Connacher reports 2006 results



    CALGARY, March 23 /CNW/ - Connacher Oil and Gas Limited (CLL - TSX)
achieved significant operational and financial progress during 2006. The
Company's financial and operating metrics were expansive and positive.
    Connacher made big steps in 2006 on our oil sands properties at Great
Divide, Alberta. The development of the high quality oil sands reservoir at
Great Divide's Pod One project is well advanced. Start up is expected to
commence in the summer of 2007. Meanwhile, other pods have been identified for
future growth. Connacher also plans to submit an application to regulators
(including due consultation with all stakeholders) to proceed with an
additional 10,000 bbl/d project (the "Algar Project") at its Pod Two located
east of Pod One at Great Divide.
    Our conventional natural gas production and our oil refinery are
supporting our oil sands initiative as planned. Connacher's investment in
Petrolifera Petroleum has performed exceptionally well, with significant
growth in market value.

    
    Highlights of the 2006 year were as follows:

    -   Conventional production more than tripled to 2,725 boe/d
    -   Revenues expanded approximately 25 times to reach $245 million
    -   Cash flow from operations before working capital adjustments(1)
        increased 9 fold to $40 million
    -   Cash flow per share(1) increased 450 percent, despite a 75 percent
        increase in weighted average outstanding shares issued to finance
        growth
    -   Capital spending including acquisitions reached $452 million
    -   Almost $600 million of debt and equity financing was completed during
        the year, assuring control of Great Divide
    -   Great Divide Pod One 10,000 bbl/d SAGD oil sands development project
        approved, financed and underway, on time and on budget
    -   Pod Two development application being finalized - subject to
        regulatory and final approval by Connacher's Board of Directors,
        another 10,000 bbl/d project to follow completion of Pod One
    -   Proved conventional and bitumen reserves up 30 times over 2005 level

    The following table summarizes the company's financial and operating
highlights for the full year, compared to 2005 reported results.

    FINANCIAL AND OPERATING HIGHLIGHTS

    -------------------------------------------------------------------------
                                            2006          2005      % Change
    -------------------------------------------------------------------------
    FINANCIAL
    -------------------------------------------------------------------------
    ($000 except per share amounts)
    Revenues net of royalties          $ 244,684     $   9,795          2400
    Cash flow from operations(1)          40,196         4,358           822
      Basic, per share(1)                   0.22          0.04           450
      Diluted, per share(1)                 0.21          0.04           425
    Net earnings                           6,953           991           602
      Basic and diluted, per share          0.04          0.01           300
    Capital expenditures and
     acquisitions                        451,525        16,807         2,587
    Proceeds on disposal of oil and
     gas properties                       10,000             -             -
    Bank debt                            229,254             -             -
    Working capital                      118,626        75,427            59
    Cash on hand                         142,391        75,511            89
    Shareholders' equity                 385,398       129,108           196
    Total assets                         712,930       134,813           429

    OPERATING
    -------------------------------------------------------------------------
    Production
      Natural gas (mcf/d)                 10,473           827         1,166
      Crude oil (bbl/d)                      980           729            34
      Equivalent (boe/d)(2)                2,725           867           214
    Pricing
      Crude oil ($/bbl)                    53.85         42.33            27
      Natural gas ($/mcf)                   5.85          1.37           327
    Selected Highlights ($/boe)(2)
      Weighted average sales price         41.83         36.91            13
      Royalties                             9.87          8.16            21
      Operating and transportation
       costs                                8.32          7.73             8
      Netback                              24.67         23.23             6
    Reserves (mboe)(3)
      Proved (1P)                         50,381         1,501         3,256
      Probable                            42,555        70,598           (40)
      Total proved plus probable (2P)(4)  92,936        72,099            29

    COMMON SHARE INFORMATION
    -------------------------------------------------------------------------
    Shares outstanding at end of
     period (000)                        197,894       139,940            41
    Weighted average shares outstanding
      Basic (000)                        184,469       106,114            74
      Diluted (000)                      188,432       111,846            68
    Volume traded during the year (000)  323,825       338,402            (4)
    Common share price ($)
      High                                  6.07          4.20            45
      Low                                   3.09          0.49           531
      Close, end of year                    3.49          3.84            (9)
    -------------------------------------------------------------------------

    (1) Cash flow from operations before working capital changes 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 from operations before working capital changes
        includes all cash flow from operating activities and is calculated
        before changes in non-cash working capital. The most comparable
        measure calculated in accordance with GAAP would be net earnings.
        Cash flow from operations before working capital changes is
        reconciled with net earnings on the Consolidated Statement of Cash
        Flows and in the accompanying Management's 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: 1bbl. Boes 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) The reserve estimates for 2006 and 2005 were prepared by an
        independent professional petroleum engineering firm in accordance
        with National Instrument 51-101 (NI 51-101). Under NI 51-101, proved
        reserve assignments are based on a high degree of certainty with a
        targeted 90 percent probability that total quantities received will
        equal or exceed proved reserve estimates. Proved plus probable
        reserves are the most likely case with a targeted 50 percent
        probability that they will equal or exceed estimates. Proved plus
        probable plus possible reserves are based on a low degree of
        certainty with a 10 percent probability that they will equal or
        exceed estimates.
    (4) After production of 1 million boe in 2006.
    (5) No dividends have been declared by the company since its
        incorporation.

    Summary fourth quarter 2006 results are contained in the enclosed MD&A.
    Connacher Oil and Gas Limited experienced a year of great expansion in
2006. As indicated above, revenues exploded to $245 million; cash flow
increased almost ten fold to $40 million; conventional production more than
tripled to 2,725 boe/d and our proved reserve base expanded 30 fold to over
50 million boe, following the initial recognition of proved reserves at our
Great Divide Pod One oil sands project in northeastern Alberta.
    During the year we successfully implemented our integration strategy to
enable a smaller producer like Connacher to successfully manage its
involvement in a steam assisted gravity drainage ("SAGD") oil sands project.
This included:

    -   purchasing Luke Energy Ltd. for its natural gas reserves, exploratory
        potential, cash flow and credit capacity to allow us to physically
        hedge against natural gas costs to be incurred with the steam
        generating process at Pod One;

    -   addressing crude oil pricing differential risk by purchasing a small
        but efficient and profitable refinery (and associated product
        inventory) located just across the Canada-US border at Great Falls,
        Montana. Following the purchase, which also provided revenue, cash
        flow and considerable earnings, we expanded throughput capacity and
        improved operating efficiency;

    -   strengthening our balance sheet with successful equity and term debt
        financings totaling $591 million, thereby assuring Connacher the
        ability to develop Pod One on its own. Shares were also issued in
        conjunction with the aforementioned purchases to ensure financial
        viability and to avoid undue balance sheet leverage. Of particular
        note was our successful private placement of an attractively priced
        US$180 million issue of seven year term debt to assist in financing
        the $256 million Pod One project and to repay the bridge loan
        incurred to acquire the Montana refinery. As a result, Connacher
        secured the balance of funding required to complete its initial oil
        sands project. The company was able to secure the loan solely with
        its oil sands and refining interests, leaving Connacher with optimum
        financial flexibility and the debt capacity of its conventional
        properties and its valuable holdings of Petrolifera Petroleum
        Limited, which during the year exceeded $300 million; and

    -   addressing execution risk. In initiating its Pod One plant and site
        construction and arranging for the drilling of its 15 SAGD well pairs
        for steam injection and production, Connacher was able to reduce
        execution and cost escalation risk by careful pre-planning and
        adopting a modular approach, particularly for its plant construction
        program. In this manner, Connacher has been able to build most of its
        long lead essential and expensive components in nearby fabrication
        shops away from the plant site, which is remote and would have been
        prone to increasing inflationary cost pressures. Under our approach,
        components can be skid-mounted and transported by road to Pod One
        when the timetable is appropriate. By introducing an oil field
        mentality to the process, Connacher is confident of its general
        ability to control costs and complete on time.
    

    This strategy translates into a reduction of operating cost risk,
construction cost risk, balance sheet risk and downstream crude oil price
differential risk. It forms an integral part of Connacher's integrated
approach and will set precedents for future developments by the company in the
region.
    Considerable drilling success was encountered at Marten Creek, Alberta
and elsewhere in northern Alberta during the current 2007 winter drilling
season. Also, approximately 80 core holes and an extensive 3D seismic program
were completed on our Great Divide main lease block during this period.
    As a consequence, Connacher will be updating its reserve estimates for
both conventional properties and its oil sands properties during the second
quarter of 2007 and will communicate the results of this update upon
acceptance by our Board of Directors of reports to be prepared by GLJ
Petroleum Consultants ("GLJ") of Calgary, Alberta.
    Construction at Great Divide Pod One is proceeding favorably with a view
to commissioning and startup during the summer 2007. Drilling of the SAGD well
pairs has been efficient and yielded favorable results. Readers are referred
to our website at www.connacheroil.com for pictorial updates of our progress.
Connacher has introduced innovative, cost-saving and environmentally friendly
technology to its Pod One plant and remains mindful of sound relationships
with regulators and stakeholders, including First Nations people, in its
operations in this area of northern Alberta. Transportation alternatives are
under late-stage evaluation and a decision on the preferred alternative is
pending.
    Successful follow up drilling at Pod Two has enabled Connacher to arrive
at a decision point to proceed with an application to develop another
10,000 bbl/d small scale commercial operation (the "Algar Project") at Great
Divide. It is anticipated the application for Algar will be submitted in May,
2007 with a view to commencement of construction sometime in early 2008,
subject to final approval by Connacher's Board of Directors and following due
consultation with stakeholders and receipt of regulatory approval. Preliminary
design and advance equipment ordering would likely occur throughout the second
half of 2007. This sequential development will enable Connacher to retain its
access to personnel and suppliers while it starts up and commences production
at Pod One. It is consistent with Connacher's commitment of sustainability and
repeatability of growth opportunities for its shareholders.
    Connacher's total capital budget for 2007 has initially been established
at $249 million, with the majority of this amount directed to completion of
our development project at Great Divide Pod One. When the final decision on
transportation and development of Pod Two occurs, additional capital and
related budgetary allocations will be required at some point during 2007.
    Connacher's outlook remains very buoyant and exciting.

    Connacher is a Calgary-based oil and natural gas exploration and
production company. Its principal asset is its 100 percent interest in
reserves, resources and lands in the Great Divide regions of Alberta's oil
sands. Connacher also has conventional crude oil and natural gas properties in
Alberta and Saskatchewan, owns an 9,500 bbl/d refinery in Great Falls, Montana
and owns a 26 percent basic and fully-diluted interest in, and assists in the
management of, Petrolifera Petroleum Limited. This investment has a current
market value in excess of $200 million.

    FORWARD LOOKING STATEMENTS

    This press release contains forward-looking statements, including but not
limited to estimated reserves, resources and future net revenues related
thereto, future exploration and development plans, anticipated capital
expenditures and sources of funding in respect thereof, anticipated start-up
of Pod One and current plans with respect to the development for Pod Two,
including plans for regulatory application and commencement of construction,
including final approval by Connacher's Board of Directors. These statements
are based on current expectations that involve a number of risks and
uncertainties, which could cause actual results to differ materially from
those anticipated. These risks include, but are not limited to 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 in relation to production, costs and expenses and health,
safety and environmental risks), risks associated with construction and
commencement of first production, the risk of commodity price and foreign
exchange rate fluctuations, the uncertainty associated with geological
interpretations and risks relating to securing required approvals and consents
to proceed with future development opportunities. Additional risks and
uncertainties are described in the company's Annual Information Form which is
filed on SEDAR at www.sedar.com.
    The reserves, resources and future net revenue in this press release
represent estimates only. The reserves, resources and future net revenue from
the company's properties have been independently evaluated by GLJ Petroleum
Consultants with an effective date of December 31, 2006. This evaluation
includes a number of assumptions relating to factors such as initial
production rates, production decline rates, ultimate recovery of reserves and
resources, timing and amount of capital expenditures, marketability of
production, future prices of bitumen, crude oil and natural gas, operating
costs, abandonment and salvage values, royalties and other government levies
that may be imposed during the producing life of the reserves and resources.
These assumptions were based on price forecasts in use at December 31, 2006
and many of these assumptions are subject to change and are beyond the control
of the company. Actual production, sales and cash flows derived therefrom will
vary from the evaluation and such variations could be material. The present
value of estimated future net cash flows referred to herein should not be
construed as the current market value of estimated bitumen, crude oil and
natural gas reserves attributable to the company's properties.
    Forecast capital expenditures are based on Connacher's current budgets
and development plans which are subject to change based on commodity prices,
market conditions, drilling success and potential timing delays. Additionally,
forecast capital expenditures do not include capital required to pursue future
acquisitions or for the development of additional oil sands projects, such as
Pod Two. Anticipated production has been estimated based on the proposed
drilling program with a success rate based upon historical drilling success
and an evaluation of the particular wells to be drilled and has been risked.


    MANAGEMENT'S DISCUSSION AND ANALYSIS

    The following is dated as of March 23, 2007 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 2006 and 2005
as contained in the Company's 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.

    FORWARD-LOOKING INFORMATION

    Information in this report contains forward-looking information based on
current expectations, estimates and projections of future production, capital
expenditures and available sources of financing and estimates of reserves,
resources and future net revenues and exploration and development plans. It
should be noted forward-looking information involves a number of risks and
uncertainties and actual results may vary materially from those anticipated by
the company. There can be no assurance that the plans, intentions or
expectations upon which these forward-looking statements are based will occur.
Forward-looking statements are subject to risks, uncertainties and
assumptions, including those discussed in the company's Annual Information
Form for the year ended December 31, 2006, which include, without limitation,
changes in market conditions, law or governing policy, operating conditions
and costs, operating performance, demand for crude oil and natural gas, price
and exchange rate fluctuations, commercial negotiations, regulatory processes
and approvals and technical and economic factors. Although Connacher believes
that the expectations represented in such forward-looking statements are
reasonable, there can be no assurance that such expectations will prove to be
correct. The forward-looking statements contained herein are expressly
qualified in their entirety by this cautionary statement. The forward-looking
statements included in this MD&A are made as of the date of the MD&A and
Connacher undertakes no obligation to publicly update such forward-looking
statements to reflect new information, subsequent events or otherwise unless
so required by applicable securities laws. 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 crude oil (6:1). The
conversion is based on an energy equivalency conversion method primarily
applicable to the burner tip and does not represent a value equivalency at the
wellhead. Boes may be misleading, particularly if used in isolation.

    
    BUSINESS STRATEGY

    -------------------------------------------------------------------------
           Strategic Priorities                   Progress in 2006

    -------------------------------------------------------------------------
    Operate with large focused working   Great Divide - 100% working interest
    interest                             retained through the financing of
                                         Pod One
                                         Battrum Saskatchewan crude oil and
                                         Marten Creek natural gas
    -------------------------------------------------------------------------
    Apply financial discipline           Great Divide (Pod One) financing
                                         arranged with term debt - non-
                                         recourse to conventional assets &
                                         equity in Petrolifera
                                         Successful equity financings in 2005
                                         and 2006 totaling $220 million
                                         Cash flow finances conventional and
                                         refinery projects; available banking
                                         lines of credit
    -------------------------------------------------------------------------
    Focus on projects with               Develop Great Divide Pod One and use
    characteristics of                   as a template to develop additional
    sustainability, repeatability        pods
    -------------------------------------------------------------------------
    Mitigate and manage risks of         Purchased Luke Energy Ltd. ("Luke")
    smaller company in the oil sands     (gas producer) for natural gas
      -integrated approach               required for steaming Pod One at
                                         Great Divide
                                         Purchase of Montana refinery to
                                         mitigate price differential risk and
                                         potential for marketing Great Divide
                                         bitumen production
                                         Initiatives to mitigate
                                         environmental concerns
                                         -low impact seismic (minimum line
                                          width)
                                         -SAGD provides smaller surface
                                          footprint than mining
                                         -produced gas conserved
                                         -evaporator/package boiler
    -------------------------------------------------------------------------


    FINANCIAL AND OPERATING REVIEW
    CONVENTIONAL PRODUCTION, PRICING AND REVENUE

    For the years ended December 31             2006        2005        2004
    -------------------------------------------------------------------------
    Daily production / sales volumes
    -------------------------------------------------------------------------
      Crude oil - bbl/d                          980         729         785
    -------------------------------------------------------------------------
      Natural gas - mcf/d                     10,473         827       1,620
    -------------------------------------------------------------------------
      Combined - boe/d                         2,725         867       1,055
    -------------------------------------------------------------------------
    Product pricing ($)
    -------------------------------------------------------------------------
      Crude oil - per bbl                      53.85       42.33       31.42
    -------------------------------------------------------------------------
      Natural gas - per mcf                     5.85        1.37        3.62
    -------------------------------------------------------------------------
      Boe - per boe                            41.83       36.91       28.95
    -------------------------------------------------------------------------
    Revenue ($000)
      Petroleum and natural gas - gross       41,607      11,678      11,180
    -------------------------------------------------------------------------
    Royalties                                 (9,821)     (2,583)     (2,139)
    -------------------------------------------------------------------------
    Petroleum and natural gas revenue - net   31,786       9,095       9,041
    -------------------------------------------------------------------------

    In 2006, net petroleum and natural gas revenues were up 256.3 percent to
$31.8 million from $9.1 million in 2005. This was primarily attributable to a
substantial increase in natural gas production resulting from the Luke
acquisition in March 2006. Natural gas sales volumes increased 1,166 percent
and crude oil sales volumes increased 34 percent in 2006. As a consequence of
increased world oil prices in 2006, the company's average crude oil selling
price increased by 27 percent to $53.85 per barrel compared to $42.33 per
barrel in 2005. Natural gas sales prices increased 327 percent in 2006, but
this was primarily due to the influence of low natural gas prices received in
Argentina in 2005 when the results of Petrolifera Petroleum Limited
("Petrolifera") were consolidated with those of Connacher. As a result of the
Luke acquisition, the company's product mix is more balanced. Crude oil sales
represented 46 percent of the company's total production revenue in 2006 and
natural gas sales contributed 54 percent.

    ROYALTIES ON CONVENTIONAL PETROLEUM AND NATURAL GAS SALES

                                       2006                    2005
                              -----------------------------------------------
                                 Total      Per boe      Total      Per boe
    -------------------------------------------------------------------------
    Petroleum and natural
     gas royalties             $   9,821   $    9.87   $   2,583   $    8.16
    -------------------------------------------------------------------------
    Percentage of petroleum
     and natural gas revenue       23.6%                     22%
    -------------------------------------------------------------------------

    Royalties represent charges against production or revenue by governments
and landowners. Royalties in 2006 were $9.8 million ($9.87 per boe, or 23.6
percent of petroleum and natural gas revenue) compared to $2.6 million in 2005
($8.16 per boe, or 22 percent of petroleum and natural gas 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 increase from 2005 to 2006
reflects market conditions related to increased product prices and production
volumes.

    CONVENTIONAL OPERATING EXPENSES AND NETBACKS(1)

    For the years ended December 31


    ($000 except           2006                2005            % Change
     per boe)      ----------------------------------------------------------
                     Total   Per boe     Total   Per boe     Total   Per boe
    -------------------------------------------------------------------------
    Average daily
     production
     (boe/d)             2,725                867                 214
    -------------------------------------------------------------------------
    Petroleum and
     natural gas
     revenue       $41,607   $ 41.83   $11,678   $ 36.91       256        13
    -------------------------------------------------------------------------
      Royalties     (9,821)    (9.87)   (2,583)    (8.16)      280        21
    -------------------------------------------------------------------------
      Net revenue   31,786     31.96     9,095     28.75       250        11
    -------------------------------------------------------------------------
      Operating
       costs        (8,270)    (8.32)   (2,445)    (7.73)      238         8
    -------------------------------------------------------------------------
    Operating
     netback       $23,516   $ 23.64   $ 6,650   $ 21.02       254        13
    -------------------------------------------------------------------------

    (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 2006 operating costs of $8,270 were 238 percent higher than in the
prior year, and on a per unit basis, increased by 7.6 percent to $8.32 per boe
reflecting the higher cost environment in 2006 and the substantial increases
in production volumes during the year. However, higher product prices resulted
in higher operating netbacks in 2006.

    NETBACK BY PRODUCT TYPE
    -------------------------------------------------------------------------
    For the year ended
     December 31                                   2006
    -------------------------------------------------------------------------
    ($000, except per unit              Oil                    Gas
     amounts)                         (bbl/d)                (mcf/d)
    -------------------------------------------------------------------------
    Average daily production            980                  10,473
    -------------------------------------------------------------------------
    Revenue                    $  19,257   $   53.85   $  22,350   $    5.85
    -------------------------------------------------------------------------
    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
    -------------------------------------------------------------------------

    Reconciliation of Operating Netback to Net Earnings

    -------------------------------------------------------------------------
    For the year ended
     December 31                                2006                    2005
    -------------------------------------------------------------------------
    ($000, except per unit
     amounts)                      Total     Per boe       Total     Per boe
    -------------------------------------------------------------------------
    Operating netback
     as above                  $  23,516   $   23.64   $   6,650   $   21.02
    -------------------------------------------------------------------------
    Interest income                1,024        1.03         700        2.21
    -------------------------------------------------------------------------
    Refining margin - net         29,206       29.36           -           -
    -------------------------------------------------------------------------
    General and administrative    (3,886)      (3.91)     (2,660)      (8.40)
    -------------------------------------------------------------------------
    Stock-based compensation      (7,816)      (7.86)     (1,192)      (3.77)
    -------------------------------------------------------------------------
    Finance charges               (5,086)      (5.11)       (308)      (0.97)
    -------------------------------------------------------------------------
    Foreign exchange (loss)
     gain                         (4,287)      (4.31)         30        0.09
    -------------------------------------------------------------------------
    Depletion, depreciation
     and amortization            (32,949)     (33.13)     (5,797)     (18.32)
    -------------------------------------------------------------------------
    Income taxes                  (3,870)      (3.89)       (870)      (2.75)
    -------------------------------------------------------------------------
    Equity interest in
     Petrolifera earnings
     and dilution gain            11,101       11.16       4,437       14.02
    -------------------------------------------------------------------------
    Net earnings               $   6,953   $    6.98   $     991   $    3.13
    -------------------------------------------------------------------------

    REFINING REVENUES AND MARGINS

    The operating results of the refinery since its acquisition on March 31,
2006 to December 31, 2006 are summarized below.

    Refinery Throughput

    -------------------------------------------------------------------------
    Crude charged                                                8,713 bbl/d
    -------------------------------------------------------------------------
    Refinery production                                          9,498 bbl/d
    -------------------------------------------------------------------------
    Sales of produced refined products                           9,661 bbl/d
    -------------------------------------------------------------------------
    Sales of refined products (includes purchased products)     10,053 bbl/d
    -------------------------------------------------------------------------
    Refinery utilization(1)                                              94%
    -------------------------------------------------------------------------
    (1) Note in Q4 refinery capacity was increased to 9,900 bbl/d.

    Feedstocks

    -------------------------------------------------------------------------
    Sour crude oil                                                       92%
    -------------------------------------------------------------------------
    Other feedstocks & blend                                              8%
    -------------------------------------------------------------------------

    Revenues and Margins

    -------------------------------------------------------------------------
    Refining sales revenue ($000)                                    211,874
    -------------------------------------------------------------------------
    Refining - crude oil and operating costs ($000)                  182,668
    -------------------------------------------------------------------------
    Refining - margin ($000)                                          29,206
    -------------------------------------------------------------------------
    Refining margin (%)                                                13.8%
    -------------------------------------------------------------------------

    Sales of Produced Refined Products (Volume %)

    -------------------------------------------------------------------------
    Gasolines                                                          35.6%
    -------------------------------------------------------------------------
    Diesel fuels                                                       17.6%
    -------------------------------------------------------------------------
    Jet fuels                                                           3.4%
    -------------------------------------------------------------------------
    Asphalt                                                            40.2%
    -------------------------------------------------------------------------
    LPG and other                                                       3.2%
    -------------------------------------------------------------------------
    Total                                                               100%
    -------------------------------------------------------------------------

    Averages Per Barrel of Refined Products Sold

    -------------------------------------------------------------------------
    Refining sales revenue                                            $76.63
    -------------------------------------------------------------------------
    Less: Refining - crude oil and operating costs                    $66.07
    -------------------------------------------------------------------------
    Refining margin                                                   $10.56
    -------------------------------------------------------------------------
    

    On March 31, 2006, Connacher completed the acquisition of an 8,300 bbl/d
refinery and related assets, including substantial product inventory, in Great
Falls, Montana.
    The refinery is a good strategic fit with Connacher's oilsands
development, as it is well-located - the closest U.S. refinery to Alberta's
oilsands. It processes Canadian heavy crude into a range of higher value
products including regular and premium gasoline, jet fuel, diesel, home
heating oil and asphalt. The refinery thus provides a physical hedge
protecting Connacher's future oil sands revenues against crude oil/bitumen
price differentials.
    The 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 states by truck and rail transport.
    Shortly after taking over the refinery, the company undertook a 20 day
turnaround to complete normal maintenance and de-bottlenecking activities. As
a result, throughput capacity was increased to 9,000 bbl/d. Through the year,
subsequent optimizations have increased crude throughput capacity to
9,900 bbl/d. Since the turnaround, the refinery has operated continuously with
no downtime and crude throughput has averaged 9,400 bbl/d with an average
annual capacity utilization of 94%.
    Connacher's refinery operation achieved an outstanding year in 2006 with
record levels of throughput, profit and profit margin. This performance was
due to improved efficiencies implemented subsequent to the acquisition,
increased throughput and sales volumes, and high product prices and
differentials for the heavy crude feedstocks used as a result of market
conditions.
    During the year, the company also made significant environmental
improvements to the operation. These included capital projects to remove
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.
    Other improvements initiated during the year included the construction of
a new 150,000 barrel asphalt tank (commissioned in March 2007) and expanded
rail loading facilities, both undertaken to handle the increased throughput
achieved during the year.
    Connacher employs a well-trained and experienced staff in Great Falls.
The company was successful in retaining most of the key personnel associated
with the refinery, as well as recruiting a number of other experienced
professionals. Key processes and systems have been fully integrated into the
company. Connacher's operation includes a strong training and development
program as well as rigorous procedures for safety and environmental
protection.
    In 2007, Connacher plans to continue making environmental and capacity
enhancements at the Montana refinery. We are designing new high efficiency
boilers, further increasing rail load-out capabilities, improving wastewater
treatment facilities, and further enhancing our sulphur treatment process.
    As well, Connacher has initiated a major Clean Fuels project targeted to
allow the production of ultralow sulphur diesel and gasoline in 2008.
    Engineering and marketing studies have also been initiated to assess the
possibility of major expansion of the refinery's heavy oil capacity.

    INTEREST AND OTHER INCOME

    In 2006, the company earned interest of $1 million (2005 - $700,000) on
excess funds invested in secure short-term investments.

    GENERAL AND ADMINISTRATIVE EXPENSES

    In 2006, general and administrative ("G&A") expenses were $3.9 million
compared to $2.7 million in 2005, an increase of 46 percent, reflecting
increased costs associated with being a public company as well as increased
staffing that occurred in 2006 in connection with the acquisition of the
Montana refinery and to support the development of Great Divide. G&A of $1.0
million was also capitalized in 2006 (2005 - $205,000).
    Non-cash stock-based compensation costs of $11.8 million were recorded in
2006 (2005 - $1.6 million). These charges reflect the fair value of all stock
options granted and vested in each year. Of this amount, $7.8 million was
expensed (2005 - $1.2 million), $3.5 million was capitalized (2005 - $410,000)
and $500,000 was charged to refining operating costs in 2006.

    FINANCE CHARGES

    Financing charges were $5.1 million in 2006 compared to $308,000 reported
in 2005. These charges increased significantly from 2005 due to the issuance
of debt in 2006, including the US$51 million bridge loan used to fund the
acquisition of the Montana refinery and the conventional line of credit. In
addition, an unrealized foreign exchange loss of $4.3 million was incurred in
2006 primarily due to the conversion of US$180 million oil sands term loan to
Canadian dollars for reporting purposes.
    The company's main exposure to foreign currency risk relates to the
pricing of its crude oil sales, which are denominated in US dollars, and the
translation of the US$180 million oil sands term loan. On an economic basis,
the company's crude oil and bitumen reserves hedge the company's exposure to
foreign currency fluctuations of its US dollar denominated oil sands term
loan.

    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 2006 was $32.9 million, a 468 percent
increase from last year due to increased production volumes and due to the
significant additions made to capital assets in 2006. This equates to $33.13
per boe of production compared to $18.32 per boe last year.
    Capital costs of $156.7 million (2005 - $11.3 million) related to the
Great Divide oil sands project, which is in the pre-production stage, have
been excluded from the depletion calculation. Additionally, undeveloped land
acquisition costs of $16.2 million (2005 - $2.5 million) were excluded from
the depletion calculation, while future development costs of $3.2 million
(2005 - $1.8 million) for proved undeveloped reserves were included in the
depletion calculation.
    Included in DD&A is a charge of $348,000 (2005 - $165,000) in respect of
the company's estimated asset retirement obligations. These charges will
continue to be necessary in the future to accrete the currently booked
discounted liability of $7.3 million to the estimated total undiscounted
liability of $17.4 million over the remaining economic life of the company's
oil and gas properties.

    CEILING TEST

    Oil and gas companies are required to compare the recoverable value of
their 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
2006 or 2005.

    TAXES

    The income tax provision of $3.9 million in 2006 includes a current tax
provision of $7.4 million, principally related to US refinery operations and a
future tax recovery of $3.5 million reflecting the benefit of increased tax
pools.
    At December 31, 2006 the company had approximately $25.8 million of non-
capital losses which do not expire before 2009, $253.5 million of deductible
resource pools and $20.7 million of deductible financing costs.

    EQUITY INTEREST IN PETROLIFERA PETROLEUM LIMITED

    Connacher accounts for its 26 percent equity investment in Petrolifera on
the equity method basis of accounting. Until the third quarter of 2005,
Petrolifera was consolidated with Connacher. Connacher's equity interest share
of Petrolifera's earnings in 2006 was $11.1 million (2005 - $27,000 loss)

    DILUTION GAIN

    In 2004 and in 2005, the company's equity interest in Petrolifera was
diluted as a result of Petrolifera issuing common shares. In November 2004,
the company's equity interest was reduced from 100 percent to 61 percent; in
March 2005 it was reduced to 40 percent, in late 2005, it was reduced to 33
percent and in 2006 it was further reduced to 26 percent. These reductions
resulted in a dilution gain to the company of $23,000 in 2006 and $4.5 million
in 2005.

    NET EARNINGS (LOSS)

    In 2006 the company reported earnings of $7.0 million ($0.04 per basic
and diluted share outstanding). This compares to earnings of $991,000 or $0.01
per basic and diluted share for 2005. Earnings per boe produced was $6.98
compared to $3.13 last year.

    SHARES OUTSTANDING

    For 2006, the weighted average number of common shares outstanding was
184,468,631 (2005 - 106,113,563) and the weighted average number of diluted
shares outstanding, as calculated by the treasury stock method, was
188,431,809 (2005 - 111,845,687). The substantial increase in shares
outstanding year over year reflects the issuance from treasury of 55,461,382
common shares for cash proceeds of $130 million and in connection with the
acquisitions of Luke and the Montana refinery assets.
    As at March 23, 2007, the company had the following securities issued and
outstanding:

    
    -  198,218,448 common shares; and
    -  15,840,057 share purchase options.
    

    Details of the exercise provisions and terms of the outstanding options
are noted in the consolidated financial statements.

    LIQUIDITY AND CAPITAL RE

SOURCES At December 31, 2006, the company had working capital of $118.6 million, including $123 million of cash dedicated to funding the remaining costs of completing Pod One. In 2006 the company drew US$51 million on a bridge loan facility to partially fund the acquisition of the Montana refinery assets, which closed on March 31, 2006. This bridge loan was repaid in full on October 20, 2006 from the proceeds of a US$180 million term loan facility that was fully drawn on that date (the "oil sands term loan"). The primary purpose of the oil sands term loan is to fund the development of the company's first oil sands project at Great Divide in northern Alberta ("Pod One"). After also depositing US$14 million into an account to fund the estimated interest costs during the course of completing the Pod One project and after paying US$4 million in costs to complete the transaction, the balance of oil sands term loan proceeds have been designated solely to fund the total estimated remaining costs necessary to complete Pod One. The oil sands term loan has a seven year term. Its principal is amortized by one percent per year commencing in 2008. Additional repayments will be due if certain cash flow performance thresholds are attained. Principal payments on the oil sands term loan are not expected to be significant in the first six years. The oil sands term loan is a floating-rate facility, bearing interest either at a US Dollar Base Rate plus a margin or a US Eurodollar rate plus a margin. In October 2006, the company entered into an interest rate swap with a financial institution whereby the floating rate on US$90 million of the oil sands term loan was fixed at an all-in rate of 8.516 percent over the term of the loan. All interest on the oil sands term loan is being capitalized until Pod One becomes operational. On October 20, 2006 the company also secured a US$15 million revolving line of credit ("refining line of credit") to fund the working capital requirements of the refinery in Great Falls, Montana. The refining line of credit has a five year term and bears interest at a US Eurodollar rate plus a margin or at a US Dollar Base Rate plus a margin. The oil sands term loan and the refining line of credit are secured by debenture and mortgage agreements covering all of the assets of the refinery and all of the company's interest in the Great Divide oil sands assets. These two facilities are non-recourse to the company's conventional petroleum and natural gas assets or to its investment in Petrolifera. The company also has available a $55 million extendible revolving loan facility (the "conventional line of credit") with no scheduled repayments. At December 31, 2006, $19.5 million was drawn in the form of bankers' acceptances under this facility at an interest rate of 5.62 percent including margin. The facility matures on April 15, 2007 and is extendible upon request by the company, at the lender's option for 364 days. The conventional line of credit is secured by a $50 million fixed and floating charge debenture and a general assignment of book debts over the company's conventional crude oil and natural gas assets, and is non-recourse to the company's Great Divide oil sands, its refining assets or to its investment in Petrolifera. Cash flow from operations before working capital changes ("cash flow"), cash flow per share and cash flow per boe 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. 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 below. Cash flow per share is calculated by dividing cash flow by the weighted average shares outstanding; cash flow per boe is calculated by dividing cash flow by the quantum of crude oil and natural gas (expressed in boe) sold in the period. 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. In addition to available cash, unused debt facilities and cash flow, additional sources of funding in the form of additional equity issuances or additional debt financing may be utilized to provide sufficient funding for working capital purposes and for the company's anticipated capital program in 2007. The company's only financial instruments are cash, accounts receivable and payable, bank debt and the interest rate swap. The company maintains no off-balance sheet financial instruments. Reconciliation of net earnings to cash flow from operations before working capital changes: Twelve months ended December 31 ------------------------------------------------------------------------- ($000) 2006 2005 ------------------------------------------------------------------------- Net earnings $ 6,953 $ 991 ------------------------------------------------------------------------- Items not involving cash: ------------------------------------------------------------------------- Depletion, depreciation and accretion 32,949 5,797 ------------------------------------------------------------------------- Stock-based compensation 8,293 1,192 ------------------------------------------------------------------------- Financing charges 2,237 150 ------------------------------------------------------------------------- Future income tax provision (recovery) (3,535) 768 ------------------------------------------------------------------------- Employee future benefits 381 - ------------------------------------------------------------------------- Foreign exchange (gain) loss 4,287 (30) ------------------------------------------------------------------------- Lease inducement amortization (268) (72) ------------------------------------------------------------------------- Dilution gain (23) (4,465) ------------------------------------------------------------------------- Equity interest in Petrolifera loss (earnings) (11,078) 27 ------------------------------------------------------------------------- Cash flow from operations before working capital changes $ 40,196 $ 4,358 ------------------------------------------------------------------------- For 2006, cash flow was $40.2 million ($0.22 per basic and $0.21 per diluted share), 822 percent higher than the $4.4 million reported ($0.04 per basic and diluted share) in 2005. Cash flow per boe was $40.41 in 2006 compared to $13.77 in 2005. This represents 97 percent of the average company selling price per boe compared to 37 percent in 2005 and an increase of 193 percent over 2005. CAPITAL EXPENDITURES AND FINANCING ACTIVITIES Capital expenditures totaled $452 million in 2006. A breakdown of the expenditures follows: Twelve months ended December ($000) 2006 2005 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Acquisition of Luke $ 204,658 $ - Acquisition of refinery assets 66,333 - Minor property acquisitions 6,767 1,700 Oil sands expenditures 144,765 7,224 Conventional oil and gas expenditures 23,152 7,783 Refinery expenditures 5,850 - ------------------------------------------------------------------------- $ 451,525 $ 16,807 ------------------------------------------------------------------------- Additionally, the company disposed of non-core properties for proceeds of $10 million in the fourth quarter of 2006. Oil sands expenditures include exploratory core hole drilling, seismic, lease acquisition and facility costs. In 2006, 26 exploratory core holes were drilled. Conventional oil and gas expenditures include costs of drilling, completing, equipping and working over conventional oil and gas wells as well as undeveloped land acquisition and seismic expenditures. 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 an approximate 87 percent working interest in its conventional properties, providing the company with operational and timing controls. Recent Financings In February 2006, the company issued 19,047,800 common shares at $5.25 per share for gross proceeds of $100 million to fund exploration and development activities associated with conventional crude oil and natural gas activities and the Great Divide Oil Sands project, for general corporate purposes, for working capital and to partially fund the acquisition of Luke. Proceeds of the financing were utilized as follows: As stated at the As time of actually ($000) financing applied ------------------------------------------------------------------------- Gross proceeds $ 100,000 $ 100,000 Underwriters commission and issue costs 6,250 6,250 ------------------------------------------------------------------------- Available for exploration and development, general corporate purposes for working capital and to fund a portion of the Luke acquisition $ 93,750 $ 93,750 ------------------------------------------------------------------------- In September 2006, the company issued 5,714,300 common shares on a "flow- through" basis at $5.25 per common share for gross proceeds of $30 million to fund exploration activities including the further delineation of the company's oil sands properties through the drilling of additional core holes and shooting 3D seismic. Proceeds of the financing were utilized as follows: As stated at the As time of actually ($000) financing applied ------------------------------------------------------------------------- Gross proceeds $ 30,000 $ 30,000 Underwriters commission and issue costs 2,075 1,883 ------------------------------------------------------------------------- Available for exploration activities $ 27,925 $ 28,117 ------------------------------------------------------------------------- Refer also to the "Liquidity and Capital Resources," above, for a discussion of the US$180 million and US$15 million debt facilities entered into in October 2006. Great Divide Oil Sands Project, Northern Alberta The company holds a 100 percent working interest in approximately 90,000 acres of oil sands leases in northern Alberta. To date, the focus has been on an approximate 1,586 acre tract ("Pod One") on which approximately $155 million has been invested to the end of 2006 to acquire the oil sands leases, to delineate the oil bearing reservoir, and for certain facilities related to the project. Capital development costs for Pod One are expeed to approximate $256 million. These cll be inurred in 2007. Acquisition of Luke Energy Ltd. ("Luke") In March 2006 the company closed the purchase of Luke for cash consideration of $92.7 million and the issuance of 29.7 million Connacher common shares from treasury. Luke produced natural gas, largely at Marten Creek in northern Alberta and operated most of its high working interest properties. This production was considered strategic to Connacher, as it provides a physical hedge to its initial requirements for natural gas to create steam for the company's SAGD oil sands project (Pod One) at Great Divide. Based on purchased production volumes and anticipated development programs, the Luke purchase is expected to provide surplus natural gas volumes for sale in the marketplace and meet future Connacher requirements at Great Divide. Luke was amalgamated with Connacher on January 1, 2007 Acquisition of Refining Assets in Montana In March 2006, the company acquired an 8,300 bbl/d refinery located in Great Falls, Montana, USA, for cash of $61 million and one million Connacher common shares issued from treasury. This acquisition was considered strategic to provide Connacher with protection against wider and more volatile type of heavy crude oil price differential swings. These have become increasingly frequent in the current higher oil price environment for the type of heavy oil which would be produced at Great Divide. Since its acquisition, the refinery has been a profitable and strong business unit contributing to the company's cash flow. Connacher completed the purchase of the refining assets and related inventory through a new wholly-owned subsidiary, Montana Refining Company, Inc. ("MRC"). Its continued profitability will depend largely on the spread between market prices for refined petroleum products and the cost of crude oil. MRC's principal source of revenue is from the sale of high value light end products such as gasoline, diesel and jet fuel in markets in the western United States. Additionally, MRC sells a high grade asphalt into the local market. MRC's principal expenses relate to crude oil purchases and operating expenses. In April 2006, MRC completed a scheduled plant "turnaround" maintenance program of its refinery facilities. Such turnarounds are normally scheduled every two to five years. Turnaround costs are capitalized and amortized over the period to the next scheduled turnaround. With minimal additional anticipated capital investment, MRC will be capable of producing low sulfur gasoline and diesel as required in 2008. The above mentioned regulatory compliance items or other presently existing or future environmental regulations, could cause management to make additional capital investments beyond those described above and/or incur additional operating costs to meet applicable requirements. In 2004, the American Jobs Creation Act of 2004 was signed into law. Among other things, the Act creates tax incentives for small refiners preparing to produce low sulphur gasoline and diesel. The Act provides an immediate deduction of 75% of certain costs paid or incurred to comply with these standards and a tax credit based on production for up to 25% of those costs. Management intends to utilize these incentives when it makes these required expenditures. RELATED PARTY TRANSACTIONS In 2006 the company paid professional legal fees of $1.8 million (2005 - $539,000) 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 is not meant to be exhaustive. Oil and Gas Reserves Under Canadian Securities Regulators' "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 equal or 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 are also used in determining the company's borrowing base for its credit facilities and may impact the same upon revision or changes to the reserve estimates. The effect of changes in proved oil and gas reserves on the financial results and position of the company is described under the heading "Full Cost Accounting for Oil and Gas Activities". 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 oil and gas reserves. 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 production. 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. 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 these estimates are subject to measurement uncertainty and the impact on the consolidated financial statements 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 determine if such a loss can be estimated. When any such loss is determined, it is charged to earnings. Management continually monitors known and potential contingent matters and makes appropriate provisions by charges to earnings when warranted by circumstance. Income Taxes The company follows the liability method of accounting for income taxes. Under this method tax assets are recognized when it is more than likely realization will occur. Tax liabilities are recognized for temporary differences between recorded book values and underlying tax values. Rates used to determine income tax asset and liability amounts are enacted tax rates expected to be used in future periods when the timing differences reverse. The period in which a timing difference reverses are impacted by future income and capital expenditures. Rates are also affected by legislation changes. These components can impact the charge for future income taxes. 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. These estimates by their nature are subject to measurement uncertainty. NEW SIGNIFICANT ACCOUNTING POLICIES The company has assessed new and revised accounting pronouncements that have been issued but that are not yet effective and has determined that the following may have a significant impact on the company. Beginning with the year ending December 31, 2007 the company will be required to adopt, if applicable, the Canadian Institute of Chartered Accountants ("CICA") Sections 1530, 3251, 3855 and 3865 on "Comprehensive Income", "Equity", "Financial Instruments - Recognition and Measurement", and "Hedges" respectively, all of which were issued in January 2005. Under the new standards additional financial statement disclosure, namely Consolidated Statement of Other Comprehensive Income, has been introduced that will identify certain gains and losses, including the foreign currency translation adjustments and other amounts arising from changes in fair value, to be temporarily recorded outside the income statement. In addition, all financial instruments, including derivatives, are to be included in the company's Consolidated Balance Sheet and measured, in most cases, at fair values. Requirements for hedge accounting have been further clarified. Although Connacher is in the process of evaluating the impact of these standards, the company does not expect these standards to have a material impact on its Consolidated Financial Statements. Over the next five 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 Stands ("IFRS") over the next five years. The company continues to monitor and assess the impact of the convergence of Canadian GAAP with IFRS. MRC's financial results are reported in accordance with Canadian GAAP and are consolidated with Connacher's other business units. The preparation of MRC's financial results require certain estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from those estimates under different assumptions or conditions. Connacher's management considers the following new MRC accounting policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact on the company's results of operations, financial condition and cash flows. Inventory Valuation Crude oil and refined product inventories are stated at the lower of cost or net realizable value. Since acquiring the refining assets in March 2006, management re-evaluated the inventory costing method and has chosen the average cost method in order to conform to impending Canadian GAAP changes. The effect of this change was to decrease inventory by $2.5 million at December 31, 2006 (see Note 4 to the Consolidated Financial Statements). Net realizable value is determined using current estimated selling prices. Deferred Maintenance Costs MRC's refinery units 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 unit and by catalyst, but generally is every two to five years. Turnaround costs are capitalized and amortized over the period to the next scheduled turnaround or change-out. In order to minimize downtime during turnarounds, contract labor as well as maintenance personnel are utilized on a continuous 24 hour basis. Whenever possible, turnarounds are scheduled so that some units continue to operate while others are down for maintenance. The costs of turnarounds are recorded as deferred charges and are amortized over the expected periods of benefit. Employee Future Benefits As a consequence of the refinery acquisition and related employment of refinery personnel, the company's new US subsidiary, MRC, adopted new employee future benefit plans with effect from March 31, 2006. A new non-contributory defined benefit retirement plan covers only MRC's employees from March 31, 2006. MRC's policy is to make regular contributions in accordance with the funding requirements of the United States Employee Retirement Income Security Act of 1974. Benefits are to be based on the employee's years of service and compensation. MRC also established new defined contribution (US tax code "401(k)") plans that cover all of its employees from March 31, 2006. The company's contributions are based on employees' compensation and partially match employee contributions. Long-lived Refining Assets Depreciation and amortization is calculated based on estimated useful lives and salvage values. When assets are placed into service, estimates are made with respect to their useful lives that are believed to be reasonable. However, factors such as new technologies, competition, regulation or environmental matters could cause changes to estimates, thus impacting the future calculation of depreciation and amortization. Long-lived assets are also evaluated for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash 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 discontinued cash flows and fair values of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates. Goodwill Goodwill arose on the acquisition of Luke in 2006. Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is assessed for impairment annually. Goodwill and all other assets and liabilities have been allocated to 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. RISK MANAGEMENT - MRC Certain strategies could be used to reduce some commodity prices 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 would outweigh the benefit. MRC'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 supply and use of heavy crude oil from the company's Great Divide Oil Sands Project, as a feedstock for the refinery, would provide a physical hedge to this exposure, as planned. MRC's operations are subject to normal hazards of operations, including fire, explosion and weather-related perils. Various insurance coverages, including business interruption insurance, are maintained in accordance with industry practices. However, MRC is not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or, in management's judgment, premium costs are prohibitive in relation to the perceived risks. Additionally, the company has recently issued parental guarantees and indemnifications on behalf of MRC. This is considered to be in the normal course of business. The company has not entered into any off-balance sheet arrangements. BUSINESS RISKS 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 both crude oil and natural gas 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 will require a significant amount of natural gas in order to generate steam for the SAGD process used at Great Divide. 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 gas properties at Marten Creek acquired with the purchase of Luke. 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 hedge the company's exposure to foreign currency fluctuations of its US dollar denominated oil sands term loan. 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 purchase of the Montana Refinery was meant to help mitigate the risk exposure. The company relies on access to capital markets for new equity to supplement internally generated cash flow and bank borrowings to finance its growth plans. Periodically, these markets may not be receptive to offerings of new equity from treasury, 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. An increased emphasis on flow-through share financings may accelerate the pace at which junior oil and gas companies become cash-taxable, which could reduce cash flow available for capital expenditures on growth projects. Periodic fluctuations in energy prices may also affect lending policies of the company's banker, 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. Furthermore, the company generally relies on equity financing and a bias towards conservative financing of its operations under normal industry conditions to offset the inherent risks of domestic and international oil and gas exploration, development and production activities. In the past the company has entered into 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: ------------------------------------------------------------------------- Subse- Contractual obligations 2008- 2011- quent ($000) 2007 2010 2012 to 2012 Total ------------------------------------------------------------------------- Term debt and short- term loans $ 19,500 $ 2,360 $ 4,079 $205,296 $231,235 Asset retirement obligations 166 31 75 7,050 7,322 Operating leases 1,426 6,355 3,323 7,649 18,753 Employee future benefits 488 - - - 488 Other long term obligations 638 1,069 - - 1,707 ------------------------------------------------------------------------- Total $ 22,218 $ 9,815 $ 7,477 $219,995 $259,505 ------------------------------------------------------------------------- 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. 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 evaluation 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. FOURTH QUARTER During the fourth quarter of 2006, the company drew down in full the US$180 million oil sands term loan in order to secure financing for the costs of completing Pod One at the Great Divide project and to repay the bridge loan incurred to purchase the Montana refinery. Spending during the fourth quarter related to Pod One amounted to approximately $65 million. OUTLOOK The company's business plan anticipates substantial growth. Emphasis will continue to be on delineating and developing the Great Divide Oil Sands Project in Alberta while continuing to develop the company's recently-expanded conventional production base and profitably operating the Montana refinery. Additional financing may be required for the Great Divide Oil Sands Project, the company's conventional petroleum and natural gas assets and for the Montana refinery. Additional information relating to Connacher, including Connacher's Annual Information Form, has been filed on SEDAR at www.sedar.com. QUARTERLY RESULTS Fluctuations in results over the previous eight quarters are due principally to variations in oil and gas prices and the acquisitions of Luke and the Montana refinery in 2006, both of which increased revenues substantially. Additionally, operating and general and administrative costs increased due to higher staff levels necessitated by the company's growth. Depletion, depreciation and amortization increased as a result of higher production volumes and additions to capital assets. 2005 ------------------------------------------------------------------------- Three Months Ended Mar 31 Jun 30 Sept 30(3) Dec 31 ------------------------------------------------------------------------- Financial Highlights ($000 except per share amounts) - Unaudited ------------------------------------------------------------------------- Revenue net of royalties 1,488 2,107 3,222 2,978 ------------------------------------------------------------------------- Cash flow from operations before working capital changes(1) 265 877 1,978 1,238 ------------------------------------------------------------------------- Basic, per share(1) - 0.01 0.02 0.01 ------------------------------------------------------------------------- Diluted, per share(1) - 0.01 0.02 0.01 ------------------------------------------------------------------------- Net earnings (loss) 1,673 (230) (1,034) 582 ------------------------------------------------------------------------- Basic and diluted per share 0.02 - (0.01) - ------------------------------------------------------------------------- Capital expenditures 6,047 5,649 2,870 2,241 ------------------------------------------------------------------------- Proceeds on disposal of PNG properties - - - - ------------------------------------------------------------------------- Bank debt - 250 - - ------------------------------------------------------------------------- Working capital surplus (deficiency) 5,588 854 67,440 75,427 ------------------------------------------------------------------------- Cash on hand 8,286 2,629 67,708 75,511 ------------------------------------------------------------------------- Shareholders' equity 41,079 41,090 113,081 129,108 ------------------------------------------------------------------------- Operating Highlights ------------------------------------------------------------------------- Production / sales volumes ------------------------------------------------------------------------- Natural gas - mcf/d 1,328 1,416 497 86 ------------------------------------------------------------------------- Crude oil - bbl/d 629 702 808 775 ------------------------------------------------------------------------- Equivalent - boe/d(2) 850 938 891 789 ------------------------------------------------------------------------- Pricing Crude oil - $/bbl 30.02 41.23 53.40 41.54 ------------------------------------------------------------------------- Natural gas - $/mcf 1.18 0.99 1.88 7.55 ------------------------------------------------------------------------- Selected Highlights - $/boe(2) ------------------------------------------------------------------------- Weighted average sales price 24.04 32.35 49.48 41.61 ------------------------------------------------------------------------- Royalties 4.82 8.06 11.73 7.76 ------------------------------------------------------------------------- Operating costs 7.01 7.42 7.69 8.90 ------------------------------------------------------------------------- Operating netback(4) 12.21 16.87 30.06 24.95 ------------------------------------------------------------------------- Common Share Information ------------------------------------------------------------------------- Shares outstanding at end of period (000) 92,753 93,013 134,236 139,940 ------------------------------------------------------------------------- Weighted average shares outstanding for the period ------------------------------------------------------------------------- Basic (000) 91,189 92,875 103,851 136,071 ------------------------------------------------------------------------- Diluted (000) 94,197 95,555 106,397 142,507 ------------------------------------------------------------------------- Volume traded during quarter (000) 40,486 16,821 180,848 100,246 ------------------------------------------------------------------------- Common share price ($) ------------------------------------------------------------------------- High 1.22 1.05 2.69 4.20 ------------------------------------------------------------------------- Low 0.49 0.68 0.76 1.09 ------------------------------------------------------------------------- Close (end of period) 0.93 0.82 2.54 3.84 ------------------------------------------------------------------------- 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 from operations before working capital changes(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 ------------------------------------------------------------------------- Capital expenditures 300,836 34,280 41,449 74,960 ------------------------------------------------------------------------- Proceeds on disposal of PNG properties - - - 10,000 ------------------------------------------------------------------------- Bank debt 17,600 70,365 62,380 229,254 ------------------------------------------------------------------------- Working capital surplus (deficiency) (11,061) (42,483) (39,942) 118,626 ------------------------------------------------------------------------- Cash on hand - 7,505 14,450 142,391 ------------------------------------------------------------------------- Shareholders' equity 337,584 340,639 378,730 385,398 ------------------------------------------------------------------------- Operating Highlights ------------------------------------------------------------------------- Production / sales volumes ------------------------------------------------------------------------- Natural gas - mcf/d 2,600 15,172 13,028 11,291 ------------------------------------------------------------------------- Crude oil - bbl/d 689 1,026 1,084 1,139 ------------------------------------------------------------------------- Equivalent - boe/d(2) 1,122 3,554 3,256 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 - $/boe(2) ------------------------------------------------------------------------- Weighted average sales price 39.83 41.88 42.16 42.15 ------------------------------------------------------------------------- Royalties 8.02 10.43 10.72 9.00 ------------------------------------------------------------------------- Operating costs 8.24 7.63 7.99 9.27 ------------------------------------------------------------------------- Operating netback(4) 23.57 23.82 23.45 23.88 ------------------------------------------------------------------------- Common Share Information ------------------------------------------------------------------------- Shares outstanding at end of period (000) 191,257 191,924 197,878 197,894 ------------------------------------------------------------------------- Weighted average shares outstanding for the period ------------------------------------------------------------------------- Basic (000) 154,152 191,672 193,587 193,884 ------------------------------------------------------------------------- Diluted (000) 160,574 198,931 200,572 204,028 ------------------------------------------------------------------------- Volume traded during quarter (000) 148,184 80,347 48,849 46,444 ------------------------------------------------------------------------- Common share price ($) ------------------------------------------------------------------------- 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 ------------------------------------------------------------------------- (1) Cash flow from operations before working capital changes 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 from operations before working capital changes includes all cash flow from operating activities and is calculated before changes in non-cash working capital. The most comparable measure calculated in accordance with GAAP would be net earnings. Cash flow from operations before working capital changes 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) In the third quarter of 2005, the company discontinued consolidating the financial and operational results of Petrolifera Petroleum Limited. Comparative figures have not been restated. (4) Operating 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. CONSOLIDATED BALANCE SHEETS Connacher Oil and Gas Limited December 31 ------------------------------------------------------------------------- ($000) 2006 2005 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ASSETS ------------------------------------------------------------------------- CURRENT ------------------------------------------------------------------------- Cash and cash equivalents $ 19,603 $ 75,511 ------------------------------------------------------------------------- Restricted cash (Note 15(c)) 122,788 - ------------------------------------------------------------------------- Accounts receivable 30,956 1,605 ------------------------------------------------------------------------- Refinery inventories (Note 4) 24,437 - ------------------------------------------------------------------------- Due from Petrolifera (Note 5) 32 221 ------------------------------------------------------------------------- Prepaid expenses 1,525 407 ------------------------------------------------------------------------- 199,341 77,744 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Property and equipment (Note 6) 384,311 45,242 ------------------------------------------------------------------------- Goodwill (Note 3) 103,676 - ------------------------------------------------------------------------- Deferred charges (Note 7) 4,005 256 ------------------------------------------------------------------------- Investment in Petrolifera (Note 5) 21,597 10,496 ------------------------------------------------------------------------- Future income tax asset (Note 8) - 1,075 ------------------------------------------------------------------------- $ 712,930 $ 134,813 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES ------------------------------------------------------------------------- CURRENT ------------------------------------------------------------------------- Accounts payable and accrued liabilities $ 57,571 $ 2,184 ------------------------------------------------------------------------- Income taxes payable 3,644 132 ------------------------------------------------------------------------- Current portion of bank debt (Note 9) 19,500 - ------------------------------------------------------------------------- 80,715 2,316 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Asset retirement obligations (Note 10) 7,322 3,108 ------------------------------------------------------------------------- Deferred credits - 281 ------------------------------------------------------------------------- Employee future benefits (Note 11) 388 - ------------------------------------------------------------------------- Bank debt (Note 9) 209,754 - ------------------------------------------------------------------------- Future income taxes (Note 8) 29,353 - ------------------------------------------------------------------------- 327,532 5,705 ------------------------------------------------------------------------- ------------------------------------------------------------------------- SHAREHOLDERS' EQUITY ------------------------------------------------------------------------- Share capital and contributed surplus (Note 12) 376,500 127,033 ------------------------------------------------------------------------- Cumulative translation adjustment (130) - ------------------------------------------------------------------------- Retained earnings 9,028 2,075 ------------------------------------------------------------------------- 385,398 129,108 ------------------------------------------------------------------------- $ 712,930 $ 134,813 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Commitments, contingencies and guarantees (Note 16) Approved by the Board Signed Signed "D.H. Bessell", Director "C.M. Evans", Director CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS Connacher Oil and Gas Limited Years Ended December 31 ------------------------------------------------------------------------- ($000, except per share amounts) 2006 2005 ------------------------------------------------------------------------- ------------------------------------------------------------------------- REVENUE ------------------------------------------------------------------------- Petroleum and natural gas revenue, net of royalties $ 31,786 $ 9,095 ------------------------------------------------------------------------- Refining and marketing sales 211,874 - ------------------------------------------------------------------------- Interest and other income 1,024 700 ------------------------------------------------------------------------- 244,684 9,795 ------------------------------------------------------------------------- ------------------------------------------------------------------------- EXPENSES ------------------------------------------------------------------------- Petroleum and natural gas operating costs 8,270 2,445 ------------------------------------------------------------------------- Refining - crude oil purchases and operating costs 182,668 - ------------------------------------------------------------------------- General and administrative 3,886 2,660 ------------------------------------------------------------------------- Stock-based compensation (Note 12) 7,816 1,192 ------------------------------------------------------------------------- Finance charges 5,086 308 ------------------------------------------------------------------------- Foreign exchange loss (gain) 4,287 (30) ------------------------------------------------------------------------- Depletion, depreciation and accretion 32,949 5,797 ------------------------------------------------------------------------- 244,962 12,372 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Loss before income taxes and other items (278) (2,577) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Current income tax provision (Note 8) 7,405 102 ------------------------------------------------------------------------- Future income tax provision (recovery) (3,535) 768 ------------------------------------------------------------------------- 3,870 870 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Loss before other items (4,148) (3,447) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Equity interest in Petrolifera earnings (loss) (Note 5) 11,078 (27) ------------------------------------------------------------------------- Dilution gain(Note 5) 23 4,465 ------------------------------------------------------------------------- ------------------------------------------------------------------------- NET EARNINGS 6,953 991 ------------------------------------------------------------------------- ------------------------------------------------------------------------- RETAINED EARNINGS, BEGINNING OF YEAR 2,075 1,084 ------------------------------------------------------------------------- ------------------------------------------------------------------------- RETAINED EARNINGS, END OF YEAR $ 9,028 $ 2,075 ------------------------------------------------------------------------- ------------------------------------------------------------------------- EARNINGS PER SHARE (Note 15(a)) ------------------------------------------------------------------------- Basic and diluted $ 0.04 $ 0.01 ------------------------------------------------------------------------- CONSOLIDATED STATEMENTS OF CASH FLOW Connacher Oil and Gas Limited Years Ended December 31 ($000) 2006 2005 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Cash provided by (used in) the following activities: ------------------------------------------------------------------------- OPERATING ------------------------------------------------------------------------- Net earnings $ 6,953 $ 991 ------------------------------------------------------------------------- Items not involving cash: ------------------------------------------------------------------------- Depletion, depreciation and accretion 32,949 5,797 ------------------------------------------------------------------------- Stock-based compensation (Note 12) 8,293 1,192 ------------------------------------------------------------------------- Financing charges 2,237 150 ------------------------------------------------------------------------- Employee future benefits 381 - ------------------------------------------------------------------------- Future income tax provision (recovery) (3,535) 768 ------------------------------------------------------------------------- Foreign exchange loss (gain) 4,287 (30) ------------------------------------------------------------------------- Dilution gain (23) (4,465) ------------------------------------------------------------------------- Lease inducement amortization (268) (72) ------------------------------------------------------------------------- Equity interest in Petrolifera (earnings) loss (11,078) 27 ------------------------------------------------------------------------- Cash flow from operations before working capital changes 40,196 4,358 ------------------------------------------------------------------------- Changes in non-cash working capital(Note 15(b)) (9,271) (485) ------------------------------------------------------------------------- 30,925 3,873 ------------------------------------------------------------------------- FINANCING ------------------------------------------------------------------------- Issue of common shares, net of share issue costs 123,188 86,512 ------------------------------------------------------------------------- Increase in bank debt 280,078 - ------------------------------------------------------------------------- Repayment of bank debt (57,707) - ------------------------------------------------------------------------- Issue of shares by Petrolifera, net of share issue costs - 6,228 ------------------------------------------------------------------------- Deferred financing costs - (258) ------------------------------------------------------------------------- 345,559 92,482 ------------------------------------------------------------------------- INVESTING ------------------------------------------------------------------------- Acquisition and development of oil and gas properties (175,033) (16,807) ------------------------------------------------------------------------- Proceeds on disposal of oil and gas properties 10,000 - ------------------------------------------------------------------------- Increase in restricted cash (Note 15(c)) (122,788) - ------------------------------------------------------------------------- Acquisition of Luke Energy Ltd. (Note 3) (92,692) - ------------------------------------------------------------------------- Acquisition of refining assets (Note 3) (61,273) - ------------------------------------------------------------------------- Acquisition of other assets (5,185) - ------------------------------------------------------------------------- Purchase of Petrolifera shares (Note 5) - (6,000) ------------------------------------------------------------------------- Collection of Petrolifera note (Note 5) - 750 ------------------------------------------------------------------------- Change in non-cash working capital (Note 15(b)) 14,122 396 ------------------------------------------------------------------------- (432,849) (21,661) ------------------------------------------------------------------------- ------------------------------------------------------------------------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (56,365) 74,694 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Impact on cash resulting from de-consolidation of Petrolifera (Note 5) - (3,097) ------------------------------------------------------------------------- Impact of foreign exchange on foreign currency denominated cash balances 457 - ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR 75,511 3,914 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS, END OF YEAR $ 19,603 $ 75,511 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- Supplementary information - Note 15 ------------------------------------------------------------------------- NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS Connacher Oil and Gas Limited Years Ended December 31, 2006 and 2005 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. Operating in Canada, and in the U.S. through its subsidiary Montana Refining Company, Inc. ("MRC"), the company is in the business of exploring, developing, producing, refining and marketing conventional petroleum and natural gas and has recently commenced exploration and development of bitumen in the oil sands of northern Alberta. Prior to the de-consolidation of Petrolifera in 2005 (Note 5) it also conducted a conventional petroleum and natural gas business in Argentina. 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. Subsequent to the acquisition of the refining assets, the company has adopted the average cost method; net realizable value is determined using current estimated selling prices. Deferred charges Costs incurred in respect of transactions not completed have been temporarily capitalized and will be recognized on completion of the transactions. Petroleum and natural gas operations The company follows the full cost method of accounting whereby all costs relating to the exploration for and development of crude oil and natural gas 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 crude oil and natural gas 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 lower of 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 lower of 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 production. 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. To date, all costs, including financing costs, incurred in relation to the 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 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 and depleted using the unit-of-production method. 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. 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. Refining Assets Depreciation and amortization is calculated based on estimated useful lives and salvage values. When assets are placed into service, estimates are made with respect to their useful lives that are believed to be reasonable. However, factors such as 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 discontinued cash flows and fair values of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates. Deferred Maintenance Costs 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 are recorded as deferred charges and are amortized over the period to the next scheduled turnaround or change-out. 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 and losses. 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 oil and natural gas 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 oil and natural gas 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 oil and 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. 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 MRC 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 currency translation adjustment in shareholders' equity. Financial instruments Financial instruments include cash and cash equivalents, accounts receivable, amounts due from/to Petrolifera, bank debt and accounts payable. All carrying values of financial instruments approximate fair value unless otherwise noted. The fair value of interest rate swaps and all payments received or made under interest rate swaps are recorded as part of financing costs. Joint venture operations A part of the company's activities are conducted with others, and these consolidated financial statements reflect only the company's proportionate interest in such activities. Revenue recognition Petroleum and natural gas sales and refined product sales are recognized as revenue at the time the respective commodities are delivered to purchasers. 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 in the earnings of Petrolifera, financing 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. Argentina Oil and Gas includes the exploration, development, production and sales of conventional crude oil and natural gas in Argentina, through the company's investment in Petrolifera during the time its results were consolidated. 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 whose 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 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 book amounts. Measurement uncertainty The timely preparation of the consolidated financial statements in conformity with Canadian generally accepted accounting principles 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, plant 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 natural gas and crude oil 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 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 fixed price crude oil sales contracts for the physical delivery of its crude oil 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, 2006 there were no such contracts in place. Additionally, the company is exposed to interest rate risk as a portion of the company's bank debt is subject to floating interest rates. 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. 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 the 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 10) (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 the consolidated financial statements from that date. Net assets 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 12) 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 liabilities arising over the next five years for environmental matters existing at the purchase date. As a means to facilitate the expeditious transition of the ongoing refinery business, MRC assumed all of the ongoing purchase and sales contracts with suppliers and customers of the refinery. These contracts are all short-term in nature and necessitated some guarantees from Connacher, all considered to be in the normal course of business. 4. REFINERY INVENTORIES Inventories at December 31 consist of the following: ($000) 2006 2005 ------------------------------------------------------------------------- Crude oil $ 3,520 $ - Other raw materials and unfinished products(1) 1,292 - Refined products(2) 17,440 - Process chemicals(3) 909 - Repairs and maintenance supplies and other 1,276 - ------------------------------------------------------------------------- $ 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. Subsequent to the acquisition of the refinery, management changed the method of inventory cost determination from the last in, first out (LIFO) method to the average cost method. Had the LIFO method been used throughout 2006, inventory at December 31, 2006 would have been increased by $2.5 million, refinery cost of sales would have been decreased by $2.4 million and net income would have been increased by $1.5 million. 5. INVESTMENT IN PETROLIFERA PETROLEUM LIMITED ("PETROLIFERA") In the third quarter of 2005 the company discontinued consolidating the financial results of Petrolifera, as the company was no longer considered to control Petrolifera due to the election of independent directors and the reduction in its ownership percentage below 50%. The investment in Petrolifera has since been accounted for following the equity basis of accounting. The impact of not consolidating Petrolifera had the effect of reducing the company's net assets by $4.1 million as follows: ($000) ------------------------------------------------------------------------- Cash $ (3,097) ------------------------------------------------------------------------- Other current assets (321) Future income tax asset (985) Property and equipment (4,110) Current liabilities 381 Asset retirement obligations 442 Non-controlling interests 3,564 ------------------------------------------------------------------------- Changes in net assets $ (4,126) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Connacher's investment in Petrolifera at the time of de-consolidation $ 4,126 Increases (decreases) in investment: Equity interest in Petrolifera's loss from the time of deconsolidating to December 31, 2005 (27) Collection of Promissory Note and reclassification of amounts due from Petrolifera (1,047) Purchase of shares in Petrolifera 6,000 Dilution gain on shares issued by Petrolifera to unrelated parties after de-consolidation 1,444 ------------------------------------------------------------------------- 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 ------------------------------------------------------------------------- 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 a further dilution gain of $1.5 million was then recognized. In consideration for the assistance provided 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 in 2005, 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. 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 expires in May 2007, Connacher provides all management, operational, accounting and general and administrative services necessary or appropriate to manage and operate Petrolifera. The fee for this service $15,000 per month. At December 31, 2006, Connacher was owed $32,000 for these services, and for other amounts advanced and other amounts paid on Petrolifera's behalf (2005 - $221,000). 6. PROPERTY AND EQUIPMENT ------------------------------------------------------------------------- Accumulated Depletion, Depreciation and Net ($000) Cost Amortization Book Value ------------------------------------------------------------------------- 2006 Petroleum 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 ------------------------------------------------------------------------- 2005 Petroleum and natural gas properties and equipment $ 60,291 $ 15,680 $ 44,611 Furniture, equipment and leaseholds 1,058 427 631 ------------------------------------------------------------------------- $ 61,349 $ 16,107 $ 45,242 ------------------------------------------------------------------------- In 2006, the company capitalized $4.5 million (2005 - $615,000) of general and administrative expenses, including stock-based compensation of $3.5 million (2005 - $410,000), related to conventional petroleum and natural gas activities and oil sands activities and $7.9 million (2005 - $nil) of interest and financing costs related to major development projects. Depletion, depreciation and accretion expense includes a charge of $348,000 (2005 - $165,000) to accrete the company's estimated asset retirement obligations (Note 10). The ceiling test as at December 31, 2006 excludes $16.2 million (2005 - $2.5 million) of undeveloped land and $156.7 million (2005 - $11.2 million) of major development projects, principally related to oil sands assets in the pre-production stage, which have been separately evaluated by management for impairment. Based on the ceiling test and other assessments, no impairment has been recorded at December 31, 2006. Connacher's oil and natural gas reserves were evaluated by qualified independent evaluators as at December 31, 2006 in a report dated March 9, 2007. The evaluation was conducted in accordance with the Canadian Securities Administrators' National Instrument 51-101, using the following base price assumptions adjusted for the company's product quality and transportation differentials: ------------------------------------------------------------------------- Bitumen Wellhead WTI @ Alberta Current Cushing Spot (CDN$/bbl) ($US/bbl) (CDN$/mcf) ------------------------------------------------------------------------- 2007 31.50 62.00 7.25 2008 32.75 60.00 7.50 2009 33.50 58.00 7.50 2010 33.37 57.00 7.50 2011 34.50 57.00 7.50 ------------------------------------------------------------------------- + approximately 2% after 2012 + approximately 2% thereafter ------------------------------------------------------------------------- 7. DEFERRED CHARGES The balance of $4 million as at December 31, 2006 represents deferred maintenance costs. Deferred charges of $256,000 at December 31, 2005 relate to costs incurred in respect of transactions incomplete at that date and which were subsequently capitalized to property, plant and equipment. 8. INCOME TAXES The following table reconciles income taxes calculated at the Canadian statutory rate with recorded income taxes: ------------------------------------------------------------------------- Years Ended December 31 ($000) 2006 2005 ------------------------------------------------------------------------- Earnings before income taxes $ 10,823 $ 1,861 Canadian statutory rate 35.4% 39.0% Expected income taxes (recovery) 3,831 726 Non-deductible Canadian crown payments 1,729 555 Canadian resource allowance (945) (371) Impact of reduction in Canadian tax rates and other (3,955) 245 Foreign taxes (recovery) 973 (17) Capital taxes 502 119 Non taxable portion of capital gains 762 - Equity income and dilution gain (1,962) (852) Non deductible stock-based compensation 2,935 465 ------------------------------------------------------------------------- Provision for taxes $ 3,870 $ 870 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The company had the following future tax assets (liabilities) relating to temporary timing differences: ------------------------------------------------------------------------- As at December 31 ($000) 2006 2005 ------------------------------------------------------------------------- Book value in excess of tax basis of property, plant and equipment $ (37,628) $ (2,370) Non-capital losses carried forward 7,754 1,075 Foreign exchange gain on debt 882 - Partnership deferral (5,930) - ------------------------------------------------------------------------- Investment in Petrolifera (1,980) - ------------------------------------------------------------------------- Deferred maintenance costs (1,547) - ------------------------------------------------------------------------- Share issue costs 6,463 2,370 ------------------------------------------------------------------------- Asset retirement obligation 2,158 - ------------------------------------------------------------------------- Other 475 - ------------------------------------------------------------------------- Net future income tax asset (liability) $ (29,353) $ 1,075 ------------------------------------------------------------------------- ------------------------------------------------------------------------- At December 31, 2006 the company had approximately $25.8 million of non- capital losses which expire at various periods to 2026, $253.5 million of deductible resource pools and $20.7 million of deductible financing costs. 9. BANK DEBT The company had the following loans outstanding, as at December 31: ($000) 2006 2005 ------------------------------------------------------------------------- Conventional line of credit $ 19,500 $ - Refinery line of credit - - Oil sands term loan 209,754 - ------------------------------------------------------------------------- Total 229,254 - Less current portion 19,500 - ------------------------------------------------------------------------- Long-term portion $ 209,754 $ - ------------------------------------------------------------------------- ------------------------------------------------------------------------- At December 31, 2006, the company had available a $55 million Extendible Revolving Loan Facility (the "Conventional line of credit"). Borrowings are available in the form of prime loans, bankers' acceptances, US dollar base rate loans, LIBOR loans and letters of credit. As at December 31, 2006, $19.5 million in bankers' acceptances were outstanding at a rate of 5.62 percent and $168 thousand in letters of credit were issued. The facility's borrowing base is redetermined semi-annually based on the lending value of the company's conventional crude oil and natural gas reserves, as determined by the company's lenders in accordance with customary practice. The facility matures on April 15, 2007 and is extendible upon request by the company and at the lender's option for 364 days. The Conventional line of credit is secured by a $50 million fixed and floating charge debenture and a general assignment of book debts over the company's conventional crude oil and natural gas reserves and assets, and is non-recourse to the company's Great Divide oil sands, its refining assets and its investment in Petrolifera. At December 31, 2006 the company also had available a US$15 million revolving line of credit (the "Refinery line of credit") to fund the working capital requirements of the refinery in Great Falls, Montana. Borrowings are available under this facility in the form of US dollar base rate loans, US Eurodollar rate loans and letters of credit. As at December 31, 2006 no amounts were drawn on this facility other than US$1.7 million of letters of credit. This facility matures October 20, 2011 and is secured by debenture and mortgage agreements covering all of the assets of the refinery and all of the company's interest in its Great Divide oil sands assets but is non-recourse to the company's conventional petroleum and natural gas assets and investment in Petrolifera. In October 2006, the company secured a US$180 million, seven-year term loan (the "Oil sands term loan"). The full amount of the loan was drawn to fund US$51 million of the acquisition cost of the Montana refinery, to fund a US $14 million debt-service reserve account and to fund all of the remaining budgeted costs to complete the development of Pod One, the company's first oil sands project at Great Divide in northern Alberta. The loan is a floating rate facility, bearing interest either at a US dollar base rate plus a margin or a US Eurodollar rate plus a margin. The loan's Eurodollar interest rate as at December 31, 2006 was 8.61 percent. In October 2006 the company entered into an interest rate swap with a financial institution whereby the floating rate on US$90 million of the loan was fixed at an all-in rate of 8.516 percent over the term of the loan. All interest on this loan is being capitalized until Pod One becomes operational. One percent of the principal is required to be repaid annually, commencing in the fourth quarter of 2008. The oil sands term loan is secured by debenture and mortgage agreements covering all of the assets of the refinery and all of the company's interest in its Great Divide oil sands assets, but is non-recourse to the company's conventional petroleum and natural gas assets and to its investment in Petrolifera. As indicated above, at December 31, 2006, the company had in place an interest rate swap to convert the effective rate on one-half of the oil sands term loan to an all-in fixed interest rate of 8.516 percent. The fair value of this interest rate swap at December 31, 2006 was a liability of $1.4 million. Principal repayments under the aforementioned loans are due as follows: ($000) ------------------------------------------------------------------------- 2007 $ 19,500 2008 524 2009 2,098 2010 2,098 2011 2,098 Thereafter 202,936 ------------------------------------------------------------------------- $ 229,254 ------------------------------------------------------------------------- 10. 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 conventional petroleum and natural gas properties and facilities and its oil sands properties and facilities. ------------------------------------------------------------------------- Year ended December 31 ($000) 2006 2005 ------------------------------------------------------------------------- Asset retirement obligations, beginning of year $ 3,108 $ 2,905 Liabilities incurred 2,384 301 Liabilities acquired(Note 3(a)) 2,109 - Liabilities settled with Petrolifera deconsolidation - (442) Liabilities disposed (864) (24) Change in estimated future cash flows 237 203 Accretion expense 348 165 ------------------------------------------------------------------------- Asset retirement obligations, end of year $ 7,322 $ 3,108 ------------------------------------------------------------------------- At December 31, 2006 the estimated total undiscounted amount required to settle the asset retirement obligations was $17.4 million (2005 - $5.4 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 and 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 intent to maintain and upgrade the refinery so that it will be operational for the foreseeable future. Consequently, it is not possible at the present time to estimate a date or range of dates for settlement of any asset retirement obligation related to the refinery. 11. EMPLOYEE FUTURE BENEFITS During 2006, the company established the following retirement/savings plans for its employees: a defined benefit pension plan and a defined contribution savings plan for its new US-based employees and a defined contribution savings plan for its Canadian employees. (a) The defined benefit pension plan As a consequence of the refinery acquisition and related employment of refinery personnel, the company's new US subsidiary, Montana Refining Company, Inc. ("MRC"), adopted a new non-contributory defined benefit retirement plan (the "Plan") covering MRC's employees on March 31, 2006. MRC's policy is to make regular contributions in accordance with the funding requirements of the United States Employee Retirement Income Security Act of 1974 as determined by regular actuarial valuations. The company's pension obligation is based on the employees' years of service and compensation, effective from, and after, March 31, 2006. MRC is responsible for administering the plan. MRC 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 the December 31, 2006 actuarial valuation are as follows: Pension benefits ($000) ------------------------------------------------------------------------- Components of net benefits cost Current service cost $ 365 Interest cost 16 ------------------------------------------------------------------------- Net benefit cost $ 381 ------------------------------------------------------------------------- Change in benefit obligation: Benefit obligation at acquisition of refinery $ - Current service cost 365 Interest cost 16 Foreign currency translation 7 ------------------------------------------------------------------------- Benefit obligation at December 31, 2006 $ 388 ------------------------------------------------------------------------- Amount recognized in the consolidated balance sheet consists of: ------------------------------------------------------------------------- Accrued benefits $ (388) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Assumptions used to determine benefit obligations at December 31, 2006 ------------------------------------------------------------------------- Discount rate 5.75% Long-term rate of compensation increase 3.00% ------------------------------------------------------------------------- (b) The MRC defined contribution savings plan for United States employees MRC also established new defined contribution (US tax code "401(k)"), savings plans that cover all of its employees from March 31, 2006. MRC's contributions are based on employees' compensation and partially match employee contributions. In 2006, MRC contributed $201,000 to this plan. (c) The defined contribution savings plan for Canadian employees In 2006, the company established a new defined contribution savings plans for its Canadian employees, whereby the company matches employee contributions to a maximum of eight percent of each employee's salary. In 2006, the company contributed $121,500 to this plan. 12. SHARE CAPITAL AND CONTRIBUTED SURPLUS 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 Amount of Shares ($000) ------------------------------------------------------------------------- Balance, December 31, 2004 89,626,743 $ 38,756 Issued for cash in public offerings (a) 45,541,000 90,001 Issued upon exercise of stock options (d) 981,000 666 Issued upon exercise of warrants (e) 3,791,705 1,986 Share issue costs (5,980) Tax effect of share issue costs 2,339 Tax effect of expenditures renounced pursuant to the issuance of flow through common shares (f) (2,697) ------------------------------------------------------------------------- Balance, December 31, 2005 139,940,448 125,071 Issued for cash in private placement (b) 19,047,800 100,001 Issued for cash in public offerings (c) 5,714,300 30,000 Issued for Luke acquisition (Note 3) 29,699,282 111,966 Issued for refinery acquisition (Note 3) 1,000,000 5,060 Issued upon exercise of options (d) 998,365 1,017 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 (g) (5,448) ------------------------------------------------------------------------- Balance, December 31, 2006 197,894,015 $ 363,082 ------------------------------------------------------------------------- Contributed Surplus: ------------------------------------------------------------------------- Balance, December 31, 2004 $ 535 Fair value of share options granted in 2005 (d) 1,588 Assigned value of options exercised in 2005 (161) ------------------------------------------------------------------------- Balance, December 31, 2005 1,962 Fair value of options granted in 2006 (d) 11,777 Assigned value of options exercised in 2006 (321) ------------------------------------------------------------------------- Balance Contributed Surplus, December 31, 2006 $ 13,418 ------------------------------------------------------------------------- Total Share Capital and Contributed Surplus: December 31, 2005 $ 127,033 December 31, 2006 $ 376,500 ------------------------------------------------------------------------- (a) Public Offerings - 2005 In September 2005 the company issued from treasury 40,541,000 common shares at $1.85 per share. In December 2005 the company issued from treasury another five million common shares on a flow-through basis at $3.00 per share, renouncing resource expenditures of $15 million effective December 31, 2005. (b) 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. (c) 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. The company agreed to renounce the related resources expenditures of $30 million to the flow through investors effective December 31, 2006. The company has until December 31, 2007 to incur the eligible resource expenditures. As at December 31, 2006 $6.5 million of these expenditures have been incurred. (d) Stock Options A summary of the company's outstanding stock options, as at December 31, 2006 and 2005 and changes during those years is presented below: ------------------------------------------------------------------------- 2006 2005 ------------------------------------------------------------------------- Weighted Weighted Average Average Number of Exercise Number of Exercise Shares Price Shares Price ------------------------------------------------------------------------- Outstanding, beginning of year 8,592,600 $ 1.49 3,988,600 $ 0.53 Granted 8,739,255 $ 4.81 5,994,000 $ 1.94 Exercised (998,365) $ 0.70 (981,000) $ 0.51 Expired (121,000) $ 3.68 (409,000) $ 1.05 ------------------------------------------------------------------------- Outstanding, end of year 16,212,490 $ 3.31 8,592,600 $ 1.49 ------------------------------------------------------------------------- Exercisable, end of year 6,563,864 $ 2.14 3,159,869 $ 1.03 ------------------------------------------------------------------------- All stock options have been granted for a period of five years. Options granted under the plan are generally fully exercisable after three years and expire five years after the date granted. The table below summarizes unexercised stock options. ------------------------------------------------------------------------- Weighted Weighted Average Weighted Average Weighted Remaining Range of Number Average Remaining Number Average Contrac- Exercise Out- Exercise Contractual Out- Exercise tual Prices standing Price Life standing Price Life ------------------------------------------------------------------------- At December 31 2006 2005 ------------------------------------------------------------------------- $0.20 - $0.99 3,137,235 $ 0.69 1.7 4,276,600 $ 0.67 3.2 $1.00 - $1.99 1,996,000 $ 1.61 2.4 1,886,000 $ 1.61 5.0 $2.00 - $3.99 3,679,000 $ 3.18 3.1 2,430,000 $ 2.84 4.9 $4.00 - $5.99 7,400,255 $ 4.99 3.3 - $ - - ------------------------------------------------------------------------- 16,212,490 $ 3.31 8,592,600 $ 1.49 ------------------------------------------------------------------------- In 2006 a compensatory non-cash expense of $8.3 million (2005 - $1.2 million) was recorded, reflecting the fair value of stock options amortized over the vesting period. Of this amount, $7.8 million (2005 - $1.2 million) was expensed as G&A and $0.5 million was charged to refining operating costs. A further $3.5 million (2005 - $0.4 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: ------------------------------------------------------------------------- 2006 2005 ------------------------------------------------------------------------- Risk free interest rate 4.1% 3.0% Expected option life (years) 3 3 Expected volatility 50% 50% ------------------------------------------------------------------------- The weighted average fair value at the date of grant of all options granted in 2006 was $1.81 per option (2005 - $0.65). (e) Share purchase warrants A summary of the company's outstanding share purchase warrants, as at December 31, 2006 and 2005 and changes during the years is presented below: ------------------------------------------------------------------------- 2006 2005 ------------------------------------------------------------------------- Outstanding, beginning of year 1,493,820 5,300,525 Exercised (1,493,820) (3,791,705) Expired - (15,000) ------------------------------------------------------------------------- Outstanding, end of year - 1,493,820 ------------------------------------------------------------------------- (f) Flow-through shares (2004) The company renounced $7 million of resource expenditures to flow-through share investors effective December 31, 2004. The related tax effect of those expenditures has been recorded in 2005 in the amount of $2.7 million and the company incurred the expenditures in 2005 as required. (g) Flow-through shares (2005) Effective December 31, 2005, the company renounced $15 million of resource expenditures to flow-through investors. The related tax effect of $5,448,000 on those expenditures was recorded in 2006. The company incurred all of the required expenditures related to these flow-through shares in 2006. 13. RELATED PARTY TRANSACTIONS In 2006 the company paid professional legal fees of $1.8 million (2005 - $539,000) to a law firm in which officers or directors 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. 14. SEGMENTED INFORMATION In Canada, the company is in the business of exploring and producing conventional petroleum and natural gas and has recently commenced exploration and development 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. Prior to the de-consolidation of Petrolifera in 2005 (Note 5) it also conducted a conventional petroleum and natural gas business in Argentina. 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 Canada Argentina December 31 Canada Oil Adminis- USA Oil ($000) and Gas trative Refining and Gas Total ------------------------------------------------------------------------- 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 22,795 107,548 262 712,930 ------------------------------------------------------------------------- 2005 (1) Revenues, net of royalties $ 8,202 $ - $ - $ 893 $ 9,095 Equity interest in Petrolifera loss - (27) - - (27) Interest and other income 678 - - 22 700 Operating costs 2,126 - - 319 2,445 General and administrative - 2,348 - 312 2,660 Stock-based compensation - 1,178 - 14 1,192 Finance charges 261 - - 47 308 Foreign exchange loss (gain) 5 - - (35) (30) Depletion, depreciation and accretion 5,304 - - 493 5,797 Taxes (recovery) 893 - - (23) 870 Net earnings (loss) (3,262) 4,465 - (212) 991 Property and equipment, net 44,611 631 - - 45,242 Capital expenditures 14,771 269 - 1,767 16,807 Total assets 134,182 631 - - 134,813 ------------------------------------------------------------------------- (1) 2005 comparative figures have been restated to conform to the current year's presentation. 15. SUPPLEMENTARY INFORMATION (a) Per share amounts The following table summarizes the common shares used in per share calculations. ------------------------------------------------------------------------- For the years ended December 31 2006 2005 ------------------------------------------------------------------------- Weighed average common shares outstanding 184,468,631 106,113,563 Dilutive effect of stock options and stock purchase warrants 3,963,178 5,732,124 ------------------------------------------------------------------------- Weighed average common shares outstanding - diluted 188,431,809 111,845,687 ------------------------------------------------------------------------- (b) Net change in non-cash working capital ------------------------------------------------------------------------- For the years ended December 31 ($000) 2006 2005 ------------------------------------------------------------------------- Accounts receivable $ (25,284) $ (277) Refinery inventories (4,441) - Due from Petrolifera 189 61 Prepaid expenses (692) (124) Accounts payable and accrued liabilities 31,567 251 Income taxes payable 3,512 - ------------------------------------------------------------------------- Total $ 4,851 $ (89) ------------------------------------------------------------------------- Summary of working capital changes: ------------------------------------------------------------------------- ($000) 2006 2005 ------------------------------------------------------------------------- Operations $ (9,271) $ (485) Investing 14,122 396 ------------------------------------------------------------------------- $ 4,851 $ (89) ------------------------------------------------------------------------- (c) Supplementary cash flow information ------------------------------------------------------------------------- For the years ended December 31 2006 2005 ------------------------------------------------------------------------- ($000) ------------------------------------------------------------------------- Interest paid $ 6,578 $ 67 Income taxes paid 3,655 3 Stock-based compensation capitalized 3,485 410 ------------------------------------------------------------------------- At December 31, 2006 cash of $122.8 million is restricted for use in paying expenditures for a designated oil sands project under the terms of the Oil sands term loan (Note 9). 16. 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: 2007 - $1.7 million; 2008 - $2.6 million; 2009 - $2.6 million; 2010 - $2.2 million; 2011 - $1.6 million; total thereafter $9.3 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.

For further information:

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


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