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Press release from CNW Group

Connacher's Progress Evident in Q2 2011; Record Bitumen Sales in June at 15,400 Bbl/D; Great Divide Joint Venture Process Underway; Q2 2011 and 1H 2011 Bitumen Production More than Doubled; ; New Drilling Underway at Twining and Penhold Light Crude Oil Resource Plays; Record Refinery Results

Thursday, August 11, 2011

Connacher's Progress Evident in Q2 2011; Record Bitumen Sales in June at 15,400 Bbl/D; Great Divide Joint Venture Process Underway; Q2 2011 and 1H 2011 Bitumen Production More than Doubled; ; New Drilling Underway at Twining and Penhold Light Crude Oil Resource Plays; Record Refinery Results17:14 EDT Thursday, August 11, 2011CALGARY, 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=3625380HIGHLIGHTSGreat Divide bitumen production more than doubled; June 2011 sales were 15,400 bbl/d, a recordGreat 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 2011SAGD+™ steam plus solvent project initiated at AlgarEngaged an advisor and advanced joint venture processStreamlined and strengthened our balance sheet with refinancing of long-term debtAdvanced our asset rationalization process while expanding  involvement in two light gravity crude oil resource plays at Twining (Pekisko) and Penhold (Viking) in central AlbertaRefinery results near record levels; strong results expected for full yearAdjusted 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 resultsOur 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 2011Q1 2011%Q2 2010%YTD 2011YTD 2010%Revenues, net of royalties$234,556$178,99031$132,87777$413,546$253,97263Adjusted EBITDA (1)$37,608$15,845137$20,17386$53,453$34,61354Cash flow (1)$15,873$(5,770)375$8,66983$10,103$12,476(19)     Per share, basic and diluted (1)$0.04$(0.01)500$0.02100$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)160Capital 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$530,086(12) OPERATIONALQ2 2011Q1 2011%Q2 2010%YTD 2011YTD 2010%Daily production volumes (3)         Bitumen (bbl/d)13,72013,20046,21112113,4616,572105 Crude oil (bbl/d)398540(26)906(56)468921(49) Natural gas (Mcf/d)3,7556,805(45)9,278(60)5,2719,469(44) Barrels of oil equivalent (boe/d) (4)14,74414,874(1)8,6637014,8089,07163Upstream pricing (5)         Bitumen ($/bbl)54.4941.783043.132648.2347.771 Crude oil ($/bbl)90.9371.702761.904779.9166.5420 Natural gas ($/Mcf)3.943.57103.7843.704.33(15) Barrels of oil equivalent ($/boe) (4)54.1541.313141.443147.6845.894Downstream         Throughput - Crude charged (bbl/d)9,8609,76419,37359,8129,3605 Refinery utilization (%)1041031995103994 Margins (%)1066713(23)8560(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 volumesWe 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 InformationThis 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+TM on 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 ANALYSISThis 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 REVIEWUPSTREAM - CANADAPRODUCTION AND SALES VOLUMES (1)         Three months ended June 30Six months ended June 30 20112010% Change20112010% ChangeDilbit sales - bbl/d (2)17,0238,29410517,1098,77095Diluent used - bbl/d (2)(3,707)(2,083)78(3,921)(2,198)78Bitumen sold - bbl/d (2)13,3166,21111413,1886,572101Change in inventory and other (3) - bbl/d404-100273-100Bitumen produced - bbl/d (2)13,7206,21112113,4616,572105Crude oil produced and sold - bbl/d398906(56)468921(49)Natural gas produced and sold - Mcf/d3,7559,278(60)5,2719,469(44)Total production volumes - boe/d14,7448,6637014,8089,07163Total sales volumes- boe/d (3)14,3408,6636614,5359,07160(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 production and sales volumes for Algar prior to October 1, 2010(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 lossesBitumen 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 30Six months ended June 30 20112010%20112010%Average benchmark prices       West Texas Intermediate (WTI) crude oil US$/barrel at Cushing$102.34$77.8831$98.50$78.3526Western Canadian Select (WCS) C$/bbl84.7063.963278.2566.8917Differential -WCS to WTI C$/bbl17.6414.092520.2511.5775Natural Gas (Alberta spot) C$/Mcf at AECO3.543.90(9)3.564.41(19)Average realized prices (1)      Bitumen - C$/bbl54.4943.132648.2347.771Crude oil - C$/bbl90.9361.904779.9166.5420Natural gas - C$/Mcf3.943.7843.704.33(15)Weighted average sales price - C$/boe (2)$54.15$41.4431$47.68$45.894(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; andJanuary 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 3020112010($000 except per unit amounts)Oil sandsCrude oilNatural gasTotalOil sandsCrude oilNatural gasTotalGross upstream revenues (2)$118,334$3,320$1,347$123,001$44,616$5,132$3,195$52,943Diluent 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$32,676Price ($ 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 3020112010($000 except per unit amounts)Oil sandsCrude oilNatural gasTotalOil sandsCrude oilNatural gasTotalGross upstream revenues (2)$217,752$6,822$3,533$228,107$99,789$11,131$7,425$118,345Diluent 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$75,347Price ($ 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 3020112010($ 000 except per unit amounts)Oil sandsCrude oilNatural gasTotalOil sandsCrude oilNatural gasTotalRoyalties$4,948$768$(505)$5,211$965$1,317$(128)$2,154Royalties ($ per bbl / Mcf / boe) (2)$4.08$21.20$(1.48)$3.99$1.71$15.98$(0.15)$2.73         Six months ended June 3020112010($ 000 except per unit amounts)Oil sandsCrude oilNatural gasTotalOil sandsCrude oilNatural gasTotalRoyalties$7,333$1,574$(844)$8,063$2,350$2,886$(33)$5,203Royalties ($ per bbl / Mcf / boe) (2)$3.07$18.56$(0.88)$3.06$1.98$17.31$(0.02)$3.17(1)Effective October 1, 2010, the capitalized costs relating to the company's second oil sands project, Algar, were subjected to depletion and the revenues, expenses and finance charges associated with the project were reported in the statement of operations. Prior thereto, Algar was considered a major development project under construction and all costs, including related financing costs and operating expenses net of revenue were capitalized. Accordingly, the above table does not include operating results for Algar prior to October 1, 2010(2)Per unit costs are calculated using royalties divided by bitumen, crude oil and natural gas actual volumes soldRoyalties represent charges against production or revenue by governments and landowners. From period to period, royalties vary due to changes in the product mix, the components of which are subject to different royalty rates. Additionally, royalty rates are applied on a sliding scale to commodity prices. Royalties in Q2 2011 and YTD 2011 increased by 142 percent and 55 percent compared to Q2 2010 and YTD 2010, respectively, primarily due to higher sales volumes and WTI benchmark prices by which royalties are calculated, partially offset by Alberta gas cost allowance recoveries.OPERATING COSTS (1)          Three months ended June 3020112010($ 000 except per unit amounts)Oil sandsCrude oilNatural gasTotalOil sandsCrude oilNatural gasTotalOperating costs$23,776$676$646$25,098$12,770$928$1,473$15,171Operating costs ($ per bbl / Mcf / boe) (2)$19.62$18.67$1.89$19.23$22.59$11.26$1.75$19.25         Six months ended June 3020112010($ 000 except per unit amounts)Oil sandsCrude oilNatural gasTotalOil sandsCrude oilNatural gasTotalOperating costs$49,801$1,577$1,809$53,187$24,811$2,041$3,232$30,084Operating costs ($ per bbl / Mcf / boe) (2)$20.86$18.60$1.90$20.22$20.86$12.24$1.89$18.32(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)Per unit costs are calculated using operating costs divided by bitumen, crude oil and natural gas actual volumes sold 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 30Six months ended June 30 2011201020112010 ($000)%($000)%($000)%($000)%Natural gas costs (1)$7,61132$3,18575$15,12430$7,69869Other operating costs16,165689,5852534,6777017,11331Total oil sands operating costs$23,776100$12,770100$49,801100$24,811100(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; andJanuary 1, 2012 - December 31, 2012 - 5,000 GJ/d a minimum of AECO CAD$3.70/GJ and a maximum of AECO CAD$4.30/GJ.Total conventional crude oil and natural gas operating costs were slightly lower in Q2 2011 and YTD 2011, due to the sale of our Battrum and Marten Creek properties in 2011; on a per unit basis, they were higher, primarily reflecting the fixed cost component and lower production volumes in Q2 2011 and YTD 2011.UPSTREAM NETBACKS (1) Three months ended June 30, 2011Bitumen$ 000Bitumen ($ per bbl)Crude oil$ 000Crude oil ($ per bbl)Natural gas$ 000Natural gas ($ per Mcf)Total$ 000Total ($ per boe)Revenues (2)$66,027$54.49$3,293$90.93$1,347$3.94$70,667$54.15Royalties(4,948)(4.08)(768)(21.20)5051.48(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$30.93          Three months ended June 30, 2010Bitumen$ 000Bitumen($ per bbl)Crude oil$ 000Crude oil($ per bbl)Natural gas$ 000Natural gas($ per Mcf)Total$ 000Total($ per boe)Revenues (2)$24,379$43.13$5,102$61.90$3,195$3.78$32,676$41.44Royalties(965)(1.71)(1,317)(15.98)1280.15(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$19.46         Six months ended June 30, 2011     Bitumen$ 000Bitumen ($ per bbl)Crude oil$ 000Crude oil ($ per bbl)Natural gas$ 000Natural gas ($ per Mcf)Total$ 000Total ($ per boe)Revenues (2)115,129$48.236,776$79.913,533$3.70125,438$47.68Royalties(7,333)(3.07)(1,574)(18.56)8440.88(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$24.40          Six months ended June 30, 2010Bitumen$ 000Bitumen($ per bbl)Crude oil$ 000Crude oil($ per bbl)Natural gas$ 000Natural gas($ per Mcf)Total$ 000Total($ per boe)Revenues (2)$56,826$47.77$11,096$66.54$7,425$4.33$75,347$45.89Royalties(2,350)(1.98)(2,886)(17.31)330.02(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(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)Revenues are calculated after deducting diluent and transportation costs, but before royalties and risk management contract gains or losses(3)Netbacks are a non-GAAP measure and are defined in the Advisory section of the MD&A 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 - USAConnacher'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 30Six months ended June 30 2011201020112010Crude charged - bbl/d(1)9,8609,3739,8129,360Refinery production - bbl/d (2)10,74010,54610,86510,679Sales of refined petroleum products - bbl/d(3)12,02610,07610,6999,274Refinery 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 30Six months ended June 30 20112010%20112010%Average benchmark prices       West Texas Intermediate (WTI) crude oil US$/barrel at Cushing$102.34$77.8831$98.50$78.3526Average realized prices (1)      Gasoline - US$/bbl122.4988.4139110.4386.5928Diesel - US$/bbl124.6094.3232120.5191.3432Asphalt - US$/bbl93.4390.22484.0871.7917Jet fuel - US$/bbl$140.24$96.2846$133.50$95.3240(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$94.00 per barrel.DOWNSTREAM REVENUE       Three months ended June 30Six months ended June 30 2011201020112010Gross revenue (1)($ 000)$120,333$85,693$202,285$148,473Transportation cost (2) ($ 000)(2,387)(1,705)(4,279)(2,896)Revenue ($ 000)$117,946$83,988$198,006$145,577Weighted average sales price ($ 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 $7.2 million in YTD 2010)(2)Transportation cost is deducted in calculating above revenue whereas it is included in expenses in the consolidated statements of operations (3)Per unit prices are calculated using revenue divided by volumes of refined products sold In Q2 2011 and YTD 2011, downstream revenue increased by 40 percent and 36 percent compared to Q2 2010 and YTD 2010, respectively. Higher revenue was primarily due to larger diesel and asphalt sales volumes and higher weighted average realized sales prices for all products were driven by stronger economic conditions in our sales market.CRUDE OIL PURCHASES AND OPERATING COSTS       Three months ended June 30Six months ended June 30 2011201020112010Crude oil purchases and operating costs ($ 000)$106,216$73,008$181,589$138,464Crude oil purchases and operating costs ($ per bbl) (1)$97.06$79.63$93.77$82.49(1)Per unit costs are calculated using crude oil purchases and operations costs divided by volumes of refined products sold In Q2 2011, crude oil purchases and operating costs increased by 45 percent compared to levels in Q2 2010 (31 percent in YTD 2011 compared to YTD 2010), primarily due to higher refined crude oil volumes and higher benchmark crude oil input costs.REFINING NETBACKS (1)       Three months ended June 30Six months ended June 30 2011201020112010Refining netbacks (1)($ 000)$11,730$10,980$16,417$7,113Refining netbacks (weighted average $ per bbl)$10.44$11.97$8.48$4.23Refining 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 REVIEWGAIN (LOSS) ON DISPOSITION OF PROPERTY, PLANT AND EQUIPMENTIn 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 EXPENSESIn 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 CHARGESFinance 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 DEBTAs 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 $8.6 million).  These amounts are volatile in occurrence and can vary significantly from reporting period to reporting period.SHARE BASED COMPENSATION       Three months ended June 30Six months ended June 30($ in 000)2011201020112010Charged to expense$948$1,121$2,013$3,006Capitalized to property, plant and equipment1015191701,072Total$1,049$1,640$2,183$4,078The decrease in share based compensation charges in 2011 is primarily due to a lower number of options being granted in 2011 compared to 2010.DEPLETION, DEPRECIATION AND AMORTIZATION ("DD&A")       Three months ended June 30Six months ended June 30($ in 000)2011201020112010Depletion and amortization expense on upstream property, plant and equipment$20,120$12,168$35,474$24,133Depreciation expense on downstream property, plant and equipment2,2862,5004,3484,846Depreciation on corporate property, plant and equipment5566078571,143Amortization expense on exploration and evaluation assets8951,1191,6522,129Total$23,857$16,394$42,331$32,251Depletion 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 ASSOCIATEIn 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 TAXESThe 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 EXPENDITURESCapital expenditures incurred are presented below:      Three months ended June 30Six months ended June 30($000)2011201020112010Upstream$29,478$50,354$77,964$165,870Downstream5,2831,2598,9582,398Cash-related capital expenditures34,76151,61386,922168,268Non-cash related capital expenditures4,2277,563(7,104)9,180Total capital expenditures$38,988$59,176$79,818$177,448During 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 $10 million of non-cash capitalized items.CAPITAL RESOURCESConnacher's objectives in managing its cash, debt, equity, balance sheet and future capital expenditure programs are to safeguard its ability to meet its financial obligations, to maintain a flexible capital structure that allows financing options when a financing need arises and to optimize its use of short-term and long-term debt and equity at an appropriate level of risk. The company manages its capital structure and follows a financial strategy that considers economic and industry conditions, the risk characteristics and long-term nature of its underlying assets and its growth opportunities. It strives to continuously improve its credit rating and reduce its cost of capital. The company reported the following debt outstanding:   ($ 000)June 30, 2011December 31, 2010Convertible Debentures, 4 ¾%, due June 30, 2012$97,764$96,548First Lien Senior Notes, 11 ¾%, due July 15, 201488184,176Second Lien Senior Notes, 10 ¼%, due December 15, 20153,671566,663Second Lien Senior Notes, 8.75%, due August 1, 2018342,762-Second Lien Senior Notes, 8.5%, due August 1, 2019486,548-Total$930,833$847,387Connacher's capital structure and certain financial ratios are noted below:   ($ 000)June 30, 2011December 31, 2010Long-term debt (1)$829,310$847,387Shareholders' equity467,057526,985Total Long-term debt plus Equity ("capitalization")$1,296,367$1,374,372Long-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 debtAs 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 GuidanceThe 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 - 14,500Conventional Production (boe/d) (1) 1,300 - 1,600Total 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 propertiesWe 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  Conventional2 Refining12 Corporate5Total sustaining and maintenance56Growth capital and special projects  Oil sands6 Conventional61 Refining5 Exploration26 EIA and Algar expansion engineering8Total growth capital and special projects106Total 2011 capital budget on cash basis$162Actual 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 COMMITMENTSIn 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 OUTSTANDINGAs 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; and312,500 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 MANAGEMENTConnacher 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 ESTIMATESAdoption of International Financial Reporting StandardsOn 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 2010YTD 2010Net loss before taxes per previous GAAP$(37,963)$(34,941) Exploration and evaluation expense-(140) Depletion, depreciation, amortization and impairment8842,967 Gain on disposition of oil and gas properties-432 Compensation1622 Unwinding of discount on decommissioning liabilities243450 Interest in associate(1,597)(1,686) Unrealized loss on revaluation of Convertible Debentures3,0432,085 Income taxes3,6577,599Net loss after taxes per IFRS$(31,717)$(23,212)Accounting Policy ChangesThe 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 propertiesUnder 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 CombinationsIFRS 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.ImpairmentUnder 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 PropertiesUnder 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 CurrencyIn 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 PlanThe 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 AssociateAs 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.TaxesThe 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.DebtUnder 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.ReclassificationsIn 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 flowThe 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 endedJune 30, 2010Cash 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 expenses140Cash 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 EstimatesUpstream assets and reservesReserve 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 obligationsThe 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 mattersIn 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 taxesThe 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 instrumentsWe 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 PROCEDURESThe 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 REPORTINGThe 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.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.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.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" 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.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.NON-GAAP MEASUREMENTSThe 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.NETBACKSUpstream 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 EBITDAAdjusted 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 MEASURESCash 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 30Six months ended June 30($000)  2011201020112010Cash 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)$962RECONCILIATIONS OF UPSTREAM AND DOWNSTREAM NETBACKS TO NET LOSS       (Canadian dollar in thousands)Three months ended June 30Six months ended June 30 2011201020112010Upstream netbacks$40,358$15,351$64,188$40,060Downstream netbacks11,73010,98016,4177,113Interest and other income19449541120Gain (loss) on sale of assets(1,369)-27,947432Gain (loss) on risk management contracts24,81610,049(8,413)8,485General and administrative(7,987)(5,220)(18,410)(11,605)Stock-based compensation(948)(1,121)(2,013)(3,006)Finance charges(22,472)(11,905)(49,038)(26,332)Foreign exchange gain (loss)1,144(32,545)18,544(8,602)Depletion, depreciation and amortization(23,857)(16,394)(42,331)(32,251)Income tax recovery (provision)(1,429)3,6575,4757,599Share of interest in and loss on disposition of associate-(4,618)(6,828)(5,085)Exploration and evaluation expenses(71)-(71)(140)Costs of refinancing long-term debt(64,278)-(64,278)-Net loss$(44,169)$(31,717)$(58,270)$(23,212)RECONCILIATIONS OF ADJUSTED EBITDA TO NET LOSS        Three months ended June 30Six months ended June 30(Canadian dollar in thousands)2011201020112010Adjusted EBITDA $37,608$20,173$53,453$34,613Interest and other income 19449541120Defined benefit plan expense (145)(154)(293)(309)Unrealized gain on risk management contracts 31,45411,1416229,749Gain (loss) on disposition of property, plant and equipment (1,369)-27,947432Share-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)3,6575,4757,599Share 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 CONVERSIONSIn 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 HIGHLIGHTSFluctuations 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)20092009201020102010201020112011Three Months EndedSept 30(5)Dec 31(5)Mar 31June 30Sept 30(5)Dec 31(5)Mar 31June 30Revenues, net of royalties$142,729$123,991$121,095$132,877$156,616$182,239$178,990$234,556Cash flow (1)10,410(2,766)3,8078,66915,1789,090(5,770)15,873Basic, per share (1)0.03(0.07)0.010.020.040.02(0.01)0.04Diluted, per share (1)0.03(0.07)0.010.020.040.02(0.01)0.04Adjusted EBITDA (1)16,7244,51314,44020,17325,64231,95115,84537,608Net earnings (loss)47,767(14,731)8,505(31,717)7,946(19,164)(14,101)(44,169)Basic per share0.12(0.03)0.02(0.07)0.02(0.04)(0.03)(0.10)Diluted per share0.11(0.03)0.02(0.07)0.02(0.04)(0.03)(0.10)Capital expenditures100,727116,846118,27259,17649,84220,54840,83038,988Cash on hand333,634256,787118,38269,41251,12019,53242,86531,525Working capital surplus347,139245,067127,416100,20261,54365,37580,90218,954Long-term debt 889,113876,181856,495889,797867,650843,601843,089829,310Shareholders' equity$658,336$671,588$554,328$530,086$648,543$650,183$515,941$467,057OPERATIONAL         Upstream: Daily production volumes (2)         Bitumen - bbl/d6,5516,0906,9366,2116,75813,23813,20013,720 Crude oil - bbl/d993880937906819873540398 Natural gas - Mcf/d10,37710,3199,6629,2789,1588,3186,8053,755 Equivalent - boe/d (3)9,2748,6909,4838,6639,10315,49814,87414,744Product sales prices (4)         Bitumen - $/bbl45.3048.2351.9843.1342.6845.0841.7854.49 Crude oil - $/bbl60.5867.2471.0861.9062.4566.7271.7090.93 Natural gas - $/Mcf2.914.344.863.783.423.443.573.94Selected highlights - $/boe (3)         Weighted average sales price (4)41.7445.7649.9941.4440.7444.0941.3154.15 Royalties2.132.453.572.732.722.762.153.99 Operating costs15.4320.6117.4719.2518.0817.9121.1819.23 Netback (1)24.1822.7028.9519.4619.9423.4217.9730.93Downstream: Refining         Crude charged - bbl/d7,0768,1889,3479,3739,90310,1379,7649,860 Refining utilization - %75869899104107103104 Margins - %8(7)(8)12129610COMMON SHARES        Shares outstanding end of period (000)403,567427,031428,246429,103429,120447,168447,858448,058Weighted average shares outstanding for the period         Basic (000)403,565421,804427,830429,023429,106442,941448,457447,992 Diluted (000)424,058422,344430,077429,023431,487442,941448,457447,992Volume traded (000)129,206207,978167,483182,41998,105137,128180,297127,468Common share price ($)         High1.151.331.651.881.521.351.661.59 Low0.760.941.161.201.151.101.261.03 Close (end of period)1.101.281.491.291.201.331.431.05(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 LIMITEDCondensed 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)NoteJune 30, 2011  December 31, 2010ASSETS     CURRENT ASSETS     Cash $31,525  $19,532Trade and accrued receivables472,707  57,419Inventories 61,824  57,144Investment in equity securities521,197  -Other assets610,560  17,653Assets held for sale711,275  88,157  209,088  239,905NON-CURRENT ASSETS      Other assets6898  615Exploration and evaluation assets8116,707  110,949Property, plant and equipment91,239,960  1,222,773  1,357,565  1,334,337  $1,566,653  $1,574,242       LIABILITIES AND SHAREHOLDERS' EQUITY     CURRENT LIABILITIES     Trade and accrued payables10$75,206  $81,370Current portion of long-term debt12101,523  -Risk management contracts1113,405  8,984Liabilities relating to assets held for sale7-  10,907  190,134  101,261       NON-CURRENT LIABILITIES      Long-term debt12829,310  847,387Decommissioning liabilities1352,399  60,038Deferred income taxes 22,462  28,499Risk management contracts114,837  9,879Employee benefits 454  193  909,462  945,996       SHAREHOLDERS' EQUITY     Share capital14620,049  618,628Contributed surplus15.437,404  36,107Deficit (174,076)  (115,806)Accumulated other comprehensive loss (16,320)  (7,452)Accumulated other comprehensive losson assets held for sale7-  (4,492)  467,057  526,985  $1,566,653  $1,574,242The 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 30Six monthsended June 30(Canadian dollar in thousands)Notes 2011201020112010       REVENUE, NET OF ROYALTIES 20.1 $234,556 $132,877$413,546$253,972EXPENSES      Purchases of crude oil and products20.1 137,57479,513239,741153,094Production and operating expenses20.1 31,38022,12866,39644,395Transportation and handling costs20.1 13,514 4,90526,8049,310General and administrative  7,9875,22018,41011,605Share-based compensation15.3 9481,1212,0133,006Exploration and evaluation expenses  71-71140Depletion, depreciation and amortization  23,85716,39442,33132,251   215,331129,281395,766253,801Earnings before undernoted  19,2253,59617,780171       FINANCIAL AND OTHER ITEMS      Finance charges16 22,47211,90549,03826,332Interest 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 contracts11 (24,816)(10,049)8,413(8,485)(Gain) loss on disposition of property, plant and equipment7.1 1,369-(27,947)(432)Share of interest in and loss on associate7.2 -4,6186,8285,085Costs of refinancing long-term debt12.3 64,278-64,278-   61,96538,97081,52530,982LOSS BEFORE INCOME TAX   (42,740)(35,374)(63,745)(30,811)Income tax (provision) recovery18 (1,429)3,6575,4757,599NET LOSS   (44,169)(31,717)(58,270)(23,212)       OTHER COMPREHENSIVE INCOME (LOSS) AFTER TAX18     Items that may be recycled to statement of operations:      Exchange differences on translating foreign operations  (1,066)6,074(4,395)1,424Available for sale financial asset5 (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 operations7.2 -4224,492422OTHER 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 diluted14 $(0.10)$(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) 20112010SHARE CAPITAL   Balance, beginning of period $618,628$593,119Cash received on shares issued upon exercise of stock options 5951,379Transfer from contributed surplus - stock options exercised 352748Transfer from contributed surplus - share awards issued 534480Share issue costs, net of tax (60)(59)Balance, end of period $620,049$595,667    CONTRIBUTED SURPLUS   Balance, beginning of period $36,107$31,040Share-based compensation 2,1834,078Transfer 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)1,424Available 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 4,492422Balance, end of period $(16,320)$(1,509)Total Shareholders' equity $467,057$530,086The 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)Note2011201020112010OPERATING     Net loss $(44,169)$(31,717)$(58,270)$(23,212)Adjustments for:      Depletion, depreciation and amortization 23,85716,39442,33132,251 Share-based compensation - equity-settled15.39481,1212,0133,006 Finance charges - non-cash portion 8261375,0673,271 Defined benefit plan expense 145154293309 Deferred income tax181,310(3,807)(5,664)(7,955) Unrealized gain on risk management contracts11(31,454)(11,141)(622)(9,749) Share of interest in and loss on associate7.2-4,6186,8285,085 Unrealized foreign exchange (gain) loss1710,35532,910(6,612)9,902 Loss (gain) on disposition of property, plant and equipment 1,369-(27,947)(432) Costs of refinancing long-term debt12.364,278-64,278- Realized foreign exchange gain on settlementof long-term debt (11,592)-(11,592)-  15,8738,66910,10312,476Changes in non-cash working capital (25,378)832(15,385)(11,046)Decommissioning liabilities settled13(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 sale721,340-78,2751,205Changes 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 shares14193(154)5951,379Share issue costs14(38)-(60)(80)Proceeds on issue of long-term debt12945,912-945,912-Repayment of long-term debt12(893,798)-(893,798)-Long-term debt issue cost12(16,452)-(16,452)-Cash flow from financing activities 35,817(154)36,1971,299      NET INCREASE (DECREASE) IN CASH (10,782)(50,800)11,802(184,943)      Foreign exchange loss on cash balancesheld in foreign currency (558)1,830(1,108)(2,432)CASH, BEGINNING OF PERIOD 42,865118,38219,532256,787      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 20101. Nature of Operations and Segment ReportingConnacher 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 PreparationIn 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 PoliciesThese 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 adoptedThe 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, 2011December 31, 2010Trade receivables$32,613$16,904Accrued revenue39,79239,942Other receivables302527Due from associate-46 $72,707$57,419   5. Investment In Equity SecuritiesUpon 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, 2011December 31, 2010Prepayments $9,105$5,754Deposits 19810,779Unamortized transaction costs relating to the credit facility (note 12.4) 1,366939Income taxes refundable 772796Derivative financial asset (note 6.1) 17-Total 11,45818,268Less: 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 $9.62 per common share before August 28, 2011. The common share purchase warrants are classified as held for trading and have been recorded at fair value with changes in the fair value included in finance charges7. Assets and Liabilities Classified as Held For Sale     Canadian dollar in thousands)         NotesJune 30, 2011December 31, 2010Assets classified as held for sale    Property, plant and equipment7.1$-$54,348 Exploration and evaluation assets7.111,2755,652 Investment in associate7.2-27,683 Investment in derivative financial instrument7.2-474Assets classified as held for sale $11,275$88,157    Liabilities associated with assets classified as held for sale    Decommissioning liabilities7.1$-$10,907    Equity associated with assets classified as held for sale    Accumulated other comprehensive loss7.2$-$4,4927.1 Oil and gas propertiesAs 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$96,162Additions25,048Transferred to assets classified as held for sale (note 7.1)(8,688)Balance, December 31, 2010112,522Additions36,673Transfer 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$4,609Transferred to assets classified as held for sale (note 7.1)(3,036)Balance, December 31, 20101,573Charge for the period1,652Balance, June 30, 2011$3,225  Carrying value As at December 31, 2010$110,949As 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)CorporateTotal     Cost    Balance, January 1, 2010$1,029,396$105,789$12,272$1,147,457Additions204,4748,5752,128215,177Dispositions(751)--(751)Change in decommissioning liabilities15,700--15,700Foreign 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, 20101,189,140108,47714,4001,312,017Additions42,3518,95857151,880Transfer from exploration and evaluation assets17,988--17,988Dispositions(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$23,543Depletion and depreciation55,04010,4702,33067,840Impairment charge4,476--4,476Foreign 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, 201054,18527,2617,79889,244Depletion and depreciation35,9254,34885741,130Disposition(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$1,222,773At  June 30, 2011$1,150,349$83,295$6,316$1,239,960In 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, 2011December 31, 2010Accrued liabilities$53,620$54,514Trade payables15,02010,973Accrued interest payable6,33313,280Taxes payable111319Other payables1222,284 $75,206$81,370   11. Financial InstrumentsThe 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, 2011December 31, 2010(Canadian dollar in thousands) Carrying ValueFair ValueCarrying ValueFair ValueLoans and receivables     Cash (1) $31,525$31,525$19,532$19,532Trade and accrued receivables (1) 72,70772,70757,41957,419Available for sale financial assets     Investment in equity securities (2) 21,19721,197--Fair value through profit and loss ("FVTPL")     Derivative financial assets (2) 1717474474Risk management contract liabilities (3) 18,24218,24218,86318,863Convertible debentures (2) 97,76497,76496,54896,548Other liabilities     Trade and accrued payables (1) 75,20675,20681,37081,370Long-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 liabilitiesThe following table summarizes the net position of the company's risk management contracts in the upstream segment:    (Canadian dollar in thousands) June 30, 2011December 31, 2010    Current liability    Oil contracts $13,060$8,241 Natural gas contracts 345743Current liability 13,4058,984Non-current liability    Oil contracts 4,7549,879 Natural gas contracts 83-Non-current liability 4,8379,879Risk management contract liabilities $18,242$18,863The following tables summarize the details of the risk management contract positions:June 30, 2011 - Crude oil contracts      Volume (bbl/d)TermTypePrice(WTI U.S.$/bbl)Liability (Asset) as at June 30, 2011 (Canadian dollar in thousands)2,000Jan 1, 2011 - Dec 31, 2011Swap (1)$90.6011,6632,000Apr 1, 2011 - Mar 31, 2012Call option$96.003,9042,000Apr 1, 2011 - Mar 31, 2012Put option$80.00(893)2,000Jul 1, 2011 - Jun 30, 2012Call option$100.004,7242,000Jul 1, 2011 - Jun 30, 2012Put option$80.00(1,584)2,000Jan 1, 2012 - Dec 31, 2012Call option$120.003,1042,000Jan 1, 2012 - Dec 31, 2012Put 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/bblJune 30, 2011 - Natural gas contracts      Volume (GJ/d)TermTypePrice(AECO CAD$/GJ)Liability (Asset) as at June 30, 2011(Canadian dollar in thousands)4,000Sept 1, 2010 - Aug 31, 2011Swap$3.87$544,000Oct 1, 2010 - Sept 30, 2011Swap$4.202095,000Jan 1, 2012 - Dec 31 2012Call option$4.30(496)5,000Jan 1, 2012 - Dec 31 2012Put option$3.70541Balance, 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 3020112010 (Canadian dollar in thousands)UpstreamUpstreamDownstream (1)TotalUnrealized gain$31,454$10,436$705$11,141Realized 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 3020112010 (Canadian dollar in thousands)UpstreamUpstreamDownstream (1)TotalUnrealized gain$622$9,658$91$9,749Realized loss(9,035)(497)(767)(1,264)Gain (loss) on risk management contracts$(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$9/bbl. The contract expired on September 30, 2010.12. Long-Term Debt      June 30, 2011December 31, 2010 Notes    (Canadian dollar in thousands)Second Lien Senior Notes, due August 1, 2019 (US$ 550 million)12.1$530,365$-Second Lien Senior Notes, due August 1, 2018 (CAD$ 350 million)12.1350,000-Second Lien Senior Notes, due December 15, 2015 (US$ 3.8 million)12.23,777584,168First Lien Senior Notes, due July 15, 2014 (US$ 100,000)Senior Notes, due July 15, 2014 (US$ 100,000)12.296198,920Convertible Debentures, due June 30, 2012 (CAD$ 100 million)       97,764     96,548Total debt       982,002      879,636Unamortized transaction costs        (51,169)       (32,249)Current portion of long-term debt (101,523)-Long-term debt $829,310      $847,387    12.1 Second Lien Senior Notes issued in 2011In May 2011, the company issued US$ 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 $10 million. Any any time prior to August 1, 2015, the company may redeem some or all of the New Notes at their principal amount plus a make whole premium plus applicable interest. At any time, the company may redeem all or part of the US-dollar denominated notes at 108.5 percent and Canadian-dollar denominated notes at 108.75 percent with the net proceeds of an asset sale. After August 1, 2015 the New Notes may be redeemed at redemption prices ranging from 104.25 percent, reducing to 100 percent on August 1, 2017, and thereafter for the US-dollar denominated notes and for Canadian-dollar denominated notes at 104.375 percent reducing to 100 percent on August 1, 2017 and thereafter.Upon a change of control of the company, the holders of the notes may require the company to purchase the notes at the redemption prices noted above, with a minimum price of 101 percent of the principal amount to be repurchased.12.2 First Lien Senior Notes due 2014 and and Second Lien Senior Notes due 2015In conjunction with the completion of the issuance of the New Notes described in note 12.1, the company repurchased US$ 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 debtAs 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 LiabilitiesThe following table summarizes the details of decommissioning liabilities:   (Canadian dollar in thousands)Six months ended June 30, 2011Year endedDecember 31, 2010Balance, beginning of period $70,945 $53,729Liabilities incurred25911,560Liabilities acquired2,229-Liabilities settled(813)(647)Liabilities disposed(9,881)(263)Change in estimates(11,223)4,463Unwinding of discount8832,103Balance, end of period52,39970,945Classified 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, 2011Year ended December 31, 2010(Canadian dollar in thousands except number of shares)NumberAmountNumberAmountBalance, beginning of period447,167,694$618,628427,031,362$593,119Issued for cash on flow-through basisnet of premium of $2,272--17,480,00023,074Cash received on exercise of stock options608,0885952,017,8361,936Transfer from contributed surplus - stock options-352-1,082Transfer from contributed surplus - share awards282,209534638,496480Share issue cost, net of tax-(60)-(1,063)Balance, end of period448,057,991$620,049447,167,694$618,628      Three months ended June 30Six months ended June 30 2011201020112010Weighted average common shares outstandingbasic and diluted447,991,640429,022,518447,799,247428,429,659Outstanding 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.15Stock Option Plan and Share Award Plan for Directors 15.1  Stock option planThe following table summarizes the changes in stock options and the related weighted average exercise prices:   Six months ended June 3020112010 Numberof OptionsWeighted AverageExercise PriceNumberof OptionsWeighted AverageExercise PriceOutstanding, beginning of period24,413,668$1.5022,579,045$1.72Granted4,034,0141.329,123,0841.38Exercised(608,088)0.98(1,433,134)0.96Forfeited(827,415)1.25(374,145)1.31Expired(475,500)4.36(843,000)3.00Outstanding, end of period26,536,679$1.4429,051,850$1.62Exercisable, end of period15,883,779$1.5514,404,099$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 3020112010Risk free interest rate (percent)1.91.9Expected option life (year)3.03.0Expected volatility (percent)5572   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 DirectorsThe following table summarizes the changes in share award plan for directors:   For the six months ended June 30 20112010Outstanding, beginning of period380,598648,916Granted375,000380,598Vested and Settled(406,640)(638,496)Cancelled(36,458)-Outstanding, end of period312,500391,018Vested, end of period-10,42015.3  Share-based compensation              Three months ended June 30Six months ended June 30(Canadian dollar in thousands)2011201020112010Equity-settled grants    Employee stock option plan$927$1,485$1,944$3,907Share award plan for Directors122155239171          1,0491,6402,1834,078Less: Share-based compensation capitalized(101)(519)(170)(1,072)          $948$1,121$2,013$3,00615.4  Contributed surplus    (Canadian dollar in thousands)Six months ended June 30, 2011Year endedDecember 31, 2010Balance, beginning of period$36,107$31,040Equity-settled share-based compensation2,1836,629Transfer 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 30Six months ended June 30(Canadian dollar in thousands)2011201020112010Interest expense on long-term debt$22,655$23,989$46,167$48,326Amortization of transaction costs relating to the Facility86209198327Stand-by fees relating to the Facility167500258500Bank charges and other fees92142181142Unrealized loss on derivative financial asset (note 6.1)3201,2201351,491Unwinding of discount on decommissioning liabilities (note 13)437505883974Unrealized (gain) loss on remeasurement of convertible debentures(1,285)(2,000)1,216- 22,47224,56549,03851,760Less: Interest capitalized-(12,660)-(25,428)Finance charges$22,472$11,905$49,038$26,332     17. Foreign Exchange Gain (Loss)      (Canadian dollar in thousands)Three months ended June 30Six months ended June 30 2011201020112010Unrealized foreign exchange gain (loss) on translation of:     U.S. denominated long-term debt$(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 gain11,49936511,9321,300Foreign exchange gain (loss)$1,144$(32,545)$18,544$(8,602)   18. Income TaxesIncome tax recovery (provision) recognized in statement of operations     Three months ended June 30Six months ended June(Canadian dollar in thousands)2011201020112010Current     Canada$(119)$(154)$(189)$(360) USA-4-4Total current tax(119)(150)(189)(356)Deferred tax (provision) recovery(1,310)3,8075,6647,955Income 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 ManagementThe 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, 2011December 31, 2010Long-term debt (1)$829,310$847,387Shareholders' equity467,057526,985Total long-term debt plus equity ("capitalization")$1,296,367$1,374,372Long-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 Information20.1  Results of operations      (Canadian dollar in thousands)For the three months ended June 30, 2011CanadaUpstream      USADownstreamCorporate &Eliminations ConsolidatedRevenues, net of royalties$117,790$120,333$(3,567)$234,556Purchases 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) 40,35811,730-52,088Realized loss on risk management contracts - net(6,638)--(6,638)General and administrative expenses(6,897)(1,090)-(7,987)Segment operating income26,82310,640-37,463Depletion, depreciation and amortization(21,015)(2,286)(556)(23,857)Segment income (loss)5,8088,354(556)13,606Interest and other income--194194Loss on disposition of property, plant and equipment--(1,369)(1,369)Unrealized gain on risk management contracts - net--31,45431,454Share-based compensation--(948)(948)Finance charges--(22,472)(22,472)Foreign exchange loss--1,1441,144Exploration 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, 2010CanadaUpstream      USADownstreamCorporate &Eliminations ConsolidatedRevenues, net of royalties$50,789$85,693$(3,605)$132,877Purchases of crude oil and products(17,065)(66,053)3,605(79,513)Production and operating expenses(15,173)(6,955) (22,128)Transportation and handling costs(3,200)(1,705)-(4,905) 15,35110,980-26,331Realized loss on risk management contracts - net(325)(767)-(1,092)General and administrative expenses(4,123)(1,097)-(5,220)Segment operating income10,9039,116-20,019Depletion, depreciation and amortization(13,512)(2,346)(536)(16,394)Segment income (loss)(2,609)6,770(536)3,625Interest and other income--4949Unrealized gain risk management contracts - net--11,14111,141Share-based compensation--(1,121)(1,121)Finance charges--(11,905)(11,905)Foreign exchange loss--(32,545)(32,545)Income tax recovery--3,6573,657Share of interest in associate and loss on associate--(4,618)(4,618)Net earnings (loss)$(2,609)$6,770$(35,878)$(31,717)     (Canadian dollar in thousands)For the six months ended June 30, 2011CanadaUpstream      USADownstreamCorporate &Eliminations ConsolidatedRevenues, net of royalties$220,044$202,285$(8,783)$413,546Purchases 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) 64,18816,417-80,605Realized loss on risk management contracts - net(9,035)--(9,035)General and administrative expenses(16,101)(2,309)-(18,410)Segment operating income39,05214,108-53,160Depletion, depreciation and amortization(37,126)(4,348)(857)(42,331)Segment income (loss)1,9269,760(857)10,829Interest and other income--541541Gain on disposition of property, plant and equipment--27,94727,947Unrealized gain on risk management contracts - net--622622Share-based compensation--(2,013)(2,013)Finance charges--(49,038)(49,038)Foreign exchange gain--18,54418,544Exploration 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--5,4755,475Net earnings (loss)$1,926$9,760$(69,956)$(58,270)     (Canadian dollar in thousands)For the six months ended June 30, 2010CanadaUpstream      USADownstreamCorporate &Eliminations ConsolidatedRevenues, net of royalties$113,142$148,473$(7,643)$253,972Purchases 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) 40,0607,113-47,173Realized loss on risk management contracts - net(497)(767)-(1,264)General and administrative expenses(9,830)(1,775)-(11,605)Segment operating income29,7334,571-34,304Depletion, depreciation and amortization(26,262)(4,846)(1,143)(32,251)Segment income (loss)3,471(275)(1,143)2,053Interest and other income--120120Gain on disposition of property, plant and equipment--432432Unrealized gain on risk management contracts--9,7499,749Share-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--7,5997,599Net earnings (loss)$3,471$(275)$(26,408)$(23,212)20.2  Capital expenditures     Three months ended June 30Six months ended June 30(Canadian dollar in thousands)2011201020112010Upstream$29,479$50,354$77,964$165,870Downstream5,2821,2598,9582,398Total cash related capital expenditures$34,761$51,613$86,922$168,268     21. First time adoption of IFRSAs 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 propertiesUnder 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 combinationsIFRS 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 sheetAs at June 30, 2010    (Canadian dollar in thousands)IFRS Adjustments   Previous GAAPE&EDD&A & ImpairmentDispos-itionForeign CurrencyCompe-nsationAROAssoci-ateTaxesDebtIFRSASSETSNotes21.121.221.321.421.521.621.721.821.9 CURRENT ASSETS           Cash$69,412$-$-$-$-$-$-$-$-$-$69,412Trade and accrued receivables49,573---------49,573Inventories51,911---------51,911Other assets18,932---------18,932 189,828---------189,828NON-CURRENT ASSETS           Other assets-------1,220--1,220Investment in associate45,621------(5,160)--40,461Exploration and evaluation assets-111,037(2,129)-------108,908Property, plant and equipment1,373,996(111,177)(5,087)432-(114)11,163-(3,847)-1,265,366Goodwill103,676 (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)----89,626NON-CURRENT LIABILITIES          Long-term debt888,323--------1,474889,797Decommissioning liabilities37,799-----31,594---69,393Employee benefits1,394----(722)----672Deferred income taxes51,445(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)1,474986,071            SHAREHOLDERS' EQUITY           Share capital586,366----(522)--9,823-595,667Equity component ofconvertible debentures16,817--------(16,817)-Contributed surplus33,660----415----34,075Retained earnings21,964(105)(109,090)324(16,178)1,083(15,307)2113,60815,343(98,147)Accumulated othercomprehensive 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 sheetAs at December 31, 2010  (Canadian dollar in thousands)IFRS Adjustments  Previous GAAPE&EDD&A & ImpairmentAHFS & Disposi-tionForeignCurrencyCompe-nsationAROAssociateTaxesDebtIFRSASSETSNotes21.121.221.321.421.521.621.721.821.9 CURRENT ASSETS           Cash$19,532$-$-$-$-$-$-$-$-$-$19,532Trade and accrued receivables57,419---------57,419Inventories57,144---------57,144Other assets17,653---------17,653Deferred tax assets4,497-------(4,497)--Assets held for sale---60,000---28,157--88,157 156,245--60,000---28,157(4,497)-239,905NON-CURRENT ASSETS           Other assets615---------615Investment in associate27,938------(27,938)---Exploration and evaluation assets-120,844(4,609)(5,286)------110,949Property, plant and equipment1,395,524(121,808)(770)(58,392)-(53)11,685-(3,413)-1,222,773Goodwill103,676-(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)$-$-$-$-$81,370Risk management contracts8,984---------8,984Liabilities relating to assets held for sale---10,907------10,907 90,870--10,907-(516)----101,261NON-CURRENT LIABILITIES          Risk management contracts9,879---------9,879Long-term debt843,601--------3,786847,387Decommissioning liabilities39,191--(10,907)--31,754---60,038Employee benefits915----(722)----193Deferred income taxes49,359(242)(1,342)(919)--(6,108)(636)(11,613)-28,499 942,945(242)(1,342)(11,826)-(722)25,646(636)(11,613)3,786945,996            SHAREHOLDERS' EQUITY          Share capital611,599----(522)--7,551-618,628Equity component of convertible debentures16,817--------(16,817)-Contributed surplus35,503----604----36,107Retained earnings10,746(722)(107,713)(2,759)(16,178)1,103(13,961)4,495(3,848)13,031(115,806)Accumulated othercomprehensive 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)8553,703(3,786)526,985 $1,683,998$(964)$(109,055)$(3,678)$-$(53)$11,685$219$(7,910)$-$1,574,242Consolidated statement of operations and comprehensive income (loss)For the three months ended June 30, 2010    IFRS Adjustments (Canadian dollar in thousands)PreviousGAAPDD&A and ImpairmentCompensationAROAssociateTaxesReclassDebtIFRS Notes21.221.521.621.721.821.1021.9 Revenue$131,172$-$-$-$-$-$1,705$-$132,877EXPENSES         Purchased products79,513-------79,513Operating costs23,070-----(942)-22,128Transportation costs3,200-----1,705-4,905General and administrative4,278-----942-5,220Share-based compensation1,137-(16)-----1,121Depletion, depreciationand amortization18,026(883)----(749)-16,394 129,224(883)(16)---956-129,281Earnings before undernoted1,94888316---749-3,596FINANCIAL AND OTHER ITEMS         Finance charges13,222--(243)1,220-749(3,043)11,905Interest and other income(49)-------(49)Gain on risk management contracts(10,049)-------(10,049)Foreign exchange loss32,545-------32,545Share of interest in associate4,242---376---4,618 39,911--(243)1,596-749(3,043)38,970EARNINGS (LOSS) BEFORE TAX (37,963)88316243(1,596)--3,043(35,374)Income tax expense (recovery)4,837(221)-(61)677(1,575)--3,657NET EARNINGS (LOSS) (33,126)66216182(919)(1,575)-3,043(31,717)          OTHER COMPREHENSIVE LOSS AFTER TAX         Exchange differences on translating foreign operations6,074-------6,074Share of other comprehensive loss of associate113---(1,622)---(1,509)Recycle share of other comprehensive loss of associate----422---422OTHER COMPREHENSIVE LOSS AFTER TAX 6,187---(1,200)---4,987TOTAL COMPREHENSIVE INCOME (LOSS) $(26,939)$662$16$182$(2,119)$(1,575)-$3,043$(26,730)                              LOSS PER SHAREPreviousGAAP       IFRSBasic 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 GAAPE&EDD&A and ImpairmentAHFS & DispositionCompen-sationAROAssociateTaxesReclassDebtIFRS Notes21.121.221.321.521.621.721.821.1021.9 Revenue$251,076$-$-$-$-$-$-$-$2,896$-253,972EXPENSES           Purchased products153,094---------153,094Operating costs46,170-------(1,775)-44,395Transportation costs6,414-------2,896-9,310General and administrative9,830-------1,775-11,605Share-based compensation3,028---(22)-----3,006Depletion, depreciationand amortization36,643-(2,967)-----(1,425)-32,251Exploration and evaluation-140--------140 255,179140(2,967)-(22)---1,471-253,801Earnings beforeundernoted(4,103)(140)2,967-22---(1,425)-171FINANCIAL AND OTHER ITEMS           Finance charges25,951----(450)1,491-1,425(2,085)26,332Interest and other income(120)---------(120)Gain on disposition of PP&E---(432)      (432)Gain on revenue-relatedrisk management contracts(8,485)---------(8,485)Foreign exchange loss8,602---------8,602Share of interest in associate4,890-----195---5,085 30,838--(432)-(450)1,686-1,425(2,085)30,982EARNINGS (LOSS) BEFORE TAX (34,941)(140)2,96743222450(1,686)--2,085(30,811)Income tax expense (recovery)7,36135(743)(108)-(113)769398--7,599NET EARNINGS (LOSS) (27,580)(105)2,22432422337(917)398-2,085(23,212)            OTHER COMPREHENSIVE LOSS AFTER TAX           Exchange differences on translating foreign operations1,424---------1,424Share of other comprehensive loss of associate113-----(2,841)---(2,728)Recycle share of other comprehensive loss of associate on dilution------422---422OTHER 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 SHAREPrevious GAAP         IFRSBasic 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.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, 2010.21.2 Depletion, Depreciation and amortization ("DD&A") and Impairment Depletion, depreciation and amortizationUnder 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.ImpairmentUnder 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 PropertiesUnder 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.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 CurrencyIn 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 CompensationShare based paymentsIn 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 planThe 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.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 AssociateAs 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.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, 2010Balance sheet  Amount reported under previous GAAP$45,621$27,938Share of accumulated income (loss)(1,161)4,874Share of accumulated other comprehensive loss(3,046)(4,492)Deferred tax(953)(636)Total Investment balance under IFRS40,46127,684Other asset - derivative financial asset1,220474Total investment in Petrolifera41,68128,157Less: Assets classified as held for sale$-$28,157Statement of operations   Share of interest in associate$(195)$5,377Finance charges - change in fair value of derivative(1,490)(2,237)Deferred tax769228Effect to retained earnings excluding January, 1 2010 adjustments(916)3,368Adjustments to retained earnings - January 1, 2010   Share of loss(1,584)(1,584) Derivative financial asset2,7112,711 1,1271,127Total impact on retained earnings$211$4,49521.8 TaxesThe 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, 2010Flow-through shares  $6  $6,943Capital loss on intercompany transaction  (11,253)  (12,653)Discount on Long-term Debt  (397)  (875)Foreign exchange impact on debt  (1,787)  3,470Capitalized 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 DebtUnder 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 ReclassificationsIn 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.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).21.11 Changes to the Statement of Cash flowThe 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 endedJune 30, 2010Cash 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   140Cash 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 OR Peter D. Sametz President and Chief Operating Officer OR Grant D. Ukrainetz Vice President, Corporate Development       Phone: (403) 538‐6201      Fax: (403) 538‐6225 inquiries@connacheroil.com     Website: www.connacheroil.com