Connacher Oil and Gas Ltd. Reports Fourth Quarter 2010 And Year End 2010 Results; Bitumen Reserve And Resource Base Expand by 24hgold

Equity securities

Fixed income securities

Cash and cash equivalents

CALGARY, March 17 /CNW/ - Connacher Oil and Gas Limited (News - Market indicators); ("Connacher" or the "Company") today released its financial and operating results for 2010. The year was marked by a significant expansion of the company's crude oil reserve and resource base; on time, under budget completion of Algar, the Company's second notional 10,000 bbl/d steam-assisted gravity drainage ("SAGD") bitumen project at Great Divide; on time, under budget completion of the Algar 13.1 megawatt natural gas fired electrical co-generation facility; and significant production growth by year end 2010, setting the stage not only for continued improvement in the company's capacity to meet all financial obligations, but also enhancing Connacher's capacity to finance future growth from internally-generated funds.

Readers are reminded we will be holding a conference call to discuss the contents of this release and our year-end 2010 results scheduled for 7:00 AM MDT on Friday, March 18, 2011. To listen to or participate in the live conference call please dial either 1-647-427-7450 or 1-888-231-8191. A replay of the event will be available from Friday, March 18, 2011 at 12:00 MDT until 21:59 MDT on Friday, March 25, 2011. To listen to the replay please dial either 1-416-849-0833 or Toll Free at 1-800-642-1687 and enter the pass code 43686622. You can also listen to the conference call online, through the following webcast link: http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=3403620

Highlights of the year are as follows:

The Company's proved and probable ("2P") reserves increased by 31 percent to surpass half a billion barrels of oil equivalent ("boe"); our 2P reserves are 99 percent crude oil and 2P reserve additions replaced production over 30 times
Connacher's best estimate contingent resources increased 63 percent to 221 million barrels
Algar, a notional 10,000 bbl/d bitumen production project, was completed in April 2010, commissioned, placed onstream and determined to be commercial by October 2010
Application for Great Divide expansion was submitted for continued growth; regulatory decisions are anticipated by late 2011 to enable construction to start, likely by mid-2012 at the earliest
Revenues net of royalties increased 34 percent to $574 million; Record 2010 EBITDA of $92 million up 147 percent over 2009 levels; cash flow increased 195 percent to $37 million
Total production increased 16 percent; our fourth quarter 2010 bitumen production rate of 13,238 bbl/d exceeded our 2010 average by 60 percent. The "stage is set" for 2011, as December 2010 bitumen production rate was approximately 14,000 bbl/d and Algar is still ramping up
Montana Refining Company Inc. ("MRC") had an excellent year, with high throughput, solid margins and a strong outlook
New light gravity crude oil resource play established in central Alberta near existing Connacher production; early drilling results are encouraging; potential for 100 plus follow-up well locations on 100 percent-owned lands
Initiated a non-core asset rationalization program, which is anticipated to strengthen liquidity and cash balances, thus reducing net debt; debt refinancing alternatives under assessment to reduce cost of capital as operating results improve, for compound positive impact

HIGHLIGHTS

FINANCIAL ($000 except per share amounts)		Years ended December 31
		2010	2009	% Change
Revenues, net of royalties		$574,302	$428,214	34
Cash flow ⁽¹⁾		$36,884	$12,522	195
	Per share, basic and diluted ⁽¹⁾	$0.09	$0.04	125
Adjusted EBITDA ⁽¹⁾		$92,206	$37,268	147
Net earnings (loss)		$(38,798)	$26,158	(248)
	Per share, basic	$(0.09)	$0.08	(213)
Additions to property, plant and equipment		$247,978	$322,064	(23)
Cash on hand		$19,532	$256,787	(92)
Working capital		$65,375	$246,707	(74)
Long-term debt		$843,601	$876,181	(4)
Shareholders' equity		$650,183	$671,588	(3)
Total assets		$1,683,998	$1,741,866	(3)

OPERATIONAL
Daily production volumes ⁽⁴⁾
	Bitumen (bbl/d)	8,299	6,274	32
	Crude oil (bbl/d)	883	1,041	(15)
	Natural gas (Mcf/d)	9,100	11,407	(20)
	Barrels of oil equivalent (boe/d) ⁽⁵⁾	10,699	9,216	16
Upstream pricing ⁽⁶⁾
	Bitumen ($/bbl)	$45.65	$39.39	16
	Crude oil ($/bbl)	$65.63	$54.61	20
	Natural gas ($/Mcf)	$3.90	$3.90	-
	Barrels of oil equivalent ($/boe) ⁽⁵⁾	$44.13	$37.81	17
Downstream
	Throughput - Crude charged (bbl/d)	9,693	7,820	24
	Refinery utilization (%)	102	82	24
	Margins (%)	8	4	100

RESERVES AND RESOURCES
Reserves and resources (mboe) ⁽⁷⁾
	Proved (1P) reserves	186,668	180,159	4
	Proved plus probable (2P) reserves	509,434	388,915	31
	Proved plus probable plus possible (3P) reserves	613,485	471,406	30
Best estimate contingent resources		220,572	134,919	63
Reserves and resources values ($ million) ⁽⁸⁾
	1P reserves	$1,497	$1,491	-
	2P reserves	$3,101	$2,156	44
	3P reserves	$3,849	$3,311	16
Best estimate contingent resources		$571	$384	49
COMMON SHARE INFORMATION
Shares outstanding end of period (000)		447,168	427,031	5
Weighted average shares outstanding for the period
	Basic (000)	432,258	326,560	33
	Diluted (000)	432,258	327,067	32
Volume traded (000)		585,135	654,270	(11)
Common share price ($)
	High	$1.88	$1.66	13
	Low	$1.10	$0.61	80
	Close (end of period)	$1.33	$1.28	4

⁽¹⁾	^{A non-GAAP measure which is defined in the Advisory section of the MD&A.}
⁽²⁾	^{No dividends have been declared by the company since its incorporation.}
⁽³⁾	^{Effective October 1, 2010, the capitalized costs relating to the company's second oil sands project, Algar, were added to the full cost pool for depletion and ceiling test calculations 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. Daily production and sales averages are based on total calendar years during the year.}
⁽⁴⁾	^{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 production volumes sold were 10,606 boe/d in 2010 (2009 - 9,216 boe/d).}
⁽⁵⁾	^{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.}
⁽⁶⁾	^{Before royalties and risk management contract gains or losses and after applicable diluent and transportation costs divided by actual sales volumes.}
⁽⁷⁾	^{The reserve and resource estimates for 2010 and 2009 were prepared by GLJ Petroleum Consultants Ltd. an independent professional petroleum engineering firm, in accordance with Canadian Securities Administrators' National Instrument 51-101 and the Canadian Oil and Gas Evaluation Handbook. Refer to "Oil, Natural Gas and Bitumen Reserves and Resources" in the Company's Annual Information Form dated March 17, 2011 for the year ended December 31, 2010 and the Company's Annual Information Form dated March 19, 2010 for the year ended December 31, 2009.}
⁽⁸⁾	^{10 percent present value of future net revenue before taxes. Future net revenues associated with reserves and resources do not necessarily represent fair market value.}

GENERAL

Connacher is in the tenth year of its run on the Canadian crude oil and natural gas scene. Since 2004 current management has executed an oil sands development strategy, converting a junior company with a very modest asset base into a meaningful producer with a substantial reserve backing. Since that time, the company has expanded aggressively, established itself as a significant independent player in the Canadian oil sands industry, recruited a strong cast of dedicated and talented people to manage the diverse business affairs of the Company and has seen its enterprise value grow from virtually zero to in excess of $1.5 billion. Our underlying pre-tax and after-tax net asset value is a significant multiple of our current market valuation. As we accomplish our objectives, grow our production with reliability and broaden our horizons through the application of exciting new technological innovations underway, in the oil sands and in conventional crude oil, we believe this value gap will diminish and our accomplishments will be more clearly acknowledged in capital markets to the benefit of our shareholders and other stakeholders.

REVIEW OF 2010

Connacher made significant strides during 2010. While production grew considerably with improved reliability by year end, the year was not without its challenges, especially during the summer months when unreliable power supplies adversely impacted our operating results at Pod One, our first SAGD oil sands project at Great Divide in north-eastern Alberta. Power interruptions, collateral damage to many of our electrical submersible pumps and a resultant erratic steam injection regime limited our ability to achieve all of our 2010 production objectives.

During the year, with the startup of Algar, the activation of our 13.1 megawatt natural gas-fired electrical co-generation facility ("cogen") and the visibility of further improvements to the regional grid by the regional power supplier, we believe stable power supplies will now be available. In fact, since September 2010 we have not experienced meaningful or sustained interruptions in the supply of electricity for our two SAGD projects. This augers well for stable operating conditions in 2011 and beyond. We are undaunted by these past events, are more experienced and expect to solve any new challenges that will undoubtedly arise. We are already moving forward with confidence to achieve our goals and objectives in 2011.

Reserve Growth

We conducted a very successful exploration program on our oil sands properties during the first quarter of 2010, drilling a total of 81 gross (74.5 net) core holes, largely on our 100 percent-owned Great Divide acreage. After record production, we increased our 2P reserves by 31 percent to over half a billion boe, almost all crude oil. We have one of the largest crude oil reserve bases among independent public oil companies in Canada and are recognized as being highly-leveraged to crude oil price movements. On a proved and probable or 2P basis, we replaced our 2010 production per boe over thirty times, a very high level of reserve replacement. We have an enviable long reserve life index, positioning the Company to participate in strong crude oil markets for many years. Over time, as we accelerate our growth through further development projects at Great Divide, this reserve life index will compress as we increase our daily production to much higher levels. This will enable us to generate significant levels of sustainable internally-generated cash flow for many years, thereby increasing our self-reliance and capacity to fund future activity and to discharge long term indebtedness, which we will use prudently alongside internally generated funds and other available capital to finance our growth expenditures on our long-life assets.

Additionally, including successful results at Halfway Creek (Hangingstone), where we own a 50 percent working interest in 38 sections of oil sands leases in the region, we augmented our 2P best estimate contingent resources by over 80 million barrels to end 2010 with 221 million barrels of bitumen, an increase of 63 percent over year-end 2009 levels. We are well positioned for continuing reserve and resource growth in the oil sands having only evaluated approximately 15 percent of our lands through core hole drilling. Our year-end 2010 reserve and resource estimates were prepared by GLJ, independent reserve evaluators. We anticipate continuing to evaluate and develop our oil sands properties with a view to further developments towards our longer-term goal of reaching approximately 70,000 bbl/d from our lands, based on our internal assessment, which parallels that of GLJ.

Our 2011 core hole drilling and three dimensional seismic program is nearing completion and was focused on further assessment of our Divide and Thornbury properties. Results of this winter's drilling will be included in subsequent independent reserve reports.

Algar Completed and Onstream

Our major accomplishment in 2010 was the successful completion and startup of Algar, our second SAGD project, which is situated a short distance east of Pod One but still proximate to Highway 63, the main transportation corridor in the region. Algar is connected to the trucking terminal at Pod One by means of transfer lines. The trucking terminal was also expanded in 2010 to enable handling of approximately 26,000 bbl/d of diluted bitumen ("dilbit") production from the two projects and also to receive the diluent we require. We continue to truck our dilbit to market, although more recently we have also accessed rail lines to reach new markets with attractive pricing opportunities.

Algar was completed on time and under budget in April 2010. We commissioned the project immediately thereafter, commenced steam circulation in late May 2010, initiated full SAGD production in August 2010 and experienced a very acceptable rampup of production by year end 2010. We commenced recording operating results ("commerciality") from Algar effective October 1, 2010, including the full expensing of interest on long term debt incurred to construct the facility. Readers will recall Algar has been designed to facilitate future brownfield expansion, once we secure regulatory approvals for our anticipated Great Divide Expansion Project, together with acceptance of our Environmental Impact Assessment ("EIA"). This application was also prepared and submitted during 2010. Approval might occur before year-end 2011, although we do not anticipate making a final decision on the scope of our expansion or the source and structure of related financial arrangements until late 2011 or possibly 2012, depending in part on the status of our existing operations, capital market conditions, the outcome of possible discussions with joint venture candidates and other related matters, including costing. In the interim, we are hard at work on engineering, design and the costing process.

The good news for Connacher is that we have already established the reserve backing for this anticipated expansion, so we have materially derisked our outlook as a consequence. As part of this process, we will also evaluate whether it is prudent to moderate our rate of expansion by building two 12,000 bbl/d projects at Algar or alternatively whether, under appropriate circumstances, it would be more advantageous to proceed with one 24,000 bbl/d expansion, to achieve scale economies. Given our modular approach and sequential expansion strategy of the past, we are most favourably positioned to capitalize on key learnings from existing operations, while still able to introduce new innovations aimed at streamlining the SAGD process, as it is applied to bitumen recovery in the oil sands. While SAGD has obviously passed the "commerciality" test during the past decade, it is inevitable it will undergo various and advantageous technological advances in the future.

Innovation Will Accelerate in 2011

We are very much engaged in the process of SAGD innovation and we will continue to apply new techniques in 2011 and beyond to advance well productivity and recovery factors. Among the innovations Connacher has applied or anticipates introducing in 2011 is the continued use of electrical submersible pumps ("ESP" or "ESPs"), methane coinjection, SAGD plus solvent, which will be introduced at Algar later this year and other operating procedures. We were the first company worldwide to install a high temperature ESP at Pod One in 2010. We may now be able to conduct mini-turnarounds on certain plant components "on the fly" at Pod One to minimize downtime and the associated impact of having to cool down the entire operation before maintenance is undertaken. Connacher is at the leading edge of technological advances, which will serve us well in future years.

Cogen Built and Operative

In 2010, we also completed the Algar cogen facility, again on time and under budget. We have developed an enviable record of field construction in the difficult physical environment we encounter in our area of operation. We are gratified some of our competitors follow suit by doing things "the Connacher way." Once the regional power provider completes construction of a new power substation at Great Divide later in 2011, surplus electrical power from the Algar cogen will be directed to Pod One, thus reducing much of that project's historical reliance on the third party regional power grid.

Conventional Property Rationalization - Accelerated Liquidity

In 2010, we completed a strategic review of our operations and embarked on a program to rationalize our non-core conventional asset base. We sold our legacy but very mature Battrum, Saskatchewan crude oil producing property for an attractive price of $57.5 million, prior to customary closing adjustments. We recently entered into an agreement to also sell our Marten Creek/Randall natural gas property in north central Alberta for cash proceeds of $22.5 million, prior to customary closing adjustments, with an effective date of March 1, 2011 and an anticipated closing on April 29, 2011. With plentiful supplies of cheap natural gas available to us for our operations and because weak economics discouraged continuing capital investment in these assets to maintain productivity, the rationale of needing to be physically hedged with this type of short-life, dry natural gas production was diminished. Gross proceeds of $80 million from the two transactions will be added to working capital and will accordingly reduce our net debt.

Petrolifera to Be Acquired - Prospect of More Cash to Strengthen Balance Sheet

We recently supported a decision by the Board of Directors of Petrolifera Petroleum Limited ("Petrolifera") to enter into an arrangement agreement with Gran Tierra Energy Inc. ("Gran Tierra Energy") whereby, pursuant to the terms of a Plan of Arrangement, Connacher will receive Gran Tierra Energy common shares and share purchase warrants with an approximate market value of $30 million, in exchange for its holdings in Petrolifera, if the transaction secures necessary approvals, including a favourable vote of shareholders scheduled for March 17, 2011. While the share and warrant exchange resulted in Connacher recording a book loss in 2010 due to the book value of its investment and non-cash equity in the earnings of Petrolifera, which have been accumulated since the company's inception, we expect to realize a gain on a cash basis. It is anticipated Connacher will monetize its interest in Gran Tierra Energy in the foreseeable future and further strengthen its cash balances, strengthen its liquidity and again further reduce its net debt.

Exciting New Conventional Light Gravity Crude Oil Resource Project

In 2010, we embarked on a new land acquisition and drilling program in the general Three Hills/Twining area of central Alberta, in close proximity to existing core area conventional crude oil operations. This followed an extensive and detailed "resource project" approach to this endeavour prior to initiation. Our goal was to secure a significant inventory of potential locations which, if early drilling was successful, would give us a project in scope and size similar to our oil sand projects, but with a focus on high netback light gravity crude oil which could be exploited aggressively, using modern horizontal drilling technology, with which we have extensive experience and newly developed multi-frac technology.

We are pleased to report we have acquired over 30 sections of petroleum and natural gas ("P&NG") rights in the area; have drilled our first three wells, have one on production, one about to go on production and one well awaiting completion of a rapid matrix frac, which we redesigned to more effectively impact the Pekisko Formation, our primary objective. Once we have reliable data, we will provide more details on the actual well results. Our landholdings could permit the drilling of 100 or more wells on this resource play, with the obvious potential of a meaningful impact on our production, revenue and cash flow. This could occur in a much more compressed time frame than is characteristic of our oil sands projects, which often require several years to reach fruition. Needless to say, we are excited about this initiative, which we see as complementary to our longer term commitment to the development of our oil sands assets, by providing Connacher with the potential of much increased internally generated cash flow in a short time frame to assist in financing the Company's overall growth, while simultaneously allowing us to capitalize on our in-house expertise in horizontal drilling and project management.

Downstream Division Had an Excellent Year

Our downstream division in Montana had an excellent year. We experienced high levels of throughput, exceeding rated capacity. The availability of widened heavy crude oil price differentials helped improve financial results which, for Connacher, offset a good portion of the adverse impact these conditions usually have on upstream results. Our integrated strategy is working. Our refining margin was healthy.

During 2010, we continued our program to improve the reach of our business by expanding markets, especially into Alberta. While poor weather limited asphalt sales in the summer months, prices were near record levels and margins for all products were much healthier, as the Montana economy rebounded from the 2009 recession. We more closely aligned our overall marketing initiatives with our upstream and downstream operations, which we believe will serve us well in the more challenging market environment arising from higher oil prices, pipeline disruptions and other dislocations which have evolved in late 2010 and early 2011.

Review of 2010 Operating and Financial Results

During 2010, we increased our production levels by 16 percent. Bitumen production rose 32 percent to 8,299 bbl/d and reached 13,238 bbl/d in the fourth quarter 2010 ("Q4 2010"), reflecting the impact of the Algar rampup and continued improvement with increased stability of production levels at Pod One. Bitumen sales in 2010 averaged 8,206 bbl/d; the difference from reported production levels is dilbit inventory held in tanks and trucks. Our December bitumen production rate was 14,004 bbl/d and we continue to provide full year guidance of between 14,500 bbl/d and 16,500 bbl/d for bitumen production in 2011.

Our conventional production declined 18 percent to 2,400 boe/d in 2010 reflecting lower levels of capital invested in our mature, non-core producing properties. Our focus in 2010 was harvesting cash from these properties, which we achieved through previously-discussed sales and in identifying new unconventional light gravity high netback crude oil resource opportunities.

We recorded excellent growth in revenue during 2010, as the economy and crude oil prices recovered from the collapse of 2008/2009. Our adjusted earnings before interest, taxes and amortization ("EBITDA") rose sharply to $92 million, which exceeded our full year 2010 estimate provided to the market in November of last year. Refer to our attached Management's Discussion and Analysis ("MD&A") for a more detailed discussion in this regard.

Our cash flow from operations, before non-cash working capital adjustments, ("cash flow") increased 195 percent to $36.9 million, compared to $12.5 million in 2009. After provision for higher interest charges and deduction of various non-cash items, including non-cash impairment provision for our holdings in Petrolifera and significantly lower foreign exchange gains in 2010 compared to last year, we recorded a loss of $38.8 million, compared to earnings of $26.2 million last year.

At December 31, 2010, we had cash balances of $19.5 million, working capital of $65 million and long term debt of $844 million, with no current maturities and no short-term debt. We had available bank credit lines of $44 million, as there were $6 million of outstanding letters of credit which had been issued by the Company at year end 2010. During the year, we successfully renegotiated this bank credit facility, extending term, lowering related costs and eliminating a restrictive covenant. Subsequent to year end we sold Battrum for cash, which was added to working capital, thereby reducing net debt. The potential sale of Marten Creek/Randall, scheduled to close on April 29, 2011 and eventual monetizing of marketable securities to be received in exchange for our common shares and share purchase warrants of Petrolifera at a scheduled closing on or about March 18, 2011, could further augment corporate liquidity.

Total capital expenditures during the year were $248 million, primarily for the completion of the Algar project and related cogen plant. Activity was financed from cash flow and cash balances. Details of our overall capital program are contained in the attached MD&A.

Fourth Quarter 2010

Production of bitumen in Q4 2010 averaged 13,238 bbl/d, 96 percent above Q3 2010 levels and 60 percent above full year 2010 production levels of 8,299 bbl/d. Bitumen sales in Q4 2010 averaged 12,868 bbl/d, the difference from reported production levels representing dilbit inventory held in tanks and trucks. Bitumen production at Pod One in Q4 2010 was 7,247 bbl/d, the highest quarterly production level recorded at that facility since startup in late 2007. Bitumen production in the month of December was 14,004 bbl/d, of which 7,448 bbl/d was at Pod One, the highest monthly production level since December 2009. Total Q4 2010 production was 15,498 boe/d, 45 percent above full year 2010 levels and 78 percent above Q4 2009 levels. These results auger well for our 2011 production outlook.

Revenue in Q4 2010 was $159 million, an increase of 44 percent over Q4 2009. Cash flow was markedly improved in Q4 2010 at $9.1 million, compared to negative cash flow recorded in Q4 2009. Capital expenditures were a modest $20.6 million in Q4 2010, reflecting the successful completion of Algar earlier in the year, followed by its subsequent successful startup. A net loss impacted by what have become normal year-end adjustments for non-cash items, including a non-cash impairment of our carrying cost for our investment in Petrolifera, resulted in a reported loss of $19 million for the quarter, larger than that recorded in 2009.

Balance sheet metrics are included in our review of the full year.

OUTLOOK

Connacher has entered 2011 with confidence and enthusiasm. Our significant achievements of 2010 set the stage for more sustained growth and improved production reliability during the current year. Difficult marketing conditions, which have prevailed since the Enbridge crude oil pipeline ruptures occurred in the third and fourth quarters of 2010, have resulted in wider differentials early in 2011, although these are not expected to persist. Fortunately for Connacher, adverse upstream developments are recaptured to some extent in our profitable downstream refining and marketing business. We are also adapting to bottleneck and North American market access issues through innovative solutions, including the use of rail to penetrate and secure new markets offering the potential of more attractive netback pricing at the Great Divide plant gate.

We have retained our guidance levels for bitumen production at between 14,500 and 16,500 bbl/d at Great Divide for 2011. Combined with conventional production, adjusted for recent sales and with a modest provision for new production from the three wells at our new resource play at Three Hills/Twining, expressed on an oil equivalent basis, we anticipate full year production will range between 15,500 boe/d and 17,900 boe/d. This would compare quite favourably with 2010 results and may result in an improvement in successive and overall financial results during 2011.

Following a recent review, our capital budget for 2011 has been expanded from $104 million to $122 million. We have increased our proposed outlays for land acquisition on another unconventional resource play, using an identical and proven "project" approach, but focusing on a different reservoir. The other significant increase will be to expand the scope for our diluent recovery project at Pod One, designed to quickly improve economic returns as it will serve to reduce our diluent blending requirements at Pod One. As was the case in November 2010, approximately one half of our new capital outlays will be growth oriented with the balance for plant maintenance or performance improvement. We are particularly excited about the 2011 introduction of SAGD plus solvent at one well pad at Algar, scheduled for the second half of this year. This project has already been approved by regulators. Connacher is also able to confirm that these capital outlays can be financed from available cash and anticipated cash flow, while we continue to be positioned to meet all outstanding financial obligations.

Should we decide at a later date to accelerate spending at Three Hills/Twining because of successful and sustainable results, we do anticipate utilizing a portion of funds in working capital from recent property sales. This funding will be supplemented by project cash flow to allow us, over several years, to drill in excess of our one hundred new locations we have identified on 100 percent-owned lands. The Battrum property sale proceeds were in excess of our initial expectations. Combined with the prospective cash receipts from the agreed sale of Marten Creek/Randall and prospectively from the eventual monetization of the Gran Tierra Energy securities we anticipate receiving from the sale of Petrolifera, further expansion of this exciting new light oil drilling activity at Three Hills/Twining can be concluded without equity dilution. Buoyed by the attraction of high netback production of light gravity crude oil, we can assure our shareholders that the acceleration of drilling and construction of new and expanded facilities in the region will only occur if we are satisfied, after review of reliable data, that we have results which would warrant a further adjustment to our capital budget. This would be a nice challenge to encounter and to reiterate, we are very encouraged by results to date.

On balance, we believe we will finish 2011 with a strong level of cash balances and a stronger and more diversified asset base with expanded productive capacity.

Using a combination of WTI based financial swaps and collars, our 2011 hedging program provides solid protection against a steep downside correction in crude oil prices, albeit such hedges do moderate the beneficial participation in commodity price increases.

GENERAL

One of our directors, Stewart McGregor, has indicated he will not stand as a nominee for re-election to the Board of Directors at our next Annual Meeting. He has served as a director on our Board, on several committees over a number of years and more recently as a liaison with management in the position of Lead Director. We thank him for his contribution to the growth and development of Connacher. A new Lead Director may be selected from among the newly elected directors after the Annual and Special General Meeting, scheduled to be held in Calgary on May 17, 2011.

Connacher Oil and Gas Limited is a Calgary-based exploration, development and production company active in the production and sale of bitumen, crude oil, natural gas and natural gas liquids. Our principal assets are our holdings in the Great Divide oil sands project in northern Alberta. We also hold conventional light gravity crude oil and natural gas properties in Alberta. A wholly-owned subsidiary operates a 9,500 bbl/d heavy crude oil refinery in Great Falls, Montana and we also own a valuable equity stake in Petrolifera Petroleum Limited, a public Canadian company active in the oil business in South America.

Forward Looking Information:

This press release contains forward looking information including but not limited to development of additional oil sands reserves (including the expansion of bitumen productive capacity at Great Divide and the anticipated timing of required regulatory approvals associated therewith), expected timing to initiate construction for the Great Divide expansion project, expectations of future production, anticipated capital expenditures, anticipated sources of funding for capital expenditures and current financial obligations, future liquidity, future development and exploration activities, future heavy oil differentials, utilization of alternative financial derivative strategies to protect Connacher's cash flow, joint venture arrangements, improved stability of power at Pod One and Algar, the proposed sale of natural gas properties at Marten Creek/Randall and the use of proceeds from the Marten Creek/Randall and Battrum dispositions, the anticipated timing of introducing SAGD plus solvent at one of the Algar well pads, new innovations to be introduced in 2011, the proposed acquisition of Petrolifera by Gran Tierra Energy and the anticipated monetization of Connacher's interest in Gran Tierra Energy.

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 Marten Creek/Randall properties and the acquisition of Petrolifera by Gran Tierra Energy.

Information relating to "reserves" and "future net revenues" associated therewith are deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future to achieve the future net revenue calculated in accordance with certain assumptions. The assumptions relating to the reserves and associated future net revenues reported herein are contained in the report of GLJ Petroleum Consultants Ltd on the reserves, resources and future net revenue of the Corporation as at December 31, 2010 (the "GLJ 2010 Report") and are summarized in Connacher's AIF. Future net revenues associated with reserves do not necessarily represent fair market value.

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. Reserve replacement is calculated by dividing the total net additions to 2P gross reserves on a boe basis by the total gross production for the year on a boe basis, as contained in the GLJ 2010 Report.

In addition, reported average 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 the production of bitumen.

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 March 17, 2011 and should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2010 and the audited consolidated financial statements and MD&A for the year ended December 31, 2009. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP") and are presented in Canadian dollars (C$). MD&A provides management's view of the financial condition of the company and the results of its operations for the reporting periods.

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 the company's website at www.connacheroil.com.

BACKGROUND INFORMATION AND BUSINESS STRATEGY

Headquartered in Calgary, Alberta, Canada, Connacher is a growing integrated crude oil and natural gas company with a focus on producing bitumen and expanding its in-situ oil sands projects located near Fort McMurray, Alberta. Connacher also owns and operates conventional crude oil and natural gas production in Alberta and owns and operates a heavy oil refinery in Great Falls, Montana. Connacher also owns 26.9 million common shares representing 18.5 percent of Petrolifera Petroleum Limited ("Petrolifera") and 6.8 million Petrolifera share purchase warrants. Petrolifera is engaged in petroleum and natural gas exploration, development and production activities in South America. Petrolifera is in the process of being acquired by Gran Tierra Energy Inc. pursuant to a plan of arrangement which is anticipated to close on or about March 18, 2011. Connacher will then become a shareholder of Gran Tierra Energy Inc., a listed public company. These shares may be monetized by Connacher in due course.

The company's business is conducted through two major business segments - upstream in Canada and downstream in the United States of America ("USA") through its wholly owned subsidiary, Montana Refining Company, Inc. (''MRCI''). Upstream includes exploration, development and production of bitumen, crude oil, natural gas and natural gas liquids. Downstream includes refining of crude oil to produce and market gasoline, jet fuel, diesel fuels, asphalt and ancillary products.

Connacher's overall objective is to create shareholder value. Specific goals that contribute to the achievement of this objective and the innovative and committed strategy in pursuit of these goals are tabulated below:

OBJECTIVES

Optimize bitumen production at Great Divide
Position the company to achieve bitumen productive capacity of 44,000 bbl/d, following receipt of regulatory approval anticipated in late 2011
Continue to grow bitumen and conventional reserves and resources
Introduce innovative solutions to enhance optimization objectives

STRATEGY

Own and operate large working interests in oil and gas properties
Focus on projects exhibiting characteristics of expandability, repeatability and sustainability
Mitigate and manage the risks of a smaller company in the oil sands with an integrated approach
Operate with financial discipline, maintain a high level of liquidity and prefund major capital programs

CONSOLIDATED FINANCIAL AND OPERATING REVIEW

SELECT ANNUAL INFORMATION


($000 except per share amounts)		2010	2009	2008
Revenue, net of royalties		$574,302	$428,214	$636,734
Cash flow ⁽¹⁾		36,884	12,522	54,817
	Cash flow per share - basic and diluted ⁽¹⁾	0.09	0.04	0.26
Net earnings (loss)		(38,798)	26,158	(26,603)
	Net earnings (loss) per share - basic and diluted	(0.09)	0.08	(0.13)
Additions to property, plant and equipment		247,978	322,064	351,736
Total assets		1,683,998	1,741,866	1,431,675
Long-term debt		$843,601	$876,181	$778,732

₍₁₎ _{Cash flow is a non-GAAP measure, which is defined in the Advisory section of the MD&A.}

In 2010, higher revenue in both upstream and downstream segments contributed to a 34 percent increase in total net revenue compared to 2009. Upstream revenue increased by 41 percent, primarily as result of a 31 percent increase in bitumen sales volume (8,206 bbl/d in 2010 compared to 6,274 bbl/d in 2009) as a result of the completion of the construction of the company's second oil sands project, Algar and the inclusion of its operating results from October 1, 2010. In addition, higher weighted average upstream sales prices ($44.13/boe in 2010 compared to $37.81/boe in 2009) contributed to increased revenue in 2010 compared to 2009. This was primarily due to higher benchmark crude oil prices, partially offset by wider heavy crude oil differentials resulting from pipeline disruptions and other factors. Downstream revenue increased by 24 percent in 2010, compared to 2009, due to a 10 percent increase in the sales volume of refined petroleum products (10,080 bbl/d in 2010 compared to 9,188 bbl/d in 2009) due to increased crude oil refining volumes. We experienced a 15 percent increase in the weighted average sales price of refined petroleum products sold ($88.68/bbl in 2010 compared to $77.05 per bbl in 2009) due to higher benchmark prices and from sales of our specialty asphalt products under favorable price arrangements.

In 2009, revenue decreased by 33 percent compared to 2008. Although upstream production and sales volumes increased in 2009, the impact of reduced market pricing for crude oil and refined petroleum products, caused by the economic downturn in 2009 and lower volumes of refined petroleum products produced and sold resulted in lower revenues in 2009 compared to 2008.

In 2010, cash flow increased 195 percent compared to levels achieved in 2009, primarily due to higher upstream and downstream netbacks and lower realized risk management contract losses, partially offset by higher finance charges and lower realized foreign exchange gains.

Lower cash flow in 2009 compared to 2008 was due to lower upstream and downstream selling prices, higher realized risk management contract losses and higher finance charges.

Notwithstanding higher upstream and downstream cash flow, the company incurred a net loss of $38.8 million in 2010 compared to net earnings of $26.2 million in 2009. This was primarily due to lower unrealized foreign exchange gains, higher depletion, higher finance charges and an impairment charge related to our equity investment in Petrolifera in 2010.

In 2009, net earnings were higher than in 2008 primarily due to higher unrealized foreign exchange gains.

The company incurred capital expenditures of $248 million in 2010 compared to $322 million in 2009, as our main capital project, Algar, was completed in 2010.

A slight decrease in total assets in 2010 was primarily due to a decrease in cash balances. Higher cash balances in 2009 compared to 2010 were primarily due to financings completed in late 2009.

Total assets increased as at December 31, 2009 compared to December 31, 2008 as a result of capital additions to our oil sands properties.

Although the face value of our long-term debt did not change in 2010, its carrying value decreased slightly in 2010 due to the effect of translation to a Canadian dollar equivalent of our US-dollar denominated long-term debt, at a stronger Canadian dollar exchange rate as at December 31, 2010 compared to its level at December 31, 2009. The majority of the company's long-term debt is denominated in US dollars.

The increase in long-term debt at December 31, 2009 compared to December 31, 2008 was primarily due to the issuance of First Lien Senior Notes in 2009.

SELECT QUARTERLY INFORMATION


($000 except per share amounts)		Q1 2009	Q2 2009	Q3 2009	Q4 2009	Q1 2010	Q2 2010	Q3 2010	Q4 2010
Revenues, net of royalties		$62,602	$101,529	$153,798	$110,285	$119,602	$142,975	$152,391	$159,334
Cash flow ⁽¹⁾		(4,692)	9,570	10,410	(2,766)	3,948	8,668	15,178	9,090
	Cash flow per share - Basic ⁽¹⁾	(0.02)	0.04	0.03	(0.07)	0.01	0.02	0.04	0.02
	Cash flow per share - Diluted ⁽¹⁾	(0.02)	0.03	0.03	(0.07)	0.01	0.02	0.04	0.02
Net earnings (loss)		(46,844)	39,966	47,767	(14,731)	5,546	(33,126)	7,946	(19,164)
	Net earnings (loss) per share - Basic	(0.22)	0.15	0.12	(0.03)	0.01	(0.08)	0.02	(0.04)
	Net earnings (loss) per share - Diluted	(0.22)	0.14	0.11	(0.03)	0.01	(0.08)	0.02	(0.04)
Additions to property, plant and equipment		$64,255	$40,236	$100,727	$116,846	$118,272	$59,316	$49,842	$20,548

₍₁₎ _{Cash flow is a non-GAAP measure, which is defined in the Advisory section of the MD&A.}

In the fourth quarter 2010 ("Q4 2010"), higher revenue in both upstream and downstream segments contributed to a 44 percent increase in revenue compared to Q4 2009. Upstream revenue increased in Q4 2010 compared to Q4 2009 due to higher sales volume (15,128 boe/d in Q4 2010 compared to 8,690 boe/d in Q4 2009), resulting from the completion of the construction of Algar and inclusion of its operating results from October 1, 2010. Downstream revenues increased in Q4 2010 compared to Q4 2009 primarily due to increase in the weighted average sales price of refined products ($94.47/bbl in Q4 2010 compared to $71.73/bbl in Q4 2009), resulting from generally higher benchmark prices and also due to increased throughput resulting from improved reliability.

In Q4 2010, cash flow was significantly higher compared to Q4 2009, primarily due to higher upstream and downstream pricing and sales volumes, as noted above.

Despite higher upstream and downstream netbacks, the company incurred a net loss of $19.2 million in Q4 2010 compared to net loss of $14.7 million in Q4 2009 primarily due to higher non-cash charges for risk management contracts, depletion and an impairment charge relating to our investment in Petrolifera.

The company had capital expenditures of $20.5 million in Q4 2010, compared to $117 million in Q4 2009. A significant portion of capital expenditures in Q4 2009 were incurred at our oil sands properties for construction of Algar, which was completed earlier in 2010.

SEGMENTED FINANCIAL AND OPERATING REVIEW

UPSTREAM - CANADA

COMMODITY PRICES AND RISK MANAGEMENT


	Three months ended December 31			Years ended December 31
	2010	2009	%	2010	2009	%
Average benchmark prices
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing	$85.16	$76.03	12	$79.51	$61.99	28
Natural Gas (Alberta spot) C$/Mcf at AECO	3.61	4.62	(22)	3.98	3.98	-
Western Canadian Select (WCS) C$/bbl	67.87	67.66	-	67.23	58.66	15
Differential - WTI/WCS C$/bbl	18.35	12.82	43	14.69	11.89	24
Average realized prices ⁽¹⁾
Bitumen - C$/bbl	45.08	48.23	(7)	45.65	39.39	16
Crude oil - C$/bbl	66.72	67.24	(1)	65.63	54.61	20
Natural gas - C$/Mcf	3.44	4.34	(21)	3.90	3.90	-
Weighted average sales price - C$/boe ⁽²⁾	$44.09	45.76	(4)	$44.13	37.81	17

⁽¹⁾ ^{Before royalties and risk management contract gains or losses and after applicable diluent and transportation costs divided by actual sales volumes.}

⁽²⁾ ^{Boes 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".

In 2010, higher benchmark crude oil prices resulted in higher realized average selling prices for bitumen and crude oil compared to 2009. The increase was partially offset by wider heavy oil differentials and a stronger Canadian dollar relative to the U.S. dollar. Realized natural gas prices in 2010 were in line with benchmark prices.

In Q4 2010, the heavy oil differential discount widened due to Enbridge pipeline disruptions in the USA that limited the transportation capacity of heavy crude products, resulting in lower realized crude oil and bitumen selling prices compared to Q4 2009. Lower AECO natural gas prices in Q4 2010 resulted in lower realized selling prices for natural gas in Q4 2010 compared to Q4 2009.

Diluted bitumen ("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, at either 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. 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 revenue in 2010 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; and
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.

Subsequent to December 31, 2010, the company entered in the following risk management contract:

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 $13.6 million and $1.7 million, respectively, in 2010 (2009 - unrealized and realized losses of $4.5 million and $20.6 million, respectively) on the above risk management contracts.

PRODUCTION AND SALES VOLUMES ⁽¹⁾


Years ended December 31	2010	2009	% Change
Dilbit sales - bbl/d ⁽²⁾	11,012	8,493	30
Diluent used - bbl/d ⁽²⁾	(2,806)	(2,219)	26
Bitumen sold ⁽²⁾	8,206	6,274	31
Change in inventory - bbl/d	93	-	100
Bitumen produced - bbl/d ⁽²⁾	8,299	6,274	32
Crude oil produced and sold - bbl/d	883	1,041	(15)
Natural gas produced and sold - Mcf/d	9,100	11,407	(20)
Total production volumes - boe/d	10,699	9,216	16
Total sales volumes- boe/d ⁽³⁾	10,606	9,216	15

₍₁₎	_{Effective October 1, 2010, the capitalized costs relating to the company's second oil sands project, Algar, were added to the full cost pool for depletion and ceiling test calculations 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. Daily production and sales averages are based on a total calendar year.}
₍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 32 percent in 2010 compared to 2009, primarily due to the completion of the company's second oil sands project, Algar. In late September 2010, the company completed the conversion of a majority of Algar's well pairs to full-scale steam-assisted gravity drainage ("SAGD") bitumen production and accordingly processed increasing levels of bitumen through the surface plant. Consequently, Algar production was included in the above volumes from October 1, 2010. Algar average production was 1,510 bbl/d in 2010, as incorporated above on a calendar year basis.

At Pod One, the company's first oil sands project, production for the year 2010 averaged 6,789 bbl/d compared to 6,274 bbl/d in 2009, representing an increase of eight percent. Production was affected by evaporator performance issues and by numerous periodic power outages and related pump failures in the summer of 2010. Operational reliability at Pod One and Algar has improved subsequent to the activation of a newly constructed cogeneration facility at Algar in early September 2010 which also reduced power demands on the regional grid.

In 2010, conventional crude oil and natural gas production and sales volumes decreased by 15 percent and 20 percent respectively, compared to 2009, primarily due to natural reservoir declines resulting from reduced capital spending on conventional properties.

UPSTREAM REVENUE ⁽¹⁾


	Year ended December 31, 2010					Year ended December 31, 2009
($ 000 except per unit amounts)	Oil sands	Crude oil	Natural gas	Total	Oil sands	Crude oil	Natural gas	Total
Gross upstream revenues ⁽²⁾	$247,187	$21,229	$12,942	$281,358	$162,640	$21,070	$16,232	$199,942
Diluent costs ⁽³⁾	(91,644)	-	-	(91,644)	(60,407)	-	-	(60,407)
Transportation costs	(18,806)	(66)	(1)	(18,873)	(12,031)	(321)	(3)	(12,355)
Revenues	$136,737	$21,163	$12,941	$170,841	$90,202	$20,749	$16,229	$127,180
Price ($ per bbl / Mcf / boe)⁽⁴⁾	$45.65	$65.63	$3.90	$44.13	$39.39	$54.61	$3.90	$37.81

₍₁₎	_{Effective October 1, 2010, the capitalized costs relating to the company's second oil sands project, Algar, were added to the full cost pool for depletion and ceiling test calculations 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 $14.3 million from our subsidiary, MRCI in 2010 and $7 million in 2009 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 41 percent in 2010 compared to 2009, primarily due to higher bitumen revenue, partially offset by lower natural gas revenue. Higher bitumen revenue in 2010 was due to higher bitumen sales volumes at higher realized commodity selling prices.

Diluent used represented approximately 25 percent of the dilbit barrel sold in 2010 (26 percent in 2009). Total diluent costs increased by 52 percent in 2010 compared to 2009, primarily due to the 31 percent increase in bitumen sales volume for the year and a 20 percent increase in diluent pricing, which was driven by higher energy prices in 2010.

Transportation costs are costs to transport dilbit and crude oil to customers. Transportation costs increased by 53 percent in 2010 compared to 2009, due to the 31 percent increase in bitumen sales volumes, higher trucking costs and increased sales travel distances to markets in 2010 due to the Enbridge pipeline disruptions. In 2009 and 2010, all of our dilbit sales were transported by trucks. We continue to evaluate the merits of a sales pipeline as a transportation alternative. Additionally, we recently commenced railing some dilbit to new USA markets to alleviate downstream related barriers to the overall production ramp-up at Great Divide and to access new sales markets that are less tied to current WCS pricing levels. Although this will result in higher transportation costs and higher inventory levels and related carrying costs, we anticipate higher netbacks may be achieved.

ROYALTIES ⁽¹⁾


	Year ended December 31, 2010				Year ended December 31, 2009
($ 000 except per unit amounts)	Oil sands	Crude oil	Natural gas	Total	Oil sands	Crude oil	Natural gas	Total
Royalties	$5,440	$5,713	$172	$11,325	$2,370	$4,990	$623	$7,983
Royalties ($ per bbl / Mcf / boe) ⁽²⁾	$1.82	$17.72	$0.05	$2.93	$1.03	$13.13	$0.15	$2.37

₍₁₎

_{Effective October 1, 2010, the capitalized costs relating to the company's second oil sands project, Algar, were added to the full cost pool for depletion and ceiling test calculations 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 2010 increased by 42 percent compared to 2009, primarily due to higher oil prices. This was reflected in higher per unit royalty costs for bitumen and crude oil. The reduction in the 2010 per unit royalty cost for natural gas, compared to the 2009, reflected Alberta gas cost allowance recoveries in conjunction with lower natural gas prices.

Our oil sands royalties are computed on a "gross basis" (before recovering allowed capital and other costs) at one percent of gross bitumen revenue when oil trades at or below the WTI equivalency of C$55.00 per barrel, increasing to nine percent when the WTI equivalency is at or above C$120.00 per barrel. After payout of allowed capital and other costs, oil sands royalties are also to be computed on a "net basis" (bitumen revenue less allowed operating and other costs) calculated at 25 percent when the WTI equivalency is less than or equal to C$55.00 per barrel, escalating to 40 percent, when the WTI equivalency is at or above C$120.00 per barrel. The oil sands royalty then payable would be the higher of the computed gross and net amounts. Based on recent bitumen selling prices and our internal analysis, a royalty payout position is not anticipated until 2015.

OPERATING COSTS ⁽¹⁾


	Year ended December 31, 2010				Years ended December 31, 2009
($ 000 except per unit amounts)	Oil sands	Crude oil	Natural gas	Total	Oil sands	Crude oil	Natural gas	Total
Operating costs	$60,344	$4,407	$5,403	$70,154	$42,980	$4,380	$9,407	$56,767
Operating costs ($ per bbl / Mcf / boe) ⁽²⁾	$20.15	$13.67	$1.63	$18.12	$18.77	$11.53	$2.26	$16.88

₍₁₎

₍₂₎

_{Per unit costs are calculated using operating costs divided by bitumen, crude oil and natural gas actual volumes sold.}

Total operating costs in 2010 were 24 percent higher than in 2009, primarily due to higher operating costs in our oil sands operations. Oil sands operating costs increased by 40 percent in 2010 compared to 2009 and by 7 percent on a per unit basis in 2010 compared to 2009.

The primary reason for the increase in total and per unit oil sands operating costs in 2010 compared to 2009 were costs associated with unplanned evaporator and treating system maintenance in the first quarter of 2010 combined with costs associated with numerous plant shut downs and start-ups resulting from an abnormally high occurrence of power failures experienced at Pod One in the summer of 2010. There was also collateral wear on down-hole pumps, necessitating some replacements earlier than anticipated. In September 2010, a 13.1 megawatt cogeneration facility at Algar was commissioned and commenced operations. This has resulted in stable and adequate power at Algar and helped increase power reliability at Pod One. The resultant reduction of grid-related power outages continues to improve production performance reliability at Pod One.

The completion of an electric substation by the regional power utility at Great Divide in the first half of 2011 is anticipated to provide additional power reliability for our oil sands operations as surplus power from the Algar Cogeneration facility will then be able to be directed to Pod One, reducing reliance on the third-party power grid. Additionally, the continued ramp-up of bitumen production at Algar in 2011 should spread our fixed operating costs over a larger production base, lowering unit operating costs.

The tables below summarize information related to our oil sands operating costs.


Years ended December 31	2010		2009
	($000)	%	($000)	%
Natural gas costs ⁽¹⁾	$18,142	30	$13,480	31
Other operating costs	42,202	70	29,500	69
Total oil sands operating costs	$60,344	100	$42,980	100

₍₁₎	_{Excluding risk management contract gains and losses. Includes natural gas consumed by boilers and other vessels at Great Divide.}

In 2010 the combined full year steam : oil ratio ("SOR") from Pod One and Algar was 4.3; in 2009, when only Pod One was in operation, it was 3.7. The 2009 and 2010 SORs reflect the initial steaming of new well pairs in each year (two new well pairs in each of 2009 and 2010 for Pod One and 16 new well pairs for Algar in 2010). It is a common SAGD practice to circulate steam into new wells for approximately 90 days before converting the wells to full SAGD production. During this steam circulation phase, minimal bitumen (oil) is produced and consequently, SORs are typically higher than experienced during the long-term production phase. As production ramps up from these new wells and as we apply additional enhanced recovery techniques, we anticipate lower SORs.

The company also recorded risk management contract losses of $1.3 million 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.

Conventional crude oil operating costs were slightly higher in 2010, due to additional expensed work-overs; on a per unit basis, they were higher primarily due to a significant fixed component and lower production volumes in 2010.

Natural gas operating costs were lower in 2010 due to improved operating efficiencies arising from capital investment in 2009, notwithstanding lower production volumes in 2010.

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


Year ended December 31, 2010	Oil sands $ 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⁾	$136,737	$45.65	$21,163	$65.63	$12,941	$3.90	$170,841	$44.13
Royalties	(5,440)	(1.82)	(5,713)	(17.72)	(172)	(0.05)	(11,325)	(2.93)
Operating costs	(60,344)	(20.15)	(4,407)	(13.67)	(5,403)	(1.63)	(70,154)	(18.12)
Netbacks ⁽³⁾	$70,953	$ 23.68	$11,043	$34.24	$7,366	$2.22	$89,362	$23.08

Year ended December 31, 2009	Oil sands $ 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⁾	$90,202	$39.39	$20,749	$54.61	$16,229	$3.90	$127,180	$37.81
Royalties	(2,370)	(1.03)	(4,990)	(13.13)	(623)	(0.15)	(7,983)	(2.37)
Operating costs	(42,980)	(18.77)	(4,380)	(11.53)	(9,407)	(2.26)	(56,767)	(16.88)
Netbacks ⁽³⁾	$44,852	$19.59	$11,379	$29.95	$6,199	$1.49	$62,430	$18.56

₍₁₎	_{Effective October 1, 2010, the capitalized costs relating to the company's second oil sands project, Algar, were added to the full cost pool for depletion and ceiling test calculations 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.}

Total upstream netbacks were 43 percent higher in 2010 compared to 2009 due to higher sales volumes and higher realized prices of bitumen and crude oil. Sales volumes of bitumen increased by 31 percent in 2010 compared to 2009, primarily due to new production at Algar. Bitumen and crude selling oil prices increased by 16 percent and 20 percent, respectively, in 2010 compared to 2009, consistent with higher benchmark oil prices.

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

COMMODITY PRICES AND RISK MANAGEMENT


	Three months ended December 31			Years ended December 31
	2010	2009	%	2010	2009	%
Average benchmark prices
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing	$85.16	$76.03	12	$79.51	$61.99	28
Average realized prices ⁽¹⁾
Gasoline - US$/bbl	88.35	75.51	17	87.55	69.16	27
Diesel - US$/bbl	107.82	83.98	28	95.03	71.42	33
Asphalt - US$/bbl	79.22	57.11	39	81.37	67.76	20
Jet fuel - US$/bbl	$105.18	$89.82	17	$96.55	$82.29	17

⁽¹⁾ ^{Before risk management contracts gains and losses and after transportation costs.}

Higher world prices for refined products in 2010 compared to 2009 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 December 31, 2010, MRCI has agreements to sell approximately 667,000 barrels of asphalt at a weighted average price approximating US$95.00 per barrel.

To mitigate some of the risk of reduced gasoline selling prices and margins, the company entered into a risk management contract to sell 2,000 bbl/d of gasoline at the calendar month average WTI price expressed in US$/bbl plus US$9.00/bbl for the period of April 1, 2010 to September 30, 2010. The contract expired on September 30, 2010 and resulted in a realized loss of $543,000 in 2010, which, has been separately reported.

REFINERY THROUGHPUT


Years ended December 31	2010	2009
Crude charged - bbl/d⁽¹⁾	9,693	7,820
Refinery production - bbl/d ⁽²⁾	10,704	8,797
Sales of refined petroleum products - bbl/d⁽³⁾	10,080	9,188
Refinery utilization ⁽⁴⁾	102%	82%

₍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 2010, the total sales volume of refined petroleum products increased by 10 percent compared to 2009 primarily due to the improved stability of refining operations subsequent to the completion of the ultra low sulphur diesel ("ULSD") project in 2009, our triennial plant turnaround in late 2009 and increased demand for refined petroleum products in 2010. A significant portion of our Refinery sales is derived from gasoline (4,500 bbl/d or 45%), diesel (1,617 bbl/d or 16%), jet fuel (693 bbl/d or 7%) and asphalt (2,971 bbl/d or 30%). Increases in gasoline, diesel and jet fuel sales volumes in 2010 were offset by a decrease in asphalt sales volumes, due to adverse weather conditions during the high activity summer/fall paving season. As at December 31, 2010, MRCI has agreements to sell approximately 667,000 barrels of asphalt at a weighted average price approximating US$95.00 per barrel in 2011.

DOWNSTREAM REVENUE


Years ended December 31	2010	2009
Gross revenue ⁽¹⁾($ 000)	$334,165	$264,924
Transportation cost ⁽²⁾	(7,899)	(6,524)
Revenue	$326,266	$258,400
Weighted average sales price ($ per bbl) ⁽³⁾	$88.68	$77.05

₍₁₎	_{Includes intersegment sales of $14.3 million in 2010 (2009 - $7.1 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 2010, total downstream revenue was 26 percent higher compared to 2009, primarily due to refining and selling larger volumes and due to higher weighted average realized sales prices. Total sales volume increased by 10 percent in 2010 compared to 2009 and the weighted average sales price of refined petroleum products sold increased by 15 percent, driven by stronger economic conditions in our sales market.

CRUDE OIL AND OPERATING COSTS


Years ended December 31	2010	2009
Crude oil purchases and operating costs ⁽¹⁾ ($ 000)	$301,084	$248,837
Crude oil purchases and operating costs ($ per bbl) ⁽²⁾	$81.83	$74.20

₍₁₎	_{Includes intersegment cost of sales of $13.2 million in 2010 (2009 - $6.8 million) which has been eliminated from the consolidated financial statements.}
₍₂₎	_{Per unit costs is calculated using crude oil purchases and operations costs divided by volumes of refined products sold.}

In 2010, total crude oil purchases and operating costs increased by 21 percent compared to levels in 2009 primarily due to higher refined crude oil volumes and higher benchmark crude oil prices. Notwithstanding that WTI crude oil prices increased by 28 percent in 2010 compared to 2009, crude oil and operating costs per barrel only increased by 10 percent primarily due to the benefit of lower feedstock costs due to wider heavy crude oil differentials in 2010.

REFINING NETBACKS ⁽¹⁾


Years ended December 31	2010	2009
Refining netbacks ⁽¹⁾ ($ 000)	$25,182	$9,564
Refining netbacks (weighted average $ per bbl)	$6.84	$2.85
Refining netbacks (% of revenue)	8%	4%

₍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 163 percent higher in 2010 compared to 2009 and refining netbacks per barrel of refined petroleum product sold increased by 140 percent. This significant increase in 2010 compared to 2009 was due to refining and selling higher volumes, higher realized prices and lower feedstock cost due to wider heavy oil differentials. In addition, the higher netbacks also include the benefit of a reversal of a previous inventory write-down of approximately $1.4 million.

CORPORATE REVIEW

INTEREST AND OTHER INCOME

In 2010, the company earned interest and other income of $256,000 (2009 - $3.6 million), primarily from temporarily investing surplus funds in short term deposits. A portion of the interest earned was recognized as income and a portion (in respect of cash balances on hand from pre-funding oil sands projects under construction) was credited to capitalized costs. Interest and other income in 2009 included a gain of $2.3 million on the repurchase of Second Senior Lien Notes. No similar transactions occurred in 2010.

GENERAL AND ADMINISTRATIVE EXPENSES

In 2010, general and administrative ("G&A") expenses were $19.9 million, compared to $14.8 million in 2009, an increase of 35 percent, primarily due to personnel costs of an expanded staff required to support corporate growth. In 2010, G&A of $5.1 million attributable to capital projects was also capitalized to upstream property, plant and equipment (2009 - $5.0 million).

STOCK BASED COMPENSATION

The company recorded non-cash stock-based compensation charges as follows:


Years ended December 31 ($ in 000)	2010	2009
Charged to expense	$5,063	$4,562
Capitalized to property, plant and equipment	1,664	1,095
Total	$6,727	$5,657

The increase from the prior period was due to higher fair values for options granted in 2010.

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. The company has capitalized interest on a portion of its long-term debt, proceeds of which were used to finance the construction of major oil sands projects.

In 2010, finance charges of $64.9 million were higher than $44.4 million expensed in 2009. The higher finance charges in 2010 were primarily a result of higher debt levels, following issuance of the First Lien Senior Notes in June 2009. In addition, finance charges relating to the company's second oil sands project, Algar, which had been capitalized during its construction, were charged to the statement of operations after October 1, 2010. Connacher capitalized finance charges of $38.3 million in 2010 (2009 - $52.4 million) in respect of its oil sands capital projects.

FOREIGN EXCHANGE GAINS

The value of the Canadian dollar relative to the U.S. dollar has strengthened over the past two years. This had a significant impact on Connacher upon translating its U.S. dollar-denominated long-term debt and U.S. dollar cash balances into Canadian dollars for financial reporting purposes. Connacher recognized foreign exchange gains of $41.6 million in 2010 (2009 -$106.2 million).

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


Years ended December 31 ($ in 000)	2010	2009
Depletion expense on upstream property, plant and equipment	$63,872	$55,525
Depreciation expense on downstream property, plant and equipment	10,471	7,391
Depreciation on corporate property, plant and equipment	2,328	1,445
Accretion expense on asset retirement obligations	2,915	2,201
Total	$79,586	$66,562

Depletion expense is calculated using the unit-of-production method based on estimated total proved reserves. Depletion equated to $16.36/boe of production in 2010 (2009 - $16.51/boe of production). Effective October 1, 2010, the capitalized costs relating to Algar were subjected to depletion which resulted in higher depletion expense in 2010 compared to 2009. Future development costs of $1.4 billion (2009 - $1.4 billion) were included in the depletion calculation while capital costs of $118.7 million (2009 - $96.9 million) related to unproved properties were excluded from the depletion calculation. Downstream and corporate property, plant and equipment are depreciated over their estimated useful lives.

EQUITY INTEREST IN PETROLIFERA PETROLEUM LIMITED ("PETROLIFERA")

Connacher accounts for its investment in Petrolifera under the equity method of accounting. Connacher's share of Petrolifera's loss in 2010 was a $1.8 million (2009 - $2.5 million).

In April 2010, Petrolifera closed a public offering of 23,678,500 common shares at a price of $0.85 per common share for gross proceeds of $20.1 million (the "Offering"). The company did not subscribe for shares in the Offering and 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 non-cash dilution loss of $4.3 million in 2010. Connacher continued to equity account for this investment in 2010 despite the modest reduction in percentage ownership.

In January 2011, Petrolifera entered into an arrangement agreement with Gran Tierra Energy Inc. ("Gran Tierra Energy"), pursuant to which Gran Tierra Energy would indirectly acquire all of the issued and outstanding common shares and common share purchase warrants of Petrolifera. Under the terms of the arrangement agreement, if the transaction proceeded with necessary approvals, Connacher would receive 3.3 million common shares and 841,000 share purchase warrants of Gran Tierra Energy on the expected closing date of March 18, 2011. Based on this transaction, the estimated fair value of our investment in Petrolifera was $15.3 million lower than our carrying value. Consequently, the company recorded an impairment charge of $15.3 million in 2010.

INCOME TAXES

The total income tax recovery of $12.8 million in 2010 (2009 - $7.3 million) included a current income tax recovery of $291,000 (2009 - $1.6 million), principally related to taxes refundable by MRCI. The future income tax recovery of $12.5 million in 2010 (2009 -$5.7 million) reflected the change in tax pools during the periods.

The approximate amounts of total income tax pools available as at December 31, 2010 were $1,248 million in Canada and $48 million in the USA (2009 - $1,075 million in Canada and $53 million in the USA), including non-capital losses of approximately $503 million in Canada and $18 million in the USA, which expire over time to 2030 and $34 million of net capital losses in Canada, which are available to reduce taxable capital gains in future.

NET EARNINGS (LOSS)

Notwithstanding higher upstream and downstream netbacks, the company incurred a net loss of $38.8 million in 2010 compared to net earnings of $26.2 million in 2009, primarily due to non-cash charges including lower unrealized foreign exchange gains, higher depletion expense and an investment impairment charge of $15.3 million.

SHARES OUTSTANDING

As at December 31, 2010, the number of common shares issued and outstanding was 447.2 million (December 31, 2009 - 427.0 million). The increase in 2010 compared to 2009 was due to shares issued on a flow-through basis in October 2010, shares issued in respect of share option exercises and shares issued to non-employee directors in respect of director share awards.

As at March 17, 2011, the company had the following securities issued and outstanding.

447,839,563 common shares;
24,082,334 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:


Years ended December 31 ($ in millions)	2010	2009
Algar	$72	$168
Pod One and trucking terminal	28	30
Cogeneration facility and sales transfer lines	25	13
Exploration program	29	13
Conventional and corporate	22	14
Refinery expenditures	8	21
Capitalized interest, G&A and other costs	50	54
EIA application and other	3	1
Capital expenditures	237	314
Non-cash expenditures	11	8
Additions to property, plant and equipment	$248	$322

In 2010, expenditures on Algar were primarily related to the completion of construction, commissioning of the plant and for minor capital projects after start-up of operations. Pod One expenditures were related to the drilling and completion of two additional SAGD well pairs, initial installation of nine down-hole electric submersible pumps ("ESPs"), and the expansion of the trucking terminal and for other facility enhancements. Connacher also completed the construction of 13.1 megawatt cogeneration facility at Algar and constructed two 8 km transfer pipelines between Algar and Pod One to allow for the consolidation of marketing efforts at the Pod One trucking terminal. Exploration expenditures were incurred primarily to drill 68 exploratory core holes at Great Divide, 13 (6.5 net) exploratory core holes at Halfway Creek and for seismic expenditures related to the 2010 winter exploration program. Expenditures on conventional activities were primarily for drilling (two crude oil wells, three natural gas wells, four abandoned wells at Marten Creek and three stratagraphic wells at Twining), land acquisition, seismic, well work-overs and facilities. Refinery expenditures were comprised of a number of smaller projects including additional water treatment facilities and initial work on each of a boiler replacement, a 20 megawatt electrical substation and the benzene removal project.

In 2009, expenditures at Algar were primarily related to the design, construction and drilling of 17 SAGD well pairs. Pod One expenditures were incurred to drill and complete two SAGD well pairs and to install seven new ESPs and for other facility enhancement expenditures. Exploration and evaluation expenditures represented the drilling of 23 exploratory core holes, one SAGD observation well and one water source well. Expenditures on conventional properties were incurred for drilling (two wells), land acquisitions, seismic, well work-overs and facilities. Refinery capital expenditures were primarily directed to the completion and tie-in of our new hydrogen plant, as part of the completion of the ultra-low sulphur diesel project, the regularly scheduled turnaround and the scheduled replacement of the fluid catalytic cracker reactor.

RECENT FINANCINGS

Common Share Issuance

On June 5, 2009 Connacher issued 191,762,500 common shares from treasury at a price of $0.90 per common share, for gross proceeds of $173 million. The proceeds were raised for working capital to fund the company's capital expenditures, including Algar and for general corporate purposes. At December 31, 2010, the proceeds had been fully utilized to fund capital expenditures, including oil sands capital costs.

First Lien Senior Secured Notes

On June 16, 2009, the company issued US$200 million first lien five-year secured notes ("First Lien Senior Notes") at an issue price of 93.678 percent for gross proceeds of $212 million in equivalent Canadian funds. These funds were raised for working capital and for general corporate purposes, including funding a portion of the remaining expenditures associated with the construction and drilling costs of Algar. At December 31, 2010, the proceeds had been utilized to fund capital expenditures primarily related to Algar. Construction of Algar was completed in April 2010.

Flow-Through Shares

In October 2009, to fund the company's 2010 exploration program the company issued 23,172,500 common shares on a flow-through basis at $1.30 per common share, for gross proceeds of $30.1 million. At December 31, 2010, the proceeds had been utilized to fund capital expenditures for the exploration program. The company renounced the income tax benefits of these expenditures ($30.1 million) to the subscribing investors, effective December 31, 2009.

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. Most of these expenditures will be incurred in 2011.

Revolving Credit Facility

The company has a US$50 million revolving credit facility (the "Facility") provided by a syndicate of Canadian and international banks. At December 31, 2010, $5.7 million of letters of credit were issued in the normal course of business pursuant to the Facility.

In 2010, the Facility was amended. The Facility was extended to November 24, 2013, borrowing and stand-by costs were reduced and one of the financial covenants was extinguished. The Facility is available for general corporate purposes and provides Connacher with additional liquidity and financial flexibility, including the issuance of letters of credit and the conduct of hedging activities. The Facility ranks senior to all of Connacher's other indebtedness and is collateralized by a first priority security interest in all present and after-acquired assets of Connacher, except Connacher's investment in Petrolifera and the pipeline assets of an inactive subsidiary. The Facility has the following financial covenants:

Consolidated total debt (excluding the company's outstanding convertible debentures) to total capitalization (defined to include all debt, convertible debentures and equity) shall not be greater than 70 percent, declining to 65 percent when production from Algar exceeds 8,000 bbl/d for a period of 30 consecutive days; and
debt outstanding under the Revolving Credit Facility to EBITDA (defined to include Earnings before Finance charges, Taxes, Depletion, depreciation and accretion, Risk management contract gains or losses, Share of loss, dilution loss and impairment loss in Petrolifera, Stock-based compensation expense, Employee benefit costs, Gain or loss on disposition of property, plant and equipment and Foreign exchange gains or losses) shall not be greater than 2.0:1.

As at December 31, 2010, Connacher was in compliance with all its debt covenants.

LIQUIDITY AND CAPITAL RESOURCES

In 2010, cash flow increased by 195 percent to $36.9 million ($0.09 per basic and diluted share outstanding) compared to $12.5 million ($0.04 per basic and diluted share outstanding) in 2009.

At December 31, 2010, the company had working capital of $65.4 million (December 31, 2009 - $247 million), including $19.5 million of cash (December 31, 2009 - $257 million). The significant decrease in working capital as at December 31, 2010 compared to December 31, 2009 was due to the decrease in our cash balances. The company completed a debt financing and equity financings in 2009 which resulted in higher cash balances as at December 31, 2009. The majority of these funds were used in the first half of 2010 on the completion of the construction of Algar and other capital activities. As at December 31, 2010, 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 cash generated from operations in 2011 to fund its ongoing capital program and to satisfy its financial obligations in 2011.

The increase in accounts receivable balances as at December 31, 2010 compared to December 31, 2009 was primarily due to higher revenue in 2010 compared to 2009. Inventory balances increased as at December 31, 2010 compared to December 31, 2009 primarily due to higher inventory volumes and values of our refined products. Lower accounts payable and accrued liabilities as at December 31, 2010 compared to 2009 reflect lower capital expenditures towards the end of 2010.

In light of the current volatility of commodity prices, the US:Canadian dollar exchange rate and their significance to the company's operating performance, 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.

In 2010, the company entered into WTI risk management contracts on a portion of its crude oil sales and on a portion of its refined gasoline sales and entered into 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 February 2011, the company closed its Battrum property sale for gross proceeds of $57.5 million, subject to normal closing adjustments. The effective date of the sale was January 1, 2011. The sale proceeds were added to Connacher's cash balances and working capital, thereby reducing net debt. In March 2011, we entered into an agreement to sell our Marten Creek/Randall properties on April 29, 2011 for gross proceeds of $22.5 million, subject to normal closing adjustments. The sale proceeds will be added to cash balances and hence, will further strengthen our liquidity.

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 debts outstanding.


As at December 31 ($ 000)	2010	2009
Convertible Debentures, 4 ¾%, due June 30, 2012	$92,762	$88,488
First Lien Senior Notes, 11 ¾%, due July 15, 2014	184,176	191,509
Second Lien Senior Notes, 10 ¼%, due December 15, 2015	566,663	596,184
Total - no current maturities	$843,601	$876,181

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


As at December 31 ($ 000)	2010	2009
Long-term debt ⁽¹⁾	$843,601	$876,181
Shareholders' equity	650,183	671,588
Total Debt plus Equity ("capitalization")	$1,493,784	$1,547,769
Debt to book capitalization ⁽²⁾	56%	57%

⁽¹⁾ ^{Long-term debt is stated at its carrying value, which is net of transaction costs and the Convertible Debentures' equity component value.}

⁽²⁾ ^{Calculated as long-term debt divided by the book value of shareholders' equity plus long-term debt.}

As at December 31, 2010, the company's net debt (long-term debt, net of cash on hand) was $824 million. Its net debt to book capitalization was 55 percent. Completion of Algar resulted in reduced cash balances but it is anticipated that the higher production will result in increased cash flow from operations in 2011 and ensuing years, if similar prices are realized for sales of bitumen.

COMMITMENTS AND CONTRACTUAL OBLIGATIONS

The company's annual commitments under leases for office premises and operating costs, software license agreements, other equipment and long term debt are as follows:


As at December 31, 2010 ($ 000)	2011	1-3 years	4-5 years	Thereafter	Total
Operating commitments ⁽¹⁾	$7,280	$18,323	$8,537	$40,673	$74,813
Capital commitments ⁽²⁾	1,632	-	-	-	1,632
Long-term debt at face value including interest ⁽³⁾	87,997	540,335	641,507	-	1,269,839
Asset retirement obligations	-	2,370	-	84,640	87,010
Employee future benefits	497	-	-	-	497
Total	$97,406	$561,028	$650,044	$125,313	$1,433,791

⁽¹⁾ ^{Includes rent of office space, operating lease rentals for vehicles and equipment, maintenance fee relating to the cogeneration facility and charges relating to utility agreements.}

⁽²⁾ ^{Primarily related to drilling rig commitments and success fee relating to the sale of properties.}

⁽³⁾ ^{Includes future interest payments.}

The above table excludes ongoing crude oil and product purchase commitments of the Refinery, which are in the normal course of business and are contracted at market prices. The above table also excludes the company's commitment to incur qualifying capital expenditures under its flow-through common share issuance in October 2010.

OUTLOOK

We expect stronger financial results in 2011 compared to 2010, due to anticipated higher production and sales volumes and more stable operating performance at Pod One and the continued production ramp-up at Algar. We also anticipate more stable operations and improved efficiencies resulting from fewer power disruptions, with the activation of our cogeneration facility at Algar. It appears higher commodity prices (supported by our hedging program) will prevail and we anticipate favorable results from our refining and conventional operations.

All of our debt is long-term, with our first maturity in 2012 and remaining maturities in 2014 and 2015. We will monitor the long-term debt market for advantageous refinancing alternatives, having regard for existing call provisions and maturities and provided price and term alternatives extant in the public debt market remain favorable. Our focus in 2011 will be on optimizing our production at Great Divide, rationalizing non-core conventional assets, expanding our new core 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.

ESTIMATED 2010 NETBACKS AND ADJUSTED EBITDA

In our 2009 MD&A as contained in our annual report and as filed separately on SEDAR, we provided guidance with regard to Connacher's estimated 2010 adjusted EBITDA per barrel of bitumen sold. We updated that guidance in our Q3 2010 MD&A (the "Q3 2010 Estimate"). Estimated 2010 adjusted EBITDA is calculated on an annual basis and, consequently, quarterly adjusted EBITDA per barrel of bitumen sold will vary from the average annual adjusted EBITDA. The table below compares the company's consolidated results for year ended December 31, 2010 ("2010 Actual results") to the Q3 2010 estimate. Explanations for variances are provided below the table.


	2010 Actual results		Q3 2010 Estimate
	$/bbl of bitumen	Total ($ millions)	$/bbl of bitumen	Total ($ millions)
Bitumen netback	$23.68	$71	$21.42	$66
Conventional netback	6.01	18	6.01	19
Refining cash netback ⁽¹⁾	8.68	26	8.88	27
Loss on risk management contracts	(1.00)	(3)	(0.79)	(2)
Corporate netback	37.37	112	35.52	110
Corporate G&A	(6.68)	(20)	(6.21)	(19)
Adjusted EBITDA ⁽²⁾	$30.69	$92	$29.31	$91

₍₁₎ _{Refining cash netback excludes the non-cash charge of defined benefit plan expense.}

₍₂₎ _{Adjusted EBITDA is a non-GAAP measure, which is defined in the Advisory section of the MD&A.}

2010 adjusted EBITDA of $92 million was $1 million higher than the Q3 2010 estimate for the same period for the reasons cited below.

The 2010 bitumen netback of $71 million was $5 million greater than the Q3 2010 estimate for the same period. The higher actual bitumen netback was primarily due to stronger crude oil prices, a weaker Canadian dollar, narrower heavy oil differentials and lower diluent premiums to WTI as compared to assumptions used in the Q3 2010 estimate. 2010 actual daily bitumen sales volumes were three percent lower than the Q3 2010 estimate of sales volumes for the same period.

The 2010 conventional netback of $18 million was in line with the Q3 2010 estimate for the same period.

The 2010 refining netback of $26 million was $1 million lower than the Q3 2010 estimate for the same period, as narrower heavy oil differentials and lower volumes of asphalt sold in the fourth quarter of 2010 more than offset higher realized margins on sales of gasoline, diesel and jet fuel, compared to assumptions used in the Q3 2010 estimate.

Realized losses on risk management contracts in 2010 of $3 million were $1 million greater than the Q3 2010 estimate for the same period because of higher actual WTI prices compared to assumptions used in the Q3 2010 estimate.

Corporate G&A in 2010 of $20 million was $1 million greater than the Q3 2010 estimate for the same period, because of higher staffing costs.

Actual adjusted EBITDA on a per barrel basis was higher than anticipated at Q3 2010 due to the above noted difference notwithstanding 2010 actual daily bitumen sales volumes were three percent lower than the Q3 2010 estimate of sales volumes for the same period.

2011 OUTLOOK

The company's revised 2011 production guidance and 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.}^.


2011 Capital budget on 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	16
	Refining	9
	Exploration	26
	EIA and Algar expansion engineering	10
Total Growth Capital and Special Projects		69
Total 2011 Capital budget		$122

Sustaining and maintenance capital for the oil sands includes two initial ESPs at Pod One and three at Algar, expenditures related to a diluent recovery system, tankage at Pod One and for minor projects. At the Refinery, sustaining and maintenance capital includes the completion of a 20MW electrical substation and expenditures related to ethanol blending, tank and boiler replacements.

Growth capital for the oil sands includes expenditures related to solvent SAGD at Algar and enhanced recovery at Pod One. In conventional operations, growth capital includes expenditures related to our three well resource project at Twining and land purchases. The Refinery growth expenditures relate to the completion of the benzene removal project. The exploration budget is for our current core-hole and 3D seismic program at Great Divide and Thornbury.

The 2011 production and capital guidance assumes the sale of our Marten Creek/Randall properties for $22.5 million on April 29, 2011. The company anticipates that cash balances and full year 2011 upstream and downstream cash flows (assuming similar WTI pricing and foreign exchange levels realized in 2010) together with available unused revolving lines of banking credit, should be more than sufficient to meet all budgeted capital expenditures and ongoing financial obligations throughout 2011. 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".

RELATED PARTY TRANSACTIONS

In 2010 the company incurred professional legal fees of $779,000 (2009 - $1.3 million) to a law firm in which an officer and a director of the company were partners. Transactions with the related party occurred within the normal course of business and have been measured at their exchange amount on normal business terms. The exchange amount is the amount of consideration established and agreed to with the related parties. As at December 31, 2010, accounts payable to the law firm was approximately $158,000 (2009 - $71,000).

SIGNIFICANT ACCOUNTING POLICIES AND APPLICATION OF CRITICAL ACCOUNTING ESTIMATES

The significant accounting policies used by the company are described below. Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Changes in these estimates and assumptions may have a material impact on the company's financial results and condition. The following discusses such accounting policies and is included herein to aid the reader in assessing the critical accounting policies and practices of the company and the likelihood of materially different results being reported. Management reviews its estimates and assumptions regularly in light of changing circumstances, economic and otherwise. The emergence of new information and changed circumstances may result in changes to estimates and assumptions which could be material and the company might realize different results from the application of new accounting standards promulgated, from time to time, by various regulatory rule-making bodies.

RESERVE ESTIMATES

The reserve estimates for 2010 and 2009 were prepared by GLJ Petroleum Consultants Ltd., an independent professional petroleum engineering firm, in accordance with Canadian Securities Administrators' National Instrument 51-101 (NI 51-101) and the Canadian Oil and Gas Evaluation Handbook. Under NI 51-101, proved reserves are those reserves which can be estimated with a high degree of certainty to be recoverable. It is likely that actual remaining quantities recovered will exceed estimated proved reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved pus probable plus possible reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

All of the company's oil and gas reserve estimates are made by independent reservoir engineers using all available geological and reservoir data as well as historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes, reservoir performance or a change in the company's plans. The reserve estimates can also be used in determining the company's borrowing base for its credit facilities and may impact the same upon revision or changes to the reserve estimates. The effect of changes in proved oil and gas reserves on the financial results and position of the company is described below.

Full Cost Accounting For Oil And Gas Activities

The company uses the full cost method of accounting for exploration and development activities. In accordance with this method of accounting, all costs associated with exploration and developments are capitalized whether successful or not. The aggregate of net capitalized costs and estimated future development costs is depleted using the unit-of-production method based on estimated proved oil and gas reserves. A change in estimated total proved reserves could significantly affect the company's calculation of depletion.

Major Development Projects And Unproved Properties

Certain costs related to acquiring and evaluating unproved properties are excluded from net capitalized costs subject to depletion until proved reserves have been determined or their value is impaired. Costs associated with major development projects are not depleted until they are capable of production or the related development activity ceases or the property is determined to be impaired. All capitalized costs are reviewed quarterly and any impairment is transferred to the costs being depleted.

All costs related to the Great Divide oil sands project are being capitalized to specific projects, or "Pods". The capital costs and estimates of future capital requirements for Pods are added to the company's depletable costs and depleted under the unit-of-production method based on the company's total proved reserves when each Pod becomes capable of production or the development activities at any Pod ceases or an impairment occurs. Effective October 1, 2010, the company's second oil sands project, Algar, became capable of commercial production and its related costs were added to the company's depletable cost pool.

Ceiling Test

The company is required to review the carrying value of oil and gas assets for potential impairment. Impairment is indicated if the carrying value of oil and gas cost centre is not recoverable by the future undiscounted cash flows. If impairment is indicated, the amount by which the carrying value exceeds the estimated fair value of oil and gas assets is charged to earnings.

The ceiling test is based on estimates of reserves, production rate, crude oil, bitumen and natural gas prices, future development costs and other relevant assumptions. By their nature reserve estimates are subject to measurement uncertainty and the impact of ceiling test calculations on the consolidated financial statements for changes in reserve estimates could be material.

ASSET RETIREMENT OBLIGATIONS

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

LEGAL AND OTHER CONTINGENT MATTERS

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

INCOME TAXES

The company follows the liability method of accounting for income taxes. Under this method tax assets are recognized when it is more than likely realization will occur. Tax liabilities are recognized for temporary differences between recorded book values and underlying tax values. Rates used to determine income tax asset and liability amounts are enacted tax rates expected to be used in future periods when the timing differences reverse. The period in which a timing difference reverses are impacted by future income and capital expenditures. Rates are also affected by legislation changes. These components can impact the charge for future income taxes.

Tax interpretations, regulations and legislations in the jurisdictions in which the Company, its subsidiary and equity accounted for investment operate are subject to change. As such, income taxes are subject to measurement uncertainty and the interpretations can impact net earnings through income tax expense arising from the changes in future income tax asset and liabilities.

STOCK-BASED COMPENSATION

The company uses the fair value method to account for stock options. The determination of the amounts for stock-based compensation is based on estimates of share price volatility, interest rates and the expected life of the option. These estimates by their nature are subject to measurement uncertainty.

SHARE AWARD PLAN

Obligations under our share award plan for non-employee directors are accrued as compensation expense over the vesting period. Fluctuations in the price of our common shares change the accrued compensation expense and are recognized when they occur.

EMPLOYEE FUTURE BENEFITS

As a consequence of the Refinery acquisition and related employment of Refinery personnel, our U.S. subsidiary, MRCI, adopted employee future benefit plans with effect from March 31, 2006. A non-contributory defined benefit retirement plan covers only certain Refinery employees from March 31, 2006. MRCI's policy is to make regular contributions in accordance with the regulatory requirements. Benefits are based on employees' years of service and compensation. We also established defined contribution (U.S. tax code ''401(k)'') plans that cover all Refinery employees from March 31, 2006. MRCI's contributions are based on employees' compensation and partially match employee contributions.

LONG-LIVED ASSETS

Depreciation and amortization is calculated based on estimated useful lives and salvage values. When assets are placed into service, estimates are made with respect to their useful lives that are believed to be reasonable. However, factors such as new technologies, competition, regulation or environmental matters could cause changes to estimates, thus impacting the future calculation of depreciation and amortization. Long-lived assets are also evaluated for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flow. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset's carrying value exceeds its fair value. Estimates of future discontinued cash flow and fair values of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates.

GOODWILL

Goodwill arose on a corporate acquisition in 2006. Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is assessed for impairment annually. Goodwill and all other assets and liabilities have been allocated to our segments, referred to as reporting units. To assess impairment, the fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, then a second test is performed to determine the amount of the impairment. The amount of the impairment is 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 book value of the reporting unit's goodwill. Any excess of the book value of goodwill over the implied fair value of goodwill is the impairment amount.

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. 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.

INTERNATIONAL FINANCIAL REPORTING STANDARDS

The company is executing a conversion project to complete the transition to IFRS by January 1, 2011, including the preparation of 2010 required comparative information. The conversion plan consists of four phases: diagnostic; design and planning; solution development; and implementation. The company is currently in the implementation phase and is still in the process of finalizing the financial impact of adopting IFRS. However, we have determined that the differences that could have the greatest impact on Connacher's consolidated financial statements relate to accounting for exploration and development activities, property, plant and equipment, goodwill, asset retirement obligations and income taxes.

The majority of the adjustments made on transition to IFRS will be recorded retrospectively to the opening balance of retained earnings at January 1, 2010. Changes arising from the transition where the accounting standards do not require retrospective application will be applied prospectively to transactions occurring subsequent to January 1, 2010.

IFRS 1 ''First-Time Adoption of International Financial Reporting Standards'' provides entities adopting IFRS for the first time with a number of optional and mandatory exemptions, in certain specific areas, to the general requirement for full retrospective application of IFRS. The company is in the final stage of analyzing the various accounting policy choices available and will implement those determined to be most appropriate in the company's circumstances.

One such exemption we will utilize is the amendment to IFRS 1 issued by the International Accounting Standards Board (IASB) in July 2009 respecting the determination of opening balances of property, plant and equipment. That amendment permits oil and gas companies currently using the full cost method of accounting to allocate the balance of property, plant and equipment as determined under Canadian GAAP to the IFRS categories of exploration and evaluation assets and development and producing properties without requiring full retrospective restatement of historic property, plant and equipment balances to the IFRS basis of accounting.

Other exemptions from retrospective application of IFRS which we will use are those available for foreign currency translation differences recorded in accumulated other comprehensive income, actuarial gains and losses relating to MRCI's defined benefit pension plan, stock-based compensation, borrowing costs, leases, decommissioning liabilities included in the cost of property, plant and equipment and business combinations.

The following discussion provides an overview of the areas that will have the greatest impact on Connacher's consolidated financial statements. The items discussed below should not be considered a complete list of the changes which may occur as a result of the transition to IFRS. The discussion is intended to highlight the areas of most significant impact on Connacher based on the work completed to date. However, the company's analysis of the changes is ongoing.

PROPERTY, PLANT & EQUIPMENT

International Accounting Standard (IAS) 16 ''Property, Plant & Equipment'' and Canadian GAAP contain the same basic principles. However there are some differences. IFRS requires that significant components of an asset be depreciated separately. Depreciation under IFRS commences when an asset is available for use. Capitalization of costs under IFRS ceases when an item of property, plant and equipment is in the location and condition necessary for it to be capable of operating in the manner intended by management. IFRS also permits property, plant and equipment to be measured using the fair value model or the historical cost model. The company will not adopt the fair value model to measure its property, plant and equipment. Additionally, under IFRS exploration and evaluation assets are accounted for separately from development and producing assets.

IFRS 1 contains an elective exemption where an entity may elect to reset as the new cost basis for property, plant and equipment, its fair value at the date of transition. The company will not use this exemption and will continue to measure its property, plant and equipment at cost.

Connacher will adopt the IFRS 1 exemption, which allows the Company to deem its January 1, 2010 IFRS upstream asset costs to be equal to its Canadian GAAP historical upstream net book value. On January 1, 2010, the IFRS exploration and evaluation asset is approximately $96.9 million, which is equal to the Canadian GAAP unproved properties balance. The IFRS development costs will be equal to the full cost pool balance. Connacher allocated this upstream full cost pool to its developed oil and gas properties in proportion to their established reserve values.

IMPAIRMENT TESTING OF ASSETS

Impairment testing of non-financial assets under IFRS, including property, plant and equipment and goodwill, is measured using discounted cash flows and fair values. Under Canadian GAAP, an asset's carrying amount was first compared to its undiscounted future cash flows. If the carrying value exceeded that amount, the impairment was measured as the excess of the carrying value over the asset's discounted future cash flows. Under IFRS, there is no initial assessment using undiscounted cash flows. Therefore, impairments may occur more frequently under IFRS compared to Canadian GAAP. Under IFRS there is an opportunity to reverse impairment losses for assets other than goodwill where there is a favorable change in the circumstances which gave rise to the impairment. Under Canadian GAAP, impairments were not reversed.

Additionally, under Canadian GAAP, Connacher's oil and gas assets were tested for impairment in a single, country-wide full cost pool. Under IFRS, assets must be segregated into "cash-generating units" ("CGUs") for purposes of impairment testing. A CGU 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. As a result, impairments may occur with respect to certain of the company's assets which would not have been incurred under Canadian GAAP because of the ability under full cost accounting to shelter assets using the cash flow from the all of the company's oil and gas properties included in the full cost pool. The company expects to record impairment charge of approximately $103 million, on January 1, 2010, relating to its Goodwill with corresponding charge to retained earnings. The company is still in the process of finalizing the effect of impairment on its oil and gas assets.

ASSET RETIREMENT OBLIGATIONS

Differences exist between Canadian GAAP and IFRS with respect to the measurement of asset retirement obligations. Specifically, under Canadian GAAP asset retirement obligations were measured at fair value using a credit-adjusted risk-free discount rate. Under IFRS, asset retirements obligations are measured using the best estimate of the expenditure required to settle the obligation, and are discounted using a risk-free interest rate. Using such a lower discount rate will result in an increase in Connacher's asset retirement obligation recorded on the consolidated balance sheet.

In addition, IFRS requires changes to the timing of cash flows, estimated amounts of cash flows and discount rates to be accounted for prospectively. Canadian GAAP is similar; however, under IFRS changes to the discount rates for ARO are only applied to the incremental changes in the liability and not to the entire liability.

As a result of Connacher's use of the IFRS 1 upstream asset exemption, the Company is required to revalue its January 1, 2010 ARO balance recognizing the adjustment in retained earnings. The company expects to recognize an increase in the obligation of approximately $20 million with a corresponding reduction to retained earnings on the IFRS opening balance sheet.

INCOME TAXES

Under IAS 12 "Income Taxes", deferred taxes are not recognized for temporary differences arising from the initial recognition of an asset or liability in a transaction which is not a business combination and which at the time of the transaction affects neither accounting nor taxable income. Canadian GAAP contains no such exemption.

Additionally, under IFRS current and deferred taxes are normally recognized in the income statement, except to the extent that deferred tax arises from (1) an item that has been recognized directly in equity, whether in the same or a different period, (2) a business combination or (3) a share-based payment transaction. If a deferred tax asset or liability is remeasured subsequent to initial recognition, the impact of remeasurement is recorded in earnings, unless it relates to an item originally recognized in equity, in which case the change would also be recorded in equity. The practice of tracking the remeasurement of taxes back to the item which originally triggered the recognition is commonly referred to as ''backwards tracing.'' Canadian GAAP prohibits backwards tracing except in relation to business combinations and financial reorganizations.

Connacher expects to recognize a decrease in the deferred tax liability of approximately $16 million with a corresponding increase to retained earnings of $20 million and decrease to equity portion of convertible debentures of $4 million on the IFRS opening balance sheet.

OTHER IFRS 1 CONSIDERATIONS

As permitted by IFRS 1, Connacher's foreign currency translation adjustment, currently the only balance in Connacher's accumulated other comprehensive income, will be deemed to be zero and the balance of $16 million will be reclassified to retained earnings on January 1, 2010. There is no impact to Connacher's shareholders equity as a result of this reclassification. Retrospective restatement of foreign currency translation adjustments under IFRS principles will not be performed.

With respect to employee benefit plans, cumulative unamortized actuarial gains and losses will be charged to retained earnings on January 1, 2010. As such, they will not be retrospectively restated using IFRS principles. Connacher expects to recognize a decrease in the pension liability of approximately $0.7 million with a corresponding increase to retained earnings on the IFRS opening balance sheet.

INTERNAL CONTROLS

Connacher is currently assessing the impact of the conversion to IFRS on internal controls and business processes. Based on our initial assessment, the impact is not expected to be significant. However, some additional controls will be required in regard to recording transitional adjustments and new processes for identifying and separately accounting for exploration and evaluation assets.

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 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. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the company's disclosure controls and procedures at the financial year end of the company and have concluded that the company's disclosure controls and procedures are effective at the financial year end of the company for the foregoing purposes.

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. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the company's internal controls over financial reporting at the financial year end of the company and concluded that the company's internal controls over financial reporting is effective at the financial year end of the company for the foregoing purpose.

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 material changes in the company's internal controls over financial reporting were identified during such period that has materially affected, or are reasonably likely to materially affect, the company's internal controls over financial reporting.

It should be noted that a control system, including the company's disclosure and internal controls and procedures, no matter how well conceived, 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.

RISK FACTORS AND RISK MANAGEMENT

GENERAL

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, 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, commodity prices and exchange rates, 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 Annual Information Form 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 complies with government regulations and has in place an up-to-date emergency response program. Connacher adheres 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.

COMMODITY PRICE AND EXCHANGE RATE RISKS

Connacher's future financial performance remains closely linked to crude oil and natural gas commodity prices and foreign exchange rate changes which may be influenced by many factors including global and regional supply and demand, seasonality, worldwide political events and weather. These factors can cause a high degree of price volatility. We mitigate some of the risk associated with changes in commodity prices through the use of hedges and other derivative financial instruments.

Crude oil and dilbit selling prices are based on U.S. dollar benchmarks that result in our realized prices being influenced by the US:Canadian dollar exchange rate, thereby creating another element of uncertainty. Should the Canadian dollar strengthen compared to the U.S dollar, the resulting negative effect on revenue, including the translation of MRCI's US denominated results to Canadian dollars for financial reporting purposes would be partially offset with exchange gains on translating our U.S. dollar denominated debt and associated interest payments thereon. The opposite would occur should the Canadian dollar weaken compared to the U.S. dollar. See "Liquidity and Capital Resources" above.

REGULATORY APPROVAL RISKS

Before proceeding with most major development projects, Connacher must obtain regulatory approvals, which approvals must be maintained in good standing during the currency of the particular project. The regulatory approval process involves stakeholder consultation, environmental impact assessments and public hearings, among other factors. Failure to obtain regulatory approvals, or failure to obtain them on a timely basis, could result in delays, abandonment, or restructuring of projects and increased costs, all of which could negatively impact future earnings and cash flow. Failure to maintain approvals, licenses, permits and authorizations in good standing could result in the imposition of fines, production limitations or suspension orders.

PERFORMANCE

Our financial and operating performance is potentially affected by a number of factors, including, but not limited to the following:

Our ability to reliably operate our conventional and oil sands facilities and our refinery is important to meet production targets.
Operating costs could be impacted by inflationary pressures on labor, volatile pricing for natural gas used as an energy source in oil sands processes, and planned and unplanned maintenance. We continue to address these risks though such strategies as application of technologies and an increased focus on preventative maintenance.
While fiscal regimes in Alberta and Canada are generally stable relative to many global jurisdictions, royalty and tax treatments are subject to periodic review, the outcome of which is not predictable and could result in changes to the company's planned investments and rates of return on existing investments.
Management expects that fluctuations in demand and supply for refined products, margin and price volatility, market competition and the seasonal demand fluctuations for some of our refined products will continue to impact our refining business.
There are certain risks associated with the execution of capital projects, including the risk of cost overruns. Numerous risks and uncertainties can affect construction schedules, including the availability of labor and other impacts of competing projects drawing on the same resources during the same time period.

CAPITAL REQUIREMENTS

The company anticipates making substantial capital expenditures for the acquisition, exploration, development and production of bitumen and crude oil reserves and refining in the future. As the company's revenues may decline as a result of decreased commodity pricing, it may be required to reduce capital expenditures. In addition, uncertain levels of near term industry activity coupled with the "recent" global credit crisis exposes the company to additional access to capital risk. There can be no assurance that debt or equity financing, or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the company. The inability of the company to access sufficient capital for its operations and growth could have a material adverse effect on the company's business financial condition, results of operations and prospects.

THIRD PARTY CREDIT RISK

Credit risk is a risk of failure of performance by counter-parties. We attempt to mitigate this credit risk before contract initiation and ensuring product sales and delivery contracts are made with well-known and financially strong crude oil and natural gas marketers. The company may be exposed to third party credit risk through its contractual arrangements with its current counter parties. In the event such entities fail to meet their contractual obligations to the company, such failures may have a material adverse effect on the company's business, financial condition, results of operations and prospects.

ENVIRONMENTAL

All phases of the oil and gas and refining business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial, state and local laws and regulations. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. There has been much public debate with respect to Canada's alternative strategies with respect to climate change and the control of greenhouse gases. Implementation of strategies for reducing greenhouse gases could have a material impact on the nature of oil gas and refining operations, including those of the company. Given the evolving nature of the issues related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict either the nature of those requirements or the impact on the company and its operations and financial condition. The company may be subject to remedial environmental and litigation costs resulting from potential unknown and unforeseeable environmental impacts arising from the company's operations. While these costs have not been material to the company in the past, there is no guarantee that this will continue to be the case in the future as the company carries on with development of technologies.

At our Refinery, we now make ultra-low sulphur diesel and gasoline. We are also mandated to remove benzene from our refined gasoline in 2011. This project is ongoing and is on schedule. Our upstream and downstream businesses are closely regulated with respect to land disturbance, water usage and green house gas emission. To meet these requirements, our operations personnel closely follow established environmental policies and procedures and regularly report to regulators. The quality of these reports has been affirmed by recent audits.

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 and margins, forecast realized gain (loss) on risk management contracts, future corporate general and administration expenses, future profitability, expectations of future production, anticipated sales volumes for 2011, further anticipated reductions in operating costs as a result of continued operational optimization at Great Divide Pod One and Algar, expected operational performance of the cogeneration facility at Algar and subsequent 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, potential rationalization of the conventional property base, future development and exploration activities, estimates of future commodity prices, foreign exchange rates and heavy oil differentials, utilization of alternative financial derivative strategies to protect the company's cash flow, Petrolifera's proposed acquisition by Gran Tierra Energy Inc., the possible monetization of Connacher's equity investment in Gran Tierra Energy Inc. assuming the completion of the acquisition of Petrolifera, future possible joint venture arrangements, anticipated commencement of a "SAGD with solvent" project at Algar, anticipated future reclamation, timing of receipt of regulatory approvals for future expansion at oil sands properties, future royalties which may become payable and the anticipated impact of the conversion to International Financing Reporting Standards ("IFRS") on the company's consolidated financial statements. 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, future economic conditions and the plans and expected impacts of adopting IFRS.

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; 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 March 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, bitumen netback, conventional netback, refinery margins or netback, corporate netback and adjusted earnings before interest, taxes, depreciation and amortization ("adjusted EBITDA"). These terms are not defined by GAAP and 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 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 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 GAAP is cash flow from operating activities. Cash flow from operating activities is reconciled with the cash flow for three and twelve months ended December 31, 2010 and 2009 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 and operating costs from refining sales revenues.

ADJUSTED EBITDA

Adjusted EBITDA is calculated as net earnings before finance charges, taxes, depreciation, amortization and accretion, stock based compensation, foreign exchange gains/losses, unrealized gains/losses on risk management contracts, interest/other income, equity earnings/losses and dilution gains/losses.

RECONCILIATIONS OF NON-GAAP MEASURES

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

RECONCILIATIONS OF CASH FLOW TO CASH FLOW FROM OPERATING ACTIVITIES


		Three months ended December 31		Years ended December 31
($000)		2010	2009	2010	2009
Cash flow		$9,090	$(2,766)	$36,884	$12,522
	Non-cash working capital changes	(35,151)	8,294	(24,935)	(17,300)
	Asset retirement expenditures	(140)	14	(647)	(142)
	Contribution to defined benefit plan	-	-	(517)	(234)
Cash flow from operating activities		$(26,201)	$5,542	$10,785	$(5,154)

RECONCILIATIONS OF UPSTREAM AND DOWNSTREAM NETBACKS TO NET EARNINGS


	Three months ended December 31				Years ended December 31
	2010		2009		2010		2009
($000, except per unit amounts)	Total	Per boe	Total	Per boe	Total	Per boe	Total	Per boe
Upstream netbacks	$32,599	$23.42	$18,149	$22.69	$89,362	$23.08	$62,430	$18.56
Downstream netbacks	7,091	5.10	(4,050)	(5.07)	25,182	6.50	9,564	2.84
Interest and other income	83	0.06	187	0.23	256	0.07	3,550	1.06
Gain (loss) on risk management contracts	(18,008)	(12.94)	(9,300)	(11.63)	(17,186)	(4.44)	(25,125)	(7.47)
General and administrative	(5,560)	(3.99)	(3,710)	(4.64)	(19,921)	(5.15)	(14,772)	(4.39)
Stock-based compensation	(1,240)	(0.89)	(2,118)	(2.65)	(5,063)	(1.31)	(4,562)	(1.36)
Finance charges	(25,706)	(18.47)	(13,190)	(16.50)	(64,877)	(16.76)	(44,354)	(13.19)
Foreign exchange gain	26,935	19.35	12,275	15.35	41,641	10.76	106,164	31.56
Depletion, depreciation and accretion	(23,636)	(16.98)	(16,884)	(21.12)	(79,586)	(20.56)	(66,562)	(19.79)
Income tax recovery	4,282	3.08	7,139	8.93	12,787	2.70	7,305	2.17
Equity interest in Petrolifera loss	(731)	(0.53)	(810)	(1.00)	(1,847)	(0.48)	(2,468)	(0.72)
Dilution loss	-	-	(2,419)	(3.02)	(4,273)	(1.10)	(5,012)	(1.49)
Impairment loss in Petrolifera	(15,273)	(10.97)	-	-	(15,273)	(3.95)	-	-
Net earnings (loss)	$(19,164)	$(13.76)	$14,731	$(18.43)	$(38,798)	$(10.64)	$26,158	$7.78

RECONCILIATION OF ACTUAL ADJUSTED EBITDA IN TOTAL AND PER BARREL OF BITUMEN PRODUCED


	2010		2009
	$/bbl of bitumen	Total ($millions)	Total ($millions)
Adjusted EBITDA	$30.69	$92	$37
Interest and other income	0.10	-	4
Employee benefit expense	(0.14)	(1)	(1)
Unrealized loss on risk management contracts	(4.79)	(14)	(5)
Stock-based compensation	(1.69)	(5)	(5)
Finance charges	(21.66)	(65)	(44)
Foreign exchange gain	13.90	42	106
Depletion, depreciation and accretion	(26.57)	(80)	(66)
Income tax recovery	4.27	13	7
Equity interest in Petrolifera loss	(0.62)	(2)	(7)
Dilution loss	(1.43)	(4)	-
Impairment loss in Petrolifera	(5.10)	(15)	-
Net earnings (loss)	$(13.04)	$(39)	$26

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. Significant volatility and low commodity prices, together with severe economic uncertainty in Q1 2009 are the primary factors affecting financial results during that quarter.


FINANCIAL ($000 except per share amounts)		2009	2009	2009	2009	2010	2010	2010	2010
Three Months Ended		Mar 31	June 30	Sept 30	Dec 31	Mar 31	June 30	Sept 30	Dec 31
Revenues, net of royalties		61,757	100,219	151,360	108,354	118,411	141,270	150,293	156,429
Cash flow ⁽¹⁾		(4,692)	9,570	10,410	(2,766)	3,948	8,668	15,178	9,090
Basic, per share ⁽¹⁾		(0.02)	0.04	0.03	(0.07)	0.01	0.02	0.04	0.02
Diluted, per share ⁽¹⁾		(0.02)	0.03	0.03	(0.07)	0.01	0.02	0.04	0.02
Adjusted EBITDA ⁽¹⁾		2,772	13,259	16,724	4,513	14,440	20,173	25,642	31,951
Net earnings (loss)		(46,844)	39,966	47,767	(14,731)	5,546	(33,126)	7,946	(19,164)
Basic per share		(0.22)	0.15	0.12	(0.03)	0.01	(0.08)	0.02	(0.04)
Diluted per share		(0.22)	0.14	0.11	(0.03)	0.01	(0.08)	0.02	(0.04)
Property and equipment additions		64,255	40,236	100,727	116,846	118,272	59,316	49,842	20,548
Cash on hand		96,220	401,160	333,634	256,787	118,382	69,412	51,120	19,532
Working capital surplus		120,035	455,001	347,139	245,067	127,186	99,834	61,543	65,375
Long-term debt		803,915	960,593	889,113	876,181	851,978	888,323	867,650	843,601
Shareholders' equity		428,276	622,235	658,336	671,588	668,722	644,166	648,543	650,183
OPERATIONAL
Upstream: Daily production volumes ⁽²⁾
	Bitumen - bbl/d	6,170	6,284	6,551	6,090	6,936	6,211	6,758	13,238
	Crude oil - bbl/d	1,180	1,114	993	880	937	906	819	873
	Natural gas - Mcf/d	12,828	12,144	10,377	10,319	9,662	9,278	9,158	8,318
	Equivalent - boe/d ⁽³⁾	9,488	9,421	9,274	8,690	9,483	8,663	9,103	15,498
Product sales prices ⁽⁴⁾
	Bitumen - $/bbl	22.45	40.95	45.30	48.23	51.98	43.13	42.68	45.08
	Crude oil - $/bbl	39.63	54.87	60.58	67.24	71.08	61.90	62.45	66.72
	Natural gas - $/Mcf	4.89	3.35	2.91	4.34	4.86	3.78	3.42	3.44
Selected highlights - $/boe ⁽³⁾
	Weighted average sales price ⁽⁴⁾	26.13	38.11	41.74	45.76	49.99	41.44	40.74	44.09
	Royalties	3.02	1.90	2.13	2.45	3.57	2.73	2.72	2.76
	Operating costs	17.73	13.98	15.43	20.61	17.47	19.25	18.08	17.91
	Netback ⁽¹⁾	5.38	22.23	24.18	22.70	28.95	19.46	19.94	23.42
Downstream: Refining
	Crude charged - bbl/d	6,867	9,145	7,076	8,188	9,347	9,373	9,903	10,137
	Refining utilization - %	72	96	75	86	98	99	104	107
	Margins - %	7	5	8	(7)	(8)	12	12	9
COMMON SHARES
Shares outstanding end of period (000)		211,291	403,546	403,567	427,031	428,246	429,103	429,120	447,168
Weighted average shares outstanding for the period
	Basic (000)	211,286	266,425	403,565	421,804	427,830	429,023	429,106	442,941
	Diluted (000)	211,286	286,985	424,058	422,344	430,077	429,023	431,487	442,941
Volume traded (000)		67,387	249,700	129,206	207,978	167,483	182,419	98,105	137,128
Common share price ($)
	High	1.00	1.66	1.15	1.33	1.65	1.88	1.52	1.35
	Low	0.61	0.74	0.76	0.94	1.16	1.20	1.15	1.10
	Close (end of period)	0.74	0.92	1.10	1.28	1.49	1.29	1.20	1.33

₍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. Actual production volumes sold were 15,405 boe/d in Q4 2010 (production volumes equal sales volume from Q1 2009 to Q3 2010).}
₍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.}

Consolidated Balance Sheets


As at December 31 (Canadian dollar in thousands)	2010		2009
ASSETS
CURRENT ASSETS
Cash		$19,532	$256,787
Accounts receivable		57,419	43,067
Inventories (note 4)		57,144	36,871
Prepayments and other assets		16,857	15,166
Income taxes recoverable		796	2,608
Future income tax asset (note 10)		4,497	2,348
		156,245	356,847

Prepayments and other assets (note 7.4)		615	708
Investment in Petrolifera Petroleum Limited (note 6)		27,938	50,379
Property, plant and equipment (note 5)		1,395,524	1,230,256
Goodwill		103,676	103,676
		$1,683,998	$1,741,866

LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities		$81,886	$105,620
Risk management contracts (note 13.2)		8,984	4,520
		90,870	110,140

Risk management contracts (note 13.2)		9,879	-
Long-term debt (note 7)		843,601	876,181
Asset retirement obligations (note 8)		39,191	32,848
Employee future benefits (note 9)		915	1,066
Future income taxes (note 10)		49,359	50,043
		1,033,815	1,070,278

SHAREHOLDERS' EQUITY
Share capital (note 11)		611,599	590,845
Equity component of convertible debentures (note 7.1)		16,817	16,817
Contributed surplus (note 12)		35,503	30,560
Retained earnings		10,746	49,544
Accumulated other comprehensive loss		(24,482)	(16,178)
		650,183	671,588
		$1,683,998	$1,741,866

Commitments (note 18)
Subsequent events (notes 6.2 and 19)

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

Consolidated Statements of Operations and Retained Earnings


For the years ended December 31 (Canadian dollar in thousands, except per share amounts)	2010	2009
REVENUE
Upstream, net of royalties	$270,033	$191,959
Downstream (note 16)	319,898	257,830
Loss on revenue risk management contracts (note 13.2)	(15,885)	(25,125)
Interest and other income	256	3,550
	574,302	428,214
EXPENSES
Upstream - diluent purchases and operating costs (note 16)	160,697	116,910
Downstream - crude oil purchases and operating costs (note 16)	287,918	242,006
Transportation costs (note 16)	26,772	18,879
Loss on operating cost risk management contracts (note 13.2)	1,301	-
General and administrative	19,921	14,772
Stock-based compensation (note 12)	5,063	4,562
Finance charges (note 7.6)	64,877	44,354
Foreign exchange gain (note 13.2)	(41,641)	(106,164)
Depletion, depreciation and accretion	79,586	66,562
	604,494	401,881
Earnings (loss) before income taxes and other items	(30,192)	26,333

Share of loss, dilution loss and impairment loss in Petrolifera Petroleum Limited (note 6)	(21,393)	(7,480)
Earnings (loss) before income taxes	(51,585)	18,853

Current income tax recovery (note 10)	291	1,601
Future income tax recovery (note 10)	12,496	5,704
	12,787	7,305

NET EARNINGS (LOSS)	(38,798)	26,158
Retained earnings, beginning of year	49,544	23,386
Retained earnings, end of year	$10,746	$49,544

EARNINGS (LOSS) PER SHARE - basic and diluted (note 17.1)	$(0.09)	$0.08

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

Consolidated Statements of Comprehensive Income (Loss)


For the years ended December 31 (Canadian dollar in thousands)	2010	2009
Net earnings (loss)	$(38,798)	$26,158
Foreign currency translation adjustment	(8,304)	(23,980)
Comprehensive income (loss)	$(47,102)	$2,178

Consolidated Statements of Accumulated Other Comprehensive Loss


For the years ended December 31 (Canadian dollar in thousands)	2010	2009
Balance, beginning of year	$(16,178)	$7,802
Foreign currency translation adjustment relating to Montana Refining Company, Inc.	(7,452)	(23,255)
Share of foreign currency translation adjustment of Petrolifera Petroleum Limited, net of tax of $196 (2009 - $104)	(852)	(725)
Balance, end of year	$(24,482)	$(16,178)

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

Consolidated Statements of Cash Flow


For the years ended December 31 (Canadian dollar in thousands)		2010	2009
Cash provided by (used in) the following activities:
OPERATING
Net earnings (loss)		$(38,798)	$26,158
Add (Deduct) items not involving cash:
	Depletion, depreciation and accretion	79,586	66,562
	Stock-based compensation	5,063	4,562
	Financing charges - non-cash portion	6,970	5,061
	Defined benefit plan expense (note 9.1)	426	651
	Future income tax recovery	(12,496)	(5,704)
	Unrealized loss on risk management contracts - net (note 13.2)	14,343	4,520
	Gain on repurchase of Second Lien Senior Notes	-	(2,271)
	Share of loss, dilution loss and impairment loss in Petrolifera Petroleum Limited (note 6)	21,393	7,480
	Unrealized foreign exchange gain (note 13.2)	(39,603)	(94,497)
Cash flow from operations before working capital		36,884	12,522
and other changes
Contribution to defined benefit plan (note 9.1)		(517)	(234)
Asset retirement expenditures (note 8)		(647)	(142)
Changes in non-cash working capital (note 17.2)		(24,935)	(17,300)
		10,785	(5,154)
FINANCING
Proceeds on issue of common shares (note 11.1)		27,282	203,098
Share issue costs		(1,489)	(10,560)
Issuance of First Lien Senior Notes		-	212,218
Debt issue cost of First Lien Senior Notes		-	(7,503)
Repurchase of Second Lien Senior Notes		-	(2,901)
		25,793	394,352
INVESTING
Capital expenditures		(236,687)	(313,894)
Proceeds on disposition of property, plant and equipment		1,721	-
Investments in Petrolifera Petroleum Limited		-	(12,029)
Changes in non-cash working capital (note 17.2)		(34,797)	(14,948)
		(269,763)	(340,871)
NET (DECREASE) INCREASE IN CASH		(233,185)	48,327
Foreign exchange loss on cash balances held in foreign currency		(4,070)	(15,203)
CASH, BEGINNING OF YEAR		256,787	223,663

CASH, END OF YEAR		$19,532	$256,787

For supplementary cash flow information - see note 17

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

Notes to the Consolidated Financial Statements
Years ended December 31, 2010 and 2009

1. Nature of Operations and Organization

Connacher Oil and Gas Limited ("Connacher" or "the company") is a publicly traded integrated energy company headquartered in Calgary, Alberta, Canada.

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 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.

The company also has an investment in Petrolifera Petroleum Limited ("Petrolifera"), which has been accounted for on the equity basis. Petrolifera is engaged in petroleum and natural gas exploration, development and production activities in South America. See note 6.2.

2. Significant Accounting Policies

2.1 Principles of consolidation and preparation of financial statements

The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (''Canadian GAAP'') and include the accounts of the company and its subsidiaries after the elimination of intercompany balances and transactions. Some of the company's upstream activities are conducted jointly with third parties and accordingly these consolidated financial statements reflect the company's proportionate share of these activities. All amounts are presented in Canadian dollars unless otherwise specified.

2.2 Cash and cash equivalents

Cash and cash equivalents consist of cash on hand and short term deposits with initial maturities of equal to or less than three months. There were no short term deposits as at December 31, 2010 and December 31, 2009.

2.3 Inventories

Inventories are stated at the lower of cost or net realizable value. Cost is determined following the weighted average cost method. Previous impairment write-downs are reversed when or if there is a change in the situation that caused the impairment.

2.4 Property, plant and equipment

Petroleum and natural gas - Upstream

The company follows the full cost method of accounting whereby all costs relating to the exploration for and development of bitumen, crude oil and natural gas reserves is capitalized on a country by country cost centre basis. Such costs include land acquisition, geological and geophysical activity, drilling of productive and non-productive wells, asset retirement costs, carrying costs directly related to unproved properties and administrative and interest costs directly related to exploration and development activities. Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred.

Capitalized costs of petroleum and natural gas properties, plant and related equipment within a cost centre are depleted and depreciated using the unit-of-production method, based on estimated proved reserves, before royalties, as determined by the company's independent reservoir engineers. For the purpose of this calculation, production and reserves of natural gas are converted to equivalent units of crude oil based on relative energy content (6 Mcf:1 barrel). Costs subject to depletion and depreciation include the estimated future costs required to develop proved reserves. Proceeds from dispositions are normally credited to oil and gas properties and a gain or loss is not recognized, unless the gain or loss changes the depletion rate by 20 percent or more.

Costs of acquiring and evaluating unproved properties are excluded from costs subject to depletion and depreciation until it is determined whether or not proved reserves are attributable to the properties, or the property is determined to be impaired. Costs associated with major development projects are excluded from costs subject to depletion and depreciation until the property becomes capable of production or development activity ceases or the property is determined to be impaired.

Impairment losses are recognized when the carrying amount of a cost centre exceeds the sum of:

the undiscounted cash flows expected to result from production of proved reserves, based on forecast oil and gas prices and costs;
the cost of unproved properties, less impairment; and
the cost of major development projects, less impairment.

The amount of impairment loss is determined to be the amount by which the carrying amount of the cost centre exceeds the sum of:

the fair value of proved and probable reserves, calculated using a present value technique that uses the cash flows expected to result from production of the proved and probable reserves, discounted using an appropriate rate; and
the cost, less impairment, of unproved properties and major development projects.

Refining - Downstream

Depreciation and amortization of refining assets are calculated based on estimated useful lives and salvage values. When assets are placed into service, estimates are made with respect to their useful lives that are believed to be reasonable. However, factors such as competition, regulation or environmental matters could cause changes to estimates, thus impacting the future calculation of depreciation and amortization. Depreciation is provided using the straight-line method, based on estimated useful lives of assets, which range from three to sixteen years.

Long-lived refining assets are also evaluated for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset's carrying value exceeds its fair value. Estimates of future cash flows and fair values of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates.

The refining assets require regular major maintenance and repairs, which are commonly referred to as ''turnarounds''. The required frequency of the maintenance varies by asset type and occurs generally every three to four years. The costs of turnarounds are recorded as capital costs if they meet the definition of a capital asset and are amortized on a straight-line method over the period of the life of that capital asset. Normal repairs and maintenance costs that do not meet the criteria for recognition as an asset are charged to earnings when they arise.

Furniture, equipment and leaseholds - Corporate

Furniture and equipment are recorded at cost and are depreciated on a declining balance basis at rates of 20 percent to 30 percent per year. Leaseholds are amortized over the lease term.

2.5 Investment in Petrolifera Petroleum Limited ("Petrolifera")

The investment in Petrolifera is accounted for on the equity basis, whereby the carrying value reflects the company's initial cost of its investment, the company's equity interest share of its accumulated income (loss) and other comprehensive income (loss) and the dilution gains and losses resulting from the issuance of additional shares by the investee, net of any permanent impairment in the value of investment.

2.6 Income taxes

The company follows the liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributed to differences between the amounts reported in the financial statements and their respective tax bases, using substantively enacted income tax rates. The effect of a change in income tax rates on future income tax assets and liabilities is recognized in income in the period during which that change occurs. Future tax assets recognized are assessed by management at each balance sheet date for impairment. An impairment is recognized when management assesses that it is not more likely than not that the asset will be recovered.

2.7 Goodwill

Goodwill is the excess of purchase price over fair value of net assets acquired in a business combination. Goodwill is not amortized and is subject to impairment test at least on an annual basis, or more frequently, if there are indicators of impairment. Goodwill and all other assets and liabilities have been allocated to the company's segments, referred to as reporting units. To assess impairment, the fair value of each reporting unit is determined and compared to the carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, then a second test is performed to determine the amount of the impairment. The amount of the impairment is 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. Any excess of the carrying value of goodwill over the implied fair value of goodwill is the impairment amount.

2.8 Asset retirement obligations

The company recognizes an asset retirement obligation for abandoning petroleum, natural gas and bitumen wells, related facilities, compressors and gas plants, removal of equipment from leased acreage and for returning such land to its original condition, by estimating and recording the fair value of each asset retirement obligation arising in the period a well or related asset is drilled, constructed or acquired. This fair value is estimated using the present value of the estimated future cash outflows to abandon the asset at the company's credit adjusted risk-free interest rate and includes estimates for inflation. The obligation is reviewed regularly by management, based upon current regulations, costs, technologies and industry standards. The discounted obligation is initially capitalized as part of the carrying amount of the related upstream property, plant and equipment and a corresponding liability is recognized. The liability is accreted against earnings until it is settled, or the property is sold and is included as a component of depletion, depreciation and accretion expense. The amount of the capitalized retirement obligation is depleted and depreciated on the same basis as the other capitalized upstream property, plant and equipment. Actual abandonment and reclamation expenditures are charged to the accumulated obligation as incurred and costs of properties disposed are removed.

2.9 Employee future benefits

The company maintains a defined benefit pension plan and defined contribution savings plans. The costs associated with the defined benefit pension plan are actuarially determined using the projected benefit method, prorated on service and management's best estimate of expected plan investment performance, salary escalation and retirement ages of employees. The expected return on plan assets is based on the fair value of those assets. The cost of the company's portion of the defined contribution savings plans is expensed as incurred.

2.10 Convertible debentures

On initial recognition, the convertible debentures were classified into debt and equity components at fair value. The fair value of the liability component was determined as the present value of the principal and interest payments, discounted using the company's incremental borrowing rate for debt with similar terms but without a conversion feature. The amount of the equity component was determined as a residual, after deducting the amount of the liability component from the face value of the debentures. Subsequent to the initial recognition, the liability component is remeasured at amortized cost using the effective interest rate method. The equity component is not remeasured subsequent to initial recognition.

2.11 Stock-based compensation

Employee stock options

The fair value of each stock option granted is estimated on the date of grant using the Black-Scholes option pricing model. The amount is expensed or capitalized and credited to contributed surplus over the vesting period. Upon exercise of the options, the exercise proceeds, together with amounts previously credited to contributed surplus, are credited to share capital. On the occurrence of forfeitures, accrued compensation for an unvested option is adjusted to earnings by decreasing the compensation cost in the period of actual forfeiture.

Share award plan for non-employee directors

Obligations for payments in common shares under the company's share award plan for non-employee directors are accrued as stock-based compensation expense and liabilities over the vesting period. Fluctuations in the price of the company's common shares change the accrued compensation expense and are recognized over the remaining vesting period.

2.12 Flow-through shares

The resource expenditure deductions, for income tax purposes, related to exploratory and development activities funded by flow-through share arrangements are renounced to investors in accordance with tax legislation. Accordingly, share capital is reduced and the future income tax liability is increased by the tax benefits related to the expenditures at the time they are renounced.

2.13 Foreign currency translation

Monetary assets and liabilities denominated in foreign currency are translated at the rate of exchange prevailing on the balance sheet date. Gains or losses resulting from these translation adjustments are included in statement of operations. Non-monetary assets and liabilities and revenue and expenses are recorded using monthly average rates of exchange.

The accounts of self-sustaining foreign operations are translated to Canadian dollars using the current rate method. Assets and liabilities are translated at the rate of exchange prevailing on the balance sheet date and revenues and expenses are translated at the monthly average exchange rate for the period. Gains and losses on the translation of self-sustaining foreign operations are included in other comprehensive income (loss). MRCI's operations are considered self-sustaining for the purposes of these consolidated financial statements.

2.14 Financial instruments

Non-derivative financial instruments

Non-derivative financial instruments comprise cash, accounts receivable, accounts payable and accrued liabilities and long-term debt. Non-derivative financial instruments are recognized initially at fair value plus any directly attributable costs. Subsequent to initial recognition, non-derivative financial instruments are classified as follows with their respective subsequent measurement basis:


Non-derivative financial instrument	Classification	Subsequent measurement basis
Cash	Held for trading	Fair value
Accounts receivable	Held for trading	Fair value
Accounts payable and accrued liabilities	Held for trading	Fair value
Long-term debt (Revolving Credit Facility)	Other liabilities	Amortized cost. Transaction costs are amortized over the term of the facility using the straight line method.
Long-term debt (First and Second Lien Senior Notes)	Other liabilities	Amortized cost. Transaction costs are amortized using the effective interest rate method.

Derivative financial instruments

The company enters into certain derivative 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 derivative contracts as effective accounting hedges and thus has not applied hedge accounting. As a result, all derivative contracts are classified as "held for trading" and recorded on the balance sheet at fair value at each reporting date. Realized gains or losses from derivative contracts related to crude oil and gasoline commodity price contracts are recognized in revenue as the related sales occur. Realized gains or losses from derivative contracts related to natural gas costs are recognized in expenses as the related natural gas costs are incurred. Unrealized gains and losses on the derivative contracts are recorded as revenue or expenses based on the mark-to-market calculations at the end of each respective reporting period. 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.

2.15 Revenue recognition

Revenues from the sale of crude oil, natural gas, natural gas liquids, bitumen, purchased commodities and refined petroleum products are recorded when title passes to an external party and payment has either been received or collection is reasonably certain. Sales between the business segments of the company are eliminated from revenues and expenses.

Revenues received prior to bringing an item of property, plant and equipment into its substantial completion and productive use are credited to the capitalized costs of the property, plant and equipment.

2.16 Measurement uncertainty

The timely preparation of the consolidated financial statements in conformity with Canadian GAAP requires that management make estimates and assumptions and use judgment regarding the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the consolidated financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur.

Amounts recorded for depletion, depreciation and accretion expense, asset retirement costs and obligations and amounts used in impairment tests for goodwill and property, plant and equipment are based on estimates. These estimates include petroleum and natural gas reserves, future petroleum and natural gas prices, future interest rates and future costs required to develop those reserves and other fair value assumptions. By their nature, these estimates are subject to measurement uncertainty and changes in such estimates in future years could be material.

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.

The estimated fair value of the investment in Petrolifera involves estimates which, by their nature, are subject to uncertainty.

The estimated fair value of derivative instruments involves the estimates of forecast commodity price and volatility and accordingly, is subject to measurement uncertainty.

Tax interpretations, regulations and legislation in the jurisdictions in which the company and its subsidiary and Petrolifera operate are subject to change.

Amounts recorded for stock-based compensation expense are based 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.

2.17 Per share amounts

Basic per share amounts are calculated using the weighted average number of common shares outstanding for the year. The company follows the treasury stock method to calculate diluted per share amounts. The treasury stock method assumes that any proceeds from the exercise of in-the-money stock options and other dilutive instruments, plus the amount of stock-based compensation not yet recognized would be used to purchase common shares at the average market price during the period.

2.18 Reclassifications

Certain information provided for the prior year has been reclassified to conform to the presentation adopted in 2010.

3. Recent Accounting Pronouncements

3.1 International Financial Reporting Standards ("IFRS"):

Effective January 1, 2011, the company will be required to report its consolidated financial statements in accordance with IFRS and restate the comparative information for year ended December 31, 2010. The company is in final phase of the assessment of the significant impacts on its consolidated financial statements relating to the conversion to IFRS.

4. Inventories


As at December 31 (Canadian dollar in thousands)	2010	2009
Raw materials	$10,222	$13,456
Finished products	40,267	18,185
Chemicals and supplies	6,655	5,230
	$57,144	$36,871

As a result of improved commodity prices, Connacher reversed the previous write-down totaling $1.4 million and $9 million in 2010 and 2009, respectively. These reversals are included in "Downstream-Crude Oil Purchases and Operating Costs".

5. Property, plant and equipment


	As at December 31, 2010			As at December 31, 2009
(Canadian dollar in thousands)	Cost	Accumulated Depletion & Depreciation	Net Book Value	Cost	Accumulated Depletion & Depreciation	Net Book Value
Upstream	$1,539,693	$231,988	$1,307,705	$1,303,276	$167,538	$1,135,738
Downstream	107,615	26,398	81,217	105,789	18,075	87,714
Furniture, equipment and leaseholds	14,400	7,798	6,602	12,272	5,468	6,804
	$1,661,708	$266,184	$1,395,524	$1,421,337	$191,081	$1,230,256

In 2010, the company capitalized $5.1 million (2009 - $5.0 million) of general and administrative expenses, $1.7 million (2009 - $1.1 million) of stock-based compensation costs and $38.3 million (2009 - $52.4 million) of interest and financing costs related to upstream property, plant and equipment.

As at December 31, 2010, costs relating to unproved properties totaling $118.7 million (2009 - $96.9 million) were excluded from costs subject to depletion and depreciation. As at December 31, 2010, future development costs of approximately $1.4 billion (2009 - $1.4 billion) were included in costs subject to depletion.

Effective October 1, 2010, the capitalized costs relating to the company's second oil sands project, Algar, were added to the full cost pool for depletion and ceiling test calculations and the revenues, expenses and finance charges associated with the project after October 1, 2010 have been recorded in the statement of operations. Prior to October 1, 2010, Algar was considered a major development project and all costs, including financing costs and expenses net of revenues were capitalized and were not subjected to depletion.

Connacher's petroleum and natural gas reserves were evaluated by qualified independent evaluators as at December 31, 2010 using the following forecast price assumptions. Based on these assumptions, the company completed a ceiling test of its upstream property, plant and equipment and determined no impairment was required for 2010 and 2009.


	2011	2012	2013	2014	2015	2016	2017	2018	2019	2020	2021+
Heavy oil @ Hardisty ($Cdn/bbl)	$68.79	$68.33	$67.03	$67.84	$70.23	$72.03	$74.08	$75.95	$78.00	$79.59	+2.0%/yr
WTI @ Cushing (US$/bbl)	88.00	89.00	90.00	92.00	95.17	97.55	100.26	102.74	105.45	107.56	+2.0%/yr
Alberta Spot (CDN$/mmbtu)	$4.16	$4.74	$5.31	$5.77	$6.22	$6.53	$6.76	$6.90	$7.06	$7.21	+2.0%/yr

6. Investment in Petrolifera Petroleum Limited ("Petrolifera")


As at December 31 (Canadian dollar in thousands)		2010	2009
Balance, beginning of year		$50,379	$46,659
Effect of items recorded in consolidated statement of operations
	Share of loss	(1,847)	(2,468)
	Dilution loss (note 6.1)	(4,273)	(5,012)
	Accumulated impairment (note 6.2)	(15,273)	-
		(21,393)	(7,480)
Acquisition of units (note 6.3)		-	12,029
Share of other comprehensive loss		(1,048)	(829)
Balance, end of year		$27,938	$50,379

As at December 31, 2010 and December 31, 2009, Connacher owned 26.9 million Petrolifera common shares, representing 18.5 percent as at December 31, 2010 and 22 percent as at December 31, 2009, of Petrolifera's issued and outstanding common shares and 6.8 million Petrolifera share purchase warrants.

6.1			In April 2010, Petrolifera closed a public offering of 23,678,500 common shares at a price of $0.85 per common share for gross proceeds of $20.1 million (the "Offering"). Connacher did not subscribe for shares in the Offering and accordingly, Connacher's equity interest in Petrolifera was reduced to 18.5 percent from 22 percent. The reduction in the ownership interest resulted in a dilution loss of $4.3 million for the year ended December 31, 2010.
6.2			In January 2011, Petrolifera entered into an agreement with Gran Tierra Energy Inc. ("Gran Tierra Energy") pursuant to which Gran Tierra Energy would acquire all of the issued and outstanding common shares and common share purchase warrants of Petrolifera. Under the terms of the agreement, Connacher would receive 0.1241 of a common share and common share purchase warrant of Gran Tierra Energy for each Petrolifera common share and common share purchase warrant held. The transaction is subject to the approval of the shareholders of Petrolifera. As at December 31, 2010, Connacher performed an impairment test of its investment in Petrolifera by comparing the carrying amount of the investment with its fair value. This resulted in an impairment loss of $15.3 million which was recognized in 2010.
6.3			In 2009, Petrolifera issued 66.5 million units from treasury to raise gross proceeds of $58 million. Each unit was comprised of one Petrolifera common share and one-half Petrolifera share purchase warrant. 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. Connacher subscribed for 13,556,000 units at a cost of $11.9 million. In addition, in 2009, Connacher exercised its previously held option (see below) to purchase an additional 200,000 Petrolifera common shares at $0.50 per common share at a cost of $100,000.

In consideration for the assistance provided by the company in 2005 to Petrolifera in securing two Peruvian licenses for exploratory lands and for the provision of financial guarantees respecting Petrolifera's annual work commitments on the two licensed blocks, Connacher was granted a five-year option to acquire 200,000 common shares at $0.50 per share (note 6.1) and was granted a 10 percent carried working interest ("CWI") through the drilling of the first well on each block. Petrolifera has the right of first purchase of this CWI should Connacher elect to sell it at some future date. The CWI is convertible at Connacher's election into a two percent gross overriding royalty on each license, after the drilling of the first well on each block. In 2010, Connacher was fully released from the provision of financial guarantees. The company will continue to own the CWI and related rights after the closing of the transaction described in note 6.2.

Under the terms of an Administrative Services Agreement, dated January 1, 2008 with Petrolifera, Connacher provided certain general and administrative services to Petrolifera. The fee for this service was $15,000 per month. Petrolifera paid Connacher $180,000 in 2010 (2009 - $180,000) under the Administrative Services Agreement. Petrolifera also reimbursed Connacher for certain other out-of-pocket expenses incurred by Connacher on Petrolifera's behalf. The agreement will be terminated upon closing of the transaction described in note 6.2.

7. Long-term Debt


As at December 31 (Canadian dollar in thousands)	2010	2009
Convertible Debentures, Due June 30, 2012 (CAD$100 million) (note 7.1)	$100,014	$100,014
First Lien Senior Notes, Due July 15, 2014 (US$200 million) (note 7.2)	198,920	210,200
Second Lien Senior Notes, Due December 15, 2015 (US$587 million) (note 7.3)	584,168	617,294
	883,102	927,508
Unamortized discount and transaction costs	(39,501)	(51,327)
Long-term debt	$843,601	$876,181

7.1 Convertible Debentures, Due June 30, 2012

In May 2007, Connacher issued subordinated unsecured Convertible Debentures with a face value of $100,050,000. Interest is payable semi-annually on June 30 and December 31 at the rate of 4.75 percent. The Convertible Debentures mature on June 30, 2012, unless converted prior to that date. The Convertible Debentures are convertible at any time into common shares, at the option of the holder, at a conversion price of $5.00 per share.

The Convertible Debentures are redeemable on or after June 30, 2010 by the company, in whole or in part, at a redemption price equal to 100 percent of the principal amount of the Convertible Debentures to be redeemed, plus accrued and unpaid interest, provided that the market price of the company's common shares is at least 120 percent of the conversion price of the Convertible Debentures.

As at the date of issuance, the value of the conversion feature of the Convertible Debentures was accounted for as a separate component of equity in the amount of $16.8 million.

In June 2009, $36,000 principal amount of Convertible Debentures were converted into 7,200 common shares. Accordingly, a portion of each of the liability and equity components of the debentures, together with the principal amount, were transferred to share capital and no gain or loss was recorded.

7.2 First Lien Senior Notes, Due July 15, 2014

In June 2009, the company issued US$200 million of First Lien Senior Notes ("FLSN"). Interest is payable semi-annually at a rate of 11.75 percent on January 15 and July 15 each year the FLSN is outstanding and the principal is to be repaid on July 15, 2014. The FLSN are secured on a first priority basis (subject to specific liens up to US$50 million for the Revolving Credit Facility - note 7.4) by liens on all of the company's assets, excluding certain pipeline assets in the USA and the company's investment in Petrolifera.

The company may redeem some or all of the FLSN at their principal amount, plus a make whole premium, if such redemption occurs prior to July 15, 2011. The company may redeem up to 35 percent of the FLSN prior to July 15, 2011 at a redemption price of 111.75 percent of the principal amount, plus accrued interest, with the proceeds of certain equity offerings, provided that at least 65 percent of the aggregate principal amount of the FLSN remains outstanding on existing terms. After July 15, 2011, the FLSN may be redeemed at redemption prices ranging from 105.875 percent, reducing to 100 percent on July 15, 2013 and thereafter.

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

7.3 Second Lien Senior Notes, Due December 15, 2015

In December 2007, the company issued US$600 million of Second Lien Senior Notes ("SLSN"). Interest is payable semi-annually at a rate of 10.25 percent on June 15 and December 15 each year the SLSN is outstanding and the principal is to be repaid on December 15, 2015. The SLSN are secured by a second lien covering all of the company's assets, with the exception of certain pipeline assets in the USA and the company's investment in Petrolifera.

The company may redeem some or all of the SLSN at their principal amount plus a make whole premium, if such redemption occurs prior to December 15, 2011. After December 15, 2011, the SLSN may be redeemed at redemption prices ranging from 105.125 percent, reducing to 100 percent on December 15, 2013, and thereafter.

In 2009, the company repurchased a total face value of SLSN of US$4.7 million (CAD$5.1 million) in the market at a discount and cancelled the repurchased SLSNs. No similar repurchases were made in 2010.

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

7.4 Revolving Credit Facility

The company has a US$50 million revolving credit facility (the "Facility"). In 2010, the Facility was amended to extend the maturity to November 24, 2013, to reduce certain interest costs and to remove an interest coverage covenant. The two remaining financial covenants are:

Total debt (excluding the convertible debentures) to total capitalization (defined to include all debt, convertible debentures and share holders' equity) shall not be greater than 70 percent, declining to 65 percent when production from Algar exceeds 8,000 bbl/d for a period of 30 consecutive days; and
debt outstanding under the Facility to EBITDA (defined to include Earnings before Finance charges, Taxes, Depletion, Depreciation and Accretion, Risk management contract gains or losses, Share of loss, dilution loss and impairment loss in Petrolifera, Stock-based compensation expense, Employee benefits cost, Gain or loss on disposition of property, plant and equipment and Foreign exchange gains or losses) shall not be greater than 2.0:1.

The company has been in compliance with all covenants throughout 2009 and 2010.

The Facility ranks ahead of the company's First and Second Lien Senior Notes. It is secured by a first lien charge on all of the company's assets, excluding certain pipeline assets in the USA and the company's investment in Petrolifera. Borrowings are available as Canadian bankers acceptances, Canadian prime rate, LIBOR-base loans or US-dollar base rate loans. For the amounts drawn under the Facility, interest is payable quarterly at floating rates of lenders' Canadian prime rate, a U.S. base rate, a Bankers' Acceptance rate, or at a LIBOR rate plus applicable margins. At December 31, 2010, $5.7 million of letters of credit were issued and outstanding pursuant to the Facility. In 2010, the weighted average interest rate on the Facility was 7.8 percent per annum.

The following table reconciles the beginning and ending balance of transaction costs of the Facility recorded as a part of prepayments and other assets:


For the years ended December 31 (Canadian dollar in thousands)	2010	2009
Balance, beginning of year	$1,440	$-
Paid during the year	251	2,456
Amortization expense for the year	(752)	(1,016)
Total	939	1,440
Less: current portion	(324)	(732)
Prepayments and other assets - non-current	$615	$708

7.5 Principal Repayments Due

Principal repayments for all the aforementioned loans are due as follows:


As at December 31 (Canadian dollar in thousands)	2010	2009
2011	$-	$-
2012	100,014	100,014
2013	-	-
2014	198,920	210,200
2015	584,168	617,294
Total	$883,102	$927,508

7.6 Finance charges


For the years ended December 31 (Canadian dollar in thousands)	2010	2009
Interest expense on long-term debt	$101,018	$94,549
Amortization of transaction costs relating to the Facility	752	1,016
Stand by fees relating to the Facility	999	648
Bank charges and other fees	398	499
	103,167	$96,712
Less: Interest capitalized (note 7.6.1)	(38,290)	(52,358)
Finance charges - net	$64,877	$44,354

7.6.1 Capitalized interest relates to the construction of the Algar project and has been included as a part of cost of upstream property, plant and equipment. Effective October 1, 2010, capitalization of interest ceased (note 5).

8. Asset Retirement Obligations

The following table reconciles the beginning and ending aggregate carrying amount of the obligation associated with the company's retirement of its upstream petroleum and natural gas properties and facilities.


For the year ended December 31 (Canadian dollar in thousands)	2010	2009
Balance, beginning of year	$ 32,848	$26,396
Liabilities incurred	4,339	6,194
Liabilities settled	(647)	(142)
Liabilities disposed	(264)	-
Change in estimates	-	(1,803)
Accretion expense	2,915	2,203
Balance, end of year	$39,191	$32,848

At December 31, 2010, the estimated total undiscounted amount required to settle the asset retirement obligations was $87.0 million (December 31, 2009 - $72.0 million). These obligations are expected to be settled over a period of 25 years. This amount has been discounted using credit-adjusted risk-free rates of interest ranging between 6 percent to 10 percent, depending on the year in which the obligation was incurred and after provision for inflation at 2 percent per annum.

The company has not recorded an asset retirement obligation for the Refining property, plant and equipment as it is currently the company's intent to maintain and upgrade the refinery so that it will be operational for the foreseeable future. Consequently, it is not possible at the present time to estimate a date or range of dates for settlement of any asset retirement obligation related to the refinery.

9. Employee Future Benefits

The company maintains the following retirement/savings plans for its employees: a defined benefit pension plan and a defined contribution savings plan for its USA based employees and a defined contribution savings plan for its Canadian employees.

9.1 Defined benefit pension plan for USA employees

The company's USA subsidiary, MRCI, maintains a non-contributory defined benefit retirement plan (the "Defined Benefit Plan") covering MRCI's employees. MRCI's policy is to make regular contributions in accordance with the funding requirements of the United States Employee Retirement Income Security Act of 1974, as determined by regular actuarial valuations. The company's defined benefit obligation is based on the employees' years of service and compensation, effective from and after, March 31, 2006, the date that Connacher acquired MRCI. The information relating to the Defined Benefit Plan is as follows:

Defined Benefit Plan Obligation


For the years ended December 31 (Canadian dollar in thousands)	2010	2009
Defined benefit plan obligation, beginning of year	$1,225	$1,470
Current service cost	409	623
Interest cost	121	97
Actuarial loss (gain)	1,193	(755)
Benefits paid	(166)	(13)
Foreign exchange gain	(175)	(197)
Defined benefit plan obligation, end of year	$2,607	$1,225

Defined Benefit Plan Assets


For the years ended December 31 (Canadian dollar in thousands)	2010	2009
Fair value of defined benefit plan assets, beginning of year	$881	$640
Actual return on plan assets	133	141
Employer contributions	517	234
Benefits paid	(166)	(13)
Foreign exchange loss	(66)	(121)
Fair value of defined benefit plan assets, end of year	$1,299	$881

Funded Status of the Defined Benefit Plan


As at December 31 (Canadian dollar in thousands)	2010	2009
Defined benefit plan obligation, end of year	$2,607	$1,225
Fair value of defined benefit plan assets, end of year	(1,299)	(881)
Excess defined benefit obligation	1,308	344
Unamortized net actuarial (loss) gain	(393)	722
Accrued defined benefit obligation	$915	$1,066


Weighted average assumptions used in	Accrued Benefit Obligation		Defined benefit plan expense
(percent)	2010	2009	2010	2009
Discount rate	6.3	7.9	7.9	5.8
Expected long-term rate of return on plan assets	n/a	n/a	8.9	9.8
Long-term rate of increase in compensation level	3.0	3.0	3.0	3.0

The expense relating to the Defined Benefit Plan was included in Downstream - crude oil purchases and operating expenses and comprised the following:


(Canadian dollar in thousands)	2010	2009
Current service cost	$409	$623
Interest cost	121	97
Expected return on plan assets	(93)	(69)
Amortization of net actuarial (gain) loss	(11)	-
Net defined benefit plan expense	$426	$651

The company amortizes the portion of the unrecognized actuarial gains or losses that exceed 10 percent of the greater of the accrued benefit obligation or fair value of benefit plan assets. The gains or losses that are in excess of 10 percent are amortized over the expected future years of service which was 15.7 years as at December 31, 2010 (December 31, 2009 - 15.6 years).

MRCI is responsible for administering the Defined Benefit Plan and has retained the services of an independent and professional investment manager, as fund manager, for the related investment portfolio. Among the factors considered in developing the investment policy are the Defined Benefit Plan's primary investment goal, rate of return objective, investment risk, investment time horizon, role of asset classes and asset allocation. The expected rate of return on plan assets is based on historical and projected rates of return for each asset class in the plan investment portfolio. The objective of the plan's asset allocation policy is to manage the funded status of the plan at an appropriate level of risk, giving consideration to the security of the assets and the potential volatility of market returns and the resulting effect on both contribution requirements and pension expense. The long-term return is expected to achieve or exceed the return from a composite benchmark comprised of passive investments in appropriate market indices. The asset allocation structure is subject to diversification requirements and constraints which reduce risk by limiting exposure to individual equity investments, credit rating categories and foreign currency exposures. The company expects to contribute US $500,000 to the plan in 2011.

The composition of the Defined Benefit Plan asset was as follows:

Estimated future benefits payments under the Defined Benefit Plan are as follows:


(Canadian dollar in thousands)							As at December 31, 2010
2011							$50
2012							63
2013							96
2014							107
2015							119
2016 to 2020							799
Total							$1,234

9.2 Defined contribution savings plan for USA Employees

MRCI also maintains a defined contribution (US tax code "401(k)") savings plan that covers all of its employees. MRCI's contributions are based on employees' compensation and partially match employee contributions. In 2010, MRCI contributed $367,000 which was recorded to "Downstream - crude oil purchases and operating costs" (2009 - $400,000) to this plan to satisfy, in full, its obligation under this plan.

9.3 Defined contribution savings plan for Canadian employees

The company also maintains a defined contribution savings plan for its Canadian employees, whereby the company matches employee contributions to a maximum of eight percent of each employee's salary. In 2010, the company contributed $1.3 million (2009 - $839,000) which was recorded to general and administrative expenses to satisfy, in full, its obligation under this plan.

10. Income Taxes

The provision for income taxes in the consolidated statement of operations reflects an effective tax rate which differs from the expected statutory tax rate. These differences are presented below:


For the years ended December 31 (Canadian dollar in thousands)	2010	2009
Earnings (loss) before income taxes	$(51,585)	$18,853
Canadian statutory rate	28.05%	29.1%
Expected income tax expense (recovery)	(14,470)	5,486
Impact of reduction in Canadian tax rates	3,563	1,329
Foreign taxes	(752)	(756)
Capital taxes	437	402
Non taxable portion of foreign exchange gains	(5,968)	(16,302)
Impairment and dilution loss in Petrolifera	3,000	1,210
Non deductible stock-based compensation costs	1,403	1,326
Recovery of income taxes	$(12,787)	$(7,305)

The net future income tax liability comprises the tax effect of the following temporary differences:


As at December 31 (Canadian dollar in thousands)		2010	2009
Future income tax liability
	Property, plant and equipment	$175,983	$131,541
	Investment in Petrolifera	427	3,109
	Long-term debt	7,355	3,472
		183,765	138,122
Future income tax asset
	Non-capital losses carried forward	132,919	87,976
	Financing and share issue costs	4,885	7,871
	Asset retirement obligation	9,818	8,238
	Capital losses carried forward	8,523	8,560
	Risk management contracts and others	7,231	1,935
		163,376	114,580
	Less: valuation allowance	(24,473)	(24,153)
		138,903	90,427
Net future income tax liability		44,862	47,695
Less: current portion of future income tax asset		4,497	2,348
Net future income tax liability - non-current		$49,359	$50,043

The approximate amount of total income tax pools available as at December 31, 2010 were $1,248 million in Canada and $48 million in the USA (2009 - $1,075 million in Canada and $53 million in the USA), including non-capital losses of approximately $503 million in Canada and $18 million in the USA, which expire over time to 2030 and $34 million of net capital losses in Canada, which are available to reduce taxable capital gains in future. These capital losses have no expiry and their future income tax benefit has not been recognized due to uncertainty of their realization at December 31, 2010 and 2009.

11. Share Capital

Authorized: unlimited number of common voting shares

Authorized: unlimited number of first preferred shares of which none are outstanding

Authorized: unlimited number of second preferred shares of which none are outstanding

11.1 Issued and outstanding common share capital


For the years ended December 31		2010		2009
(Canadian dollar in thousands except number of shares)	Number	Amount	Number	Amount
Balance, beginning of year	427,031,362	$590,845	211,181,815	$395,023
Issued for cash (note 11.2)	-	-	191,762,500	172,586
Issued for cash on flow-through basis (note 11.3)	17,480,000	25,346	23,172,500	30,124
Shares issued upon exercise of stock options (note 12.2)	2,017,836	1,936	579,724	388
Assigned value of stock options exercised (note 12.1)		1,082		183
Conversion of debentures (note 7.1)	-	-	7,200	36
Shares issued to directors as compensation (note 12.3)	638,496	1,002	327,623	302
Share issue cost, net of future income tax of $426 (2009 - $2,763)		(1,063)		(7,797)
Tax effect of flow-through shares (note 11.3)		(7,549)		-
Balance, end of year	447,167,694	$611,599	427,031,362	$590,845

11.2	In June 2009, the company issued 191,762,500 common shares at $0.90 per common share for gross proceeds of $172.6 million.
11.3	In October 2010, 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. The related future income tax liability will be accounted for in 2011. As at December 31, 2010, the total remaining commitments to the qualifying expenditures pursuant to this flow-through share issuances was $25.3 million.
	In October 2009, the company issued 23,172,500 common shares on a flow-through basis at $1.30 per common share for gross proceeds of $30.1 million and renounced the qualifying expenditures to investors effective December 31, 2009. The related tax effect of $7.5 million was recorded in 2010.
12.	Contributed surplus, Stock options and Share award plan for non-employee Directors
12.1	Contributed surplus

The following table shows the changes in contributed surplus.


For the years ended December 31 (Canadian dollar in thousands)	2010	2009
Balance, beginning of year	$30,560	$26,053
Stock based compensation expensed	4,361	3,595
Stock based compensation capitalized	1,664	1,095
Assigned value of stock options exercised	(1,082)	(183)
Balance, end of year	$35,503	$30,560

12.2 Stock options

The company has a stock option plan permitting the issue from time to time of options entitling the holders to acquire common shares up to an aggregate of 10 percent of the number of common shares outstanding less four million common share reserved for directors share awards. Options are granted at the discretion of the Board of Directors on such terms as the board may determine. The options have a term of five years to maturity and vest over the period of two to three years. The following table shows the changes in stock options and the related weighted average exercise prices:


For the years ended December 31	2010		2009
	Number of Options	Weighted Average Exercise Price	Number of Options	Weighted Average Exercise Price
Outstanding, beginning of year	22,579,045	$1.72	16,383,104	$3.16
Granted	10,263,154	1.36	12,318,375	0.96
Exercised	(2,017,836)	0.96	(579,724)	0.67
Forfeited	(3,153,695)	2.15	(945,710)	1.97
Expired	(3,257,000)	2.31	(190,000)	1.35
Cancelled	-	-	(4,407,000)	4.89
Outstanding, end of year	24,413,668	$1.50	22,579,045	$1.72
Exercisable, end of year	13,166,750	$1.73	12,689,028	$2.18

The following table summarizes stock options outstanding and exercisable under the plan.


	As at December 31, 2010			As at December 31, 2009
Range of Exercise Prices	Number Outstanding	Weighted Average Exercise Price	Weighted Average Remaining Contractual Life	Number Outstanding	Weighted Average Exercise Price	Weighted Average Remaining Contractual Life
$0.20 - $0.99	3,598,599	$0.75	3.3	5,089,267	$0.76	3.8
$1.00 - $1.99	17,691,857	1.26	3.9	11,399,047	1.19	4.1
$2.00 - $2.99	15,000	2.10	2.8	1,692,000	2.67	0.9
$3.00 - $3.99	2,573,703	3.62	1.5	3,441,222	3.61	2.4
$4.00 - $4.99	366,509	4.14	1.0	432,509	4.24	1.8
$5.00 - $5.99	168,000	5.04	0.2	525,000	5.04	1.2
	24,413,668	$1.50	3.5	22,579,045	$1.72	3.4

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 years ended ended December 31	2010	2009
Risk free interest rate (percent)	1.9	1.3
Expected option life (years)	3.0	3.0
Expected volatility (percent)	72	72

The weighted average fair value at the date of grant of options granted during the year ended December 31, 2010 was $0.66 per option (2009 - $0.46 per option).

12.3 Share award plan for non-employee Directors

Under the share award plan, share units may be granted to non-employee directors of the company in amounts determined by the Board of Directors on the recommendation of the Governance Committee. Share units vest in January of the year following issue and are settled by issuing common shares from treasury, subject to certain limitations. The Board of Directors may alternatively elect to pay cash equal to the fair market value of the common shares to be delivered to non-employee directors, upon vesting of such share units, in lieu of delivering common shares.


For the year ended December 31 (Number of common share units)	2010	2009
Outstanding, beginning of year	648,916	392,705
Granted	380,598	638,496
Issued	(638,496)	(327,623)
Cancelled	(10,420)	(54,662)
Outstanding, end of year ⁽¹⁾	380,598	648,916
Exercisable, end of year	-	10,420

⁽¹⁾ ^{Vested and issued in January 2011 and January 2010.}

In 2010, $702,000 was recorded as a part of stock based compensation expense and accounts payable and accrued liabilities in respect of outstanding shares under the share award plan (2009 -$967,000).

13. Financial Instruments

Connacher's financial instruments include its cash, accounts receivable, accounts payable and accrued liabilities, risk management contracts and long-term debt.

13.1 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:


As at December 31, 2010 (Canadian dollar in thousands)	Carrying Value	Fair Value
Held for trading
Cash ⁽¹⁾	$19,532	$19,532
Accounts receivable ⁽¹⁾	$57,419	$57,419
Accounts payable and accrued liabilities ⁽¹⁾	$81,886	$81,886
Risk management contracts ⁽²⁾	$18,863	$18,863
Other liabilities
Convertible Debentures ⁽³⁾	$92,762	$96,548
First Lien Senior Notes ⁽³⁾	$184,176	$216,823
Second Lien Senior Notes ⁽³⁾	$566,663	$587,049

⁽¹⁾	^{The fair value of cash is determined based on transaction value and is categorized as a Level 1 measurement. The fair values of accounts receivable and accounts payable and accrued liabilities are determined from transaction values which were derived from observable market input. The fair values of these financial instruments were based on LeveI 2 measurements.}
⁽²⁾	^{The fair values of the risk management contracts were determined using forward prices. These values were derived in part using active quotes and in part using observable market-corroborated data. The fair values of risk management contracts were based on Level 2 measurements}
⁽³⁾	^{The estimated fair values of the long-term debt have been determined based on market information.}

13.2 Risk exposures

The company is exposed to market risks related to the volatility of commodity prices, foreign exchange rates and interest rates. In certain instances, the company uses derivative instruments to manage the company's exposure to these risks. The company is also exposed to credit risk on accounts receivable, to counterparties to risk management contracts and to liquidity risk relating to debt and the fulfillment of its financial obligations. The company employs risk management strategies and policies to ensure that any exposures to risk are in compliance with the company's business objectives and risk tolerance levels. Risk management is ultimately established by the company's Board of Directors and is implemented and monitored by senior management of the company.

Credit risk

Credit risk is the risk that the contracting entity will not fulfill its obligations under a contract when they are due. The company generally extends unsecured credit to customers and therefore, the collection of accounts receivable may be affected by changes in economic or other conditions. Management believes this risk is mitigated by the size and creditworthiness of the companies to which credit has been extended. The company has not historically experienced any material credit loss in the collection of accounts receivable.

Accounts receivable are due from crude oil and natural gas purchasers and joint venture partners in the petroleum and natural gas industry and are subject to normal industry credit risks. The company periodically assesses the financial strength of its crude oil and natural gas purchasers and will adjust its marketing plan to mitigate credit risks. This assessment involves a review of external credit ratings and an internal credit review, based on the purchaser's past financial performance. Generally, the only instances of impairment are when a purchaser or partner is facing bankruptcy or extreme financial distress. Sales made to two upstream customers represented 78 percent of the total upstream sales in 2010 (2009 - three customers represented 90 percent). Sales made to one downstream customer represented 12 percent and 10 percent, respectively of the total downstream sales in 2010 and 2009, respectively. Three upstream customers represented 73 percent of the upstream accounts receivable as at December 31, 2010. One downstream customers comprised 10 percent of the downstream account receivable balances as at December 31, 2010 (2009 - three customers comprised 38 percent). The company considers all amounts due over 90 days as past due. As at December 31, 2010, $1.1 million of accounts receivable were past due, all of which were considered to be collectible.

The company is also exposed to credit risk from counterparties to risk management contracts. This risk is managed by limiting counterparties to investment grade banking institutions; there has been no history of impairment with these counterparties.

The maximum exposure to credit risk relating to the above classes of financial assets at December 31, 2010 and December 31, 2009 is the carrying value of accounts receivable.

Liquidity risk

Liquidity risk is the risk that the company will not have sufficient funds to repay its debts and fulfill its financial obligations. To manage this risk, the company pre-funds major development projects, monitors expenditures against pre-approved budgets to control costs, regularly monitors its operating cash flow, working capital and bank balances against its business plan, maintains accessible revolving banking lines of credit and maintains prudent insurance programs to minimize exposure to insurable losses. Additionally, the long term nature of the company's debt repayment obligations is aligned to the long term nature of its assets. The Convertible Debentures do not mature until June 30, 2012, unless converted to common shares earlier and principal repayments are not required on the First or Second Lien Senior Notes until their maturity dates of July 15, 2014 and December 15, 2015, respectively. The company also has a revolving credit facility of US$50 million, as more fully described in note 7.4, which gives Connacher additional short-term financial flexibility for its working capital requirements. The following table shows the maturities of Connacher's financial liabilities:


As at December 31 (Canadian dollar in thousands)	Total	Within 1 year	1-3 years	4-5 years

Non-derivative liabilities:
Accounts payable and accrued liabilities	$81,886	$81,886	$-	$-
Long-term debt and interest payment obligations ⁽¹⁾	$1,269,840	87,997	540,336	641,507
Derivative-based liabilities:
Risk management contracts	$18,863	$8,984	$9,879	$-

⁽¹⁾ ^{The amounts include the face value of the principal amounts due in Canadian dollar for US$ denominated loans.}

Market risk and sensitivity analysis

Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market prices. Market risk is comprised of commodity price risk, interest rate risk and foreign currency risk. The objective of market risk management is to manage and control market price exposures within acceptable limits, while maximizing returns.

Commodity price risk

The company is exposed to commodity price risk as a result of potential changes in the market prices of its crude oil sales and purchases and bitumen, natural gas and refined product sales. A portion of this risk is mitigated by Connacher's integrated business model. The cost of purchasing natural gas for use in its oil sands and refinery operations is partially offset by the company's conventional natural gas sales. In accordance with policies approved by the Board of Directors, derivative contracts, including petroleum commodity futures contracts, price swaps and collars may be utilized to reduce exposure to price fluctuations associated with a portion of the sales of natural gas, crude oil or bitumen sales volumes and for the sale of refined products.

The following table summarizes the net position of the company's risk management contracts.


As at December 31 (Canadian dollar in thousands)	2010	2009

Current liability	$8,984	$4,520
Non-current liability	9,879	-
Net risk management contracts liability	$18,863	$4,520

The following table shows the net unrealized risk management positions.


As at December 31 (Canadian dollar in thousands)	2010	2009
Crude oil liability - Upstream	$18,120	$4,520
Natural gas liability - Upstream	743	-
Liability, end of year	$18,863	$4,520

The following tables show the details of the risk management positions.

December 31, 2010 - Crude oil contracts - Upstream


Volume (bbl/d)	Term	Type	Price (WTI U.S.$/bbl)	Liability (Asset) as at December 31, 2010 (Canadian dollar in thousands)
1,000	Jan 1, 2011 - Mar 31, 2011	Swap	$86.10	$561
1,000	Jan 1, 2011 - Mar 31, 2011	Swap	$88.10	382
2,000	Apr 1, 2011 - Jun 30, 2011	Swap	$85.25	1,552
2,000	Jan 1, 2011 - Dec 31, 2011	Swap ⁽¹⁾	$90.60	10,392
2,000	Jan 1, 2011 - Mar 31, 2011	Call option	$100.25	162
2,000	Jan 1, 2011 - Mar 31, 2011	Put option	$80.00	(82)
2,000	Apr 1, 2011 - Mar 31, 2012	Call option	$96.00	5,918
2,000	Apr 1, 2011 - Mar 31, 2012	Put option	$80.00	(2,796)
2,000	Jul 1, 2011 - Jun, 2012	Call option	$100.00	5,591
2,000	Jul 1, 2011 - Jun 30, 2012	Put option	$80.00	(3,560)
Balance, as at December 31, 2010				$18,120

⁽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.}

Subsequent to December 31, 2010, the company entered in the following risk management contract:

January 1, 2012 - December 31, 2012 - 2,000 bbl/d at a minimum of WTI U.S.$80.00 bbl/d and a maximum of WTI U.S.$120.00/bbl.

December 31, 2010 - Natural gas contracts - Upstream


Volume (GJ/d)	Term	Type	Price (AECO CAD$/GJ)	Liability as at December 31, 2010 (Canadian dollar in thousands)
4,000	Sept 1, 2010 - Aug 31, 2011	Swap	$3.87	$187
4,000	Oct 1, 2010 - Sept 30, 2011	Swap	$4.20	556
Balance, as at December 31, 2010				$743

December 31, 2009 - Crude oil contracts - Upstream


Volume (bbl/d)	Term	Type	Price (WTI U.S.$/bbl)	Liability as at December 31, 2009 (Canadian dollar in thousands)
2,500	Jan 1 - Dec 31, 2010	Swap	$78.00	$4,115
2,500	Feb 1 - Apr 30, 2010	Swap	$79.02	405
Balance, as at December 31, 2009				$4,520

The following table summarizes the amounts recorded in the statement of operations with respect to the revenue-related risk management contracts.


For the years end December 31		2010		2009
(Canadian dollar in thousands)	Upstream	Downstream ⁽¹⁾	Total	Upstream
Unrealized loss	$13,600	$-	$13,600	$4,520
Realized loss	1,742	543	2,285	20,605
Loss on risk management contracts	$15,342	$543	$15,885	$25,125

⁽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 statement of operations with respect to the operating cost-related upstream risk management contracts.


For the years ended December 31 (Canadian dollar in thousands)	2010	2009
Unrealized loss	$743	$-
Realized loss	558	-
Loss on risk management contracts	$1,301	$-

As at December 31, 2010, had the forward price for WTI been U.S. $1/bbl higher or lower, the impact relating to the crude oil risk management contracts would have been to increase or decrease, respectively, the loss before income taxes by $2.6 million.

As at December 31, 2010, had the forward price for AECO been CAD $0.10/GJ higher or lower, the impact relating to the natural gas risk management contracts would have been to decrease or increase, respectively, the loss before income taxes by $206,000.

Interest rate risk

Interest rate risk refers to the risk that the future cash flows of a financial instrument will fluctuate because of changes in market interest rates. The company's First and Second Lien Senior Notes and Convertible Debentures have fixed interest rate obligations and, therefore, are not subject to changes in interest rates. The Revolving Credit Facility bears floating interest rate. At December 31, 2010, the company had no floating rate debt outstanding under the Facility. Therefore, the potential increase or decrease in net earnings or loss for each one percent change in interest rate was nil.

Currency risk

Currency risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in foreign exchange rates. The company is exposed to fluctuations in foreign currency on its financial instruments primarily as a result of its U.S. dollar denominated long-term debt, crude oil sales based on U.S. dollar indices and commodity price contracts that are settled in U.S. dollars. The effect on the company's financial instruments of a $0.01 change in the U.S. to Canadian dollar exchange rate would have resulted in a $7.6 million change in foreign exchange gain/loss at December 31, 2010. The company's downstream operations operate with a U.S. dollar functional currency, which gives rise to currency exchange rate risk on translation of MRCI's operations. The impact is recorded in other comprehensive income/loss. The effect on the company's financial instruments of a $0.01 change in the U.S. to Canadian dollar exchange rate would have resulted in $84,000 change in other comprehensive income (loss) at December 31, 2010. The company manages these exchange rate risks by occasionally entering into fixed rate currency exchange contracts on future U.S. dollar payments and U.S. dollar sales receipts.

The following table summarizes the components of the company's foreign exchange gain (loss):


For the year ended December 31 (Canadian dollar in thousands)		2010	2009
Unrealized foreign exchange gain (loss) on translation of:
	U.S. denominated First and Second Lien Senior Notes	$42,552	$109,854
	Foreign currency denominated cash balances	(3,241)	(14,062)
	Other foreign currency denominated monetary items	292	(1,295)
Unrealized foreign exchange gain		39,603	94,497
Realized foreign exchange gain ⁽¹⁾		2,038	11,667
Foreign exchange gain		$41,641	$106,164

⁽¹⁾

^{In 2008, Connacher entered into a foreign exchange revenue collar for the calendar year 2009 which set a floor of $11.92 million and a ceiling of $13 million on a notional amount of US $10 million of monthly production revenue. In 2009, a foreign exchange gain of $8.0 million was was realized in respect of this contract.}

14. 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 December 31 (Canadian dollar in thousands)	2010	2009
Long term debt ⁽¹⁾	$843,601	$876,181
Shareholders' equity	650,183	671,588
Total Debt plus Equity ("capitalization")	$1,493,784	$1,547,769
Debt to book capitalization ⁽²⁾	56%	57%

⁽¹⁾ ^{Long-term debt is stated at its carrying value, which is net of transaction costs and the Convertible Debentures' equity component value.}

⁽²⁾ ^{Calculated as long-term debt divided by the book value of shareholders' equity plus long-term debt.}

As at December 31, 2010, the company's net debt (long-term debt, net of cash on hand) was $824 million. Its net debt to book capitalization was 55 percent (2009 - 40 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. The Revolving Credit Facility has financial covenants of which the company was in compliance throughout 2010 and 2009.

15. Related Party Transactions

16. Segmented Information

The company has two business segments. In Canada, the company is in the business of exploring for and producing bitumen and natural gas. In the USA, the company is in the business of refining and marketing petroleum products. The significant information of these segments is presented below.


(Canadian dollar in thousands) For the year ended December 31 2010	Canada Oil and Gas	USA Refining	Intersegment Elimination ⁽¹⁾	Total
Net revenues	$270,033	$334,165	$(14,267)	$589,931
Diluent, crude oil purchases and operating costs	161,798	301,084	(14,267)	448,615
Transportation costs	18,873	7,899	-	26,772
Loss on risk management contracts - net	(16,643)	(543)	-	(17,186)
Equity interest in Petrolifera loss	(1,847)	-	-	(1,847)
Interest and other income	138	118	-	256
Finance charges	64,853	24	-	64,877
Depletion, depreciation and accretion	69,115	10,471	-	79,586
Income tax recovery	(12,416)	(371)	-	(12,787)
Net (loss) earnings	(43,517)	4,719	-	(38,798)
Property, plant and equipment	1,314,308	81,216	-	1,395,524
Goodwill	103,676	-	-	103,676
Capital expenditures	228,112	8,575	-	236,687
Total assets	$1,519,603	164,395	$-	$1,683,998
For the year ended December 31 2009
Net revenues	$191,959	$264,924	$(7,094)	$449,789
Diluent, crude oil purchases and operating costs	117,173	248,837	(7,094)	358,916
Transportation costs	12,355	6,524	-	18,879
Loss on risk management contracts	(25,125)	-	-	(25,125)
Equity interest in Petrolifera loss	(2,468)	-	-	(2,468)
Interest and other income	2,950	600	-	3,550
Finance charges	43,979	375	-	44,354
Depletion, depreciation and accretion	59,171	7,391	-	66,562
Income tax recovery	(4,062)	(3,243)	-	(7,305)
Net earnings (loss)	29,406	(3,248)	-	26,158
Property, plant and equipment	1,142,542	87,714	-	1,230,256
Goodwill	103,676	-	-	103,676
Capital expenditures	293,074	20,820	-	313,894
Total assets	$1,592,591	$149,275	$-	$1,741,866

^{(1) Intersegment sales of $14.3 million (2009 - $7.1 million) and related costs of sales of $13.2 million (2009 - $6.8 million) are eliminated on consolidation.}

17. Supplementary Information

17.1 Per share amounts


For the years ended December 31 (000)	2010	2009
Weighted average common shares outstanding - basic	432,258	326,560
Dilutive effect of employee stock options	-	126
Dilutive effect of non-employee directors share award plan	-	381
Weighted average common shares outstanding - diluted	432,258	327,067

Outstanding employee stock options of 24.4 million as at December 31, 2010 (2009 - 22.6 million) and non-employee director share awards of 381,000 as at December 31, 2010 (2009 - nil) were excluded from the diluted earnings per share calculation as the effect of including them would be anti-dilutive. Common shares issuable upon the exercise of convertible debentures (note 7.1) were excluded as the effect of including them would be anti-dilutive.

17.2 Changes in non-cash working capital


As at December 31 (Canadian dollar in thousands)	2010		2009
Accounts receivable		$(15,618)	$(25,145)
Inventories		(21,802)	(8,530)
Due from Petrolifera		(17)	13
Prepayments and other assets		(1,907)	(16,427)
Income taxes recoverable		1,751	9,197
Accounts payable and accrued liabilities		(22,139)	8,644
Total		$(59,732)	$(32,248)
Relating to:
Operations		$(24,935)	$(17,300)
Investing		(34,797)	(14,948)
Total		$(59,732)	$(32,248)

17.3 Other cash flow information


For the years ended December 31 (Canadian dollar in thousands)	2010	2009
Interest paid	$92,019	$71,999
Income taxes paid	$421	$1,621

18. Commitments


As at December 31 2010 (Canadian dollar in thousands)	2011	2012	2013	2014	2015	Thereafter	Total
Operating leases	$3,243	$2,913	$2,934	$2,940	$2,951	$4,923	$19,904
Service and maintenance arrangements	2,912	2,905	2,898	2,892	2,617	38,702	52,926
Capital commitments	1,566	-	-	-	-	-	1,566
Other commitments	1,192	569	252	21	19	-	2,053
Total	$8,913	$6,387	$6,084	$5,853	$5,587	$43,625	$76,449

In addition, the company is also obligated to make contributions to the defined benefit plan (note 9.1), incur qualifying expenditures under the flow-through share issuances (note 11.3) and is committed to financial liabilities (note 13.2).

19. Subsequent events

In February 2011, the company closed the sale of certain properties for gross proceeds of $57.5 million, subject to normal closing adjustments. As at December 31, 2010, the company received a deposit of $5.8 million related to this disposition, which was held in escrow with the company's counsel and accordingly, was excluded from reported cash balances.

In addition, in March 2011, the company entered into an agreement to sell certain properties for gross proceeds of $22.5 million and received a deposit of $2.25 million related to this transaction. This sale is expected to close on April 29, 2011.

For further information:

Richard A. Gusella, President and Chief Executive Officer
OR
Peter D. Sametz, Executive Vice President and Chief Operating Officer
OR
Grant D. Ukrainetz, Vice President, Corporate Development

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

Legends
	Production
	Mine development
	Discovery
	Exploration
	Past producer
On Google Earth, click on the button, to show property information, and access to project page or company page.