Connacher reports record cash flow and earnings for second quarter and first half 2007



    CALGARY, Aug. 10 /CNW/ - Connacher Oil and Gas Limited (TSX - CLL) had a
wonderful second quarter of 2007. It was highlighted by the completion of our
updated reserve report which showed significant expansion of our bitumen and
conventional reserve base; filing of the application for development of our
Pod Two or "Algar" Project east of Great Divide Pod One (the company's second
10,000 bbl/d oil sands development project); the near completion of our plant
and facilities at Pod One, which completion will be celebrated on August 10,
2007; successful raising of $100 million of new capital through the sale of
low coupon senior unsecured subordinated convertible debentures; and strong
second quarter and first half 2007 financial and operating results resulting
in record cash flow and earnings.

    
    HIGHLIGHTS

    -   Bitumen reserves grew dramatically - 2P ("proved and probable")
        reserves more than doubled to 178 million barrels and 3P ("proved,
        probable and possible") reserves increased 120 percent to 242 million
        barrels
    -   2P Reserves and Best Estimate Total Resources of bitumen rose
        60 percent to 417 million barrels; 3P Reserves and High Estimate
        Total Resources reached 798 million barrels
    -   2P conventional reserves rose 14 percent, including a 27 percent
        increase in 2P natural gas reserves due to successful winter 2007
        drilling
    -   10 percent present value of future net revenues for 2P Reserves and
        Best Estimate Total Resources approximately $1.2 billion; 3P Reserves
        and High Estimate Total Resources exceeds $1.8 billion
    -   Pod One construction nearing completion; commissioning ceremony
        August 10, 2007 within 300 day construction timetable
    -   Pod Two ("Algar") application for a second 10,000 bbl/d plant
        submitted to Alberta Energy and Utilities Board ("EUB") and other
        regulators
    -   Record cash flow from operations and earnings for second quarter and
        first half 2007
    -   First half earnings reached $27.2 million ($0.14 per share), compared
        to a loss in 2006
    -   Capital expenditures approximated $93 million in the second quarter
        and $203 million for the year-to-date 2007

    SUMMARY RESULTS
    -------------------------------------------------------------------------
                        Three months ended June 30  Six months ended June 30
    -------------------------------------------------------------------------
                          2007     2006  % Change    2007     2006  % Change
    -------------------------------------------------------------------------
    FINANCIAL ($000 except
     per share amounts)

    Revenues, net
     of royalties        93,266   61,239       52  159,189   64,874      145
    Cash flow from
     operations(1)       16,876    9,499       78   27,857   11,224      148
      Per share,
       basic(1)            0.09     0.05       80     0.14     0.07      100
      Per share,
       diluted(1)          0.08     0.05       60     0.14     0.06      133
    Net earnings (loss)
     for the period      22,228   (2,419)   1,019   27,212   (3,085)     982
      Per share, basic     0.11    (0.01)   1,200     0.14    (0.02)     800
    Per share, diluted     0.11    (0.01)   1,200     0.14    (0.02)     800
    Capital expenditures
     and acquisitions    93,223   34,280      172  203,104  335,116      (39)
    Cash on hand                                    25,375    7,505      238
    Working capital
     (deficit)                                      36,320  (42,483)     185
    Long term debt                                 272,559        -        -
    Shareholders' equity                           417,793  340,639       23
    Total assets                                   821,927  492,859       67

    OPERATING
    Daily production
     /sales volumes
      Crude oil - bbl/d     731    1,026      (29)     817      858       (5)
      Natural gas - mcf/d 9,017   15,172      (41)   9,340    8,921        5
      Barrels of oil
       equivalent
       - boe/d(2)         2,234    3,554      (37)   2,374    2,345        1
    Product pricing
      Oil - $/bbl         49.79    61.45      (19)   49.42    53.26       (7)
      Natural gas - $/mcf  7.02     5.66       24     7.40     5.76       28
      Barrels of oil
       equivalent
       - $/boe(2)         44.63    41.88        7    46.13    41.39       11

    Common shares
     outstanding (000)
    Weighted average
      Basic             198,360  191,672        3  198,240  173,015       15
      Diluted           209,088  198,931        5  204,762  180,416       14
    End of period
      Issued                                       198,834  191,924        4
      Fully diluted                                236,811  207,551       14
    -------------------------------------------------------------------------
    (1) Cash flow from operations before working capital changes ("cash flow
        from operations") 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 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 is reconciled with net earnings on the Consolidated
        Statements 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:1 bbl. 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.
    

    Connacher Oil and Gas had a wonderful second quarter and first half of
2007. The events of the quarter were dominated by continued excellent progress
in our construction of facilities at Great Divide Pod One, within timetable
and close to budget. Our accomplishments in this regard, especially for a
smaller company, are considerable.
    While we did experience modest cost overruns, they were both manageable
and comprehensible against the backdrop of incredible inflationary pressure in
this space. We will have completed the plant and facility and site
construction within our allotted 300 days, an achievement of which we can be
justifiably proud, especially with the pressures of competition, weather in
that we built through a fairly cold winter and the original delays and site
construction challenges we faced.
    Also, our extensive and successful 81 well core hole drilling program
this past winter on our main lease block at Great Divide resulted in a marked
expansion of our reserve and resource base and supported our application to
proceed with a second oil sands plant to also produce 10,000 bbl/d of bitumen
at Algar. The proposed plant site is approximately five miles east of the Pod
One plant, across Highway 63. Assuming an approximate 12 month review period
by the regulators and for consultation with interested stakeholders, Connacher
hopes to be able to proceed with building its second plant sometime during the
first half of 2008 with a view to completion by early 2009.
    The company is also optimistic about its ability to further identify and
upgrade other accumulations on its 100 percent-owned acreage in the Divide
region to commercial status and in the fullness of time, over the next seven
years or so, would anticipate moving towards overall production in excess of
50,000 bbl/d in the region. This outlook is buoyed by the continuing
identification of many new leads and prospects on our main lease block arising
from the winter 2007 3D seismic program. Connacher will continue its cycle of
shooting extensive 3D seismic over its undrilled or unevaluated acreage,
followed by an active core hole program and then, with these results in hand,
continued reserve and resource expansion on a consistent and regular basis.
Already we are anticipating a 120-130 well core hole drilling program in the
winter of 2008, primarily on our main lease block. New seismic in 2008 will
focus on our unevaluated lands to set up drilling the following winter.
    Unlike many other companies who are drilling core holes in a more
"exploratory" manner, in order to establish broad based resource estimates for
prospective company sales, Connacher uses core hole drilling for defining
exploitable reserves which can be booked and converted to production in an
expeditious manner. We have moved from initial ownership to production in the
shortest timeframe of any other producer in the oil sands. Our compact and
coordinated approach will serve us well going forward as we become a more
meaningful production company.
    Connacher's reserve and resource base expanded dramatically compared to
year end 2006. On July 10, 2007 we issued a press release detailing the
results of an updated independent reserve report ("June 2007 Report"),
prepared by GLJ Petroleum Consultants ("GLJ"), of Calgary, Alberta. The June
2007 Report had an effective date of June 30, 2007 and detailed estimates of
the company's bitumen and conventional reserves and resources for 1P, 2P and
3P reserves and contingent and prospective resources for bitumen and 1P and 2P
reserves for conventional resources. The company's reserve and resource base
showed considerable expansion, as did the GLJ estimates of future net revenue
and the present value thereof, calculated after deduction of estimated capital
expenditures, royalties and operating costs but before corporate general and
administrative expenses ("G&A"), finance charges and income tax. This expanded
reserve and resource base and the value of Connacher's future net revenue
provides a solid underpinning for the company's net asset value and
creditworthiness, which was reaffirmed by an improvement in the ratings
assigned by Standard and Poor's to the company's outstanding debt instruments.
    Other developments of consequence during the period included the exercise
by Connacher of its Petrolifera Petroleum Limited initial warrants to maintain
the company's equity stake in this highly successful company at the 26 percent
level. Also, during the reporting period Connacher was able to further
strengthen its financial condition with the successful placement for resale of
$100 million of 4.75 percent senior subordinated unsecured convertible
debentures, on a bought deal basis with a syndicate of investment banks,
headed by Canada's largest investment dealer. This expression of support and
increased sponsorship reflects favorably on the company's progress as the
transaction was also fully supported by the company's previous banking
syndicate.
    Also, Connacher's $50 million revolving reserve-backed loan facility,
secured by Connacher's conventional reserve base, was renewed during the
period, based on the company's successful 2007 drilling program and despite
the erosion of natural gas prices which adversely affected loan values for the
industry. The facility was undrawn as at quarter end.
    Connacher's financial and operating results for the second quarter and
first half of 2007 are discussed in greater detail in the MD&A which comprises
a portion of this Interim Report. However, some items of note should be
recognized. Our refinery in Montana had an exceptional second quarter and
first half 2007 with a significant expansion in refining netbacks, especially
in the second quarter. Our cash flow from operations continued to grow nicely,
reaching $27.9 million for the first half 2007 and increasing by about
78 percent over the first quarter 2007 at $16 million. This represents an
increase of 148 percent over the first half of 2006 and 78 percent for the
second quarter. Cash flow per share (weighted average) was 80 percent higher
in the first half of 2007 compared to 2006, performance achieved during a
period when our focus was on our considerable efforts at Pod One.
    Earnings showed an even better relative performance, reaching
$27.2 million for the first half of 2007, compared to a $3.1 million loss last
year. While the results were influenced markedly by foreign exchange gains,
which arose from the strength of the Canadian dollar, related to our
US$-denominated indebtedness, the strong dollar also adversely influences
Canadian dollar pricing for crude oil and natural gas. Second quarter 2007
earnings were $22.2 million ($0.11 per share).
    All resolutions submitted to shareholders for approval at the company's
Annual and Special Meeting held on May 10, 2007 were approved by shareholders.
We have also been very successful in attracting new expertise and talent to
the company with our hiring program at head office and at Great Divide as we
plan for our exciting future. We welcomed one new officer and numerous new
employees to the company during the second quarter reporting period, which is
a positive reflection on Connacher's reputation as a dynamic and growing
business.
    Following our plant commissioning (formal ceremony on August 10, 2007 and
then the balance of the commissioning process until mid-September) we will
begin injecting steam into the fifteen SAGD well pairs which are onsite at
Great Divide Pod One. This process will be carried out with close monitoring
for 90 days, after which production will commence from Pod One and will be
ramped up thereafter towards our licensed volume of 10,000 bbl/d. We will keep
our shareholders informed of our progress. Check our website at
www.connacheroil.com for pictures and periodic updates as new information
becomes available.


    MANAGEMENT'S DISCUSSION AND ANALYSIS

    The following is dated as of August 9, 2007 and should be read in
conjunction with the unaudited consolidated financial statements of Connacher
Oil and Gas Limited ("Connacher" or the "company") for the three and six
months ended June 30, 2007 and 2006 as contained in this interim report and
the MD&A and audited financial statements for the years ended December 31,
2006 and 2005 as contained in the company's 2006 annual report. The unaudited
consolidated financial statements for the six months ended June 30, 2007 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.
    Additional information relating to Connacher, including Connacher's
Annual Information Form is on SEDAR at www.sedar.com.

    FINANCIAL AND OPERATING REVIEW

    
    PETROLEUM AND NATURAL GAS ("PNG") PRODUCTION, PRICING AND REVENUE
    -------------------------------------------------------------------------
                        Three months ended June 30  Six months ended June 30
    -------------------------------------------------------------------------
                          2007     2006  % Change    2007     2006  % Change
    -------------------------------------------------------------------------
    Daily production
     /sales volumes
    -------------------------------------------------------------------------
      Crude oil - bbl/d     731    1,026      (29)     817      858       (5)
    -------------------------------------------------------------------------
      Natural gas - mcf/d 9,017   15,172      (41)   9,340    8,921        5
    -------------------------------------------------------------------------
      Combined - boe/d    2,234    3,554      (37)   2,374    2,345        1
    -------------------------------------------------------------------------
    Product pricing ($)
      Crude oil - per bbl 49.79    61.45      (19)   49.42    53.26       (7)
    -------------------------------------------------------------------------
      Natural gas
       - per mcf           7.02     5.66       24     7.40     5.76       28
    -------------------------------------------------------------------------
      Combined - per boe  44.63    41.88        7    46.13    41.39       12
    -------------------------------------------------------------------------
    Revenue ($000)
    -------------------------------------------------------------------------
    PNG revenue - gross   9,070   13,546      (33)  19,817   17,567       13
    -------------------------------------------------------------------------
    Royalties              (657)  (3,375)     (81)  (3,197)  (4,185)     (24)
    -------------------------------------------------------------------------
    PNG revenue - net     8,413   10,171      (17)  16,620   13,382       24
    -------------------------------------------------------------------------
    

    In the second quarter of 2007, net PNG revenues were down 17 percent to
$8.4 million from $10.2 million in 2006. This was primarily attributable to a
41 percent decrease in natural gas sales volumes as no new wells, reserves and
behind pipe production tested at over 1,000 boe/d (all natural gas) can be
placed onstream until the winter first quarter of 2008 due to limited access,
and a 29 percent decrease in crude oil sales volumes. Although world oil
selling prices were down approximately eight percent from the second quarter
of 2006, the company's average crude oil selling price decreased by 19 percent
to $49.79 per barrel due to the impact of crude quality differentials on
pricing and the effect of the strengthening Canadian dollar on the prices
received by the company. The company's natural gas sales prices increased
24 percent in 2007 as a result of achieving better industry market pricing for
our sales volumes in the current year.
    In the first quarter of 2007, the company entered into a "costless
collar" contract with a third party to sell approximately one half of its of
natural gas production. Mitigating some downside natural gas pricing risk, the
company will receive a minimum of US $7.00 per mmbtu and a maximum of US $9.50
per mmbtu on a notional quantity of 5,000 mmbtu/day of natural gas sold
between April 1, 2007 and October 31, 2007. This transaction was not meant to
speculate on future natural gas prices, but rather to protect the downside
risk to the company's cash flow and the lending value of its reserves-based
line of credit, which is considered important during a period of rapid growth
with significant capital expenditures. At June 30, 2007 the fair value of this
collar was an asset of $282,000, recorded in accounts receivable on the
consolidated balance sheet and the gain has been included in PNG revenue.

    
    ROYALTIES ON PNG SALES
    -------------------------------------------------------------------------
                                                      2007              2006
    For the three months ended June 30    -----------------------------------
    ($000 except per boe)                   Total  Per boe    Total  Per boe
    -------------------------------------------------------------------------
    Royalties                                $657    $3.23   $3,375   $10.43
    -------------------------------------------------------------------------
    As a percentage of PNG revenue                    7.2%             25.0%
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                                      2007              2006
    For the six months ended June 30      -----------------------------------
    ($000 except per boe)                   Total  Per boe    Total  Per boe
    -------------------------------------------------------------------------
    Royalties                              $3,197    $7.44   $4,185   $ 9.86
    -------------------------------------------------------------------------
    As a percentage of PNG revenue                   16.1%             24.0%
    -------------------------------------------------------------------------
    

    Royalties represent charges against production or revenue by governments
and landowners. Royalties in the second quarter of 2007 were $657,000
($3.23 per boe, or seven percent of petroleum and natural gas revenue)
compared to $3.4 million in 2006 ($10.43 per boe, or 25 percent of petroleum
and natural gas revenue). The decrease, which was substantially non-recurring,
occurred primarily due to gas cost allowance credits received in the second
quarter of 2007 relating to prior year royalties. 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.

    
    PNG OPERATING EXPENSES AND NETBACKS
    -------------------------------------------------------------------------
    PNG Netbacks(1)
    For the three months
     ended June 30                  2007              2006          % Change
    -------------------------------------------------------------------------
    ($000 except
     per boe)             Total  Per boe    Total  Per boe    Total  Per boe
    -------------------------------------------------------------------------
    Average daily
     production (boe/d)            2,234             3,554               (37)
    Gross PNG revenue   $ 9,070  $ 44.63  $13,546  $ 41.88      (33)       7
    Royalties              (657)   (3.23)  (3,375)  (10.43)     (81)     (70)
    -------------------------------------------------------------------------
    Net PNG revenue       8,413    41.40   10,171    31.45      (17)      32
    Operating costs      (2,660)  (13.08)  (2,468)   (7.63)       8       71
    -------------------------------------------------------------------------
    PNG netback         $ 5,753  $ 28.32  $ 7,703  $ 23.82       25       19
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    For the six months
     ended June 30                  2007              2006          % Change
    -------------------------------------------------------------------------
    ($000 except
     per boe)             Total  Per boe    Total  Per boe    Total  Per boe
    -------------------------------------------------------------------------
    Average daily
     production (boe/d)            2,374             2,345                 1
    Gross PNG revenue   $19,817  $ 46.13  $17,567  $ 41.39       13       11
    Royalties            (3,197)   (7.44)  (4,185)   (9.86)     (24)     (25)
    -------------------------------------------------------------------------
    Net PNG revenue      16,620    38.69   13,382    31.53       24       23
    Operating costs      (4,592)  (10.69)  (3,300)   (7.77)      39       38
    -------------------------------------------------------------------------
    PNG netback         $12,028  $ 28.00  $10,082  $ 23.76       19       18
    -------------------------------------------------------------------------

    (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.
    

    In the second quarter of 2007 operating costs of $2.7 million were eight
percent higher than in the same prior period, and on a per unit basis,
increased by 71 percent to $13.08 per boe reflecting the higher cost
environment in 2007 in addition to more well workovers completed in 2007 and
higher power costs. However, higher product prices and lower royalties
resulted in higher operating netbacks in 2007.

    
    Reconciliation of PNG Netback to Net Earnings(1)
    -------------------------------------------------------------------------
    For the six months ended June 30                  2007              2006
    -------------------------------------------------------------------------
    ($000, except per unit amounts)         Total  Per boe    Total  Per boe
    -------------------------------------------------------------------------
    PNG netback as above                  $12,028   $28.00  $10,082   $23.76
    -------------------------------------------------------------------------
    Interest income                           345     0.80      525     1.24
    -------------------------------------------------------------------------
    Refining margin - net                  29,346    68.29    3,988     9.40
    -------------------------------------------------------------------------
    General and administrative             (5,248)  (12.21)  (2,299)   (5.42)
    -------------------------------------------------------------------------
    Stock-based compensation               (3,279)   (7.63)  (5,194)  (12.24)
    -------------------------------------------------------------------------
    Finance charges                        (1,710)   (3.98)  (3,239)   (7.63)
    -------------------------------------------------------------------------
    Foreign exchange (loss) gain           16,188    37.67      (38)   (0.09)
    -------------------------------------------------------------------------
    Depletion, depreciation
     and amortization                     (14,721)  (34.25) (12,890)  (30.37)
    -------------------------------------------------------------------------
    Income taxes                          (12,747)  (29.67)   3,339     7.87
    -------------------------------------------------------------------------
    Equity interest in Petrolifera
     earnings and dilution gain             7,010    16.31    2,641     6.22
    -------------------------------------------------------------------------
    Net earnings (loss)                   $27,212   $63.33  $(3,085)  $(7.26)
    -------------------------------------------------------------------------
    (1) Certain income and expense items included in this reconciliation
        relate to non-PNG business and, therefore, affect the consolidated
        net earnings (loss) per boe calculations.


    PNG Operating Netbacks by Product
    -------------------------------------------------------------------------
    For the three months ended                Crude oil         Natural gas
     June 30, 2007                        -----------------------------------
    ($000, except per unit amounts)         Total  Per bbl    Total  Per mcf
                                          -----------------------------------
    -------------------------------------------------------------------------
    Average daily production                  731 bbl/d        9,017 mcf/d
    Revenue                               $ 3,311  $ 49.79  $ 5,759  $  7.02
    Royalties                                (828)  (12.45)     171     0.21
    Operating costs                          (808)  (12.15)  (1,852)   (2.26)
    -------------------------------------------------------------------------
    PNG Netback                           $ 1,675  $ 25.19  $ 4,078  $  4.97
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    For the three months ended                Crude oil         Natural gas
     June 30, 2006                        -----------------------------------
                                            Total  Per bbl    Total  Per mcf
    -------------------------------------------------------------------------
    ($000s, except per unit amounts)
    -------------------------------------------------------------------------
    Average daily production                 1,026 bbl/d      15,172 mcf/d
    Revenue                               $ 5,735  $ 61.45  $ 7,811  $  5.66
    Royalties                              (1,267)  (13.57)  (2,108)   (1.53)
    Operating costs                          (870)   (8.78)  (1,648)   (1.19)
    -------------------------------------------------------------------------
    PNG Netback                           $ 3,648  $ 39.10  $ 4,055  $  2.94
    -------------------------------------------------------------------------


    For the six months ended June 30, 2007
    -------------------------------------------------------------------------
                                              Crude oil         Natural gas
    2007                                  -----------------------------------
    ($000, except per unit amounts)         Total  Per bbl    Total  Per mcf
                                          -----------------------------------
    -------------------------------------------------------------------------
    Average daily production                  817 bbl/d        9,340 mcf/d
    Revenue                               $ 7,308  $ 49.42  $12,509  $  7.40
    Royalties                              (1,767)  (11.95)  (1,430)   (0.85)
    Operating costs                        (1,684)  (11.39)  (2,908)   (1.72)
    -------------------------------------------------------------------------
    PNG Netback                           $ 3,857  $ 26.08  $ 8,171  $  4.83
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    For the six months ended                  Crude oil         Natural gas
     June 30, 2006                        -----------------------------------
                                            Total  Per bbl    Total  Per mcf
    -------------------------------------------------------------------------
    ($000, except per unit amounts)
    -------------------------------------------------------------------------
    Average daily production                  858 bbl/d        8,921 mcf/d
    Revenue                               $ 8,273  $ 53.26  $ 9,294  $  5.76
    Royalties                              (1,713)  (11.03)  (2,472)   (1.53)
    Operating costs                        (1,349)   (8.68)  (1,951)   (1.21)
    -------------------------------------------------------------------------
    PNG Netback                           $ 5,211  $ 33.55  $ 4,871  $  3.02
    -------------------------------------------------------------------------
    

    REFINING REVENUES AND MARGINS

    The quarterly operating results of the Montana refinery are summarized
below.

    Refining Operations and Sales

    The Montana refinery is subject to a number of seasonal factors which may
cause product sales to vary throughout the year. The refinery's primary
asphalt market is paving for road construction which is predominantly a summer
demand. Consequently, process and volumes for our asphalt tend to be higher in
the summer and lower in the colder seasons. During the winter most of the
refinery's asphalt production is stored in tankage for sale in the subsequent
summer. Seasonal factors also affect gasoline (higher demand in the summer
months) and distillate and diesel (higher winter demand). As a result,
inventory levels, sales volumes and prices can be expected to fluctuate on a
seasonal basis.
    The Montana refinery achieved record performance during the second
quarter 2007 due to higher product prices and refining margins. Refining sales
revenues were $84.6 million compared to $57.6 million in the first quarter
2007 and $51.0 million in the second quarter of 2006. Sales revenues increased
due to higher product prices and higher seasonal sales of asphalt.
    Crude oil and operating costs were also up, rising to $66.5 million in
the quarter 2007 compared to $46.4 million in the first quarter 2007 and
$47 million in the same period last year. Refinery margins increased to
$18.1 million (21.4%) compared to $11.2 million (19.4%) in the first quarter
2007 and $4.0 million (7.8%) in the second quarter of 2006.
    In the first six months of 2007, the refinery ran at 99% of capacity and
there was no downtime. During the second quarter the company sanctioned its
ultralow sulphur diesel project to allow the company to produce ultraclean
fuels by late 2008. Vendor selection and detailed engineering design is
currently underway. The company has also initiated a project to assess a
potential expansion of the Montana refinery. The project is currently in the
conceptual engineering stage.

    
    -------------------------------------------------------------------------
                                         Three months ended  Six months ended
                                                June 30           June 30
    -------------------------------------------------------------------------
    Refinery throughput                      2007     2006     2007   2006(5)
    -------------------------------------------------------------------------
    Crude charged (bbl/d)(1)                9,244    6,864    9,432    6,864
    -------------------------------------------------------------------------
    Refinery production (bbl/d)(2)         10,085    6,932   10,358    6,932
    -------------------------------------------------------------------------
    Sales of produced refined products
     (bbl/d)                                9,753    6,266    8,771    6,266
    -------------------------------------------------------------------------
    Sales of refined products (bbl/d)(3)   10,735    7,384    9,501    7,384
    -------------------------------------------------------------------------
    Refinery utilization (%)(4)              97.3%    82.7%    99.3%    82.7%
    -------------------------------------------------------------------------
    (1) Crude charged represents the barrels per day of crude oil processed
        at the refinery.
    (2) Refinery production represents the barrels per day of refined
        products yielded from processing crude and other refinery feedstocks.
    (3) Includes refined products purchased for resale.
    (4) Represents crude charged divided by total crude capacity of the
        refinery. Note refining capacity has been increased to 9,500 bbl/d in
        the fourth quarter of 2006.
    (5) From the date of acquisition on March 31, 2006.



    -------------------------------------------------------------------------
                                         Three months ended  Six months ended
                                                June 30           June 30
    -------------------------------------------------------------------------
                                             2007     2006     2007     2006
    -------------------------------------------------------------------------
    Feedstocks - three months ended
    -------------------------------------------------------------------------
    Sour crude oil (%)                         93%      98%      93%      98%
    -------------------------------------------------------------------------
    Other feedstocks and blends (%)             7%       2%       7%       2%
    -------------------------------------------------------------------------
    Total                                     100%     100%     100%     100%
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Revenues and Margins
    -------------------------------------------------------------------------
    Refining sales revenue ($000s)         84,628   50,967  142,224   50,967
    -------------------------------------------------------------------------
    Refining - crude oil and operating
     costs ($000s)                         66,480   46,979  112,878   46,979
    -------------------------------------------------------------------------
    Refining margin ($000s)                18,148    3,988   29,346    3,988
    -------------------------------------------------------------------------
    Refining margin (%)                      21.4%     7.8%    20.6%     7.8%
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Sales of Produced Refined Products (Volume %)
    -------------------------------------------------------------------------
    Gasolines (%)                              40%      27%      45%      27%
    -------------------------------------------------------------------------
    Diesel fuels (%)                           18%      15%      22%      15%
    -------------------------------------------------------------------------
    Jet fuels (%)                               5%       3%       5%       3%
    -------------------------------------------------------------------------
    Asphalt (%)                                33%      50%      24%      50%
    -------------------------------------------------------------------------
    LPG and other (%)                           4%       5%       4%       5%
    -------------------------------------------------------------------------
    Total                                     100%     100%     100%     100%
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Averages per Barrel of Refined Product Sold
    -------------------------------------------------------------------------
    Refining sales revenue                $ 86.63  $ 89.38  $ 82.70  $ 89.38
    -------------------------------------------------------------------------
    Less: refining - crude oil purchases
     and operating costs                    68.05    82.39    65.64    82.39
    -------------------------------------------------------------------------
    Refining margin                       $ 18.58  $  6.99  $ 17.06  $  6.99
    -------------------------------------------------------------------------
    

    INTEREST AND OTHER INCOME

    In the second quarter of 2007, the company earned interest of $225,000
(second quarter, 2006 - $101,000) on excess funds invested in secure
short-term investments.

    GENERAL AND ADMINISTRATIVE EXPENSES

    In the second quarter of 2007, general and administrative ("G&A")
expenses were $1.7 million compared to $1.3 million in the second quarter of
2006, an increase of 24 percent, reflecting increased costs associated with
the company's growth. On a per unit basis, G&A was $8.18 per boe sold,
reflecting the project nature of the company's main activity, and is expected
to be significantly reduced when bitumen production from Pod One commences and
is booked. G&A of $1.1 million was capitalized in the first six months of 2007
(2006 - $99,000), primarily reflecting costs incurred respecting the oil sands
development in the pre-production stage.
    Non-cash stock-based compensation costs of $875,000 were recorded in the
second quarter of 2007 (June 30, 2006 - $6.5 million). These charges reflect
the fair value of all stock options granted and vested in the period. Of this
amount, $333,000 was expensed (2006 - $4.8 million) and $542,000 was
capitalized (2006 - $1.7 million). Charges for the reporting periods are lower
in 2007 due to either the timing of awards or lower award volumes in 2007.

    FINANCE CHARGES AND FOREIGN EXCHANGE

    Financing charges in the second quarter of 2007 of $1.3 million (year to
date - $1.7 million) comprise interest paid on funds drawn on the company's
lines of credit, interest accrued on the Convertible Debentures and accretion
booked on the Convertible Debentures. Finance charges in the second quarter of
2006 of $3.2 million (first six months of 2006 - $3.3 million) comprise
interest on the company's lines of credit, interest on the US $51 million
bridge loan then outstanding and the amortization of deferred financing costs
related to the US $51 million bridge loan facility placed in 2006. Interest on
the oil sands term loan is capitalized during the pre-operating phase.
    An unrealized foreign exchange gain of $14.5 million was recorded in the
second quarter of 2007 primarily due to the conversion of the US$180 million
oil sands term loan into Canadian dollars for reporting purposes, as the
Canadian dollar strengthened significantly in the reporting period.
    The company's main exposure to foreign currency risk relates to the
pricing of its crude oil sales, which are denominated in US dollars, the
translation of the US$180 million oil sands term loan and the translation of
the Montana refinery financial results. 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")

    Conventional oil and gas depletion expense is calculated using the
unit-of-production method based on total estimated proved reserves. Refining
properties and other assets are depreciated over their estimated useful lives.
DD&A in the second quarter of 2007 was $7.4 million, a 30 percent decrease
from last year due to decreased production volumes and increased proved
conventional reserves. Conventional oil and gas depletion equates to
$34.25 per boe of production on a year-to-date basis compared to $28.50 per
boe last year. Depletion of Pod One's oil sands capital costs will commence
when that project attains commercial production.
    Capital costs of $322 million (June 30, 2006 - $64 million) related to
the Great Divide oil sands project, which is in the pre-production stage, and
undeveloped land acquisition costs of $17 million (2006 - $10 million) were
excluded from the depletion calculation, while future development costs of
$15 million (2006 - $2 million) for proved undeveloped reserves were included
in the depletion calculation.
    Included in DD&A is an accretion charge of $433,000 (June 30, 2006 -
$130,000) 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 $13.1 million to the estimated total
undiscounted liability of $42 million over the remaining economic life of the
company's oil and gas properties.

    INCOME TAXES

    The income tax provision of $12.7 million in the first six months of 2007
includes a current income tax provision of $7.5 million, principally related
to US refinery operations and a future income tax provision of $5.3 million
relating to both Canadian and US operations. The income tax recovery of
$3.3 million for the first six months of 2006 was due primarily to enacted
federal and provincial tax rate reductions.
    At June 30, 2007 the company had approximately $28 million of non-capital
losses which do not expire before 2009, $416 million of deductible resource
pools and $21 million of deductible financing costs.

    EQUITY INTEREST IN PETROLIFERA PETROLEUM LIMITED ("PETROLIFERA") AND
    DILUTION GAIN

    Connacher accounts for its 26 percent equity investment in Petrolifera on
the equity method basis of accounting. Connacher's equity interest share of
Petrolifera's earnings in the first six months of 2007 was $5.1 million
(June 30, 2006 - $2.6 million).
    In May 2007, the company exercised its right to purchase 1.7 million
additional common shares in Petrolifera for total consideration of
$5.1 million. As a result, the company maintained its 26 percent equity
interest, as other Petrolifera shareholders similarly exercised their right to
purchase additional common shares in Petrolifera on identical terms. As a
consequence of this investment, the company's carrying value of its
Petrolifera investment holding increased to cause a dilution gain of $1.9
million.

    NET EARNINGS

    In the first six months of 2007, the company reported earnings of
$27.2 million ($0.14 per basic and diluted share outstanding) compared to a
loss of $3.1 million or $0.02 loss per basic and diluted share for the first
six months of 2006. In 2007, the refinery contributed significantly to these
results, as did the recorded foreign exchange gains.

    SECURITIES OUTSTANDING

    For the first six months of 2007, the weighted average number of common
shares outstanding was 198,240,426 (2006 - 173,015,395) and the weighted
average number of diluted shares outstanding, as calculated by the treasury
stock method, was 204,762,395 (2006 - 180,415,669).
    As at August 8, 2007, the company had the following securities issued and
outstanding:

    
    -   198,953,923 common shares;

    -   17,939,711 share purchase options;

    -   217,950 deferred share units ("DSUs") under the share award plan; and

    -   20,010,000 common shares issuable upon conversion of the $100,050,000
        convertible debentures
    

    Details of the exercise provisions and terms of the outstanding options,
DSUs and convertible debentures are noted in the consolidated financial
statements, included in this interim report.

    LIQUIDITY AND CAPITAL RE

SOURCES On May 25, 2007 Connacher issued senior unsecured subordinated convertible debentures with a face value of $100,050,000. The debentures mature June 30, 2012 unless converted prior to that date and bear interest at an annual rate of 4.75 percent payable semiannually on June 30 and December 31. The debentures are convertible at any time into common shares at the option of the holder at a conversion price of $5 per share. The debentures are redeemable or after June 30, 2010 by the company, in whole or in part at a redemption price equal to 100 percent of the principal amount of the debentures to be redeemed plus accrued and unpaid interest provided that the market price of the company's common shares is at least 120 percent of the conversion price of the debentures. The conversion feature of the debentures has been accounted for as a separate component of equity in the amount of $16,823,000. The remainder of the net proceeds of the debentures of $79,243,000 has been recorded as long-term debt, which will be accreted up to the face value of $100,050,000 over the five-year term of the debentures. Accretion and interest paid are recorded as finance charges on the consolidated statement of operations. If the debentures are converted to common shares, the value of the conversion feature will be reclassified to share capital along with the principal amounts converted. Proceeds of the financing were utilized as follows: ------------------------------------------------------------------------- As stated As at the time actually of financing applied ------------------------------------------------------------------------- ($000s) ------------------------------------------------------------------------- Gross proceeds $ 100,050 $ 100,050 Underwriters' commissions and issue cost 3,252 3,984 ------------------------------------------------------------------------- Net proceeds $ 96,798 $ 96,066 ------------------------------------------------------------------------- The net proceeds were used to fund the company's ongoing capital expenditure program in respect of the development of its oil sands projects, its conventional capital program, for operating expenses, and to repay $52.5 million of the company's conventional oil and gas operating line of credit, which had been drawn to temporarily fund some of the aforementioned capital and operating expenditures. In the second quarter of 2007, the company also renewed its revolving conventional oil and gas operating line of credit for one year for a limit of $50 million. None of this amount was drawn at June 30, 2007. At June 30, 2007, the company had working capital of $36.3 million, including $21 million of cash and $4.5 million of segregated cash dedicated to funding the remaining costs of completing the Pod One oil sands project, no short-term debt, an unused $50 million reserve-backed revolving line of credit. In the first half of 2007, cash flow was $27.8 million ($0.14 per basic and diluted share), 148 percent higher than the $11.2 million reported ($0.07 per basic and $0.06 diluted share) for the first half of 2006. A significant portion of this was contributed by the refinery. 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 2007 capital program. As the company's oil sands term loan is denominated in US dollars, there is a foreign exchange risk associated with its repayment using Canadian currency. The company's crude oil selling prices are established in relation to US dollar denominated markets and, therefore, provide a partial hedge to this exposure. The company has entered into an interest rate swap to mitigate some of the interest rate volatility associated with the variable interest rate inherent in the oil sands term loan. The company also entered into a natural gas costless collar to mitigate some downside natural gas pricing risk and, therefore, protect the risk of reduced cash flow from operations and the risk of reductions to the lending value of its conventional banking facilities, which is considered particularly important in a time of rapid growth with significant capital expenditure. The company's only financial instruments are cash, accounts receivable and payable, bank debt, the interest rate swap and the natural gas costless collar. The company maintains no off-balance sheet financial instruments. Reconciliation of net earnings to cash flow from operations before working capital changes: ------------------------------------------------------------------------- Three months ended Six months ended June 30 June 30 2007 2006 2007 2006 ------------------------------------------------------------------------- ($000s) ------------------------------------------------------------------------- Net earnings (loss) $22,228 $(2,419) $27,212 $(3,085) Items not involving cash: Depletion, depreciation and accretion 7,363 10,013 14,721 12,890 Stock-based compensation 333 4,800 3,279 5,194 Financing charges 324 2,300 324 2,307 Future employee benefits 122 124 252 124 Future income tax provision (recovery) 4,102 (3,186) 5,267 (3,573) Foreign exchange (gain) loss (14,486) 31 (16,188) 38 Lease inducement amortization - (15) - (30) Dilution (gain) loss (1,896) 51 (1,896) (52) Equity interest in Petrolifera earnings (1,214) (2,200) (5,114) (2,589) ------------------------------------------------------------------------- Cash flow from operations before working capital changes $16,876 $ 9,499 $27,857 $11,224 ------------------------------------------------------------------------- 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. CAPITAL EXPENDITURES AND FINANCING ACTIVITIES Capital expenditures totaled $93.2 million in the second quarter of 2007 and $203.1 million year-to-date (second quarter 2006 - $34.3 million; first half of 2006 - $335.1 million). A breakdown of these expenditures follows: ------------------------------------------------------------------------- Six months ended June 30 ($000) 2007 2006 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Acquisition of Luke Energy Ltd. $- $205,000 Acquisition of the Montana refinery assets - 67,000 Oil sands expenditures 166,523 52,096 Conventional oil and gas expenditures 30,737 10,763 Refinery expenditures 5,844 257 ------------------------------------------------------------------------- $203,104 $335,116 ------------------------------------------------------------------------- Oil sands expenditures include exploratory core hole drilling, seismic, lease acquisition on Pods One through Six and costs incurred for the development of Pod One. In the first six months of 2007, 75 exploratory core holes were drilled. In the first half of 2006, 20 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. In 2007, 19 (18 net) conventional oil and gas wells were drilled, resulting in eight cased gas wells; one suspended gas well, two suspended oil wells (being evaluated); and eight (seven net) abandoned wells. 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 average of over 90 percent working interest in its PNG properties and 100% interest in its oil sands properties, providing the company with operational and timing controls. Great Divide Oil Sands Project, Northern Alberta The company holds a 100 percent working interest in approximately 95,000 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 $277 million of expenditures have been incurred to June 30, 2007 to acquire the oil sands leases, to delineate the oil bearing reservoir and for facilities related to the development of a 10,000 bbl/d SAGD project. Capital development costs for Pod One are expected to approximate $300 million, prior to the commencement of bitumen production in the latter part of 2007. The remaining costs will be funded with cash on hand and available lines of credit. 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. NEW SIGNIFICANT ACCOUNTING POLICIES The company has assessed new and revised accounting pronouncements that have been issued. In 2007 the company has adopted, as necessary, 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 the Consolidated Statement of Other Comprehensive Income, has been introduced which identifies certain gains and losses, including 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 at fair values. CONVERTIBLE DEBENTURES The convertible debentures have been recorded as a compound financial instrument in accordance with Section 3861 of the CICA Handbook. The fair value of the liability component has been determined at the date of issue based on the company's incremental borrowing rate for debt with similar terms. The amount of the equity component has been determined as a residual after deducting the amount of the liability component from the face value of the issue. DEFERRED SHARE AWARD PLAN Obligations for payments in cash or common shares under the company's deferred share award plan for non-employee directors are accrued as compensation expense over the vesting period. Fluctuations in the price of the company's common shares change the accrued compensation expense and are recognized when they occur. BUSINESS RISKS Connacher is exposed to certain risks and uncertainties inherent in the oil and gas and refining businesses. Furthermore, 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 is exposed to other risks including currency fluctuations, political risk, price controls and varying forms of fiscal regimes or changes thereto which may impair that investee'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. For the Montana refinery, 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. The refinery's profitability will depend largely on the spread between market prices for refined products sold and market prices for crude oil purchased. A substantial or prolonged reduction in this spread could have a significant negative effect on earnings, financial condition and cash flows. Petroleum commodity futures contracts could be utilized to reduce exposure to price fluctuations associated with crude oil and refined products. Such contracts could be used principally to help manage the price risk inherent in purchasing crude oil in advance of the delivery date and as a hedge for fixed-price sales contracts of refined products. Commodity price swaps and collar options could also be utilized to help manage the exposure to price volatility relating to forecasted purchases of natural gas. Contracts could also be utilized to provide for the purchase of crude oil and other feedstocks and for the sales of refined products. Certain of these contracts may meet the definition of a hedge and may be subject to hedge accounting. The 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. The refinery'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, the refinery 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, Connacher has issued parental guarantees and indemnifications on behalf of the refinery. This is considered to be in the normal course of business. 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. It is anticipated this risk will be substantially mitigated by the production and sale of natural gas from the company's gas properties at Marten Creek acquired with the purchase of Luke Energy Ltd. 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 term debt. Bitumen is generally less marketable than light or medium crude oil, and prices received for bitumen are generally lower than those for crude oil. The company is therefore exposed to the price differential between crude oil and bitumen; fluctuations in this differential could have a material impact on the company's profitability. The purchase of the Montana refinery was meant to help mitigate this 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 oil and gas exploration, development and production activities. Long-life reserves such as the oil sands now owned by the company may facilitate greater utilization of medium to long-term debt to finance development projects. Occasionally, the company utilizes 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 regularly reviews the need to utilize such financing techniques. Long-life reserves such as the oil sands now owned by the company may facilitate greater utilization of medium to long-term debt to finance development projects. 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, summarized 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. There have been no changes in the company's systems of internal control over financial reporting that would materially affect, or is reasonably likely to materially affect, the company's internal controls over financial reporting. 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. In reaching a reasonable level of assurance, management necessarily is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. 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. 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 Energy 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 2006 ------------------------------------------------------------------------- Three Months Ended Sept 30 Dec 31 Mar 31 Jun 30 ------------------------------------------------------------------------- Financial Highlights ($000 except per share amounts) - Unaudited Revenue net of royalties 3,222 2,978 3,635 61,239 Cash flow from operations before working capital changes(1) 1,978 1,238 1,725 9,499 Basic, per share(1) 0.02 0.01 0.01 0.05 Diluted, per share(1) 0.02 0.01 0.01 0.05 Net earnings (loss) (1,034) 582 (666) (2,419) Basic and diluted per share (0.01) - - (0.01) Capital expenditures 2,870 2,241 300,836 34,280 Proceeds on disposal of PNG properties - - - - Cash on hand 67,708 75,511 - 7,505 Working capital surplus (deficiency) 67,440 75,427 (11,061) (42,483) Long term debt - - - - Shareholders' equity 113,081 129,108 337,584 340,639 Operating Highlights Daily production/sales volumes Natural gas - mcf/d 497 86 2,600 15,172 Crude oil - bbl/d 808 775 689 1,026 Equivalent - boe/d(2) 891 789 1,122 3,554 Product pricing Crude oil - $/bbl 53.40 41.54 40.93 61.45 ----------------------------------- Natural gas - $/mcf 1.88 7.55 6.34 5.66 Selected Highlights - $/boe(2) Weighted average sales price 49.48 41.61 39.83 41.88 Royalties 11.73 7.76 8.02 10.43 Operating costs 7.69 8.90 8.24 7.63 PNG netback(4) 30.06 24.95 23.57 23.82 Common Share Information Shares outstanding at end of period (000) 134,236 139,940 191,257 191,924 Basic (000) 103,851 136,071 154,152 191,672 Diluted (000) 106,397 142,507 160,574 198,931 Volume traded during quarter (000) 180,848 100,246 148,184 80,347 Common share price ($) High 2.69 4.20 6.07 5.05 Low 0.76 1.09 3.47 3.10 Close (end of period) 2.54 3.84 4.95 4.30 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2006 2007 ------------------------------------------------------------------------- Three Months Ended Sept 30 Dec 31 Mar 31 Jun 30 ------------------------------------------------------------------------- Financial Highlights ($000 except per share amounts) - Unaudited Revenue net of royalties 103,110 76,700 65,923 93,266 Cash flow from operations before working capital changes(1) 14,957 14,015 10,980 16,876 Basic, per share(1) 0.08 0.08 0.06 0.09 Diluted, per share(1) 0.08 0.07 0.05 0.08 Net earnings (loss) 6,771 3,267 4,984 22,228 Basic and diluted per share 0.03 0.02 0.03 0.11 Capital expenditures 41,449 74,960 109,881 93,223 Proceeds on disposal of PNG properties - 10,000 - - Cash on hand 14,450 142,391 66,209 25,375 Working capital surplus (deficiency) (39,942) 118,626 24,027 36,320 Long term debt - 209,754 207,828 272,559 Shareholders' equity 378,730 385,398 384,593 417,793 Operating Highlights Daily production/sales volumes Natural gas - mcf/d 12,711 11,291 9,665 9,017 Crude oil - bbl/d 1,059 1,139 905 731 Equivalent - boe/d(2) 3,177 3,021 2,515 2,234 Product pricing Crude oil - $/bbl 62.53 46.65 49.09 49.79 ----------------------------------- Natural gas - $/mcf 5.33 6.57 7.76 7.02 Selected Highlights - $/boe(2) Weighted average sales price 42.16 42.15 47.48 44.63 Royalties 10.72 9.00 11.22 3.23 Operating costs 7.99 9.27 8.54 13.08 PNG netback(4) 23.45 23.88 27.72 28.32 Common Share Information Shares outstanding at end of period (000) 197,878 197,894 198,218 198,834 Basic (000) 193,587 193,884 198,119 198,360 Diluted (000) 200,572 204,028 200,008 209,088 Volume traded during quarter (000) 48,849 46,444 55,292 61,162 Common share price ($) High 4.55 4.43 4.13 4.43 Low 3.09 3.17 3.07 3.07 Close (end of period) 3.60 3.49 3.86 3.69 ------------------------------------------------------------------------- (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. 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) 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) PNG 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. Netbacks by product type are disclosed in the accompanying MD&A. CONSOLIDATED BALANCE SHEETS Connacher Oil and Gas Limited (Unaudited) ------------------------------------------------------------------------- ($000) June 30, December 31, 2007 2006 ------------------------------------------------------------------------- ASSETS CURRENT Cash and cash equivalents $20,889 $19,603 Restricted cash (Note 11 (c)) 4,486 122,788 Accounts receivable 43,488 30,956 Refinery inventories (Note 4) 37,176 24,437 Prepaid expenses 2,171 1,525 Income taxes recoverable 3,942 - Due from Petrolifera - 32 ------------------------------------------------------------------------- 112,152 199,341 Property and equipment 569,532 384,311 Goodwill 103,676 103,676 Deferred costs 2,817 4,005 Investment in Petrolifera 33,750 21,597 ------------------------------------------------------------------------- $821,927 $712,930 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES CURRENT Accounts payable and accrued liabilities $69,400 $57,571 Income taxes payable - 3,644 Revolving line of credit 6,392 19,500 Due to Petrolifera 40 - ------------------------------------------------------------------------- 75,832 80,715 Asset retirement obligations (Note 5) 13,074 7,322 Employee future benefits (Note 11(d)) 591 388 Long term debt (Note 7) 272,559 209,754 Future income taxes 42,078 29,353 ------------------------------------------------------------------------- 404,134 327,532 ------------------------------------------------------------------------- SHAREHOLDERS' EQUITY Share capital and contributed surplus (Note 8) 389,230 376,500 Accumulated other comprehensive loss (Note 3) (7,677) (130) Retained earnings 36,240 9,028 ------------------------------------------------------------------------- 417,793 385,398 ------------------------------------------------------------------------- $821,927 $712,930 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS Connacher Oil and Gas Limited (Unaudited) ------------------------------------------------------------------------- Three Months ended Six months ended June 30 June 30 ------------------------------------------------------------------------- ($000, except per share amounts) 2007 2006 2007 2006 ------------------------------------------------------------------------- REVENUE Petroleum and natural gas revenue, net of royalties $8,413 $10,171 $16,620 $13,382 Refining and marketing sales 84,628 50,967 142,224 50,967 Interest and other income 225 101 345 525 ------------------------------------------------------------------------- 93,266 61,239 159,189 64,874 ------------------------------------------------------------------------- ------------------------------------------------------------------------- EXPENSES Petroleum and natural gas operating costs 2,660 2,468 4,592 3,300 Refining - crude oil purchases and operating costs 66,480 46,979 112,878 46,979 General and administrative 1,663 1,343 5,248 2,299 Stock-based compensation (Note 8) 333 4,800 3,279 5,194 Finance charges 1,264 3,155 1,710 3,239 Foreign exchange loss (gain) (14,486) 31 (16,188) 38 Depletion, depreciation and accretion 7,363 10,013 14,721 12,890 ------------------------------------------------------------------------- 65,277 68,789 126,240 73,939 ------------------------------------------------------------------------- Earnings (loss) before income taxes and other items 27,989 (7,550) 32,949 (9,065) Current income tax provision 4,769 204 7,480 234 Future income tax provision (recovery) 4,102 (3,186) 5,267 (3,573) ------------------------------------------------------------------------- 8,871 (2,982) 12,747 (3,339) ------------------------------------------------------------------------- Earnings (loss) before other items 19,118 (4,568) 20,202 (5,726) Equity interest in Petrolifera earnings 1,214 2,200 5,114 2,589 Dilution gain (loss) (Note 6) 1,896 (51) 1,896 52 ------------------------------------------------------------------------- NET EARNINGS (LOSS) 22,228 (2,419) 27,212 (3,085) ------------------------------------------------------------------------- ------------------------------------------------------------------------- RETAINED EARNINGS, BEGINNING OF PERIOD 14,012 1,409 9,028 2,075 ------------------------------------------------------------------------- ------------------------------------------------------------------------- RETAINED EARNINGS (DEFICIT), END OF PERIOD $36,240 $(1,010) $36,240 $(1,010) ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- EARNINGS (LOSS) PER SHARE (Note 11(a)) Basic $0.11 $(0.01) $0.14 $(0.02) Diluted $0.11 $(0.01) $0.14 $(0.02) ------------------------------------------------------------------------- CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME Connacher Oil and Gas Limited Three Months Ended June 30 (Unaudited) ------------------------------------------------------------------------- ($000) 2007 ------------------------------------------------------------------------- Balance, beginning of period $4,423 ------------------------------------------------------------------------- Net earnings 22,228 Foreign currency translation adjustment (6,986) ------------------------------------------------------------------------- Balance, end of period $19,665 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Connacher Oil and Gas Limited Six Months Ended June 30 (Unaudited) ------------------------------------------------------------------------- ($000) 2007 ------------------------------------------------------------------------- Balance, beginning of period ------------------------------------------------------------------------- Net earnings $27,212 Foreign currency translation adjustment (7,547) ------------------------------------------------------------------------- Balance, end of period $19,665 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) Connacher Oil and Gas Limited Three Months Ended June 30 (Unaudited) ------------------------------------------------------------------------- ($000) 2007 ------------------------------------------------------------------------- Balance, beginning of period $(691) Foreign currency translation adjustment (6,986) ------------------------------------------------------------------------- Balance, end of period $(7,677) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Connacher Oil and Gas Limited Six Months Ended June 30 (Unaudited) ------------------------------------------------------------------------- ($000) 2007 ------------------------------------------------------------------------- Balance, beginning of period $(130) Foreign currency translation adjustment (7,547) ------------------------------------------------------------------------- Balance, end of period $(7,677) ------------------------------------------------------------------------- ------------------------------------------------------------------------- CONSOLIDATED STATEMENTS OF CASH FLOW Connacher Oil and Gas Limited (Unaudited) ------------------------------------------------------------------------- Three Months ended Six months ended June 30 June 30 ------------------------------------------------------------------------- ($000) 2007 2006 2007 2006 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Cash provided by (used in) the following activities: ------------------------------------------------------------------------- ------------------------------------------------------------------------- OPERATING ------------------------------------------------------------------------- Net earnings (loss) $22,228 $(2,419) $27,212 $(3,085) Items not involving cash: Depletion, depreciation and accretion 7,363 10,013 14,721 12,890 Stock-based compensation 333 4,800 3,279 5,194 Financing charges - non-cash portion 324 2,300 324 2,307 Employee future benefits 122 124 252 124 Future income tax provision (recovery) 4,102 (3,186) 5,267 (3,573) Foreign exchange loss (gain) (14,486) 31 (16,188) 38 Dilution (gain) loss (1,896) 51 (1,896) (52) Lease inducement amortization - (15) - (30) Equity interest in Petrolifera earnings (1,214) (2,200) (5,114) (2,589) ------------------------------------------------------------------------- Cash flow from operations before working capital changes 16,876 9,499 27,857 11,224 Changes in non-cash working capital (Note 11(b)) (43,062) (37,742) (36,141) (33,499) ------------------------------------------------------------------------- (26,186) (28,243) (8,284) (22,275) ------------------------------------------------------------------------- ------------------------------------------------------------------------- FINANCING Issue of common shares, net of share issue costs 238 108 518 95,030 Increase in bank debt 41,601 55,045 69,201 72,645 Repayment of bank debt (72,996) - (81,996) - Issuance of convertible debenture net of issue costs 96,066 - 96,066 - Deferred financing costs - (845) - (2,792) ------------------------------------------------------------------------- 64,909 54,308 83,789 164,883 ------------------------------------------------------------------------- ------------------------------------------------------------------------- INVESTING Acquisition and development of oil and gas properties (91,404) (34,280) (196,698) (63,836) Decrease in restricted cash 61,724 - 118,303 - Acquisition of Luke Energy Ltd. - (426) - (92,654) Acquisition of refining assets - - - (62,041) Exercise of Petrolifera warrants (Note 6) (5,143) - (5,143) - Acquisition of other assets - (4,927) - (4,927) Change in non-cash working capital (Note 11(b)) 21,649 9,374 14,544 14,218 ------------------------------------------------------------------------- (13,174) (30,259) (68,994) (209,240) ------------------------------------------------------------------------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 25,549 (4,194) 6,511 (66,632) ------------------------------------------------------------------------- Impact of foreign exchange on foreign currency denominated cash balances (4,660) (1,374) (5,225) (1,374) ------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD - 13,073 19,603 75,511 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS, END OF PERIOD $20,889 $7,505 $20,889 $7,505 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Supplementary information - Note 11 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS Connacher Oil and Gas Limited Period ended June 30, 2007 (Unaudited) 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. ("the refinery"), the company is in the business of exploration and development of bitumen in the oil sands of northern Alberta, and exploring, developing, producing, refining and marketing conventional petroleum and natural gas. 2. SIGNIFICANT ACCOUNTING POLICIES The interim Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as indicated in the annual audited Consolidated Financial Statements for the year ended December 31, 2006, except as described below and in Note 3. The disclosures provided below do not conform in all respects to those included with the annual audited Consolidated Financial Statements. The interim consolidated Financial Statements should be read in conjunction with the annual audited Consolidated Financial Statements and the notes thereto for the year ended December 31, 2006. (a) Convertible debentures The convertible debentures have been classified as term debt and equity at their fair value at the date of issue. The fair value of the liability component has been determined based on the company's incremental borrowing rate for debt with similar terms. The amount of the equity component has been determined as a residual after deducting the amount of the liability component from the face value of the issue. (b) Deferred share award plan for non-employee directors Obligations for payments in cash or common shares under the company's deferred share award plan for non-employee directors are accrued as compensation expense over the vesting period. Fluctuations in the price of the company's common shares change the accrued compensation expense and are recognized when they occur. 3. NEW ACCOUNTING STANDARDS Effective January 1, 2007 the company adopted CICA Handbook sections 1530, 3251, 3855 and 3865 relating to Comprehensive Income, Equity, Financial Instruments - Recognition and Measurement, and Hedges, respectively. Under the new standards, additional financial statement disclosure, namely the Consolidated Statement of Comprehensive Income, has been introduced. This statement identifies certain gains and losses, which in the company's case include only foreign currency translation adjustments arising from translation of the company's U.S. refining subsidiary which is considered to be self-sustaining, that are recorded outside the income statement. Additionally, a separate component of equity, Accumulated Other Comprehensive Income ("AOCI"), has been introduced in the consolidated balance sheet to record the continuity of other comprehensive income balances on a cumulative basis. The adoption of comprehensive income has been made in accordance with the applicable transitional provisions. Accordingly, the December 31, 2006 period end accumulated foreign currency translation adjustment balance of $130,000 has been reclassified to AOCI. In addition, the change in the accumulated foreign currency translation adjustment balance for the six months ended June 30, 2007 of $7,547,000 is now included in the Statement of Comprehensive Income (Loss) (six months ended June 30, 2006 - nil). Finally, all financial instruments, including derivatives, are recorded in the company's consolidated balance sheet and measured at their fair values. Under section 3855, the company is required to classify its financial instruments into one of five categories. The company has classified all of its financial instruments, with the exception of the oil sands term loan and the convertible debentures, as Held for Trading, which requires measurement on the balance sheet at fair value with any changes in fair value recorded in income. This classification has been chosen due to the nature of the company's financial instruments, which, except for the oil sands term loan and the convertible debentures, are of a short-term nature such that there are no material differences between the carrying values and the fair values of these financial statement components. Transaction costs related to financial instruments classified as Held for Trading are recorded in income in accordance with the new standards. The US $180 million oil sands term loan and the convertible debentures have been classified as other liabilities (as defined by the accounting standard) and are accounted for on the amortized cost basis. The adoption of section 3865, "Hedges", has had no effect on the company's consolidated financial statements as the company does not account for its derivative financial instruments as hedges. Changes during the period in other comprehensive income and AOCI were as follows: ------------------------------------------------------------------------- Three months Six months ended ended June 30, June 30, 2007 2007 ------------------------------------------------------------------------- Increase/ Increase/ ($000) (Decrease) (Decrease) ------------------------------------------------------------------------- Other comprehensive income $(6,986) $(7,547) Accumulated other comprehensive income (loss) $(6,986) $(7,547) ------------------------------------------------------------------------- Effective January 1, 2007, the company adopted the revised recommendations of CICA Handbook section 1506, Accounting Changes. The new recommendations permit voluntary changes in accounting policy only if they result in financial statements which provide more relevant and reliable financial information. Accounting policy changes must be applied retrospectively unless it is impractical to determine the period or cumulative impact of the change in policy. Additionally, when an entity has not applied a new primary source of GAAP that has been issued but is not yet effective, the entity must disclose that fact along with information relevant to assessing the possible impact that application of the new primary source of GAAP will have on the entity's financial statements in the period of initial application. As of January 1, 2008, the company will be required to adopt two new CICA Handbook requirements, section 3862, "Financial Instruments - Disclosures" and section 3863, "Financial Instruments - Presentation" which will replace current section 3861. The new standards require disclosure of the significance of financial instruments to an entity's financial statements, the risks associated with the financial instruments and how those risks are managed. The new presentation standard essentially carries forward the current presentation requirements. The company is assessing the impact of these new standards on its consolidated financial statements and anticipates that the main impact will be in terms of the additional disclosures required. As of January 1, 2008, the company will be required to adopt CICA Handbook section 1535, "Capital Disclosures" which requires entities to disclose their objectives, policies and processes for managing capital and, in addition, whether the entity has complied with any externally imposed capital requirements. The company is assessing the impact of this new standard on its consolidated financial statements and anticipates that the main impact will be in terms of the additional disclosures required. 4. REFINERY INVENTORIES Inventories consist of the following: ------------------------------------------------------------------------- June 30, December 31, ($000) 2007 2006 ------------------------------------------------------------------------- Crude oil $4,995 $3,520 Other raw materials and unfinished products(1) 1,496 1,292 Refined products(2) 27,133 17,440 Process chemicals(3) 1,371 909 Repairs and maintenance supplies and other 2,181 1,276 ------------------------------------------------------------------------- $37,176 $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. 5. 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 petroleum and natural gas properties and facilities. ------------------------------------------------------------------------- ($000) Six months ended Year ended June 30, December 31, 2007 2006 ------------------------------------------------------------------------- Asset retirement obligations, beginning of period $7,322 $3,108 Liabilities incurred 5,319 2,384 Liabilities acquired - 2,109 Liabilities disposed - (864) Change in estimated future cash flows - 237 Accretion expense 433 348 ------------------------------------------------------------------------- Asset retirement obligations, end of period $13,074 $7,322 ------------------------------------------------------------------------- Liabilities incurred in 2007 have been estimated using a discount rate of eight percent to reflect the company's credit-adjusted risk free interest rate given its current capital structure. 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. 6. RELATED PARTY TRANSACTIONS In May 2007, the company exercised its right to purchase 1.7 million additional common shares in Petrolifera for total consideration of $5.1 million. As a result, the company maintained its 26 percent equity interest, as other Petrolifera shareholders similarly exercised their right to purchase additional common shares in Petrolifera on identical terms. As a consequence of this investment, the company's carrying value of its Petrolifera investment holding increased to cause a dilution gain of $1.9 million. 7. LONG TERM DEBT On May 25, 2007 Connacher issued senior unsecured subordinated convertible debentures with a face value of $100,050,000. The debentures mature June 30, 2012 unless converted prior to that date and bear interest at an annual rate of 4.75 percent payable semiannually on June 30 and December 31. The debentures are convertible at any time into common shares at the option of the holder at a conversion price of $5 per share. The debentures are redeemable or after June 30, 2010 by the company, in whole or in part at a redemption price equal to 100 percent of the principal amount of the debentures to be redeemed plus accrued and unpaid interest provided that the market price of the company's common shares is at least 120 percent of the conversion price of the debentures. The conversion feature of the debentures has been accounted for as a separate component of equity in the amount of $16,823,000. The remainder of the net proceeds of the debentures of $79,243,000 has been recorded as long-term debt, which will be accreted up to the face value of $100,050,000 over the five-year term of the debentures. Accretion and interest paid are recorded as finance charges on the consolidated statement of operations. If the debentures are converted to common shares, the value of the conversion feature will be reclassified to share capital along with the principal amounts converted. Convertible debenture initially recognized, less issue costs of $2.8 million net of income taxes of $1.2 million $80,463 Accretion to June 30, 2007 324 ------------------------------------------------------------------------- 80,787 ---------------------- ---------------------- Oil sands term loan 191,772 ------------------------------------------------------------------------- $272,559 ------------------------------------------------------------------------- ------------------------------------------------------------------------- During the second quarter of 2007 the company's revolving line of credit, backed by its conventional reserve base, was renewed for $50 million for one year. 8. 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) ------------------------------------------------------------------------- Share Capital: Balance, December 31, 2006 197,894,015 $363,082 Issued upon exercise of options (a) 830,933 556 Shares issued to directors as compensation (b) 108,975 393 Assigned value of options exercised - 195 Tax effect of expenditures renounced pursuant to the issuance of flow-through common shares (c) (9,000) Share issue costs (38) ------------------------------------------------------------------------- Balance, Share Capital, June 30, 2007 198,833,923 $355,188 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Contributed Surplus: Balance, December 31, 2006 $13,418 Fair value of share options granted 3,996 Assigned value of options exercised (195) ------------------------------------------------------------------------- Balance, Contributed Surplus, June 30, 2007 $17,219 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Equity component of convertible debentures, June 30, 2007 $16,823 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total Share Capital, Contributed Surplus and equity component: ------------------------------------------------------------------------- December 31, 2006 $376,500 ------------------------------------------------------------------------- June 30, 2007 $389,230 ------------------------------------------------------------------------- (a) Stock options A summary of the company's outstanding stock options, as at June 30, 2007 and 2006 and changes during those periods is presented below: ------------------------------------------------------------------------- 2007 2006 ------------------------------------------------------------------------- Weighted Weighted Average Average Number of Exercise Number of Exercise Options Price Options Price ------------------------------------------------------------------------- Outstanding, beginning of period 16,212,490 $3.31 8,592,600 $1.49 Granted 3,349,597 3.86 7,777,300 4.94 Exercised (830,933) (0.70) (742,699) (0.72) Expired (982,000) (3.60) - - ------------------------------------------------------------------------- Outstanding, end of period 17,749,154 $3.52 15,627,201 $3.24 ------------------------------------------------------------------------- Exercisable, end of period 9,693,064 $3.10 5,140,198 $2.56 ------------------------------------------------------------------------- All stock options have been granted for a period of five years. Options granted under the plan are generally fully exercisable after two or three years and expire five years after the date granted. The table below summarizes unexercised stock options. ------------------------------------------------------------------------- Weighted Average Remaining Range of Exercise Prices Contractual Life at Number June 30, Outstanding 2007 ------------------------------------------------------------------------- $0.20 - $0.99 2,415,302 2.4 $1.00 - $1.99 1,766,000 2.9 $2.00 - $3.99 6,438,597 4.2 $4.00 - $5.56 7,129,255 3.8 ------------------------------------------------------------------------- 17,749,154 ------------------------------------------------------------------------- In the first six months of 2007 a compensatory non-cash expense of $4.4 million (2006 - $7.1 million) was recorded, reflecting the amortization of the fair value of stock options over the vesting period and the fair value of shares granted to directors. Of this amount, $3.3 million (2006 - $5.2 million) was expensed and $1.1 million (2006 - $1.9 million) was capitalized to property and equipment. In the second quarter of 2007 a compensatory non-cash expense of $875,000 (2006 - $6.5 million) was recorded, reflecting the amortization of the fair value of stock options over the vesting period and the fair value of shares granted to directors. Of this amount, $333,000 (2006 - $4.8 million) was expensed and $542,000 (2006 - $1.7 million) was capitalized to property and equipment. The fair value of each stock option granted is estimated on the date of grant using the Black-Scholes option-pricing model with weighted average assumptions for grants as follows: ------------------------------------------------------------------------- 2007 2006 ------------------------------------------------------------------------- Risk free interest rate 4.5% 4.1.% Expected option life (years) 3 3 Expected volatility 52% 48% ------------------------------------------------------------------------- The weighted average fair value at the date of grant of all options granted in the first six months of 2007 was $1.52 per option (2006 - $1.81). (b) Deferred share award plan for non-employee directors Shareholders of the company approved a deferred share award incentive plan for non-employee directors at the company's Annual and Special meeting of Shareholders on May 10, 2007. Under the plan, a total of 326,925 deferred share units were awarded to non-employee directors. In June 2007, 108,975 common shares were issued to directors as compensation under the plan. The remaining 217,950 deferred share units vest one-half on January 1, 2008 and one-half on January 1, 2009. Under the deferred share award plan, deferred share units may be granted to non-employee directors of the company in amounts determined by the Board of Directors on the recommendation of the Governance Committee. Payment under the plan is made by delivering common shares to non- employee directors either through purchases on the TSX or by issuing shares from treasury, subject to certain limitations. The Board of Directors may also elect to pay cash equal to the fair market value of the common shares to be delivered to non-employee directors upon vesting of such deferred share units in lieu of delivering shares. In the first six months of 2007, $393,000 was charged to expense in respect of awards granted under the deferred share award plan. (c) Flow through shares Effective December 31, 2006, the company renounced $30 million of resource expenditures to flow-through investors. The related tax effect of $9 million of these expenditures was recorded in 2007. The company incurred all of the required expenditures related to these flow-through shares in 2006 and 2007. 9. COMMODITY PRICE RISK MANAGEMENT During the first quarter of 2007 the company entered into a costless collar arrangement whereby the sales price for 5,000 mmbtu per day of the company's natural gas production was fixed within a range of US$7.00 per mmbtu - US$9.50 per mmbtu. The effective date of the arrangement commenced April 1, 2007 and continues until October 31, 2007. At June 30, 2007 the fair value of this collar was an asset of $282,000, which has been recorded in accounts receivable on the consolidated balance sheet and the gain has been included in PNG revenue. 10. SEGMENTED INFORMATION In Canada, the company is in the business of exploring and producing conventional petroleum and natural gas and is engaged in the 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. 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. ------------------------------------------------------------------------- Canada Canada Oil and Adminis- USA ($000) Gas trative Refining Total ------------------------------------------------------------------------- Three months ended June 30, 2007 Revenues, net of royalties $8,413 $- $84,628 $93,041 Equity interest in Petrolifera earnings - 1,214 - 1,214 Dilution gain - 1,896 - 1,896 Interest and other income 111 - 114 225 Crude oil purchases and operating costs 2,660 - 66,480 69,140 General and administrative - 1,663 - 1,663 Stock-based compensation - 333 - 333 Finance charges - 1,264 - 1,264 Foreign exchange loss (gain) (14,486) - - (14,486) Depletion, depreciation and accretion 5,891 - 1,472 7,363 Tax provision 3,197 - 5,674 8,871 Net earnings (loss) 11,262 (150) 11,116 22,228 Property and equipment, net 517,584 2,788 49,160 569,532 Capital expenditures 89,713 783 2,727 93,223 Total assets 668,691 36,537 116,699 821,927 ------------------------------------------------------------------------- Three months ended June 30, 2006 Revenues, net of royalties $10,171 $- $50,967 $61,138 Equity interest in Petrolifera earnings - 2,200 - 2,200 Dilution gain (loss) - (51) - (51) Interest and other income 15 - 86 101 Crude oil purchases and operating costs 2,468 - 46,979 49,447 General and administrative - 1,343 - 1,343 Stock-based compensation - 4,800 - 4,800 Finance charges - 224 2,931 3,155 Foreign exchange loss (gain) 31 - - 31 Depletion, depreciation and accretion 9,158 - 855 10,013 Tax provision (recovery) (2,797) - (185) (2,982) Net earnings (loss) 1,326 (4,218) 473 (2,419) Property and equipment, net 253,899 759 43,305 297,963 Capital expenditures and acquisitions 34,023 - 257 34,280 Total assets 384,824 759 107,276 492,859 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Canada Canada Oil and Adminis- USA ($000) Gas trative Refining Total ------------------------------------------------------------------------- Six months ended June 30, 2007 Revenues, net of royalties $16,620 $- $142,224 $158,844 Equity interest in Petrolifera earnings - 5,114 - 5,114 Dilution gain - 1,896 - 1,896 Interest and other income 124 - 221 345 Crude oil purchases and operating costs 4,592 - 112,878 117,470 General and administrative - 5,248 - 5,248 Stock-based compensation - 3,279 - 3,279 Finance charges - 1,710 - 1,710 Foreign exchange loss (gain) (16,188) - - (16,188) Depletion, depreciation and accretion 11,992 - 2,729 14,721 Tax provision (recovery) 3,419 - 9,328 12,747 Net earnings (loss) 12,929 (3,227) 17,510 27,212 Property and equipment, net 517,584 2,788 49,160 569,532 Capital expenditures and acquisitions 195,435 1,825 5,844 203,104 Total assets 668,691 36,537 116,699 821,927 ------------------------------------------------------------------------- Six months ended June 30, 2006 Revenues, net of royalties $13,382 $- $50,967 $64,349 Equity interest in Petrolifera earnings and dilution gain - 2,589 - 2,589 Dilution gain - 52 - 52 Interest and other income 431 - 94 525 Crude oil purchases and operating costs 3,300 - 46,979 50,279 General and administrative - 2,299 - 2,299 Stock-based compensation - 5,194 - 5,194 Finance charges - 308 2,931 3,239 Foreign exchange loss (gain) 38 - - 38 Depletion, depreciation and accretion 12,035 - 855 12,890 Tax provision (recovery) (3,154) - (185) (3,339) Net earnings (loss) 1,594 (5,160) 481 (3,085) Property and equipment, net 253,899 759 43,305 297,963 Capital expenditures 268,832 - 66,284 335,116 Total assets 384,824 759 107,276 492,859 ------------------------------------------------------------------------- 11. SUPPLEMENTARY INFORMATION (a) Per share amounts The following table summarizes the common shares used in per share calculations. ------------------------------------------------------------------------- For the three months ended June 30 2007 2006 ------------------------------------------------------------------------- Weighted average common shares outstanding 190,360,390 191,671,650 Dilutive effect of stock options and deferred share units 2,591,943 7,259,755 ------------------------------------------------------------------------- Dilutive effect of convertible debentures 8,135,934 - ------------------------------------------------------------------------- Weighed average common shares outstanding - diluted 209,088,267 198,931,405 ------------------------------------------------------------------------- ------------------------------------------------------------------------- For the six months ended June 30 2007 2006 ------------------------------------------------------------------------- Weighted average common shares outstanding 198,240,426 173,015,395 Dilutive effect of stock options and deferred share units 2,431,527 7,400,274 ------------------------------------------------------------------------- Dilutive effect of convertible debentures 4,090,442 - ------------------------------------------------------------------------- Weighed average common shares outstanding - diluted 204,762,395 180,415,669 ------------------------------------------------------------------------- For the three and six months ended June 30, 2007, $562,600 of interest and accretion expense on the convertible debentures has been added to net income in the numerator of the diluted earnings per share calculation. (b) Net change in non-cash working capital ------------------------------------------------------------------------- For the three months ended June 30 2007 2006 ------------------------------------------------------------------------- ($000) ------------------------------------------------------------------------- Accounts receivable $(12,350) $(26,769) Refinery inventories 1,819 (8,031) Due from Petrolifera (38) 164 Prepaid expenses (1,012) (1,245) Accounts payable and accrued liabilities (2,753) 7,513 Income taxes payable (7,079) - ------------------------------------------------------------------------- Total $(21,413) $(28,368) ------------------------------------------------------------------------- Summary of working capital changes: ------------------------------------------------------------------------- For the three months ended June 30 2007 2006 ------------------------------------------------------------------------- ($000) ------------------------------------------------------------------------- Operations $(43,062) $(37,742) Investing 21,649 9,374 ------------------------------------------------------------------------- $(21,413) $(28,368) ------------------------------------------------------------------------- ------------------------------------------------------------------------- For the six months ended June 30 2007 2006 ------------------------------------------------------------------------- ($000) ------------------------------------------------------------------------- Accounts receivable $(12,532) $(29,207) Due from Petrolifera 73 (5) Prepaid expenses (646) (1,256) Refinery inventories (12,738) (8,031) Accounts payable and accrued liabilities 11,832 19,218 Income taxes payable (7,586) - ------------------------------------------------------------------------- Total $(21,597) $(19,281) ------------------------------------------------------------------------- Summary of working capital changes: ------------------------------------------------------------------------- For the six months ended June 30 2007 2006 ------------------------------------------------------------------------- ($000) Operations $(36,141) $(33,499) Investing 14,544 14,218 ------------------------------------------------------------------------- $(21,597) $(19,281) ------------------------------------------------------------------------- (c) Supplementary cash flow information ------------------------------------------------------------------------- For the three months ended June 30 2007 2006 ------------------------------------------------------------------------- ($000) $ $ ------------------------------------------------------------------------- Interest paid 4,152 855 Income taxes paid 6,107 - Stock-based compensation capitalized 542 1,704 ------------------------------------------------------------------------- ------------------------------------------------------------------------- For the six months ended June 30 2007 2006 ------------------------------------------------------------------------- ($000) $ $ ------------------------------------------------------------------------- Interest paid 7,599 932 Income taxes paid 9,146 - Stock-based compensation capitalized 1,088 1,914 ------------------------------------------------------------------------- At June 30, 2007 cash of $4.5 million (December 31, 2006 - $122.8 million) is restricted for use in paying expenditures for a designated oil sands project under the terms of the company's financing arrangements for its oil sands project. (d) Defined benefit pension plan In the first six months of 2007, $252,000 (2006 - $124,000) has been charged to expense in relation to the refinery's defined benefit pension plan. 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.

For further information:

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


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