Connacher Oil and Gas Limited reports 2007 results; Commerciality achieved at Great Divide Pod One oil sands project; Total corporate production has now surpassed 9,300 boe/d; 2p and 3p reserve base more than doubled during the year; Conference call March 20, 2008 at 9:00 AM MT



    CALGARY, March 19 /CNW/ - Connacher Oil and Gas Limited (CLL - TSX) today
released its year end operating and financial results for the year ended
December 31, 2007. The contents of this press release and our year end results
will be the subject of a Conference Call to be held on March 20, 2008 at 9AM
MT. Certain statements contained in this press release contain forward looking
information. See "Forward Looking Information".
    To listen to this Conference call please enter the following link in your
web browser:
    http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=2205060.
    To participate in the live conference call, please dial either (416)
644-3416 or (800) 732-9303. A replay of the event will be available from March
20, 2008 at 11:00 a.m. MT until March 27, 2008 at 11:59 p.m. MT. To listen to
the replay please, dial either (416) 640-1917 or (877) 289-8525 and enter the
passcode 21264560 followed by the pound sign.
    Your company made significant progress during 2007. We successfully
completed construction of our Great Divide Pod One steam assisted gravity
drainage ("SAGD") facility and we are ramping up our production of bitumen
towards the design capacity of 10,000 bbl/d. Our bitumen production at Pod One
recently approached 6,000 bbl/d and has been ranging between 5,000 and 6,000
bbl/d. Individual well productivity has approached 1,000 bbl/d on given days.
As we ramp up production, which is occurring at higher rates than originally
anticipated, we have recently constrained production during the process, while
dealing with normal treating issues. This is to ensure that treating
operations are optimized and "on spec" oil is produced to enable us to access
pipelines and related maximum prices available in the market place.
    We have determined that Pod One has achieved commerciality with an
effective date of March 1, 2008. Accordingly, production, sales and related
costs will be booked in our income statement from that date forward.
    Our total corporate production has now surpassed 9,300 boe/d up from
7,500 boe/d as reported on February 28, 2008, with the ramp up of bitumen
production at Pod One and the recent startup of significant new natural gas
sales from 2007 and 2008 discoveries at Randall in the Marten Creek area of
northern Alberta. Conventional production has now surpassed 3,600 boe/d with
the successful startup of the Randall plant. We are quickly approaching the
rank of an intermediate producer. Further short term production gains are
anticipated as full design capacity at Pod One is realized and other recent
new conventional discoveries in Alberta are brought onstream.
    Readers are cautioned that a barrel of oil equivalent (boe) is derived by
converting natural gas to oil in the ratio of six thousand cubic feet of
natural gas to one barrel of crude oil and that this may be misleading,
particularly if used in isolation. A boe 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.
    As a result of successful drilling, including our extensive first quarter
2007 core hole program at Great Divide, our proved and probable ("2P") bitumen
reserves at December 31, 2007 had more than doubled to 187 million barrels
compared to December 31, 2006, with a 10 percent pre-tax present value of
future net revenue of $1.2 billion as estimated by GLJ Petroleum Limited,
independent petroleum consultants of Calgary, Alberta ("GLJ"). Their estimate
of our proved, probable and possible bitumen reserves ("3P") and high estimate
contingent and prospective bitumen resources reached 799 million barrels with
a 10 percent pre-tax present value of $2.6 billion, up 111 percent from last
year. Of the 3P reserves, 64 million barrels are possible reserves. On
February 25, 2008 we issued a detailed press release, to which readers are
referred, about our year end 2007 reserve report. Please refer to that release
and the notes herein about the different reserve and resource categories and
the different associated risks.

    
    Specific 2007 highlights are as follows:

    -   Completed construction, commissioned and commenced production from
        Pod One, the company's first 10,000 bbl/d SAGD oil sands project at
        Great Divide. We have now achieved commerciality effective March 1,
        2008.
    -   Revenue increased 41 percent to $345 million, buoyed by improved
        throughput at our Great Falls, Montana refinery.
    -   Cash flow from operations before working capital and other changes
        ("cash flow") increased 12 percent to $45 million, with our refinery
        making a significant after-tax contribution. The purchase of the
        refinery, which occurred in March 2006, has now paid out. The level
        of cash flow growth reflects the concentration of our efforts on
        building and activating our Great Divide Pod One SAGD oil sands plant
        during the year. Significant gains are anticipated in 2008.
    -   Earnings were healthy at $41 million ($0.20 per weighted average and
        diluted common share) compared to $7 million (0.04 per weighted
        average common and diluted share) in 2006. There were 200.1 million
        shares outstanding on a weighted average basis in 2007 compared to
        184.5 million in 2006. Strong earnings reflect the positive impact of
        the Canadian dollar, which resulted in a significant realized foreign
        exchange gain upon the repayment of previously outstanding debt
        denominated in US dollars, offsetting the otherwise negative impact
        on crude oil revenues and Montana refinery results arising from the
        unusual and significant strength of the Canadian dollar during 2007.
    -   Refining throughput was strong during the year, increasing by
        nine percent to average 9,485 bbl/d in 2007 compared to 8,713 bbl/d
        for the nine months of 2006 during which we owned the refinery.
        Utilization rates in 2007 were 99.8 percent with high margins
        throughout most of the year, despite the significant increase in
        crude oil prices which resulted in higher input costs for this
        division.
    -   We applied to regulators, including the Alberta Energy Resources
        Conservation Board ("ERCB"), Alberta Environment ("AE") and Alberta
        Sustainable Resources and Development ("ASRD") for permission to
        proceed with the construction of our second 10,000 bbl/d oil sands
        plant at Great Divide Pod Two ("Algar" or "Algar project").
    -   During the year we raised a total of $752 million of cash through the
        sale of flow through common shares, convertible debentures and
        US$600 million of eight-year term senior secured second lien notes
        ("Notes"). These Notes do not require any repayment until maturity.
        Proceeds after expenses of these issues were used to finance capital
        programs, discharge previously issued debt and for working capital to
        fund our planned construction program at Algar. Additionally,
        proceeds were used to fund a one-year interest reserve account for
        the Notes in the amount of US$63.6 million. In conjunction with the
        issuance of the Notes, we also arranged senior secured first lien
        five-year syndicated credit facilities in the amounts of
        C$150 million and US$50 million, which are available to the company
        for its operations. These facilities were undrawn at year end except
        for US$1.8 million in letters of credit. Connacher is well-financed
        and positioned to conduct its growth activities in a difficult credit
        environment.
    -   Fixed asset additions were $323 million during 2007, primarily
        focused on the construction program at Pod One. In 2006, the company
        was active in acquiring another conventional oil and gas company and
        the Montana refinery. Excluding acquisitions, Connacher's 2007
        capital program was almost 180 percent higher than in 2006.
    -   Our reserve and resource bases expanded considerably during 2007,
        primarily due to increases in estimates of our recoverable bitumen at
        Great Divide, with our 2P bitumen reserves and best estimate
        contingent and prospective bitumen resources increasing 60 percent to
        417 million barrels and our 3P bitumen reserves and high estimate
        contingent and prospective resources increasing 67 percent to
        799 million barrels, after production of 850 thousand barrels in
        2007, compared to year end 2006. Our conventional 2P boe reserves
        also increased eight percent during 2007. The related 10 percent pre-
        tax present value of our reserves and resources increased
        dramatically, reflecting higher forecast pricing by our independent
        consultant and the completion of significant capital programs at
        Great Divide, as future net revenue is calculated after deduction of
        royalties, operating costs, well abandonment costs and future capital
        requirements to realize the forecast production and revenue base, but
        before income taxes and indirect costs such as general and
        administrative (G&A) expenses. Readers are again referred to our
        press release dated February 25, 2008, which is posted on SEDAR at
        www.sedar.com and on our website at www.connacheroil.com.
    -   Working capital at year end was a strong $390 million, including
        $329 million of cash and $63 million of restricted cash in our
        interest reserve account. This was put in place while Pod One
        production ramps up, sales increase and cash flow is generated from
        this project to supplement other cash flow sources which it is
        anticipated will provide the company with ability to service its
        indebtedness from internal sources.

    The following table summarizes these highlights and provides other
information with comparisons to results in 2006.

    Financial Highlights
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                                                2007        2006    % Change
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    FINANCIAL
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    ($000 except per share amounts)
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    Revenues, net of royalties              $344,520    $244,684          41
    -------------------------------------------------------------------------
    Cash flow(1)                              44,965      40,196          12
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      Basic, per share(1)                       0.22        0.22           -
    -------------------------------------------------------------------------
      Diluted, per share(1)                     0.22        0.21           5
    -------------------------------------------------------------------------
    Net earnings                              40,961       6,953         481
    -------------------------------------------------------------------------
      Basic and diluted, per share              0.20        0.04         400
    -------------------------------------------------------------------------
    Property and equipment additions
     and acquisitions                        322,962     451,525         (28)
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    Cash on hand                             392,271     142,391         175
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    Working capital                          389,789     118,626         229
    -------------------------------------------------------------------------
    Term debt                                664,462     209,754         217
    -------------------------------------------------------------------------
    Shareholders' equity                     480,439     385,398          25
    -------------------------------------------------------------------------
    Total assets                           1,258,828     712,930          77
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    COMMON SHARE INFORMATION
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    Shares outstanding at end of period
     (000)                                   209,971     197,894           6
    -------------------------------------------------------------------------
    Weighted average shares outstanding
    -------------------------------------------------------------------------
      Basic (000)                            200,092     184,469           8
    -------------------------------------------------------------------------
      Diluted (000)                          202,766     188,432           8
    -------------------------------------------------------------------------
    Common shares traded during the year
     (000)                                   239,590     323,825         (26)
    -------------------------------------------------------------------------
    Common share price ($)
    -------------------------------------------------------------------------
      High                                      4.43        6.07         (27)
    -------------------------------------------------------------------------
      Low                                       3.07        3.09          (1)
    -------------------------------------------------------------------------
      Close, end of year                        3.79        3.49           9
    -------------------------------------------------------------------------
    (1) Cash flow and cash flow per share do not have standardized meanings
        prescribed by Canadian generally accepted accounting principles
        ("GAAP") and therefore may not be comparable to similar measures used
        by other companies. Cash flow is calculated before changes in non-
        cash working capital, pension funding and site restoration
        expenditures. The most comparable measure calculated in accordance
        with GAAP would be net earnings. Cash flow is reconciled with net
        earnings on the Consolidated Statement of Cash Flows and in the
        accompanying Management's Discussion & Analysis. Commonly used in the
        oil and gas industry, management uses these non-GAAP measurements for
        its own performance measures and to provide its shareholders and
        investors with a measurement of the company's efficiency and its
        ability to internally fund future growth expenditures.
    (2) No dividends have been declared by the company since its
        incorporation.


    Operating Highlights
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                                                2007        2006    % Change
    -------------------------------------------------------------------------
    OPERATING
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    Production
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      Natural gas (mcf/d)                      9,172      10,473         (12)
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      Crude oil (bbl/d)                          792         980         (19)
    -------------------------------------------------------------------------
      Equivalent (boe/d)(1)                    2,320       2,725         (15)
    -------------------------------------------------------------------------
    Pricing
    -------------------------------------------------------------------------
      Crude oil ($/bbl)                        52.80       53.85          (2)
    -------------------------------------------------------------------------
      Natural gas ($/mcf)                       6.38        5.85           9
    -------------------------------------------------------------------------
    Selected highlights ($/boe)(1)
    -------------------------------------------------------------------------
      Weighted average sales price             43.22       41.83           3
    -------------------------------------------------------------------------
      Royalties                                 6.93        9.87         (30)
    -------------------------------------------------------------------------
      Operating and transportation costs       11.06        8.32          33
    -------------------------------------------------------------------------
      Netback(2)                               25.23       23.64           7
    -------------------------------------------------------------------------
    RESERVES AND RE

SOURCES ------------------------------------------------------------------------- Reserves and resources (mboe)(3, 4) ------------------------------------------------------------------------- Proved (1P) reserves 59,857 50,381 19 ------------------------------------------------------------------------- Proved plus probable (2P) reserves 187,250 92,935 101 ------------------------------------------------------------------------- Proved plus probable plus possible (3P) reserves(6) 242,009 118,649 104 ------------------------------------------------------------------------- 2P reserves and best estimate contingent and prospective 426,179 269,413 58 ------------------------------------------------------------------------- 3P reserves and high estimate contingent and prospective 808,486 487,741 66 ------------------------------------------------------------------------- Reserves and resources values ($million)(5) ------------------------------------------------------------------------- 1P reserves 603 312 93 ------------------------------------------------------------------------- 2P reserves 1,193 528 126 ------------------------------------------------------------------------- 3P reserves 1,165 616 89 ------------------------------------------------------------------------- 2P reserves and best estimate contingent and prospective 1,921 931 106 ------------------------------------------------------------------------- 3P reserves and high estimate contingent and prospective 2,774 1,397 99 ------------------------------------------------------------------------- REFINERY ------------------------------------------------------------------------- Refining throughput ------------------------------------------------------------------------- Crude charged (bbl/d) 9,485 8,713 9 ------------------------------------------------------------------------- Refinery utilization (%) 99.8 94 6 ------------------------------------------------------------------------- Margins (%) 15.4 13.8 12 ------------------------------------------------------------------------- (1) 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. (2) Netback is a non-GAAP measure used by management as a measure of operating efficiency and profitability. It is calculated as petroleum and natural gas revenue less royalties and operating costs. (3) The reserve and resource estimates for 2007 and 2006 were prepared by GLJ Petroleum Consultants ("GLJ") 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 90 percent likely that actual remaining quantities 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 proved plus probable reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is only a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status. Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be subclassified based on project maturity. Resource estimates are described as follows: Best Estimate - This is considered to be the best estimate of the quantity that will actually be recovered from the accumulation. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.; High Estimate - This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate. Low Estimate - this is considered to be a conservative estimate of the quantity that will actually be recovered from the accumulation. If probabilistic methods were used, the term reflects a P90 confidence level. (4) After production of 850,000 boe in 2007. (5) 10 percent present value of future net revenue before taxes. (6) Possible reserves account for 64,000 mboe of the estimated total 3P reserves. Connacher made considerable progress during 2007. The highlight of the year was the completion of our 10,000 bbl/d Pod One SAGD plant and related facilities at our Great Divide oil sands project in northeastern Alberta, Canada. Following commissioning and the commencement of steam circulation in the initial 15 SAGD well pairs drilled to produce the design volumes, we started the process of converting these well pairs to steam injection and bitumen production. Our ramp up process has advanced exceedingly well. Despite some minor slowdowns experienced due to severely inclement weather in late January and early February 2008, when temperatures with wind chill reached levels approaching minus 60 degrees Celsius, our bitumen production recently approached 6,000 bbld and has been ranging between 5,000 and 6,000 bbl/d. Individual well productivity has approached 1,000 bbl/d on given days. As we proceed to ramp up production, which is occurring at higher rates than originally anticipated, we have recently constrained production during the process, while dealing with normal treating issues. This is to ensure that treating operations are optimized and "on spec" oil is produced to enable us to access pipelines and related maximum prices available in the market place. We are selling dilbit into the marketplace at favorable prices. In the current high price environment for crude oil, our recent dilbut sales have resulted in an approximate selling price in the range of $70-$80 per barrel, which translates into an approximate bitumen wellhead price ranging between $50-$60 per barrel. These prices are volatile and transitory and are affected by numerous variables, including among others, the price of crude oil, heavy oil differentials, the relationship between the Canadian dollar and United States dollar, the cost of diluent, the selling point and related transportation costs. There can be no assurance that this level of pricing will be sustainable. Effective March 1, 2008 Great Divide Pod One has achieved commerciality; production, sales and related costs will be booked in our income statement from that date forward. We are gratified with the results we have achieved in a very short timeframe since we initiated production procedures at Pod One. It reflects favorably on our operating staff and on the quality of the reservoir which underlies the project. We built Pod One facilities and conducted related activity, including drilling the SAGD well pairs, on time in 300 days from the completion of plant site preparation work. Excluding sunk costs and capitalized items, the total cost of the project, while approximately 20 percent over our original budget cast in 2006, was $272 million. Inflationary pressures and higher site preparation costs were the principal sources of higher actual expenditures. Also, it should be noted that meeting the original timetable was a considerable achievement in a heated industry environment and also as the project was primarily constructed during winter months. By drawing on its oil field experience, Connacher was able to reduce the normal delays encountered in the oil sands from commencement of construction to first production and eventual cash flow. Our achievement also underscores the merit of our modular approach, which emphasizes the efficiency of small scale operations in the oil sands. Our success at Great Divide is a credit to our compact group of dedicated head office employees as well as to our advisors, consultants, suppliers and to our recently-recruited operating staff at Pod One. Our involvement in the oil sands at Great Divide and Halfway Creek is the driver of our future growth. We operate in this area of the oil and gas industry with an integrated approach. This is designed to mitigate the risks of bitumen production, with its attendant higher cost structure, substantial upfront capital requirements and long timeframes to convert assets to revenue, cash flow and earnings with exposure to the vagaries of price differential swings for heavy oil. Our integrated strategy incorporates an objective of upstream self-reliance for natural gas volumes to provide a physical hedge and price protection against the volumes we consume to make steam in the SAGD process. We are pleased to report that we are presently producing more natural gas than we consume, so we are ahead of the curve in terms of our future needs at Algar. Our strategy also incorporates downstream protection against the widening and volatile heavy oil differentials in a rising price environment by owning a refinery that currently can process approximately an equivalent amount of heavy oil to our 10,000 bbl/d design capacity at Pod One. Our Montana refinery has been very profitable since we acquired it in 2006 and it contributes differential capture and refining margins, integral parts of the netbacks we anticipate accessing as an integrated bitumen producer. We anticipate these netbacks will significantly outstrip those available if we were just producing raw bitumen for sale in the market. This is important for long-life oil sands projects such as Great Divide Pod One. Our evaluation of our Great Divide acreage continued during 2007. We drilled 81 core holes during late December 2006 and the first quarter of 2007. We also conducted additional 3D seismic programs on our main lease block during the year. As a consequence, our bitumen reserves and resources, as estimated by GLJ, increased significantly in all categories during the year. Our conventional natural gas reserves also experienced considerable growth during 2007, as a result of our successful drilling at Randall in the Marten Creek area of Alberta. This translated into the estimates of undiscounted pre-tax future net revenue and the pre-tax present value thereof experiencing significant increases during 2007. Readers are referred to our press release of February 25, 2008 for a more detailed discussion of our considerable reserve growth during the year. Based on our successful first quarter 2007 core hole program at Great Divide, we were able to confirm our decision to submit an application for our second 10,000 bbl/d oil sands plant at Algar, anticipated to be located approximately eight kilometers east of Pod One. This was submitted to regulators, including ERCB, AE, and ASRD in mid-2007. Based on prior experience, we anticipate a decision on our application will be forthcoming by mid-year 2008. We have already preordered certain key long lead items in anticipation of approval and to ensure we can remain on our preferred timeline for completion in 2009. We estimate the cost of this second plant, which incorporates some scope changes, increased outlays for infrastructure, including access roads and utilities and a higher level of contingencies excluding sunk costs and capitalizations, will approximate $326 million. It should also be noted that preliminary results of our 2008 core hole drilling program at Great Divide reinforce our enthusiasm for further significant expansion of our production from this region over time. Connacher is very pleased with the density, frequency and apparent quality of the bitumen accumulations it has encountered with its targeted exploration and development core hole drilling program. The company is finishing the last two wells in its first quarter 2008 drilling program. The program included drilling of 138 gross (128.5 net) core holes and observation wells in the oil sands and 20 gross (16.5 net) conventional wells, which resulted in 13 gross (10.5 net) natural gas wells and 3 gross (2 net) crude oil wells. This results in a success ratio of 76 percent, calculated on a net well basis. The full impact of the results of this activity will be further evaluated in our mid-year 2008 reserve report, which will take into account results from drilling at Great Divide, Halfway Creek and from our successful conventional drilling this year during early 2008. Against a backdrop of deteriorating capital and credit markets, Connacher had a very successful year raising the capital it will need to proceed with and complete the Algar project and conduct other capital programs in 2008 and 2009. We strengthened our financial condition and liquidity considerably in the process. In total, we raised $752 million of gross proceeds from the sale of flow through common shares ($52 million), a convertible debenture issue ($100 million) and a US$600 million private placement of senior secured second lien eight year notes ("Notes"). The Notes do not require any principal repayment prior to maturity, which enhances our financial flexibility. During 2007, proceeds of these financings were used to fund capital expenditures, to repay previously-incurred short term and long term indebtedness, to pay the expenses of the issues and to fund a one-year interest reserve account on the Notes of US$63.6 million. This was established to provide our new lenders increased confidence, during the period when our cash flow from Pod One and other established sources is anticipated to build up to self sufficient. The considerable cash balance from our Notes issue was added to working capital, primarily to complete Algar. At year end, our working capital aggregated $390 million, including unrestricted cash balances of $329 million. This financing activity resulted in minimal dilution of shareholders' equity and could not be accomplished in today's credit environment. Through careful preplanning, we have the cash to accelerate our growth profile through our ability to proceed with the construction of our second 10,000 bbl/d SAGD plant in the oil sands. Our fixed assets additions of $323 million were comprised of cash and non-cash items, including asset retirement obligations ("ARO") and provision for a portion of non-cash charges related to stock option awards. They also included capital improvements at our new head office in Calgary during 2007. Expenditures aggregated $256 million at the Great Divide Pod One SAGD facility, including the cost of 15 SAGD well pairs, seismic, capitalized items, ARO and 75 core holes. Our seismic programs have proven to be effective in assisting us in locating prospective exploitable oil sands accumulations or pods. The impact of these investments was incorporated into our consequential increase in reserve volumes and values. We also acquired new oil sands leases at Halfway Creek, situated northeast of our lands at Great Divide. Subsequent to year end, we completed a pooling of our acreage in that region, expanding our net acreage holdings in the process. In addition to our oil sands activity, we invested approximately $51 million in our conventional programs. These amounts also included certain non-cash items, leasehold improvements and information technology costs related to our new head office. Our conventional capital outlays were primarily for new natural gas reserves and productive capacity at Randall in the Marten Creek area west of our oil sands properties. We are now realizing the impact of these investments with the startup in March 2008 of our new facilities and pipeline at Randall, with approximately 1,000 boe/d of new production now onstream. Unfortunately, we could not convert these 2007 discoveries into immediate production. They would have offset normal declines in production levels from this area which occurred during late 2006 and throughout 2007. This delay contributed to lower conventional 2007 production as compared to 2006. To clarify, this was because our discoveries were made late in the first quarter of 2007 and as this is a winter-only access region, we could not install facilities until the winter of 2008. However, new discoveries made during the current winter season are being tied in, due to preplanning to overcome the challenges of very short drilling windows in northern swamps or muskeg. We also considerably enhanced our facilities and productive capacity at Three Hills, Alberta during 2007. Our Montana refining operation had an exceptional year during 2007. We invested $16 million in our Great Falls plant during the year. High margins and high throughput prevailed throughout 2007 and we have now fully recovered our original 2006 purchase price. This is remarkable for this type of business and is reflective of operating efficiencies, a dedicated management and staff in this division and improvements made during the time since acquisition. Ownership of this refinery is a cornerstone of our integrated strategy to the oil sands. During the year we not only secured some diluent from our own refinery, but we also processed dilbit from Pod One, which assisted in our subsequent marketing efforts. However, more importantly, our refinery permits Connacher to recapture differentials in the price of heavy crude oil, especially during times of rising crude oil prices and widening light-heavy spreads. This contributes to our enhanced "integrated" netbacks for bitumen production, just as our physical hedge on natural gas consumption from our natural gas production base mitigates the risk of high natural gas prices for volumes used to produce steam at Great Divide. During 2007, our refinery investments included projects which improve the environmental performance of the plant, in addition to construction of a new 150,000 bbl/d asphalt storage tank to assist us in maintaining high throughput during winter months. This also positions us to sell asphalt for higher prices during summer months. We also initiated investments for 2008 completion, which will enable the refinery to produce mandated ultra-low sulphur diesel. Our Montana refining operation was the major contributor to corporate cash flow during 2007 and while the current economic slowdown and deterioration in credit markets is expected to adversely affect economic and market conditions, we remain optimistic about the long term prospects for this business division. To that end, we are actively evaluating the expansion of the refinery's capacity to as much as 35,000 bbl/d. Decisions in this regard will await the completion of detailed engineering and costing studies. As previously noted, we also incurred expenses for our head office relocation and for increased technological capabilities. We now have the capacity to locate new personnel in one office as we continue to grow, which we anticipate will improve morale and efficiency. We experienced satisfactory improvements in our revenue, cash flow and earnings during 2007. Our fourth quarter 2007 was somewhat weaker than the prior reporting period and compared to last year. This was primarily due to the narrowing of heavy oil differentials which adversely affects refinery results. Also, there was some deterioration in refining margins late in 2007. We experienced higher financial charges and increases in short-term conventional operating costs and a minor loss resulted. These results are discussed in greater detail in our Management's Discussion and Analysis ("MD&A") incorporated into this press release. In many ways 2007 was a transition year for Connacher, with our primary focus on our plant construction and startup at Great Divide. We continue to believe our integrated strategy and our operating platform of repeatability, sustainability and expandability make sense in the present environment. We believe our approach to prefunding our financial requirements for major projects such as Pod One and Algar is prudent, especially in light of the recent severe deterioration in credit conditions. Upon receipt of regulatory approval, Connacher, in proceeding with Algar, will continue to adopt a modular approach for control of its construction costs, using our Pod One facility and its successful startup as a template. This should enable us to anticipate production of up to 20,000 bbl/d of bitumen in a short period of time, supplemented by growing conventional volumes. These are aimed at maintaining adequate natural gas supplies for self-sufficiency relative to our fuel needs at Great Divide. We now produce more natural gas than our requirements at Pod One. We are positioned to anticipate reaping the fruits of our 2007 labor. This is already becoming evident in early 2008, as embodied in the significant increases already being achieved in our bitumen and conventional production which recently surpassed 9,300 boe/d. As we progress from being categorized as a junior company into a more intermediate category, we anticipate that capital markets will be able to capitalize our improving and growing financial and operating results and our bright future as a company in a more expansive and appropriate manner. Accordingly, we hope to see our share price improve considerably in the near future and for the longer term. Our outlook is strong and our finances are solid as we embark on another active and focused capital spending program in 2008. As previously announced, our cash capital expenditure budget for 2008 is $344 million. Based on our estimates of growing cash flow and available cash balances, and in the absence of any further unusual exogenous shocks or severe deterioration in crude oil prices, we do not anticipate having to access our revolving credit facilities to any great extent to accomplish this program, save for letters of credit. These appear to be increasingly required by suppliers and vendors, due to current adverse credit conditions. This assessment does not provide for any new acquisitions or for possible capital requirements related to either pipelines at Great Divide, or for the expansion of our Montana refinery, which would be major capital undertakings requiring separate financial arrangements. We continue to hold our 26 percent equity stake in Petrolifera Petroleum Limited ("Petrolifera"), a public Canadian oil company created by Connacher in 2004. This company is solely active in South America and expanded its reserve base, productive capacity and exploratory acreage in 2007. Three new concessions were acquired by Petrolifera in Argentina during the year and three new concessions were also secured in Colombia. These complement a solid production and reserve base at Puesto Morales in the Neuquén Basin, Argentina and large acreage blocks held under license onshore Peru in the Maranon and Ucayali Basins. Petrolifera is currently producing approximately 9,500 boe/d and holds interests in over 7 million acres of petroleum and natural gas rights in the three named countries in South America. The company has had enviably low average finding, development and onstream costs, as calculated in compliance with the standards set out in National Instrument 51-101 ("NI 51-101") for the past three years. It also has low field operating costs. During 2007, a water treatment plant, waterflood facilities and a new high pressure natural gas pipeline were completed at Puesto Morales. Petrolifera anticipates that this should assist in the stability and growth of its crude oil and natural gas production base in 2008. Petrolifera has announced that plans are evolving to drill seismically-defined prospects with considerable potential in both Colombia and more particularly, in Peru during the latter part of 2008. Petrolifera remains well-financed and liquid with significant internally generated cash flow and surplus available credit to conduct an announced $144 million capital program in 2008. Recently, pronouncements have been made by various levels of governments in Canada regarding environmental initiatives which could, if adopted, impact on oil sands operations. We are assessing these initiatives and working with industry associations to quantify the impact and to determine any impact which these may have on our operations. At this time it does not appear that these initiatives will have a material impact on Connacher, although it is difficult to quantify any amounts based on available information. It should be noted our Pod One plant is modern with "state-of-the-art" attributes, including high energy efficiency, which helps minimize emissions. We do not use surface water for steam generation as we rely on a subsurface non-potable aquifer. Furthermore, our Pod One plant has an extremely high recycle rate for water, targeting in excess of 95 percent. Connacher is committed to a sustainable environmental program which recognizes the importance of appropriate operational response to environmental concerns. Readers are reminded that Connacher's year end earnings conference call, which was brought to your attention at the beginning of this press release. Also, our Annual General Meeting will be held in Calgary, Alberta on May 13, 2008 at the Calgary Petroleum Club, 319 - 5th Avenue S. W., at 3:00 P.M. in the afternoon. We will also release our first quarter 2008 results on that date prior to the time set for the Annual Meeting. Connacher Oil and Gas is a Calgary-based crude oil and natural gas exploration company. Our principal asset is our reserves, resources, production and land at Great Divide in Alberta's oil sands. We also own conventional properties, 9,500 bbl/d refinery in Great Falls, Montana, and a 26 percent investment in Petrolifera Petroleum Limited, a public company listed on the Toronto Stock Exchange. Forward Looking Information This press release contains forward-looking information including estimations of reserves and resources and future net revenue associated therewith, expectations of future production, cash flow, netbacks and capital expenditures, development of additional oil sands resources (including receipt of regulatory approvals in respect of Algar and timeline for construction of Algar), expansion of current conventional oil and gas and refining operations, evaluation of future transportation alternatives and implementation thereof and anticipated sources of funding capital expenditures. Forward looking information is based on managements expectations regarding future growth, results of operations, production, 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. 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 estimates and projections relating to production, costs and expenses, and health, safety, and environmental risks), and the risks of commodity price and foreign exchange rate fluctuation, and risk and uncertainties associated with securing the necessary regulatory approvals and financing to proceed with the continued expansion of the Great Divide project at Algar and other regions and expansion of the company's refinery in Great Falls, Montana. These risk and uncertainties are described in details in Connacher's Annual Information Form for the year ended December 31, 2007, which is available at www.sedar.com. Information relating to "reserves" and "resources" 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 and resources, as the case may be, 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 resources of the Corporation and associated future net revenues are contained in the 2007 GLJ Report and are summarized in Connacher's Annual Information Form for the year ended December 31, 2007. Future net revenues associated with reserves and resources do not necessarily represent fair market value. Additionally certain information relating to Petrolifera's future exploration and development plans and capital expenditures represent future-looking information that has been publicly released by Petrolifera. This information is subject to change in the discretion of the Board of Directors of Petrolifera. Connacher assumes no obligation to update or revise the forward-looking information to reflect new events or circumstances, except as required by law. MANAGEMENT'S DISCUSSION & ANALYSIS Connacher's business plan anticipates continuing growth. Emphasis will be on delineating and developing the Great Divide Oil Sands Project in Alberta, while expanding the company's conventional production base and sustaining and expanding profitable operations at the Montana refinery. The following is dated as of March 19, 2008 and should be read in conjunction with the consolidated financial statements of Connacher Oil and Gas Limited ("Connacher" or the "company") for the years ended December 31, 2007 and 2006 as contained in this annual report. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP") and are presented in Canadian dollars. This MD&A provides management's view of the financial condition of the company and the results of its operations for the reporting periods. Throughout the MD&A, 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 of crude oil (6:1). The 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. Boe may be misleading, particularly if used in isolation. FORWARD-LOOKING INFORMATION This annual report contains forward-looking information including estimates of reserves and resources and future net revenue associated therewith, expectations of future production, cash flow and capital expenditures, development of additional oil sands resources (including receipt of regulatory approvals in respect of Algar and timeline for construction of Algar), expansion of current conventional oil and gas and refining operations, evaluation of future transportation alternatives and implementation thereof and anticipated sources of funding capital expenditures. Forward looking information is based on management's expectations regarding future growth, results of operation, production, 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. 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 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 and uncertainties associated with securing the necessary regulatory approvals and financing to proceed with the continued expansion of the Great Divide Project at Algar and other regions and expansion of the company's refinery in Great Falls, Montana. These risks and uncertainties are described in detail in Connacher's Annual Information Form for the year ended December 31, 2007, which is available at www.sedar.com. Information relating to "reserves" and "resources" and "future net revenues" associated therewith are deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the described reserves and resources, as the case may be, exist in the quantities predicted, and that they 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 resources of the company and the associated future net revenues are contained in the GLJ 2007 Report and are contained in Connacher's Annual Information Form for the year ended December 31, 2007. Future net revenues associated with reserves and resources do not necessarily represent fair market value. Additionally, certain information relating to Petrolifera's future exploration and development plans and capital expenditures represent forward-looking information that has been publicly released by Petrolifera. This information is subject to change in the discretion of the Board of Directors of Petrolifera. The company assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances, except as required by law. 2007/2008 Risk Management & Financing Strategy Connacher's business plan is to provide increasing investor returns while mitigating risks by using an integrated approach to developing its oil sands assets. ------------------------------------------------------------------------- Risk Response ------------------------------------------------------------------------- Operating - Own and produce the natural gas volumes required to make steam for injection into the oil sands reservoirs, thus hedging exposure to natural gas price volatility ------------------------------------------------------------------------- Differential pricing - Our Montana refinery allows us to recapture a for heavy oil portion of heavy oil differentials and to earn refining margins ------------------------------------------------------------------------- Finance - Pre-funding major projects with a sound balance of equity and long-term debt ------------------------------------------------------------------------- Execution - Complete projects such as Pod One on time, using a modular construction approach with related cost control ------------------------------------------------------------------------- Environmental - Adopt sustaining strategies for the environment ------------------------------------------------------------------------- Our goal is to generate growth and increase shareholder value by developing our oil sands projects, while expanding related assets in a sustainable and controlled manner within our integrated approach. ------------------------------------------------------------------------- Report Card ------------------------------------------------------------------------- Strategic Priorities Progress through 2007 ------------------------------------------------------------------------- Operate with large - Great Divide Oil Sands Project - retained focused working 100% working interest while financing interests expenditures of over $300 million. We also retained very high working interests in our conventional petroleum and natural gas assets ------------------------------------------------------------------------- Focus on projects with - Completed and commissioned our first oil characteristics of sands project (Pod One); expandability, - Applied for regulatory approval to start repeatability and construction of Algar, which will replicate sustainability Pod One; and - Commenced a $50 million winter 2008 core hole drilling and a 3D seismic program ------------------------------------------------------------------------- Mitigate and manage - Producing the natural gas required to make risks of a smaller steam to be injected into the oil sands company in the oil reservoir - current production exceeds needs; sands with an - Montana refinery provides a natural hedge to integrated approach the light oil/heavy oil price differential, allowing us to capture more of the barrel's value; and - The successful timely completion of our first SAGD oil sands project in 2007 illustrates the effectiveness of our modular approach to facilities construction and cost control ------------------------------------------------------------------------- Operate with financial - Algar has been pre-funded with minimal equity discipline dilution; - Achieve self-sufficiency by having cash flow finance conventional and refinery projects and eventually overall expansion in the oil sands; - $200 million credit facility established and available for further flexibility; and - Petrolifera investment, with growth potential, remains a financial safety valve which could be sold, if necessary ------------------------------------------------------------------------- THREE YEAR SUMMARY INFORMATION ------------------------------------------------------------------------- ($000 except per share amounts) 2007 2006 2005 ------------------------------------------------------------------------- Total revenues $350,387 $254,505 $12,378 ------------------------------------------------------------------------- Net earnings 40,961 6,953 991 ------------------------------------------------------------------------- Basic and diluted, per share 0.20 0.04 0.01 ------------------------------------------------------------------------- Total assets 1,258,828 712,930 134,813 ------------------------------------------------------------------------- Total debt 664,462 209,754 - ------------------------------------------------------------------------- Dividends declared/paid - - - ------------------------------------------------------------------------- FINANCIAL AND OPERATING REVIEW CRUDE OIL AND NATURAL GAS PRODUCTION, PRICING AND REVENUE ------------------------------------------------------------------------- For the years ended December 31 2007 2006 ------------------------------------------------------------------------- Daily production/sales volumes ------------------------------------------------------------------------- Crude oil - bbl/d 792 980 ------------------------------------------------------------------------- Natural gas - mcf/d 9,172 10,473 ------------------------------------------------------------------------- Combined - boe/d 2,320 2,725 ------------------------------------------------------------------------- Product pricing ($) ------------------------------------------------------------------------- Crude oil - per bbl 52.80 53.85 ------------------------------------------------------------------------- Natural gas - per mcf 6.38 5.85 ------------------------------------------------------------------------- Boe - per boe 43.22 41.83 ------------------------------------------------------------------------- Revenue ($000) ------------------------------------------------------------------------- Gross 36,589 41,607 ------------------------------------------------------------------------- Royalties (5,867) (9,821) ------------------------------------------------------------------------- Revenues - net 30,722 31,786 ------------------------------------------------------------------------- Daily production and sales of crude oil and natural gas ("PNG") volumes over the past three years was influenced by the March 31, 2006 acquisition of Luke Energy Ltd ("Luke"). Volumetric increases in 2006 were primarily related to that acquisition. In December 2006 the company disposed of some minor properties acquired in the Luke transaction. This resulted in some of the reduced sales volumes in 2007. Additionally, the company experienced natural production declines during 2007 which, due to limited winter-only access to the fields, could not be offset by production from new reserves discovered last winter until the spring of 2008. The company has completed the construction of its new natural gas gathering and processing facilities. This new production is expected to add approximately six mmcf of daily production commencing in March 2008. Throughout 2006 and 2007, natural gas production represented approximately two thirds of the company's PNG sales volumes and approximately 55 percent of gross PNG revenue. As the annual average crude oil and natural gas pricing did not significantly change year over year, the 12 percent reduction in gross PNG revenue from 2006 is primarily the result of normal decline in natural gas production and sales volumes or our inability to service wells until after year end 2007. Because the company has little influence over the pricing it receives for its products, it sometimes enters into commodity hedging contracts to protect the downside risk to its operating cash flow and to protect the lending value of its reserves. In 2007, the company entered into a costless collar contract with a third party to hedge the price of approximately one half of its natural gas production between April 1 and October 31, 2007. As a result of this contract, the company realized approximately $500,000 more revenue in 2007 than it would have otherwise realized. In February 2008, the company entered into another costless collar contract to receive a minimum of US $7.50 and a maximum of US $10.05 per mmbtu on a notional quantity of 5,000 mmbtu per day of natural gas sold between April 1 and October 31, 2008. The 2007 PNG volumes and revenues do not reflect any results from Great Divide Pod One as, while the company's first oil sands project produced approximately 29,000 barrels of incidental bitumen production in the fourth quarter of 2007 during the pre-heating steam circulation phase, all revenues have been and will continue to be credited against the accumulated project costs until February 29, 2008. Thereafter, revenues will be reported as the company declared commerciality of Pod One effective March 1, 2008. ROYALTIES ON PNG SALES ------------------------------------------------------------------------- For the years ended December 31 2007 2006 --------------------------------------- ($000 except per boe) Total Per boe Total Per boe ------------------------------------------------------------------------- PNG royalties $5,867 $6.93 $9,821 $9.87 ------------------------------------------------------------------------- Percentage of PNG revenue 16.0% 23.6% ------------------------------------------------------------------------- Royalties represent charges against production or revenue by governments and landowners. PNG royalties in 2007 were $5.9 million ($6.93 per boe, or 16.0 percent of PNG revenue) compared to $9.8 million in 2006 ($9.87 per boe, or 23.6 percent of PNG revenue). From year to year, royalties can change based on changes to the weighting in the product mix which is subject to different royalty rates, and rates usually escalate with increased product prices. The decrease from 2006 to 2007, which was substantially non-recurring, occurred primarily due to gas cost allowance credits received relating to prior years' royalties paid. Oil sands royalties represent one percent of oil sands revenues until payout of capital costs is achieved. On October 25, 2007, the Government of Alberta proposed a new royalty regime. The new regime will introduce amended royalties for conventional oil, natural gas and bitumen produced in Alberta effective January 1, 2009. They are scheduled to be linked to price and production levels and will apply to both new and existing oil sands projects and conventional oil and gas activities. The changes to the royalty regime require changes to existing legislation and regulations together with development of proprietary software to support the calculation and collection of royalties. The impact of the proposed new royalty regime on the company will be dependent on, among other things, commodity prices, bitumen valuation, specified allowed costs that are recoverable in the pre-payout period for oil sands projects and production volumes in Alberta. The company is currently awaiting finalization of the royalty implementation regulations. Connacher expects that its 2009 and future Alberta royalty payments will increase as a result of the proposed Alberta royalty changes. Royalties on Saskatchewan-based production are unaffected and unchanged. PNG OPERATING EXPENSES AND NETBACKS(1) ------------------------------------------------------------------------- For the years ended December 31 2007 2006 % Change ($000 except ----------------------------------------------------------- per boe) Total Per boe Total Per boe Total Per boe ------------------------------------------------------------------------- Average daily production (boe/d) 2,320 2,725 (15) ------------------------------------------------------------------------- Gross PNG revenue $36,589 $43.22 $41,607 $41.83 (12) 3 ------------------------------------------------------------------------- PNG royalties (5,867) (6.93) (9,821) (9.87) (40) (30) ------------------------------------------------------------------------- Net PNG revenue 30,722 36.29 31,786 31.96 (3) 14 ------------------------------------------------------------------------- Operating costs (9,364) (11.06) (8,270) (8.32) 13 33 ------------------------------------------------------------------------- Netback $21,358 $25.23 $23,516 $23.64 (9) 7 ------------------------------------------------------------------------- (1) Calculated by dividing related revenue and costs by total boe produced, resulting in an overall combined company netback. Netbacks do not have a standardized meaning prescribed by GAAP and, therefore, may not be comparable to similar measures used by other companies. This non-GAAP measurement is a useful and widely used supplemental measure that provides management with performance measures and provides shareholders and investors with a measurement of the company's efficiency and its ability to fund future growth through capital expenditures. Operating netbacks are reconciled to net earnings below. For 2007, operating costs were $9.4 million, 13 percent higher than in the prior year, and, on a per unit basis, increased by 33 percent to $11.06 per boe. This reflects a higher-cost environment in 2007, more well workovers expensed in the year and the impact of fixed operating costs on lower production volumes in 2007 as compared to 2006. The impact of additional natural gas volumes (approximately six mmcf/d (1,000 boe/d) commencing in March 2008) is expected to result in an increase in total operating costs but a reduction in per unit operating costs, as fixed operating costs will be spread over larger production volumes. Notwithstanding higher operating costs in 2007, PNG netbacks on a boe basis were up seven percent, primarily as a result of reduced PNG royalties, as certain prior period adjustments to gas cost allowance credits were received in 2007. Reconciliation of Netback to Net Earnings ------------------------------------------------------------------------- For the year ended December 31 2007 2006 ------------------------------------------------------------------------- ($000, except per unit amounts) Total Per boe Total Per boe ------------------------------------------------------------------------- Netback as above $21,358 $25.23 $23,516 $23.64 ------------------------------------------------------------------------- Interest income 748 0.88 1,024 1.03 ------------------------------------------------------------------------- Refining margin - net 48,202 56.92 29,206 29.36 ------------------------------------------------------------------------- General and administrative (8,543) (10.09) (3,886) (3.91) ------------------------------------------------------------------------- Stock-based compensation (5,650) (6.67) (7,816) (7.86) ------------------------------------------------------------------------- Finance charges (6,858) (8.10) (5,086) (5.11) ------------------------------------------------------------------------- Foreign exchange (loss) gain 26,900 31.77 (4,287) (4.31) ------------------------------------------------------------------------- Depletion, depreciation and amortization (31,061) (36.68) (32,949) (33.13) ------------------------------------------------------------------------- Income taxes (13,005) (15.36) (3,870) (3.89) ------------------------------------------------------------------------- Equity interest in Petrolifera earnings and dilution gain 8,870 10.47 11,101 11.16 ------------------------------------------------------------------------- Net earnings $40,961 $48.37 $6,953 $6.98 ------------------------------------------------------------------------- NETBACK BY PRODUCT TYPE ------------------------------------------------------------------------- For the year ended December 31 2007 ------------------------------------------------------------------------- Oil Gas ------------------------------------------------------------------------- ($000, except per unit amounts) Total Per bbl Total Per mcf ------------------------------------------------------------------------- Average daily production 792 bbl/d 9,172 mcf/d ------------------------------------------------------------------------- PNG revenue $15,257 $52.80 $21,332 $6.38 ------------------------------------------------------------------------- PNG royalties (3,632) (12.57) (2,235) (0.67) ------------------------------------------------------------------------- Operating costs (3,193) (11.05) (6,171) (1.84) ------------------------------------------------------------------------- Netback $8,432 $29.18 $12,926 $3.87 ------------------------------------------------------------------------- ------------------------------------------------------------------------- For the year ended December 31 2006 ------------------------------------------------------------------------- Oil Gas ------------------------------------------------------------------------- ($000, except per unit amounts) Total Per bbl Total Per mcf ------------------------------------------------------------------------- Average daily production 980 bbl/d 10,473 mcf/d ------------------------------------------------------------------------- PNG revenue $19,257 $53.86 $22,350 $5.85 ------------------------------------------------------------------------- PNG royalties (4,534) (12.68) (5,287) (1.38) ------------------------------------------------------------------------- Operating costs (3,829) (10.71) (4,441) (1.16) ------------------------------------------------------------------------- Netback $10,894 $30.46 $12,622 $3.30 ------------------------------------------------------------------------- The reasons for the year over year changes in the component of the product type netbacks are the same as detailed for overall PNG netback changes described above. REFINING REVENUES AND MARGINS Seasonality of Refining Operations and Sales The Montana refinery is subject to a number of seasonal factors which may cause product sales revenues to vary throughout the year. The refinery's primary asphalt market is for paving roads which is predominantly a summer demand. Consequently, prices and sales volumes for our asphalt 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 months. Seasonal factors also affect gasoline (higher demand in summer months) and distillate and diesel (higher winter demand). As a result, inventory levels, sales volumes and prices can be expected to continue to fluctuate on a seasonal basis. As a consequence of seasonally reduced asphalt selling prices, the company reduced the realizable value of asphalt inventory at December 31, 2007, by $562,000, charging cost of sales in the consolidated statement of operations. ------------------------------------------------------------------------- Refinery Throughput 2007 2006(1) ------------------------------------------------------------------------- Crude charged - bbl/d 9,485 8,713 ------------------------------------------------------------------------- Refinery production - bbl/d 10,444 9,498 ------------------------------------------------------------------------- Sales of produced refined products - bbl/d 10,282 9,661 ------------------------------------------------------------------------- Sales of refined products (includes purchased products) - bbl/d 10,877 10,053 ------------------------------------------------------------------------- Refinery utilization 99.8% 94% ------------------------------------------------------------------------- ------------------------------------------------------------------------- Feedstocks ------------------------------------------------------------------------- Sour crude oil 92% 92% ------------------------------------------------------------------------- Other feedstocks & blend 8% 8% ------------------------------------------------------------------------- ------------------------------------------------------------------------- Revenues and Margins ------------------------------------------------------------------------- Refining sales revenue ($000) $313,050 $211,874 ------------------------------------------------------------------------- Refining - crude oil and operating costs ($000) $264,848 $182,668 ------------------------------------------------------------------------- Refining - margin ($000) $48,202 $29,206 ------------------------------------------------------------------------- Refining margin (%) 15.4% 13.8% ------------------------------------------------------------------------- ------------------------------------------------------------------------- Sales of Produced Refined Products ------------------------------------------------------------------------- Gasolines 38.2% 35.6% ------------------------------------------------------------------------- Diesel fuels 17.1% 17.6% ------------------------------------------------------------------------- Jet fuels 5.7% 3.4% ------------------------------------------------------------------------- Asphalt 35.4% 40.2% ------------------------------------------------------------------------- LPG and other 3.6% 3.2% ------------------------------------------------------------------------- Total 100% 100% ------------------------------------------------------------------------- ------------------------------------------------------------------------- Averages Per Barrel of Refined Products Sold ------------------------------------------------------------------------- Refining sales revenue $78.85 $76.63 ------------------------------------------------------------------------- Less: Refining - crude oil and operating costs $66.71 $66.07 ------------------------------------------------------------------------- Refining margin $12.14 $10.56 ------------------------------------------------------------------------- (1) For the nine months from March 31, 2006, the date the refinery assets were acquired. The refinery is a strategic fit with Connacher's oil sands development. It is the closest US refinery to Alberta's oil sands. It processes Canadian heavy crude similar to Great Divide dilbit into a range of higher value products, including regular and premium gasoline, jet fuel and diesel as well as home heating oil and asphalt. The refinery thus provides a physical hedge protecting Connacher's future oil sands revenues from the impact of adverse or widened crude oil/bitumen price differentials. The Montana refinery is a complex operation 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. It also is a major supplier of paving grade asphalt, polymer modified grades and asphalt emulsions for road construction. The Montana refinery markets products to retailers in Montana and neighbouring regions by truck and rail transport. Connacher's refinery operating results were outstanding in 2006 and 2007, with record levels of throughput, profit and profit margin. This performance was due to improved efficiencies, implemented subsequent to the acquisition of these refining assets, increased throughput and sales volumes and high product prices and differentials for the heavy crude feedstocks used. As a result, the original cost of the refinery (excluding inventory) has been fully recovered with after-tax cash flow within 18 months of its purchase. The company also made significant environmental improvements to the refinery's operation. These included the removal of excess sulphur from boiler fuel and recovery and remediation of an old wastewater aeration pond. Sulphur removal in the boiler fuel has now been improved by over 200 times from the previous operation. Sulphur removal is accomplished by means of a unique process which converts the sulphur to a product now being used commercially for environmental remediation in other parts of the U.S. Additionally, the company constructed a new 150,000 barrel asphalt tank (commissioned in March 2007) and expanded rail loading facilities, both undertaken to handle the increased throughput achieved since acquiring the refinery in March 2006. Connacher's operation includes a strong training and development program as well as rigorous procedures for safety and environmental protection. In 2008, Connacher plans to continue making environmental and capacity enhancements at the Montany refinery. Connacher has initiated a major Clean Fuels project targeted to allow the production of ultralow sulphur diesel ("ULSD") and gasoline in 2008. Engineering and marketing studies have also been initiated to assess the possibility of a major expansion of the refinery's capacity. INTEREST AND OTHER INCOME In 2007, the company earned interest of $748,000 (2006 - $1 million) on excess funds invested in secure short-term investments. GENERAL AND ADMINISTRATIVE EXPENSES In 2007, general and administrative ("G&A") expenses were $8.5 million compared to $3.9 million in 2006, an increase of 120 percent, reflecting increased costs associated with being a public company as well as increased staffing to support the company's substantial growth, primarily associated with the expanded scale of the company's operations. G&A of $3.4 million was also capitalized in 2007 (2006 - $1 million) and charged to to the company's conventional and oil sands capital projects. STOCK-BASED COMPENSATION The company recorded non-cash stock-based compensation charges in the respective years as follows: ------------------------------------------------------------------------- Years Ended December 31 ------------------------------------------------------------------------- ($000) 2007 2006 ------------------------------------------------------------------------- Charged to G&A expense $5,650 $7,816 ------------------------------------------------------------------------- Capitalized to property and equipment 2,220 3,475 ------------------------------------------------------------------------- Charged to refining operating costs 421 486 ------------------------------------------------------------------------- $8,291 $11,777 ------------------------------------------------------------------------- FINANCE CHARGES In accordance with new accounting standards relating to financial instruments, Connacher follows the amortized cost method to record the term debt obligation of the Convertible Debentures and Senior Notes. Consequently, their transaction costs have been deducted from their face values at the time the debentures and notes were issued and initially recorded. Over the term to maturity of each debt instrument, the discounted debts will be accreted to face value. Interest and accretion on the Convertible Debentures is recorded in finance charges. Interest and accretion on funds borrowed to finance oil sands expenditures (the Oil Sands Term Loan and the Senior Notes) are being capitalized until February 29, 2008. Thereafter, as portion of total interest and accretion attributable to Pod One will be expensed as a result of the company declaring commerciality of Pod One effective March 1, 2008. Expensed finance charges in the amount of $6.9 million in 2007 comprised interest and accretion on the Convertible Debentures ($4.8 million) and interest charged for amounts borrowed under the revolving credit facilities. Expensed finance costs in 2006 in the amount of $5.1 million comprised interest costs on funds borrowed under the company's revolving credit facilities and the US $51 million bridge loan facility, together with the amortization of deterred financing costs. In 2007, the company capitalized financing costs of $25 million related to the Great Divide oil sands project; 2006 - $3 million. FOREIGN EXCHANGE GAINS AND LOSSES The significant strengthening in 2007 of the Canadian dollar relative to the US dollar resulted in substantial foreign exchange gains on the settlement of US dollar denominated debt. In December 2007, Connacher issued US $600 million of Senior Notes. (See Recent Financings.) A portion of the proceeds of this financing were utilized to discharge the outstanding US $180 million Oil Sands Term Loan (the "Oil Sands Term Loan"), which had been issued in 2006 to finance a portion of Pod One construction costs. At the time of fully repaying the Oil Sands Term Loan, the Canadian dollar was at par with its US counterpart. Therefore, the company realized a foreign exchange gain of approximately $30 million. A portion of this realized gain was offset by an unrealized foreign exchange loss of $3 million on the translation of US dollar denominated cash balances on hand at year end. The translation of the Oil Sands Term Loan at December 31, 2006 had resulted in an unrealized foreign exchange loss of $4.3 million in 2006. To partially mitigate the foreign exchange risk associated with its Senior Notes, the company has entered into cross currency and interest rate swaps to fix a portion of the US dollar denominated principal and interest payments into Canadian dollars. The swaps provided for a fixed payment of $304.8 million in exchange for the prospective receipt of US $300 million on December 15, 2015. The swaps also provided for semi-annual interest payments commencing June 15, 2009 until December 15, 2015 at a fixed rate of 10.795 percent (based on a notional $304.8 million of debt) in exchange for receipt of semi-annual interest payments at a fixed rate of 10.25 percent (based on a notional US $300 million of debt). At December 31, 2007, the fair value of this swap was a liability of $12.7 million, which has been included with long-term debt in the consolidated balance sheet. An unrealized foreign exchange loss of $9.6 million related to the cross currency swap has been recorded in income and $3.1 million has been capitalized to property and equipment. This unrealized loss was offset by a $9.7 million unrealized gain on translating the Senior Notes and the interest rate swap at year end. It is anticipated the company's main exposure to foreign currency risk will continue to be the pricing of its crude oil sales, which are denominated in US dollars, the translation of the US $600 million Senior Notes and the translation of the Montana refinery financial results. DEPLETION, DEPRECIATION AND ACCRETION ("DD&A") DD&A expense is calculated using the unit-of-production method based on total estimated proved reserves. DD&A in 2007 was $31.1 million, a five percent decrease from last year due to lower production volumes in 2007. This equates to $36.68 per boe of production compared to $33.13 per boe last year. For greater certainty, no costs or reserves related to Great Divide were included in these amounts. Capital costs of $413 million (2006 - $157 million) related to the Great Divide oil sands project, which was in the pre-commercial stage and undeveloped land acquisition costs of $14.7 million (2006 - $16.2 million) were excluded from the depletion calculation. Future development costs of $14.3 million (2006 - $3.2 million) for proved undeveloped conventional reserves were included in the depletion calculation. Included in DD&A is a charge of $1.6 million (2006 - $348,000) in respect of the company's estimated asset retirement obligations ("ARO"). These charges will continue in future years in order to accrete the currently booked discounted liability of $24.4 million to the estimated total undiscounted liability of $44.4 million over the remaining economic life of the company's oil sands, crude oil and natural gas properties. Pod One's accumulated capital costs will be added to the depletion pool in the first quarter of 2008 and will be depleted with the company's conventional properties. This is expected to increase total DD&A, but substantially reduce the company's depletion rate per unit produced, having regard to the accumulated capital costs associated with Pod One and the significant proved reserves to be added to the depletable reserve base. CEILING TEST Oil and gas companies are required to compare the recoverable value of their productive oil and gas assets to their recorded carrying value at the end of each reporting period. Excess carrying values over ceiling value are to be written off against earnings. No write-down was required for any reporting period in 2007 or 2006. INCOME TAXES The income tax provision of $13.0 million in 2007 (2006 - $3.9 million) includes a provision for current income taxes of $10.7 million (2006 - $7.0 million) related to US refinery operations and $2.3 million (2006 - $400,000) related to Canadian capital and other taxes. The future income tax recovery of $3.5 million in 2006 reflected the benefit of increased tax pools and reduced tax rates in that year. Connacher's Pod One capital expenditures in 2007 have been the primary source of additions to the company's tax pools. These pools will be available to deduct against future earnings and it is anticipated that the Canadian business operations will not be subject to cash income taxes for several years. The US refining operation does not have large tax pools to shelter its income from US tax; it is expected to continue paying cash taxes in 2008. At December 31, 2007 the company had approximately $66 million of non-capital losses which expire over time to 2027, $414 million of deductible resource pools and $36 million of deductible financing costs available to be applied to reduce the company's future taxable income. EQUITY INTEREST IN PETROLIFERA PETROLEUM LIMITED ("PETROLIFERA") Connacher accounts for its 26 percent equity investment in Petrolifera on the equity method basis. Connacher's equity interest in Petrolifera's earnings in 2007 was $7.0 million (2006 - $11.1 million). Due to an accounting error, in March 2008 Petrolifera restated and refiled its 2006 financial statements because it overstated its 2006 net earnings by approximately $2.6 million. Connacher's 26 percent equity interest in that amount was not considered sufficiently material to warrant Connacher restating its 2006 financial statements. Consequently, Connacher's equity interest in Petrolifera's 2007 earnings has been reduced by its interest in the amount of this error. Under the terms of a Management Services Agreement with Petrolifera, which has been extended on a month-to-month basis since its original term, which expired in May 2007, Connacher provides certain management and general and administrative services to Petrolifera. The fee for this service is $15,000 per month. From time to time Connacher also pays bills on behalf of Petrolifera, for which it is reimbursed at cost. Connacher is also guarantor for Petrolifera in Peru and operator of record on behalf of Petrolifera in Colombia for which Connacher is indemnified by Petrolifera. Petrolifera paid Connacher $200,000 in 2007 under the management agreement which is anticipated to be replaced on substantially the same terms by a new agreement effective January 1, 2008. Connacher currently holds approximately 13.1 million common shares of Petrolifera, a publicly traded company on the Toronto Stock Exchange (PDP - TSX). Current market value of this holding is approximately $150 million. Connacher's cost of this holding is approximately $11 million. Connacher also holds options to acquire an additional 200,000 common shares at $0.50 per share until February 1, 2010. As Petrolifera's founding shareholder, Connacher anticipates being a long-term holder, with the intent of maximizing its investment return upon Petrolifera developing its significant resource opportunities in South America. This investment holding provides a "financial safety valve" to Connacher, as these shares have not been collateralized. DILUTION GAIN In 2006, the company's equity interest in Petrolifera was reduced to 26 percent from 33 percent. These reductions resulted in a dilution gain of $23,000 in 2006. In April 2007, the company exercised its right to purchase 1.7 million additional common shares in Petrolifera for total consideration of $5.1 million. As a result, the company increased its investment. However, because other Petrolifera shareholders similarly exercised their right to purchase additional common shares in Petrolifera on identical terms, a dilution gain of $1.9 million to Connacher's account resulted from these transactions. NET EARNINGS In 2007, the company net earnings were $41.0 million ($0.20 per basic and diluted share outstanding). This compares to net earnings of $7.0 million ($0.04 per basic and diluted share) for 2006. Higher earnings primarily reflect the impact of realized foreign exchange gains during the year. SHARES OUTSTANDING In 2007, the weighted average number of common shares outstanding was 200,092,469 (2006 - 184,468,631) and the weighted average number of diluted shares outstanding, as calculated by the treasury stock method, was 202,766,939 (2006 - 188,431,809). The increase reflects the impact of common shares issued during 2007. As at March 18, 2008, the company had the following securities issued and outstanding: - 210,265,232 common shares; - 17,671,440 share purchase options; - 108,975 share units ("SUs") under the non-employee director share awards plan; and - 20,010,000 common shares issuable upon conversion of the $100,050,000 Convertible Debentures. Details of the exercise provisions and terms of the outstanding options, SUs and Convertible Debentures are noted in the consolidated financial statements, included in this annual report. LIQUIDITY AND CAPITAL RE

SOURCES Connacher operates in an environment where capital resources and liquidity are impacted by changes in the price of bitumen, crude oil, natural gas and refined products, reserve finding and development costs, market uncertainty and a variety of additional factors beyond the company's control. These risks include, among others, the level of consumer demand for products, fluctuations in the Canadian dollar/US dollar exchange rate, governmental regulations, environmental risks, and overall market and global economic conditions. See "Forward-Looking Information" and "Risk Factors" for further information related to risks and other factors. Future capital expenditures, as well as borrowings under the company's credit facilities and other sources of capital, may be affected by these conditions. Historically, the company has been successful in raising funds in the Canadian equity market and the Canadian and US debt markets. The company's primary sources of current liquidity are cash, cash flow, unutilized borrowing capacity under existing revolving lines of credit and its marketable investment holding in Petrolifera, currently valued at approximately $150 million, is considered a "financial safety valve." At December 31, 2007, the company had working capital of $390 million, including $392 million of cash on hand. Of this amount, $63 million was restricted in an interest reserve account related to the Senior Notes. Connacher has no direct exposure to asset-backed commercial paper. At December 31, 2007 the company also had approximately $200 million available to be drawn on its five year term Revolving Credit Facilities. Available cash, cash flow and funds available under its available Revolving Credit Facilities are anticipated to be sufficient to fully fund the company's capital program in 2008 and to complete Algar in 2009. A significant part of the company's capital program is discretionary and may be expanded or curtailed based on drilling results and the availability of capital. This is reinforced by the fact that Connacher operates most of its wells and holds very high working interests in its oil sands and conventional properties, providing the company with operational flexibility and control of the timing of expenditures. For 2007, cash flow was $45.0 million ($0.22 per basic and diluted share), 12 percent higher than $40.2 million of cash flow ($0.22 per basic and diluted share) reported in 2006. Cash flow from operations before working capital and other changes ("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 would be net earnings. Cash flow is reconciled with net earnings on the Consolidated Statement of Cash Flows and herein. Cash flow per share is calculated by dividing cash flow by the weighted average number of shares outstanding. Management uses these non-GAAP measurements (which are common industry parameters) for its own performance measures and to provide its shareholders and investors with a measurement of the company's efficiency and its ability to fund a portion of its future growth expenditures. The company's only financial instruments are cash, restricted cash, accounts receivable and payable, amounts due from Petrolifera, the revolving credit facilities, the convertible debentures, the Senior Notes and the cross-currency interest rate swaps. The company maintains no off-balance sheet financial instruments. Connacher's capital structure is composed of: ------------------------------------------------------------------------- As at December 31 ------------------------------------------------------------------------- ($000) 2007 2006 ------------------------------------------------------------------------- Long-term debt(1) $664,462 $209,754 ------------------------------------------------------------------------- Shareholders' equity ------------------------------------------------------------------------- Share capital, contributed surplus and equity component 444,086 376,500 ------------------------------------------------------------------------- Accumulated other comprehensive loss (13,636) (130) ------------------------------------------------------------------------- Retained earnings 49,989 9,028 ------------------------------------------------------------------------- Total $1,144,901 $595,152 ------------------------------------------------------------------------- Debt to book capitalization(2) 58% 35% ------------------------------------------------------------------------- Debt to market capitalization(3) 44% 23% ------------------------------------------------------------------------- (1) Long-term debt is stated at its carrying value, which is net of fair value adjustments, original issue discounts and transaction costs. (2) Calculated as long-term debt divided by the book value of shareholders' equity plus long-term debt. (3) Calculated as long-term debt divided by the year end market value of shareholders' equity plus long-term debt. Connacher had a high calculated ratio of debt to capitalization at December 31, 2007. This resulted from Connacher's decision to pre-fund the full cost of Algar in 2007, through the issuance of US $600 million of Senior Notes. As at December 31, 2007, the company's net debt (long-term debt, net of cash on hand) to market capitalization was 24 percent. At December 31, 2007, Pod One, the company's first oil sands facility, had been commissioned into service and was commencing operations. It is anticipated that Pod One will attain its design capacity of 10,000 bbl/d of bitumen production during 2008. This is anticipated to result in substantially higher levels of revenue and resultant cash flow for the company. Such amounts, together with cash deposited in a debt service account, are anticipated to be more than sufficient to fund the company's interest costs in 2008. Reconciliation of net earnings to cash flow from operations before working capital and other changes: ------------------------------------------------------------------------- Twelve months ended December 31 ------------------------------------------------------------------------- ($000) 2007 2006 ------------------------------------------------------------------------- Net earnings $40,961 $6,953 ------------------------------------------------------------------------- Items not involving cash: ------------------------------------------------------------------------- Depletion, depreciation and accretion 31,061 32,949 ------------------------------------------------------------------------- Stock-based compensation 6,071 8,293 ------------------------------------------------------------------------- Non-cash financing charges 2,168 2,237 ------------------------------------------------------------------------- Future income tax provision (recovery) 27 (3,535) ------------------------------------------------------------------------- Employee future benefits 447 381 ------------------------------------------------------------------------- Realized foreign exchange gain (29,754) - ------------------------------------------------------------------------- Unrealized foreign exchange loss 2,854 4,287 ------------------------------------------------------------------------- Lease inducement amortization - (268) ------------------------------------------------------------------------- Dilution gain (1,917) (23) ------------------------------------------------------------------------- Equity interest in Petrolifera loss (earnings) (6,953) (11,078) ------------------------------------------------------------------------- Cash flow from operations before working capital and other changes $44,965 $40,196 ------------------------------------------------------------------------- Recent Financings Senior Notes In December 2007 the company issued US $600 million second lien eight-year notes ("Senior Notes") at an issue price of 98.657 for net proceeds of US $575 million after fees and expenses. A portion of the proceeds was used to repay the US $180 million Oil Sands Term Loan, to fully repay drawn amounts and then cancel the company's conventional oil and gas line of credit and to fund a one-year interest reserve account in the amount of US $63.6 million. The remainder of the proceeds are targeted to fund the construction of Algar. The Senior Notes bear interest at a rate of 10.25 percent, payable semi-annually on June 15 and December 15, with the first interest payment occurring on June 15, 2008. No principal repayments are required until the maturity date of December 15, 2015. This affords Connacher the opportunity to deploy its conventional, oil sands and refinery cash flow to fund the development of further expansion projects over the next eight years without having to make principal payments on the Senior Notes. The Senior Notes are secured by a second lien, subordinate to the liens under the company's revolving lines of credit, covering substantially of the company's assets with the exception of its investment in Petrolifera. The Senior Notes were rated BB by Standard & Poor's ("S&P") and B1 by Moody's. Each debt rating has a stable outlook. Standard & Poor's and Moody's gave Connacher a corporate rating of BB- and B1, respectively. The S&P rating was improved over the 2006 rating. Proceeds of the Senior Note financing were utilized as follows: ------------------------------------------------------------------------- As stated As at the time actually of financing(1) applied(1) ------------------------------------------------------------------------- ($000s) ------------------------------------------------------------------------- Gross proceeds $576,380 $591,942 ------------------------------------------------------------------------- Underwriters commissions and issue costs (13,380) (16,493) ------------------------------------------------------------------------- Repayment of Oil Sands Term Loan (186,000) (180,000) ------------------------------------------------------------------------- Funding interest reserve account (66,000) (63,600) ------------------------------------------------------------------------- Repay the conventional line of credit - (2,500) ------------------------------------------------------------------------- Net proceeds for the construction of Algar(2) $311,000 $329,349 ------------------------------------------------------------------------- (1) The Canadian dollar equivalent changed between the dates of announcing and closing the financing due to significant changes in the CDN/US exchange rates in late 2007. (2) Net proceeds are available for funding capital expenditures relating to Algar. As at December 31, 2007, $4.2 million had been spent in respect of these expenditures. In order to partially mitigate the foreign currency translation exposure on its US dollar denominated Senior Notes, the company entered into cross currency and interest rate swaps on a notional US $300 million amount. The swaps provide for a payment of C $305 million on December 15, 2015, the maturity date of the Senior Notes, in exchange for receipt of US $300 million on that date. The swaps also provide for semi-annual interest payments throughout the life of the Senior Notes at a fixed rate of 10.795 percent on a notional US $305 million of debt in exchange for the receipt of semi-annual interest payments throughout the term of the Senior Notes at a fixed rate of 10.25 percent on a notional amount of US $300 million of debt commencing June 15, 2009. These contracts have not been designated as hedges for accounting purposes and are accounted for at fair value on the balance sheet. The exchange gains and losses on the cross-currency swap are recorded in income. A portion of the payments under the interest rate swaps is being capitalized to Pod One costs (based on the proportionate use of proceeds to repay the Oil Sands Term Loan) pending commencement of commercial operations at Pod One. The remaining interest cost is being capitalized during the construction and pre-operational phase of Algar. In connection with the repayment of the Oil Sands Term Loan, the interest rate swap pertaining to the Oil Sands Term Loan was terminated in December 2007. The US $4.6 million paid upon its termination was capitalized to Pod One costs. Revolving Credit Facilities In December 2007 the company also arranged five-year revolving syndicated credit facilities ("Revolving Credit Facilities") in the amounts of US $150 million and US $50 million. Borrowings are available under the facilities in the form of Canadian or US dollar prime rate loans, US dollar base rate loans, US dollar LIBOR loans, bankers' acceptances and letters of credit. Amounts borrowed under the facilities bear interest at either a Canadian prime rate, a US base rate or LIBOR, in each case plus an applicable margin. The facilities expire in December 2012 and are secured by a first ranking lien over substantially all of the company's assets, except its investment in Petrolifera. At December 31, 2007, draws on these facilities were limited to letters of credit in the amount of US $1.8 million. Flow-through Shares In November 2007 the company issued 10,450,000 common shares on a flow-through basis at $5.00 per share for gross proceeds of $52.25 million. The company used the proceeds from this financing in December 2007 and in the first quarter of 2008 to drill exploratory core holes and shoot 3D seismic in order to further delineate its oil sands reserves and resources. The company renounced the income tax benefits of these expenditures ($52.25 million) to the subscribing investors effective December 31, 2007. Proceeds of the flow-through share financing were utilized as follows. ------------------------------------------------------------------------- As stated at As the time of actually financing applied ------------------------------------------------------------------------- ($000s) ------------------------------------------------------------------------- Gross proceeds $52,250 $52,250 ------------------------------------------------------------------------- Underwriters' commissions and issue costs (2,913) (2,748) ------------------------------------------------------------------------- Exploration expenditures (49,337) (49,502) ------------------------------------------------------------------------- $ - $ - ------------------------------------------------------------------------- Convertible Debentures On May 25, 2007, Connacher issued senior unsecured subordinated convertible debentures, ("Convertible Debentures") with a face value of $100,050,000. The debentures mature on June 30, 2012, unless converted prior to that date and bear interest at an annual rate of 4.75 percent, payable semi-annually on June 30 and December 31. The 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 debentures are redeemable in whole or in part by the company, on or after June 30, 2010 at a redemption price equal to 100 percent of the principal amount of the 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 debentures. The conversion feature of the debentures has been accounted for as a separate component of equity in the amount of $16,823,000. The remainder of the net proceeds of the debentures of $79,187,000 has been recorded as long-term debt, which amount will be accreted to the face value of $100,050,000 over the five-year term of the debentures. Accretion and interest paid are recorded as finance charges on the consolidated statement of operations. If the debentures are converted to common shares, the value of the conversion feature will be reclassified to share capital along with the principal amounts converted. Proceeds of the Convertible Debenture financing were utilized as follows. ------------------------------------------------------------------------- As stated at As the time of actually financing applied ------------------------------------------------------------------------- ($000s) ------------------------------------------------------------------------- Gross proceeds $100,050 $100,050 ------------------------------------------------------------------------- Underwriters' commissions and issue costs (3,252) (4,040) ------------------------------------------------------------------------- Net proceeds 96,798 96,010 ------------------------------------------------------------------------- Repay short-term debt (52,500) (52,500) ------------------------------------------------------------------------- Fund Pod One and other oil sands projects (35,000) (37,500) ------------------------------------------------------------------------- Fund conventional capital program (8,298) (4,810) ------------------------------------------------------------------------- Fund operating expenses (1,000) (1,200) ------------------------------------------------------------------------- Balance - - ------------------------------------------------------------------------- Property and Equipment Additions Property and equipment additions totaled $323 million in 2007. Excluding acquisitions, these 2007 additions were 79 percent higher than in 2006. Additions include certain non-cash charges for ARO and capitalized stock-based compensation. These totalled $18 million in 2007 and $9.1 million in 2006. A breakdown of property and equipment additions follows. ------------------------------------------------------------------------- Twelve months ended December 31 ------------------------------------------------------------------------- ($000) 2007 2006 ------------------------------------------------------------------------- Crude oil, natural gas, oil sands and head office $307,047 $167,917 ------------------------------------------------------------------------- Refinery 15,915 5,850 ------------------------------------------------------------------------- Minor property acquisitions - 6,767 ------------------------------------------------------------------------- Acquisition of Luke - 204,658 ------------------------------------------------------------------------- Acquisition of refinery assets - 66,333 ------------------------------------------------------------------------- $322,962 $451,525 ------------------------------------------------------------------------- Oil sands expenditures of $256 million were incurred in 2007 primarily to complete the Pod One facilities and to drill the 15 horizontal SAGD wells ($166 million) and to delineate further reserves and resources by drilling 75 core holes and shooting and evaluating 3D seismic ($36 million). In 2006, a total of $145 million was spent primarily to commence the construction of the Pod One facility ($106 million) and for delineation ($23 million). Connacher's total cost of the Pod One facility and its 15 horizontal SAGD well pairs was $272 million. Crude oil and natural gas capital expenditures of $45 million were incurred in 2007 (2006 - $23 million) for drilling, completing, equipping and working over conventional oil and gas wells and for undeveloped land acquisition and seismic expenditures. In 2007, Connacher drilled 22 gross, 21 net, conventional oil and gas wells. Head office capital expenditures of $6 million in 2007 related to office leasehold improvements, furniture and information technology costs. A significant part of the company's capital program is discretionary and may be expanded or curtailed based on drilling results and the availability of capital. This is reinforced by the fact that Connacher operates most of its wells and holds very high working interests in its oil sands and conventional properties, providing the company with operational flexibility and timing controls. Great Divide Oil Sands Project, Northern Alberta At December 31, 2007, the company held a 100 percent working interest in approximately 95,000 acres of oil sands leases in northern Alberta. In 2007, Connacher constructed and commissioned its first 10,000 bbl/d oil sands project, Pod One and applied to Alberta governmental regulators for approval to commence construction of its second 10,000 bbl/d oil sands project, Algar. In anticipation of receiving this approval in the first half of 2008, the company raised funds in December 2007 to finance this project in 2008 and 2009. The company is currently conducting a winter core hole drilling and 3D seismic interpretation program, the objective of which is to delineate additional oil sands reserves and resources. These would further support the development of additional oil sands projects. FOURTH QUARTER Connacher's fourth quarter 2007 results reflected the company's focus on completion of Pod One, normal production declines awaiting new volumes of natural gas at Marten Creek and Randall, weak natural gas prices and higher operating costs. Revenue and cash flow decreased from the prior quarter due to seasonal factors at the Montana refinery and narrower heavy oil price differentials and cash flow in the current year was lower than in 2006 due to higher costs. A loss of $840,000 was recorded in the fourth quarter of 2007 compared to higher earnings in the third quarter of 2007 and the fourth quarter of 2006. The company completed major financing transactions in the fourth quarter 2007 to position it for construction of Algar in 2008 and 2009. OUTLOOK The company's business plan anticipates continued growth, with stronger production revenue and cash flow as Pod One becomes commercial and included in our accounts. Emphasis will continue to be on delineating and developing the Great Divide oil sands project in Alberta, while developing the company's recently-expanded conventional production base and profitably operating the Montana refinery. Additional financing may be required for other projects at Great Divide, for the company's conventional petroleum and natural gas assets and for the Montana refinery, especially if a decision is made to expand the refinery's throughput capacity. The company's first 10,000 bbl/d oil sands project, Pod One, was completed on schedule in 2007. Its fifteen horizontal well pairs are presently being placed on production. It is anticipated that the targeted production volume of 10,000 bbl/d will be achieved in 2008. The company's second project, Algar, is expected to commence a 10-month period of construction in the second half of 2008, upon prior receipt of the necessary governmental regulatory approvals. As most of the features of Algar will be similar to Pod One, Algar's construction timetable is generally expected to be similar to that of Pod One and, therefore, production from Algar is anticipated to commence in late 2009 or early 2010 and ramp up to add an additional 10,000 bbl/d to Connacher's growing production base. The cost of Algar is budgeted at $326 million with contingencies, scope changes and for increased costs for related infrastructure. Additional 10,000 bbl/d oil sands projects (pods) are anticipated, subject to confirmation of definitive additional reserves and resources. Achievement of this timeline is dependent on a number of factors which are outside of the control of the company. Information relating to Connacher, including Connacher's Annual Information Form is on SEDAR at www.sedar.com. See also the company's website at www.connacheroil.com. RELATED PARTY TRANSACTIONS In 2007 the company paid professional legal fees of $667,000 (2006 - $1.8 million) to a law firm in which an officer and director of the company are partners. Transactions with the foregoing related parties 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 by the related parties. 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. 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. The following assessment of significant accounting polices and critical accounting estimates is not meant to be exhaustive. Reserve Estimates Under Canadian Securities Administrators' "National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities" ("NI 51-101") proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. In accordance with this definition, the level of certainty should result in at least a 90 percent probability that the quantities actually recovered will exceed the estimated reserves. In the case of probable reserves, which are less certain to be recovered than proved reserves, NI 51-101 states that it must be 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 reserves less certain to be recovered than probable reserves. There is at least a 10 percent probability that the quantities actually recovered will exceed the sum of proved plus probable plus possible reserves. 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 reserve estimates on the financial results and financial 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 development 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 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 commencement of commercial operations. All capitalized costs are reviewed quarterly and any impairment is transferred to the costs being depleted or, if the properties are located in a cost centre where there is no reserve base, the impairment is charged directly to income. Currently, all costs related to the Great Divide oil sands project are being capitalized pending commencement of commercial operations. Upon commencement of commercial operations, the capital costs and estimates of future capital requirements will be added to the company's depletable costs and depleted under the unit-of-production method based on the company's total proved reserves. Ceiling Test The company is required to review the carrying value of all property, plant and equipment, including the carrying value of oil and gas assets, for potential impairment. Impairment is indicated if the carrying value of the long-lived asset or 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 the long-lived asset is charged to earnings. The ceiling test is based on estimates of reserves prepared by qualified independent evaluators, production rate, petroleum and natural gas prices, future 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 of changes to 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 subject to management uncertainty. Legal, Environmental Remediation 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 also to 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 differences reverse is impacted by future income and capital expenditures. Rates are also affected by legislative changes. These components can impact the charge for future income taxes. Stock-Based Compensation The company uses the fair value method to account for stock options. The determination of the amounts for stock-based compensation are based on estimates of stock volatility, interest rates and the term of the option. By their nature, these estimates are subject to measurement uncertainty. NEW SIGNIFICANT ACCOUNTING POLICIES Convertible Debentures The Convertible Debentures have been recorded as a compound financial instrument in accordance with Section 3861 of the CICA Handbook. The fair value of the liability component was determined at the date of issue based on the company's incremental borrowing rate for debt with similar terms. 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. Share Award Plan Obligations for payments in cash or common shares under the company's share award plan for non-employee directors are accrued as compensation expense over the vesting period. Fluctuations in the price of the company's common shares change the accrued compensation expense and are recognized when they occur. Financial Instruments and Comprehensive Income Effective January 1, 2007, the company's accounting policies for financial instruments and comprehensive income are as follows: All financial instruments are recognized at estimated fair value on the consolidated balance sheet at each balance sheet date. The estimated fair value of financial instruments is determined based on appropriate internal valuation methodologies and/or third party indications. However, these estimates may not necessarily be indicative of the amounts that will be realized or settled in a current market transaction and these differences may be material. The company would formally document any derivative financial instruments to be designated as hedging transactions at the inception of the hedging relationship, in accordance with the company's risk management policies. The effectiveness of the hedging relationship must be evaluated, both at inception of the hedge and on an ongoing basis. The company periodically enters into commodity price contracts to manage anticipated sales of crude oil and natural gas production in order to protect cash flow for capital expenditure programs. To date, these transactions have not been designated as hedges and all changes in the fair value of these crude oil and natural gas commodity price contracts are recognized in consolidated net earnings. The company periodically enters into cross-currency and interest rate swap contracts to manage its foreign currency exposure on US-dollar denominated long-term debt and its fixed and floating interest rate mix on certain of its long-term debt. The interest rate swap contracts require the periodic exchange of payments on the notional principal amount on which the swap is based. Changes in the fair value of cross currency and interest rate swap contracts are included in consolidated net earnings or are capitalized as appropriate in the particular circumstances. Gains or losses on derivative financial instruments that have been designated as cash flow hedges would be deferred under accumulated other comprehensive income on the consolidated balance sheets and amortized into consolidated net earnings in the period in which the underlying hedged item is recognized. In the event a designated hedged item is sold, extinguished or matures prior to the termination of the related derivative instrument, any unrealized derivative gain or loss would be recognized immediately in consolidated net earnings. Gains or losses on the termination of financial instruments that have not been designated as hedges would be recognized in consolidated net earnings immediately. Currently, Connacher does not have any derivative financial instruments designated as hedges for accounting purposes. Embedded derivatives are derivatives that are included in a non-derivative host contract. Embedded derivatives are recorded at fair value separately from the host contract when their economic characteristics and risks are not clearly and closely related to the host contract. Transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability and original issue discounts on long-term debt have been included in the carrying value of the financial asset or liability and are amortized to consolidated net earnings over the life of the financial instrument using the effective interest method. As of January 1, 2008, the company will be required to adopt two new CICA Handbook requirements, section 3862, "Financial Instruments - Disclosures" and section 3863, "Financial Instruments - Presentation" which will replace current section 3861. The new standards require disclosure of the significance of financial instruments to an entity's financial statements, the risks associated with the financial instruments and how those risks are managed. The new presentation standard essentially carries forward the current presentation requirements. The company is assessing the impact of these new standards. As of January 1, 2008, the company will be required to adopt CICA Handbook section 1535, "Capital Disclosures" which requires entities to disclose their objectives, policies and processes for managing capital and, in addition, whether the entity has complied with any externally imposed capital requirements. The company is assessing the impact of this new standard. In February 2008, the CICA issued Section 3064, "Goodwill and Intangible Assets", replacing Section 3062, "Goodwill and Other Intangible Assets" and Section 3450, "Research and Development Costs." Various changes have been made to other sections of the CICA Handbook for consistency purposes. The new Section will be applicable to financial statements relating to fiscal years beginning on or after October 1, 2008. Accordingly, the company will adopt the new standards for its fiscal year beginning January 1, 2009. It establishes standards for the recognition, measurement, presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit-oriented enterprises. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. The company is currently evaluating the impact of the adoption of this new Section. INTERNATIONAL FINANCIAL REPORTING STANDARDS Over the next few years the CICA will adopt its new strategic plan for the direction of accounting standards in Canada, which was ratified in January 2006. As part of the plan, Canadian GAAP for public companies will converge with International Financial Reporting Standards ("IFRS") over the next few years. The company is currently assessing the impact of the convergence of Canadian GAAP with IFRS on its financial statements and expects to begin work on the conversion process later in 2008. RISK FACTORS AND RISK MANAGEMENT The lack of established markets for bitumen and the volatility of crude oil, natural gas and refined product prices may have a material adverse effect on Connacher's cash flow and results of operations. In recent years, the prices of crude oil, natural gas and refined products have fluctuated substantially. These prices depend on numerous factors beyond the company's control, including the global supply and demand for these products, which are subject to, among other things: - Changes in the global economy and the level of foreign and domestic production of crude oil and refined products; - Threatened or actual terrorists incidents, acts of war and other global political conditions; - Availability of crude oil, natural gas and refined products and the infrastructure to transport crude oil, natural gas and refined products; - Weather conditions, hurricanes or other natural disasters; - Government regulations; and - Local factors, including market conditions, the level of operations of other oil and gas companies and refineries. The oil and gas industry has inherent risks. Drilling, exploring and operating oil and gas properties and refineries is inherently subject to spills, discharges or other releases of petroleum or hazardous substances. If any of these events occur in the future in connection with any of the company's operations or facilities, other than events for which the company is indemnified, the company could be liable for all costs and penalties associated with their remediation under federal, provincial state and local environmental laws or common law and could be liable for property damage to third parties caused by contamination from releases and spills. The penalties and clean-up costs that the company may have to pay for releases or spills, could be significant and the payment of these amounts could have a material adverse effect on Connacher's business, financial condition and results of operations. Connacher operates in some environmentally sensitive areas closely regulated by federal, provincial, state and local agencies and monitored by environmental interest groups. Transportation of bitumen, crude oil and refined products involves inherent risk. The dangers inherent in oil and gas and refining operations and the potential limits on insurance coverage could expose the company to potentially significant liability costs. Connacher's operations are subject to hazards and risks inherent in oil and gas and refining operations and in transporting and storing crude oil and refined products, such as blowouts, fires, natural disasters, explosions, pipeline ruptures and spills and mechanical failures of equipment, any of which can result in damage to Connacher's properties and the properties of others. A serious accident could also result in serious injury or death to employees or contractors and could expose the company to significant liability for personal injury claims and reputational risk. Any unplanned shutdown could have a material adverse effect on Connacher's business, financial condition and results of operations. Various insurance coverages are maintained in accordance with industry practices. However, Connacher is not fully insured against all risks because certain risks are not fully insurable, coverage is unavailable, or, in management's judgment, premium costs are prohibitive in relation to the perceived risks. Oil and gas and refining operations are subject to general environmental risks, expenses and liabilities which could affect results of operations. From time to time Connacher could be subject to litigation and investigations with respect to environmental and related matters, including product liability claims. Consistent with the experience of other oil and gas companies and refineries, environmental laws and regulations have raised operating costs and require significant capital investments. Management believes that existing physical facilities are substantially adequate to maintain compliance with existing applicable laws and regulatory requirements. However, potentially material expenditures could be required in the future. Currently, various legislative and regulatory measures to address greenhouse gas emissions are in various phases of discussion or implementation. These actions could result in increased costs to (i) operate and maintain facilities, (ii) install new emission controls on facilities and (iii) administer and manage any greenhouse gas emissions program. These actions could also impact the production and consumption of bitumen, crude oil, natural gas and refined products, thereby affecting Connacher's operations. Certain strategies have been employed to reduce commodity price and operational risks. No attempt will be made to eliminate all market risk exposures when it is believed the exposure relating to such risk would not be significant to future earnings, financial position, capital resources or liquidity or that the cost of eliminating the exposure could outweigh the benefit. The refinery's profitability will depend largely on the spread between market prices for refined products sold and market prices for crude oil purchased. A substantial or prolonged reduction in this spread could have a significant negative effect on earnings, financial condition and cash flows. Petroleum commodity futures contracts could be utilized to reduce exposure to price fluctuations associated with crude oil and refined products. Such contracts could be used principally to help manage the price risk inherent in purchasing crude oil in advance of the delivery date and as a hedge for fixed-price sales contracts of refined products. Commodity price swaps and collar options could also be utilized to help manage the exposure to price volatility relating to forecasted purchases of natural gas. Contracts could also be utilized to provide for the purchase of crude oil and other feedstocks and for the sales of refined products. Certain of these contracts may meet the definition of a hedge and may be subject to hedge accounting. The company has issued parental guarantees and indemnifications on behalf of the Montana refinery operations. This is considered to be in the normal course of business. Connacher is also guarantor for Petrolifera in Peru and operator of record on behalf of Petrolifera in Colombia for which Connacher is indemnified by Petrolifera. The company has not entered into any off-balance sheet arrangements. Connacher is exposed to certain risks and uncertainties inherent in the oil and gas business. Furthermore, being a smaller independent company, it is exposed to financing and other risks which may impair its ability to realize on its assets or to capitalize on opportunities which might become available to it. Additionally, through the company's investment in Petrolifera which operates in foreign jurisdictions, it has become exposed to other risks including currency fluctuations, political risk, price controls and varying forms of fiscal regimes or changes thereto which may impair Petrolifera's ability to conduct profitable operations. The risks arising in the oil and gas industry include price fluctuations for crude oil, natural gas and bitumen over which the company has limited control; risks arising from exploration and development activities; production risks associated with the depletion of reservoirs and the ability to market production. Additional risks include environmental and safety concerns. The company is expected to require a significant amount of natural gas in order to generate steam for the SAGD process used at its Great Divide Oil Sands Project. The company is exposed to the risk of changes in the price of natural gas, which could increase operating costs of the Great Divide project. This risk is mitigated to a certain extent by the production and sale of natural gas from the company's natural gas properties. Additionally, the company is exposed to exchange rate fluctuations since oil prices and its long term debt are denominated in US dollars, while the majority of its operating and capital costs are denominated in Canadian dollars. On an economic basis, the company's crude oil and bitumen reserves and its refinery operations hedge the company's exposure to foreign currency fluctuations of its US dollar denominated term debt. Bitumen is generally less marketable than light or medium crude oil, and prices received for bitumen are generally lower than those for crude oil. The company is therefore exposed to the price differential between crude oil and bitumen; fluctuations in this differential could have a material impact on the company's profitability. The fact that the Montana refinery processes heavy crude oil provides a physical hedge, protecting Connacher's future cash flows against crude oil/bitumen price differentials. The company relies on access to capital markets for new equity to supplement internally generated cash flow and debt to finance its growth plans. Periodically, these markets may not be receptive to offerings of new equity from treasury or debt, whether by way of private placement or public offerings. This may be further complicated by the limited market liquidity for shares of smaller companies, restricting access to some institutional investors. Periodic fluctuations in energy prices may also affect lending policies of the company's bankers, whether for existing loans or new borrowings. This in turn could limit growth prospects over the short run or may even require the company to dedicate cash flow, dispose of properties or raise new equity to reduce bank borrowings under circumstances of declining energy prices or disappointing drilling results. The success of the company's capital programs as embodied in its productivity and reserve base could also impact its prospective liquidity and pace of future activities. Control of finding, development, operating and overhead costs per boe is an important criterion in determining company growth, success and access to new capital sources. The company attempts to mitigate its business and operational risk exposures by maintaining comprehensive insurance coverage on its assets and operations, by employing or contracting competent technicians and professionals, by instituting and maintaining operational health, safety and environmental standards and procedures and by maintaining a prudent approach to exploration and development activities. The company also addresses and regularly reports on the impact of risks to its shareholders, writing down the carrying values of assets that may not be recoverable. The company generally relies on equity and debt financing and has a bias towards conservatively financing its operations under normal industry conditions, to offset the inherent risks of domestic and international oil and gas exploration, development and production activities. Recently, with an expanded reserve base, long-term borrowings on acceptable terms have been available to reduce the need for substantial or additional equity dilution. Over time, the company's objective is to internally finance its growth, repay its debt and provide a financial return to shareholders alongside value appreciation. In the past the company has entered into price collars and forward sale, fixed price contracts to mitigate reduced product price risk and foreign exchange risk during periods of price improvement, primarily with a view to assuring the availability of funds for capital programs and to enhance the creditworthiness of its assets with its lenders. While hedging activities may have opportunity costs when realized prices exceed hedged pricing, such transactions are not meant to be speculative and are considered within the broader framework of financial stability and flexibility. Management continuously reviews the need to utilize such financing techniques. COMMITMENTS, CONTINGENCIES, GUARANTEES, CONTRACTUAL OBLIGATIONS AND OFF BALANCE SHEET ARRANGEMENTS The company's annual commitments under leases for office premises and operating costs, software license agreements and other equipment, and long term debt are as follows: ------------------------------------------------------------------------- Contractual obligations 2009- 2012- Subsequent ($000) 2008 2011 2013 to 2013 Total ------------------------------------------------------------------------- Principal repayment of term debt $ - $ - $100,050 $612,735 $712,785 ------------------------------------------------------------------------- Asset retirement obligations 300 900 600 22,565 24,365 ------------------------------------------------------------------------- Operating leases 3,355 8,254 5,536 9,688 26,833 ------------------------------------------------------------------------- Employee future benefits 261 - - - 261 ------------------------------------------------------------------------- Total $3,916 $9,154 $106,186 $644,988 $764,244 ------------------------------------------------------------------------- The company's US subsidiary, MRCI, maintains a non-contributory defined benefit retirement plan (the "Plan") covering MRCI's employees. MRCI's policy is to make regular contributions in accordance with applicable regulations as determined by regular actuarial valuations. The company's pension obligation is based on the employees' years of service and compensation, effective from, and after, March 31, 2006, the date that Connacher acquired these refining assets. In 2007, MRCI fully funded the Plan's cost for 2006 and 2007 and as at December 31, 2007 the Plan Assets ($757,000) exceeded the Accrued Benefit Obligation ($617,000) by $140,000. Connacher's balance sheet does not reflect this over funded amount as an asset. The above table excludes ongoing crude oil and refined product purchase commitments of the Montana refinery, which are in the normal course of business and are contacted at market prices, where the products are for resale into the market. Connacher is subject to financial and other covenants related to the Convertible Debentures, Senior Notes and Revolving Credit Facilities. Failure to meet the terms of one or more of these covenants could constitute an Event of Default as defined in the respective debt agreements, potentially resulting in accelerated repayment of one or more of the company's debt obligations. Additionally, the company has various guarantees and indemnifications in place in the ordinary course of business, none of which are expected to have a significant impact on the company's financial statements or operations. The company has not entered into any off-balance sheet arrangements. DISCLOSURE CONTROLS AND PROCEDURES Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the company is accumulated, recorded, processed and reported to the company's management as appropriate to allow timely decisions regarding required disclosure. The company's Chief Executive Officer and Chief Financial Officer have concluded, based on their evaulation as of the end of the period covered by this MD&A, that the company's disclosure controls and procedures as of the end of such period are effective to provide reasonable assurance that material information related to the company, including its consolidated subsidiaries, is communicated to them as appropriate to allow timely decisions regarding required disclosure. INTERNAL CONTROL OVER FINANCIAL REPORTING Management of the company is responsible for designing adequate internal controls over the company's financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. It should be noted that while the company's Chief Executive Officer and Chief Financial Officer believe that the company's disclosure controls and procedures provide a reasonable level of assurance that they are effective and that the internal controls over financial reporting are adequately designed, they do not expect that the financial disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. QUARTERLY RESULTS Fluctuations in results over the previous eight quarters are due principally to variations in oil and gas prices and reflect the acquisitions of Luke and the Montana refinery in 2006, both of which substantially increased revenues. Bitumen sales of 29,000 barrels were capitalized during the fourth quarter of 2007 awaiting the declaration of commerciality for Pod One. ------------------------------------------------------------------------- 2006 ------------------------------------------------------------------------- Three Months Ended Mar 31 Jun 30 Sept 30 Dec 31 ------------------------------------------------------------------------- Financial Highlights ($000 except per share amounts) - Unaudited ------------------------------------------------------------------------- Revenue net of royalties 3,635 61,239 103,110 76,700 ------------------------------------------------------------------------- Cash flow(1) 1,725 9,499 14,957 14,015 ------------------------------------------------------------------------- Basic, per share(1) 0.01 0.05 0.08 0.08 ------------------------------------------------------------------------- Diluted, per share(1) 0.01 0.05 0.08 0.07 ------------------------------------------------------------------------- Net earnings (loss) (666) (2,419) 6,771 3,267 ------------------------------------------------------------------------- Basic and diluted per share - (0.01) 0.03 0.02 ------------------------------------------------------------------------- Property and equipment additions 300,836 34,280 41,449 74,960 ------------------------------------------------------------------------- Cash on hand - 7,505 14,450 142,391 ------------------------------------------------------------------------- Working capital surplus (deficiency) (11,061) (42,483) (39,942) 118,626 ------------------------------------------------------------------------- Debt 17,600 70,365 62,380 229,254 ------------------------------------------------------------------------- Shareholders' equity 337,584 340,639 378,730 385,398 ------------------------------------------------------------------------- Operating Highlights ------------------------------------------------------------------------- Production / sales volumes ------------------------------------------------------------------------- Natural gas - mcf/d 2,600 15,172 12,711 11,291 ------------------------------------------------------------------------- Crude oil - bbl/d 689 1,026 1,059 1,139 ------------------------------------------------------------------------- Equivalent - boe/d(2) 1,122 3,554 3,177 3,021 ------------------------------------------------------------------------- Pricing ------------------------------------------------------------------------- Crude oil - $/bbl 40.93 61.45 62.53 46.65 ------------------------------------------------------------------------- Natural gas - $/mcf 6.34 5.66 5.33 6.57 ------------------------------------------------------------------------- Selected Highlights - $/boe(2) ------------------------------------------------------------------------- Weighted average sales price 39.83 41.88 42.16 42.15 ------------------------------------------------------------------------- Royalties 8.02 10.43 10.72 9.00 ------------------------------------------------------------------------- Operating costs 8.24 7.63 7.99 9.27 ------------------------------------------------------------------------- Operating netback(3) 23.57 23.82 23.45 23.88 ------------------------------------------------------------------------- Refining throughput ------------------------------------------------------------------------- Crude charged (bbl/d) 6,864 9,613 9,642 ------------------------------------------------------------------------- Refining utilization (%) 83 101 102 ------------------------------------------------------------------------- Margins (%) 8 16 15 ------------------------------------------------------------------------- Common Share Information ------------------------------------------------------------------------- Shares outstanding at end of quarter (000) 191,257 191,924 197,878 197,894 ------------------------------------------------------------------------- Weighted average shares outstanding for the quarter ------------------------------------------------------------------------- Basic (000) 154,152 191,672 193,587 193,884 ------------------------------------------------------------------------- Diluted (000) 160,574 198,931 200,572 204,028 ------------------------------------------------------------------------- Volume traded during quarter (000) 148,184 80,347 48,849 46,444 ------------------------------------------------------------------------- Common share price ($) ------------------------------------------------------------------------- High 6.07 5.05 4.55 4.43 ------------------------------------------------------------------------- Low 3.47 3.10 3.09 3.17 ------------------------------------------------------------------------- Close (end of period) 4.95 4.30 3.60 3.49 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2007 ------------------------------------------------------------------------- Three Months Ended Mar 31 Jun 30 Sept 30 Dec 31 ------------------------------------------------------------------------- Financial Highlights ($000 except per share amounts) - Unaudited ------------------------------------------------------------------------- Revenue net of royalties 65,923 93,266 101,991 83,340 ------------------------------------------------------------------------- Cash flow(1) 10,980 16,876 10,025 7,084 ------------------------------------------------------------------------- Basic, per share(1) 0.06 0.09 0.05 0.03 ------------------------------------------------------------------------- Diluted, per share(1) 0.05 0.08 0.05 0.03 ------------------------------------------------------------------------- Net earnings (loss) 4,984 22,228 14,589 (840) ------------------------------------------------------------------------- Basic and diluted per share 0.03 0.11 0.07 (0.00) ------------------------------------------------------------------------- Property and equipment additions 109,881 93,223 64,006 55,852 ------------------------------------------------------------------------- Cash on hand 66,209 25,375 754 392,271 ------------------------------------------------------------------------- Working capital surplus (deficiency) 24,027 36,320 (19,853) 389,789 ------------------------------------------------------------------------- Debt 207,828 272,559 260,606 664,462 ------------------------------------------------------------------------- Shareholders' equity 384,593 417,793 428,764 480,439 ------------------------------------------------------------------------- Operating Highlights ------------------------------------------------------------------------- Production / sales volumes ------------------------------------------------------------------------- Natural gas - mcf/d 9,665 9,017 9,413 8,889 ------------------------------------------------------------------------- Crude oil - bbl/d 905 731 781 752 ------------------------------------------------------------------------- Equivalent - boe/d(2) 2,515 2,234 2,350 2,233 ------------------------------------------------------------------------- Pricing ------------------------------------------------------------------------- Crude oil - $/bbl 49.09 49.79 55.98 56.79 ------------------------------------------------------------------------- Natural gas - $/mcf 7.76 7.02 4.70 5.82 ------------------------------------------------------------------------- Selected Highlights - $/boe(2) ------------------------------------------------------------------------- Weighted average sales price 47.48 44.63 37.43 42.29 ------------------------------------------------------------------------- Royalties 11.22 3.23 6.32 6.34 ------------------------------------------------------------------------- Operating costs 8.54 13.08 9.00 13.77 ------------------------------------------------------------------------- Operating netback(3) 27.72 28.32 22.11 22.18 ------------------------------------------------------------------------- Refining throughput ------------------------------------------------------------------------- Crude charged (bbl/d) 9,621 9,248 9,400 9,610 ------------------------------------------------------------------------- Refining utilization (%) 101 97 100 101 ------------------------------------------------------------------------- Margins (%) 19 21 15 6 ------------------------------------------------------------------------- Common Share Information ------------------------------------------------------------------------- Shares outstanding at end of quarter (000) 198,218 198,834 199,447 209,971 ------------------------------------------------------------------------- Weighted average shares outstanding for the quarter ------------------------------------------------------------------------- Basic (000) 198,119 198,360 198,539 204,701 ------------------------------------------------------------------------- Diluted (000) 200,008 209,088 210,580 220,362 ------------------------------------------------------------------------- Volume traded during quarter (000) 55,292 61,162 70,939 52,198 ------------------------------------------------------------------------- Common share price ($) ------------------------------------------------------------------------- High 4.13 4.43 4.40 4.08 ------------------------------------------------------------------------- Low 3.07 3.07 3.20 3.31 ------------------------------------------------------------------------- Close (end of period) 3.86 3.69 4.01 3.79 ------------------------------------------------------------------------- (1) Cash flow and cash flow per share do not have standardized meanings prescribed by Canadian generally accepted accounting principles ("GAAP") and therefore may not be comparable to similar measures used by other companies. Cash flow is calculated before changes in non- cash working capital and other changes. The most comparable measure calculated in accordance with GAAP would be net earnings. Cash flow is reconciled with net earnings on the Consolidated Statement of Cash Flows and in the accompanying Management Discussion & Analysis. Management uses these non-GAAP measurements for its own performance measures and to provide its shareholders and investors with a measurement of the company's efficiency and its ability to fund a portion of its future growth expenditures. (2) All references to barrels of oil equivalent (boe) are calculated on the basis of 6 mcf : 1 bbl. Boe may be misleading, particularly if used in isolation. 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. (3) Netback is a non-GAAP measure used by management as a measure of operating efficiency and profitability. It is calculated as petroleum and natural gas revenue less royalties and operating costs. For a reconciliation of netback to net earnings, refer to this MD&A. CONSOLIDATED FINANCIAL STATEMENTS MANAGEMENT'S REPORT To the Shareholders of Connacher Oil and Gas Limited: The consolidated financial statements of Connacher Oil and Gas Limited were prepared by and are the responsibility of management. The consolidated financial statements have been prepared in conformity with Canadian generally accepted accounting principles appropriate in the circumstances and include some amounts that are based on managements' best estimates and judgments. Information contained elsewhere in the Annual Report is consistent, where applicable, with information contained in the consolidated financial statements. The company maintains systems of internal accounting controls designed to provide reasonable assurance that all transactions are properly recorded in the company's books and records, that policies and procedures are adhered to and that the assets are protected from unauthorized use. The systems of internal accounting controls are complemented by the selection, training and development of qualified staff. The consolidated financial statements have been audited by the independent accounting firm Deloitte & Touche LLP, whose appointment is ratified annually by the shareholders at the annual shareholders' meeting. The independent accountants perform such tests and related procedures as they deem necessary to arrive at an opinion on the fairness of the consolidated financial statements. The audit committee of the board of directors periodically meets with the independent accountants and management to satisfy they are properly discharging their responsibilities. The independent accountants have unrestricted access to the audit committee, without management present, to discuss the results of their examination and the quality of financial reporting and internal accounting controls. Signed, Signed, "R.A. Gusella" "R. R. Kines" President and Chief Executive Vice President, Finance and Chief Officer Financial Officer March 12, 2008 March 12, 2008 AUDITORS' REPORT To the Shareholders of Connacher Oil and Gas Limited: We have audited the consolidated balance sheets of Connacher Oil and Gas Limited as at December 31, 2007 and 2006 and the consolidated statements of operations and retained earnings and cash flow for the years then ended and the consolidated statements of comprehensive income and accumulated other comprehensive loss for the year ended December 31, 2007. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the company as at December 31, 2007 and 2006 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles. Signed, Calgary, Alberta "DELOITTE & TOUCHE LLP" March 12, 2008 Chartered Accountants Connacher Oil and Gas Limited CONSOLIDATED BALANCE SHEETS December 31 ------------------------------------------------------------------------- ($000) 2007 2006 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ASSETS ------------------------------------------------------------------------- CURRENT ------------------------------------------------------------------------- Cash $329,110 $19,603 ------------------------------------------------------------------------- Restricted cash (Note 16) 63,161 122,788 ------------------------------------------------------------------------- Accounts receivable 25,084 30,956 ------------------------------------------------------------------------- Inventories (Note 5) 18,379 24,437 ------------------------------------------------------------------------- Due from Petrolifera (Note 6) - 32 ------------------------------------------------------------------------- Prepaid expenses 2,520 1,525 ------------------------------------------------------------------------- Income taxes recoverable 4,279 - ------------------------------------------------------------------------- 442,533 199,341 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Property and equipment (Note 7) 671,422 384,311 ------------------------------------------------------------------------- Goodwill (Note 4) 103,676 103,676 ------------------------------------------------------------------------- Investment in Petrolifera (Note 6) 35,610 21,597 ------------------------------------------------------------------------- Deferred costs (Note 8) 5,587 4,005 ------------------------------------------------------------------------- $1,258,828 $712,930 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES ------------------------------------------------------------------------- CURRENT ------------------------------------------------------------------------- Accounts payable and accrued liabilities $52,744 $57,571 ------------------------------------------------------------------------- Income taxes payable - 3,644 ------------------------------------------------------------------------- Revolving line of credit (Note 9) - 19,500 ------------------------------------------------------------------------- 52,744 80,715 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Long-term debt (Note 9) 664,462 209,754 ------------------------------------------------------------------------- Future income taxes (Note 10) 36,818 29,353 ------------------------------------------------------------------------- Asset retirement obligations (Note 11) 24,365 7,322 ------------------------------------------------------------------------- Employee future benefits (Note 12) - 388 ------------------------------------------------------------------------- 778,389 327,532 ------------------------------------------------------------------------- ------------------------------------------------------------------------- SHAREHOLDERS' EQUITY ------------------------------------------------------------------------- Share capital, contributed surplus and equity component (Note 13) 444,086 376,500 ------------------------------------------------------------------------- Accumulated other comprehensive loss (13,636) (130) ------------------------------------------------------------------------- Retained earnings 49,989 9,028 ------------------------------------------------------------------------- 480,439 385,398 ------------------------------------------------------------------------- $1,258,828 $712,930 ------------------------------------------------------------------------- Commitments, contingencies and guarantees (Note 17) Approved by the Board Signed, Signed, "D.H. Bessell", Director "C.M. Evans", Director Connacher Oil and Gas Limited CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS Years Ended December 31 ------------------------------------------------------------------------- ($000, except per share amounts) 2007 2006 ------------------------------------------------------------------------- ------------------------------------------------------------------------- REVENUE ------------------------------------------------------------------------- Petroleum and natural gas revenue, net of royalties $30,722 $31,786 ------------------------------------------------------------------------- Refining and marketing sales 313,050 211,874 ------------------------------------------------------------------------- Interest and other income 748 1,024 ------------------------------------------------------------------------- 344,520 244,684 ------------------------------------------------------------------------- EXPENSES ------------------------------------------------------------------------- Petroleum and natural gas operating costs 9,364 8,270 ------------------------------------------------------------------------- Refining - crude oil purchases and operating costs 264,848 182,668 ------------------------------------------------------------------------- General and administrative 8,543 3,886 ------------------------------------------------------------------------- Stock-based compensation (Note 13) 5,650 7,816 ------------------------------------------------------------------------- Finance charges 6,858 5,086 ------------------------------------------------------------------------- Foreign exchange (gain) loss (26,900) 4,287 ------------------------------------------------------------------------- Depletion, depreciation and accretion 31,061 32,949 ------------------------------------------------------------------------- 299,424 244,962 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Earnings (loss) before income taxes and other items 45,096 (278) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Current income tax provision (Note 10) 12,978 7,405 ------------------------------------------------------------------------- Future income tax provision (recovery) (Note 10) 27 (3,535) ------------------------------------------------------------------------- 13,005 3,870 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Earnings (loss) before other items 32,091 (4,148) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Equity interest in Petrolifera earnings (Note 6) 6,953 11,078 ------------------------------------------------------------------------- Dilution gain (Note 6) 1,917 23 ------------------------------------------------------------------------- ------------------------------------------------------------------------- NET EARNINGS 40,961 6,953 ------------------------------------------------------------------------- ------------------------------------------------------------------------- RETAINED EARNINGS, BEGINNING OF YEAR 9,028 2,075 ------------------------------------------------------------------------- ------------------------------------------------------------------------- RETAINED EARNINGS, END OF YEAR $49,989 $9,028 ------------------------------------------------------------------------- ------------------------------------------------------------------------- EARNINGS PER SHARE (Note 16(a)) ------------------------------------------------------------------------- Basic and diluted $0.20 $0.04 ------------------------------------------------------------------------- Connacher Oil and Gas Limited CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME Year Ended December 31 ------------------------------------------------------------------------- ($000) 2007 ------------------------------------------------------------------------- Net earnings $40,961 ------------------------------------------------------------------------- Foreign currency translation adjustment (13,506) ------------------------------------------------------------------------- Net comprehensive income $27,455 ------------------------------------------------------------------------- CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE LOSS Year Ended December 31 ------------------------------------------------------------------------- ($000) 2007 ------------------------------------------------------------------------- Balance, beginning of year $(130) ------------------------------------------------------------------------- Foreign currency translation adjustment (13,506) ------------------------------------------------------------------------- Balance, end of year $(13,636) ------------------------------------------------------------------------- Connacher Oil and Gas Limited CONSOLIDATED STATEMENTS OF CASH FLOW Years Ended December 31 ------------------------------------------------------------------------- ($000) 2007 2006 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Cash provided by (used in) the following activities: ------------------------------------------------------------------------- OPERATING ------------------------------------------------------------------------- Net earnings $40,961 $6,953 ------------------------------------------------------------------------- Items not involving cash: ------------------------------------------------------------------------- Depletion, depreciation and accretion 31,061 32,949 ------------------------------------------------------------------------- Stock-based compensation (Note 13) 6,071 8,293 ------------------------------------------------------------------------- Finance charges - non-cash portion 2,168 2,237 ------------------------------------------------------------------------- Employee future benefits 447 381 ------------------------------------------------------------------------- Future income tax provision (recovery) 27 (3,535) ------------------------------------------------------------------------- Realized foreign exchange gain (29,754) - ------------------------------------------------------------------------- Unrealized foreign exchange loss 2,854 4,287 ------------------------------------------------------------------------- Dilution gain (1,917) (23) ------------------------------------------------------------------------- Lease inducement amortization - (268) ------------------------------------------------------------------------- Equity interest in Petrolifera earnings (6,953) (11,078) ------------------------------------------------------------------------- Cash flow from operations before working capital and other changes 44,965 40,196 ------------------------------------------------------------------------- Changes in non-cash working capital (Note 16(b)) 6,464 (9,271) ------------------------------------------------------------------------- Pension funding (781) - ------------------------------------------------------------------------- Asset retirement expenditures (311) - ------------------------------------------------------------------------- 50,337 30,925 ------------------------------------------------------------------------- FINANCING ------------------------------------------------------------------------- Repayment of oil sands term loan (180,000) - ------------------------------------------------------------------------- Issue of common shares, net of share issue costs 50,968 123,188 ------------------------------------------------------------------------- Increase in term debt 135,856 280,078 ------------------------------------------------------------------------- Repayment of bank debt (154,963) (57,707) ------------------------------------------------------------------------- Issuance of Convertible Debentures, net of issue costs (Note 9) 96,010 - ------------------------------------------------------------------------- Issuance of Senior Notes, net of issue costs (Note 9) 575,449 - ------------------------------------------------------------------------- Deferred financing costs (Note 8) (3,848) - ------------------------------------------------------------------------- 519,472 345,559 ------------------------------------------------------------------------- INVESTING ------------------------------------------------------------------------- Acquisition and development of oil and gas properties (301,877) (175,033) ------------------------------------------------------------------------- Proceeds on disposal of oil and gas properties - 10,000 ------------------------------------------------------------------------- Decrease (increase) in restricted cash (Note 16(c)) 59,627 (122,788) ------------------------------------------------------------------------- Acquisition of Luke Energy Ltd. (Note 4) - (92,692) ------------------------------------------------------------------------- Acquisition of refining assets (Note 4) - (61,273) ------------------------------------------------------------------------- Acquisition of other assets - (5,185) ------------------------------------------------------------------------- Exercise of Petrolifera warrants (Note 6) (5,143) - ------------------------------------------------------------------------- Change in non-cash working capital (Note 16(b)) (8,669) 14,122 ------------------------------------------------------------------------- (256,062) (432,849) ------------------------------------------------------------------------- ------------------------------------------------------------------------- NET INCREASE (DECREASE) IN CASH 313,747 (56,365) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Impact of foreign exchange on foreign currency denominated cash balances (4,240) 457 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CASH, BEGINNING OF YEAR 19,603 75,511 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CASH, END OF YEAR $329,110 $19,603 ------------------------------------------------------------------------- Supplementary information - Note 16 ------------------------------------------------------------------------- Connacher Oil and Gas Limited NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS Years Ended December 31, 2007 and 2006 1. FINANCIAL STATEMENT PRESENTATION The consolidated financial statements include the accounts of Connacher Oil and Gas Limited and its subsidiaries (collectively "Connacher" or the "company") and are presented in accordance with Canadian generally accepted accounting principles ("Canadian GAAP"). Operating in Canada and in the U.S. through its subsidiary Montana Refining Company, Inc. ("MRCI"), the company is in the business of exploring for and developing, producing, refining and marketing conventional petroleum and natural gas and the exploration, development and production of bitumen in the oil sands of northern Alberta. 2. SIGNIFICANT ACCOUNTING POLICIES Cash and cash equivalents Cash and cash equivalents include short-term deposits with initial maturities of three months or less, when purchased. Inventory valuation Crude oil and refined product inventories are stated at the lower of cost or net realizable value, determined under the weighted average cost method. Net realizable value is determined using current estimated selling prices, in conformity with the adoption in 2006 of CICA Handbook Section 3031 - "Inventories." Deferred costs These amounts include costs incurred in relation to the company's Revolving Credit Facilities, which have been deferred and are being amortized over the 5-year term of the facilities. The refining assets require regular major maintenance and repairs which are commonly referred to as "turnarounds". Catalysts used in certain refinery processes also require routine "change-outs". The required frequency of the maintenance varies by asset type and by catalyst, but generally is every two to five years. The costs of turnarounds and change-outs are recorded as deferred costs and are amortized over the period to the next scheduled turnaround or change-out. Petroleum, natural gas and bitumen operations The company follows the full cost method of accounting whereby all costs relating to the exploration for and development of crude oil, natural gas and bitumen reserves are capitalized on a country by country cost centre basis. Capitalized costs of petroleum and natural gas properties 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 independent consulting 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 (6:1). The company applies a "ceiling test" to the net book value of petroleum and natural gas properties to ensure that such carrying value does not exceed the estimated fair value of the properties. The carrying value is assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves and the cost, less impairment, of unproved properties exceeds the carrying value. If the carrying value is assessed to not be recoverable, the calculation compares the carrying value to the sum of the discounted cash flows expected from the production of proved and probable reserves and the cost, less impairment, of unproved properties. Should the carrying value exceed this sum, an impairment loss is recognized. The cash flows are estimated using projected future product prices and costs and are discounted using the credit adjusted risk-free interest rate. 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 impairment occurs. Costs associated with major development projects are not depleted until commencement of commercial operations. All capitalized costs are reviewed quarterly and any impairment is transferred to the costs being depleted or, if the properties are located in a cost centre where there is no reserve base, the impairment is charged directly to earnings. To date, all costs, including financing costs, incurred in relation to the company's Great Divide oil sands project in Northern Alberta, have been capitalized as the project is considered to be in the pre-production stage. Judgment is required in order to determine when commercial operations have commenced. Once it is determined that commercial operations have been achieved, revenue will be recognized, operating costs will be expensed to earnings and the capitalized costs of the project will be added to the full cost pool for depletion and ceiling test calculations. Revenues generated in the period prior to commencement of commercial operations are credited against capitalized costs. Gains or losses on sales of properties are recognized only when crediting the proceeds to the cost pool would result in a change of 20 percent or more in the depletion and depreciation rate. Refining assets Depreciation and amortization of refining assets 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 competition, regulation or environmental matters could cause changes to estimates, thus impacting the future calculation of depreciation and amortization. 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. Furniture, equipment and leaseholds Furniture and equipment are recorded at cost and are being depreciated on a declining balance basis at rates of 20 percent to 30 percent per year. Leaseholds are amortized over the lease term. Investment in Petrolifera Petroleum Limited The investment in Petrolifera Petroleum Limited ("Petrolifera") is accounted for on an equity basis, whereby the carrying value reflects the company's investment, at the lower of cost and fair value, and the company's equity interest share of its accumulated income. Any permanent decline in value would be charged to earnings. 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 that the 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's not more likely than not that the asset will be recovered. Goodwill 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 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 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. Asset retirement obligations The company recognizes an asset retirement obligation liability for abandoning petroleum, natural gas and bitumen wells, related facilities, compressors and gas plants, removal of equipment from leased acreage and 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 petroleum, natural gas or bitumen property and a corresponding liability is recognized. The liability is accreted against income until it is settled or the property is sold and is included as a component of depletion and depreciation expense. The amount of the capitalized retirement obligation is depleted and depreciated on the same basis as the other capitalized petroleum or natural gas property costs. Actual restoration expenditures are charged to the accumulated obligation as incurred and costs for properties disposed are removed. Employee future benefits The costs of the defined benefit pension plan and other retirement benefits are actuarially determined using the projected benefit method prorated on service and management's best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected health care costs. For the purpose of calculating the expected return on plan assets, those assets are valued at a market- related value. The cost of the company's portion of the defined contribution plan is expensed as incurred. Convertible Debentures The Convertible Debentures have been classified as long term debt and equity at their fair value at the date of issue. The fair value of the liability component has been determined based on the company's incremental borrowing rate for debt with similar terms. The amount of the equity component has been determined as a residual after deducting the amount of the liability component from the face value of the debentures. Share award plan for non-employee directors Obligations for payments in cash or 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. 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. Foreign currency translation The company has assessed the operations of MRCI to be self-sustaining. Assets and liabilities of self-sustaining foreign operations are translated into Canadian dollars at the rate of exchange in effect at the balance sheet date and revenues and expenses are translated at the average monthly rates of exchange during the periods. Gains or losses on translation of self-sustaining foreign operations are included in accumulated other comprehensive loss in shareholders' equity. Transaction-based foreign exchange gains and losses are included in earnings Financial instruments Financial instruments include cash and cash equivalents, restricted cash, accounts receivable, amounts due from/to Petrolifera, the Revolving Credit Facilities, accounts payable, the Convertible Debentures, the Senior Notes and the cross-currency and interest rate swaps. All carrying values of financial instruments approximate fair value with the exception of the Convertible Debentures and Senior Notes, which are initially recognized at fair value and are subsequently accounted for under the amortized cost method. The change in fair value of interest rate swaps and all payments received or made under interest rate swaps are recorded in earning or capitalized, as appropriate in the circumstances. Foreign currency gains and losses on the notional amount of the cross-currency swaps are recorded in income. Accretion of the discount on the Convertible Debentures and Senior Notes is a finance cost. The company has classified all of its financial instruments, with the exception of the Senior Notes, the Convertible Debentures and the Revolving Credit Facilities, as Held for Trading, which requires measurement on the balance sheet at fair value with any changes in fair value recorded in earnings. This classification has been chosen due to the nature of the company's financial instruments, which, except for the Senior Notes, the Convertible Debentures and Revolving Credit Facilities are of a short-term nature such that there are no material differences between the carrying values and the fair values. Transaction costs related to financial instruments classified as Held for Trading are recorded in earnings in accordance with the new standards. Transaction costs relating to the Convertible Debentures and Senior Notes are amortized against earnings over the term of the instrument using the effective interest rate method. The Revolving Credit Facilities have been classified as "other financial liabilities" on the consolidated balance sheet. The fair value of the liability closely approximates carrying value due to the revolving nature of these liabilities. Transaction costs related to the Revolving Credit Facilities have been deferred and are being amortized over the five-year term of the facilities. Joint venture operations A part of the company's activities is conducted with others, and these consolidated financial statements reflect only the company's proportionate interest in such activities. Revenue recognition Petroleum, natural gas and refined product sales are recognized as revenue at the time the respective commodities are delivered to purchasers. Unrealized gains and losses from the company's natural gas and crude oil commodity price risk management activities are recorded as revenue based on mark-to-market calculations. Prior to attaining commercial operations status, revenues on bitumen sales from the company's oil sands projects are credited to those project costs. When commercial operations are attained, oil sands revenues will be recognized as bitumen is delivered to purchasers. Natural gas, bitumen, diluent and other products and services may be purchased and sold between the company's subsidiaries. On consolidation, these intercompany amounts are eliminated. Stock-based compensation 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 credited to contributed surplus, are credited to share capital. Segment reporting Management has determined that the company operates in the following segments: Canada Oil and Gas includes the exploration, development, production and sales in western Canada of conventional and unconventional hydrocarbon reserves. Canada Administrative includes assets not related directly to any of the company's other business segments, being primarily the company's investment in Petrolifera. Income and expense in this segment are comprised mainly of equity interest in the earnings of Petrolifera, finance charges, stock-based compensation and general and administrative expenses. USA Refining includes the refining and marketing of refined petroleum products from the company's refinery in Great Falls, Montana. The above have been defined as the operating segments of the company because they (a) produce products which are sufficiently differentiated from each other so as to be separately identifiable; (b) are those for which operating results are regularly reviewed by the company's chief operating decision maker to make decisions about resources to be allocated to each segment and to assess its performance; and (c) are those for which discrete financial information is available. Segment accounting policies are the same as those described in this summary of significant accounting policies. Transfers of assets between segments are recorded at carrying value. 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. Income taxes are subject to re-assessment by tax authorities. Estimates of the stage of completion of capital projects at the financial statement date affect the calculation of additions to property and equipment and the related accrued liability. Amounts recorded for depreciation, depletion and accretion, asset retirement costs and obligations, amounts used for ceiling test and impairment calculations and amounts used in the determination of future taxes are based on estimates of petroleum, natural gas and bitumen reserves and future costs required to develop those reserves. By their nature, these estimates of reserves, including the estimates of future prices and costs and the related future cash flows are subject to measurement uncertainty. Credit risk The majority of the accounts receivable balance is in respect of refining operations. The company generally extends unsecured credit to customers and therefore, the collection of accounts receivable may be affected by changes in economics or other conditions. Management believes this risk is mitigated by the size and reputation 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. Commodity and financial risk management The company periodically enters into contracts to fix the price of a portion of its petroleum and natural gas sales to reduce the exposure to commodity price fluctuations; and occasionally these contracts are denominated in Canadian dollars to mitigate foreign exchange risks. At December 31, 2007 there were no such contracts in place. To help mitigate some of the foreign currency and interest rate risk associated with its US-denominated Senior Note, the company has entered into cross-currency and interest rate swaps. Unless any of these transactions are designated as "hedges" for accounting purposes, they would be marked to market for financial statement reporting purposes. 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. 3. NEW ACCOUNTING STANDARDS Effective January 1, 2007 the company adopted the Canadian Institute of Chartered Accountants ("CICA") Handbook Section 1530, "Comprehensive Income," Section 3251, "Equity," Section 3855, "Financial Instruments - Recognition and Measurement," and Section 3865, "Hedges." As required by the new standards, prior periods have not been restated, except to reclassify the foreign currency translation adjustment balance as described under Comprehensive Income. The adoption of these standards has had no material impact on the company's net earnings or cash flow. The other effects of the implementation of the new standards are discussed below. Comprehensive Income The new standards introduce comprehensive income, which consists of net earnings and Other Comprehensive Income ("OCI"). The company's Consolidated Financial Statements now include a Statement of Comprehensive Income, which includes the components of comprehensive income. For Connacher, OCI currently comprises the changes in the foreign currency translation adjustment balance. The cumulative changes in OCI are included in Accumulated Other Comprehensive Income ("AOCI"), which is presented as a new category within shareholders' equity in the Consolidated Balance Sheet. The accumulated foreign currency translation adjustment, formerly presented as a separate category within shareholders' equity, is now included in AOCI. The company's Consolidated Financial Statements now include a Statement of Accumulated Other Comprehensive Income, which provides the continuity of the AOCI balance. The adoption of comprehensive income has been made in accordance with the applicable transitional provisions. Accordingly, the December 31, 2006 period end accumulated foreign currency translation adjustment balance of $130,000 has been reclassified to AOCI. In addition, the change in the accumulated foreign currency translation adjustment balance for the year ended December 31, 2007 of $13.5 million is now included in the Statement of Comprehensive Income (year ended December 31, 2006 - nil). Changes during the period in other comprehensive income and AOCI were as follows: ------------------------------------------------------------------------- Year ended December 31, 2007 ------------------------------------------------------------------------- ($000) Increase (Decrease) ------------------------------------------------------------------------- Other comprehensive income $(13,506) ------------------------------------------------------------------------- Accumulated other comprehensive income (loss) $(13,506) ------------------------------------------------------------------------- Financial Instruments The financial instruments standard establishes the recognition and measurement criteria for financial assets, financial liabilities and derivatives. All financial instruments are required to be measured at fair value on initial recognition of the instrument, except for certain related party transactions. Measurement in subsequent periods depends on whether the financial instrument has been classified as "held-for- trading," "available-for-sale," "held-to-maturity," "loans and receivables," or "other financial liabilities" as defined by the accounting standard. Financial assets and financial liabilities "held-for-trading" are measured at fair value with changes in those fair values recognized in net earnings. Financial assets "available-for-sale" are measured at fair value, with changes in those fair values recognized in OCI. Financial assets "held-to-maturity," "loans and receivables" and "other financial liabilities" are measured at amortized cost using the effective interest rate method of amortization. The company has classified all of its financial instruments, with the exception of the Senior Notes, the Convertible Debentures and the Revolving Credit Facilities, as Held for Trading. This classification has been chosen due to the nature of the company's financial instruments, which, except for the Senior Notes, the Convertible Debentures and Revolving Credit Facilities, are of a short-term nature such that there are no material differences between the carrying values and the fair values. Transaction costs related to financial instruments classified as Held for Trading are recorded in earnings in accordance with the new standards. The Senior Notes and the Convertible Debentures have been classified as "other financial liabilities" and are accounted for on the amortized cost method, with transaction costs being amortized over the life of the instrument using the effective interest rate method. The Revolving Credit Facilities have been classified as "other financial liabilities" on the consolidated balance sheet. The fair value of the liability closely approximates carrying value due to the revolving nature of these liabilities. Transaction costs related to the Revolving Credit Facilities have been deferred and are being amortized over the five-year term of the facilities. The adoption of Section 3865, "Hedges", has had no effect on the company's consolidated financial statements as the company has no designated hedges for accounting purposes. Effective January 1, 2007, the company adopted the revised recommendations of CICA Handbook section 1506, Accounting Changes. The new recommendations permit voluntary changes in accounting policy only if they result in financial statements which provide more relevant and reliable financial information. Accounting policy changes must be applied retrospectively unless it is impractical to determine the period or cumulative impact of the change in policy. Additionally, when an entity has not applied a new primary source of Canadian GAAP that has been issued but is not yet effective, the entity must disclose that fact along with information relevant to assessing the possible impact that application of the new primary source of Canadian GAAP will have on the entity's financial statements in the period of initial application. As of January 1, 2008, the company will be required to adopt two new CICA Handbook requirements, section 3862, "Financial Instruments - Disclosures" and section 3863, "Financial Instruments - Presentation," which will replace current section 3861. The new standards require disclosure of the significance of financial instruments to an entity's financial statements, the risks associated with the financial instruments and how those risks are managed. The presentation of financial instruments is unchanged from the presentation requirements included in Section 3861. The company is assessing the impact of these new standards. As of January 1, 2008, the company will be required to adopt CICA Handbook section 1535, "Capital Disclosures" which requires entities to disclose their objectives, policies and processes for managing capital and, in addition, whether the entity has complied with any externally imposed capital requirements. The company is assessing the impact of this new standard. In February 2008, the CICA issued Section 3064, "Goodwill and Intangible Assets," replacing Section 3062, "Goodwill and Other Intangible Assets" and Section 3450, "Research and Development Costs." Various changes have been made to other sections of the CICA Handbook for consistency purposes. The new Sections will be applicable to financial statements relating to fiscal years beginning on or after October 1, 2008. Accordingly, the company will adopt the new standards for its fiscal year beginning January 1, 2009. Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit- oriented enterprises. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. The company is currently evaluating the impact of the adoption of this new Section. Over the next few years the CICA will adopt its new strategic plan for the direction of accounting standards in Canada, which was ratified in January 2006. As part of the plan, Canadian GAAP for public companies will converge with International Financial Reporting Standards ("IFRS") over the next few years. The company is currently assessing the impact of the convergence of Canadian GAAP with IFRS on its financial statements and expects to begin work on the conversion process later in 2008. 4. BUSINESS ACQUISITIONS During 2006, Connacher completed the following transactions: (a) Acquisition of Luke Energy Ltd. The company completed the acquisition of all of the outstanding shares of Luke Energy Ltd. ("Luke") on March 16, 2006. The results of operations of Luke have been included in Connacher's consolidated financial statements since that date. Net assets acquired and consideration paid were as follows: ------------------------------------------------------------------------- ($000) ------------------------------------------------------------------------- Net assets acquired: ------------------------------------------------------------------------- Petroleum and natural gas assets $ 153,755 ------------------------------------------------------------------------- Goodwill 103,676 ------------------------------------------------------------------------- Asset retirement obligations(Note 11) (2,109) ------------------------------------------------------------------------- Working capital deficit (19,308) ------------------------------------------------------------------------- Future income tax liability (31,356) ------------------------------------------------------------------------- Net assets acquired $ 204,658 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Consideration paid: ------------------------------------------------------------------------- Cash $ 92,692 ------------------------------------------------------------------------- Common shares(Note 13) 111,966 ------------------------------------------------------------------------- $ 204,658 ------------------------------------------------------------------------- Included in cash consideration paid are transaction costs of $1.2 million. The value of the common share consideration paid was determined by reference to the market value of the company's shares at the time of announcing the acquisition. Effective January 1, 2007, Luke was amalgamated with Connacher. (b) Acquisition of refining assets On March 31, 2006 the company acquired all of the assets of a refinery in Great Falls, Montana. The refinery's results of operations have been included in Connacher's consolidated financial statements from that date. Net assets acquired and consideration paid were as follows: ------------------------------------------------------------------------- ($000) ------------------------------------------------------------------------- Net assets acquired: ------------------------------------------------------------------------- Refining assets $ 46,337 ------------------------------------------------------------------------- Inventory 19,996 ------------------------------------------------------------------------- Net assets acquired $ 66,333 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Consideration paid: ------------------------------------------------------------------------- Cash $ 61,273 ------------------------------------------------------------------------- Common shares(Note 13) 5,060 ------------------------------------------------------------------------- $ 66,333 ------------------------------------------------------------------------- Included in cash consideration paid are transaction costs of $1.2 million. The value of the common share consideration paid was determined by reference to the market value of the company's shares at the time of announcing the acquisition. The purchase agreement commits the vendor to resolve any environmental matters existing at the purchase date which arise in the first five years from the purchase date. 5. INVENTORIES Inventories at December 31 consist of the following: ------------------------------------------------------------------------- ($000) 2007 2006 ------------------------------------------------------------------------- Crude oil $ 2,258 $ 3,520 ------------------------------------------------------------------------- Other raw materials and unfinished products(1) 1,501 1,292 ------------------------------------------------------------------------- Refined products(2) 11,183 17,440 ------------------------------------------------------------------------- Process chemicals(3) 1,036 909 ------------------------------------------------------------------------- Repair and maintenance supplies and other(4) 2,401 1,276 ------------------------------------------------------------------------- $ 18,379 $ 24,437 ------------------------------------------------------------------------- (1) Other raw materials and unfinished products include feedstocks and blendstocks, other than crude oil. The inventory carrying value includes the costs of the raw materials and transportation. (2) Refined products include gasoline, jet fuels, diesels, asphalts, liquid petroleum gases and residual fuels. The inventory carrying value includes the cost of raw materials including transportation and direct production costs. (3) Process chemicals include catalysts, additives and other chemicals. The inventory carrying value includes the cost of the purchased chemicals and related freight. (4) Repair and maintenance supplies in crude refining and oil sands supplies. As a consequence of seasonally reduced asphalt selling prices, the company reduced the realizable value of asphalt inventory at December 31, 2007, by $562,000, charging cost of sales in the consolidated statement of operations. The amount of inventory recognized as an expense in cost of sales during 2007 was $237.1 million (2006 -$164.5 million). 6. INVESTMENT IN PETROLIFERA Changes to the investment in Petrolifera are as follows ($000): ------------------------------------------------------------------------- Investment in Petrolifera, December 31, 2005 $ 10,496 ------------------------------------------------------------------------- Equity in Petrolifera's 2006 earnings 11,078 ------------------------------------------------------------------------- Dilution gain resulting from issuance of Petrolifera shares in 2006 23 ------------------------------------------------------------------------- Investment in Petrolifera, December 31, 2006 21,597 ------------------------------------------------------------------------- Equity in Petrolifera's 2007 earnings 6,953 ------------------------------------------------------------------------- Exercise of warrants - purchase of additional Petrolifera common shares 5,143 ------------------------------------------------------------------------- Dilution gain resulting from issuance of Petrolifera shares in 2007 1,917 ------------------------------------------------------------------------- Investment in Petrolifera, December 31, 2007 $ 35,610 ------------------------------------------------------------------------- Dilution gains have been recognized whenever changes have occurred in the company's equity interest in Petrolifera, most notably relative to Petrolifera's $7 million private placement financing completed in March 2005, when Connacher's equity interest holding was reduced from 61 percent to 40 percent, resulting in a dilution gain of $3 million. Although Connacher participated in Petrolifera's $21.3 million initial public offering in November 2005 by investing $6 million, Connacher's equity investment interest was reduced to 35 percent and an additional dilution gain of $1.5 million was then recognized. In April 2007, the company exercised warrants to purchase 1.7 million additional common shares in Petrolifera for total consideration of $5.1 million. As a result, the company increased its equity interest in Petrolifera. However, because other Petrolifera shareholders similarly exercised their warrants to purchase additional common shares in Petrolifera on identical terms, the company's equity interest decreased to 26 percent, resulting in a dilution gain of $1.9 million. In consideration for the assistance provided 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 in the two licensed blocks, Connacher was granted an option to acquire 200,000 common shares at $0.50 per share and was granted a 10 percent carried working interest ("CWI") through the drilling of the first well on each block. Connacher has since been indemnified by Petrolifera for the financial guarantees it provided to the Peruvian regulators. 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 the holder's election into a two percent gross overriding royalty on each license after the drilling of the first well on each block. Under the terms of a Management Services Agreement with Petrolifera, which has been extended on a month-to-month basis since its original term, which expired in May 2007, Connacher provides certain management and general and administrative services to Petrolifera. The fee for this service is $15,000 per month. From time to time Connacher also pays bills on behalf of Petrolifera, for which it is reimbursed at cost. Connacher is also guarantor for Petrolifera in Peru and operator of record on behalf of Petrolifera in Colombia for which Connacher is indemnified by Petrolifera. Petrolifera paid Connacher $200,000 in 2007 under the management agreement which management anticipates to be replaced on substantially the same terms by a new agreement effective January 1, 2008. 7. PROPERTY AND EQUIPMENT ------------------------------------------------------------------------- Accumulated Depletion, Depreciation and Amort- Net Book ($000) Cost ization Value ------------------------------------------------------------------------- 2007 ------------------------------------------------------------------------- Oil sands, crude oil and natural gas properties and equipment $ 678,176 $ 67,499 $ 610,677 ------------------------------------------------------------------------- Refining assets 59,192 5,182 54,010 ------------------------------------------------------------------------- Furniture, equipment and leaseholds 9,219 2,484 6,735 ------------------------------------------------------------------------- $ 746,587 $ 75,165 $ 671,422 ------------------------------------------------------------------------- 2006 ------------------------------------------------------------------------- Oil sands, crude oil and natural gas properties and equipment $ 377,172 $ 43,816 $ 333,356 ------------------------------------------------------------------------- Refining assets 51,959 2,319 49,640 ------------------------------------------------------------------------- Furniture, equipment and leaseholds 2,625 1,310 1,315 ------------------------------------------------------------------------- $ 431,756 $ 47,445 $ 384,311 ------------------------------------------------------------------------- In 2007, the company capitalized $5.6 million (2006 -$4.5 million) of general and administrative expenses, including stock-based compensation of $2.2 million (2006 -$3.5 million), related to oil sands and conventional petroleum and natural gas activities and $24.6 million (2006 - $7.9 million) of interest and finance costs related to major development projects. Depletion, depreciation and accretion expense includes a charge of $1.6 million (2006 - $348,000) to accrete the company's estimated asset retirement obligations (Note 11). The ceiling test as at December 31, 2007 excludes $14.7 million (2006 - $16.2 million) of undeveloped land and $413 million (2006 - $156.7 million) of major development project costs, principally related to oil sands assets in the pre-production stage, which have been separately evaluated by management for impairment. Based on the ceiling test and other assessments, no impairment has been recorded in 2006 or 2007. Connacher's oil sands, crude oil and natural gas reserves were evaluated by qualified independent evaluators as at December 31, 2007 in a report dated February 28, 2008. The evaluation was conducted in accordance with the Canadian Securities Administrators' National Instrument 51-101, using the following base price assumptions adjusted for the company's product quality and transportation differentials: ------------------------------------------------------------------------- Bitumen Wellhead WTI @ Alberta Current Cushing Spot ($CDN/bbl) ($US/bbl) ($CDN/mcf) ------------------------------------------------------------------------- 2008 54.02 98.14 7.67 ------------------------------------------------------------------------- 2009 50.60 96.86 7.55 ------------------------------------------------------------------------- 2010 47.28 96.96 7.60 ------------------------------------------------------------------------- 2011 45.22 97.06 7.60 ------------------------------------------------------------------------- 2012 44.33 97.16 7.64 ------------------------------------------------------------------------- approximately approximately approximately 2% thereafter 2% thereafter 2% thereafter ------------------------------------------------------------------------- 8. DEFERRED COSTS Deferred costs are composed of the following: ------------------------------------------------------------------------- December 31, December 31, ($000s) 2007 2006 ------------------------------------------------------------------------- Deferred maintenance costs related to refinery $ 1,835 $ 4,005 ------------------------------------------------------------------------- Deferred financing costs related to Revolving Credit Facilities 3,752 - ------------------------------------------------------------------------- $ 5,587 $ 4,005 ------------------------------------------------------------------------- 9. INDEBTEDNESS The company had the following loans outstanding, as at December 31. ------------------------------------------------------------------------- ($000) 2007 2006 ------------------------------------------------------------------------- Senior Notes $ 570,594 $ - ------------------------------------------------------------------------- Cross-currency interest rate swap 12,735 - ------------------------------------------------------------------------- Convertible Debentures 81,133 - ------------------------------------------------------------------------- Oil Sands Term Loan - 209,754 ------------------------------------------------------------------------- Revolving Credit Facilities - $ 19,500 ------------------------------------------------------------------------- Total 664,462 229,254 ------------------------------------------------------------------------- Less current portion - 19,500 ------------------------------------------------------------------------- Long-term portion $ 664,462 $ 209,754 ------------------------------------------------------------------------- Senior Notes On December 3, 2007 the company issued US $600 million of second lien eight-year notes ("Senior Notes") at an issue price of 98.657 percent for net proceeds of US $575.4 million after fees and expenses. A portion of the proceeds was used to repay the US $180 million Oil Sands Term Loan and to fund a one-year interest reserve account in the amount of US $63.6 million, which has been classified as restricted cash on the consolidated balance sheet (Note 16(c)). The remainder of the proceeds are anticipated to be used to fund the construction of the company's second oil sands project (the "Algar" project). The Senior Notes bear interest at a rate of 10.25 percent, payable semi-annually on June 15 and December 15, with the first interest payment scheduled to occur on June 15, 2008. No principal repayments are due until the maturity date of December 15, 2015. The Senior Notes are unconditionally guaranteed by Connacher's subsidiaries and are secured by a second lien, which is subordinate to the liens under the company's Revolving Credit Facilities, which covers substantially all of the company's and its subsidiaries' assets, with the exception of Connacher's investment in Petrolifera. The company may redeem some or all of the Senior Notes at their principal amount plus a make whole premium if such redemption occurs prior to December 15, 2011. After December 15, 2011, the Senior Notes may be redeemed at redemption prices ranging from 105.125 percent reducing to 100 percent on December 15, 2013 and thereafter. The company may redeem up to 35 percent of the of the Senior Notes prior to December 15, 2010 at a redemption price of 110.25 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 Senior Notes remains outstanding on existing terms. Upon a change of control of the company, the holders of the Senior Notes may require Connacher to purchase the Senior Notes at redemption prices noted above, with a minimum price of 101 percent of the principal amount to be repurchased. A portion of the interest on the Senior Notes is being capitalized to the company's first oil sands project ("Pod One"), pending commencement of its commercial operations. Interest on the portion of the loan which is used to fund the Algar project is also being capitalized until Algar commences commercial operations. At December 31, 2007, the fair value of the Senior Notes was approximately $598 million. This amount was determined by reference to the quoted market price for the company's Senior Notes. Cross Currency and Interest Rate Swaps To partially mitigate the foreign exchange risk associated with its Senior Notes, the company entered into cross currency and interest rate swaps to fix a portion of the Senior Notes' US dollar denominated principal and interest payments in Canadian dollars. The swaps provide for a fixed payment of $304.8 million in exchange for receipt of US $300 million on December 15, 2015. The swaps also provide for semi- annual interest payments commencing June 15, 2009 at a fixed rate of 10.795 percent (based on a notional $304.8 million of debt), in exchange for receipt of semi-annual interest payments at a fixed rate of 10.25 percent (based on a notional US $300 million of debt). At December 31, 2007, the fair value of this swap was a liability of $12.7 million, which has been included with long-term debt in the consolidated balance sheet. An unrealized foreign exchange loss of $9.6 million related to the cross currency swap has been recorded in income and $3.1 million has been capitalized to property and equipment. This unrealized loss was offset by a $9.7 million unrealized gain on translating the Senior Notes and the interest rate swap at year end. Convertible Debentures On May 25, 2007 Connacher issued senior unsecured subordinated convertible debentures ("Convertible Debentures") with a face value of $100,050,000. The debentures mature June 30, 2012 unless converted prior to that date and bear interest at an annual rate of 4.75 percent payable semi-annually on June 30 and December 31. The 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 debentures are redeemable in whole or in part by the company on or after June 30, 2010 at a redemption price equal to 100 percent of the principal amount of the 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 debentures. The conversion feature of the debentures has been accounted for as a separate component of equity in the amount of $16,823,000. The remainder of the net proceeds of the debentures of $79,187,000 has been recorded as long-term debt, which will be accreted up to the face value of $100,050,000 over the five-year term of the debentures. Accretion of $1.9 million and interest paid are recorded as finance charges on the consolidated statement of operations. If the debentures are converted to common shares, the value of the conversion feature will be reclassified to share capital along with the principal amounts converted. At December 31, 2007, the fair value of the Convertible Debentures was $96.5 million. This amount was determined by reference to quoted market prices for convertible debt instruments with similar terms. Oil Sands Term Loan and Interest Rate Swap A portion of the proceeds of the Senior Notes was used to fully repay the US $180 million term loan (the "Oil Sands Term Loan") in 2007. At the date of its repayment, the company had in place an interest rate swap to convert the effective floating interest rate on one-half of the Oil Sands Term Loan to an all-in fixed interest rate of 8.516 percent as was required by the terms of the Oil Sands Term Loan agreement. The swap was terminated in December 2007 in connection with the repayment of the Oil Sands Term Loan. The company paid US $4.6 million to the counterparty to extinguish the interest rate swap. This amount has been capitalized to Pod One. Revolving Credit Facilities At December 31, 2007 the company had available senior secured syndicated five-year term revolving lines of credit in the amounts of C $150 million and US $50 million (the "Revolving Credit Facilities"). Borrowings are available under the Revolving Credit Facilities in the form of Canadian or US dollar prime rate loans, US dollar base rate loans, US dollar LIBOR loans, bankers' acceptances and letters of credit. Amounts drawn on the Revolving Credit Facilities bear interest at either a Canadian banker's acceptances or prime rate, a US base or prime rate or LIBOR, in each case plus an applicable margin. The Revolving Credit Facilities expire on December 3, 2012, are unconditionally guaranteed by Connacher's subsidiaries and are secured by a first ranking lien over all of the company's assets except for Connacher's investment in Petrolifera. No amounts were drawn under the Revolving Credit Facilities at December 31, 2007 other than letters of credit in the amount of US $1.8 million. Principal repayments of the company's indebtedness are due as follows: ------------------------------------------------------------------------- ($000) ------------------------------------------------------------------------- 2008 $ - ------------------------------------------------------------------------- 2009 - ------------------------------------------------------------------------- 2010 - ------------------------------------------------------------------------- 2011 - ------------------------------------------------------------------------- 2012 100,050 ------------------------------------------------------------------------- Thereafter 612,735 ------------------------------------------------------------------------- $ 712,785 ------------------------------------------------------------------------- 10. INCOME TAXES The income tax provision of $13.0 million in 2007 includes a current income tax provision of $10.7 million related to US refinery operations and $2.3 million relating to Canadian capital and other taxes. The following table reconciles income taxes calculated at the Canadian statutory rate with recorded income taxes: ------------------------------------------------------------------------- Years Ended December 31 ($000) 2007 2006 ------------------------------------------------------------------------- Earnings before income taxes $ 53,966 $ 10,823 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Canadian statutory rate 32.7% 35.4% ------------------------------------------------------------------------- ------------------------------------------------------------------------- Expected income taxes 17,647 3,831 ------------------------------------------------------------------------- Non-deductible Canadian crown payments - 1,729 ------------------------------------------------------------------------- Canadian resource allowance - (945) ------------------------------------------------------------------------- Impact of reduction in Canadian tax rates and other (5,385) (3,955) ------------------------------------------------------------------------- Foreign taxes 2,488 973 ------------------------------------------------------------------------- Capital taxes 1,896 502 ------------------------------------------------------------------------- Non taxable portion of foreign exchange (gains) losses (4,100) 762 ------------------------------------------------------------------------- Equity income and dilution gain (1,523) (1,962) ------------------------------------------------------------------------- Non deductible stock-based compensation 1,982 2,935 ------------------------------------------------------------------------- Provision for taxes $ 13,005 $ 3,870 ------------------------------------------------------------------------- The company had the following future tax assets (liabilities) relating to temporary differences. ------------------------------------------------------------------------- As at December 31 ($000) 2007 2006 ------------------------------------------------------------------------- Book value in excess of tax basis of property and equipment $ (56,725) $ (37,628) ------------------------------------------------------------------------- Non-capital losses carried forward 18,647 7,754 ------------------------------------------------------------------------- Foreign exchange gain on debt (532) 882 ------------------------------------------------------------------------- Partnership deferral (6,360) (5,930) ------------------------------------------------------------------------- Investment in Petrolifera (2,850) (1,980) ------------------------------------------------------------------------- Deferred maintenance costs (723) (1,547) ------------------------------------------------------------------------- Financing and share issue costs 3,998 6,463 ------------------------------------------------------------------------- Asset retirement obligation 6,164 2,158 ------------------------------------------------------------------------- Other 1,563 475 ------------------------------------------------------------------------- Net future income tax liability $ (36,818) $ (29,353) ------------------------------------------------------------------------- At December 31, 2007 the company had approximately $66 million of non- capital losses which expire over time to 2027, $414 million of deductible resource pools and $36 million of deductible financing costs available to be applied to reduce the company's future taxable income. 11. 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 oil sands and conventional petroleum and natural gas properties and facilities. ------------------------------------------------------------------------- Year ended December 31 ($000) 2007 2006 ------------------------------------------------------------------------- Asset retirement obligations, beginning of year $ 7,322 $ 3,108 ------------------------------------------------------------------------- Liabilities incurred 8,277 2,384 ------------------------------------------------------------------------- Liabilities acquired(Note 4(a)) - 2,109 ------------------------------------------------------------------------- Liabilities settled (311) - ------------------------------------------------------------------------- Liabilities disposed - (864) ------------------------------------------------------------------------- Change in estimated future cash flows 7,503 237 ------------------------------------------------------------------------- Accretion expense 1,574 348 ------------------------------------------------------------------------- Asset retirement obligations, end of year $ 24,365 $ 7,322 ------------------------------------------------------------------------- At December 31, 2007 the estimated total undiscounted amount required to settle the asset retirement obligations was $44.4 million (2006 - $17.4 million). These obligations are expected to be settled over the useful lives of the underlying assets, which currently extend up to 20 years into the future. This amount has been discounted using a credit- adjusted risk-free interest rate of six percent for wells drilled prior to 2007 and eight percent for wells drilled in 2007, after provision for an inflation rate of 2.0 percent. The company has not recorded an asset retirement obligation for the Montana refinery as it is currently the company's intention 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. 12. EMPLOYEE FUTURE BENEFITS The company maintains the following retirement/savings plans for its employees: a defined benefit pension plan and a 401(k) savings plan for its US-based employees and a registered savings plan for its Canadian employees. (a) The defined benefit pension plan The company's US subsidiary, MRCI, maintains a non-contributory defined benefit retirement plan (the "Plan") covering MRCI's employees. MRCI's policy is to make regular contributions in accordance with applicable regulations as determined by regular actuarial valuations. The company's pension obligation is based on the employees' years of service and compensation, effective from, and after, March 31, 2006, the date that Connacher acquired the refining assets and commenced employing its employees. In 2007, MRCI fully funded the Plan's cost for 2006 and 2007 and as at December 31, 2007 the Plan Assets ($757,000) exceeded the Accrued Benefit Obligation ($617,000) by $140,000. Connacher's consolidated balance sheet does not reflect this over-funded amount as an asset. MRCI is responsible for administering the 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 Plan's primary investment goal, rate of return objective, investment risk, investment time horizon, role of asset classes and asset allocation. Details of this Plan and actuarial valuations are as follows: ------------------------------------------------------------------------- For the years ended December 31 ($000) 2007 2006 ------------------------------------------------------------------------- Total expense for the Plan $ 447 $ 381 ------------------------------------------------------------------------- Pension expense is included in refining operating costs in the consolidated statement of operations. Accrued Benefit Obligation ($000) ------------------------------------------------------------------------- Accrued Benefit Obligation, Beginning of the Year $ 388 $ - ------------------------------------------------------------------------- Current service cost 470 365 ------------------------------------------------------------------------- Interest cost 21 16 ------------------------------------------------------------------------- Actuarial (gain) loss (140) - ------------------------------------------------------------------------- Benefits paid (24) - ------------------------------------------------------------------------- Foreign exchange (gain) loss (98) 7 ------------------------------------------------------------------------- Accrued Benefit Obligation, End of Year $ 617 $ 388 ------------------------------------------------------------------------- Plan Assets ($000) ------------------------------------------------------------------------- Fair Value of Plan Assets, Beginning of Year $ - $ - ------------------------------------------------------------------------- Actual return on plan assets 43 - ------------------------------------------------------------------------- Employer contributions 781 - ------------------------------------------------------------------------- Benefits paid (24) - ------------------------------------------------------------------------- Foreign exchange gain (loss) (43) - ------------------------------------------------------------------------- Fair Value of Plan Assets, End of Year $ 757 $ - ------------------------------------------------------------------------- Accrued Benefit Asset (Liability) ($000) ------------------------------------------------------------------------- Funded Status - Plan Assets greater (less) than Benefit Obligation $ 140 $ (388) ------------------------------------------------------------------------- Unamortized net actuarial gain (140) - ------------------------------------------------------------------------- Accrued Benefit Asset (Liability) $ - $ (388) ------------------------------------------------------------------------- The assumptions used to determine benefit obligations and periodic expense are as follows: ------------------------------------------------------------------------- Discount Rate 5.75% 5.75% ------------------------------------------------------------------------- Expected Long-Term Rate of Return on Plan Assets 7.0% 7.0% ------------------------------------------------------------------------- Rate of Compensation Increase 3.0% 3.0% ------------------------------------------------------------------------- The periodic expense for benefits is as follows ($000): ------------------------------------------------------------------------- Current Service Cost $ 470 $ 365 ------------------------------------------------------------------------- Interest Cost 21 16 ------------------------------------------------------------------------- Actual Return on Plan Assets (43) - ------------------------------------------------------------------------- Difference between actual and expected return on plan assets (1) - ------------------------------------------------------------------------- Net Benefit Plan Expense $ 447 $ 381 ------------------------------------------------------------------------- The average remaining service period of the active employees covered by the defined benefit pension plan is 14.66 years. The company's pension plan asset allocation is as follows: ------------------------------------------------------------------------- As at December 31 2007 2006 ------------------------------------------------------------------------- Asset Category ------------------------------------------------------------------------- Equity Securities 57% -% ------------------------------------------------------------------------- Debt Securities 39% -% ------------------------------------------------------------------------- Cash and Equivalents 4% 100% ------------------------------------------------------------------------- Total 100% 100% ------------------------------------------------------------------------- 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 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 investment, credit rating categories and foreign currency exposure. (b) The MRCI savings plan for United States employees MRCI also maintains (US tax code "401(k)") savings plans that cover all of its employees. MRCI's contributions are based on employees' compensation and partially match employee contributions. In 2007, MRCI contributed $345,000 (2006 -$201,000) to this plan, to fully satisfy its obligation under this plan. This amount is included in refining operating expenses. (c) The registered savings plans for Canadian employees The company also maintains registered savings plans for its Canadian employees, whereby the company matches employee contributions to a defined maximum. In 2007, the company contributed $474,000 (2006 - $121,500) to this plan, to fully satisfy its obligation under this plan. This amount is included in general and administrative expenses. 13. SHARE CAPITAL, CONTRIBUTED SURPLUS AND EQUITY COMPONENT Authorized The authorized share capital comprises the following: - Unlimited number of common voting shares - Unlimited number of first preferred shares - Unlimited number of second preferred shares Issued Only common shares have been issued by the company. ------------------------------------------------------------------------- Number of Amount Shares ($000) ------------------------------------------------------------------------- Balance, Share Capital, December 31, 2005 139,940,448 $ 125,071 ------------------------------------------------------------------------- Issued for cash in private placement (a) 19,047,800 100,001 ------------------------------------------------------------------------- Issued for cash in public offerings (b) 5,714,300 30,000 ------------------------------------------------------------------------- Issued for Luke acquisition (Note 4(a)) 29,699,282 111,966 ------------------------------------------------------------------------- Issued for refinery acquisition (Note 4(b)) 1,000,000 5,060 ------------------------------------------------------------------------- Issued upon exercise of options (d) 998,365 696 ------------------------------------------------------------------------- Assigned value of options exercised 321 ------------------------------------------------------------------------- Issued upon exercise of warrants (e) 1,493,820 881 ------------------------------------------------------------------------- Share issue costs (8,390) ------------------------------------------------------------------------- Tax effect of share issue costs 2,924 ------------------------------------------------------------------------- Tax effect of expenditures renounced pursuant to the issuance of flow through common shares in 2005 (5,448) ------------------------------------------------------------------------- Balance, Share Capital, December 31, 2006 197,894,015 363,082 ------------------------------------------------------------------------- Issued for cash in public offering (c) 10,450,000 52,250 ------------------------------------------------------------------------- Issued upon exercise of options (d) 1,518,267 1,466 ------------------------------------------------------------------------- Issued to directors as compensation (f) 108,975 392 ------------------------------------------------------------------------- Assigned value of options exercised 518 ------------------------------------------------------------------------- Tax effect of expenditures renounced pursuant to the issuance of flow-through common shares in 2006 (b) (9,000) ------------------------------------------------------------------------- Share issue costs (2,748) ------------------------------------------------------------------------- Tax effect of share issue costs 921 ------------------------------------------------------------------------- Balance, Share Capital, December 31, 2007 209,971,257 $ 406,881 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Contributed Surplus: ------------------------------------------------------------------------- Balance, Contributed Surplus, December 31, 2005 $ 1,962 ------------------------------------------------------------------------- Stock-based compensation for share options expensed in 2006 (d) 11,777 ------------------------------------------------------------------------- Assigned value of options exercised in 2006 (321) ------------------------------------------------------------------------- Balance, Contributed Surplus, December 31, 2006 13,418 ------------------------------------------------------------------------- Stock-based compensation for share options expensed in 2007 (d) 7,482 ------------------------------------------------------------------------- Assigned value of options exercised in 2007 (518) ------------------------------------------------------------------------- Balance, Contributed Surplus, December 31, 2007 $ 20,382 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Equity component of Convertible Debentures, December 31, 2007 $ 16,823 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total Share Capital, Contributed Surplus and Equity Component: ------------------------------------------------------------------------- December 31, 2006 $ 376,500 ------------------------------------------------------------------------- December 31, 2007 $ 444,086 ------------------------------------------------------------------------- (a) Private Placement - 2006 In February 2006, the company issued 19,047,800 common shares from treasury at $5.25 per share on a private placement basis. (b) Flow-through Share Issue - 2006 In September 2006, the company issued from treasury 5,714,300 common shares on a flow through basis at $5.25 per share and renounced the related resources expenditures of $30 million to the flow through investors effective December 31, 2006. (c) Flow-through share issue - 2007 In November 2007, the company issued 10,450,000 common shares on a flow- through basis at $5.00 per share for gross proceeds of $52.25 million. The company agreed to renounce the related expenditures to the flow- through investors effective December 31, 2007. The company has until December 31, 2008 to incur the expenditures. As at December 31, 2007, $4.7 million of these expenditures had been incurred. The tax effect of renouncing these expenditures will be recorded in 2008. (d) Stock Options A summary of the company's outstanding stock options, as at December 31, 2007 and 2006 and changes during those years is presented below: ------------------------------------------------------------------------- 2007 2006 ------------------------------------------------------------------------- Weighted Weighted Average Average Number of Exercise Number of Exercise Shares Price Shares Price ------------------------------------------------------------------------- Outstanding, beginning of year 16,212,490 $3.31 8,592,600 $1.49 ------------------------------------------------------------------------- Granted 4,311,703 $3.88 8,739,255 $4.81 ------------------------------------------------------------------------- Exercised (1,518,267) $0.97 (998,365) $0.70 ------------------------------------------------------------------------- Expired (1,573,209) $4.00 (121,000) $3.68 ------------------------------------------------------------------------- Outstanding, end of year 17,432,717 $3.60 16,212,490 $3.31 ------------------------------------------------------------------------- Exercisable, end of year 10,204,053 $3.18 6,563,864 $2.14 ------------------------------------------------------------------------- All stock options have been granted for a period of five years. Options granted under the plan are generally fully exercisable after three years. The table below summarizes unexercised stock options. ------------------------------------------------------------------------- Weighted Weighted Average Average Remaining Number Exercise Contractual Range of Exercise Prices Outstanding Price Life ------------------------------------------------------------------------- At December 31 2007 ------------------------------------------------------------------------- $0.20 - $0.99 1,997,968 $0.72 1.8 ------------------------------------------------------------------------- $1.00 - $1.99 1,632,000 $1.58 2.4 ------------------------------------------------------------------------- $2.00 - $3.99 6,479,216 $3.51 3.7 ------------------------------------------------------------------------- $4.00 - $5.99 7,323,533 $4.91 3.4 ------------------------------------------------------------------------- 17,432,717 $3.60 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Weighted Weighted Average Average Remaining Number Exercise Contractual Range of Exercise Prices Outstanding Price Life ------------------------------------------------------------------------- At December 31 2006 ------------------------------------------------------------------------- $0.20 - $0.99 3,137,235 $0.69 1.7 ------------------------------------------------------------------------- $1.00 - $1.99 1,996,000 $1.61 2.4 ------------------------------------------------------------------------- $2.00 - $3.99 3,679,000 $3.18 3.1 ------------------------------------------------------------------------- $4.00 - $5.99 7,400,255 $4.99 3.3 ------------------------------------------------------------------------- 16,212,490 $3.31 ------------------------------------------------------------------------- In 2007 a non-cash charge of $6.1 million (2006 -$8.3 million) was expensed, reflecting the fair value of stock options amortized over the vesting period. Of this amount, $5.7 million (2006 -$7.8 million) was included in general and administrative expenses and $0.4 million (2006- $0.5 million) was charged to refining operating costs. A further $2.2 million (2006 -$3.5 million) was capitalized to property and equipment. The fair value of each stock option granted is estimated on the date of grant using the Black-Scholes option-pricing model with weighted average assumptions for grants as follows: ------------------------------------------------------------------------- 2007 2006 ------------------------------------------------------------------------- Risk free interest rate 4.1% 4.1% ------------------------------------------------------------------------- Expected option life (years) 3 3 ------------------------------------------------------------------------- Expected volatility 52% 50% ------------------------------------------------------------------------- The weighted average fair value at the date of grant of all options granted in 2007 was $1.50 per option (2006 -$1.81). (e) Share purchase warrants In 2006, the company's 1,493,820 outstanding share purchase warrants were exercised. No further share purchase warrants were issued or are outstanding. (f) Share award plan for non-employee directors Shareholders of the company approved a share award incentive plan for non-employee directors at the company's Annual and Special Meeting of Shareholders on May 10, 2007. Under the plan, a total of 326,925 share units (represented by common shares) were awarded to non-employee directors. In June 2007, 108,975 common shares were issued to directors as compensation under the plan; on January 1, 2008 a further 108,975 share units vested and the equivalent number of common shares were issued on January 16, 2008; the remaining 108,975 share units vest on January 1, 2009. 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. Payment under the plan is made by delivering common shares to non-employee directors either through purchases on the Toronto Stock Exchange or by issuing shares from treasury, subject to certain limitations. The Board of Directors may also 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 shares. In the year ended December 31, 2007, a non-cash charge of $810,000 (year ended December 31, 2006 - nil) was recorded in respect of grants under the share award plan. Of this amount, $392,000 was credited to Share Capital for the 108,975 shares issued and $418,000 was accrued in Accounts Payable for the vested portion of the remaining 217,950 shares to be issued. 14. RELATED PARTY TRANSACTIONS In 2007 the company paid professional legal fees of $667,000 (2006 - 1.8 million) to a law firm in which an officer and a director of the company are 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. 15. SEGMENTED INFORMATION In Canada, the company is in the business of exploring and producing conventional petroleum and natural gas and the exploration, development and production of bitumen in the oil sands of northern Alberta. In the U.S., the company is in the business of refining and marketing petroleum products. The significant aspects of these operating segments are presented below. Included in Canadian administrative assets is the company's carrying value of its investment in Petrolifera. ------------------------------------------------------------------------- Year ended December 31 Canada Canada USA ------------------------------------------------------------------------- Oil and Adminis- ($000) Gas trative Refining Total ------------------------------------------------------------------------- 2007 ------------------------------------------------------------------------- Revenues, net of royalties $ 30,722 $ - $ 313,050 $ 343,772 ------------------------------------------------------------------------- Equity interest in Petrolifera earnings - 6,953 - 6,953 ------------------------------------------------------------------------- Dilution gain - 1,917 - 1,917 ------------------------------------------------------------------------- Interest and other income 232 - 516 748 ------------------------------------------------------------------------- Crude oil purchase and operating costs 9,364 - 264,848 274,212 ------------------------------------------------------------------------- General and administrative - 8,543 - 8,543 ------------------------------------------------------------------------- Stock-based compensation - 5,650 - 5,650 ------------------------------------------------------------------------- Finance charges - 6,858 - 6,858 ------------------------------------------------------------------------- Foreign exchange (gain) (26,900) - - (26,900) ------------------------------------------------------------------------- Depletion, depreciation and accretion 25,887 - 5,174 31,061 ------------------------------------------------------------------------- Taxes (recovery) (1,927) - 14,932 13,005 ------------------------------------------------------------------------- Net earnings (loss) 24,530 (12,181) 28,612 40,961 ------------------------------------------------------------------------- Property and equipment, net 610,677 6,735 54,010 671,422 ------------------------------------------------------------------------- Capital expenditures and acquisitions 300,336 6,711 15,915 322,962 ------------------------------------------------------------------------- Total assets 1,108,309 42,346 108,173 1,258,828 ------------------------------------------------------------------------- 2006 ------------------------------------------------------------------------- Revenues, net of royalties $ 31,786 $ - $ 211,874 $ 243,660 ------------------------------------------------------------------------- Equity interest in Petrolifera earnings - 11,078 - 11,078 ------------------------------------------------------------------------- Dilution gain - 23 - 23 ------------------------------------------------------------------------- Interest and other income 600 - 424 1,024 ------------------------------------------------------------------------- Crude oil purchase and operating costs 8,270 - 182,668 190,938 ------------------------------------------------------------------------- General and administrative 3,886 - - 3,886 ------------------------------------------------------------------------- Stock-based compensation - 7,816 - 7,816 ------------------------------------------------------------------------- Finance charges 4,992 - 94 5,086 ------------------------------------------------------------------------- Foreign exchange loss 4,287 - - 4,287 ------------------------------------------------------------------------- Depletion, depreciation and accretion 29,366 - 3,583 32,949 ------------------------------------------------------------------------- Taxes (recovery) (5,165) - 9,035 3,870 ------------------------------------------------------------------------- Net earnings (loss) (13,250) 3,285 16,918 6,953 ------------------------------------------------------------------------- Property and equipment, net 333,358 1,314 49,639 384,311 ------------------------------------------------------------------------- Capital expenditures and acquisitions 378,173 1,169 72,183 451,525 ------------------------------------------------------------------------- Total assets 582,325 23,057 107,548 712,930 ------------------------------------------------------------------------- 16. SUPPLEMENTARY INFORMATION (a) Per share amounts The following table summarizes the common shares used in per share calculations. ------------------------------------------------------------------------- For the years ended December 31 2007 2006 ------------------------------------------------------------------------- Weighed average common shares outstanding 200,092,469 184,468,631 ------------------------------------------------------------------------- Dilutive effect of stock options and stock purchase warrants 2,674,470 3,963,178 ------------------------------------------------------------------------- Weighed average common shares outstanding - diluted 202,766,939 188,431,809 ------------------------------------------------------------------------- Common shares issuable on conversion of the convertible debentures have not been included in the diluted earnings per share calculation as their effect is anti-dilutive at Connacher's current share price at year end. (b) Net change in non-cash working capital ------------------------------------------------------------------------- For the years ended December 31 ($000) 2007 2006 ------------------------------------------------------------------------- Accounts receivable $ 5,872 $ (25,284) ------------------------------------------------------------------------- Inventories 6,058 (4,441) ------------------------------------------------------------------------- Due from Petrolifera 32 189 ------------------------------------------------------------------------- Prepaid expenses (995) (692) ------------------------------------------------------------------------- Accounts payable and accrued liabilities (5,249) 31,567 ------------------------------------------------------------------------- Income taxes payable/recoverable (7,923) 3,512 ------------------------------------------------------------------------- Total $ (2,205) $ 4,851 ------------------------------------------------------------------------- Summary of working capital changes: ------------------------------------------------------------------------- ($000) 2007 2006 ------------------------------------------------------------------------- Operations $ 6,464 $ (9,271) ------------------------------------------------------------------------- Investing (8,669) 14,122 ------------------------------------------------------------------------- $ (2,205) $ 4,851 ------------------------------------------------------------------------- (c) Supplementary cash flow information ------------------------------------------------------------------------- For the years ended December 31 ($000) 2007 2006 ------------------------------------------------------------------------- Interest paid $ 24,403 $ 6,578 ------------------------------------------------------------------------- Income taxes paid 19,001 3,655 ------------------------------------------------------------------------- Stock-based compensation capitalized $ 2,220 3,485 ------------------------------------------------------------------------- At December 31, 2007 cash of $63.2 million was restricted to fund the first year of interest payments on the company's Senior Notes. At December 31, 2006, $122.8 million was restricted for use in paying expenditures for a designated oil sands project under the Oil Sands Term Loan agreement. 17. COMMITMENTS, CONTINGENCIES AND GUARANTEES The company's annual commitments under leases for office premises and operating costs, field compression equipment, software license agreements and other equipment are as follows: 2008 - $3.3 million; 2009 - $2.9 million; 2010 - $2.6 million; 2011 - $2.8 million; 2012 - $2.8 million; total thereafter $12.5 million. Additionally, the company has various guarantees and indemnifications in place in the ordinary course of business, none of which are expected to have a significant impact on the company's financial statements or operations. 18. SUBSEQUENT EVENT Subsequent to December 31, 2007 the company entered into a costless collar contract for a notional 5,000 mmbtu per day of natural gas sales for the period from April 1 to October 31, 2008. The collar has a floor price of US $7.50 per mmbtu and a ceiling price of US $10.05 per mmbtu.

For further information:

For further information: Richard A. Gusella, President and Chief
Executive Officer, Phone: (403) 538-6201, Fax: (403) 538-6225,
inquiries@connacheroil.com, www.connacheroil.com


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