended June 30, 2011 upon completion of the sale of these assets. A loss of $1 million in the three months ended June 30, 2011 and a net gain of $28.2 million in the six months ended June 30, 2011 relating to these dispositions was included in gain (loss) on disposition of property, plant and equipment.

Assets classified as held for sale are not depleted, depreciated or amortized.

7.2 Investment in associate

As at December 31, 2010, Connacher owned 26.9 million common shares, representing 18.5 percent, of Petrolifera Petroleum Limited's ("Petrolifera") issued and outstanding common shares and 6.8 million Petrolifera common share purchase warrants. The investment in Petrolifera was classified as an asset held for sale on December 31, 2010, following management's commitment to support the sale of all of the issued and outstanding common shares of Petrolifera to Gran Tierra Energy. Upon the completion of a share exchange under a Plan of Arrangement in March 2011, the company received 3.3 million common shares and 841,000 common share purchase warrants of Gran Tierra Energy. Connacher de-recognized the investment in Petrolifera in March 2011 and recorded a loss of $6.8 million, including a $4.5 million transfer from the other comprehensive loss.

8. Exploration and Evaluation Assets ("E&E")


(Canadian dollar in thousands)	Upstream Segment - Canada

*Cost*
Balance, January 1, 2010	$96,162
Additions	25,048
Transferred to assets classified as held for sale (note 7.1)	(8,688)
Balance, December 31, 2010	112,522
Additions	36,673
Transfer to property, plant and equipment	(17,988)
Transferred to assets classified as held for sale (note 7.1)	(11,275)
Balance, June 30, 2011	$119,932

*Accumulated amortization and impairment*
Balance, January 1, 2010	-
Charge for the period	$4,609
Transferred to assets classified as held for sale (note 7.1)	(3,036)
Balance, December 31, 2010	1,573
Charge for the period	1,652
Balance, June 30, 2011	$3,225

*Carrying value*
As at December 31, 2010	$110,949
As at June 30, 2011	$116,707

E&E assets consist of unproved land and the company's oil sands evaluation projects, which are pending the determination of technical feasibility and commercial viability.

9. Property, Plant and Equipment


(Canadian dollar in thousands)	Oil and gas properties (Upstream)	Refining (Downstream)	Corporate	Total

*Cost*
Balance, January 1, 2010	$1,029,396	$105,789	$12,272	$1,147,457
Additions	204,474	8,575	2,128	215,177
Dispositions	(751)	-	-	(751)
Change in decommissioning liabilities	15,700	-	-	15,700
Foreign currency translation changes	-	(5,887)	-	(5,887)
Transferred to assets classified as held for sale (note 7.1)	(59,679)	-	-	(59,679)
Balance, December 31, 2010	1,189,140	108,477	14,400	1,312,017
Additions	42,351	8,958	571	51,880
Transfer from exploration and evaluation assets	17,988	-	-	17,988
Dispositions	(475)	-	-	(475)
Change in decommissioning liabilities	(8,735)	-	-	(8,735)
Foreign currency translation changes	-	(3,390)	-	(3,390)
Balance, June 30, 2011	$1,240,269	$114,045	$14,971	$1,369,285

*Accumulated depletion, depreciation and impairment*
Balance, January 1, 2010	$-	$18,075	$5,468	$23,543
Depletion and depreciation	55,040	10,470	2,330	67,840
Impairment charge	4,476	-	-	4,476
Foreign currency translation changes	-	(1,284)	-	(1,284)
Transferred to assets classified as held for sale (note 7.1)	(5,331)	-	-	(5,331)
Balance, December 31, 2010	54,185	27,261	7,798	89,244
Depletion and depreciation	35,925	4,348	857	41,130
Disposition	(190)	-	-	(190)
Foreign currency translation changes	-	(859)	-	(859)
Balance, June 30, 2011	$89,920	$30,750	$8,655	$129,325

*Carrying value*
At December 31, 2010	$1,134,955	$81,216	$6,602	$1,222,773
At June 30, 2011	$1,150,349	$83,295	$6,316	$1,239,960

In May 2011, the company acquired certain oil and gas properties for cash consideration of $9.7 million. The acquisition resulted in the allocation of $11.9 million to the upstream property, plant and equipment and $2.2 million to decommissioning liabilities.

10. Trade and Accrued Payables


(Canadian dollar in thousands)	June 30, 2011	December 31, 2010
Accrued liabilities	$53,620	$54,514
Trade payables	15,020	10,973
Accrued interest payable	6,333	13,280
Taxes payable	111	319
Other payables	122	2,284
	$75,206	$81,370

11. Financial Instruments

The company's financial instruments include its cash, trade and accrued receivables, investment in equity securities, derivative financial instruments, trade and accrued payables and long-term debt. Fair values of financial assets and liabilities and summarized information related to derivative financial assets and liabilities are presented below.

11.1 Fair value measurements for financial instruments

The following table shows the comparison of the carrying and fair values of the company's financial instruments:


	June 30, 2011		December 31, 2010
(Canadian dollar in thousands)	Carrying Value	Fair Value	Carrying Value	Fair Value
Loans and receivables
Cash ⁽¹⁾	$31,525	$31,525	$19,532	$19,532
Trade and accrued receivables ⁽¹⁾	72,707	72,707	57,419	57,419
Available for sale financial assets
Investment in equity securities ⁽²⁾	21,197	21,197	-	-
Fair value through profit and loss ("FVTPL")
Derivative financial assets ⁽²⁾	17	17	474	474
Risk management contract liabilities ⁽³⁾	18,242	18,242	18,863	18,863
Convertible debentures ⁽²⁾	97,764	97,764	96,548	96,548
Other liabilities
Trade and accrued payables ⁽¹⁾	75,206	75,206	81,370	81,370
Long-term debt excluding convertible debentures ⁽⁴⁾	$833,069	$846,606	$750,839	$803,872

⁽¹⁾ The fair values of cash, trade and accrued receivables and trade and accrued payables approximate their carrying amounts due to the short-term maturity of those instruments
⁽²⁾ The fair values of the investment in equity securities, derivative financial assets and convertible debentures are based on quoted market prices, a Level 1 measurement
⁽³⁾ The fair values of the risk management contract liabilities were derived from observable market prices or indices, a Level 2 measurements
⁽⁴⁾ The fair values of long-term debt excluding convertible debentures have been determined based on market information.

11.2 Risk management contract liabilities

The following table summarizes the net position of the company's risk management contracts in the upstream segment:


(Canadian dollar in thousands)		June 30, 2011	December 31, 2010

Current liability
	Oil contracts	$13,060	$8,241
	Natural gas contracts	345	743
Current liability		13,405	8,984
Non-current liability
	Oil contracts	4,754	9,879
	Natural gas contracts	83	-
Non-current liability		4,837	9,879
Risk management contract liabilities		$18,242	$18,863

The following tables summarize the details of the risk management contract positions:

June 30, 2011 - Crude oil contracts


Volume (bbl/d)	Term	Type		Price (WTI U.S.$/bbl)	Liability (Asset) as at June 30, 2011 (Canadian dollar in thousands)
2,000	Jan 1, 2011 - Dec 31, 2011	Swap ⁽¹⁾	$90.60		11,663
2,000	Apr 1, 2011 - Mar 31, 2012	Call option	$96.00		3,904
2,000	Apr 1, 2011 - Mar 31, 2012	Put option	$80.00		(893)
2,000	Jul 1, 2011 - Jun 30, 2012	Call option	$100.00		4,724
2,000	Jul 1, 2011 - Jun 30, 2012	Put option	$80.00		(1,584)
2,000	Jan 1, 2012 - Dec 31, 2012	Call option	$120.00		3,104
2,000	Jan 1, 2012 - Dec 31, 2012	Put option	$80.00		(2,984)
Balance, as at June 30, 2011					$17,934

⁽¹⁾On December 30, 2011, the counterparty has a right to extend the maturity date of the contract for additional one year from January 1, 2012 to December 31, 2012 at US$ 90.60/bbl

June 30, 2011 - Natural gas contracts


Volume (GJ/d)	Term	Type	Price (AECO CAD$/GJ)	Liability (Asset) as at June 30, 2011 (Canadian dollar in thousands)
4,000	Sept 1, 2010 - Aug 31, 2011	Swap	$3.87	$54
4,000	Oct 1, 2010 - Sept 30, 2011	Swap	$4.20	209
5,000	Jan 1, 2012 - Dec 31 2012	Call option	$4.30	(496)
5,000	Jan 1, 2012 - Dec 31 2012	Put option	$3.70	541
Balance, as at June 30, 2011				$308

The following tables summarize the amounts recorded in the consolidated statements of operations with respect to the risk management contracts:


For the three months ended June 30	2011	2010
(Canadian dollar in thousands)	Upstream	Upstream	Downstream ⁽¹⁾	Total
Unrealized gain	$31,454	$10,436	$705	$11,141
Realized loss	(6,638)	(325)	(767)	(1,092)
Gain (loss) on risk management contracts	$24,816	$10,111	$(62)	$10,049


For the six months ended June 30	2011	2010
(Canadian dollar in thousands)	Upstream	Upstream	Downstream ⁽¹⁾	Total
Unrealized gain	$622	$9,658	$91	$9,749
Realized loss	(9,035)	(497)	(767)	(1,264)
Gain (loss) on risk management contracts	$(8,413)	$9,161	$(676)	$8,485

⁽¹⁾ In April 2010, the company entered into a commodity price risk contract to hedge its gasoline revenue at a floating price of WTI plus US$9/bbl. The contract expired on September 30, 2010.

12. Long-Term Debt


		June 30, 2011	December 31, 2010
	Notes	(Canadian dollar in thousands)
Second Lien Senior Notes, due August 1, 2019 (US$ 550 million)	12.1	$530,365	$-
Second Lien Senior Notes, due August 1, 2018 (CAD$ 350 million)	12.1	350,000	-
Second Lien Senior Notes, due December 15, 2015 (US$ 3.8 million)	12.2	3,777	584,168
First Lien Senior Notes, due July 15, 2014 (US$ 100,000) Senior Notes, due July 15, 2014 (US$ 100,000)	12.2	96	198,920
Convertible Debentures, due June 30, 2012 (CAD$ 100 million)		97,764	96,548
Total debt		982,002	879,636
Unamortized transaction costs		(51,169)	(32,249)
Current portion of long-term debt		(101,523)	-
Long-term debt		$829,310	$847,387

12.1 Second Lien Senior Notes issued in 2011

In May 2011, the company issued US$ 550 million face value 8.5% Senior Secured Second Lien Notes due August 1, 2019 and CAD$ 350 million face value 8.75% Senior Secured Second Lien Notes due August 1, 2018 (the "New Notes") and capitalized transaction costs of $17.9 million relating to their issuance.

Interest is payable semi-annually on February 1 and August 1 each year these notes are outstanding. These notes are secured on a second priority basis by liens on all of the company's existing and future property, excluding certain pipeline assets in the USA.

At any time prior to August 1, 2014, the company may redeem up to 35% of the US-dollar denominated notes at a price of 108.5 percent and up to 35% of the Canadian-dollar denominated notes at the price of 108.75 percent with proceeds of equity offerings of at least $10 million. Any any time prior to August 1, 2015, the company may redeem some or all of the New Notes at their principal amount plus a make whole premium plus applicable interest. At any time, the company may redeem all or part of the US-dollar denominated notes at 108.5 percent and Canadian-dollar denominated notes at 108.75 percent with the net proceeds of an asset sale. After August 1, 2015 the New Notes may be redeemed at redemption prices ranging from 104.25 percent, reducing to 100 percent on August 1, 2017, and thereafter for the US-dollar denominated notes and for Canadian-dollar denominated notes at 104.375 percent reducing to 100 percent on August 1, 2017 and thereafter.

Upon a change of control of the company, the holders of the notes may require the company to purchase the notes at the redemption prices noted above, with a minimum price of 101 percent of the principal amount to be repurchased.

12.2 First Lien Senior Notes due 2014 and and Second Lien Senior Notes due 2015

In conjunction with the completion of the issuance of the New Notes described in note 12.1, the company repurchased US$ 783.5 million of the face value of the outstanding First Lien Senior Notes due 2014 and Second Lien Senior Notes due 2015 (the "Old Notes") (representing 99% of the Old Notes outstanding) for cash consideration of US$ 854.7 million (CAD$ 835.9 million). See note 12.3 for the accounting of costs associated with this transaction. The remaining amounts outstanding under the Old Notes are classified as current liabilities as the company expects to repurchase the Old Notes within a year.

12.3 Costs of refinancing long-term debt

As a result of the issuance of the New Notes and the purchase and redemption of the Old Notes during the three months ended June 30, 2011, the company performed an analysis to determine whether the transaction was to be accounted for as a modification or an extinguishment of debt. The company determined that this transaction resulted partially in a modification and partially as an extinguishment. Accordingly, based on the information currently available, the company recorded $33.7 million as a discount on the New Notes and approximately $64.3 million was expensed as costs of refinancing long-term debt in the interim consolidated statement of operations. The final allocation has yet to be determined and adjustments, if necessary, will be reflected in future periods.

12.4 Revolving Credit Facility (the "Facility")

In May 2011, the Facility was amended to increase the borrowing limit to $100 million and the maturity was extended to May 31, 2014. The company capitalized transaction costs of $470,000 during the three and six months ended June 30, 2011 with respect to the amendment of the Facility. At June 30, 2011, the Facility was utilized to secure letters of credit of $5.7 million. The Facility is subject to certain covenants of which the company was in compliance with throughout 2011.

13. Decommissioning Liabilities

The following table summarizes the details of decommissioning liabilities:


(Canadian dollar in thousands)	Six months ended June 30, 2011	Year ended December 31, 2010
Balance, beginning of period	$70,945	$53,729
Liabilities incurred	259	11,560
Liabilities acquired	2,229	-
Liabilities settled	(813)	(647)
Liabilities disposed	(9,881)	(263)
Change in estimates	(11,223)	4,463
Unwinding of discount	883	2,103
Balance, end of period	52,399	70,945
Classified as held for sale - current portion	-	(10,907)
Balance, non-current portion	$52,399	$60,038

As a result of the detail analysis of the estimates of cash flows and timing to abandon the oil and gas properties and changes in the interest rates, the company recorded a decrease in decommissioning liabilities of $11.2 million in the six months ended June 30, 2011 (six months ended June 30, 2010 - increase of $4.5 million). At June 30, 2011, the estimated total undiscounted amount required to settle the decommissioning liabilities was $66.1 million (December 31, 2010 - $77.4 million). This amount has been discounted using risk-free rates of interest ranging between 1.58 percent to 3.49 percent, depending on the estimated time to abandon the asset.

14. Share Capital


	Six months ended June 30, 2011			Year ended December 31, 2010
(Canadian dollar in thousands except number of shares)	Number		Amount	Number	Amount
Balance, beginning of period	447,167,694		$618,628	427,031,362	$593,119
Issued for cash on flow-through basis net of premium of $2,272	-		-	17,480,000	23,074
Cash received on exercise of stock options	608,088		595	2,017,836	1,936
Transfer from contributed surplus - stock options	-		352	-	1,082
Transfer from contributed surplus - share awards	282,209		534	638,496	480
Share issue cost, net of tax		-	(60)	-	(1,063)
Balance, end of period	448,057,991		$620,049	447,167,694	$618,628


	Three months ended June 30		Six months ended June 30
	2011	2010	2011	2010
Weighted average common shares outstanding basic and diluted	447,991,640	429,022,518	447,799,247	428,429,659

Outstanding employee stock options of 26.5 million as at June 30, 2011 (June 30, 2010 - 29.0 million), director share awards of 312,500 as at June 30, 2011 (June 30, 2010 - 391,018) and common shares issuable upon the exercise of convertible debentures were excluded from the diluted per share calculation as the effect of including them would be anti-dilutive.

15 Stock Option Plan and Share Award Plan for Directors

15.1 Stock option plan

The following table summarizes the changes in stock options and the related weighted average exercise prices:


Six months ended June 30	2011		2010
	Number of Options	Weighted Average Exercise Price	Number of Options	Weighted Average Exercise Price
Outstanding, beginning of period	24,413,668	$1.50	22,579,045	$1.72
Granted	4,034,014	1.32	9,123,084	1.38
Exercised	(608,088)	0.98	(1,433,134)	0.96
Forfeited	(827,415)	1.25	(374,145)	1.31
Expired	(475,500)	4.36	(843,000)	3.00
Outstanding, end of period	26,536,679	$1.44	29,051,850	$1.62
Exercisable, end of period	15,883,779	$1.55	14,404,099	$2.03

The fair value of each stock option granted is estimated on the date of grant using the Black-Scholes option pricing model using the following weighted average assumptions.


For the six months ended June 30	2011	2010
Risk free interest rate (percent)	1.9	1.9
Expected option life (year)	3.0	3.0
Expected volatility (percent)	55	72

The weighted average fair value at the date of grant of options granted during the three months ended June 30, 2011 was $0.41 per option (three months ended June 30, 2010 - $0.80 per option) and six months ended June 30, 2011 was $0.51 (six months ended June 30, 2010 - $0.67).

15.2 Share award plan for Directors

The following table summarizes the changes in share award plan for directors:


For the six months ended June 30	2011	2010
Outstanding, beginning of period	380,598	648,916
Granted	375,000	380,598
Vested and Settled	(406,640)	(638,496)
Cancelled	(36,458)	-
Outstanding, end of period	312,500	391,018
Vested, end of period	-	10,420

15.3 Share-based compensation


	Three months ended June 30		Six months ended June 30
(Canadian dollar in thousands)	2011	2010	2011	2010
*Equity-settled grants*
Employee stock option plan	$927	$1,485	$1,944	$3,907
Share award plan for Directors	122	155	239	171
	1,049	1,640	2,183	4,078
Less: Share-based compensation capitalized	(101)	(519)	(170)	(1,072)
	$948	$1,121	$2,013	$3,006

15.4 Contributed surplus


(Canadian dollar in thousands)	Six months ended June 30, 2011	Year ended December 31, 2010
Balance, beginning of period	$36,107	$31,040
Equity-settled share-based compensation	2,183	6,629
Transfer to share capital - stock options exercised	(352)	(1,082)
Transfer to share capital - share awards for directors	(534)	(480)
Balance, end of period	$37,404	$36,107

16. Finance Charges


	Three months ended June 30		Six months ended June 30
(Canadian dollar in thousands)	2011	2010	2011	2010
Interest expense on long-term debt	$22,655	$23,989	$46,167	$48,326
Amortization of transaction costs relating to the Facility	86	209	198	327
Stand-by fees relating to the Facility	167	500	258	500
Bank charges and other fees	92	142	181	142
Unrealized loss on derivative financial asset (note 6.1)	320	1,220	135	1,491
Unwinding of discount on decommissioning liabilities (note 13)	437	505	883	974
Unrealized (gain) loss on remeasurement of convertible debentures	(1,285)	(2,000)	1,216	-
	22,472	24,565	49,038	51,760
Less: Interest capitalized	-	(12,660)	-	(25,428)
Finance charges	$22,472	$11,905	$49,038	$26,332

17. Foreign Exchange Gain (Loss)


(Canadian dollar in thousands)		Three months ended June 30		Six months ended June 30
		2011	2010	2011	2010
Unrealized foreign exchange gain (loss) on translation of:
	U.S. denominated long-term debt	$(9,818)	$(33,903)	$7,418	$(7,290)
	Foreign currency denominated cash balances	(164)	1,836	(424)	(2,164)
	Other foreign currency denominated monetary items	(373)	(843)	(382)	(448)
Unrealized foreign exchange gain (loss)		(10,355)	(32,910)	6,612	(9,902)
Realized foreign exchange gain		11,499	365	11,932	1,300
Foreign exchange gain (loss)		$1,144	$(32,545)	$18,544	$(8,602)

18. Income Taxes

Income tax recovery (provision) recognized in statement of operations


	Three months ended June 30			Six months ended June
(Canadian dollar in thousands)		2011	2010	2011	2010
Current
	Canada	$(119)	$(154)	$(189)	$(360)
	USA	-	4	-	4
Total current tax		(119)	(150)	(189)	(356)
Deferred tax (provision) recovery		(1,310)	3,807	5,664	7,955
Income tax (provision) recovery		$(1,429)	$3,657	$5,475	$7,599

Income tax expense recognized in the statement of other comprehensive loss in the three and six months periods ended June 30, 2011 and June 30, 2010 was $nil.

19. Capital Management

The company is exposed to financial risks on its financial instruments and in the way it finances its capital requirements. The company works to minimize its exposures to these risks through forward financial planning and with the use of financial derivatives. Connacher's objectives in managing its cash, debt and equity and its future capital requirements are to safeguard its ability to meet its financial obligations, to maintain a flexible capital structure that allows multiple financing options when a financing need or opportunity arises and to optimize its use of long-term debt and equity at an appropriate level of risk. The company manages its capital structure and follows a financial strategy that considers economic and industry conditions, the risk characteristics and the long-term nature of its underlying assets and its growth opportunities. It strives to continuously improve its credit rating with the objective of reducing its cost of capital. Connacher's current capital structure is summarized below:


(Canadian dollar in thousands)	June 30, 2011	December 31, 2010
Long-term debt ⁽¹⁾	$829,310	$847,387
Shareholders' equity	467,057	526,985
Total long-term debt plus equity ("capitalization")	$1,296,367	$1,374,372
Long-term debt to capitalization ⁽²⁾	64%	62%
⁽¹⁾ Long-term debt is stated at its carrying value, which is net of transaction costs ⁽²⁾ Calculated as long-tem debt divided by the book value of shareholders' equity plus long-term debt

As at June 30, 2011, the company's net long-term debt (long-term debt, net of cash on hand) was $798 million. Net long-term debt to capitalization was 62 percent (2010 - 60 percent). The long-term debt agreements contain certain provisions, which restrict the company's ability to incur additional indebtedness, pay dividends, make certain payments and dispose of collateralized assets.

20. Segmented Information

20.1 Results of operations


(Canadian dollar in thousands) For the three months ended June 30, 2011	Canada Upstream	USA Downstream	Corporate & Eliminations	Consolidated
Revenues, net of royalties	$117,790	$120,333	$(3,567)	$234,556
Purchases of crude oil and products	(41,208)	(99,933)	3,567	(137,574)
Production and operating expenses	(25,097)	(6,283)	-	(31,380)
Transportation and handling costs	(11,127)	(2,387)	-	(13,514)
	40,358	11,730	-	52,088
Realized loss on risk management contracts - net	(6,638)	-	-	(6,638)
General and administrative expenses	(6,897)	(1,090)	-	(7,987)
Segment operating income	26,823	10,640	-	37,463
Depletion, depreciation and amortization	(21,015)	(2,286)	(556)	(23,857)
Segment income (loss)	5,808	8,354	(556)	13,606
Interest and other income	-	-	194	194
Loss on disposition of property, plant and equipment	-	-	(1,369)	(1,369)
Unrealized gain on risk management contracts - net	-	-	31,454	31,454
Share-based compensation	-	-	(948)	(948)
Finance charges	-	-	(22,472)	(22,472)
Foreign exchange loss	-	-	1,144	1,144
Exploration and evaluation expenses	-	-	(71)	(71)
Costs of refinancing long-term debt	-	-	(64,278)	(64,278)
Income tax provision	-	-	(1,429)	(1,429)
Net earnings (loss)	$5,808	$8,354	$(58,331)	$(44,169)


(Canadian dollar in thousands) For the three months ended June 30, 2010	Canada Upstream	USA Downstream	Corporate & Eliminations	Consolidated
Revenues, net of royalties	$50,789	$85,693	$(3,605)	$132,877
Purchases of crude oil and products	(17,065)	(66,053)	3,605	(79,513)
Production and operating expenses	(15,173)	(6,955)		(22,128)
Transportation and handling costs	(3,200)	(1,705)	-	(4,905)
	15,351	10,980	-	26,331
Realized loss on risk management contracts - net	(325)	(767)	-	(1,092)
General and administrative expenses	(4,123)	(1,097)	-	(5,220)
Segment operating income	10,903	9,116	-	20,019
Depletion, depreciation and amortization	(13,512)	(2,346)	(536)	(16,394)
Segment income (loss)	(2,609)	6,770	(536)	3,625
Interest and other income	-	-	49	49
Unrealized gain risk management contracts - net	-	-	11,141	11,141
Share-based compensation	-	-	(1,121)	(1,121)
Finance charges	-	-	(11,905)	(11,905)
Foreign exchange loss	-	-	(32,545)	(32,545)
Income tax recovery	-	-	3,657	3,657
Share of interest in associate and loss on associate	-	-	(4,618)	(4,618)
Net earnings (loss)	$(2,609)	$6,770	$(35,878)	$(31,717)


(Canadian dollar in thousands) For the six months ended June 30, 2011	Canada Upstream	USA Downstream	Corporate & Eliminations	Consolidated
Revenues, net of royalties	$220,044	$202,285	$(8,783)	$413,546
Purchases of crude oil and products	(80,144)	(168,380)	8,783	(239,741)
Production and operating expenses	(53,187)	(13,209)	-	(66,396)
Transportation and handling costs	(22,525)	(4,279)	-	(26,804)
	64,188	16,417	-	80,605
Realized loss on risk management contracts - net	(9,035)	-	-	(9,035)
General and administrative expenses	(16,101)	(2,309)	-	(18,410)
Segment operating income	39,052	14,108	-	53,160
Depletion, depreciation and amortization	(37,126)	(4,348)	(857)	(42,331)
Segment income (loss)	1,926	9,760	(857)	10,829
Interest and other income	-	-	541	541
Gain on disposition of property, plant and equipment	-	-	27,947	27,947
Unrealized gain on risk management contracts - net	-	-	622	622
Share-based compensation	-	-	(2,013)	(2,013)
Finance charges	-	-	(49,038)	(49,038)
Foreign exchange gain	-	-	18,544	18,544
Exploration and evaluation expenses	-	-	(71)	(71)
Share of interest in and loss on associate	-	-	(6,828)	(6,828)
Costs of refinancing long-term debt	-	-	(64,278)	(64,278)
Income tax recovery	-	-	5,475	5,475
Net earnings (loss)	$1,926	$9,760	$(69,956)	$(58,270)


(Canadian dollar in thousands) For the six months ended June 30, 2010	Canada Upstream	USA Downstream	Corporate & Eliminations	Consolidated
Revenues, net of royalties	$113,142	$148,473	$(7,643)	$253,972
Purchases of crude oil and products	(36,583)	(124,154)	7,643	(153,094)
Production and operating expenses	(30,085)	(14,310)		(44,395)
Transportation and handling costs	(6,414)	(2,896)	-	(9,310)
	40,060	7,113	-	47,173
Realized loss on risk management contracts - net	(497)	(767)	-	(1,264)
General and administrative expenses	(9,830)	(1,775)	-	(11,605)
Segment operating income	29,733	4,571	-	34,304
Depletion, depreciation and amortization	(26,262)	(4,846)	(1,143)	(32,251)
Segment income (loss)	3,471	(275)	(1,143)	2,053
Interest and other income	-	-	120	120
Gain on disposition of property, plant and equipment	-	-	432	432
Unrealized gain on risk management contracts	-	-	9,749	9,749
Share-based compensation	-	-	(3,006)	(3,006)
Finance charges	-	-	(26,332)	(26,332)
Foreign exchange gains	-	-	(8,602)	(8,602)
Share of interest in associate and loss on associate	-	-	(5,085)	(5,085)
Exploration and evaluation expenses	-	-	(140)	(140)
Income tax recovery	-	-	7,599	7,599
Net earnings (loss)	$3,471	$(275)	$(26,408)	$(23,212)

20.2 Capital expenditures


	Three months ended June 30		Six months ended June 30
(Canadian dollar in thousands)	2011	2010	2011	2010
Upstream	$29,479	$50,354	$77,964	$165,870
Downstream	5,282	1,259	8,958	2,398
Total cash related capital expenditures	$34,761	$51,613	$86,922	$168,268

21. First time adoption of IFRS

As stated in note 2, these are the company's interim consolidated financial statements prepared in accordance with IFRS for the period ended June 30, 2011 in conjunction with the company's annual audited consolidated financial statements to be issued under IFRS as at and for the year ending December 31, 2011. As a result, these interim consolidated financial statements have been prepared in accordance with IFRS 1, "First-time Adoption of International Financial Reporting Standards" and with IAS 34, "Interim Financial Reporting".

IFRS 1 requires the presentation of comparative information as at the January 1, 2010 ("transition date") and subsequent comparative periods using the consistent and retrospective application of IFRS accounting policies. However, to assist with the transition, the provisions of IFRS 1 allow for certain mandatory and optional exemptions from the requirement of retrospective application of accounting policies and standards on first-time adoption of IFRS. Accordingly, these interim consolidated financial statements were prepared using the accounting policies stated in note 3 of the March 2011 Interim Consolidated Financial Statements and were retrospectively and consistently applied except where specific IFRS 1 optional and mandatory exemptions permitted an alternative treatment upon transition to IFRS for first-time adopters. The significant exemptions applied under IFRS 1 in preparing these interim consolidated financial statements are set out below.

Deemed cost election for oil and gas properties

Under previous GAAP, the company followed the "full cost accounting" method of accounting for oil and gas activities in which all costs directly associated with the acquisition of, the exploration for, and the development of oil and natural gas reserves were capitalized on a country-by-country cost centre basis (Upstream segment in Canada). Costs accumulated within each country cost centre were depleted using the unit-of-production method based on proved reserves determined using estimated future prices and costs. Upon transition to IFRS, the company was required to adopt new accounting policies for upstream activities, including exploration and evaluation costs and development costs. Under IFRS, exploration and evaluation costs are those expenditures for an area where technical feasibility and commercial viability has not yet been determined, are presented separately on the balance sheet as exploration and evaluation assets and may or may not be amortized based on the company's accounting policy. Development costs include those expenditures for areas where technical feasibility and commercial viability has been determined, are presented as a part of property, plant and equipment on the balance sheet and are depleted and depreciated on an area-by-area level. The company adopted the IFRS 1 exemption whereby the company deemed its January 1, 2010 IFRS upstream asset costs to be equal to its previous GAAP historical upstream property, plant and equipment net book value. Accordingly, exploration and evaluation costs were deemed equal to the unproved properties balance and the development costs were deemed equal to the upstream full cost pool balance. The development costs were allocated to the underlying property, plant and equipment assets on a pro rata basis using proved reserves values at the transition date.

Leases

The company has elected not to reassess whether an arrangement contains a lease under IFRIC 4, "Determining whether an Arrangement contains a Lease", for contracts that were assessed under previous GAAP.

Business combinations

IFRS 3, "Business Combinations" has not been applied to business combinations that occurred before the transition date.

Borrowing costs

Borrowing costs directly attributable to the acquisition or construction of qualifying assets were not retrospectively restated prior to transition date.

Additional exemptions applied

The company applied additional exemptions for cumulative foreign currency translation differences including compensation, asset retirement obligations/decommissioning liabilities and the share of associate, which are explained in the note 21.5, note 21.6 and note 21.7, respectively.

The following reconciliations present the adjustments made to the company's previous GAAP financial results of operations and financial position to comply with IFRS 1. A summary of the significant accounting policy changes and applicable exemptions are discussed following the reconciliations. Reconciliations include the company's consolidated balance sheets as at June 30, 2010 and December 31, 2010, and consolidated statements of operations and comprehensive income (loss) for the three and six months periods ended June 30, 2010. For reconciliations of the company's consolidated balance sheet as at January 1, 2010 and consolidated statements of operations and comprehensive income (loss) for the year ended December 31, 2010, please refer to the March 2011 Interim Consolidated Financial Statements.

Consolidated balance sheet
As at June 30, 2010


(Canadian dollar in thousands)		IFRS Adjustments
	Previous GAAP	E&E	DD&A & Impairment	Dispos-ition	Foreign Currency	Compe-nsation	ARO	Associ- ate	Taxes	Debt	IFRS
ASSETS	Notes	21.1	21.2	21.3	21.4	21.5	21.6	21.7	21.8	21.9
CURRENT ASSETS
Cash	$69,412	$-	$-	$-	$-	$-	$-	$-	$-	$-	$69,412
Trade and accrued receivables	49,573	-	-	-	-	-	-	-	-	-	49,573
Inventories	51,911	-	-	-	-	-	-	-	-	-	51,911
Other assets	18,932	-	-	-	-	-	-	-	-	-	18,932
	189,828	-	-	-	-	-	-	-	-	-	189,828
NON-CURRENT ASSETS
Other assets	-	-	-	-	-	-	-	1,220	-	-	1,220
Investment in associate	45,621	-	-	-	-	-	-	(5,160)	-	-	40,461
Exploration and evaluation assets	-	111,037	(2,129)	-	-	-	-	-	-	-	108,908
Property, plant and equipment	1,373,996	(111,177)	(5,087)	432	-	(114)	11,163	-	(3,847)	-	1,265,366
Goodwill	103,676		(103,676)	-	-			-	-	-	-
	1,523,293	(140)	(110,892)	432	-	(114)	11,163	(3,940)	(3,847)	-	1,415,955
	$1,713,121	$(140)	$(110,892)	$432	$-	$(114)	$11,163	$(3,940)	$(3,847)	$-	$1,605,783

LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Trade and accrued payables	$89,994	$-	$-	$-	$-	$(368)	$-	$-	$-	$-	$89,626
	89,994	-	-	-	-	(368)	-	-	-	-	89,626
NON-CURRENT LIABILITIES
Long-term debt	888,323	-	-	-	-	-	-	-	-	1,474	889,797
Decommissioning liabilities	37,799	-	-	-	-	-	31,594	-	-	-	69,393
Employee benefits	1,394	-	-	-	-	(722)	-	-	-	-	672
Deferred income taxes	51,445	(35)	(1,802)	108	-	-	(5,124)	(1,105)	(17,278)	-	26,209
	978,961	(35)	(1,802)	108	-	(722)	26,470	(1,105)	(17,278)	1,474	986,071

SHAREHOLDERS' EQUITY
Share capital	586,366	-	-	-	-	(522)	-	-	9,823	-	595,667
Equity component of convertible debentures	16,817	-	-	-	-	-	-	-	-	(16,817)	-
Contributed surplus	33,660	-	-	-	-	415	-	-	-	-	34,075
Retained earnings	21,964	(105)	(109,090)	324	(16,178)	1,083	(15,307)	211	3,608	15,343	(98,147)
Accumulated other comprehensive loss	(14,641)	-	-	-	16,178	-	-	(3,046)	-	-	(1,509)
	644,166	(105)	(109,090)	324	-	976	(15,307)	(2,835)	13,431	(1,474)	530,086
	$1,713,121	$(140)	$(110,892)	$432	$-	$(114)	$11,163	$(3,940)	$(3,847)	$-	$1,605,783

Consolidated balance sheet
As at December 31, 2010


(Canadian dollar in thousands)		IFRS Adjustments
	Previous GAAP	E&E	DD&A & Impairment	AHFS & Disposi-tion	Foreign Currency	Compe-nsation	ARO	Associate	Taxes	Debt	IFRS
ASSETS	Notes	21.1	21.2	21.3	21.4	21.5	21.6	21.7	21.8	21.9
CURRENT ASSETS
Cash	$19,532	$-	$-	$-	$-	$-	$-	$-	$-	$-	$19,532
Trade and accrued receivables	57,419	-	-	-	-	-	-	-	-	-	57,419
Inventories	57,144	-	-	-	-	-	-	-	-	-	57,144
Other assets	17,653	-	-	-	-	-	-	-	-	-	17,653
Deferred tax assets	4,497	-	-	-	-	-	-	-	(4,497)	-	-
Assets held for sale	-	-	-	60,000	-	-	-	28,157	-	-	88,157
	156,245	-	-	60,000	-	-	-	28,157	(4,497)	-	239,905
NON-CURRENT ASSETS
Other assets	615	-	-	-	-	-	-	-	-	-	615
Investment in associate	27,938	-	-	-	-	-	-	(27,938)	-	-	-
Exploration and evaluation assets	-	120,844	(4,609)	(5,286)	-	-	-	-	-	-	110,949
Property, plant and equipment	1,395,524	(121,808)	(770)	(58,392)	-	(53)	11,685	-	(3,413)	-	1,222,773
Goodwill	103,676	-	(103,676)		-	-	-	-	-	-	-
	1,527,753	(964)	(109,055)	(63,678)	-	(53)	11,685	(27,938)	(3,413)	-	1,334,337
	$1,683,998	$(964)	$(109,055)	$(3,678)	$-	$(53)	$11,685	$219	$(7,910)	$-	$1,574,242

LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Trade and accrued payables	$81,886	$-	$-	$-	$-	$(516)	$-	$-	$-	$-	$81,370
Risk management contracts	8,984	-	-	-	-	-	-	-	-	-	8,984
Liabilities relating to assets held for sale	-	-	-	10,907	-	-	-	-	-	-	10,907
	90,870	-	-	10,907	-	(516)	-	-	-	-	101,261
NON-CURRENT LIABILITIES
Risk management contracts	9,879	-	-	-	-	-	-	-	-	-	9,879
Long-term debt	843,601	-	-	-	-	-	-	-	-	3,786	847,387
Decommissioning liabilities	39,191	-	-	(10,907)	-	-	31,754	-	-	-	60,038
Employee benefits	915	-	-	-	-	(722)	-	-	-	-	193
Deferred income taxes	49,359	(242)	(1,342)	(919)	-	-	(6,108)	(636)	(11,613)	-	28,499
	942,945	(242)	(1,342)	(11,826)	-	(722)	25,646	(636)	(11,613)	3,786	945,996

SHAREHOLDERS' EQUITY
Share capital	611,599	-	-	-	-	(522)	-	-	7,551	-	618,628
Equity component of convertible debentures	16,817	-	-	-	-	-	-	-	-	(16,817)	-
Contributed surplus	35,503	-	-	-	-	604	-	-	-	-	36,107
Retained earnings	10,746	(722)	(107,713)	(2,759)	(16,178)	1,103	(13,961)	4,495	(3,848)	13,031	(115,806)
Accumulated other comprehensive loss	(24,482)	-	-	-	16,178	-	-	852	-	-	(7,452)
Accumulated other comprehensive loss for held for sale	-	-	-	-	-	-	-	(4,492)		-	(4,492)
	650,183	(722)	(107,713)	(2,759)	-	1,185	(13,961)	855	3,703	(3,786)	526,985
	$1,683,998	$(964)	$(109,055)	$(3,678)	$-	$(53)	$11,685	$219	$(7,910)	$-	$1,574,242

Consolidated statement of operations and comprehensive income (loss)
For the three months ended June 30, 2010


		IFRS Adjustments
(Canadian dollar in thousands)	Previous GAAP	DD&A and Impairment	Compensation	ARO	Associate	Taxes	Reclass	Debt	IFRS
	Notes	21.2	21.5	21.6	21.7	21.8	21.10	21.9
Revenue	$131,172	$-	$-	$-	$-	$-	$1,705	$-	$132,877
EXPENSES
Purchased products	79,513	-	-	-	-	-	-	-	79,513
Operating costs	23,070	-	-	-	-	-	(942)	-	22,128
Transportation costs	3,200	-	-	-	-	-	1,705	-	4,905
General and administrative	4,278	-	-	-	-	-	942	-	5,220
Share-based compensation	1,137	-	(16)	-	-	-	-	-	1,121
Depletion, depreciation and amortization	18,026	(883)	-	-	-	-	(749)	-	16,394
	129,224	(883)	(16)	-	-	-	956	-	129,281
Earnings before undernoted	1,948	883	16	-	-	-	749	-	3,596
FINANCIAL AND OTHER ITEMS
Finance charges	13,222	-	-	(243)	1,220	-	749	(3,043)	11,905
Interest and other income	(49)	-	-	-	-	-	-	-	(49)
Gain on risk management contracts	(10,049)	-	-	-	-	-	-	-	(10,049)
Foreign exchange loss	32,545	-	-	-	-	-	-	-	32,545
Share of interest in associate	4,242	-	-	-	376	-	-	-	4,618
	39,911	-	-	(243)	1,596	-	749	(3,043)	38,970
EARNINGS (LOSS) BEFORE TAX	(37,963)	883	16	243	(1,596)	-	-	3,043	(35,374)
Income tax expense (recovery)	4,837	(221)	-	(61)	677	(1,575)	-	-	3,657
NET EARNINGS (LOSS)	(33,126)	662	16	182	(919)	(1,575)	-	3,043	(31,717)

OTHER COMPREHENSIVE LOSS AFTER TAX
Exchange differences on translating foreign operations	6,074	-	-	-	-	-	-	-	6,074
Share of other comprehensive loss of associate	113	-	-	-	(1,622)	-	-	-	(1,509)
Recycle share of other comprehensive loss of associate	-	-	-	-	422	-	-	-	422
OTHER COMPREHENSIVE LOSS AFTER TAX	6,187	-	-	-	(1,200)	-	-	-	4,987
TOTAL COMPREHENSIVE INCOME (LOSS)	$(26,939)	$662	$16	$182	$(2,119)	$(1,575)	-	$3,043	$(26,730)



LOSS PER SHARE	Previous GAAP								IFRS
Basic and diluted (note 21.12)	$(0.08)								$(0.07)

Consolidated statement of operations and comprehensive income (loss)
For the six months ended June 30, 2010


		IFRS Adjustments
(Canadian dollar in thousands)	Previous GAAP	E&E	DD&A and Impairment	AHFS & Disposition	Compen-sation	ARO	Associate	Taxes	Reclass	Debt	IFRS
	Notes	21.1	21.2	21.3	21.5	21.6	21.7	21.8	21.10	21.9
Revenue	$251,076	$-	$-	$-	$-	$-	$-	$-	$2,896	$-	253,972
EXPENSES
Purchased products	153,094	-	-	-	-	-	-	-	-	-	153,094
Operating costs	46,170	-	-	-	-	-	-	-	(1,775)	-	44,395
Transportation costs	6,414	-	-	-	-	-	-	-	2,896	-	9,310
General and administrative	9,830	-	-	-	-	-	-	-	1,775	-	11,605
Share-based compensation	3,028	-	-	-	(22)	-	-	-	-	-	3,006
Depletion, depreciation and amortization	36,643	-	(2,967)	-	-	-	-	-	(1,425)	-	32,251
Exploration and evaluation	-	140	-	-	-	-	-	-	-	-	140
	255,179	140	(2,967)	-	(22)	-	-	-	1,471	-	253,801
Earnings before undernoted	(4,103)	(140)	2,967	-	22	-	-	-	(1,425)	-	171
FINANCIAL AND OTHER ITEMS
Finance charges	25,951	-	-	-	-	(450)	1,491	-	1,425	(2,085)	26,332
Interest and other income	(120)	-	-	-	-	-	-	-	-	-	(120)
Gain on disposition of PP&E	-	-	-	(432)							(432)
Gain on revenue-related risk management contracts	(8,485)	-	-	-	-	-	-	-	-	-	(8,485)
Foreign exchange loss	8,602	-	-	-	-	-	-	-	-	-	8,602
Share of interest in associate	4,890	-	-	-	-	-	195	-	-	-	5,085
	30,838	-	-	(432)	-	(450)	1,686	-	1,425	(2,085)	30,982
EARNINGS (LOSS) BEFORE TAX	(34,941)	(140)	2,967	432	22	450	(1,686)	-	-	2,085	(30,811)
Income tax expense (recovery)	7,361	35	(743)	(108)	-	(113)	769	398	-	-	7,599
NET EARNINGS (LOSS)	(27,580)	(105)	2,224	324	22	337	(917)	398	-	2,085	(23,212)

OTHER COMPREHENSIVE LOSS AFTER TAX
Exchange differences on translating foreign operations	1,424	-	-	-	-	-	-	-	-	-	1,424
Share of other comprehensive loss of associate	113	-	-	-	-	-	(2,841)	-	-	-	(2,728)
Recycle share of other comprehensive loss of associate on dilution	-	-	-	-	-	-	422	-	-	-	422
OTHER COMPREHENSIVE LOSS AFTER TAX	1,537	-	-	-	-	-	(2,419)	-	-	-	(882)
TOTAL COMPREHENSIVE INCOME (LOSS)	$(26,043)	$(105)	$2,224	$324	$22	$337	$(3,336)	$398	$-	$2,085	$(24,094)



LOSS PER SHARE	Previous GAAP										IFRS
Basic and diluted (note 21.12)	$(0.06)										$(0.05)

21.1 Exploration and Evaluation ("E&E")

As explained above under "Deemed cost election for oil and gas properties", the company reclassified $111.0 million and $120.8 million to exploration and evaluation assets at June 30, 2010 and December 31, 2010, respectively, based on the deemed carrying amounts representing unproved properties balance as determined under previous GAAP.

The effect of the above adjustment on retained earnings was a reduction of $105,000 after tax benefits of $35,000 for the six months ended June 30, 2010.

21.2 Depletion, Depreciation and amortization ("DD&A") and Impairment

Depletion, depreciation and amortization

Impairment

Under previous GAAP, capitalized costs of oil and gas properties and goodwill were tested for impairment separately as explained below. Under IFRS, capitalized costs of oil and gas properties and goodwill are allocated to cash-generated units for the purpose of the impairment test as explained below.

Under previous GAAP, oil and gas properties impairment was recognized if the carrying amount exceeded the undiscounted cash flows from proved reserves for a country cost centre. Impairment was measured as the amount by which the carrying value exceeded the sum of the fair value of the proved and probable reserves and the costs of unproved properties. The company did not report any impairment under previous GAAP on December 31, 2009 and 2010.

Under previous GAAP, goodwill was tested with reference to the reporting unit. Goodwill including all other assets and liabilities was allocated to the company's segments, referred to as reporting units. To recognize impairment, the fair value of each reporting unit was determined and compared to the carrying value of the reporting unit. If the fair value of the reporting unit was less than the carrying value, then a second test was performed to determine the amount of the impairment. The amount of the impairment was determined by deducting the fair value of the reporting unit's assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill and comparing that amount to the carrying value of the reporting unit's goodwill. Under previous GAAP, the entire goodwill was allocated to the upstream segment and was not considered impaired.

Under IFRS, impairment is recognized if the carrying value exceeds the recoverable amount for a cash-generating unit. A cash-generating unit is defined as the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or group of assets. If the carrying value of the cash-generating unit exceeds the recoverable amount, the cash-generating unit is written down with an impairment recognized in net earnings. The recoverable amount is determined as the higher of value in use and fair value less cost to sell where value in use is the present value of the future cash flows expected to be derived from the cash generating unit and fair value less cost to sell is the estimated amount obtainable from the sale of the cash-generating unit in an arm's length transaction between knowledgeable willing parties, less costs of disposal.

IFRS requires the performance of a goodwill impairment test upon the transition date. The company performed an impairment test by allocating all capitalized costs of oil and gas properties, goodwill and directly related liabilities to applicable cash-generating units based on their ability to generate largely independent cash flows (lower level than previous GAAP) and determined an impairment charge of $113.9 million on January 1, 2010 relating to its Northwest Alberta cash-generating unit (included in upstream segment). The impairment charge amounting to $103.7 million was allocated to goodwill and $10.2 million was allocated to oil and gas properties with the corresponding decrease to retained earnings of $111.3 million net of tax benefits of $2.6 million. The recoverable amount used in the impairment calculation was determined using fair value less costs to sell based on a cash flow valuation model.

21.3 Asset and Liabilities Held For Sale ("AHFS") and Disposition of Oil and Gas Properties

As explained in note 7, the company classified its assets and liabilities relating to certain oil and gas properties (part of the Northern Alberta and Southwest Saskatchewan cash-generating units) as held for sale on December 31, 2010 and recorded them at the lower of their carrying amount or fair value less costs to sell. The adjustment resulted in a classification of carrying amount of property, plant and equipment totaling $54.3 million, exploration and evaluation assets totaling $5.7 million and asset retirement obligations totaling $10.9 million to asset and liabilities classified as held for sale as at December 31, 2010. At December 31, 2010, the impairment charge of $4.5 million was recognized based on the difference between the December 31, 2010 net book value of the assets prior to classification and the recoverable amount. The recoverable amount was determined using fair value less costs to sell which was derived from the sale price agreed under the binding sale agreement with the third party.

In the six months ended June 30, 2010, the company recognized a gain of $432,000 on the sale of certain oil and gas properties under IFRS with a corresponding decrease of the carrying amount of property, plant and equipment. There were no dispositions in the three months ended June 30, 2010. The effect of the adjustments on retained earnings was an increase of $324,000 after tax benefits of $108,000 for the six months ended June 30, 2010.

21.4 Foreign Currency

In accordance with IFRS 1, the company has elected to deem all foreign currency translation differences that arose prior to the transition date in respect of foreign operations and the company's share of associate's translation differences to be nil and reclassified amounts recorded in other comprehensive loss as determined in accordance with previous GAAP to retained earnings. As a result, accumulated other comprehensive loss was decreased by $16.2 million with a corresponding decrease to retained earnings as at January 1, 2010.

21.5 Compensation

Share based payments

In accordance with IFRS 1, the company has elected to apply the requirements of IFRS 2 "share-based payment" to those equity instruments that were issued after November 7, 2002 but that had not vested as of January 1, 2010 and liabilities awards that will be settled after the transition date. As at December 31, 2010 and June 30, 2010, the company had two equity compensation plans.

Employee Stock Option Plan - previous GAAP allowed the company to choose an accounting policy of recording the estimate of forfeiture either on the date of the grant or by recording in a period when forfeiture actually occurs. The company had the accounting policy of recording forfeitures in the period when they occur. IFRS requires entities to measure the estimate of forfeiture at the time of grant. The impact of the estimate of the forfeitures on the unvested options as of January 1, 2010 was not material and hence, no adjustment was recorded on January 1, 2010.

Share Awards to Non-Employee Directors Plan - Under previous GAAP, awards issued under the share awards plan were considered a liability award and were revalued at each reporting period end with changes recorded in the statement of operations with corresponding amounts recorded in trade and accounts payable. Under IFRS 2, the awards issued under the share awards were determined as equity-settled awards and recorded on the date of grant using the grant date fair value. The grant date fair value was determined based on the quoted market price of the related shares. As a result, share-based compensation was decreased reflecting the removal of the impact of revaluation recorded under previous GAAP. Additionally, under previous GAAP, the related share-based compensation which was reported as a part of trade and accounts payables was reclassified to contributed surplus.

The effect of the above share options and share awards adjustments on retained earnings was an increase of $16,000 and $22,000, a reduction of property, plant and equipment of $15,000 and $114,000, reduction of trade and accounts payables of $138,000 and $368,000 and an increase in contributed surplus of $105,000 and $415,000 for the three and six month periods ended June 30, 2010, respectively, excluding the impact of the January 1, 2010 adjustment.

Defined benefit plan

21.6 Asset Retirement Obligation ("ARO")

Under previous GAAP, the asset retirement obligation was measured at the estimated fair value of the retirement and decommissioning expenditures expected to be incurred. Liabilities were not remeasured to reflect period end discount rates. Under IFRS, the asset retirement obligation has been named as "decommissioning liabilities" and is measured as the best estimate of the expenditure to be incurred and requires that the asset retirement obligation be remeasured using the period end discount rate.

In conjunction with the IFRS 1 exemption regarding oil and gas properties discussed above, the company was required to remeasure its decommissioning liabilities upon transition to IFRS and recognize the difference in retained earnings. The application of this exemption resulted in a $20.9 million increase to the decommissioning liabilities on the company's consolidated balance sheet as at January 1, 2010 and a charge to retained earnings of $15.6 million net of tax benefit of $5.2 million. Subsequent IFRS remeasurements of the obligation are recorded through property, plant and equipment with an offsetting adjustment to the decommissioning liabilities. As at June 30, 2010 and December 31, 2010, excluding the January 1, 2010 adjustment, the company's decommissioning liabilities increased by $10.7 million and $10.9 million, respectively, which primarily reflects the remeasurement of the obligation using the company's discount rate of 3.2 percent as at June 30, 2010 and 3.2 percent as at December 31, 2010. The use of the lower discount rate resulted in a decrease in the unwinding of the discount amounting $243,000 and $450,000 in the three and six month periods ended June 30, 2010, respectively.

21.7 Investment in Associate

Petrolifera was a public company and prepared 2010 and previous financial statements in accordance with Canadian generally accepted accounting principles similar to the company's reporting in 2010 and previous years. Accordingly, the company's share of loss, other comprehensive loss, dilution loss and associated deferred tax recorded in 2010 and previous years were based on previous GAAP amounts reported by Petrolifera. As a part of the company's transition to IFRS, the company recorded the adjustments to its share of loss, other comprehensive loss and dilution loss with a corresponding effect on the investment account balance and retained earnings reflecting the adjustments to comply Petrolifera's financial position and results in accordance with IFRS and the accounting policies adopted by the company on its transition date.
In 2009, Petrolifera completed an equity financing under which Petrolifera issued 66.5 million common share units. Each unit was comprised of one Petrolifera common share and one-half Petrolifera share purchase warrant. Connacher subscribed for 13,556,000 units at a cost of $11.9 million. Each full Petrolifera share purchase warrant entitled the holder to purchase one Petrolifera common share at a price of $1.20 per common share for a period of two years from issuance. These share purchase warrants were listed on Toronto Stock Exchange.

Under previous GAAP, the total cost of $11.9 million was recorded as an investment in equity-accounted for investment on the consolidated balance sheet with no value allocated to the share purchase warrants. Under IFRS, share purchase warrants meet the definition of a derivative asset that should be bifurcated from the host contract (investment in associate) and recorded at fair value on each reporting period end with changes recorded in the statement of operations. As a result, the company recorded the fair value of share purchase warrants on January 1, 2010 by increasing other assets and retained earnings.
In April 2010, Petrolifera issued common shares as a part of an equity financing and Connacher did not subscribe for shares in this financing. Accordingly, Connacher's equity interest in Petrolifera was reduced to 18.5 percent from 22 percent. The reduction in the ownership interest resulted in a dilution loss which is required to be recorded under both previous GAAP and IFRS in the consolidated statement of operations. However, the amount of dilution loss under IFRS is different due to IFRS adjustments recorded in the investment account balance as discussed above. Further, IFRS requires the classification of a proportionate amount of gain or loss previously recognized in other comprehensive loss to the statement of operations. Accordingly, the company recyled $422,000 from other comprehensive loss to the statement of operations and reported within the share of interest in associate.
As explained in note 7, under IFRS, assets relating to the investment in Petrolifera were classified as asset held for sale on December 31, 2010. Equity accounting ceased on December 31, 2010 and the carrying amount of investment in associate was classified as asset held for sale and recorded at the lower of its carrying amount and fair value less costs to sell. Under previous GAAP, the accounting standard for classification of assets and liabilities as held for sale was not applicable to the disposition of investment in associate and accordingly, no classification of asset held for sale was reported. However, under previous GAAP, the company recognized impairment to record the investment at its fair value.

The following table summarizes the effect of transition to IFRS relating to investment in Petrolifera:


(Canadian dollar in thousands)		June 30, 2010	December 31, 2010
*Balance sheet*
Amount reported under previous GAAP		$45,621	$27,938
Share of accumulated income (loss)		(1,161)	4,874
Share of accumulated other comprehensive loss		(3,046)	(4,492)
Deferred tax		(953)	(636)
Total Investment balance under IFRS		40,461	27,684
Other asset - derivative financial asset		1,220	474
Total investment in Petrolifera		41,681	28,157
Less: Assets classified as held for sale		$-	$28,157
*Statement of operations***
Share of interest in associate		$(195)	$5,377
Finance charges - change in fair value of derivative		(1,490)	(2,237)
Deferred tax		769	228
Effect to retained earnings excluding January, 1 2010 adjustments		(916)	3,368
Adjustments to retained earnings - January 1, 2010
	Share of loss	(1,584)	(1,584)
	Derivative financial asset	2,711	2,711
		1,127	1,127
Total impact on retained earnings		$211	$4,495

21.8 Taxes

The company recorded the following differences to the amounts reported for deferred tax under previous GAAP compared to IFRS.

Flow-through shares - Under Canadian income tax legislation, a company is permitted to issue flow-through shares whereby the company is obligated to incur qualifying expenditures and renounce the related income tax deductions to the investors. The qualifying expenditures incurred by the company primarily relate to the oil and gas exploratory and development activities. Generally, due to transferring the benefit of tax deduction to the investors, shares on flow-through basis are offered at higher than the prevailing quoted prices of the shares.

Under previous GAAP, the company only recorded a deferred tax liability on renouncement of these qualifying expenditures with a corresponding reduction of share capital. Under IFRS, the proceeds from issuance of these shares are allocated between share capital and a liability to incur the qualifying expenditures in lieu of the sale of tax deductions. The amounts allocated to share capital represents the quoted price of the existing shares whereas the liability represents the difference between the quoted price of the existing shares and the amount the investor pays for the shares. The liability is reversed when qualifying expenditures are renounced for tax purposes and reported within deferred income tax provision in the consolidated statement of operations. As a result, share capital increased by $9.8 million and $7.6 million with a corresponding decrease to retained earnings on June 30, 2010 and December 31, 2010, respectively.

Discount on issue of long-term debt and Capitalized stock-based compensation - Pursuant to Canadian tax regulations, where a debt is issued at a deep discount as defined under the regulations, half of the discount may be deducted upon settlement. Accordingly, upon initial recognition of the liability, there is no accounting basis associated with the discount; however there is tax basis equivalent to half of the discount to be paid upon settlement. Under previous GAAP, the company recognized the deferred tax associated with this temporary difference. Additionally, the company capitalized stock-based compensation directly related to the acquisition and development of oil and gas properties and recorded the related tax impact by increasing the property, plant and equipment and the deferred tax liability under previous GAAP.

IFRS provides an exemption whereby deferred tax on temporary difference is not required to be recorded for an item, which is not a business combination, and at the time of the transaction, neither affects accounting or taxable income. The company elected to use this exemption and accordingly, reversed the previously recognized deferred income tax asset and liability with respect to the above items with a corresponding reduction to retained earnings.

Inter-company capital losses - An adjustment to recognize the deferred tax benefit on an intercompany capital loss was recorded under IFRS which was not permitted under previous GAAP net of any unrealized foreign exchange gain or losses on long-term debt.

Current vs Non-current classification - Under IFRS, all deferred taxes are classified as non-current, irrespective of the classification of the underlying assets or liabilities to which they relate, or the expected reversal of the temporary difference. The effect is to reclassify $4.5 million at December 31, 2010 from deferred tax asset (current) to deferred tax liabilities (non-current).

The above adjustments changed the deferred tax liability as follows:


(Canadian dollar in thousands) As at	June 30, 2010	December 31, 2010
Flow-through shares	$6	$6,943
Capital loss on intercompany transaction	(11,253)	(12,653)
Discount on Long-term Debt	(397)	(875)
Foreign exchange impact on debt	(1,787)	3,470
Capitalized Stock-based compensation	(3,847)	(4,001)
Reclassification	-	(4,497)
Change in deferred tax liability	$(17,278)	$(11,613)

Other items - In addition to the above items, the change in deferred tax liability as at and for the three and six month periods ended June 30, 2010 and as at and for the year ended December 31, 2010 reflects the change in temporary differences resulting from the adjustments on transition to IFRS described above.

21.9 Debt

Under previous GAAP, the convertible debentures were treated as a compound financial instrument with a debt and equity component. Under IFRS, the equity component is considered an embedded derivative. As permitted under IFRS, the company designated the convertible debentures as "fair value through profit and loss" and accordingly, recorded convertible debentures at fair value at each reporting period end with changes reported within the consolidated statement of operations. As a result, the equity portion of convertible debentures was reduced by $16.8 million with a corresponding increase to retained earnings on January 1, 2010, June 30, 2010 and December 31, 2010. In addition, the adjustment resulted in removal of previously recorded accretion expense and recognition of unrealized gains and losses on revaluation. Accordingly, a decrease in finance charges of $3 million and $2 million in the three and six month periods ended June 30, 2010 was recorded with a corresponding change to long-term debt.

21.10 Reclassifications

In order to comply with the presentation of consolidated statement of operations adopted by the company under IFRS, in the downstream segment, the company classified certain transportation costs totaling $1.7 million and $2.9 million to revenue for the three and six month periods ended June 30, 2010, respectively. In addition, the company also classified $942,000 and $1.8 million from operating expenses to general and administrative expenses during the three and six month periods ended June 30, 2010, respectively.

21.11 Changes to the Statement of Cash flow

The following is a reconciliation of the company's cash from operating and investing activities reported in accordance with previous GAAP to cash from operating and investing activities in accordance with IFRS for the six months ended June 30, 2010:


(Canadian dollar in thousands)		Six months ended June 30, 2010
Cash from operating activities under previous GAAP		$1,102
	Exploration and evaluation expenses	(140)
Cash from operating activities under IFRS		$962

Cash used in investing activities under previous GAAP		$(187,344)
	Exploration and evaluation expenses	140
Cash used in investing activities under IFRS		$(187,204)

There was no difference between previous GAAP and IFRS related to cash from financing activities.

21.12 Earnings (loss) per share

Basic and diluted earnings (loss) per share under IFRS were impacted by the IFRS earnings (loss) adjustments discussed above.

For further information:

Richard A. Gusella
Chairman and Chief Executive Officer

Peter D. Sametz
President and Chief Operating Officer

Grant D. Ukrainetz
Vice President, Corporate Development


Phone: (403) 538‐6201		Fax: (403) 538‐6225
inquiries@connacheroil.com		Website: www.connacheroil.com

Légende
	Production
	Mine développement
	Découverte
	Exploration
	Ancien producteur
Sur Google Earth, cliquez sur les pictogrammes, pour voir les informations du projet, accéder à sa page, ou à la page de la compagnie.