Connacher's Bitumen Sales Reach Record Monthly Level During March 2011; Price Outlook Strong For Balance Of 2011; Long Term Note Tender Offer Launched; New Conventional Resource Play At Twining, Alberta Shows Early Promise

CALGARY, May 17 /CNW/ - Connacher Oil and Gas Limited (CLL-TSX) achieved record monthly bitumen production during February 2011 and record bitumen sales during March 2011, as operations at Great Divide Pod One were stable and the Algar rampup continued.  Our first quarter 2011 ("Q1 2011") bitumen sales were 13,059 bbl/d, an increase of 88 percent over Q1 2010, reflecting the continuing impact of Algar production volumes. With the recent completion of the mandated Algar turnaround in early May 2011, which was conducted in only five days, Connacher is optimistic about the prospect of achieving higher and sustainable bitumen production at much improved prices, with better netbacks, during the remainder of the year.  Bitumen prices have almost doubled from their low in February 2011, as world prices have escalated, differentials have narrowed and certain factors which adversely affected bitumen and heavy oil markets during the early part of 2011, including weather, pipeline apportionment and regional upgrader purchase restrictions, have dissipated.

On May 10, 2011, Connacher launched a tender offer to repurchase its outstanding "high yield" long-term notes due in 2014 and 2015.  Among other things, the offer is conditional upon the tender of the notes and receipt of consents representing at least a majority of the aggregate principal amount of each series of notes outstanding on or prior to June 7, 2011 and the completion, by Connacher, of one or more long-term secured debt financings in the high yield market, on terms acceptable to the company and in an amount that is sufficient to pay the offered purchase price in respect of all notes tendered, including estimated and related fees and expenses.  The initial settlement date pursuant to the tender is currently expected to be May 31, 2011.

The objective of this transaction is to allow Connacher to refinance its long term debt with new debt at a lower interest cost with an extended term.  The company believes this will result in an improvement in its overall financial condition and outlook.

Our Great Falls, Montana refinery had a creditable Q1 2011 with good utilization rates, despite this being a "winter" quarter, which typically results in less demand for our refined products. We experienced excellent pricing for gasoline and diesel, in particular and we recorded positive net operating income for Q1 2011, compared to a net operating loss in Q1 2011.

While the significant investment in our oil sands operations is Connacher's primary focus, we have maintained a conventional production base to assist us in financing our overall operations.  We recently rationalized our property base, including the sale of our more mature assets at Battrum, Saskatchewan and of our shallow natural gas properties at Marten Creek, Alberta, for cash. Nevertheless, we have significant in-house geological, geophysical, drilling and engineering expertise generating new ideas.   As we are awaiting the regulatory review of our proposed Great Divide expansion, we are experiencing a relative hiatus in our oil sands activity. Our current focus at the oil sands is on production optimization and the introduction of innovative technologies, such as steam-assisted gravity drainage plus solvent ("SAGD plus solvent"). This gave us the opportunity to capitalize on our in-house technical expertise, allowing us to expand our conventional activity into resource play types that we believe have high potential.

Arising out of this initiative, we are also pleased with the progress we have achieved to date in our drilling and the evaluation program on one of our new light gravity, high netback crude oil resource plays.  At Twining, Alberta we have developed a Pekisko resource play.   During December 2010 and in Q1 2011,  we carefully  acquired approximately one township of petroleum and natural gas rights in this region, shot 3D seismic and drilled core holes to obtain detailed geological and reservoir information. During December 2010 and in Q1 2011, we also drilled and cased three long-reach horizontal wells, which were completed with multifrac technology adapted to our particular reservoir and requirements.  An early and protracted spring breakup has delayed our progress on this project to some extent, but we have successfully tied in two of the three wells.  The third well has been completed and is awaiting the installation of equipment and a tie-in, which should happen imminently.  The first drilled well has yielded approximately 16,000 barrels of oil equivalent ("boe") since being placed onstream in late February 2011, with peak production exceeding 300 boe/d, 30-day average production of 200 boe/d and 60 day average production of 210 boe/d.   Crude oil production has represented approximately 82 percent of total boe production during this time.  Water cuts were as anticipated and stable at around 50 percent of total fluids produced.  Our second well was placed onstream in April 2011 and is demonstrating a somewhat higher, but stable to improving crude oil cut, a higher gas/oil ratio and stable production similar to the typical Pekisko vertical well.  We are awaiting receipt of additional information from the third drilled well and more production history before advancing "type" curves.  Connacher is enthusiastic about these early results, which produced strong netbacks and the prospect of attractive per well and project economics for the play.  We will be undertaking a measured one rig, four well development program, contemplated to commence in the 2H 2011, to further prove up this opportunity.  Based on current geological mapping and our established land position, we believe we currently have over 100 identified drilling locations and anticipate initially developing the play on a four well per section basis.  Readers are cautioned that the results of one, two or three initial wells with limited production history may not be fully indicative of the eventual overall results of a resource play such as our Pekisko project at Twining, Alberta, or elsewhere.

Separately, we have also accumulated an extensive land position on another light gravity crude oil resource play in central Alberta.  We also anticipate drilling our first of two wells on this play during 2H 2011, alongside the anticipated new drilling at Twining.

As a consequence of this expanded conventional activity, our Board of Directors has authorized an increase in our 2011 capital budget from the previously approved level of $122 million to $162 million, with the increase largely related to these prospective high return, high netback conventional resource projects.

Summary operating and financial results for the period are as follows:

Highlights

  • New light gravity crude oil Pekisko discoveries drilled at Twining, Alberta; over 100 follow-up locations identified
  • Record Great Divide bitumen production in February 2011 and record bitumen sales in March 2011
  • Tender offer and debt refinancing program initiated May 10, 2011 to extend term, reduce interest costs resulting in higher cash flow available for growth; target close of May 31, 2011
  • To date, successful asset sales add $80 million cash which reduces net debt, after some deployment; more asset rationalization with sale of non-cash generating holdings could increase proceeds to approximately $150 million total during 2011
  • Successful Q1 2011 oil sands core hole program provides new leads and opportunities

Summary Results

               
 
Three months ended March 31
FINANCIAL ($000 except per share amounts) 2011     2010     % Change
Revenues, net of royalties $175,801     $120,034     46
Cash flow (1) $(5,770)     $3,807     (252)
  Per share, basic and diluted (1) $(0.01)     $0.01     (200)
Adjusted EBITDA (1) $15,845     $14,440     10
Net earnings (loss) $(14,101)     $8,505     (266)
  Per share, basic $(0.03)     $0.02     (250)
Capital expenditures $40,830      $118,272     (65)
Proceeds on disposition of assets $56,935     $1,205     4,625
Cash on hand $42,865     $118,382     (64)
Working capital $80,902     $127,416     (37)
Long-term debt $834,089     $856,495     (3)
Shareholders' equity $515,941     $554,328     (7)
OPERATIONAL              
Daily production volumes (3)              
  Bitumen (bbl/d) 13,200     6,936     90
  Crude oil (bbl/d) 540     937     (42)
  Natural gas (Mcf/d) 6,805     9,662     (30)
  Barrels of oil equivalent (boe/d) (4) 14,874     9,483     57
Upstream pricing (5)              
  Bitumen ($/bbl) 41.78     51.98     (20)
  Crude oil ($/bbl) 71.70     71.08     1
  Natural gas ($/Mcf) 3.57     4.86     (27)
  Barrels of oil equivalent ($/boe) (4) 41.31     49.99     (17)
Downstream              
  Throughput - Crude charged (bbl/d) 9,764     9,347     4
  Refinery utilization (%) 103     98     5
  Margins (%) 6     (6)     175

(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 at the period end. Actual volumes sold were 14,732 boe/d in Q1 2011 (Q1 2010 - 9,483 boe/d)
(4)     All references to barrels of oil equivalent (boe) are calculated on the basis of 6 Mcf: 1 bbl. This conversion is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Boes may be misleading, particularly if used in isolation
(5)     Before royalties and risk management contract gains or losses and after applicable diluent and transportation costs divided by actual sales volumes

While we had lower than anticipated financial and operating results during Q1 2011, they were largely the result of terrible winter weather early in the year and the lingering effects of the pipeline curtailments, which adversely affected marketing conditions and resulted in periodic bitumen production curtailment in the first two months of the year.  Additionally, there were occasional shortages of available dilbit trucks. This is the first time since we started up Pod One in 2008 that we have lost any production volumes or sales due to weather or trucking, to provide a sense of the issues.  Other factors which emerged included the necessity of seeking out new markets, resulting from an abrupt, albeit temporary, cancellation of dilbit purchases by a regional upgrader; the dislocation of West Texas Intermediate ("WTI") from the Brent crude benchmark; and the adverse influence of lower volumes on reported per unit operating costs. Fortunately, this "perfect storm" is over, we are optimistic about the outlook for the balance of 2011 and already prices for dilbit and, by deduction, for bitumen have risen dramatically from their lows in February 2011.  For example, indications are April prices are almost double those achieved in February.

Based on anticipated forward sales, the outlook is good.  We also expect continuing solid production results at Great Divide, having completed the Algar turnaround and with the recent completion, commissioning and startup of the Horse River electrical substation located near our operations at Great Divide, we envisage more power reliability, leading to consistent steam production and injection which will sustain the improved reliability at Pod One.

This in turn augers well for increased oil production, as we enhance steam: oil ratios ("SORs") through various technological innovations targeted for both projects during 2011.  We have now received approvals to proceed with our "SAGD plus solvent" project at Algar and if our pilot is successful, we envisage a broader application throughout our existing production base.  The objective is to enhance well productivity at lower SORs with this initiative.

We anticipate engaging in a formal joint venture search process later in 2011 to help diversify risk and to assist in the financing of our oil sands expansion plan, pursuant to the expansion proposal and Environmental Impact Assessment we have submitted for approval to regulators.  We believe that this approach will enable us to expand and grow aggressively with little or no additional incurral of debt or permanent equity share dilution. This is a sensible strategy for Connacher to pursue at this stage of its development, especially in light of also owning identified high return conventional opportunities in our project inventory.  We have proven operating and construction expertise, including an on-time, on-budget reputation, which we anticipate will be attractive to other companies seeking to secure exposure to Canada's oil sands and near term bitumen production.  We will in the meantime focus our attention on further enhancement and optimization of our existing production base while engaging in this process, which will be formalized later in 2011, after we complete our tender and related refinancing of our long term debt.

In early 2011, we were successful in selling certain conventional assets no longer considered to be strategic to our future for a total of $80 million.  We also intend to monetize our shareholdings of Gran Tierra Energy Inc. ("Gran Tierra") and other non-cash generating assets.  Combined, we estimate these transactions may add a total of approximately $150 million of cash to our working capital, initially reducing our net debt and providing a higher level of liquidity for our planned business activities.

Our Annual and Special Meeting of Shareholders is scheduled for today's date and we are pleased to advise that both leading proxy advisory firms in Canada and the U. S. A. have recommended that their clients vote in favour of all resolutions being brought before the meeting.  We have a good governance track record and intend to continue to emphasize this along with our social responsibilities, including our relationships with Aboriginal peoples and with the environment.  We encourage you to visit our website at www.connacheroil.com and review our recent publications in this regard.

In light of legal restrictions relating to our previously announced tender offer for our outstanding notes and related transactions, there will not be a follow-up conference call to this press release, as is our normal custom.  Also, there will not be a webcast of our Shareholders Meeting nor will there be an operational update presentation at such meeting.  Our normal procedures will be reinstated when we issue our Q2 2011 and 1H 2011 results, anticipated for August 11, 2011 with a conference call anticipated to occur the morning of August 12, 2011. Further call in and timing details will be provided.

We also wish to advise our shareholders and investors that our financial statements are now being presented under the aegis of International Financial Reporting Standards ("IFRS"), with a restatement of comparative results achieved in Q1 2010.  This will be the basis of future reporting by all Canadian public companies.  This change does not affect the way we conduct our operations in any manner.  There will be some accounting and reporting adjustments required and we have explained this in our financial statements.  Our Finance group, our Audit Committee and our Board of Directors have invested considerable effort in this process and we thank them for their dedication to the successful and timely completion of this task.

Forward Looking Information:

This press release contains forward looking information including but not limited to expectations of future production, pricing and netbacks, anticipated sources of funding for capital expenditures, future development and exploration activities, possible joint venture arrangements, improved stability of power at Pod One and Algar, new innovations to be introduced in 2011 and the expected impact thereof on future SORs and well productivity, the anticipated monetization of Connacher's interest in Gran Tierra Energy Inc., anticipated proceeds from Connacher's asset rationalization program, anticipated initial settlement date of the tender offer and the anticipated impact thereof on Connacher's overall financial condition and outlook, and the potential of Connacher's conventional resource plays.

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: the risks associated with the oil and gas industry (e.g., operational risks in development, exploration and production; 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 geological interpretations, 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, risks and uncertainties associated with securing and maintaining the necessary regulatory approvals and financing to proceed with the operation and continued expansion of the Great Divide oil sands project and risks associated with the sale of other non-cash generating assets.

In this press release, 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.

In addition, 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 press release due to, among other factors, difficulties or interruptions encountered during production.

Additional risks and uncertainties affecting Connacher and its business and affairs are described in further detail in Connacher's Annual Information Form 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 herein is made as of the date of this press release and Connacher assumes no obligation to update or revise any forward looking information to reflect new events or circumstances, except as required by law.

MANAGEMENT'S DISCUSSION AND ANALYSIS

This Management's Discussion and Analysis ("MD&A") for Connacher Oil and Gas Limited ("Connacher" or the "company") is dated May 17, 2011 and should be read in conjunction with Connacher's condensed interim consolidated financial statements for the three months ended March 31, 2011 ("Q1 2011") and the MD&A and the audited consolidated financial statements for the year ended December 31, 2010 and 2009.

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

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

FINANCIAL AND OPERATING REVIEW

UPSTREAM - CANADA

COMMODITY PRICES AND RISK MANAGEMENT

       
  Three months ended March 31
  2011 2010 %
Average benchmark prices      
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing $94.10 $78.71 20
Western Canadian Select (WCS) C$/bbl 70.23 72.51 (3)
Differential - WTI/WCS C$/bbl 22.55 9.42 139
Natural Gas (Alberta spot) C$/Mcf at AECO 3.76 5.33 (29)
Average realized prices (1)      
Bitumen - C$/bbl 41.78 51.98 (20)
Crude oil - C$/bbl 71.70 71.08 1
Natural gas - C$/Mcf 3.57 4.86 (27)
Weighted average sales price - C$/boe (2) $41.31 $49.99 (17)

(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 crude oil and bitumen production slate is a heavy gravity crude. Consequently, the crude oil and 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 such items as the cost of diluent, transportation charges for both diluent from sales points to our Great Divide project  and for dilbit from our Great Divide project to market.  Other factors which influence calculated bitumen prices include the relative value of the Canadian dollar and the blend ratio of bitumen to diluent.

In Q1 2011, although benchmark crude oil prices were higher compared to Q1 2010, realized bitumen prices were lower, primarily due to wider heavy oil differentials, a stronger Canadian dollar relative to the U.S. dollar and higher transportation charges necessitated by the need to seek out transportation alternatives and new distant markets because of pipeline apportionment issues. The heavy oil differential discount widened due to Enbridge pipeline disruptions in the USA that limited the transportation capacity for heavy crude oil. In addition, high storage levels at Cushing, Oklahoma contributed to lower realized prices for heavy crude volumes.  Lower realized natural gas prices in Q1 2011 were due to lower benchmark prices.

Dilbit, crude oil and natural gas are generally sold on month-to-month sales contracts negotiated with major Canadian or U.S. marketers, refiners, regional upgraders or other end users, either at spot reference prices or at prices subject to commodity contracts 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 preferred 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 revenue in Q1 2011 was also influenced by the following WTI crude oil price risk management contracts:

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

The company recorded unrealized and realized losses of $30.9 million and $2.1 million, respectively, in Q1 2011 (Q1 2010 - unrealized and realized losses of $1.4 million and $0.2 million, respectively) on the above risk management contracts.

PRODUCTION AND SALES VOLUMES (1)

                 
Three months March 31   2011     2010     % Change
Dilbit sales - bbl/d (2)   17,197     9,249     86
Diluent used - bbl/d (2)   (4,138)     (2,313)     79
Bitumen sold (2)   13,059     6,936     88
Change in inventory and other - bbl/d   141     -     100
Bitumen produced - bbl/d (2)   13,200     6,936     90
Crude oil produced and sold - bbl/d   540     937     (42)
Natural gas produced and sold - Mcf/d   6,805     9,662     (30)
Total production volumes - boe/d   14,874     9,483     57
Total sales volumes- boe/d (3)   14,732     9,483     55

(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

Bitumen production increased by 90 percent in Q1 2011 compared to Q1 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 Q1 2011, conventional crude oil production and sales volumes decreased by 42 percent, compared to Q1 2010, 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 30 percent primarily due to natural reservoir declines.

UPSTREAM REVENUE (1)

                                                 
Three months ended March 31                       2011                       2010
($000 except per unit amounts)     Oil sands     Crude oil     Natural gas     Total     Oil sands     Crude oil     Natural gas     Total
Gross upstream revenues (2)     $99,418     $3,502     $2,186     $105,106     $55,173     $5,999     $4,230      $65,402
Diluent costs (3)     (38,937)     -     -     (38,937)     (19,517)     -     -     (19,517)
Transportation costs     (11,379)     (19)     -     (11,398)     (3,209)     (5)     -     (3,214)
Revenues     $49,102     $3,483     $2,186     $54,771     $32,447     $5,994     $4,230     $42,671
Price ($ per bbl / Mcf / boe) (4)     $41.78     $71.70     $3.57     $41.31      $51.98     $71.08      $4.86      $49.99

(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 cost have been included in "Upstream-diluent purchases and operating costs" in the consolidated financial statements. Diluent costs, above, include purchases of $5.2 million from our subsidiary, MRCI in Q1 2011 (Q1 2010 - $4.0 million) 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 60 percent in Q1 2011 compared to Q1 2010, primarily due to higher bitumen revenue, partially offset by lower crude oil and natural gas revenue. Higher bitumen revenue in Q1 2011 was primarily due to higher bitumen sales volumes resulting from Algar.

Diluent used represented approximately 24 percent of the dilbit barrel sold in Q1 2011 (25 percent in 2010). Total diluent costs increased by 100 percent in Q1 2011 compared to Q1 2010, due to the 88 percent increase in bitumen sales volume (as a result of Algar) and a 20 percent increase in diluent pricing, which was driven by higher benchmark prices in Q1 2011, which also reflected the disconnect between WTI and the Brent crude oil benchmark, which is more aligned with diluent pricing than is the case for WTI.

Transportation costs are costs to transport dilbit and crude oil to customers. Transportation costs increased by 255 percent in Q1 2011 compared to Q1 2010, due to increased bitumen sales volumes, higher trucking costs and increased sales travel distances to markets in Q1 2011 arising from the Enbridge pipeline disruptions. Additionally, we recently commenced railing some dilbit to new USA west coast markets to alleviate downstream barriers and to access new sales markets that are less connected to current WTI/WCS pricing levels. Although this resulted in higher transportation costs, higher inventory levels and related carrying costs, we anticipate over time that higher netbacks may be achieved so we will continue to pursue these options, in part because our operations are not geared to maintaining high levels of on-site storage.

ROYALTIES (1)

                                                 
Three months ended March 31, 2011 March 31, 2010
($ 000 except per unit amounts)     Oil sands     Crude oil     Natural gas     Total     Oil sands     Crude oil     Natural gas     Total
Royalties     $2,385     $806     $(339)     $2,852     $1,385     $1,569     $95     $3,049
Royalties ($ per bbl / Mcf / boe) (2)     $2.03     $16.59     $(0.55)     $2.15     $2.22     $18.60     $0.11     $3.57

(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 sold

Royalties represent charges against production or revenue by governments and landowners. From period to period, royalties vary due to changes in the product mix, the components of which are subject to different royalty rates. Additionally, royalty rates are applied on a sliding scale to commodity prices. Royalties in Q1 2011 decreased by 6 percent compared to Q1 2010, primarily due to lower sales of crude oil and natural gas. Additionally, Alberta gas cost allowance recoveries also resulted in lower royalties in Q1 2011 compared to Q1 2010. In our oil sands operation, royalties increased by 72 percent due to higher sales volumes and higher prices.

OPERATING COSTS (1)

                                                 
Three months ended March 31                       2011                       2010
($ 000 except per unit amounts)     Oil sands     Crude oil     Natural gas     Total     Oil sands     Crude oil     Natural gas     Total
Operating costs     $26,025     $901     $1,163     $28,089     $12,041     $1,113     $1,759     $14,913
Operating costs ($ per bbl / Mcf / boe) (2)     $22.14     $18.55     $1.90     $21.18     $19.29     $13.20     $2.02     $17.47

(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 Q1 2011 were 88 percent higher than in Q1 2010, primarily due to costs associated with Algar, which was not operative in Q1 2010. Oil sands operating costs increased by 116 percent in Q1 2011 compared to Q1 2010 and by 15 percent on a per unit basis in Q1 2011 compared to Q1 2010.

The primary reason for the increase in total and per unit oil sands operating costs in Q1 2011 compared to Q1 2010 related to new production volumes at Algar. Additionally, the continued ramp-up of bitumen production at Algar in 2011 and continued increase in the volume and reliability of production at Pod One, accompanied by a rigorous cost control program, should spread our fixed operating costs over a larger production base and lower unit operating costs.

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

                 
Three months ended March 31       2011       2010
    ($000)   %   ($000)   %
Natural gas costs (1)   $7,513   29   $4,513   37
Other operating costs   18,512   71   7,528   63
Total oil sands operating costs   $26,025   100   $12,041   100

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

In Q1 2011, the combined steam: oil ratio ("SOR") from Pod One and Algar was 3.8; in Q1 2010, when only Pod One was in operation, it was 3.5. As production ramps up from both projects, we anticipate lower SORs. New technologies may also contribute to lower SORs and higher productivity in subsequent years.

The company also recorded risk management contract losses of $192,000 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; and
  • October 1, 2010 - September 30, 2011 - 4,000 GJ/d at AECO CAD$4.20/GJ.

Total conventional crude oil operating costs were slightly lower in Q1 2011, due to the sale of our Battrum properties in February 2011; on a per unit basis, they were higher primarily due to a significant fixed component and lower production volumes in Q1 2011.

Total natural gas operating costs were higher in Q1 2011 due to higher production volumes in Q1 2011.

UPSTREAM NETBACKS (1) ($000 except per unit amounts)

                                             
Three months ended March 31, 2011 Bitumen
$ 000
    Bitumen
($ per bbl)
    Crude oil
$ 000
    Crude oil
($ per bbl)
    Natural gas
$ 000
    Natural gas
($ per Mcf)
    Total
$ 000
    Total
($ per boe)
Revenues (2) $49,102     $41.78     $3,483     $71.70     $2,186     $3.57     $54,771     $41.31
Royalties (2,385)     (2.03)          (806)     (16.59)     339     $0.55     (2,852)     (2.15)
Operating costs (26,025)     (22.14)     (901)     (18.55)     (1,163)     ($1.90)     (28,089)     (21.18)
Netbacks (3) $20,692     $17.61     $1,776     $36.56     $1,362     $2.22     $23,830     $17.98
                                             
Three months ended March 31, 2010 Bitumen
$ 000
    Bitumen
($ per bbl)
    Crude oil
$ 000
    Crude oil
($ per bbl)
    Natural gas
$ 000
    Natural gas
($ per Mcf)
    Total
$ 000
    Total
($ per boe)
Revenues (2) $32,447      $51.98     $5,994      $71.08     $4,230      $4.86     $42,671      $49.99
Royalties (1,385)     (2.22)     (1,569)     (18.60)     (95)     (0.11)     (3,049)     (3.57)
Operating costs (12,041)     (19.29)     (1,113)     (13.20)     (1,759)     (2.02)     (14,913)     (17.47)
Netbacks (3) $19,021      $30.47     $3,312      $39.28      $2,376      $2.73     $24,709      $28.95

(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 non-GAAP measure and are defined in the Advisory section of the MD&A

Notwithstanding higher sales volumes as a result of the contribution from Algar, total upstream netbacks were 4 percent lower in Q1 2011 compared to Q1 2010, due to lower bitumen prices, lower crude oil and natural gas sales volumes and higher operating costs for bitumen. On a unit of production basis, lower bitumen prices and higher bitumen operating costs resulted in lower corporate netbacks for all commodities produced and sold.  Weak natural gas prices also impaired pricing on a boe basis.

DOWNSTREAM - USA

Connacher's 9,500 bbl/d heavy oil refinery is located in Great Falls, Montana (the "Refinery") and 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 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 neighboring regions, including, Alberta, Canada, by truck and rail transport.

The Refinery is subject to a number of seasonal factors which cause product sales revenues to vary throughout 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.

COMMODITY PRICES AND RISK MANAGEMENT

                         
Three months ended March 31     2011     2010           %
Average benchmark prices                        
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing     $94.10     $78.71           20
Average realized prices (1)                        
Gasoline - US$/bbl     98.68      85.07           16
Diesel - US$/bbl     117.13      87.63           34
Asphalt - US$/bbl     53.42      53.33           -
Jet fuel - US$/bbl     $126.56      $94.05           35

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

Higher benchmark prices for refined products in Q1 2011 compared to Q1 2010 resulted in higher realized weighted average sales prices for our refined petroleum products. Sales of refined petroleum products are generally made on monthly 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. Occasionally, sales contracts are for periods in excess of one month. As at March 31, 2011, MRCI has agreements to sell approximately 732,000 barrels of asphalt at a weighted average price approximating US$ 101.00 per barrel.

REFINERY THROUGHPUT

             
Three months ended March 31     2011     2010
Crude charged - bbl/d (1)     9,764     9,347
Refinery production - bbl/d (2)     10,991     10,814
Sales of refined petroleum products - bbl/d (3)     9,358     8,439
Refinery utilization (4)     103%     98%

(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
(4) Represents crude charged divided by total crude capacity of the Refinery

In Q1 2011, the total sales volume of refined petroleum products increased by 11 percent compared to Q1 2010 primarily due to the improved stability of refining operations and increased demand for refined petroleum products in Q1 2011. In Q1 2011, a significant portion of our Refinery sales was derived from gasoline (4,759 bbl/d or 51%), diesel (2,309 bbl/d or 25%), jet fuel (524 bbl/d or 6%) and asphalt (1,477 bbl/d or 16%). Increases in gasoline, diesel and asphalt sales volumes in Q1 2011 were offset by a slight decrease in jet fuel sales volumes.

DOWNSTREAM REVENUE

             
Three months ended March 31     2011     2010
Gross revenue (1) ($ 000)     $81,952      $62,780
Transportation cost (2) ($ 000)     (1,892)     (1,191)
Revenue ($ 000)     $80,060     $61,589
Weighted average sales price ($ per bbl) (3)     $95.06      $81.09

(1)     Includes intersegment sales of $5.2 million in Q1 2011 (Q1 2010 - $4.0 million), which were transacted at prevailing market prices and have been eliminated from the consolidated financial statements
(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 Q1 2011, downstream revenue was 30 percent higher compared to Q1 2010, primarily due to larger sales volumes and higher weighted average realized sales prices. Total sales volume increased by 11 percent in Q1 2011 compared to Q1 2010 and the weighted average sales price of refined petroleum products sold increased by 17 percent, driven by stronger economic conditions in our sales market.

CRUDE OIL PURCHASES AND OPERATING COSTS

             
Three months ended March 31     2011     2010
Crude oil purchases and operating costs ($ 000)     $75,373     $65,456
Crude oil purchases and operating costs ($ per bbl) (1)     $89.50     $85.93

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

In Q1 2011, crude oil purchases and operating costs increased by 15 percent compared to levels in Q1 2010, primarily due to higher refined crude oil volumes and higher benchmark crude oil prices. Notwithstanding that WTI crude oil prices increased by 20 percent in Q1 2011 compared to Q1 2010, crude oil purchases and operating costs per barrel only increased by four percent, primarily due to the benefit of lower feedstock costs due to wider heavy crude oil differentials in Q1 2011.

REFINING NETBACKS (1)

             
Three months ended March 31     2011     2010
Refining netbacks (1) ($ 000)     $4,687      $(3,867)
Refining netbacks (weighted average $ per bbl)     $5.56      $(4.84)
Refining netbacks (% of revenue)     6%     (6)%

(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 221 percent higher in Q1 2011 compared to Q1 2010 when costs exceeded revenues and refining netbacks per barrel of refined petroleum product sold also demonstrated significant improvement. This increase was due to refining and selling higher volumes, higher realized prices and lower feedstock costs due to wider heavy oil differentials in Q1 2011.

CORPORATE REVIEW

INTEREST AND OTHER INCOME

In Q1 2011, the company earned interest and other income of $29.8 million (Q1 2010 - $0.5 million), primarily from the sale of non- strategic conventional oil and gas properties.

GENERAL AND ADMINISTRATIVE EXPENSES

In Q1 2011, general and administrative ("G&A") expenses were $10.4 million, compared to $6.4 million in Q1 2010, an increase of 63 percent, primarily due to personnel costs of an expanded staff required to support corporate growth and the payment of 2010 bonuses primarily related to the successful completion, startup and operations at Algar, including the construction of the project on time, under budget and similarly for the related Cogeneration plant and the continuing addition of bitumen reserves and net asset value through ongoing evaluation programs.

FINANCE CHARGES

Finance charges include interest expense relating to the Convertible Debentures, First and Second Lien Senior Notes and the Revolving Credit Facility (the "Facility"), amortization of the Facility transaction costs, standby fees associated with the Facility and fees on letters of credit issued. Finance charges also include non-cash accretion charges with respect to the Convertible Debentures and First and Second Lien Senior Notes. In Q1 2010, the company capitalized $12.8 million of interest on a portion of its long-term debt, proceeds of which were used to finance the construction of major oil sands projects.  No amounts have been capitalized in Q1 2011. Total finance charges were $26.8 million in Q1 2011 (Q1 2010 - $14.4 million)

SHARE BASED COMPENSATION

             
Three months ended March 31 ($ in 000)     2011     2010
Charged to expense     $1,065     $1,885
Capitalized to property, plant and equipment     69     553
Total     $1,134     $2,438

The decrease in share based compensation charges in Q1 2011 is primarily due to a lower number of options being granted in Q1 2011 compared to Q1 2010. Additionally, the vesting period for the options granted in Q1 2011 was longer compared to the options granted in Q1 2010.

FOREIGN EXCHANGE GAINS

The value of the Canadian dollar relative to the U.S. dollar has strengthened. This had a significant impact on Connacher's results, upon translating its U.S. dollar-denominated long-term debt and U.S. dollar cash balances into Canadian dollars for financial reporting purposes. As a result of the higher Canadian dollar, we recorded foreign exchange gains of $17.4 million in Q1 2011 (Q1 2010 -$23.9 million).  These amounts are volatile in occurrence and can vary significantly from reporting period to reporting period.

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

             
Three months ended March 31 ($ in 000)     2011     2010
Depletion expense on upstream property, plant and equipment     $16,111     $12,750
Depreciation expense on downstream property, plant and equipment     2,062     2,500
Depreciation on corporate property, plant and equipment     301     607
Total     $18,474      $15,857

Depletion expense is calculated using the unit-of-production method, based on estimated total proved and probable ("2P") reserves. Provision is made for future capital costs which are estimated to be required to realize production from the company's 2P reserve base. Depletion equated to $12.04/boe of production in Q1 2011 (Q1 2010 - $14.94/boe of production). Effective October 1, 2010, the capitalized costs relating to major oil sands project, Algar, were subjected to depletion, which resulted in higher depletion expense in Q1 2011 compared to Q1 2010. Downstream and corporate property, plant and equipment are depreciated over their estimated useful lives.

PETROLIFERA PETROLEUM LIMITED ("PETROLIFERA")

In March 2011, Petrolifera 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 on disposition of $2.3 million and transferred a loss $4.5 million to the consolidated statement of operations which was previously recognized in other comprehensive loss. The company carries investment in Gran Tierra Energy common shares and warrants at fair value on the balance sheet.

INCOME TAXES

The total income tax recovery of $6.9 million in Q1 2011 (Q1 2010 - $3.9 million) included a current income tax of $67,000 (Q1 2010 - $206,000) and the future income tax recovery of $7.0 million in Q1 2011 (Q1 2010 -$4.1 million) reflected the change in tax pools during the periods.

NET EARNINGS (LOSS)

The company incurred a net loss of $14.1 million in Q1 2011 compared to net earnings of $8.5 million in Q1 2010, primarily due to the impact of non-cash charges, including higher unrealized losses on risk management contracts, higher depletion, depreciation and amortization offset by lower unrealized foreign exchange gains.

SHARES OUTSTANDING

As at March 31, 2011, the number of common shares issued and outstanding was 447.9 million (December 31, 2010 - 447.2 million). The increase in Q1 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 May 17, 2011, the company had the following securities issued and outstanding.

  • 448,007,281 common shares;
  • 26,365,354 stock options under the company's Stock Option Plan; and
  • 375,000 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.

CAPITAL INVESTMENT

Capital expenditures incurred are presented below:

             
Three months ended March 31 ($000)     2011     2010
Crude oil, natural gas and oil sands expenditures     $37,154     $117,133
Refinery expenditures     3,676     1,139
      $40,830     $118,272

During Q1 2011, maintenance and sustaining capital of $12 million was incurred, including $7 million at our oil sands operations to install three high temperature downhole electric submersible pumps at Algar and facility enhancements at Pod One and Algar; $3 million at our refinery; and $2 million in our conventional operations and corporate activities.  Q1 2011 growth and special projects capital of $40 million was incurred, including $13 million in our conventional operations related to the purchase of petroleum and natural gas rights and our initial  horizontal well program at Twining, Alberta; $26 million during our winter 2011 oil sands exploration program; and $1 million related to the benzene removal project at our Refinery. In addition, reversal of non-cash asset abandonment provisions and share-based compensation amounting to $11 million were recorded in the period.

In Q1 2010, expenditures of $49 million were incurred on the Algar project; $11 million was incurred at Pod One to finish drilling and completing two additional SAGD well pairs and for other facility enhancement expenditures; $22 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 winter 2010 exploration program; $10 million of capital expenditures were incurred for co-generation, pipeline facilities and the Great Divide expansion project; and $17 million was capitalized for interest and G&A costs.  Additionally, $8 million was incurred on conventional drilling (one oil well, four natural gas wells and four abandoned wells), land acquisitions, seismic, well workovers, facilities and corporate and administrative assets.

RECENT FINANCINGS

Flow-Through Shares

In October 2010, to fund the company's 2011 exploration program the company issued 17,480,000 common shares on a flow-through basis at a price of $1.45 per common share, for gross proceeds of $25.3 million and renounced the qualifying expenditures to investors, effective December 31, 2010.  All of these expenditures have been incurred.

LIQUIDITY AND CAPITAL RESOURCES

In Q1 2011, cash flow was a negative $5.8 million ($0.01 per basic and diluted share outstanding) compared to positive cash flow of $3.8 million ($0.01 per basic and diluted share outstanding) in Q1 2010. Negative cash flow in Q1 2011 was primarily due to lower bitumen prices, lower realized net backs and higher general and administrative expenses compared to Q1 2010.

At March 31, 2011, the company had working capital of $80.9 million (December 31, 2010 - $138.6 million), including $42.9 million of cash (December 31, 2010 - $19.5 million). As at March 31, 2011, there were limited outstanding capital expenditure commitments and, as all of the company's indebtedness is long-term in nature, with no principal repayment obligation until June 2012, management believes that the company has sufficient liquidity and anticipated financial capacity, in combination with anticipated cash to be generated from operations in 2011, to fund its ongoing capital program and to continue to satisfy its financial obligations.

Inventory balances increased as at March 31, 2011 compared to December 31, 2010, primarily due to higher inventory volumes and increases in the value of our refined petroleum products. Higher accounts payable and accrued liabilities as at March 31, 2011, compared to December 31, 2010, reflect increased liabilities associated with our winter drilling program which started in early 2011 and increases in accrued interest expense.

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 March 31, 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.

In April 2011, the company sold Marten Creek/Randall property for $22.5 million, prior to normal closing adjustments. The sale proceeds were added to Connacher's cash balances and working capital, thereby reducing net debt.

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

The company reported the following debt outstanding:

             
As at ($ 000)     March 31, 2011     December 31, 2010
Convertible Debentures, 4 ¾%, due June 30, 2012     $99,050     $96,548
First Lien Senior Notes, 11 ¾%, due July 15, 2014     180,732     184,176
Second Lien Senior Notes, 10 ¼%, due December 15, 2015     554,307      566,663
Total - no current maturities     $834,089     $847,387

On May 10, 2011, the company announced a tender offer to redeem all of its outstanding First Lien and Second Lien Senior Notes, subject to, among other things, the majority of the aggregate principal amount of each series of Notes being tendered for redemption and the completion of one or more secured debt financings, on terms acceptable to Connacher, in an amount sufficient to fund the redemption of all outstanding Notes and related fees and expenses.

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

             
As at ($ 000)     March 31, 2011     December 31, 2010
Long-term debt (1)     $834,089     $847,387
Shareholders' equity     515,941     526,985
Total Debt plus Equity ("capitalization")     $1,350,030     $1,374,372
Debt to book capitalization (2)     61%     62%

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

As at March 31, 2011, the company's net debt (long-term debt, net of cash on hand) was $791 million. Net debt to book capitalization was 59 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 March 31, 2011, the company is in compliance with all of the terms of its debt agreements.

OUTLOOK

Despite a weak Q1 2011, for reasons explained herein, 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 the continued production ramp-up at Algar.  We also anticipate favorable results from our refining and conventional operations. Our focus in 2011 will be on optimizing our production at Great Divide, rationalizing non-core conventional assets, expanding our new resource plays in central Alberta areas with drilling success and delivering successive and sustained improvement in operating and financial results, at lower cost.

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.

The company's 2011 production guidance and revised cash capital expenditure budget is as follows:

       
2011 Production guidance      
Bitumen Production (bbl/d)     14,500 - 16,500
Conventional Production (boe/d) (1)     1,000 - 1,400
Total Upstream Production (boe/d)     15,500 - 17,900

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

   
2011 capital budget on a cash basis   ($ in millions)
Sustaining and maintenance capital  
  Oil sands $35
  Conventional 2
  Refining 10
  Corporate 6
Total sustaining and maintenance 53
Growth capital and special projects  
  Oil sands 8
  Conventional 56
  Refining 9
  Exploration 26
  EIA and Algar expansion engineering 10
Total growth capital and special projects 109
Total 2011 capital budget $162

Our Board of Directors has approved an increase in our full year 2011 cash capital budget, from $122 million to $162 million.  The $40 million increase primarily relates to growth projects in our conventional operations, including $30 million related to the acquisition of petroleum and natural gas rights and a one-rig four - well program to continue the measured development of our Twining Pekisko light crude oil resource play. This followed the early success of our initial three well horizontal drilling and multi-frac completion program initiated in late 2010 and expanded in Q1 2011. The expanded budget also contemplates a two- well horizontal drilling program in a proximate area that is also prospective for light crude oil in another formation. The location of this region is currently held confidential for competitive reasons as additional petroleum and natural gas rights and other opportunities to secure additional exposure to the play are available to the company.  Recently, we also purchased infrastructure and rights in the area for $10 million; this acquisition added key lands and rights and facilities, which will accelerate the timely development of opportunities in the region.

We will update our conventional production guidance for 2011, to reflect this higher level of investment once we have an extension to the production history from our three existing Twining Pekisko wells.  New drilling will not likely occur at Twining or other area until 2H 2011 due to a protracted spring breakup which has delayed normal field operations.

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

RISK FACTORS AND RISK MANAGEMENT

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

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

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

ACCOUNTING POLICIES AND ESTIMATES

Adoption of International Financial Reporting Standards

On January 1, 2011, the company adopted International Financial Reporting Standards ("IFRS") for financial reporting purposes, using a transition date of January 1, 2010. The financial statements for the three months ended March 31, 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 earnings (loss) before taxes calculated in accordance with previous GAAP and Connacher's 2010 net earnings (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)     Q1 2010     Year 2010
Net earnings (loss) before taxes per previous GAAP     $3,022     (51,585)
  Exploration and evaluation expense     (140)     (964)
  Depletion, depreciation, amortization and impairment     2,084     325
  Gain on disposition of oil and gas properties     432     798
  Compensation     6     44
  Unwinding of discount on decommissioning liabilities     207     812
  Interest in associate     (90)     3,140
  Unrealized loss on revaluation of convertible debentures     (958)     (228)
  Income taxes     3,942     6,787
Net earnings (loss) after taxes per IFRS     $8,505     $(40,871)

Accounting Policy Changes

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

Deemed cost election for oil and gas properties

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

Leases

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

Business Combinations

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

Borrowing Costs

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

Additional exemptions applied

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

Exploration and Evaluation

As explained above under "Deemed cost election for oil and gas properties", the company reclassified $96.2 million, $ 112.6 million and $120.8 million to exploration and evaluation assets at January 1, 2010, March 31, 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 $140,000 and $ 964,000 in three months ended March 31, 2010 and the year ended December 31, 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 and $722,000 after tax benefit of $35,000 and $242,000 for the three months ended March 31, 2010 and the year ended December 31, 2010, respectively.

Depletion, Depreciation and amortization

As explained above under "Deemed cost election for oil and gas properties", development costs at January 1, 2010 were deemed to be $1,029 million, representing the upstream full cost pool balance under previous GAAP and were presented as property, plant and equipment under previous GAAP consistent with IFRS.

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 $ 2.1 million and $4.8 million in the three months ended March 31, 2010 and year ended December 31, 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 $1.6 million and $3.6 million after a tax benefit of $500,000 and $1.2 million for the three months ended March 31, 2010 and the year ended December 31, 2010, respectively.

Impairment

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

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

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

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

Under previous GAAP, proceeds from disposition 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 than 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 three months ended March 31, 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.

During the year ended December 31, 2010, the company recognized a gain of $798,000 on sale of certain oil and gas properties ($432,000) and exploration and evaluation assets ($366,000).

The effect of the above adjustments on retained earnings was an increase of $324,000 and a reduction of $2.8 million after tax benefit of $108,000 and $919,000 for the three months ended March 31, 2010 and the year ended December 31, 2010, respectively.

Foreign Currency

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

Compensation

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

Asset Retirement Obligation

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

In conjunction with the IFRS 1 exemption regarding oil and gas properties discussed above, the company was required to remeasure its asset retirement obligation 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 asset retirement obligation 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 asset retirement obligation. As at March 31, 2010 and December 31, 2010, excluding the January 1, 2010 adjustment, the company's asset retirement obligation increased by $2.7 million and $10.9 million, respectively, which primarily reflects the remeasurement of the obligation using the company's discount rate of 3.3 percent as at March 31, 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 $207,000 in the three months ended March 31, 2010 and $812,000 in the year ended December 31, 2010.

Investment in Associate

As at January, 1, 2010, March 31, 2010 and December 31, 2010, the company owned 26.9 million Petrolifera common shares, representing 22 percent as at January 1, 2010 and March 31, 2010 and 18.5 percent as at December 31, 2010 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 shares 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 fair value a 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 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.

Taxes

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

Debt

Under previous GAAP, the convertible debentures were treated as a compound financial instrument with a debt and equity component. Under IFRS, the equity component is considered an embedded derivative. As permitted under IFRS, the company designated the convertible debentures as "fair value through profit and loss" and accordingly, recorded convertible debentures at fair value at each reporting end with changes reported within the consolidated statement of operations. As a result, the equity portion of convertible debentures was reduced by $16.8 million with a corresponding increase to retained earnings on January 1, 2010, March 31, 2010 and December 31, 2010. In addition, the company recognized the effect of change in fair value by increasing the long-term debt by $3.6 million on January 1, 2010 with a corresponding decrease to retained earnings. The adjustment also resulted in removal of previously recorded accretion expense and recognition of unrealized gains and losses on revaluation. This resulted in an increase in finance changes of $1 million and $228,000 in three months ended March 31, 2010 and December 31, 2010, respectively, with a corresponding increase to long-term debt.

Reclassifications

In order to comply with the presentation of consolidated statement of operations adopted by the company under IFRS, in downstream segment, the company classified certain transportation costs totaling $1.2 million to revenue for the three months ended March 31, 2010. In addition, the company also classified $833,000 and $3.9 million from operating expenses to general and administrative expenses during the three months ended March 31, 2010 and the year ended December 31, 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 ($676,000 in the three months ended March 31, 2010 and $2.9 million in the year ended December 31, 2010).

Changes to the Statement of Cash flow

The following is a reconciliation of the company's cash from operating and investing activities reported in accordance with previous GAAP to cash from operating and investing activities in accordance with IFRS for the three months ended March 31, 2010 and the year ended December 31, 2010:

             
(Canadian dollar in thousands)     Three months ended
March 31, 2010
    Year ended
December 31, 2010
Cash from (used in) operating activities under previous GAAP     $(8,299)     $10,785
  Exploration and evaluation expenses     (140)     (964)
Cash from (used in) operating activities under IFRS     $(8,439)     $9,821
             
Cash from (used in) investing activities under previous GAAP     $(127,297)     $(269,763)
  Exploration and evaluation expenses     140     964
Cash from (used in) investing activities under IFRS     $(127,157)     $(268,799)

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

Earnings (loss) per share

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

Critical Accounting estimates

Upstream assets and reserves

Reserves 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 charges.

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.

All of the company's oil and gas reserves and resources are evaluated and reported on by independent qualified reserves evaluators. The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, estimated commodity price forecasts and the timing of future expenditures, all of which are subject to numerous uncertainties and various interpretations. Reserve estimates can be revised upward or downward based on the results of future drilling, testing, production levels and economics of recovery based on cash flow forecasts. Contingent resources are not classified as reserves due to the absence of a commercial development plan that includes a firm intent to develop within a reasonable time frame.

Asset retirement obligations

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

Legal and other contingent matters

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

Income taxes

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

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

Derivative financial instruments

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

DISCLOSURE CONTROLS AND PROCEDURES

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

INTERNAL CONTROLS OVER FINANCIAL REPORTING

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

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

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

ADVISORY SECTION

FORWARD-LOOKING INFORMATION

This report, including the Letter to Shareholders and the 2011 outlook contained in the MD&A, contains forward-looking information including but not limited to, anticipated future operating and financial results, forecast netbacks, forecast realized gain (loss) on risk management contracts, expectations of future production, anticipated sales volumes, further anticipated reductions in operating costs, expected operational performance resulting from the recent completion of an electrical substation, 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, estimates of future commodity prices, the possible monetization of Connacher's equity investment in Gran Tierra Energy Inc., future possible joint venture arrangements, timing of receipt of regulatory approvals for future expansion at oil sands properties, anticipated terms of Connacher's new note issuance and proposed new operating line of credit and the timing thereof and of Connacher's tender offer and the anticipated impact of Connacher's refinancing efforts on its overall financial condition, the proposed sale of Connacher's interest at Halfway Creek, the timing of monetizing Connacher's dilbit inventory and the possible usage of a pipeline service to transport Connacher's production. 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.

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. The assumptions relating to the reserves and resources of Connacher are described in further detail in Connacher's Annual Information Form for the year ended December 31, 2010 which is available at www.sedar.com.

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 MD&A is based on certain assumptions regarding operational performance including, among others, steam generation levels and steam oil ratios, 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 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 May 17, 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.

NON-GAAP MEASUREMENTS

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

CASH FLOW

Cash flow and cash flow per share do not have standardized meanings prescribed by Canadian GAAP and therefore may not be comparable to similar measures used by other companies. Cash flow includes all cash flow from operating activities and is calculated before changes in non-cash working capital, pension funding and asset retirement expenditures. 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 three months ended March 31, 2011 and 2010 below. Cash flow per share is calculated by dividing cash flow by the calculated weighted average number of shares outstanding. Management uses this non-GAAP measurement (which is a common industry parameter) for its own performance measure and to provide its shareholders and investors with a measurement of the company's efficiency and its ability to fund future growth expenditures.

NETBACKS

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

ADJUSTED EBITDA

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

RECONCILIATIONS OF NON-GAAP MEASURES

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

RECONCILIATIONS OF CASH FLOW TO CASH FLOW FROM OPERATING ACTIVITIES

             
        Three months ended March 31
($000)     2011     2010
Cash flow (deficiency)     $(5,770)     $3,807
  Non-cash working capital changes     9,993     (11,878)
  Asset retirement expenditures     (783)     (368)
Cash flow from operating activities     $3,440     $(8,439)

RECONCILIATIONS OF UPSTREAM AND DOWNSTREAM NETBACKS TO NET EARNINGS

                         
Three months ended March 31                  2011           2010
($000, except per unit amounts)     Total     Per boe     Total     Per boe
Upstream netbacks     $23,830     $17.98     $24,709     $28.95
Downstream netbacks     4,687     3.53     (3,867)     (4.53)
Interest and other income     29,848     22.51     503     0.59
Loss on risk management contracts     (33,229)     (25.06)     (1,564)     (1.83)
General and administrative     (10,423)     (7.86)     (6,385)     (7.48)
Stock-based compensation     (1,065)     (0.80)     (1,885)     (2.21)
Finance charges     (26,751)     (20.18)     (14,427)     (16.90)
Foreign exchange gain     17,400     13.12     23,943     28.05
Depletion, depreciation and accretion     (18,474)     (13.93)     (15,857)     (18.58)
Income tax recovery     6,904     5.21     3,942     4.62
Share of interest in and loss on disposition of associate     (6,828)     (5.15)     (467)     (0.55)
Exploration and evaluation expenses     -     -     (140)     (0.16)
Net earnings (loss)     $(14,101)     $(10.63)     $8,505     $9.97

RECONCILIATION OF ACTUAL ADJUSTED EBITDA

             
(Canadian dollar in thousands)     Q1 2011     Q1 2010
Adjusted EBITDA     $15,845     $14,440
Interest and other income     29,848     503
Employee benefit expense     (148)     (155)
Unrealized loss on risk management contracts     (30,832)     (1,392)
Stock-based compensation     (1,065)     (1,885)
Finance charges     (26,751)     (14,427)
Foreign exchange gain     17,400     23,943
Depletion, depreciation and accretion     (18,474)     (15,857)
Income tax recovery     6,904     3,942
Share of interest in and loss on disposition of associate     (6,828)     (467)
Exploration and evaluation expenses     -     (140)
Net earnings (loss)     $(14,101)     $8,505

CRUDE OIL, NGLs AND NATURAL GAS CONVERSIONS

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

QUARTERLY HIGHLIGHTS

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

                                                 
FINANCIAL ($000 except per share amounts)     2009     2009     2009     2010     2010     2010     2010     2011
Three Months Ended     June 30(5)     Sept 30(5)     Dec 31(5)     Mar 31     June 30(5)     Sept 30(5)     Dec 31(5)     Mar 31
Revenues, net of royalties     $101,529     $153,798     $110,285     $120,034     $142,975     $152,391     $159,334     $175,801
Cash flow (1)     9,570     10,410     (2,766)     3,807     8,668     15,178     9,090     (5,770)
Basic, per share (1)     0.04     0.03     (0.07)     0.01     0.02     0.04     0.02     (0.01)
Diluted, per share (1)     0.03     0.03     (0.07)     0.01     0.02     0.04     0.02     (0.01)
Adjusted EBITDA (1)     13,259     16,724     4,513     14,440     20,173     25,642     31,951     15,845
Net earnings (loss)     39,966     47,767     (14,731)     8,505     (33,126)     7,946     (19,164)     (14,101)
Basic per share     0.15     0.12     (0.03)     0.02     (0.08)     0.02     (0.04)     (0.03)
Diluted per share     0.14     0.11     (0.03)     0.02     (0.08)     0.02     (0.04)     (0.03)
Capital expenditures     40,236     100,727     116,846     118,272     59,316     49,842     20,548     40,830
Cash on hand     401,160     333,634     256,787     118,382     69,412     51,120     19,532     42,865
Working capital surplus     455,001     347,139     245,067     127,416     99,834     61,543     65,375     80,902
Long-term debt      960,593     889,113     876,181     856,495     856,495     867,650     843,601     843,089
Shareholders' equity     622,235     658,336     671,588     554,328     554,328     648,543     650,183     515,941
OPERATIONAL                                                
Upstream: Daily production volumes (2)                                                
  Bitumen - bbl/d     6,284     6,551     6,090     6,936     6,211     6,758     13,238     13,200
  Crude oil - bbl/d     1,114     993     880     937     906     819     873     540
  Natural gas - Mcf/d     12,144     10,377     10,319     9,662     9,278     9,158     8,318     6,805
  Equivalent - boe/d (3)     9,421     9,274     8,690     9,483     8,663     9,103     15,498     14,874
Product sales prices (4)                                                
  Bitumen - $/bbl     40.95     45.30     48.23     51.98     43.13     42.68     45.08     41.78
  Crude oil - $/bbl     54.87     60.58     67.24     71.08     61.90     62.45     66.72     71.70
  Natural gas - $/Mcf     3.35     2.91     4.34     4.86     3.78     3.42     3.44     3.57
Selected highlights - $/boe (3)                                                
  Weighted average sales price (4)     38.11     41.74     45.76     49.99     41.44     40.74     44.09     41.31
  Royalties     1.90     2.13     2.45     3.57     2.73     2.72     2.76     2.15
  Operating costs     13.98     15.43     20.61     17.47     19.25     18.08     17.91     21.18
  Netback (1)     22.23     24.18     22.70     28.95     19.46     19.94     23.42     17.97
Downstream: Refining                                                
  Crude charged - bbl/d     9,145     7,076     8,188     9,347     9,373     9,903     10,137     9,764
  Refining utilization - %     96     75     86     98     99     104     107     103
  Margins - %     5     8     (7)     (8)     12     12     9     6
COMMON SHARES                                                
Shares outstanding end of period (000)     403,546     403,567     427,031     428,246     429,103     429,120     447,168     447,858
Weighted average shares outstanding for the period                                                
  Basic (000)     266,425     403,565     421,804     427,830     429,023     429,106     442,941     448,457
  Diluted (000)     286,985     424,058     422,344     430,077     429,023     431,487     442,941     448,457
Volume traded (000)     249,700     129,206     207,978     167,483     182,419     98,105     137,128     180,297
Common share price ($)                                                
  High     1.66     1.15     1.33     1.65     1.88     1.52     1.35     1.66
  Low     0.74     0.76     0.94     1.16     1.20     1.15     1.10     1.26
  Close (end of period)     0.92     1.10     1.28     1.49     1.29     1.20     1.33     1.43

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

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

For the three months ended March 31, 2011


Condensed Consolidated Balance Sheet

(Unaudited)

                     
As at (Canadian dollar in thousands) Notes     March 31, 2011     December 31, 2010     January 1, 2010
ASSETS                    
CURRENT ASSETS                    
Cash       $42,865     $19,532     $256,787
Trade and accrued receivables 4     58,278     57,419     43,067
Inventories       70,209     57,144     36,871
Investment in equity securities 5     26,104     -     -
Other assets 6     13,502     17,653     17,774
Assets held for sale 7     26,866     88,157     -
        237,824     239,905           354,499
NON-CURRENT ASSETS                    
Other assets 6     518     615     3,419
Investment in associate 7     -     -     48,240
Exploration and evaluation assets 8     135,893     110,949     96,162
Property, plant and equipment 9     1,218,292     1,222,773     1,123,914
        1,354,703     1,334,337     1,271,735
        $1,592,527     $1,574,242     $1,626,234
                     
LIABILITIES AND SHAREHOLDERS' EQUITY                    
CURRENT LIABILITIES                    
Trade and accrued payables 10     $117,560     $81,370     $104,804
Risk management contracts 11     34,995     8,984     4,520
Liabilities relating to assets held for sale 7     4,367     10,907     -
        156,922     101,261     109,324
                     
NON-CURRENT LIABILITIES                    
Risk management contracts 11     14,700     9,879     -
Long-term debt 12     834,089     847,387     879,739
Decommissioning liabilities 13     49,365     60,038     53,729
Employee benefits       318     193     344
Deferred income taxes       21,192     28,499     34,501
        919,664     945,996     968,313
                     
SHAREHOLDERS' EQUITY                    
Share capital 14     619,731     618,628     593,119
Contributed surplus 15.4     36,518     36,107     31,040
Retained earnings       (129,907)     (115,806)     (74,935)
Accumulated other comprehensive loss       (10,401)     (7,452)     (627)
Accumulated other comprehensive loss on assets held for sale 7     -     (4,492)     -
        515,941     526,985     548,597
        $1,592,527     $1,574,242     $1,626,234

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

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

(Unaudited)

                   
For the three months ended March 31 (Canadian dollar in thousands)     Notes     2011     2010
INCOME                  
Revenue     21     $178,990     $121,095
Loss on revenue-related risk management contracts     11     (33,037)     (1,564)
Interest and other income     19     29,848     503
            175,801     120,034
EXPENSES                  
Operating costs     21     137,183     95,848
Transportation and handling costs     21     13,290     4,405
Loss on operating cost-related risk management contracts     11     192     -
General and administrative           10,423     6,385
Finance charges     16     26,751     14,427
Share-based compensation     15.3     1,065     1,885
Foreign exchange gains     17     (17,400)     (23,943)
Exploration and evaluation expenses           -     140
Depletion, depreciation and amortization           18,474     15,857
Share of interest in and loss on disposition of associate     7.2     6,828     467
            196,806     115,471
EARNINGS (LOSS) BEFORE INCOME TAX           (21,005)     4,563
Income tax recovery     18     6,904     3,942
NET EARNINGS (LOSS)           (14,101)     8,505
                   
OTHER COMPREHENSIVE INCOME (LOSS) AFTER TAX                  
Exchange differences on translating foreign operations           (3,329)     (4,650)
Available for sale financial assets, net of tax of $54     5     380     -
Share of other comprehensive loss of associate, net of tax of $174           -     (1,219)
Transfer share of other comprehensive loss of associate on disposition,
net of tax of $632
    7.2     4,492     -
OTHER COMPREHENSIVE INCOME (LOSS) AFTER TAX           1,543     (5,869)
TOTAL COMPREHENSIVE INCOME (LOSS)           $(12,558)     $2,636
                   
                   
                   
For the three months ended March 31     Note     2011     2010
NET EARNINGS (LOSS) PER SHARE - basic and diluted     14     $(0.03)     $0.02

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)

               
For the three months ended March 31 (Canadian dollar in thousands)     2011       2010
SHARE CAPITAL              
Balance, beginning of period     $618,628       $593,119
Shares issued upon exercise of stock options     402       531
Assigned value of stock options and awards exercised     224       315
Shares issued to directors as compensation     499       480
Share issue cost, net of tax     (22)       (59)
Tax effect of flow-through shares     -       -
Balance, end of period     619,731       594,386
               
CONTRIBUTED SURPLUS              
Balance, beginning of period     36,107       31,040
Share-based compensation     1,134       2,438
Assigned value of stock options exercised     (224)       (315)
Assigned value of share awards issued     (499)       (295)
Balance, end of period     36,518       32,868
               
RETAINED EARNINGS              
Balance, beginning of period     (115,806)       (74,935)
Net earnings (loss)     (14,101)       8,505
Balance, end of period     (129,907)       (66,430)
               
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)              
Balance, beginning of period (including classified as held for sale)     (11,944)       (627)
Exchange differences on translating foreign operations     (3,329)       (4,650)
Available for sale financial asset     380       -
Share of other comprehensive loss of associate     -       (1,219)
Transfer share of other comprehensive loss of associate on disposition     4,492      
Balance, end of period     (10,401)       (6,496)
      $515,941       $554,328

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

Condensed Consolidated Statements of Cash Flow

(Unaudited)

               
For the three months ended March 31 (Canadian dollar in thousands) Notes     2011     2010
OPERATING              
Net earnings (loss)       $(14,101)     $8,505
Adjustments for:              
  Depletion, depreciation and amortization       18,474     15,857
  Share-based compensation       1,065     1,885
  Finance charges - non-cash portion       4,426     2,863
  Defined benefit plan expense       148     155
  Deferred income tax       (6,974)     (4,148)
  Unrealized loss on risk management contracts 11     30,832     1,392
  Share of interest in and loss on disposition of associate 7     6,828     467
  Unrealized foreign exchange gain 17     (16,967)     (23,008)
  Gain on sale of property, plant and equipment 19     (29,316)     (432)
  Unrealized (gain) loss on financial assets 19 & 16     (185)     271
        (5,770)     3,807
Changes in non-cash working capital       9,993     (11,878)
Asset retirement expenditures paid 13     (783)     (368)
Cash flow from (used in) operating activities       3,440     (8,439)
               
INVESTING              
Expenditures on property, plant and equipment       (26,460)     (91,607)
Exploration and evaluation expenditures       (25,701)     (25,048)
Proceeds on disposition of property, plant and equipment       56,935     1,205
Changes in non-cash working capital       15,289     (11,707)
Cash flow from (used in) investing activities       20,063     (127,157)
               
FINANCING              
Proceeds on issue of common shares       402     1,533
Share issue costs       (22)     (80)
Cash flow from financing activities       380     1,453
               
NET INCREASE (DECREASE) IN CASH       23,883     (134,143)
               
Foreign exchange loss on cash balances held in foreign currency       (550)     (4,262)
CASH, BEGINNING OF PERIOD       19,532     256,787
               
CASH, END OF PERIOD       $42,865     $118,382
             
SUPPLEMENTARY CASH FLOW INFORMATION:        
Interest paid   $11,660   $14,000

 

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 months ended March 31, 2011 and 2010

1.       Nature of Operations and Segment Reporting

Connacher Oil and Gas Limited ("Connacher") is a publicly traded integrated energy company headquartered in Calgary, Alberta, Canada. The address of the Company's registered office is Suite 900, 322 - 6th Avenue S.W., Calgary, Alberta. The condensed interim consolidated financial statements ("interim consolidated financial statements"), as at March 31, 2011 and for the three 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 May 17, 2011.

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

2.       Basis of Preparation
2.1       Statement of compliance

In conjunction with the company's annual audited consolidated financial statements to be issued under International Financial Reporting Standards ("IFRS") for the year ended December 31, 2011, these interim consolidated financial statements present the company's initial financial results of operations and financial position under IFRS, as at and for the three months ended March 31, 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 with International Accounting Standard ("IAS") 34, "Interim Financial Reporting". These interim consolidated financial statements do not include all the necessary annual disclosures in accordance with IFRS. Previously, the company prepared its interim and annual consolidated financial statements in accordance with Canadian generally accepted accounting principles ("previous GAAP").

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 22 along with reconciliations presenting the impact of the transition to IFRS for the comparative periods as at January 1, 2010, as at and for the three months ended March 31, 2010 and as at and for the year ended December 31, 2010. A summary of the company's significant accounting policies under IFRS is presented in Note 3. 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 22.

2.2       Basis of measurement

These interim consolidated financial statements have been prepared on a historical cost basis except for the following material items in the consolidated balance sheet:

  • Derivative financial instruments are measured at fair value;
  • Investment in equity securities are measured at fair value;
  • Liabilities for cash-settled share-based payment arrangements are measured at fair value; and
  • Assets classified as held for sale are measured at fair value where carrying amount is higher than the fair value.
2.3       Use of estimates and judgments

The timely preparation of interim consolidated financial statements requires management to make judgments, estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the interim consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Although these estimates are based on management's best knowledge of the amount, event or actions, actual results ultimately may differ from those estimates. Accordingly, actual reported amounts may differ from estimated amounts as future confirming events occur.

Estimation of petroleum and natural gas reserves

Petroleum and natural gas reserve estimates are used in the unit-of-production depletion and depreciation calculation, determination of the timing of abandonment costs and impairment analysis of upstream assets. Reserves are estimated by reference to available geological and engineering data. Estimates of petroleum and natural gas reserves are inherently imprecise, require the application of judgment and are subject to regular revision, either upward or downward, based on new information such as from the drilling of additional wells, observation of long-term reservoir performance and changes in economic factors, including product prices, contract terms or development plans.

Changes to estimates of petroleum and natural gas reserves affect prospectively the amounts of depletion, depreciation and amortization charged and, consequently, the carrying amounts of oil and gas properties. The Company makes estimates and assumptions concerning the future. The resulting accounting estimates will, by definition, seldom equal the related actual results. Such estimates and assumptions are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances.

Information about the carrying amounts of oil and gas properties and the amounts charged to income, including depletion, depreciation and amortization, is presented in note 9.

Impairment of assets

For the purposes of impairment analysis of the assets, the key assumptions used in estimating cash flows are future oil prices, expected production volumes and refining margins appropriate to the local circumstances and environment. These assumptions and the judgments of management that are based on them are subject to change as new information becomes available. Changes in economic conditions can also affect the rate used to discount future cash flow estimates.

Expected production volumes, which include both proved and proved plus probable in the future, are used for impairment testing because the company believes this to be the most appropriate indicator of expected reserves future cash flows. As discussed in "Estimation of petroleum and natural gas reserves", reserves estimates are inherently imprecise.

Changes in assumptions could affect the carrying amounts of assets, and impairment charges and reversals will affect income.

Information about the carrying amounts of assets and impairments is presented in notes 8 and 9.

Decommissioning liabilities

Provisions are recognized for the future abandonment and reclamation of petroleum and natural gas properties at the end of their economic lives. The estimated cost is recognized in income over the life of the reserves on a unit-of-production basis. Changes in the estimates of costs to be incurred, reserves or in the rate of production will therefore affect income, generally over the remaining economic life of petroleum and natural gas assets.

Estimates of the amounts of provisions recognized are based on current legal and constructive requirements, technology and price levels. Because actual outflows can differ from estimates due to changes in laws, regulations, public expectations, technology, prices and conditions, and can take place many years in the future, the carrying amounts of provisions are regularly reviewed and adjusted to take account of such changes. The interest rate used to discount the cash flows is reviewed annually.

Information about decommissioning liabilities is presented in note 13.

Taxation

Tax provisions are recognized when it is considered probable that there will be a future outflow of funds to a taxing authority. In such cases, provision is made for the amount that is expected to be settled, where this can be reasonably estimated. This requires the application of judgment as to the ultimate outcome, which can change over time depending on facts and circumstances. A change in estimate of the likelihood of a future outflow and/or in the expected amount to be settled would be recognized in income in the period in which the change occurs.

Deferred tax assets are recognized only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to realize, and a judgment as to whether or not there will be sufficient taxable profits available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability change, there can be an increase or decrease in the amounts recognized in respect of deferred tax assets as well as in the amounts recognized in income in the period in which the change occurs.

Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could affect amounts recognized in income both in the period of change, which would include any impact on cumulative provisions, and in future periods.

Other significant areas of judgment

The estimates of net realizable value of inventory involve estimating future selling prices and accordingly, are subject to measurement uncertainty.

The amounts for pension assets, obligations and pension costs charged to statement of operations depend on certain actuarial and economic assumptions, which are subject to measurement uncertainty.

Amounts recorded for stock-based compensation expense are based, in part, on the historical volatility of the company's share price, which may not be indicative of future volatility. Accordingly, those amounts are subject to measurement uncertainty.

2.4       Functional and Presentation currency

The interim consolidated financial statements are presented in Canadian dollars which is the functional currency of Connacher.

3.       Significant Accounting Policies
3.1       Basis of consolidation

The interim consolidated financial statements include the financial statements of Connacher and its subsidiaries, being those which are controlled by the company. Control exists when the company has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities. The financial statements of subsidiaries are included in the interim consolidated financial statements from the date that control commences until the date that control ceases, using consistent accounting policies. All inter-company balances and transactions, including unrealized gains and losses arising from such transactions, are eliminated.

3.2       Inventories 

Inventories are stated at the lower of cost or net realizable value. Cost comprises direct purchase costs, cost of production and manufacturing and is determined using the weighted average cost method.

3.3       Exploration and Evaluation assets ("E&E")

E&E expenditures incurred prior to acquiring the legal right to explore are charged to expense as incurred and recorded as E&E expense in statement of operations.

All costs directly associated with exploration and evaluation of oil and gas reserves are initially capitalized. E&E costs are those expenditures where technical feasibility and commercial viability has not been yet been determined and include license and unproved property acquisition costs, geological and geophysical costs and costs of drilling exploratory wells.

E&E costs are classified as intangible assets and are not depleted except for the costs associated with unproved land which are amortized to expense over the lease term. E&E assets are transferred to property, plant and equipment when they are determined to meet technical feasibility and commercial viability.

The carrying amount of E&E assets is tested for impairment in accordance with note 3.6 annually, upon transfer to property, plant and equipment, when an area is determined not to be technically feasible and commercially viable or the company decides not to continue with its activity.

3.4       Property, plant and equipment ("PP&E")

Recognition and measurement

Property, plant and equipment is initially recognized at cost which represents all costs directly associated with the development of oil and natural gas reserves where technical feasibility and commercial viability is determined. Such costs include drilling costs of development wells, tangible costs of facilities and infrastructure construction, costs of optimization and enhanced oil recovery projects, proved property acquisition costs, asset retirement costs, transfers from E&E assets and borrowing costs relating to qualifying assets.

Expenditures on major maintenance repairs comprise the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where an asset or part of an asset that was separately depreciated is replaced and it is probable that future economic benefits associated with the item will flow to the company, the expenditure is capitalized and the carrying amount of the replaced asset is derecognized. Inspection costs associated with major maintenance programs are capitalized and amortized over the period to the next inspection. Normal repairs and maintenance costs are charged to statement of operations when incurred.

Property, plant and equipment are subsequently carried at cost less accumulated depletion, depreciation and amortization (including any impairment). Gains and losses on disposals are determined by comparing disposal proceeds with the carrying amounts of assets sold and recognized in statement of operations and reported within interest and other income or expenses.

Depletion, depreciation and amortization

Property, plant and equipment relating to oil and natural gas properties including related facilities are depleted and depreciated using the unit-of-production method over the proved and probable reserves of the area. Estimated future costs to develop proved and probable reserves are included in costs subject to depletion. Costs of major development projects are excluded from depletion and depreciation until the asset is available for use.

Property, plant and equipment relating to refining properties are depreciated and amortized using the straight-line method, based on estimated useful lives of assets which range from 3 to 16 years.

Property, plant and equipment relating to the corporate office includes leasehold improvements and computer and office equipment. Leasehold improvements are amortized using the straight-line method over lease term whereas computer and office equipment are amortized using the declining balance method at 20% to 30% rate per annum.

The estimates of useful lives of property, plant and equipment are reviewed annually and if, necessary, changes are accounted for prospectively.

Impairment

The carrying value of property, plant and equipment is reviewed for impairment, in accordance with note 3.6, whenever events or changes in circumstances indicate the carrying value may not be recoverable.

3.5       Business combinations and Goodwill

Business combinations are accounted for using the acquisition method. The acquired identifiable net assets are measured at their fair value at the date of acquisition. Any excess of the purchase price over the fair value of the net assets acquired is recognized as goodwill. Any deficiency of the purchase price below the fair value of the net assets acquired is recorded as a gain in net earnings. Associated transaction costs are expensed when incurred.

Goodwill is allocated to the applicable cash-generating unit as defined in note 3.6. Goodwill is not amortized and is tested for impairment annually, in accordance with note 3.6 on December 31.

3.6       Impairment of non-financial assets (E&E, PP&E and Goodwill)

If non-financial assets are determined to be impaired, an impairment test is carried out in which the carrying amounts of those assets are written down to their recoverable amount, which is the higher of fair value less costs to sell ("FVLCS") and value-in-use ("VIU"). For the purpose of impairment test, E&E, PP&E and goodwill are grouped together into the smallest group of assets that generates cash flows from continuing use, that are largely independent of the cash flows of other assets or groups of assets (the "cash-generating unit" or "CGU").

VIU is determined by estimating the discounted future cash flows expected to be drived from continuing use of the assets. In determining FVLCS, recent market transactions are taken into account, if available. If no such transactions can be identified, an appropriate valuation model is used. These calculations are corroborated by valuation multiples or other available fair value indicators.

Estimates of future cash flows used in the evaluation of impairment of assets are made using forecasts of commodity prices, market supply and demand, product margins and, in the case of oil and gas properties, expected reserves volumes. The cash flows used in the impairment test are generally derived from the information contained in the reserve reports, which are prepared annually by independent qualified reserve evaluators and management's assumptions based on past experience.

Impairment losses are recognized in the consolidated statement of operations and reported within depletion, depreciation and amortization. Impairment losses recognized in respect of a CGU are allocated first, to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amount of the other assets in the CGU.

An impairment loss in respect of goodwill is not reversed. In respect of other assets, impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. If the amount of the impairment loss decreases in a subsequent period and the decrease can be objectively related to an event occurring after the impairment was recognized, the impairment loss is reversed up to the original carrying value of the asset that would have been determined, net of depletion, depreciation and amortization, if no impairment loss had been recognized. Such reversal is recognized in the consolidated statement of operations and reported within depletion, depreciation and amortization.

3.7       Investment in associate

An associate is an entity over which the company has the right to exercise significant influence, but not control, over the financial and operating policies. The investment in associate is accounted for using the equity method of accounting. Under the equity method, the investment is initially recorded at cost and subsequently adjusted for the post-acquisition changes in the company's share of net assets of associate, after adjustment to align the accounting policies with those of the company. The company's net earnings or loss reflects the company's share of the net earnings or loss after tax of the associate.

The company assesses the investments in associate for impairment whenever events or changes in circumstances indicate that the carrying value may not be recoverable. If any such indication of impairment exists, the carrying amount of the investment is compared with its recoverable amount, being the higher of its fair value less costs to sell and value in use. Where the carrying amount exceeds the recoverable amount, the investment is written down to its recoverable amount.

The company ceases to use the equity method of accounting on the date from which it no longer has significant influence over the associate, or when the investment becomes held for sale.

Losses of an associate in excess of the company's equity interest in that associate are recognized only to the extent that the company has incurred legal or constructive obligations or made payments on behalf of the associate.

3.8       Income taxes

Tax expense comprises current and deferred taxes. Tax expense is recognized in statement of operations except when it relates to items recognized in other comprehensive income (loss), in which case the tax is also recognized in other comprehensive income (loss). Income tax assets and liabilities are presented separately in the consolidated balance sheet except where there is a right of set-off within fiscal jurisdictions and an intention to settle such balances on a net basis.

Current tax expense is based on the results for the period as adjusted for items that are not taxable or not deductible. Current tax is calculated using tax rates and laws that have been enacted at the end of the reporting period. Management periodically evaluates positions taken in tax returns with respect to situations in which applicable tax regulation is subject to interpretation. Provisions are established where appropriate on the basis of amounts expected to be paid to the tax authorities.

Deferred tax is recognized in the balance sheet using the liability method of accounting for income taxes, on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts. Deferred tax is calculated using tax rates and laws that have been enacted or substantively enacted at the end of the reporting period, and which are expected to apply when the related deferred tax asset is realized or the deferred tax liability is settled.

3.9       Provisions

A provision is recognized if, as a result of a past event, the company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax risk-free interest rate. The unwinding of the discount is recognized as finance cost. Specific details for decommissioning and restoration costs ("decommissioning liabilities") and premium on flow-through shares are described below. The carrying amounts of provisions are regularly reviewed and adjusted for new facts or changes in laws or technology.

Decommissioning liabilities

The company recognizes a decommissioning liability for abandoning oil and natural gas wells, related facilities, compressors and gas plants, removal of equipment from leased acreage and for returning such land to its original condition, in the period a well or related asset is drilled, constructed or acquired. The decommissioning liability is estimated using the present value of the estimated expected future cash outflows at a risk-free interest rate. The obligation is reviewed regularly by management, based upon current regulations, costs, technologies and industry standards. The effects of changes resulting from revisions to the timing or the amount of the original estimate of the provision are reflected on a prospective basis, generally by adjustment to the carrying amount of the related property, plant and equipment. The discounted obligation is initially capitalized as part of the carrying amount of the related property, plant and equipment and a corresponding liability is recognized. The amount of the capitalized retirement obligation is depleted and depreciated on the same basis as the other capitalized property, plant and equipment. Actual abandonment and reclamation expenditures are charged to the accumulated obligation as incurred and obligations related to properties disposed are removed.

Premium on flow-through common 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 exploration activities. Generally, due to transferring the benefit of tax deduction to the investors, the shares issued on flow-through basis are offered at prices higher than the prevailing quoted prices of the shares. Accordingly, the proceeds from issuance of these shares are allocated between share capital and the 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 and reported within deferred income tax in statement of operations.

3.10       Employee benefits

Employee retirement plans

The company maintains a funded defined benefit pension plan and defined contribution savings plans.

A valuation of defined benefit plan is carried out annually by independent actuaries, using the projected unit credit method to calculate the defined benefit obligation. Pension cost primarily represents the increase in the actuarial present value of the obligation for pension benefits based on employee service during the year and the interest on this obligation in respect of employee service in previous years, net of the expected return on plan assets. Plan assets are valued at fair value. The present value of the accumulated benefit obligation is determined by actuaries. The expected return on plan assets is based on market expectations at the beginning of the fiscal period for returns over the entire life of the benefit obligation.

Actuarial gains and losses are recognized as income or expense when the net cumulative unrecognized actuarial gains and losses at the end of the previous reporting year exceed 10% of the higher of the defined benefit obligation and the fair value of plan assets at that date. These gains and losses are recognized in consolidated statement of operations over the expected average remaining working lives of the employees participating in the plan.

For defined contribution saving plans, the cost is the amount of employer contributions payable for the period.

Share-based compensation plans

Employees of the company receive remuneration in the form of share-based payment transactions, whereby employees render services as consideration for equity instruments. Share-based compensation is initially recognized as a part of property, plant and equipment or in the consolidated statement of operations at the fair value on the date of grant over its vesting period with a corresponding increase to contributed surplus for equity-settled plans and to trade and accrued payables for cash-settled plans. Equity-settled plans are subsequently not remeasured whereas the cash-settled plans are remeasured to fair value at each reporting period-end with changes recorded as a part of property, plant and equipment or the consolidated statement of operations. The company maintains an employee stock option plan and a non-employee directors' share awards plan. Both plans are classified as equity-settled awards. The fair value of the employee stock option plan is estimated using a Black-Scholes option pricing model whereas the fair value of the non-employee directors share awards plan is estimated by reference to the company's share price. Upon issue of shares on the exercise of options and awards under the plans, the proceeds received and the fair value of the exercised options and awards are credited to share capital.

3.11       Leases

Agreements under which payments are made to owners in return for the right to use an asset for a period are accounted for as leases. Leases that transfer substantially all the risks and rewards of ownership are recognized at the commencement of the lease term as finance leases within property, plant and equipment and debt at the fair value of the leased asset or, if lower, at the present value of the minimum lease payments. Finance lease payments are apportioned between interest expense and repayments of debt. All other leases are recorded as operating leases, and the costs are recognized in consolidated statement of operations on a straight-line basis.

3.12       Foreign currency

Foreign currency transactions

Transactions in foreign currencies are translated to the respective functional currencies of the entities at monthly average exchange rates. Monetary assets and liabilities denominated in foreign currencies at the reporting date are retranslated to the functional currency at the exchange rate at that date. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at period-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognized in statement of operations.

Foreign operations

The assets and liabilities of foreign operations are translated to Canadian dollars at exchange rates at the reporting date, while their statements of operations, other comprehensive income (loss) and cash flows are translated at monthly average rates. The resulting foreign currency differences are recognized in other comprehensive income (loss) in the cumulative translation account. Upon divestment of all or part of an interest in, or upon liquidation of, an entity, the cumulative currency translation differences related to that entity are generally recognized in the statement of operations. Foreign exchange gains or losses arising from a monetary item receivable from or payable to a foreign operation, the settlement of which is neither planned nor likely to occur in the foreseeable future and which in substance is considered to form part of the net investment in the foreign operation, are recognized in other comprehensive income (loss) in the cumulative amount of foreign currency translation differences.

3.13       Financial instruments

Financial instruments consist of financial assets, financial liabilities, compound financial instruments and derivative financial instruments and are initially recognized at fair value net of transaction costs, if applicable. Measurement in subsequent periods depends on whether the financial instrument has been classified as "fair value through profit or loss", "loans and receivables", "available-for-sale", "held-to-maturity", or "financial liabilities measured at amortized cost" as follows:

Financial assets

Financial assets comprise cash, trade and accrued receivable and investment in equity securities.

Cash and cash equivalents comprise cash at bank and in hand, including offsetting bank overdrafts and short-term deposits, if any, that mainly have a maturity of three months or less at the date of acquisition.

Trade and accrued receivables are classified as loans and receivables and recorded at amortized cost less any impairment.

Investments in equity securities are classified as available-for-sale and are carried at fair value, less any impairment. Unrealized gains and losses other than impairments are recognized in other comprehensive income (loss). On maturity or disposal, net gains and losses previously deferred in accumulated other comprehensive income (loss) are recognized in the statement of operations. Dividends on equity securities are recognized in the statement of operations when receivable.

Financial liabilities

Financial liabilities comprise trade and accrued payables, First and Second Lien Senior Notes (collectively "Notes"), Convertible debentures and the Revolving Credit Facility (the "Facility"). Notes, convertible debentures and the Facility are reported within long-term debt on the consolidated balance sheet.

Trade and accrued payables and Notes are classified as financial liabilities measured at amortized cost using effective interest rate method.

Convertible debentures are classified as "fair value through profit and loss" whereby they are carried at the fair value at reporting date. Unrealized gains and unrealized losses on remeasurement to fair value at each reporting period-end are recognized in the statement of operations and reported within interest and other income and finance charges, respectively.

The Facility is subsequently measured at amortized cost, net of transaction costs, in the event that amounts are drawn and outstanding under the Facility at the reporting period-end. In the event no amounts are outstanding at the reporting period-end, unamortized transactions costs are included in other assets. Transaction costs are amortized over the term of the Facility using the straight line method.

Derivative financial instruments

Derivative financial instruments comprise investments in share purchase warrants and risk management contracts.

The investment in share purchase warrants are classified as "fair value through profit and loss" whereby they are carried at the fair value at reporting date. Unrealized gains and losses on remeasurement to fair value at each reporting period-end is recognized in statement of operations and reported within interest and other income and finance charges, respectively.

The company enters into certain risk management contracts in order to reduce its exposure to market risks from fluctuations in commodity prices, foreign currency and interest rates. These instruments are not used for speculative purposes. The company has not designated its risk management contracts as effective accounting hedges and thus has not applied hedge accounting. As a result, all risk management contracts are classified as "fair value through profit and loss" and recorded on the balance sheet at fair value at each reporting date. Realized gains or losses from risk management contracts related to crude oil and gasoline commodity prices are recognized in income as the contracts are settled. Realized gains or losses from risk management contracts related to natural gas commodity prices are recognized in expenses as the related natural gas contracts are settled. Unrealized gains and losses are recognized in revenue or expenses at the end of each respective reporting period based on the changes in fair value of the contracts. The estimated fair value of all risk management contracts is based on quoted market prices or, in their absence, third-party market indications and forecasts. Attributable transaction costs are recorded in the statement of operations.

The company accounts for its forward physical delivery sales and purchase contracts that are entered into and continued to be held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements, as executory contracts. As such, these contracts are not considered derivative financial instruments and thus have not been recorded at fair value on the consolidated balance sheet. Settlements of these physical sales and purchase contracts are recognized in related revenues and expenses.

Derivatives embedded within contracts that are not already required to be recognized at fair value, and that are not closely related to the host contract in terms of economic characteristics and risks, are separated from their host contract and recognized at fair value; associated gains and losses are recognized in the statement of operations.

3.14       Revenue recognition

Revenue from sales of oil, natural gas, natural gas liquids and all other products is recognized at the fair value of consideration received or receivable, after deducting royalties, when the significant risks and rewards of ownership have been transferred, which is when title passes to the customer. For sales by upstream operations, this generally occurs when product is physically transferred into a pipe or our delivery trucks are accepted by the customer. For sales by downstream operations, it is either at the point of delivery or at the point of receipt, depending on contractual conditions.

3.15       Finance charges

Finance charges comprise interest expense on long-term debt, amortization of the transaction costs and stand-by fees of the Facility, unwinding of discount on provisions, unrealized loss on revaluation of convertible debentures, bank charges and any impairment losses recognized on financial assets.

Finance costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use. All other finance costs are recognized in the consolidated statement of operations in the period in which they are incurred using the effective interest method. Interest has been capitalized at the rate of interest applicable to the specific borrowings financing the asset, or where financed through general borrowings, at a capitalization rate representing the average interest rate on such borrowings.

3.16       Earnings (loss) per share

The company presents basic and diluted earnings (loss) per share data for its common shares. Basic earnings (loss) per share is calculated by dividing net earnings (loss) attributable to ordinary equity holders of the company by the weighted average number of common shares outstanding during the period. Diluted earnings (loss) per share is determined by adjusting the earnings or loss attributable to common shareholders and the weighted average number of common shares outstanding for the effects of dilutive instruments, which comprises convertible debentures, employee stock options and non-employee director share awards.

3.17       Non-current assets classified as held for sale

Non-current assets, or disposal groups comprising assets and liabilities, that are expected to be recovered primarily through sale rather than through continuing use, are classified as held for sale. This condition is regarded as met only when the sale is highly probable and the asset or disposal group is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such assets. Management must be committed to the sale, which should be expected to qualify for recognition as a completed sale within one year from the date of classification as held for sale. Immediately before classification as held for sale, the assets, or components of a disposal group, are remeasured in accordance with the company's accounting policies. Thereafter, the assets, or disposal group, are measured at the lower of their carrying amount and fair value less cost to sell. Impairment losses on initial classification as held for sale and subsequent gains or losses on remeasurement are recognized in the consolidated statement of operations. Property, plant and equipment and intangible assets once classified as held for sale are not depreciated. The company ceases to use the equity method of accounting on the date from which an interest in an associate becomes held for sale.

3.18       Fair value measurements

Fair value measurements are estimates of the amounts for which assets or liabilities could be exchanged at the measurement date, based on the assumption that such exchanges take place between knowledgeable, unrelated parties in unforced transactions. Where available, fair value measurements are derived from prices quoted in active markets for identical assets or liabilities. In the absence of such information, other observable inputs are used to estimate fair value. Where publicly available information is not available, fair value is determined using estimation techniques that take into account market perspectives relevant to the asset or liability so as far as they can reasonably be ascertained, based on predominantly unobservable inputs. For risk management contracts and for share-based compensation plans, fair value estimations are generally determined using models and other valuation methods, the key inputs for which include future prices, volatility, price correlation, counterparty credit risk and market liquidity, as appropriate; for other assets and liabilities, fair value estimations are generally based on the net present value of expected future cash flows.

3.19       Recent accounting pronouncements issued but not yet adopted

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

IAS 12 Income Taxes ("IAS 12")

IAS 12 was amended in December 2010 to remove subjectivity in determining on which basis an entity measures the deferred tax relating to an asset. The amendment introduces a presumption that an entity will assess whether the carrying value of an asset will be recovered through the sale of the asset. The amendment to IAS 12 is effective for reporting periods beginning on or after January 1, 2012. The company is currently evaluating the impact of this amendment to IAS 12 on its consolidated financial statements.

IAS 27 Separate Financial Statements ("IAS 27")

IAS 27 replaced the existing IAS 27 "Consolidated and Separate Financial Statements". IAS 27 contains accounting and disclosure requirements for investments in subsidiaries, joint ventures and associates when an entity prepares separate financial statements. IAS 27 requires an entity preparing separate financial statements to account for those investments at cost or in accordance with IFRS 9 Financial Instruments. IAS 27 is effective for annual periods beginning on or after January 1, 2013. Earlier application is permitted. The company is currently evaluating the impact of this standard on its consolidated financial statements.

IAS 28 Investments in Associates and Joint Ventures ("IAS 28")

IAS 28 was amended in 2011 which prescribes the accounting for investments in associates and sets out the requirements for the application of the equity method when accounting for investments in associates and joint ventures. IAS 28 is effective for annual periods beginning on or after January 1, 2013. Earlier application is permitted. The company is currently evaluating the impact of this amendment to IAS 28 on its consolidated financial statements.

IFRS 7 Financial Instruments: Disclosures ("IFRS 7")

IFRS 7 was amended in October 2010 to provide additional disclosure on the transfer of financial assets including the possible effects of any residual risks that the transferring entity retains. These amendments are effective as of July 1, 2011. The company is currently evaluating the impact of these amendments to IFRS 7 on its consolidated financial statements.

IFRS 9 Financial Instruments ("IFRS 9")

IFRS 9 was issued in November 2009 and is the first step to replace current IAS 39, "Financial Instruments: Recognition and Measurement". IFRS 9 uses a single approach to determine whether a financial asset is measured at amortized cost or fair value, replacing the multiple rules in IAS 39. The approach in IFRS 9 is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. The new standard also requires a single impairment method to be used, replacing the multiple impairment methods in IAS 39. IFRS 9 is effective for annual periods beginning on or after January 1, 2013. The company is currently evaluating the impact of IFRS 9 on its consolidated financial statements.

IFRS 10 Consolidated Financial Statements ("IFRS 10")

IFRS 10 establishes principles for the presentation and preparation of consolidated financial statements when an entity controls one or more other entities. IFRS 10 supersedes IAS 27 "Consolidated and Separate Financial Statements" and SIC-12 "Consolidation—Special Purpose Entities" and is effective for annual periods beginning on or after January 1, 2013. Earlier application is permitted. The company is currently evaluating the impact of this standard on its consolidated financial statements.

IFRS 11 Joint Arrangements ("IFRS 11")

IFRS 11 establishes principles for financial reporting by parties to a joint arrangement. IFRS 11 supersedes current IAS 31 "Interests in Joint Ventures and SIC-13 Jointly Controlled Entities—Non-Monetary Contributions by Venturers" and is effective for annual periods beginning on or after January 1, 2013. Earlier application is permitted. The company is currently evaluating the impact of this standard on its consolidated financial statements.

IFRS 12 Disclosure of Interests in Other Entities ("IFRS 12")

IFRS 12 applies to entities that have an interest in a subsidiary, a joint arrangement, an associate or an unconsolidated structured entity. IFRS 12 is effective for annual periods beginning on or after January 1, 2013. Earlier application is permitted. The company is currently evaluating the impact of this standard on its consolidated financial statements.

IFRS 13 Fair Value Measurements ("IFRS 13")

IFRS 13 defines fair value, sets out in a single IFRS framework for measuring fair value and requires disclosures about fair value measurements. The IFRS 13 applies to IFRSs that require or permit fair value measurements or disclosures about fair value measurements (and measurements, such as fair value less costs to sell, based on fair value or disclosures about those measurements), except in specified circumstances. IFRS 13 is to be applied for annual periods beginning on or after January 1, 2013. Earlier application is permitted. The company is currently evaluating the impact of this standard on its consolidated financial statements.

4.       Trade and Accrued Receivables

                 
As at (Canadian dollar in thousands)       March 31, 2011       December 31, 2010
Trade receivables       $14,511       $16,904
Accrued revenue       41,894       39,942
Other receivables       1,873       527
Due from associate       -       46
        $58,278       $57,419

5.       Investment In Equity Securities

Upon completion of the sale of 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 available for sale financial asset and is carried at fair value on initial recognition and subsequent reporting period end. Any changes in the value of the investment in equity securities are reported in other comprehensive income (loss).

6.       Other Assets

             
As at (Canadian dollar in thousands)     March 31, 2011     December 31, 2010
Deposits     $9,133     $10,779
Prepayments     2,942     5,754
Unamortized transaction costs relating to the facility     831     939
Income taxes refundable     778     796
Derivative financial assets (note 6.1)     336     -
Total     14,020     18,268
Less: non-current portion     (518)     (615)
Current portion     $13,502     $17,653

6.1        Upon completion of the sale of the 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 recorded at fair value. An unrealized gain of $186,000 for the change in fair value of these warrants  was recognized in the three months ended March 31, 2011 and was reported in interest and other income.

7.       Assets and Liabilities Classified as Held For Sale

The major classes of assets and liabilities reclassified as held for sale as at March 31, 2011 and 31 December 2010 are as follows:

                   
As at (Canadian dollar in thousands)              Notes     March 31, 2011     December 31, 2010
Assets classified as held for sale                  
  Property, plant and equipment     7.1     $21,970     $54,348
  Exploration and Evaluation assets     7.1     4,896     5,652
  Investment in associate     7.2     -     27,683
  Investment in derivative financial instrument     7.2     -     474
Assets classified as held for sale           $26,866     $88,157
                   
Liabilities associated with assets classified as held for sale                  
  Decommissioning liabilities     7.1     $4,367     $10,907
                   
Equity associated with assets classified as held for sale                  
  Accumulated other comprehensive loss     7.2     $-     $4,492

7.1       Oil and gas properties

As a part of the company's program to rationalize its conventional oil and gas properties, on November 15, 2010, the company's management committed to a plan to sell the following conventional oil and gas properties.

In December 2010, the company announced an agreement to sell certain oil and gas properties in Southwest Saskatchewan, forming part of the upstream segment, for cash proceeds of $56.9 million. The carrying value of the related property, plant, and equipment, exploration and evaluation assets and decommissioning liabilities have been classified as held for sale on the balance sheet at December 31, 2010. The sale was completed in February 2011 resulting in a gain of $29.3 million which was recorded within interest and other income.

In March 2011, the company entered in an agreement to sell certain natural gas properties in Northern Alberta, forming part of the upstream segment, for cash proceeds of $22.5 million, subject to normal post-closing adjustments. The carrying value of the related property, plant and equipment, exploration and evaluation assets and decommissioning liabilities have been classified as held for sale on the balance sheet at December 31, 2010 and March 31, 2011 and an impairment loss of $4.5 million was recognized in 2010 on the remeasurement to the lower of its carrying amount and its fair value less costs to sell. The sale was completed in April 2011.

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 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. Gran Tierra Energy entered into an agreement with Petrolifera on January 17, 2011, pursuant to which Gran Tierra Energy would acquire all of the issued and outstanding common shares and common share purchase warrants of Petrolifera subject to the approval of shareholders of Petrolifera. The transaction was completed in March 2011 following shareholder approval. Equity accounting ceased on December 31, 2010 upon reclassification as an asset held for sale. An impairment loss of $9.8 million on the remeasurement of the investment in Petrolifera to the lower of its carrying amount and its fair value less costs to sell was recognized in 2010.

The investment in Petrolifera was de-recognized in March 2011 and a loss of $2.3 million was reported within share of interest in and loss on disposition of associate. Further, accumulated other comprehensive loss of $4.5 million was transferred to the consolidated statement of operations and reported within share of interest in and loss on disposition of associate.

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

   
(Canadian dollar in thousands) Upstream Segment - Canada
   
Cost  
Balance, January 1, 2010 $96,162
Additions 25,048
Transferred to assets classified as held for sale (8,688)
Balance, December 31, 2010 112,522
Additions 25,701
Balance, March 31, 2011 $138,223
   
Accumulated amortization and impairment  
Balance, January 1, 2010 -
Charge for the period $4,609
Transferred to assets classified as held for sale (3,036)
Balance, December 31, 2010 1,573
Charge for the period 757
Balance, March 31, 2011 $2,330
Carrying value  
As at January 1, 2010 $96,162
As at December 31, 2010 $110,949
As at March 31, 2011 $135,893

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

9. Property, Plant and Equipment

                           
(Canadian dollar in thousands)       Oil and gas
properties
(Upstream)
    Refining
(Downstream)
    Corporate     Total
                           
Cost                          
Balance, January 1, 2010       $1,029,396     $105,789     $12,272     $1,147,457
Additions       204,474     8,575     2,128     215,177
Dispositions       (751)     -     -     (751)
Change in decommissioning liabilities       15,700     -     -     15,700
Foreign currency translation changes       -     (5,887)     -     (5,887)
Transferred to assets classified as held for sale       (59,679)     -     -     (59,679)
Balance, December 31, 2010       1,189,140     108,477     14,400     1,312,017
Additions       22,553     3,676     300     26,529
Change in decommissioning liabilities       (11,400)     -     -     (11,400)
Foreign currency translation changes       -     (2,528)     -     (2,528)
Balance, March 31, 2011       $1,200,293     $109,625     $14,700     $1,324,618
                           
Accumulated depletion, depreciation and impairment                          
Balance, January 1, 2010       $-     $18,075     $5,468     $23,543
Depletion and depreciation       55,040     10,470     2,330     67,840
Impairment charge (note 7.1)       4,476     -     -     4,476
Foreign currency translation changes       -     (1,284)     -     (1,284)
Transferred to assets classified as held for sale       (5,331)     -     -     (5,331)
Balance, December 31, 2010       54,185     27,261     7,798     89,244
Depletion and depreciation       15,354     2,062     301     17,717
Foreign currency translation changes       -     (635)     -     (635)
Balance, March 31, 2011       $69,539     $28,688     $8,099     $106,326
                           
Carrying  value                          
At  January 1, 2010       $1,029,399     $87,714     $6,804     $1,123,914
At  December 31, 2010       $1,134,955     $81,216     $6,602     $1,222,773
At  March 31, 2011       $1,130,754     $80,937     $6,601     $1,218,292

10. Trade and Accrued Payables

                                 
As at (Canadian dollar in thousands)                     March 31, 2011         December 31, 2010
Trade payables                     $35,321         $10,973
Accrued interest payable                     23,184         13,280
Taxes payable                     228         319
Other accrued liabilities                     56,644         54,514
Other payables                     2,183         2,284
                      $117,560         $81,370

11. Financial Instruments

Connacher's financial instruments include its cash, trade and accrued receivable, 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

Fair value estimates are made at a specific point in time, based on relevant market information and information about the financial instrument. These estimates cannot be determined with precision as they are subjective in nature and involve uncertainties and matters of judgment. The following table shows the comparison of the carrying and fair values of the company's financial instruments:

                                         
                  March 31, 2011     December 31, 2010
(Canadian dollar in thousands)                 Carrying Value       Fair Value     Carrying Value       Fair Value
Cash (1)                 $42,865       $42,865     $19,532       $19,532
Trade and accrued receivables (1)                 58,278       58,278     57,419       57,419
Investment in equity securities (2)                 26,104       26,104     -       -
Derivative financial assets (3)                 336       336     474       474
Trade and accrued payables (1)                 117,560       117,560     81,370       81,370
Derivative financial liabilities (3)                 49,695       49,695     18,863       18,863
Convertible Debentures (2)                 99,050       99,050     96,548       96,548
First Lien Senior Notes (4)                 180,732       209,389     184,176       216,823
Second Lien Senior Notes (4)                 $554,307       $606,290     $566,663       $587,049

(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 and convertible debentures are based on quoted market prices, a Level 1 measurement
(3)  The fair values of the derivative financial instruments were determined using quoted market prices or derived from observable market prices or indices and were based on Level 2 measurements
(4)  The fair values of Firs and Second Lien Senior Notes have been determined based on market information, a Level 1 measurement.

11.2  Derivative financial liabilities

Derivative financial liabilities comprise risk management contracts. The following table summarizes the net position of the company's risk management contracts in upstream segment:

                                 
(Canadian dollar in thousands)                     March 31, 2011         December 31, 2010
                                 
Current liability                                
  Oil contracts                     $34,391         $8,241
  Natural gas contracts                     604         743
Current liability                     34,995         8,984
Non-current liability - oil contracts                     14,700         9,879
Derivative financial liability                     $49,695         $18,863

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

March 31, 2011 - Crude oil contracts

                                     
Volume
(bbl/d)
      Term       Type       Price
(WTI U.S.$/bbl)
          Liability (Asset) as at March 31, 2011
(Canadian dollar in thousands)
2,000       Apr 1, 2011 - Jun 30, 2011       Swap       $85.25           $3,907
2,000       Jan 1, 2011 - Dec 31, 2011       Swap (1)       $90.60           23,081
2,000       Apr 1, 2011 - Mar 31, 2012       Call option       $96.00           11,294
2,000       Apr 1, 2011 - Mar 31, 2012       Put option       $80.00           (931)
2,000       Jul 1, 2011 - Jun 30, 2012       Call option       $100.00           10,625
2,000       Jul 1, 2011 - Jun 30, 2012       Put option       $80.00           (1,568)
2,000       Jan 1, 2012 - Dec 31, 2012       Call option       $120.00           5,496
2,000       Jan 1, 2012 - Dec 31, 2012       Put option       $80.00           (2,813)
Balance, as at March 31, 2011                           $49,091

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

March 31, 2011 - Natural gas contracts

                                     
Volume
(GJ/d)
      Term       Type       Price
(AECO CAD$/GJ)
          Liability as at March 31, 2011
(Canadian dollar in thousands)
4,000       Sept 1, 2010 - Aug 31, 2011       Swap       $3.87           $171
4,000       Oct 1, 2010 - Sept 30, 2011       Swap       $4.20           433
Balance, as at March 31, 2011                           $604

The following table summarizes the amounts recorded in the consolidated statements of operations with respect to the revenue-related risk management contracts:

                                             
For the three months end March 31                 2011       2010            
(Canadian dollar in thousands)                 Upstream       Upstream       Downstream (1)           Total
Unrealized loss                 $30,972       $778       $614           $1,392
Realized loss                 2,065       172       -           172
Loss on risk management contracts                 $33,037       $950       $614           $1,564

(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

The following table summarizes the amounts recorded in the consolidated statements of operations with respect to the operating cost-related upstream risk management contracts: 

                                                       
For the three months ended March 31
(Canadian dollar in thousands)
                                        2011           2010
Unrealized gain                                         $(140)           $-
Realized loss                                         332           -
Loss on risk management contracts                                         $192           $-

12. Long-Term Debt

                         
As at (Canadian dollar in thousands)           March 31, 2011           December 31, 2010
Convertible Debentures, Due June 30, 2012 (CAD$100 million)                 $99,050                $96,548
First Lien Senior Notes, Due July 15, 2014 (US$200 million)           194,360           198,920
Second Lien Senior Notes, Due December 15, 2015 (US$587 million)           570,777           584,168
                  864,187               879,636
Unamortized discount and transaction costs                  (30,098)                 (32,249)
Long-term debt           $834,089             $847,387

At March 31, 2011, the company was in compliance with all of the terms of its debt agreements. See note 23.

13. Decommissioning Liabilities

The following table summarizes the details of decommissioning liabilities:

                               
(Canadian dollar in thousands)                 Three months ended
March 31, 2011
          Year ended
December 31, 2010
Balance, beginning of period                 $70,945           $53,729
Liabilities incurred                 259           11,560
Liabilities settled                 (783)           (647)
Liabilities disposed                 (5,477)           (263)
Change in estimates                 (11,659)           4,463
Unwinding of discount                 447           2,103
Balance, end of period                 53,732           70,945
Classified as held for sale - current portion                 (4,367)           (10,907)
Balance, non-current portion                 $49,365           $60,038

At March 31, 2011, the estimated total undiscounted amount required to settle the decommissioning liabilities was $67.2 million (December 31, 2010 - $77.4 million). This amount has been discounted using risk-free rates of interest ranging between 1.72 percent to 3.66 percent, depending on the estimated time to abandon the asset.

14. Share Capital

                             
            Three months ended
March 31, 2011
    Year ended
December 31, 2010
(Canadian dollar in thousands except number of shares)           Number   Amount     Number     Amount
Balance, beginning of period           447,167,694   $618,628     427,031,362     $593,119
Issued for cash on flow-through basis                          
  net of premium of $2,272           -   -     17,480,000     23,074
Shares issued upon exercise of stock options           433,902   402     2,017,836     1,936
Shares issued to directors as compensation           256,167   499     638,496     480
Assigned value of stock options and awards exercised           -   224     -     1,082
Share issue cost, net of tax           -   (22)     -     (1,063)
Balance, end of period           447,857,763   $619,731     447,167,694     $618,628
                             
Weighted average common shares outstanding                          
  basic and diluted           448,456,839         427,830,214      

15. Stock options and share award plan for non-employee Directors

15.1  Stock options

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

                                       
Three months ended March 31                   2011                 2010
            Number
of Options
      Weighted Average
Exercise Price
        Number
of Options
      Weighted Average
Exercise Price
Outstanding, beginning of period           24,413,668       $1.72         22,579,045       $1.72
Granted           3,011,746       1.36         7,857,619       1.34
Exercised           (433,902)       0.93         (575,738)       0.92
Forfeited           (80,392)       1.31         (32,412)       1.14
Expired           (168,000)       5.04         (669,000)       3.54
Outstanding, end of period           26,743,120       $1.47         29,159,514       $1.59
Exercisable, end of period           15,998,986       $1.59         15,141,698       $1.95

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 three months ended ended March 31                                         2011           2010
Risk free interest rate (percent)                                         2.0           1.9
Expected option life (year)                                         3.0           3.0
Expected volatility (percent)                                         57           72

The weighted average fair value at the date of grant of options granted during the three months ended March 31, 2011 was $0.54 per option (three months ended March 31, 2010 - $0.64 per option).

15.2  Share award plan for non-employee Directors

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

                                                       
For the three months ended March 31                                         2011           2010
Outstanding, beginning of period                                         380,598           648,916
Granted                                         375,000           380,598
Issued                                         (256,167)           (638,496)
Cancelled                                         (124,431)           -
Outstanding, end of period                                         375,000           391,018
Exercisable, end of period                                         -           10,420

15.3  Share-based compensation

                           
For the three months ended March 31 (Canadian dollar in thousands)             2011           2010
Employee stock options             $1,017           $2,422
Share awards for non-employee directors             117           16
Total share-based compensation             1,134           2,438
Share-based compensation capitalized             (69)           (553)
Share-based compensation expensed             $1,065           $1,885

15.4  Contributed surplus

                             
(Canadian dollar in thousands)                 Three months ended
March 31, 2011
        Year ended
December 31, 2010
Balance, beginning of period                 $36,107         $31,040
Share-based compensation                 1,134         6,629
Assigned value of stock options exercised                 (224)         (1,082)
Assigned value of share awards issued                 (499)         (480)
Balance, end of period                 $36,518         $36,107

16. Finance Charges

                           
For the three months ended March 31 (Canadian dollar in thousands)             2011           2010
Interest expense on long-term debt             $23,512           $24,337
Amortization of transaction costs relating to the credit facility             112           118
Stand by fees relating to the credit facility             91           -
Bank charges and other fees             89           -
Unrealized loss on derivative financial asset             -           271
Unwinding of discount on provisions             446           469
Unrealized loss on convertible debentures             2,501           2,000
              26,751           27,195
Less: Interest capitalized             -           (12,768)
Finance charges             $26,751           $14,427

17. Foreign Exchange Gains

                           
For the three months ended March 31 (Canadian dollar in thousands)             2011           2010
Unrealized foreign exchange gain (loss) on translation of:                          
  U.S. denominated First and Second Lien Senior Notes             $17,236           $26,613
  Foreign currency denominated cash balances             (260)           (4,000)
  Other foreign currency denominated monetary items             (9)           395
Unrealized foreign exchange gains             16,967           23,008
Realized foreign exchange gains             433           935
Foreign exchange gains             $17,400           $23,943

18. Income Taxes

                           
For the three months ended March 31 (Canadian dollar in thousands)             2011           2010
Current                          
  Canada             $67           $206
  USA             -           -
Total current tax             67           206
Deferred tax recovery             (6,971)           (4,148)
Income tax recovery             $(6,904)           $(3,942)

19. Interest and Other Income

                             
For the three months ended March 31 (Canadian dollar in thousands)             2011             2010
Gain on sale of oil and gas properties             $29,316             $432
Unrealized gain on derivative financial assets             185             -
Interest and other             347             71
              $29,848             $503

20. Capital Management

The company is exposed to financial risks on its financial instruments and in the way it finances its capital requirements. The company works to minimize its exposures to these risks through forward financial planning and with the use of financial derivatives.

Connacher's objectives in managing its cash, debt and equity and its future capital requirements are to safeguard its ability to meet its financial obligations, to maintain a flexible capital structure that allows multiple financing options when a financing need or opportunity arises and to optimize its use of long-term debt and equity at an appropriate level of risk.

The company manages its capital structure and follows a financial strategy that considers economic and industry conditions, the risk characteristics and the long-term nature of its underlying assets and its growth opportunities. It strives to continuously improve its credit rating with the objective of reducing its cost of capital. Connacher monitors its capital structure using a number of financial ratios and industry metrics to ensure its objectives are being met and to ensure continued compliance with its financial covenants. Connacher's current capital structure is summarized below:

                                           
As at (Canadian dollar in thousands)                               March 31, 2011         December 31, 2010
Long term debt (1)                               $834,089         $847,387
Shareholders' equity                               515,941         526,985
Total debt plus equity ("capitalization")                               $1,350,030         $1,374,372
Debt to book capitalization (2)                               62%         62%

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

As at March 31, 2011, the company's net debt (long-term debt, net of cash on hand) was $791 million. Net debt to book capitalization was 59 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.

21. Segmented Information

21.1  Results of operations

                             
(Canadian dollar in thousands)
For the three months ended March 31, 2011
        Canada
Upstream
          USA
Downstream
    Inter-segment
Elimination
    Consolidated
Income                            
Revenues         $102,254     $81,952     $(5,216)     $178,990
Less: expenses                            
Operating costs         67,026     75,373     (5,216)     137,183
Transportation and handling costs         11,398     1,892     -     13,290
          23,830     4,687     -     28,517
Realized loss on risk management contracts - net         (2,397)     -     -     (2,397)
General and administrative expenses         (9,204)     (1,219)     -     (10,423)
Segment operating income         12,229     3,468     -     15,697
Depletion, depreciation and amortization         (16,111)     (2,062)     -     (18,173)
Segment income (loss)         (3,882)     1,406     -     (2,476)
Interest and other income                           29,848
Unrealized loss on risk management contracts - net                           (30,832)
Share-based compensation                           (1,065)
Finance charges                           (26,751)
Foreign exchange gains                           17,400
Depreciation - corporate                           (301)
Share of interest in associate and loss on disposition                           (6,828)
Income tax recovery                           6,904
Net loss                           $(14,101)
                             
(Canadian dollar in thousands)
For the three months ended March 31, 2010
        Canada
Upstream
    USA
Downstream
    Inter-segment
Elimination
    Consolidated
Income                            
Revenues         $62,353     $62,780     $(4,038)     $121,095
Less: expenses                            
Operating costs         34,430     65,456     (4,038)     95,848
Transportation and handling costs         3,214     1,191     -     4,405
          24,709     (3,867)     -     20,842
Realized loss on risk management contracts - net         (172)     -     -     (172)
General and administrative expenses         (5,707)     (678)     -     (6,385)
Segment operating income         18,830     (4,545)     -     14,285
Depletion, depreciation and amortization         (12,750)     (2,500)     -     (15,250)
Segment income (loss)         6,080     (7,045)     -     (965)
Interest and other income                           503
Unrealized loss risk management contracts - net                           (1,392)
Share-based compensation                           (1,885)
Finance charges                           (14,427)
Foreign exchange gains                           23,943
Depreciation - corporate                           (607)
Exploration and Evaluation expenses                           (140)
Income tax recovery provision                           3,942
Share of interest in associate and loss on disposition                           (467)
Net earnings                           $8,505

21.2  Capital expenditures

                           
For the three months ended March 31 (Canadian dollar in thousands)             2011           2010
Upstream             $48,485           $115,516
Downstream             3,676           1,139
Total             $52,161           $116,655

22. First time adoption of IFRS

As stated in note 2, these are the company's first interim consolidated financial statements prepared in accordance with IFRS for the period ended March 31, 2011 in conjunction with the company's annual audited consolidated financial statements to be issued under IFRS as at and for the year ended 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 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. Accordingly, these interim consolidated financial statements were prepared using the accounting policies stated in note 3 and were retrospectively and consistently applied except where specific IFRS 1 optional and mandatory exemptions permitted an alternative treatment upon transition to IFRS for first-time adopters. The significant exemptions applied under IFRS 1 in preparing these interim consolidated financial statements are set out below:

Deemed cost election for oil and gas properties

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

Leases

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

Business combinations

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

Borrowing costs

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

Additional exemptions applied

The company applied additional exemptions for cumulative foreign currency translation differences including the share of associate, compensation and decommissioning liabilities, which are explained in the note 22.4, note 22.5 and note 22.6 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 January 1, 2010, March 31, 2010 and December 31, 2010, and consolidated statements of operations and comprehensive income (loss), for the three months ended March 31, 2010 and for the year ended December 31, 2010.

Notes to the Condensed Interim Consolidated Financial Statements
(Unaudited)
Three months ended March 31, 2011 and 2010
Reconciliation of Equity
As at January 1, 2010

                                                           
              IFRS Adjustments  
              E&E     Impairment     Foreign
Currency
  Compensation     ARO     Associate     Taxes     Debt    
(Canadian dollar in thousands)       Previous
GAAP
                                                IFRS
ASSETS       Notes     22.1     22.2     22.4   22.5     22.6     22.7     22.8     22.9    
CURRENT ASSETS                                                          
Cash       $256,787     $-     $-     $-   $-     $-     $-     $-     $-   $256,787
Trade and accrued receivables       43,067     -     -     -   -     -     -     -     -   $43,067
Inventories       36,871     -     -     -   -     -     -     -     -   $36,871
Other assets       17,774     -     -     -   -     -     -     -     -   $17,774
Deferred tax assets       2,348     -     -     -   -     -     -     (2,348)     -   $-
        356,847         -                -     -   -       -         -     (2,348)     -   $354,499
NON-CURRENT ASSETS                                                          
Other assets       708     -     -     -   -     -     2,711     -     -   3,419
Investment in associate       50,379     -     -     -   -     -     (2,139)     -     -   48,240
Exploration and evaluation assets       -     96,162     -     -   -     -     -     -     -   96,162
Property, plant and equipment       1,230,256     (96,162)     (10,180)     -   -     -     -     -     -   1,123,914
Goodwill       103,676     -     (103,676)     -   -     -     -     -     -   -
        1,385,019     -     (113,856)     -   -     -     572     -     -   1,271,735
        $1,741,866     $-     $(113,856)     $-   $-     $-     $572     $(2,348)     -   $1,626,234
                                                           
LIABILITIES AND SHAREHOLDERS' EQUITY                                                  
CURRENT LIABILITIES                                                          
Trade and accrued payables       $105,620     $-     $-     $-   $(816)     $-     $-     $-     $-   $104,804
Risk management contracts       4,520     -     -     -   -     -     -     -     -   4,520
        110,140     -     -     -   (816)     -     -     -     -   109,324
                                                           
NON-CURRENT LIABILITIES                                                          
Long-term debt       876,181     -     -     -       -     -     -     3,558   879,739
Decommissioning liabilities       32,848     -     -     -       20,881     -     -     -   53,729
Employee benefits       1,066     -     -     -   (722)     -     -     -     -   344
Deferred income taxes       50,043     -     (2,545)     -       (5,237)     72     (7,832)     -   34,501
        960,138     -     (2,545)     -   (722)     15,644     72     (7,832)     3,558   968,313
                                                           
SHAREHOLDERS' EQUITY                                                          
Share capital       590,845     -     -     -   -     -     -     2,274     -   593,119
Equity component of
convertible debentures
      16,817     -     -     -   -     -     -     -     (16,817)   -
Contributed surplus       30,560     -     -     -   480     -     -     -         31,040
Retained earnings       49,544     -     (111,311)     (16,178)   1,058     (15,644)     1,127     3,210     13,259   (74,935)
Accumulated other
comprehensive loss
      (16,178)     -     -     16,178   -     -     (627)     -         (627)
        671,588     -     (111,311)     -   1,538     (15,644)     500     5,484     (3,558)   548,597
        $1,741,866     $-     $(113,856)     $-   $-     $-     $572     $(2,348)     $-   $1,626,234

Reconciliation of Equity
As at March 31, 2010

                                                     
(Canadian dollar in thousands)       IFRS Adjustments    
        E&E   DD&A &
Impairment
  Disposition     Foreign
Currency
  Compensation     ARO   Associate     Taxes     Debt    
    Previous
GAAP
                                              IFRS
ASSETS   Notes   22.1   22.2   22.3     22.4   22.5     22.6   22.7     22.8     22.9    
CURRENT ASSETS                                                    
Cash   $118,382   $-   $-   $-     $-   $-     $-   $-     $-     $-   $118,382
Trade and accrued receivables   40,269   -   -   -     -   -     -   -     -     -   40,269
Inventories   49,814   -   -   -     -   -     -   -     -     -   49,814
Other assets   17,235   -   -   -     -   -     -   -     -     -   17,235
    225,700   -   -   -     -   -     -   -     -     -   225,700
NON-CURRENT ASSETS                                                    
Other assets   -   -   -   -     -   -     -   2,440     -     -   2,440
Investment in associate   49,759   -   -   -     -   -     -   (3,351)     -     -   46,408
Exploration and evaluation assets   -   112,626   (1,010)   -     -   -     -   -     -     -   111,616
Property, plant and equipment   1,327,988   (112,766)   (7,086)   432     -   (99)     2,909   -     -     -   1,211,378
Goodwill   103,676       (103,676)   -     -             -     -     -   -
    1,481,423   (140)   (111,772)   432     -   (99)     2,909   (911)     -     -   1,371,842
    $1,707,123   $(140)   $(111,772)   $432     $-   $(99)     $2,909   $(911)     $-     $-   $1,597,542
                                                     
LIABILITIES AND SHAREHOLDERS' EQUITY                                                
CURRENT LIABILITIES                                                    
Trade and accrued payables   $92,602   $-   $-   $-     $-   $(230)     $-   $-     $-     $-   $92,372
Risk management contracts   5,912   -   -   -     -   -     -   -     -     -   5,912
    98,514   -   -   -     -   (230)     -   -     -     -   98,284
NON-CURRENT LIABILITIES                                                    
Long-term debt   851,978   -   -   -     -   -     -   -     -     4,517   856,495
Decommissioning liabilities   34,539   -   -   -     -   -     23,584   -     -     -   58,123
Employee benefits   1,182   -   -   -     -   (722)     -   -     -     -   460
Deferred income taxes   52,188   (35)   (2,023)   108     -   -     (5,185)   (195)     (15,006)     -   29,852
    939,887   (35)   (2,023)   108     -   (722)     18,399   (195)     (15,006)     4,517   944,930
                                                     
SHAREHOLDERS' EQUITY                                                    
Share capital   585,085   -   -   -     -   (522)     -   -     9,823     -   594,386
Equity component of
convertible debentures
  16,817   -   -   -     -   -     -   -     -     (16,817)   -
Contributed surplus   32,558   -   -   -     -   310     -   -     -     -   32,868
Retained earnings   55,090   (105)   (109,749)   324     (16,178)   1,065     (15,490)   1,130     5,183     12,300   (66,430)
Accumulated other
comprehensive loss
  (20,828)   -   -   -     16,178   -     -   (1,846)     -     -   (6,496)
    668,722   (105)   (109,749)   324     -   853     (15,490)   (716)     15,006     (4,517)   554,328
    $1,707,123   $(140)   $(111,772)   $432     $-   $(99)     $2,909   $(911)     $-     $-   $1,597,542

Reconciliation of Equity
As at December 31, 2010

                                                       
(Canadian dollar in thousands)         IFRS Adjustments    
          E&E   DD&A &
Impairment
  AHFS &
Disposition
    Foreign
Currency
  Compensation     ARO   Associate     Taxes     Debt    
    Previous
GAAP
                                                IFRS
ASSETS   Notes     22.1   22.2   22.3     22.4   22.5     22.6   22.7     22.8     22.9    
CURRENT ASSETS                                                      
Cash   $19,532     $-   $-   $-     $-   $-     $-   $-     $-     $-   $19,532
Trade and accrued receivables   57,419     -   -   -     -   -     -   -     -     -   57,419
Inventories   57,144     -   -   -     -   -     -   -     -     -   57,144
Other assets   17,653     -   -   -     -   -     -   -     -     -   17,653
Deferred tax assets   4,497     -   -   -     -   -     -   -     (4,497)     -   -
Assets held for sale   -     -   -   60,000     -   -     -   28,157     -     -   88,157
    156,245     -   -   60,000     -   -     -   28,157     (4,497)     -   239,905
NON-CURRENT ASSETS                                                      
Other assets   615     -   -   -     -   -     -   -     -     -   615
Investment in associate   27,938     -   -   -     -   -     -   (27,938)     -     -   -
Exploration and evaluation
assets
  -     120,844   (4,609)   (5,286)     -   -     -   -     -     -   110,949
Property, plant and equipment   1,395,524     (121,808)   (770)   (58,392)     -   (53)     11,685   -     (3,413)     -   1,222,773
Goodwill   103,676     -   (103,676)         -   -     -   -     -     -   -
    1,527,753     (964)   (109,055)   (63,678)     -   (53)     11,685   (27,938)     (3,413)     -   1,334,337
    $1,683,998     $(964)   $(109,055)   $(3,678)     $-   $(53)     $11,685   $219     $(7,910)     $-   $1,574,242
                                                       
LIABILITIES AND SHAREHOLDERS' EQUITY                                                  
CURRENT LIABILITIES                                                      
Trade and accrued payables   $81,886     $-   $-   $-     $-   (516)     $-   $-     $-     $-   $81,370
Risk management contracts   8,984     -   -   -     -   -     -   -     -     -   8,984
Liabilities relating to assets
held for sale
  -     -   -   10,907     -   -     -   -     -     -   10,907
    90,870     -   -   10,907     -   (516)     -   -     -     -   101,261
NON-CURRENT LIABILITIES                                                      
Risk management contracts   9,879     -   -   -     -   -     -   -     -     -   9,879
Long-term debt   843,601     -   -   -     -   -     -   -     -     3,786   847,387
Decommissioning liabilities   39,191     -   -   (10,907)     -   -     31,754   -     -     -   60,038
Employee benefits   915     -   -   -     -   (722)     -   -     -     -   193
Deferred income tax   49,359     (242)   (1,342)   (919)     -   -     (6,108)   (636)     (11,613)     -   28,499
    942,945     (242)   (1,342)   (11,826)     -   (722)     25,646   (636)     (11,613)     3,786   945,996
                                                       
SHAREHOLDERS' EQUITY                                                      
Share capital   611,599     -   -   -     -   (522)     -   -     7,551     -   618,628
Equity component of
debentures
  16,817     -   -   -     -   -     -   -     -     (16,817)   -
Contributed surplus   35,503     -   -   -     -   604     -   -     -     -   36,107
Retained earnings   10,746     (722)   (107,713)   (2,759)     (16,178)   1,103     (13,961)   4,495     (3,848)     13,031   (115,806)
Accumulated other
comprehensive loss
  (24,482)     -   -   -     16,178   -     -   852     -     -   (7,452)
Accumulated other for assets
held for sale
  -     -   -   -     -   -     -   (4,492)           -   (4,492)
    650,183     (722)   (107,713)   (2,759)     -   1,185     (13,961)   855     3,703     (3,786)   526,985
    $1,683,998     $(964)   $(109,055)   $(3,678)     $-   $(53)     $11,685   $219     $(7,910)     $-   $1,574,242

Reconciliation of Comprehensive Income (Loss)
For the three months ended March 31, 2010

                                                         
          IFRS Adjustments    
          E&E   DD&A and
Impairment
  AHFS &
Disposition
  Compensation       ARO   Associate     Taxes   Reclass       Debt    
(Canadian dollar in thousands)   Previous
GAAP
                                                  IFRS
INCOME   Notes     22.1   22.2   22.3   22.5       22.6   22.7     22.8   22.10       22.9    
Revenue   $119,904     $-   $-   $-   $-       $-   $-     $-   $1,191       $-   $121,095
Loss on revenue-related
risk management contracts
  (1,564)     -   -   -   -       -   -     -   -       -   (1,564)
Interest and other income   71     -   -   432   -       -   -     -   -       -   503
    118,411     -   -   432   -       -   -     -   1,191       -   120,034
EXPENSES                                                        
Operating costs   96,681     -   -   -   -       -   -     -   (833)       -   95,848
Transportation costs   3,214     -   -   -   -       -   -     -   1,191       -   4,405
General and administrative   5,552     -   -   -   -       -   -     -   833       -   6,385
Finance charges   12,729     -   -   -   -       (207)   271     -   676       958   14,427
Share-based compensation   1,891     -   -   -   (6)       -   -     -   -       -   1,885
Foreign exchange gains   (23,943)     -   -   -   -       -   -     -   -       -   (23,943)
Exploration and evaluation   -     140   -   -   -       -   -     -   -       -   140
Depletion, depreciation
and amortization
  18,617     -   (2,084)   -   -       -   -     -   (676)       -   15,857
Share of interest in associate   648     -   -   -   -       -   (181)     -   -       -   467
    115,389     140   (2,084)   -   (6)       (207)   90     -   1,191       958   115,471
EARNINGS (LOSS) BEFORE TAX   3,022     (140)   2,084   432   6       207   (90)     -   -       (958)   4,563
Income tax expense (recovery)   2,524     35   (522)   (108)   -       (52)   92     1,973   -       -   3,942
NET EARNINGS (LOSS)   5,546     (105)   1,562   324   6       155   2     1,973   -       (958)   8,505
                                                         
OTHER COMPREHENSIVE LOSS
AFTER TAX
                                                       
Exchange differences on translating
foreign operations
  (4,650)     -   -   -   -       -   -     -   -       -   (4,650)
Share of other comprehensive loss
of associate
  -     -   -   -   -       -   (1,219)     -   -       -   (1,219)
OTHER COMPREHENSIVE LOSS
AFTER TAX
  (4,650)     -   -   -   -       -   (1,219)     -   -       -   (5,869)
TOTAL COMPREHENSIVE
INCOME (LOSS)
  $896     $(105)   $1,562   $324   $6       $155   $(1,217)     $1,973   -       (958)   $2,636
                                                         
                                                         
EARNINGS PER SHARE   Previous
GAAP
                                                  IFRS
Basic and diluted (note 22.11)   $0.01                                                   $0.02

Reconciliation of Comprehensive Income (Loss)
For the year ended December 31, 2010

                                                   
(Canadian dollar in thousands)         IFRS Adjustments    
          E&E   DD&A and
Impairment
  AHFS &
Disposition
  Compensation     ARO   Associate   Taxes   Reclass     Debt    
    Previous
GAAP
                                            IFRS
INCOME   Notes     22.1   22.2   22.3   22.5     22.6   22.7   22.8   22.10     22.9    
Revenue   $589,931     $-   $-   $-   $-     $-   $-   $-   $-     $-   $589,931
Loss on revenue-related
risk management contracts
  (15,885)     -   -   -   -     -   -   -   -     -   (15,885)
Interest and other income   256     -   -   798   -     -   -   -   -     -   1,054
    574,302     -   -   798   -     -   -   -   -     -   575,100
EXPENSES                                                  
Operating costs   448,615         -   -   -     -   -   -   (3,885)     -   444,730
Transportation costs   26,772         -   -   -     -   -   -   -     -   26,772
Loss on operating cost-related
risk management contracts
  1,301         -   -   -     -   -   -   -     -   1,301
General and administrative   19,921         -   -   -     -   -   -   3,885     -   23,806
Finance charges   64,877     -   -   -         (812)   2,237   -   2,915     228   69,445
Share-based compensation   5,063     -   -   -   (44)     -   -   -   -     -   5,019
Foreign exchange gains   (41,641)     -   -   -   -     -   -   -   -     -   (41,641)
Exploration and evaluation         964   -   -   -     -   -   -   -     -   964
Depletion, depreciation
and amortization
  79,586     -   (4,801)   4,476   -     -   -   -   (2,915)     -   76,346
Share of interest in associate   21,393     -   -   -   -     -   (5,377)   -   -     -   16,016
    625,887     964   (4,801)   4,476   (44)     (812)   (3,140)   -   -     228   622,758
EARNINGS (LOSS) BEFORE TAX   (51,585)     (964)   4,801   (3,678)   44     812   3,140   -   -     (228)   (47,658)
Income tax expense (recovery)   12,787     242   (1,203)   919   -     871   228   (7,057)   -     -   6,787
NET EARNINGS (LOSS)   (38,798)     (722)   3,598   (2,759)   44     1,683   3,368   (7,057)   -     (228)   (40,871)
                                                   
OTHER COMPREHENSIVE LOSS
AFTER TAX
                                                 
Exchange differences on translating
foreign operations
  (7,452)     -   -   -   -     -   -   -   -     -   (7,452)
Share of other comprehensive loss
of associate
  (852)     -   -   -   -     -   (3,436)   -   -     -   (4,288)
Transfer on loss of ownership   -     -   -   -   -     -   422   -   -     -   422
OTHER COMPREHENSIVE LOSS
AFTER TAX
  (8,304)     -   -   -   -     -   (3,014)   -   -     -   (11,318)
TOTAL COMPREHENSIVE
INCOME (LOSS)
  $(47,102)     $(722)   $3,598   $(2,759)   $44     $1,683   $354   $(7,057)   $-     $(228)   $(52,189)
                                                   
                                                   
LOSS PER SHARE   Previous
GAAP
                                            IFRS
Basic and diluted (note 22.11)   $(0.09)                                             $(0.09)

22.1 Exploration and Evaluation ("E&E")

As explained above under "Deemed cost election for oil and gas properties", the company reclassified $96.2 million, $112.6 million and $120.8 million to exploration and evaluation assets at January 1, 2010, March 31, 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 $140,000 and $ 964,000 in three months ended March 31, 2010 and the year ended December 31, 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 and $722,000 after tax benefit of $35,000 and $242,000 for the three months ended March 31, 2010 and the year ended December 31, 2010, respectively.

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

Depletion, depreciation and amortization

As explained above under "Deemed cost election for oil and gas properties", development costs at January 1, 2010 were deemed to be $1,029 million, representing the upstream full cost pool balance under previous GAAP and were presented as property, plant and equipment under previous GAAP consistent with IFRS.

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 $ 2.1 million and $4.8 million in the three months ended March 31, 2010 and year ended December 31, 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 $1.6 million and $3.6 million after a tax benefit of $500,000 and $1.2 million for the three months ended March 31, 2010 and the year ended December 31, 2010, respectively.

Impairment

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

22.3 Asset and Liabilities Held For Sale ("AHFS") and disposition of Oil and Gas Properties

Under previous GAAP, proceeds from disposition 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 obligation 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 three months ended March 31, 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.

During the year ended December 31, 2010, the company recognized a gain of $798,000 on sale of certain oil and gas properties ($432,000) and exploration and evaluation assets ($366,000).

The effect of the above adjustments on retained earnings was an increase of $324,000 and a reduction of $2.8 million after tax benefit of $108,000 and $919,000 for the three months ended March 31, 2010 and the year ended December 31, 2010, respectively.

22.4 Foreign Currency

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

22.5 Compensation

Share based payments

In accordance with IFRS 1, the company has elected to apply the requirements of IFRS 2 "share-based payment" to those equity instruments that were issued after November 7, 2002 but that had not vested as of January 1, 2010 and liabilities awards that will be settled after the transition date. The company currently has 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. As a result, share-based compensation expense and property, plant and equipment were decreased with a corresponding decrease to contributed surplus. 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 share awards plan were considered a liability award and were revalued at each reporting period end with changes recorded in statement of operations and the 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 Connacher. 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. On January 1, 2010, the company reclassified $816,000 from trade and accounts payables, removed prior revaluation from retained earnings totaling $336,000 and recorded the remaining amount of $480,000 to contributed surplus representing the value of outstanding awards at grant date fair value.

The effect of the above share options and share awards adjustments on retained earnings was an increase of $6,000 and $44,000, a reduction of property, plant and equipment of $99,000 and $53,000, reduction of trade and accounts payables of $229,000 and $516,000 and an increase of contributed surplus of $310,000 and $604,000 for the three months ended March 31, 2010 and year ended December 31, 2010, respectively, excluding the impact of the January 1, 2010 adjustment.

Defined benefit plan

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

22.6 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 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 asset retirement obligation 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 asset retirement obligation 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 asset retirement obligation. As at March 31, 2010 and December 31, 2010, excluding the January 1, 2010 adjustment, the company's asset retirement obligation increased by $2.7 million and $10.9 million, respectively, which primarily reflects the remeasurement of the obligation using the company's discount rate of 3.3 percent as at March 31, 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 $207,000 in the three months ended March 31, 2010 and $812,000 in the year ended December 31, 2010.

22.7 Investment in Associate

As at January, 1, 2010, March 31, 2010 and December 31, 2010, the company owned 26.9 million Petrolifera common shares, representing 22 percent as at January 1, 2010 and March 31, 2010 and 18.5 percent as at December 31, 2010 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 are 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 none 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 equity financing and the company did not subscribe for shares in this financing. Accordingly, the company'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 under 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 statement of operations. Accordingly, the company recorded a transfer of $422,000 from other comprehensive loss to statement of operations and reported within 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)           Jan 1, 2010         March 31, 2010       December 31, 2010
Balance sheet                              
Amount reported under previous GAAP           $50,379         $49,759       $27,938
Share of accumulated income (loss)           (1,584)         (1,310)       4,874
Share of accumulated other comprehensive loss           (627)         (1,846)       (4,492)
Deferred tax           72         (195)       (636)
Total Investment balance under IFRS           48,240         46,408       27,684
Other asset - derivative financial asset           2,711         2,440       474
Total investment in Petrolifera           50,951         48,848       28,157
Less: Assets classified as held for sale           $-         $-       $28,157
Statement of operations                              
Share of interest in associate           $-         $181       $5,377
Finance charges - change in fair value of derivative           -         (271)       (2,237)
Deferred tax           -         92       228
Effect to retained earnings excluding January, 1 2010 adjustments                     2       3,368
Adjustments to retained earnings - January 1, 2010                              
  Share of loss           (1,584)         (1,584)       (1,584)
  Derivative financial asset           2,711         2,711       2,711
            1,127         1,127       1,127
Total impact on retained earnings           $1,127         $1,129       $4,495

22.8 Taxes

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

Flow-through shares - Under Canadian income tax legislation, a company is permitted to issue flow-through shares whereby the company is obligated to incur qualifying expenditures and renounce the related income tax deductions to the investors. The qualifying expenditures incurred by the company primarily relate to the oil and gas exploratory and development activities. Generally, due to transferring the benefit of tax deduction to the investors, the 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 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 $2.3 million, $9.8 million and $7.6 million with a corresponding decrease to retained earnings on January 1, 2010, March 31, 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 above items with 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 $2.3 million at January 1, 2010 and $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
                Jan 1, 2010         March 31, 2010       December 31, 2010
Flow-through shares                 $7,555         $6       $6,943
Capital loss on intercompany transaction                 (13,039)         (13,039)       (12,653)
Discount on Long-term Debt                 -         (186)       (875)
Foreign exchange impact on debt                 -         (1,787)       3,470
Capitalized Stock-based compensation                 -         -       (4,001)
Reclassification                 (2,348)         -       (4,497)
Change in deferred tax liability                 $(7,832)         $(15,006)       $(11,613)

Other items - In addition to the above items, the change in deferred tax liability on January 1, 2010, as at and for the three months ended March 31, 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.

22.9 Debt

Under previous GAAP, the convertible debentures were treated as a compound financial instrument with a debt and equity component. Under IFRS, the equity component is considered an embedded derivative. As permitted under IFRS, the company designated the convertible debentures as "fair value through profit and loss" and accordingly, recorded convertible debentures at fair value at each reporting 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, March 31, 2010 and December 31, 2010. In addition, the company recognized the effect of change in fair value by increasing the long-term debt by $3.6 million on January 1, 2010 with a corresponding decrease to retained earnings. The adjustment also resulted in removal of previously recorded accretion expense and recognition of unrealized gains and losses on revaluation. This resulted in an increase in finance changes of $1 million and $228,000 in three months ended March 31, 2010 and December 31, 2010, respectively, with a corresponding increase to long-term debt.

22.10 Reclassifications

In order to comply with the presentation of consolidated statement of operations adopted by the company under IFRS, in downstream segment, the company classified certain transportation costs totaling $1.2 million to revenue for the three months ended March 31, 2010. In addition, the company also classified $833,000 and $3.9 million from operating expenses to general and administrative expenses during the three months ended March 31, 2010 and the year ended December 31, 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 ($676,000 in the three months ended March 31, 2010 and $2.9 million in the year ended December 31, 2010).

22.10 Changes to the Statement of Cash flow

The following is a reconciliation of the company's cash from operating and investing activities reported in accordance with previous GAAP to cash from operating and investing activities in accordance with IFRS for the three months ended March 31, 2010 and the year ended December 31, 2010:

                           
(Canadian dollar in thousands)               Three months ended
March 31, 2010
        Year ended
December 31, 2010
Cash from (used in) operating activities under previous GAAP               $(8,299)         $10,785
  Exploration and evaluation expenses               (140)         (964)
Cash from (used in) operating activities under IFRS               $(8,439)         $9,821
                           
Cash from (used in) investing activities under previous GAAP               $(127,297)         $(269,763)
  Exploration and evaluation expenses               140         964
Cash from (used in) investing activities under IFRS               $(127,157)         $(268,799)

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

22.11 Earnings (loss) per share

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

23. Subsequent event

On May 10, 2011 the company announced a tender offer to redeem all of its outstanding First Lien and Second Lien Notes, subject to, among other things, the majority of the aggregate principal amount of each series of Notes being tendered for redemption and the completion of one or more secured debt financings on terms acceptable to Connacher in an amount sufficient to fund the redemption of all outstanding notes and related fees and expenses.

 

 

 

 

 

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    
inquiries@connacheroil.com      
Fax:  (403) 538-6225
Website:  connacheroil.com


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