Connacher reports strong second quarter 2009 earnings, buoyed by foreign exchange gains; Positive upstream and downstream results; Finances strengthened; Algar construction progressing favorably; Drilling of Algar SAGD well pairs underway



    CALGARY, Aug. 12 /CNW/ - Connacher Oil and Gas Limited (CLL-TSX) made
substantial progress during the second quarter of 2009 ("Q2 2009"). Strong
earnings were achieved, buoyed by foreign exchange gains and much improved
upstream and downstream operating results, compared to the prior quarter ("Q1
2009"). Including the value of intercompany sales of diluent to our Great
Divide Pod One ("Pod One"), our refining division earned a net margin of $3.5
million, or seven percent in the quarter. Year-to-date ("YTD" or "YTD 2009"),
our refining margin totaled approximately $6 million on sales of approximately
$102 million or approximately six percent. We remain optimistic about third
quarter 2009 ("Q3 2009") refining results due to anticipated strong asphalt
sales, although we do have a planned refinery turnaround in September 2009.
Our upstream division recorded much improved results over the difficult prior
quarter. As a consequence we had positive cash flow from operations before
changes in non-cash working capital and other ("cash flow") which more than
offset negative cash flow in Q1 2009.
    Our focus in the reporting period was on strengthening our financial
condition to be positioned to reactivate our Algar project, which we have done
successfully. We are making good progress in our plant construction and
recently initiated drilling of the 17 steam-assisted gravity drainage ("SAGD")
well pairs now planned on three drilling pads with two modern rigs. We
continue to post pictures of our progress on our website on the cover page at
www.connacheroil.com as we count down our progress to completion of the plant
and related facilities.
    We remain optimistic about our outlook as we continue our rampup of
bitumen production at Pod One, which averaged 6,284 bbl/d in the second
quarter. Our production rampup has been held back, in part arising from the
decision to curtail production earlier in the year, as a result of the
installation of four electrical submersible pumps ("ESP") in the second
quarter and because of a number of anomalous operating issues. We continue to
target bitumen production rampup to near design capacity later in 2009, after
completion of a mini-plant turnaround and anticipate installation of
additional ESP's. We remain focused on our long term goal of developing and
producing 50,000 bbl/d of bitumen by 2015.

    These Q2 2009 results will be subject to a Conference Call event at 9:00
a.m. MDT August 13, 2009. To listen to or participate in the live conference
call please dial either (416) 644-3426 or (800) 731-5774. A replay of the
event will be available from August 13, 2009 at 11:00 p.m. MT until August 20,
2009 at 11:59 p.m. MT. To listen to the replay please dial either (416)
640-1917 or (877) 289-8525 and enter the passcode 21311159 followed by the
pound sign.

    OVERVIEW

    The overall operating environment for the Canadian crude oil and natural
gas industry improved during the second quarter of 2009, as crude oil prices
were considerably stronger than during the prior reporting period ("Q1 2009"),
although they remained much below levels realized one year ago. However, the
recent strength in crude oil prices was offset by a decline in natural gas
prices, which were considerably weaker than during the prior quarter and last
year. While the impact of a stronger Canadian dollar on our revenues in Q2
2009 muted some of the benefit of increased oil prices, it favorably impacted
the carrying cost of our U.S. dollar-denominated debt, resulting in
substantial unrealized foreign exchange gains for the period.
    Both upstream and downstream netbacks were stronger and contributed to
improved financial results in Q2 2009. A strong third quarter 2009 ("Q3 2009")
is anticipated in the downstream division from the realization of high priced
asphalt sales, which were slower than expected due to poor weather conditions
for paving activity.
    Positive cash flow was achieved after two quarters of negative cash flow,
which had resulted from the collapse of energy prices. Earnings were strong in
Q2 2009, due to a significant foreign exchange gain and almost offset the
adverse effects of a weakening Canadian dollar in Q1 2009. Despite this
improvement, 1H 2009 results remained below those achieved in the same period
in 2008, primarily due to the collapse of energy prices on a comparative
basis.
    Our emphasis during Q2 2009 and YTD 2009 (or "1H 2009") was on restoring
Connacher's overall financial strength and liquidity, which had been adversely
impacted upon since year end 2008 by the weakness in commodity prices and
their impact on operating and financial results; the effect of our decision to
reduce bitumen production to minimize losses at Pod One in late 2008 and early
2009, when prices were low and heavy oil differentials were very high; normal
seasonal weakness in our downstream refining division; and our decision in Q1
2009 to cancel our credit facilities aggregating in excess of $200 million.
These developments, when combined with negative first quarter cash flow, a
responsible but controlled outlay of cash for capital projects and a reduction
in accounts payable, together with debt servicing requirements, had reduced
our cash balances and meant that our ability to be able to restore and
complete the Algar project, with confidence, required more corporate
liquidity.
    Fortunately, Connacher was able to access equity and debt markets in Q2
2009 and raised total net proceeds of $370 million, which added the requisite
liquidity and positioned the company to restore its growth profile. Subsequent
to closing both our equity and debt issues, we were able to announce the
resumption of construction at Algar, our second 10,000 bbl/d steam-assisted
gravity drainage project. Our ability to access capital markets and to attract
a high level of sponsorship from significant institutional investors
underscored the attractiveness of Connacher's growth prospects and the ongoing
long-term appeal of the oil sands sector.
    Our equity issue was a fully-marketed deal, allowing existing
shareholders to participate through the investment dealer syndicate if they
elected to do so. While the size of the issue resulted in a discount to the
prevailing market, its success enabled us to successfully place and realize
improved pricing for our new long-term debt offering.
    Our new bond issue, which matures in 2014 and does not require principal
repayments until that time, was well received and was also largely acquired by
recognized long-term investors. This added capital was secured without
exposing the company and its operations to a myriad of problematic maintenance
covenants. We continue to negotiate the terms of a follow-on revolving bank
credit facility to further enhance our total corporate financial flexibility.
    Our liquidity runway was extended as a consequence of this financing
activity and this gave us the confidence to conclude we could reactivate
Algar, supported by the improvement in crude oil markets from the devastating
lows experienced in late 2008.
    Algar is now proceeding favorably and we anticipate completing the plant
and related SAGD horizontal well pairs by approximately April, 2010.
Thereafter, we envisage approximately one month to commission the plant,
followed by approximately three months of steaming of the well pairs, with a
view to first bitumen production at Algar by mid-summer 2010 and ramping up
thereafter, to near plant capacity by late 2010 or early 2011. At that time,
our bitumen production should be approximately double or more than what it is
today. We believe there are few if any other Canadian companies that have this
visibility of solid, predictable and near-term production growth ahead of
them. We hope to double it again in the ensuing two-three years, once our
Environmental Impact Assessment ("EIA") is approved and we realize more of the
established productive potential from our oil sands properties in the Divide
region of northeast Alberta ("Great Divide"). We continue to adhere to our
target of 50,000 bbl/d of bitumen production by 2015.

    
    Highlights of the second quarter and first half of 2009 were as follows:

    -   $370 million of new equity and debt capital raised; liquidity runway
        extended

    -   Algar project reinstated in early July 2009

    -   Improved financial and operating results achieved during Q2 2009

    -   Pod One rampup continues with lower operating costs and improving
        netbacks

    Summary Results

    -------------------------------------------------------------------------
                     Three months ended June 30     Six months ended June 30
    -------------------------------------------------------------------------
                                              %                            %
                         2009      2008  Change       2009      2008  Change
    -------------------------------------------------------------------------
    FINANCIAL ($000
     except per share
     amounts)

    Revenues, net
     of royalties     100,219   202,016     (50)   161,976   302,672     (46)
    Cash flow(1)        9,570    20,550     (53)     4,878    28,375     (83)
      Per share,
       basic(1)          0.04      0.10     (60)      0.02      0.14     (86)
      Per share,
       diluted(1)        0.03      0.10     (70)      0.02      0.13     (85)
    Net earnings
     (loss)            39,966     6,683     489     (6,878)    4,850    (255)
    Per share,
     basic (loss)        0.15      0.03     400      (0.03)     0.02    (250)
    Per share,
     diluted (loss)      0.14      0.03     367      (0.03)     0.02    (250)
    Property and
     equipment
     additions         40,236    80,403     (50)   104,491   196,388     (47)
    Cash on hand                                   401,160   232,704      72
    Working capital                                455,001   234,110      94
    Long term debt                                 960,593   684,705      40
    Shareholders'
     equity                                        622,235   479,477      30
    Total assets                                 1,723,370 1,338,705      29

    UPSTREAM
     OPERATING RESULTS
    Daily production/
     sales volumes
      Bitumen -
       bbl/d(2)         6,284     6,123       3      6,227     3,948      58
      Crude oil -
       bbl/d            1,114       981      14      1,147       988      16
      Natural gas -
       Mcf/d           12,144    14,220     (15)    12,484    12,356       1
      Barrels of oil
       equivalent
       - boe/d(3)       9,421     9,474      (1)     9,455     6,996      35
    Product pricing(4)
      Bitumen -
       $/bbl(2)         40.95     60.80     (48)     31.84     59.05     (46)
      Crude oil -
       $/bbl            54.87    105.28     (48)     47.07     92.29     (49)
      Natural gas -
       $/Mcf             3.35     10.02     (67)      4.13      9.08     (55)
      Barrels of oil
       equivalent -
       $/boe(3)         38.11     65.25     (42)     32.13     62.41     (49)

    DOWNSTREAM
     OPERATING RESULTS
    Refining
     throughput -
     crude charged
     - bbl/d            9,145     9,329      (2)     8,012     9,580     (16)
    Refinery
     utilization (%)       96      98.2      (2)        84     100.8     (17)
    Margins (%)             5      (0.1)  5,100          6       0.2   2,900

    COMMON SHARES
     OUTSTANDING (000)
    Weighted average
      Basic           266,425   210,658      26    239,008   210,446      14
      Diluted         286,985   214,530      34    239,008   213,324      12
    End of period
      Issued                                       403,546   211,027      91
      Diluted                                      439,890   250,522      76
    -------------------------------------------------------------------------
    (1) Cash flow and cash flow per share do not have standardized meanings
        prescribed by Canadian generally accepted accounting principles
        ("GAAP") and therefore may not be comparable to similar measures used
        by other companies. Cash flow is calculated before changes in non-
        cash working capital, pension funding and asset retirement
        expenditures. The most comparable measure calculated in accordance
        with GAAP would be net earnings. Cash flow, commonly used in the oil
        and gas industry, 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 internally fund future growth expenditures.
    (2) The recognition of bitumen sales from Great Divide Pod One commenced
        March 1, 2008, when it was declared "commercial". Prior thereto, all
        operating costs, net of revenues, were capitalized.
    (3) All references to barrels of oil equivalent (boe) are calculated on
        the basis of 6 Mcf:1 bbl. This conversion is based on an energy
        equivalency conversion method primarily applicable at the burner tip
        and does not represent a value equivalency at the wellhead. Boes may
        be misleading, particularly if used in isolation.
    (4) Product pricing excludes realized financial derivative gains/losses
        and unrealized mark-to-market non-cash accounting gains/losses.
    


    Operating conditions improved for the Canadian oil industry during Q2
2009 as crude oil prices improved considerably. Our conventional oil prices
were up 38 percent from Q1 2009 to $54.87 per barrel. Our bitumen selling
prices almost doubled to $40.95 per barrel compared to Q1 2009. Also, in June
2009 our crude oil prices were at their highest level of the year at $65.56
per barrel for our quality of conventional crude oil sales and at $50.29 per
barrel of bitumen, net of diluent and transportation charges.
    This strength in crude oil pricing was particularly important to
Connacher, as we are highly leveraged to crude oil prices and their impact on
our valuation and our operating results. However, like all producers, we also
felt the adverse effect of weak natural gas prices, which were only about 45
percent of 1H 2008 levels at $4.13/mcf, when compared to $9.08/mcf last year.
Fortunately, these lower prices contributed to lower bitumen operating costs
as Connacher is substantially indifferent to natural gas price levels, in that
we consume approximately the same amount of natural gas as the company's
current production levels. This underscores the importance of the integrated
strategy we adopted for our oil sands business several years ago.
    Improved overall prices enabled Connacher to record positive Q2 2009
improvements in our upstream production netbacks, which were almost triple
those recorded in our Q1 2009 reporting period. While these remain below the
much stronger levels achieved in 1H 2008, when product pricing per barrel of
oil equivalent ("boe") was almost 50 percent higher than that achieved YTD
2009, the direction and rate of improvement during Q2 2009 was discernible.
    As overall capital market and industry operating conditions remained
quite volatile, our 1H 2009 results did not fully capture the improved pricing
impact as a consequence of crude oil hedging programs put in place on a
portion of our production during the dark days of early 2009. These hedges
were designed to protect Connacher against continuing operating losses from
production, had crude oil prices further deteriorated below or remained at the
very low levels realized in December 2008. At that time, WTI had declined to
the U.S.$34/bbl level and heavy oil price differentials were as high as
$22/bbl, resulting in negative wellhead bitumen prices, before operating
costs. Obviously, hedging to enhance the probability of positive netbacks from
production made sense at the time. We will continue to manage our risk profile
utilizing timely and advantageous derivative programs during periods of high
capital expenditures, as we have a leveraged balance sheet.
    We are pleased to report that both our upstream and downstream divisions
recorded positive netbacks during the Q2 2009 and, in particular, the upstream
results more than offset negative recorded netbacks in Q1 2009. We also can
report that our cash flow from operations before working capital and other
changes ("cash flow") was much stronger in Q2 2009 and more than offset the
negative cash flow of Q1 2009.
    Earnings were also significantly improved in Q2 2009, primarily arising
from unrealized foreign exchange gains on the translation of our U.S.
dollar-denominated debt, resulting from a stronger Canadian dollar. These
unrealized gains more than offset unrealized foreign exchange losses sustained
in Q1 2009. As a result, we had earnings of $40 million in Q2 2009 and
recorded a modest loss for the first half of 2009. Again, these results were
below last year due to substantially lower commodity price levels in the
current year.

    Restoring Liquidity and Growth

    Our major activity during Q2 2009 was to restore our corporate liquidity
so we could again focus on growth. Since year end 2008, our cash balances were
reduced from approximately $224 million and would have declined to
approximately $31 million at June 30, 2009, had we not secured new sources of
funding for the company.
    Accordingly, this would not have allowed us to reinstate Algar without
new funding, especially as we had cancelled our $200 million plus credit
facility in Q1 2009. We had counted on this funding being available to
complete Algar when we earlier advised we had the requisite funds for
completions.
    Shareholders have asked where the cash was invested or spent so we are
happy to elaborate. During Q1 2009, we had capital expenditure outlays of $64
million, financed operations to the extent of $5 million and used $59 million
of cash for working capital purposes, including paying down our accounts
payable and financing our asphalt and other inventory buildups in our
downstream operation. This reduced our March 31, 2009 cash balances to $96
million. Our capital outlays of $40 million in Q2 2009, combined with further
financing of working capital to the extent of $41 million was offset by $6
million in foreign exchange gains on U.S. dollar cash balances and cash flow
of $9.6 million, but our liquidity was strained.
    Because we had approximately $150 million of stranded capital already
invested in Algar and because we could not realize on this significant
investment and restore growth to the company without new funding, a decision
was made to raise cash funds to be able to proceed with Algar, with the
certainty we would have sufficient funds to complete while still meeting our
financial obligations and carrying the project through commissioning,
steaming, startup and rampup until Algar could begin to contribute higher
levels of production and resultant operating income and be recorded in our
accounts.
    We were able to access the equity markets during Q2 2009 and raised $164
million of net proceeds through an underwritten marketed sale of common equity
from treasury. While we attempted to secure the highest possible price for
this issue, market conditions dictated a clearing price of $0.90 per common
share to raise the amount of capital we felt we needed to achieve our
financing objectives. It resulted in the issuance of 192 million shares,
bringing our total shares outstanding to 403 million. As a marketed deal which
occurred over several days, all of our shareholders (except management and
directors) had the opportunity, if they chose to exercise it, to participate
in the financing through their broker/dealers. Regrettably, regulators
precluded "insider" participation (specifically management and directors),
despite the indicated willingness of certain of these individuals to acquire
shares in support of the transaction and the expressed preference by
prospective institutional buyers for insider participation and support of the
financing. Several insiders did subsequently acquire shares in public markets
at higher prices as a result of this regulatory decision, indicating their
continuing financial commitment to the growth and potential of the company.
    At the time of the equity financing, we had hoped to be able to secure
new bank financing in the form of a construction loan and revolving working
capital facility to have the desired certainty of funding before proceeding
with the reinstatement of Algar. Unfortunately suitable terms for a
construction loan were not forthcoming and accordingly we opted to access the
high yield bond market with the successful issuance of U.S.$200 million of
first lien senior secured notes. This issue was placed with a strong
contingent of long-term institutional buyers and has since traded at a premium
to the issue price of 93.678%. The notes have an 11.75% coupon and mature on
July 15, 2014. No principal payments are required in the intervening period.
Net proceeds received were $206 million at the time of closing of the debt
transaction.
    As a result of these two successful financings, Connacher not only
secured an expanded body of shareholders and noteholders with indicated
long-term investment objectives, but also was able to announce it was
reinstating the Algar project, reactivating the construction of its
cogeneration project and undertaking the building of a dilbit sales transfer
line from Algar to Pod One, while strengthening its working capital position
and overall corporate liquidity.
    We are now underway with construction at Algar and also should shortly
commence the drilling of the SAGD horizontal well pairs in order to be
completed within the approximate 275 day completion timetable established by
the company. We are regularly posting a slide show on our website at
www.connacheroil.com to demonstrate our progress at Algar and we have a
countdown clock to indicate our commitment to a timely completion of the
project. We will need cooperation from the weather to achieve our objective.
Also, where we can, we are attempting to secure improved costing of the
balance of the project, recognizing that many long lead items were built
throughout 2008 after we had established the original funding for the project.
    The deterioration in industry conditions, cancellation of our $200
million plus credit facilities in Q1 2009, delays necessitated by the extreme
economic and capital market uncertainty, weak commodity prices and the burden
of ongoing financial obligations, including a significant reduction in
accounts payable from approximately $100 million to approximately $47 million,
while also funding $104 million of capital expenditures in the first half of
2009, were behind the capital raising decisions. This was the only viable
manner by which we could have liberated the significant stranded capital
already invested in the Algar project. Our timing was fortuitous, as since we
completed our financing activity, commodity prices and capital markets have
been volatile, suggesting we would have been hard pressed to enter these
markets at a later date than needed. Also, the successful equity issue enabled
us to successfully place and secure better pricing and terms for our long-term
first lien notes.
    We now have an extended liquidity "runway", with no maintenance
covenants. We are operating with the certainty that our money is in the bank
and not subject to second-guessing by bank credit committees or the vagaries
of the credit markets, which remain extremely tight and expensive. We are
nearing conclusion of our negotiations to secure satisfactory terms and
conditions for a follow-on revolving bank credit facility, which if completed
would give us increased financial flexibility for our normal course business
activities, including the issuance of letters of credit and hedging
transactions to manage corporate risk.
    It is gratifying to be able to again focus on growth and progress. We
believe our assets are well-situated and of high quality and we are confident
in our plan going forward from here. We are advancing our EIA for further
development of our Great Divide reserves to an interim production level of
44,000 bbl/d of bitumen, representing a further 24,000 bbl/d beyond Pod One
and Algar. We hope to have the EIA approved in 2011, so that we can proceed to
expand to the 44,000 bbl/d level by approximately 2013, followed by a further
jump to 50,000 bbl/d of bitumen by 2015.
    We anticipate a significant improvement in the contribution to our
overall results from our downstream activities during Q3 2009, as the impact
of high priced asphalt sales and generally better economic conditions assist
this portion of our integrated business activity. Asphalt sales were generally
hampered by cold and wet weather in Montana and Alberta during Q2 2009, which
delayed road paving activities. As at June 30, 2009 we had over 430,000
barrels of asphalt in inventory, the majority of which had been contracted for
sale at prices in excess of U.S.$100 per barrel. We will be conducting a
scheduled turnaround at the Montana refinery during September 2009, but will
continue our aggressive asphalt sales from inventory during that period.
    Our upstream conventional activity remains quiet but stable as we await
indications of better natural gas markets to follow up on capturing
already-identified productive capacity. This would enable us to retain our
natural gas self-sufficiency quotient within our business model, timed to
meeting Algar start-up requirements.
    During Q2 2009, bitumen production at Pod One averaged approximately 63
percent of plant capacity. Production was affected by a number of minor
planned and unplanned interruptions. Power outages at the Pod One plant,
failure of a flare stack and unplanned evaporator maintenance all contributed
to a reduction in bitumen production during the quarter. Also we now have
installed five electric submersible pumps ("ESP's") which are contributing to
lower steam-oil ratios ("SOR's") and are also helping to lower operating costs
at a time when our focus is on optimization. This process has also been
assisted by lower natural gas prices and we have recently lowered unit
operating costs at Pod One to under $15 per barrel of bitumen. In July 2009,
we converted two new SAGD well pairs from the steam circulation phase to full
production, which will positively impact our bitumen production ramp-up. Our
Q3 2009 objective is to achieve steady state production at Pod One and
gradually move our plant utilization to 90 percent or better later this year.
We have a minor turnaround scheduled at Pod One in September 2009, lasting
between two days and four days. This will modestly impact on average daily
production levels.
    Our working capital at June 30, 2009 totaled $455 million including $401
million of cash. This underscored our preparedness for Algar and we anticipate
being able to manage any issues that might come our way until Algar comes on
stream. Our revised full year capital budget for Connacher for 2009 is now
$325 million, which will be financed from these cash balances and from cash
flow. The prize is the potential to more than double our bitumen production by
late 2010 or early 2011.
    The cost to complete Algar, excluding capitalized items and
contingencies, is estimated to be $360 million. Savings arising from remaining
activities occurring in a more "normalized" construction and labour
environment have been offset by minor scope changes to the project and the
decision to drill and complete two additional SAGD well pairs at Algar,
bringing the total SAGD well pairs to 17, to ensure effective exploitation of
the reservoir.
    In addition, to recognize unplanned events that often occur during a
major construction project and to factor unpredictable and often severe
weather that can occur in northern Alberta, management has added a $15 million
contingency to the Algar budget, bringing the total cost for Algar, excluding
capitalized items, to $375 million of which $128 million was incurred
pre-2009, $175 million is estimated to be incurred in 2009 and the $72 million
balance is forecast to be incurred in 2010.
    We look forward to delivering these results to you. We welcome our new
shareholders and appreciate the strong vote of confidence given to us in
moving ahead with our programs, as evidenced by the success of our recent
financings. We also appreciate the continuing support of all of our
shareholders as we work our way through these difficult but exciting times to
achieve our goals. We welcome Ms. Jennifer Kennedy, Mr. Peter Sametz and Mr.
Kelly Ogle as newly elected Directors and note the appointment of Ms. Rashi
Sengar, a partner of Macleod Dixon, as Connacher's Corporate Secretary.

    MANAGEMENT'S DISCUSSION AND ANALYSIS

    The following is dated as of August 12, 2009 and should be read in
conjunction with the unaudited consolidated financial statements of Connacher
Oil and Gas Limited ("Connacher" or the "company") for the six months ended
June 30, 2009 and 2008 as contained in this interim report and the MD&A and
audited consolidated financial statements for the years ended December 31,
2008 and 2007, as contained in the company's 2008 annual report. All of these
consolidated financial statements have been prepared in accordance with
Canadian generally accepted accounting principles ("GAAP") and are presented
in Canadian dollars. This MD&A provides management's view of the financial
condition of the company and the results of its operations for the reporting
periods.
    Additional information relating to Connacher, including Connacher's
Annual Information Form is on SEDAR at www.sedar.com.

    NON-GAAP MEASUREMENTS

    The MD&A contains terms commonly used in the oil and gas industry, such
as cash flow, cash flow per share, and cash operating netback. These terms are
not defined by GAAP and should not be considered an alternative to, or more
meaningful than, cash provided by operating activities or net earnings as
determined in accordance with GAAP as an indicator of Connacher's performance.
Management believes that in addition to net earnings, cash flow is a useful
financial measurement which assists in demonstrating the company's ability to
fund capital expenditures necessary for future growth or to repay debt.
Connacher's determination of cash flow may not be comparable to that reported
by other companies. All references to cash flow throughout this report are
based on cash flow from operating activities before changes in non-cash
working capital, pension funding and asset retirement expenditures. The
company calculates cash flow per share by dividing cash flow by the weighted
average number of common shares outstanding. Cash flow and cash operating
netbacks are reconciled to net earnings within this MD&A.

    FORWARD-LOOKING INFORMATION

    This report, including the Letter to Shareholders, contains
forward-looking information including but not limited expectations of future
production, refinery utilization rates and asphalt demand, future refined
product sales volumes and selling prices, netbacks, net operating income,
liquidity and cash flow, profitability and capital expenditures, operating
margins, anticipated reductions in operating costs as a result of optimization
of certain operations, development of additional oil sands resources
(including Algar and the timeline and capital costs for construction of
Algar), timing and duration of the planned refinery turnaround, development of
internally-generated growth prospects, utilization and alternative financial
derivative strategies to protect the company's cash flow and plans for
improving liquidity which may include securing a new banking credit facility,
corporate acquisitions or business combinations, joint venture arrangements
and restructuring components of the balance sheet. Forward looking information
is based on management's expectations regarding future growth, results of
operations, production, future commodity prices and foreign exchange rates,
future capital and other expenditures (including the amount, nature and
sources of funding thereof), plans for and results of drilling activity,
environmental matters, business prospects and opportunities and future
economic conditions. Forward-looking information involves significant known
and unknown risks and uncertainties, which could cause actual results to
differ materially from those anticipated. These risks include, but are not
limited to: the risks associated with the oil and gas industry (e.g.,
operational risks in development, exploration and production; delays or
changes in plans with respect to exploration or development projects or
capital expenditures; the uncertainty of reserve and resource estimates, the
uncertainty of estimates and projections relating to production, costs and
expenses, and health, safety and environmental risks), the risk of commodity
price and foreign exchange rate fluctuations, risks associated with the impact
of general economic conditions, risks and uncertainties associated with
securing and maintaining the necessary regulatory approvals and financing to
proceed with the continued expansion of the Great Divide Oil Sands Project. In
addition, the current financial crisis has resulted in severe economic
uncertainty and resulting illiquidity in credit and capital markets, which
increases the risk that actual results will vary from forward looking
expectations in this report and these variations may be material. There can be
no assurance that the company will be able to continue to secure sources of
liquidity. These and other risks and uncertainties are described in further
detail in Connacher's Annual Information Form for the year ended December 31,
2008, which is available at www.sedar.com. Although Connacher believes that
the expectations in such forward-looking information are reasonable, there can
be no assurance that such expectations shall prove to be correct. The
forward-looking information included in this report are expressly qualified in
their entirety by this cautionary statement. The forward-looking information
included in this report is made as of August 12, 2009 and Connacher assumes no
obligation to update or revise any forward-looking information to reflect new
events or circumstances, except as required by law.
    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.

    
    SUMMARIZED HIGHLIGHTS

                                  Three months ended        Six months ended
                                             June 30                 June 30
                                    2009        2008        2009        2008
    -------------------------------------------------------------------------
    FINANCIAL
    ($000)
    Upstream revenues, net
     of royalties             $   33,882  $   83,483  $   62,028  $  111,409
    Downstream revenues           69,094     117,820     102,246     189,719
    Upstream cash operating
     netback(1)                   12,893      30,857      17,894      45,113
    Downstream margin              3,483        (106)      5,915         400
    Cash flow                      9,570      20,550       4,878      28,375
    Net earnings (loss)           39,966       6,683      (6,878)      4,850
    Cash on hand                                         401,160     232,704
    Working capital                                      455,001     234,110
    Total assets                                       1,723,370   1,338,705

    OPERATING

    Upstream production/
     sales volumes
    Oil sands - bitumen
     - bbl/d                       6,284       6,123       6,227       3,948
    Crude oil - bbl/d              1,114         981       1,147         988
    Natural gas - Mcf/d           12,144      14,220      12,484      12,356
    Barrels of oil
     equivalent - boe/d            9,421       9,474       9,455       6,996
    Upstream cash
     netback/boe(1)           $    15.04  $    35.79  $    10.46  $    35.43
    Downstream
    Crude charged - bbl/d          9,145       9,329       8,012       9,580
    Downstream margin per
     barrel refined           $     4.05  $    (0.09) $     4.25  $     0.21
    Downstream margins as
     a percentage of
     revenue - %                       5        (0.1)          6           -
    -------------------------------------------------------------------------
    (1) Excluding unrealized non-cash mark-to-market accounting losses.
    

    MARKETING - UPSTREAM

    Diluted bitumen ("dilbit"), crude oil and natural gas are generally sold
on month-to-month sales contracts negotiated with major Canadian or U.S.
marketers, refiners or other end users at either spot reference prices or at
prices subject to commodity contracts based on U.S. WTI for crude oil and AECO
for natural gas. As a means of managing the risk of commodity price
volatility, Connacher enters into financial derivative commodity price-hedging
contracts from time to time.

    At August 12, 2009, Connacher had the following WTI crude oil
price-hedging contracts in place:

    
    -   February 1, 2009 - August 31, 2009 - 2,500 bbl/d - WTI
        U.S.$46.00/bbl;

    -   April 1, 2009 - December 31, 2009 - 2,500 bbl/d - WTI U.S.$49.50/bbl;
        and

    -   September 1, 2009 - December 31, 2009 - 2,500 bbl/d - minimum of WTI
        U.S.$60.00/bbl and a maximum of WTI U.S.$84.00/bbl.
    

    As at June 30, 2009, the WTI crude oil forward price curve exceeded the
hedging contract prices resulting in a current liability and an unrealized
mark-to-market ("MTM") non-cash accounting loss of $16.5 million for these
contracts. For the year to date, realized losses on these contracts totalled
$5.7 million. These losses are included in upstream revenues.
    Additionally, in order to mitigate foreign exchange exposure to commodity
pricing, Connacher entered into a foreign exchange revenue collar which
throughout 2009 sets a floor of CAD$1.1925 per U.S.$1.00 and a ceiling of
CAD$1.30 per U.S.$1.00 on a notional amount of U.S.$10 million of monthly
production revenue. For clarity, this contract provides the company a benefit
from a strengthening Canadian dollar. As at June 30, 2009, based on the
forward foreign exchange rate curve, the foreign exchange revenue collar had a
value of $3.1 million; at December 31, 2008 it had a value of $1.8 million.
The change in these values resulted in an unrealized non-cash foreign exchange
gain of $1.3 million in the first half of 2009. Additionally, in the first
half of 2009, Connacher realized a hedging gain (and received cash) in the
amount of $1.1 million on this contract. These gains are included in foreign
exchange gains/losses.
    During the first half of 2009, Connacher also entered into a six-month
term contract for the sale of dilbit to a company operating a bitumen upgrader
in northern Alberta.

    MARKETING - DOWNSTREAM

    Sales of refined products are generally made on monthly sales contracts
negotiated with wholesalers, retailers and large end-users for gasoline, jet
fuel and diesel and construction contractors and road builders for asphalt.
Occasionally, sales contracts are for periods in excess of one month. To date,
Connacher has not hedged these revenue streams. As at June 30, 2009, the
Montana refinery had contracts in place for the sale of approximately 250,000
barrels of asphalt at an average price exceeding U.S.$100/bbl for delivery in
the third quarter of 2009.

    PRICING

    Together with many other uncontrolled variables, general economic
conditions and international and local supplies influence the price for WTI
light gravity crude oil. Weather, domestic supplies and other variables
influence the market price for natural gas.
    In the first half of 2009, WTI crude oil averaged U.S.$51.57/bbl (first
half 2008 - U.S.$110.94/bbl) and AECO natural gas averaged $4.64/Mcf (first
half 2008 - $8.24/Mcf).
    Connacher's crude oil and bitumen production slate is generally heavier
than the referenced WTI. Consequently, the market price realized by the
company is typically lower than WTI.

    Before hedging gains and unrealized MTM non-cash accounting losses,
Connacher realized the following commodity selling prices:

    
    Six months ended June 30                                2009        2008
    -------------------------------------------------------------------------
    Bitumen - $/bbl                                   $    31.84  $    59.05
    Crude oil - $/bbl                                      47.07       92.29
    Natural gas - $/Mcf                                     4.13        9.08
    -------------------------------------------------------------------------

    Refined product selling prices are also influenced by general economic
conditions and local and international supply and demand factors. Average
prices realized by the company in the first half of 2009 are noted below.

                                                               MRCI Realized
    Six months ended June 30, 2009 (U.S.$/bbl)                 Selling Price
    -------------------------------------------------------------------------
    Gasoline                                                      $    59.94
    Diesel                                                             63.91
    Jet fuel                                                           75.27
    Asphalt                                                            56.72
    -------------------------------------------------------------------------

    FINANCIAL AND OPERATING REVIEW

    UPSTREAM NETBACKS ($000)

    For the three months
     ended June 30, 2009     Oil Sands(1)  Crude Oil  Natural Gas      Total
    -------------------------------------------------------------------------
    Gross revenues(2)         $   40,571  $    5,649  $    3,697  $   49,917
    Diluent purchased(3)         (14,669)          -           -     (14,669)
    Transportation costs          (2,487)        (88)          -      (2,575)
    -------------------------------------------------------------------------
    Production revenue            23,415       5,561       3,697      32,673
    Realized financial
     derivative losses(4)         (6,161)          -           -      (6,161)
    Unrealized mark-to-
     market losses(5)             (8,243)          -           -      (8,243)
    Royalties                        (89)     (1,431)       (111)     (1,631)
    Operating costs               (8,459)       (949)     (2,580)    (11,988)
    -------------------------------------------------------------------------
    Calculated netback        $      463  $    3,181  $    1,006  $    4,650
    -------------------------------------------------------------------------
    Cash operating netback,
     excluding unrealized
     mark-to-market
     accounting losses(6)     $    8,706  $    3,181  $    1,006  $   12,893
    -------------------------------------------------------------------------


    For the three months
     ended June 30, 2008     Oil Sands(1)  Crude Oil  Natural Gas      Total
    -------------------------------------------------------------------------
    Gross revenues(2)         $   68,087  $    9,397  $   12,968  $   90,452
    Diluent purchased(3)         (31,272)          -           -     (31,272)
    Transportation costs          (2,934)          -           -      (2,934)
    -------------------------------------------------------------------------
    Production revenue            33,881       9,397      12,968      56,246
    Realized financial
     derivative losses(4)              -           -        (402)       (402)
    Unrealized mark-to-
     market losses(5)                  -           -      (1,217)     (1,217)
    Royalties                       (374)     (2,730)     (2,246)     (5,350)
    Operating costs              (16,281)       (810)     (2,546)    (19,637)
    -------------------------------------------------------------------------
    Calculated netback        $   17,226  $    5,857  $    6,557  $   29,640
    -------------------------------------------------------------------------
    Cash operating netback,
     excluding unrealized
     mark-to-market
     accounting losses(6)     $   17,226  $    5,857  $    7,774  $   30,857
    -------------------------------------------------------------------------


    For the six months
     ended June 30, 2009     Oil Sands(1)  Crude Oil  Natural Gas      Total
    -------------------------------------------------------------------------
    Gross revenues(2)         $   69,242  $    9,926  $    9,337  $   88,505
    Diluent purchased(3)         (28,036)          -           -     (28,036)
    Transportation costs          (5,324)       (158)          -      (5,482)
    -------------------------------------------------------------------------
    Production revenue            35,882       9,768       9,337      54,987
    Realized financial
     derivative losses(4)         (5,756)          -           -      (5,756)
    Unrealized mark-to-
     market losses(5)            (16,510)          -           -     (16,510)
    Royalties                       (219)     (2,493)     (1,499)     (4,211)
    Operating costs              (19,790)     (2,251)     (5,085)    (27,126)
    -------------------------------------------------------------------------
    Calculated netback        $   (6,393) $    5,024   $   2,753  $    1,384
    -------------------------------------------------------------------------
    Cash operating netback,
     excluding unrealized
     mark-to-market
     accounting losses(6)     $   10,117  $    5,024   $   2,753  $   17,894
    -------------------------------------------------------------------------


    For the six months
     ended June 30, 2008     Oil Sands(1)  Crude Oil  Natural Gas      Total
    -------------------------------------------------------------------------
    Gross revenues(2)         $   85,237  $   16,603  $   20,417  $  122,257
    Diluent purchased(3)         (39,375)          -           -     (39,375)
    Transportation costs          (3,428)          -           -      (3,428)
    -------------------------------------------------------------------------
    Production revenue            42,434      16,603      20,417      79,454
    Realized financial
     derivative losses(4)              -           -        (402)       (402)
    Unrealized mark-to-
     market losses(5)                  -           -      (2,033)     (2,033)
    Royalties                       (460)     (4,545)     (3,408)     (8,413)
    Operating costs              (19,684)     (1,870)     (3,972)    (25,526)
    -------------------------------------------------------------------------
    Calculated netback        $   22,290  $   10,188  $   10,602  $   43,080
    -------------------------------------------------------------------------
    Cash operating netback,
     excluding unrealized
     mark-to-market
     accounting losses(6)     $   22,290  $   10,188  $   12,635  $   45,113
    -------------------------------------------------------------------------

    (1) In the first quarter of 2008, Connacher completed the conversion of a
        majority of its fifteen horizontal well pairs to production status at
        Great Divide Pod One and processed increasing levels of bitumen
        through its facility. This provided the company with the necessary
        confidence that this first oil sands project could economically
        produce, process and sell bitumen on a continuous basis. Therefore,
        effective March 1, 2008 Connacher declared it to be "commercial". As
        a result, the company discontinued the capitalization of all pre-
        operating costs, moved accumulated capital costs into the full cost
        pool, commenced the depletion of these costs, and began reporting Pod
        One production and operating results as part of the oil and gas
        reporting segment. The above tables, therefore, do not include
        operating results prior to March 1, 2008.
    (2) Bitumen produced at Great Divide Pod One is mixed with purchased
        diluent and sold as "dilbit". Diluent is a light hydrocarbon that
        improves the marketing and transportation quality of bitumen. In the
        financial statements Upstream Revenues represent sales of dilbit,
        crude oil and natural gas, net of royalties; and Upstream Operating
        Costs include the cost of purchased diluent.
    (3) Diluent volumes purchased and sold have been deducted in calculating
        production revenue and production volumes sold.
    (4) Realized financial derivative gains/losses reflect cash
        receipts/disbursements in respect of financial derivative commodity
        price-hedging contracts.
    (5) Unrealized mark-to-market accounting gains/losses reflect changes in
        the market value of unsettled commodity price derivative contracts.
        From period to period the market value of these contracts change due
        to the volatility of the commodity's forward pricing curve.
    (6) Cash operating netbacks, by product, are calculated by deducting the
        related diluent, transportation, field operating costs and royalties
        from revenues before deducting MTM accounting gains/losses. Netbacks
        on a per-unit basis are calculated by dividing related production
        revenue, costs and royalties by production volumes. 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 widely used in the oil and gas industry as a
        supplemental measure of the company's efficiency and its ability to
        fund future growth through capital expenditures. Netbacks are
        reconciled to net earnings below.


    UPSTREAM SALES AND PRODUCTION VOLUMES

    For the three months ended June 30          2009        2008    % Change
    -------------------------------------------------------------------------
    Dilbit sales - bbl/d(1)                    8,517       8,403           1
    Diluent purchased - bbl/d(1)              (2,233)     (2,280)         (2)
    -------------------------------------------------------------------------
    Bitumen produced and sold - bbl/d(1)       6,284       6,123           3
    Crude oil produced and sold - bbl/d        1,114         981          14
    Natural gas produced and sold - Mcf/d     12,144      14,220         (15)
    -------------------------------------------------------------------------
    Total - boe/d                              9,421       9,474          (1)
    -------------------------------------------------------------------------


    For the six months ended June 30            2009        2008    % Change
    -------------------------------------------------------------------------
    Dilbit sales - bbl/d(1)                    8,524       5,424          57
    Diluent purchased - bbl/d(1)              (2,297)     (1,476)         56
    -------------------------------------------------------------------------
    Bitumen produced and sold - bbl/d(1)       6,227       3,948          58
    Crude oil produced and sold - bbl/d        1,147         988          16
    Natural gas produced and sold - Mcf/d     12,484      12,356           1
    -------------------------------------------------------------------------
    Total - boe/d                              9,455       6,996          35
    -------------------------------------------------------------------------

    (1) Since declaring Great Divide Pod One "commercial" effective March 1,
        2008.


    UPSTREAM NETBACKS PER UNIT OF PRODUCTION

    For the three months         Bitumen   Crude Oil  Natural Gas     Total
     ended June 30, 2009      ($ per bbl) ($ per bbl) ($ per Mcf) ($ per boe)
    -------------------------------------------------------------------------
    Production revenue        $    40.95  $    54.87  $     3.35  $    38.11
    Realized financial
     derivative losses            (10.78)          -           -       (7.19)
    Unrealized mark-to-
     market losses                (14.41)          -           -       (9.61)
    Royalties                      (0.16)     (14.12)      (0.10)      (1.90)
    Operating costs               (14.79)      (9.37)      (2.33)     (13.98)
    -------------------------------------------------------------------------
    Calculated netback        $     0.81  $    31.38  $     0.92  $     5.43
    -------------------------------------------------------------------------
    Cash operating netback,
     excluding unrealized
     mark-to-market
     accounting losses        $    15.22  $    31.38  $     0.92  $    15.04
    -------------------------------------------------------------------------


    For the three months
     ended June 30, 2008
    -------------------------------------------------------------------------
    Production revenue        $    60.80  $   105.28  $    10.02  $    65.25
    Realized financial
     derivative losses                 -           -       (0.31)      (0.47)
    Unrealized mark-to-
     market losses                     -           -       (0.94)      (1.41)
    Royalties                      (0.67)     (30.58)      (1.74)      (6.21)
    Operating costs               (29.22)      (9.07)      (1.97)     (22.78)
    -------------------------------------------------------------------------
    Calculated netback        $    30.91  $    65.63  $     5.06  $    34.38
    -------------------------------------------------------------------------
    Cash operating netback,
     excluding unrealized
     mark-to-market
     accounting losses        $    30.91  $    65.63  $     6.00  $    35.79
    -------------------------------------------------------------------------



    For the six months           Bitumen   Crude Oil  Natural Gas     Total
     ended June 30, 2009      ($ per bbl) ($ per bbl) ($ per Mcf) ($ per boe)
    -------------------------------------------------------------------------
    Production revenue        $    31.84  $    47.07  $     4.13  $    32.13
    Realized financial
     derivative losses             (5.11)          -           -       (3.36)
    Unrealized mark-to-
     market losses                (14.65)          -           -       (9.65)
    Royalties                      (0.19)     (12.01)      (0.66)      (2.46)
    Operating costs               (17.56)     (10.84)      (2.25)     (15.85)
    -------------------------------------------------------------------------
    Calculated netback        $    (5.67) $    24.22  $     1.22  $     0.81
    -------------------------------------------------------------------------
    Cash operating netback,
     excluding unrealized
     mark-to-market
     accounting losses        $     8.98  $    24.22  $     1.22  $    10.46
    -------------------------------------------------------------------------


    For the six months
     ended June 30, 2008
    -------------------------------------------------------------------------
    Production revenue        $    59.05  $    92.29  $     9.08  $    62.41
    Realized financial
     derivative losses                 -           -       (0.18)      (0.32)
    Unrealized mark-to-
     market losses                     -           -       (0.90)      (1.60)
    Royalties                      (0.64)     (25.28)      (1.52)      (6.61)
    Operating costs               (27.39)     (10.40)      (1.77)     (20.05)
    -------------------------------------------------------------------------
    Calculated netback        $    31.02  $    56.61  $     4.71  $    33.83
    -------------------------------------------------------------------------
    Cash operating netback,
     excluding unrealized
     mark-to-market
     accounting losses        $    31.02  $    56.61  $     5.61  $    35.43
    -------------------------------------------------------------------------
    

    In response to a collapse in crude oil prices and widening of heavy oil
differentials, the company announced in December 2008 that it was curtailing
production at Pod One from levels that had exceeded 9,000 bbl/d earlier in
that month, through the reduction of steam to be injected into the bitumen
reservoir. On January 21, 2009, the company announced the resumption of full
production ramp-up at Pod One in anticipation of the reinstatement of
profitability at Pod One, as a result of improved product prices; in response
to narrower heavy oil pricing differentials; reduced transportation costs;
anticipated reduced diluent blending ratios due to increased dilbit sales to
upgraders operating near our SAGD oil sands facility; and due to WTI crude oil
hedges entered into that provided some protection against further weakness in
selling prices. Bitumen production is gradually ramping up to design capacity
from curtailed bitumen production levels of approximately 4,200 bbl/d in
January 2009.
    In the second quarter of 2009, bitumen, crude oil, and natural gas
revenues were down 45 percent to $49.9 million from $90.5 million in the
second quarter of 2008. This was due to bitumen and crude oil prices being 48
percent lower and natural gas prices being 67 percent lower than the
comparative period.
    For the same reasons, year to date upstream revenues were $33.7 million
lower than in the first six months of 2008 ($88.5 million compared to $122.2
million).
    Second quarter 2009 upstream revenues were, however, 29 percent higher
than first quarter 2009 upstream revenues ($49.9 million compared to $38.6
million) as commodity prices moderately improved.
    Royalties represent charges against production or revenue by governments
and landowners. Royalties in the second quarter of 2009 were $1.6 million
compared to $5.4 million in the second quarter of 2008 and royalties for the
first six months of 2009 were $4.2 million compared to $8.4 million in the
first half of 2008. From year to year, royalties can change based on changes
in the product mix, the components of which are subject to different royalty
rates. Additionally, royalty rates are applied on a sliding scale to commodity
prices. The most notable change in royalties this year came as a result of
reduced product pricing.
    In the second quarter of 2009, upstream diluent purchases of $14.7
million (year to date $28.0 million) were required for our oil sands
operations. Diluent purchases for the second quarter of 2009 include $3
million ($3.5 million year to date) of diluent purchased from our subsidiary,
Montana Refining Company, Inc. in the netback calculations, above. These
intercompany purchases have been eliminated on consolidation and for financial
statement presentation purposes. There were no intercompany purchases in the
prior year periods. Bitumen produced at Great Divide is mixed with purchased
diluent and sold as "dilbit". Diluent is a light hydrocarbon that improves the
marketing and transportation quality of bitumen. For the reported volumes,
diluent purchased represented approximately 26 percent of the dilbit barrel
sold, with bitumen the remaining 74 percent. It is anticipated that less
diluent will be necessary when oil sands production and handling operations
are optimized and higher volumes are processed.
    Field operating costs of $12.0 million in the second quarter were
substantially lower than $19.6 million reported in the second quarter of 2008
as a result of our concerted efforts to reduce costs and optimize our
production processes.
    Oil sands field operating costs of $8.5 million in the second quarter
averaged $14.79 per barrel of bitumen produced, and was approximately one half
the per barrel cost last year. Although lower natural gas costs contributed,
reductions in other cost components were also realized from our optimization
strategy.
    Transportation costs of $2.6 million in the second quarter of 2009 were
slightly lower than the $2.9 million recorded in the prior year comparative
period due to successful marketing arrangements in selling similar volumes to
closer markets.
    Realized financial derivative losses and unrealized MTM non-cash
accounting losses were sustained in the current year as a result of commodity
prices being higher than our commodity price contracts. These losses are
included in our reported revenues on our Statements of Operations.
    Netbacks are a widely used industry measure of a company's efficiency and
its ability to internally fund its growth. The company's overall second
quarter 2009 upstream netback of $15.04 per produced boe (a 58 percent
decrease over the same 2008 period due to lower commodity prices) was
significantly influenced by its oil sands production, which had a netback of
$15.22 per bitumen barrel produced.

    
    RECONCILIATION OF UPSTREAM OPERATING NETBACK TO NET EARNINGS

    For three months
     ended June 30                  2009                    2008
    -------------------------------------------------------------------------
    ($000, except per
     unit amounts)                 Total     Per boe       Total     Per boe
    -------------------------------------------------------------------------
    Upstream netback,
     as above                 $    4,650  $     5.43  $   29,640  $    34.38
    Refining margin - net          3,483        4.06        (106)      (0.12)
    Interest income                  246        0.29         713        0.83
    General and administrative    (3,224)      (3.77)     (2,911)      (3.38)
    Stock-based compensation        (551)      (0.64)     (1,181)      (1.37)
    Finance charges               (8,877)     (10.35)    (10,298)     (11.94)
    Foreign exchange
     (loss) gain                  65,411       76.30      (3,317)      (3.85)
    Depletion, depreciation
     and accretion               (16,538)     (19.29)    (13,825)     (16.04)
    Income taxes                  (5,490)      (6.40)     (1,033)      (1.20)
    Equity interest in
     Petrolifera earnings
     and dilution gain               856        1.00       9,001       10.44
    -------------------------------------------------------------------------
    Net earnings              $   39,966  $    46.63  $    6,683  $     7.75
    -------------------------------------------------------------------------


    For the six months
     ended June 30                  2009                    2008
    -------------------------------------------------------------------------
    ($000, except per
     unit amounts)                 Total     Per boe       Total     Per boe
    -------------------------------------------------------------------------
    Upstream netback
     as above                 $    1,384  $     0.81  $   43,080  $    33.83
    Refining margin - net          5,915        3.46         400        0.31
    Interest income                1,174        0.69       1,544        1.21
    General and administrative    (7,698)      (4.50)     (5,977)      (4.69)
    Stock-based compensation      (1,821)      (1.06)     (2,697)      (2.12)
    Finance charges              (18,037)     (10.54)    (14,729)     (11.57)
    Foreign exchange
     (loss) gain                  37,545       21.94      (5,209)      (4.09)
    Depletion, depreciation
     and accretion               (32,987)     (19.28)    (21,289)     (16.72)
    Income taxes                   6,508        3.80         313        0.25
    Equity interest in
     Petrolifera earnings
     and dilution gain             1,139        0.67       9,414        7.39
    -------------------------------------------------------------------------
    Net earnings (loss)       $   (6,878) $    (4.01) $    4,850  $     3.80
    -------------------------------------------------------------------------
    

    DOWNSTREAM REVENUES AND MARGINS

    Operations at the Montana refinery are subject to a number of seasonal
factors which typically cause product sales revenues to vary throughout the
year. The refinery's primary asphalt market is for paving roads, which is
predominantly a summer demand. Consequently, prices and sales volumes for our
asphalt tend to be higher in the summer and lower in the colder seasons.
During the winter, most of the refinery's asphalt production is stored in
tankage for sale in the subsequent summer months. Seasonal factors also affect
sales revenues for gasoline (higher demand in summer months) as well as
distillate and diesel fuels (higher winter demand). As a result, inventory
levels, sales volumes and prices can be expected to fluctuate on a seasonal
basis.

    
    Refinery throughput -    June 30,  Sept 30,   Dec 31, March 31,  June 30,
     three months ended         2008      2008      2008      2009      2009
    -------------------------------------------------------------------------
    Crude charged (bbl/d)(1)   9,329     9,239     8,333     6,867     9,145
    Refinery production
     (bbl/d)(2)               10,052    10,284     9,075     7,946    10,438
    Sales of produced
     refined products
     (bbl/d)                  12,274    11,897     6,404     5,290     9,222
    Sales of refined
     products (bbl/d)(3)      12,878    12,385     7,564     5,890     9,451
    Refinery utilization(4)      98%       97%       88%       72%       96%
    -------------------------------------------------------------------------
    (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.
    

    During the first quarter of 2009, the U.S.$20 million ultra low sulphur
diesel project was completed at the Montana refinery. Due to down time
required to tie-in the new hydrogen plant to complete this project and as a
result of certain operational upsets due to significant cold weather,
throughput volumes were lower in the fourth quarter of 2008 and the first half
of 2009 than in prior quarters. The Montana refinery is now producing and
selling ultra low sulphur diesel and gasoline.
    Second quarter 2009 refining revenues ($69.1 million) more than doubled
first quarter 2009 revenues ($33.2 million) but were still well below the
level realized in the second quarter of 2008 ($117.8 million), when refined
selling prices and sales volumes were much higher. Due to lower refined
product selling prices, downstream revenues for the six months ended June 30,
2009 of $102.2 million were significantly less than the $189.7 million
reported in the first six months of 2008. Downstream revenues and refining
margins noted in the tables, below, include intersegment diluent sales of $3
million in the second quarter of 2009 and $3.5 million for the year to date
2009, which have been eliminated on consolidation for financial statement
presentation purposes. There were no intersegment sales in the prior year
periods.
    Increased processing throughput and sales volumes and higher selling
prices occurred in the second quarter of 2009, compared to the first quarter
2009 when processing downtime and the seasonality of our downstream business
unit occurred. Higher volumes and prices led to improved refining revenues and
operating margins. General economic conditions also affect refined product
demand and pricing and we anticipate will continue to influence our financial
results in the future.
    Notwithstanding lower current year sales volumes and pricing, year to
date downstream margins were higher in the first half of 2009 ($5.9 million,
or 6 percent) compared to the first six months of 2008 ($400,000 or 0.2
percent), as crude oil input costs have come down faster than selling prices
have been reduced.
    We anticipate a significant improvement in the contribution to our
overall results from our downstream activities during Q3 2009, as the impact
of high priced asphalt sales and generally better economic conditions assist
this portion of our integrated business activity. Asphalt sales were generally
hampered by cold and wet weather in Montana and Alberta during Q2 2009, which
delayed road paving activities. As at June 30, 2009 we had over 430,000
barrels of asphalt in inventory, the majority of which had been contracted for
sale at prices in excess of U.S.$100 per barrel. We will be conducting a
scheduled turnaround at the Montana refinery during September 2009, but will
continue our aggressive asphalt sales from inventory during that period.

    
    Feedstocks -             June 30,  Sept 30,   Dec 31,   Mar 31,  June 30,
     three months ended         2008      2008      2008      2009      2009
    -------------------------------------------------------------------------
    Sour crude oil               93%       93%       94%       91%       91%
    Other feedstocks and blends   7%        7%        6%        9%        9%
    -------------------------------------------------------------------------
    Total                       100%      100%      100%      100%      100%
    -------------------------------------------------------------------------

    Revenues and Margins
     ($000)
    -------------------------------------------------------------------------
    Refining sales revenue  $117,820  $127,726  $ 56,803  $ 33,152  $ 69,094
    Refining - crude oil
     and operating costs     117,926   125,455    66,964    30,720    65,611
    -------------------------------------------------------------------------
    Refining margin         $   (106) $  2,271  $(10,161) $  2,432  $  3,483
    -------------------------------------------------------------------------
    Refining margin            (0.1%)     1.8%    (17.9%)       7%        5%
    -------------------------------------------------------------------------

    Sales of Produced Refined
     Products (Volume %)
    -------------------------------------------------------------------------
    Gasolines                    32%       35%       44%       55%       48%
    Diesel fuels                 11%       19%       25%       22%       11%
    Jet fuels                     5%        5%        8%        7%        7%
    Asphalt                      48%       38%       19%       12%       31%
    LPG and other                 4%        3%        4%        4%        3%
    -------------------------------------------------------------------------
    Total                       100%      100%      100%      100%      100%
    -------------------------------------------------------------------------

    Per Barrel of Refined
     Product Sold
    -------------------------------------------------------------------------
    Refining sales revenue  $ 100.54  $ 112.10  $  81.62  $  62.54  $  80.34
    Less: refining - crude
     oil purchases and
     operating costs          100.63    110.10     96.23     57.95     76.29
    -------------------------------------------------------------------------
    Refining margin         $  (0.09) $   2.00  $ (14.61) $   4.59  $   4.05
    -------------------------------------------------------------------------
    

    INTEREST AND OTHER INCOME

    In the second quarter of 2009, the company earned interest of $246,000
(second quarter June 30, 2008 - $713,000; 2009 year to date - $699,000; 2008
year to date - $1.5 million) on excess funds invested in secure short-term
investments and realized a gain of $475,000 on the repurchase of U.S.$660,000
(face value) of Second Lien Notes in the first quarter of 2009.

    GENERAL AND ADMINISTRATIVE EXPENSES

    In the second quarter of 2009, general and administrative ("G&A")
expenses were $3.2 million compared to $2.9 million in the second quarter of
2008, an increase of 11 percent, reflecting increased staffing and activity
levels. Additionally, G&A of $1.1 million was capitalized in the second
quarter of each of 2009 and 2008.
    For the first six months of 2009, G&A expenses were $7.7 million compared
to $6 million in the first six months of 2008, after capitalizing $2.6 million
in the first half of 2009 and $3 million in the first half of 2008.

    FINANCE CHARGES

    Finance charges include interest expense relating to the Convertible
Debentures, standby fees associated with the company's undrawn lines of
credit, which we cancelled in March 2009, fees on letters of credit issued and
a portion of the Second Lien Senior Notes interest attributable to Great
Divide Pod One since it was declared commercial, effective March 1, 2008.
Finance charges also include non-cash accretion charges with respect to the
Convertible Debentures and a portion of the First and Second Lien Senior
Notes.
    Finance charges of $8.9 million in the second quarter of 2009 were $1.4
million lower than the 2008 comparative period, as the prior year period
included a non-cash mark-to-market charge on our cross-currency interest rate
swap then in place. No such charge applied in 2009, as the cross-currency swap
was unwound in the fourth quarter of 2008 for an $89 million net cash gain.
    Year to date finance charges of $18 million are $3.3 million higher than
the 2008 comparative period as a result of not capitalizing interest to the
Pod One project since declaring it "commercial" on March 1, 2008 and due to
interest charges on higher debt levels, since issuing the First Lien Senior
Notes in mid-June 2009.
    We continued to capitalize interest to our Algar project for that portion
of our debt attributed to the project.

    STOCK BASED COMPENSATION

    The company recorded non-cash stock-based compensation charges in the
respective periods as follows:

    
                                  Three months ended        Six months ended
                                             June 30                 June 30
    -------------------------------------------------------------------------
    ($000)                          2009        2008        2009        2008
    -------------------------------------------------------------------------
    Charged to G&A expense    $      551  $    1,181  $    1,821  $    2,697
    Capitalized to property
     and equipment                   114         224         507       1,022
    -------------------------------------------------------------------------
                              $      665  $    1,405  $    2,328  $    3,719
    -------------------------------------------------------------------------
    

    The reduction from the prior period is due to fewer options being granted
in the current year.

    FOREIGN EXCHANGE GAINS AND LOSSES

    Over the past few months, the value of the Canadian dollar has
strengthened relative to the U.S. dollar. This has had a significant impact to
Connacher upon translating its U.S. dollar denominated long-term debt and U.S.
dollar cash balances into Canadian dollars for financial reporting purposes.
    In 2009, we had unrealized foreign exchange translation gains of $61.5
million in the second quarter and $33.6 million for the year to date. We also
realized foreign exchange gains of $3.9 million in the second quarter and in
the year to date 2009 from the foreign exchange revenue collar and upon the
settlement of U.S. dollar denominated obligations.
    Throughout most of 2008 we had a cross-currency swap in place to hedge
one-half of the foreign exchange exposure on our U.S. dollar debt. This
insulated us from some foreign currency volatility and reduced the impact of a
weaker Canadian dollar, which resulted in the unrealized foreign exchange
translation losses reported in the comparative 2008 periods.
    Having unwound the cross-currency swap in the fourth quarter of 2008 for
a net cash gain of $89 million, Connacher is now fully exposed to changes in
the U.S.: Canadian dollar exchange rate when translating its U.S. dollar debt
to Canadian dollars for financial reporting purposes and for purposes of
paying U.S. denominated interest and repaying such indebtedness. To mitigate
some of this exposure, the company may put into place another cross-currency
swap in the future.

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

    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. Effective March 1, 2008 Pod
One's accumulated capital costs were added to the depletion pool and have been
depleted from that date. DD&A in the second quarter of 2009 was $16.5 million,
and for the first six months of 2009 was $33 million. These charges are 20
percent and 55 percent higher, respectively, than the 2008 comparative
periods, reflecting a full six months of depletion on Pod One capital costs in
2009. Depletion equates to $16.28 per boe of production year to date compared
to $13.43 per boe in the 2008 comparative period.
    Future development costs of $1.3 billion (2008 - $999 million) for proved
undeveloped reserves were included in the year to date depletion calculation.
Capital costs of $369 million (2008 - $193 million) related to oil sands
projects currently in the pre-production stage and undeveloped land
acquisition costs of $12.2 million (2008 - $14.0 million) were excluded from
the depletion calculation.
    Included in year to date DD&A is an accretion charge of $981,000 (2008 -
$845,000) in respect of the company's estimated asset retirement obligations.
These charges will continue in future years in order to accrete the currently
booked discounted liability of $27.7 million to the estimated total
undiscounted liability of $48.2 million over the remaining economic life of
the company's oil sands, crude oil and natural gas properties.
    At June 30, 2009, the recoverable value of the company's productive crude
oil, oil sands and natural gas assets and its major development projects
significantly exceeded their carrying values and, therefore, no ceiling test
write-down was required.

    INCOME TAXES

    The income tax recovery of $6.5 million in the first six months of 2009
includes a current income tax provision of $293,000, principally related to
Canadian capital and other taxes and a future income tax recovery of $6.8
million reflecting the benefit of increased tax pools during the period.
    At June 30, 2009 the company had approximately $233 million of
non-capital losses which expire between 2010 and 2028, $610 million of
deductible resource pools and $33 million of deductible financing costs. The
future income tax benefit of these have been recognized at June 30, 2009.
Additionally, the company had $32 million of capital losses available to
reduce capital gains in future. These capital losses have no expiry date and
their future income tax benefit has not been recognized, due to uncertainty of
their realization at June 30, 2009.

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

    In June 2008, Petrolifera issued an additional 4.4 million common shares
to raise $40 million. Connacher did not subscribe for any of these shares.
Consequently, Connacher's equity interest in Petrolifera was reduced from 26
percent to 24 percent. However, the financing resulted in a dilution gain of
$8 million, which was recognized by Connacher in the second quarter of 2008.
    Connacher accounts for its 24 percent equity investment in Petrolifera
under the equity method of accounting. Connacher's share of Petrolifera's
earnings in the first six months of 2009 was $1.1 million (six months ended
June 30, 2008 - $1.4 million). In the second quarter of 2009, Connacher's
share of Petrolifera's earnings was $856,000 (second quarter 2008 - $935,000).

    NET EARNINGS

    In the second quarter of 2009, the company reported earnings of $40
million ($0.15 per basic and $0.14 per diluted share outstanding) compared to
earnings of $6.7 million ($0.03 per basic and diluted share outstanding) in
the second quarter of 2008.
    In the first six months of 2009, the company reported a loss of $6.9
million ($0.03 loss per basic and diluted share outstanding) compared to
earnings of $4.9 million or $0.02 per basic and diluted share for the first
six months of 2008.
    Explanations for the period to period fluctuations are included in the
narrative above, by earnings component.

    SHARES OUTSTANDING

    For the first six months of 2009, the weighted average number of common
shares outstanding was 239,007,899 (2008 - 210,446,291) and the weighted
average number of diluted shares outstanding, as calculated by the treasury
stock method, was 239,007,899 (2008 - 213,324,122).

    As at August 11, 2009, the company had the following equity securities
issued and outstanding:

    
    -   403,567,309 common shares;
    -   15,362,784 share purchase options; and
    -   489,292 share units under the non-employee director share awards
        plan.
    

    Additionally, 20,002,800 common shares are issuable upon conversion of
the Convertible Debentures. Details of the exercise provisions and terms of
the outstanding options are noted in the consolidated financial statements,
included in this interim report.

    LIQUIDITY AND CAPITAL RE

SOURCES At June 30, 2009, the company had working capital of $455 million, including $401 million of cash on hand of which $10 million was segregated to collateralize letters of credit. These balances reflect the receipt of net proceeds from the recently completed common share equity issuance and the First Lien Senior Note financing. On June 5, 2009 Connacher issued 191,762,500 common shares from treasury at a price of $0.90 per common share for gross proceeds of $172.6 million. On June 16, 2009 the company issued U.S.$200 million face value of 11.75 percent First Lien Senior Secured Notes (the "First Lien Senior Notes") at a price of 93.678 percent for gross proceeds of U.S.$187.4 million. The First Lien Senior Notes are not repayable until July 15, 2014 and are secured on a first priority basis (subject to specified liens up to U.S.$50 million for prior ranking senior debt) by liens on all of the company's assets, excluding Connacher's investment holding in Petrolifera. The company is currently in discussions with its banker to put in place a U.S.$30 - U.S.$50 million revolving banking facility which would rank in priority to the First Lien Senior Notes. Proceeds from the equity and First Lien Senior Note financings, net of issuance costs, were approximately $370 million. These funds were raised for working capital and general corporate purposes, including to fund the remaining costs associated with the construction of Algar, the company's second 10,000 bbl/d SAGD oil sands project and the drilling and completion of the associated SAGD well pairs. As the company has no principal debt repayment obligations until June 2012, management believes that the company has sufficient liquidity to complete the Algar project, to fund its ongoing capital program and to satisfy its financial obligations. The financial crisis has severely reduced liquidity in capital and bank markets. Economic uncertainty and significant volatility in commodity markets and stock markets have also occurred around the world. Connacher's share price and the trading value of its Second Lien Senior Notes and Convertible Debentures have been adversely affected by the uncertainty of future crude oil and natural gas prices, as well as by the impact of anticipated new environmental regulations, which could affect the economics of our business. Notwithstanding the challenges imposed by this crisis and current economic conditions, management believes that the company has attractive internally-generated growth prospects which, with our cash balances and the impact of an improvement in commodity prices, will allow us to expand our operations. In the interim, however, lower world oil prices are expected to result in lower per unit revenues, netbacks, cash flow and earnings. We anticipate increasing production and sales volumes throughout 2009, which could partially offset the impact of lower world commodity prices. In light of the volatility of current commodity prices and the U.S.:Canadian dollar exchange rate and their significance to the company's operating performance, management continues to assess alternative hedging strategies to protect the company's cash flow from the risk of potentially lower crude oil and refined product pricing and adverse exchange rate fluctuations. Although the company's integrated business model provides some protection, it does not provide a perfect hedge. The purpose of any such hedge(s) would be to ensure sufficient cash flow to continue to service indebtedness, complete capital projects and protect the credit capacity of Connacher's oil and gas reserves in a volatile and weak commodity price and weakened economic environment. In order to mitigate foreign exchange exposure to commodity pricing, the company entered into a foreign exchange revenue collar which throughout 2009 sets a floor of CAD$1.1925 per U.S.$1.00 and a ceiling of CAD$1.30 per U.S.$1.00 on a notional amount of U.S.$10 million of production revenue per month. Additionally, in 2009 the company entered into WTI derivatives at crude oil prices of U.S.$46.00/bbl and U.S.$49.50/bbl on two tranches of 2,500 bbl/d of notional production with staggered August 2009 and December 2009 maturities and has put in place a WTI crude oil "collar" contract on a notional volume of 2,500 bbl/d of production from September to December 2009 with a floor of WTI U.S.$60.00/bbl and a ceiling of WTI U.S.$84.00/bbl. Cash flow and cash flow per share do not have standardized meanings prescribed by GAAP and therefore may not be comparable to similar measures used by other companies. Cash flow includes all cash flow from operating activities and is calculated before changes in non-cash working capital, pension funding and asset retirement expenditures. The most comparable measure calculated in accordance with GAAP is net earnings. Cash flow is reconciled with net earnings on the Consolidated Statement of Cash Flows and below. Reconciliation of net earnings to cash flow from operations before working capital and other changes: Three months ended Six months ended June 30 June 30 ------------------------------------------------------------------------- 2009 2008 2009 2008 ------------------------------------------------------------------------- ($000s) ------------------------------------------------------------------------- Net earnings (loss) $ 39,966 $ 6,683 $ (6,878) $ 4,850 Items not involving cash: Depletion, depreciation and accretion 16,538 13,825 32,987 21,289 Stock-based compensation 551 1,181 1,821 2,697 Finance charges-non- cash portion 1,134 4,058 2,175 5,307 Future employee benefits 107 114 294 227 Future income tax provision (recovery) 5,369 373 (6,801) (1,790) Unrealized foreign exchange (gain) loss (61,482) 3,317 (33,616) 5,209 Unrealized loss on risk management contracts 8,243 - 16,510 - Gain on repurchase of Second Lien Senior Notes - - (475) - Equity interest in Petrolifera earnings (856) (935) (1,139) (1,390) Dilution gain - (8,066) - (8,024) ------------------------------------------------------------------------- Cash flow from operations before changes in non- cash working capital and other changes $ 9,570 $ 20,550 $ 4,878 $ 28,375 ------------------------------------------------------------------------- In the second quarter of 2009 cash flow was $9.6 million ($0.04 per basic and $0.03 per diluted share), 53 percent lower than the $20.6 million reported ($0.10 per basic and diluted share) for the second quarter of 2008 and in the first half of 2009 cash flow was $4.9 million ($0.02 per basic and diluted share) compared to cash flow of $28.4 million ($0.14 per basic and $0.13 per diluted share) reported in the first half of 2008. The primary reason for lower reported cash flows in 2009 compared to 2008 was lower commodity selling prices for each of our upstream and downstream business segments, as noted in the detailed explanations of our business activities, above. Cash flow per share is calculated by dividing cash flow by the calculated weighted average number of shares outstanding. Management uses this non-GAAP measurement (which is a common industry parameter) for its own performance measure and to provide its shareholders and investors with a measurement of the company's efficiency and its ability to fund future growth expenditures. The company's only financial instruments are cash, restricted cash, accounts receivable and payable, amounts due from Petrolifera, the Convertible Debentures, and the First and Second Lien Senior Notes. The company maintains no off-balance sheet financial instruments. As the First and Second Lien Senior Notes are denominated in U.S. dollars, there is a foreign exchange risk associated with their semi-annual interest payments and the repayment of their principal balances in 2014 and 2015, using Canadian currency. The next semi-annual interest payment of U.S.$43 million is due in December 2009. Connacher's capital structure is composed of: As at As at June 30, December 31, 2009 2008 ------------------------------------------------------------------------- ($000) ------------------------------------------------------------------------- Long term debt(1) $ 960,593 $ 778,732 Shareholders' equity Share capital, contributed surplus and equity component 606,493 437,899 Accumulated other comprehensive income (loss) (766) 7,802 Retained earnings 16,508 23,386 ------------------------------------------------------------------------- Total $ 1,582,828 $ 1,247,819 ------------------------------------------------------------------------- Debt to book capitalization(2) 61% 62% Debt to market capitalization(3) 71% 81% ------------------------------------------------------------------------- (1) Long-term debt is stated at its carrying value, which is net of transaction costs and the Convertible Debentures' equity component value. (2) Calculated as long-term debt divided by the book value of shareholders' equity plus long-term debt. (3) Calculated as long-term debt divided by the period end market value of shareholders' equity plus long-term debt. Connacher currently has a high calculated ratio of debt to capitalization. This is due to pre-funding the full cost of Algar. As at June 30, 2009, the company's net debt (long-term debt, net of cash on hand) was $559.4 million and its calculated ratio of net debt to book capitalization was 47 percent and the percentage of its net debt to market capitalization was 59 percent. FINANCINGS COMPLETED IN 2009 Common Share Issuance On June 5, 2009 Connacher issued 191,762,500 common shares from treasury at a price of $0.90 per common share for net proceeds of $164 million after fees and expenses. The proceeds were raised for working capital and general corporate purposes to fund the company's capital expenditures, including Algar. To June 30, 2009, the proceeds of the common share issuance have been utilized as follows: As stated at the time As actually of financing applied ------------------------------------------------------------------------- ($000) ------------------------------------------------------------------------- Gross proceeds $ 172,586 $ 172,586 Underwriters commissions and issue costs (8,629) (8,785) ------------------------------------------------------------------------- Net proceeds for working capital and general corporate purposes to fund capital expenditures $ 163,957 $ 163,801 ------------------------------------------------------------------------- First Lien Senior Secured Notes On June 16, 2009 the company issued U.S.$200 million first lien five-year secured notes ("First Lien Senior Notes") at an issue price of 93.678 percent for net proceeds of $205.6 million after fees and expenses. The proceeds were to be used for working capital and general corporate purposes, including to fund a portion of the remaining construction, drilling and completion costs associated with the construction of Algar. To June 30, 2009, the proceeds of the First Lien Senior Note financing have been utilized as follows: As stated at the time As actually of financing applied ------------------------------------------------------------------------- ($000s) ------------------------------------------------------------------------- Gross proceeds $ 226,475 $ 226,475 Underwriters commissions and issue costs (20,875) (20,858) ------------------------------------------------------------------------- Net proceeds to be used for working capital and general corporate purposes, including to fund a portion of the remaining construction, drilling and completion costs associated with the construction of Algar $ 205,600 $ 205,617 ------------------------------------------------------------------------- PROPERTY AND EQUIPMENT EXPENDITURES Property and equipment expenditures totaled $40.2 million in the second quarter of 2009 and $104.5 million year to date. A breakdown of these expenditures together with prior year comparatives follows. Three months ended Six months ended June 30 June 30 ------------------------------------------------------------------------- ($000) 2009 2008 2009 2008 ------------------------------------------------------------------------- Oil sands, crude oil and natural gas expenditures $ 36,724 $ 75,475 $ 97,723 $ 188,432 Refinery expenditures 3,512 4,928 6,768 7,956 ------------------------------------------------------------------------- $ 40,236 $ 80,403 $ 104,491 $ 196,388 ------------------------------------------------------------------------- In the second quarter of 2009, oil sands capital expenditures totaled $36 million, $12 million of which was incurred on our Algar oil sands project, while this project was "on-hold", for the continued construction of long-lead order equipment items, and for associated project-delay costs; additionally, $6 million of capital costs were incurred at Pod One for the completion of the two additional SAGD well pairs, for costs to install four electric submersible pumps and for other facility enhancement expenditures; $5 million was incurred on our co-generation and transfer pipeline facilities; and $13 million of interest and G&A costs were capitalized. For the year to date, $33 million was incurred on the Algar project for engineering, civil work, facilities, equipment and project delay costs; $18 million was incurred at Pod One to drill and complete the two additional SAGD well pairs and to install ESP's and for other facility enhancement expenditures; and $47 million was incurred on drilling 23 exploratory core holes, two conventional wells, for co-generation and pipeline facilities and for capitalized interest and G&A costs. Refinery capital costs in the second quarter and year to date for 2009 were primarily directed to the completion and tie-in of our new hydrogen plant to complete our ultra-low sulphur diesel project. Oil sands, crude oil and natural gas capital costs of $75.5 million in the second quarter of 2008 were comprised of preliminary facility expenditures and costs incurred for long lead-order equipment items for the Algar project, truck loading facilities at Pod One, core hole and conventional drilling costs and capitalized interest costs and G&A costs. For the 2008 year to date, oil sands and conventional exploration expenditures totaled $70 million, Algar facility and equipment expenditures totaled $49 million; conventional natural gas facilities totaled $12 million; Pod One trucking facility and capitalized pre-operating costs totaled $20 million and capitalized interest, G&A and other expenditures totaled $37 million. Most of the 2008 capital expenditures at our refinery were incurred on the ultra low sulphur diesel conversion project. Second half 2009 capital expenditures will be focused on Algar. OUTLOOK We anticipate that the current general economic conditions and product price volatility will continue to challenge industry profitability and growth in the short-term. However, recent oil price improvements have provided a basis for some investment optimism. Together with the optimization of some of our operational and marketing processes, moderately higher oil prices have contributed to Connacher's improved operating and financial results in the second quarter of 2009. We continue to anticipate a greater contribution to profitability from our refining operations, primarily due to improved throughput volumes and anticipated healthy asphalt markets, with wider margins, as newly-announced U.S. government infrastructure projects are anticipated to result in an unprecedented demand for asphalt. This improvement is now starting to be apparent. However, the Montana refinery will undergo a scheduled one-month turnaround commencing in mid-September 2009, which will have an adverse effect on throughput and refined product sales volumes later in the year. We also anticipate improved netbacks from our upstream operations during the balance of 2009, as a result of recent marketing arrangements and anticipated reductions in transportation and operating costs. At Pod One, we surpassed 10,000 bbl/d in April on a test basis and have adopted a more measured ramp-up process to introduce steady state conditions which should allow for better reservoir conformance on a sustained basis. Four new electric submersible pumps were also installed at Pod One in April 2009. This required the shut-in of the related well pairs for a one week period, which affected average daily production rates in the second quarter of 2009. Two new SAGD well pairs were recently completed at Pod One and have commenced bitumen production. Pod One is currently producing approximately 7,000 bbl/d and we anticipate approaching design capacity of 10,000 bbl/d by year-end 2009. Our recently completed financings have added significant financial liquidity. Our cash balances, together with anticipated positive operating income in 2009, are anticipated to be sufficient to meet all our financial and capital obligations, including the completion of Algar. Upon the completion of the equity and First Lien Senior Note financings, Connacher's Board of Directors sanctioned the resumption of construction of Algar (which was suspended in December 2008). To date, approximately $162 million has been invested in Algar. The majority of the long-lead equipment items have been built and the roads to the plant site and three well pads have been constructed. We estimated that it would require approximately 275 days from the re-start of the project in early July 2009, to completion of the project. Algar is expected to begin contributing to operating results in late 2010 or early 2011. The cost to complete Algar, excluding capitalized items and contingencies, is estimated to be $360 million. Savings arising from remaining activities occurring in a more "normalized" construction and labour environment have been offset by minor scope changes to the project and the decision to drill and complete two additional SAGD well pairs at Algar, bringing the total SAGD well pairs to 17, to ensure effective exploitation of the reservoir. In addition, to recognize unplanned events that often occur during a major construction project and to factor unpredictable and often severe weather that can occur in northern Alberta, management has added a $15 million contingency to the Algar budget, bringing the total cost for Algar, excluding capitalized items, to $375 million, of which $128 million was incurred pre-2009, $175 million is estimated to be incurred in 2009 and the $72 million balance is forecast to be incurred in 2010. Connacher's revised capital budget for 2009 is as follows: ($ millions) ------------------------------------------------------------------------- Conventional $ 11 Pod One 24 Algar 175 Algar capitalized items 54 Cogeneration facility, sales transfer lines and EIA 34 Coreholes/seismic 8 Refining 19 ------------------------------------------------------------------------- $ 325 ------------------------------------------------------------------------- The revised Pod One budget reflects additional electric submersible pumps and an evaporator condenser to be added in the fall of 2009. The company's business plan anticipates continued long-term growth with continued increases in revenue and cash flow from our oilsands projects, conventional crude oil and natural gas production and from stable refining operations. Future-oriented financial projections for the year 2010 have been included in the company's recent corporate presentations. Management believes the assumptions underlying the projections are reasonable, given a U.S.$65/bbl price for crude oil during that year. No changes are currently required to those projections. Information relating to Connacher, including Connacher's Annual Information Form is on SEDAR at www.sedar.com. See also the company's website at www.connacheroil.com. NEW SIGNIFICANT ACCOUNTING POLICIES In February 2008, the CICA issued Section 3064, "Goodwill and Intangible Assets", replacing Section 3062, "Goodwill and Other Intangible Assets." The new Section became applicable in 2009 and the company adopted the new standard effective January 1, 2009. Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit-oriented enterprises. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062, and did not cause any change to the company's financial statements. In January 2009, the CICA Emerging Issues Committee ("EIC") issued EIC-173, "Credit risk and the fair value of financial assets and liabilities", which requires that an entity's own credit risk and counterparty credit risk be taken into account in determining the fair value of financial assets and liabilities, including derivative financial instruments. The provisions of EIC-173 apply to all financial assets and liabilities measured at fair value in interim and annual financial statements for periods ending on or after January 20, 2009. The adoption of this standard had no material impact on the company's financial statements. In June 2009, the CICA issued amendments to CICA Handbook Section 3862, Financial Instruments - Disclosures. The amendments include enhanced disclosures related to the fair value of financial instruments and the liquidity risk associated with financial instruments. The amendments will be effective for annual financial statements for fiscal years ending after September 30, 2009 and are consistent with recent amendments to financial instrument disclosure standards in IFRS. The company will include these additional disclosures in its annual consolidated financial statements for the year ending December 31, 2009. INTERNATIONAL FINANCIAL REPORTING STANDARDS In 2008, the Canadian Accounting Standards Board confirmed that publicly accountable enterprises will be required to adopt International Financial Reporting Standards ("IFRS") in place of Canadian GAAP for interim and annual reporting purposes for fiscal years beginning on or after January 1, 2011. We have commenced our IFRS conversion project which consists of four phases: diagnostic; design and planning; solution development; and implementation. Regular reporting is provided to management and to the Audit Committee of the Board of Directors. We have completed the diagnostic phase, which involved a review of the differences between current Canadian GAAP and IFRS. During this phase we determined that the differences which will have the greatest impact on Connacher's consolidated financial statements relate to accounting for exploration and development activities and property and equipment, impairments of capital assets, asset retirement obligations and the reporting of employee future benefits. Their financial impacts have yet to be quantified. We are currently engaged in the design and planning and the solution development phases of our project. We have identified and documented the high impact areas, including an analysis of financial system impacts and have engaged in ongoing discussions with our external auditors. The impact on our disclosure controls, internal controls over financial reporting and the impact on contracts and lending agreements will also be determined. In July 2009 the International Accounting Standards Board ("IASB") issued an amendment to IFRS accounting standards in respect of property, plant and equipment as at the date of the initial transition to IFRS which permits issuers currently using the full cost method of accounting, (as described in the CICA Handbook - Accounting Guideline 16 Oil and Gas accounting - Full Cost), to allocate the balance of property, plant and equipment as determined under Canadian GAAP to the IFRS categories of exploration and evaluation assets and development and producing properties without requiring full retroactive restatement of historic balances to the IFRS basis of accounting. We anticipate using the exemption. RISK FACTORS AND RISK MANAGEMENT Connacher is engaged in the oil and gas exploration, development, production and refining industry. This business is inherently risky and there is no assurance that hydrocarbon reserves will be discovered and economically produced. Operational risks include competition, reservoir performance uncertainties, environmental factors and regulatory and safety concerns. Financial risks associated with the petroleum industry include fluctuations in commodity prices, interest rates, currency exchange rates and the cost of goods and services. Connacher's financial and operating performance is potentially affected by a number of factors including, but not limited to, risks associated with the exploration, development and production of oil and gas, commodity prices and exchange rates, environmental legislation, changes to royalty and income tax legislation, credit and capital market conditions, credit risk for failure of performance by third parties and other risks and uncertainties described in more detail in Connacher's Annual Information Form filed with securities regulatory authorities. Reference should be made to Connacher's most recent Annual Information Form for a description of its risk factors. The company's Annual Information Form is available on SEDAR at www.sedar.com. DISCLOSURE CONTROLS AND PROCEDURES The company's Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO") have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to the company is made known to the company's CEO and CFO by others, particularly during the period in which the annual and interim filings are prepared; and (ii) information required to be disclosed by the company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the company's disclosure controls and procedures at December 31, 2008 and have concluded that the company's disclosure controls and procedures were effective. INTERNAL CONTROLS OVER FINANCIAL REPORTING The CEO and CFO have designed, or caused to be designed under their supervision, internal controls over financial reporting to provide reasonable assurance regarding the reliability of the company's financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the company's internal controls over financial reporting at the financial year end of the company and concluded that the company's internal controls over financial reporting is effective at the financial year end of the company for the foregoing purpose. The company's CEO and CFO are required to cause the company to disclose any change in the company's internal controls over financial reporting that occurred during the company's most recent interim period that has materially affected, or is reasonably likely to materially affect, the company's internal controls over financial reporting. No material changes in the company's internal controls over financial reporting were identified during such period that has materially affected, or are reasonably likely to materially affect, the company's internal controls over financial reporting. It should be noted that a control system, including the company's disclosure and internal controls and procedures, no matter how well conceived, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud. In reaching a reasonable level of assurance, management necessarily is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. QUARTERLY RESULTS Fluctuations in results over the previous eight quarters are due principally to variations in oil and gas prices and production/sales volumes. Significant volatility and declining commodity prices, together with severe economic uncertainty in the fourth quarter of 2008 and the first quarter of 2009 are the primary factors affecting financial results during those quarters. The magnitude of the changes in commodity prices during these periods was unprecedented. 2007 2008 ------------------------------------------------------------------------- Three Months Ended Sep 30 Dec 31 Mar 31 Jun 30 ------------------------------------------------------------------------- ($000 except per share amounts) Revenues, net of royalties 101,991 83,340 100,656 202,016 Cash flow(1) 10,025 7,083 7,825 20,550 Basic, per share(1) 0.05 0.03 0.04 0.10 Diluted, per share(1) 0.05 0.03 0.03 0.10 Net earnings (loss) 14,589 (840) (1,833) 6,683 Basic per share 0.07 0.00 (0.01) 0.03 Diluted per share - - - - Property and equipment additions 64,006 55,852 115,984 80,403 Cash on hand 754 392,271 323,423 232,704 Working capital surplus (deficiency) (19,853) 389,789 287,105 234,110 Term debt 260,606 664,462 671,014 684,705 Shareholders' equity 428,764 480,439 471,559 479,477 Operating Highlights Upstream: Daily production/ sales volumes Bitumen - bbl/d(2) - - 1,773 6,123 Crude oil - bbl/d 781 752 996 981 Natural gas - Mcf/d 9,413 8,889 10,493 14,220 Equivalent - boe/d(3) 2,350 2,233 4,518 9,474 Product pricing(4) Bitumen - $/bbl(2) - - 53.01 60.80 Crude oil - $/bbl 55.98 56.79 79.50 105.28 Natural gas - $/Mcf 4.70 5.82 7.79 10.02 Selected Highlights - $/boe(3) Weighted average sales price 37.43 42.29 56.44 65.25 Realized derivative gain (loss) - - - (0.47) Royalties 6.32 6.34 7.45 6.21 Operating costs 9.00 13.77 14.32 22.78 Cash operating netback(5) 22.11 22.18 34.67 35.79 Downstream: Refining Crude charged - bbl/d 9,400 9,610 9,830 9,329 Refining utilization - % 100 101 104 98 Margins - % 15 6 1 (0.1) Common Share Information Shares outstanding at end of period (000) 199,447 209,971 210,277 211,027 Weighted average shares outstanding for the period Basic (000) 199,167 204,701 210,234 210,658 Diluted (000) 221,554 220,362 210,234 214,530 Volume traded (000) 70,939 52,198 63,718 107,001 Common share price ($) High 4.40 4.08 3.94 5.26 Low 3.20 3.31 2.59 3.10 Close (end of period) 4.01 3.79 3.13 4.30 ------------------------------------------------------------------------- 2008 2009 ------------------------------------------------------------------------- Three Months Ended Sept 30 Dec 31 Mar 31 June 30 ------------------------------------------------------------------------- ($000 except per share amounts) Revenues, net of royalties 224,558 102,109 61,757 100,219 Cash flow(1) 31,130 (4,688) (4,692) 9,570 Basic, per share(1) 0.15 (0.02) (0.02) 0.04 Diluted, per share(1) 0.14 (0.02) (0.02) 0.03 Net earnings (loss) 12,139 (43,592) (46,844) 39,966 Basic per share 0.06 (0.21) (0.22) 0.15 Diluted per share - - - 0.14 Property and equipment additions 69,175 86,174 64,255 40,236 Cash on hand 236,375 223,663 96,220 401,160 Working capital surplus (deficiency) 200,177 197,914 120,035 455,001 Term debt 689,673 778,732 803,915 960,593 Shareholders' equity 496,509 469,087 428,276 622,235 Operating Highlights Upstream: Daily production/ sales volumes Bitumen - bbl/d(2) 6,810 7,086 6,170 6,284 Crude oil - bbl/d 957 1,187 1,180 1,114 Natural gas - Mcf/d 13,188 12,405 12,828 12,144 Equivalent - boe/d(3) 9,966 10,341 9,488 9,421 Product pricing(4) Bitumen - $/bbl(2) 65.34 12.06 22.45 40.95 Crude oil - $/bbl 103.60 48.13 39.63 54.87 Natural gas - $/Mcf 8.92 6.61 4.89 3.35 Selected Highlights - $/boe(3) Weighted average sales price 66.41 21.73 26.13 38.11 Realized derivative gain (loss) - - 0.47 (7.19) Royalties 4.65 3.19 3.02 1.90 Operating costs 20.41 20.76 17.73 13.98 Cash operating netback(5) 41.35 (2.23) 5.85 15.04 Downstream: Refining Crude charged - bbl/d 9,239 8,333 6,867 9,145 Refining utilization - % 97 88 72 96 Margins - % 2 (18) 7 5 Common Share Information Shares outstanding at end of period (000) 211,182 211,182 211,291 403,546 Weighted average shares outstanding for the period Basic (000) 211,093 211,182 211,286 266,425 Diluted (000) 213,174 211,575 211,286 286,985 Volume traded (000) 112,401 110,244 67,387 249,700 Common share price ($) High 4.65 2.95 1.00 1.66 Low 2.63 0.60 0.61 0.74 Close (end of period) 2.75 0.74 0.74 0.92 ------------------------------------------------------------------------- (1) Cash flow and cash flow per share do not have standardized meanings prescribed by Canadian generally accepted accounting principles ("GAAP") and therefore may not be comparable to similar measures used by other companies. Cash flow is calculated before changes in non- cash working capital, pension funding and asset retirement expenditures. The most comparable measure calculated in accordance with GAAP would be net earnings. Cash flow is reconciled with net earnings on the Consolidated Statement of Cash Flows and in the applicable Management Discussion & Analysis for the periods referenced. 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 its future growth expenditures. (2) The recognition of bitumen sales from Great Divide Pod One commenced March 1, 2008, when it was declared "commercial". Prior thereto, no production volumes were reported and all operating costs, net of revenues, were capitalized. (3) All references to barrels of oil equivalent (boe) are calculated on the basis of 6 mcf : 1 bbl. This conversion is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Boes may be misleading, particularly if used in isolation. (4) Product pricing excludes realized hedging gains/losses and excludes unrealized mark-to-market non-cash accounting gains/losses. (5) Netback is a non-GAAP measure used by management as a measure of operating efficiency and profitability. Netback per boe is calculated as bitumen, crude oil and natural gas revenue less royalties and operating costs divided by related production/sales volume. Netbacks are reconciled to net earnings in the applicable MD&A for the periods referenced. CONSOLIDATED BALANCE SHEETS (Unaudited) June 30, December 31, ($000) 2009 2008 ------------------------------------------------------------------------- ASSETS CURRENT Cash $ 391,160 $ 223,663 Restricted cash (Note 9(c)) 10,000 - Accounts receivable 47,794 20,492 Inventories (Note 5) 52,494 35,993 Income taxes recoverable 14,335 13,875 Prepaid expenses 2,566 2,221 Due from Petrolifera 75 42 ------------------------------------------------------------------------- 518,424 296,286 Property and equipment 1,053,471 985,054 Goodwill 103,676 103,676 Investment in Petrolifera 47,799 46,659 ------------------------------------------------------------------------- $ 1,723,370 $ 1,431,675 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES CURRENT Accounts payable and accrued liabilities $ 46,913 $ 98,372 Risk management contracts (Note 4(b)) 16,510 - ------------------------------------------------------------------------- 63,423 98,372 Long term debt (Note 4(e)) 960,593 778,732 Future income taxes 48,591 58,296 Asset retirement obligations (Note 6) 27,727 26,396 Employee future benefits 801 792 ------------------------------------------------------------------------- 1,101,135 962,588 ------------------------------------------------------------------------- SHAREHOLDERS' EQUITY Share capital, contributed surplus and equity component (Note 7) 606,493 437,899 Retained earnings 16,508 23,386 Accumulated other comprehensive income (loss) (766) 7,802 ------------------------------------------------------------------------- 622,235 469,087 ------------------------------------------------------------------------- $ 1,723,370 $ 1,431,675 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS (Unaudited) Three months ended Six months ended June 30 June 30 ------------------------------------------------------------------------- ($000, except per share amounts) 2009 2008 2009 2008 ------------------------------------------------------------------------- REVENUES Upstream, net of royalties (Note 4(b)) $ 33,882 $ 83,483 $ 62,028 $ 111,409 Downstream 66,091 117,820 98,774 189,719 Interest and other income 246 713 1,174 1,544 ------------------------------------------------------------------------- 100,219 202,016 161,976 302,672 ------------------------------------------------------------------------- EXPENSES Upstream - diluent purchases and operating costs 23,654 50,909 51,690 64,901 Upstream transportation costs 2,575 2,934 5,482 3,428 Downstream - crude oil purchases and operating costs (Note 5) 65,611 117,926 96,331 189,319 General and administrative 3,224 2,911 7,698 5,977 Finance charges 8,877 10,298 18,037 14,729 Stock-based compensation (Note 7(b)) 551 1,181 1,821 2,697 Foreign exchange loss (gain) (Note 4(d)) (65,411) 3,317 (37,545) 5,209 Depletion, depreciation and accretion 16,538 13,825 32,987 21,289 ------------------------------------------------------------------------- 55,619 203,301 176,501 307,549 ------------------------------------------------------------------------- Earnings (loss) before income taxes and other items 44,600 (1,285) (14,525) (4,877) Current income tax provision 121 660 293 1,477 Future income tax provision (recovery) 5,369 373 (6,801) (1,790) ------------------------------------------------------------------------- 5,490 1,033 (6,508) (313) ------------------------------------------------------------------------- Earnings (loss) before other items 39,110 (2,318) (8,017) (4,564) Equity interest in Petrolifera earnings 856 935 1,139 1,390 Dilution gain (Note 9(d)) - 8,066 - 8,024 ------------------------------------------------------------------------- NET EARNINGS (LOSS) $ 39,966 6,683 $ (6,878) 4,850 RETAINED EARNINGS, (DEFICIT) BEGINNING OF PERIOD (23,458) 48,156 23,386 49,989 ------------------------------------------------------------------------- RETAINED EARNINGS, END OF PERIOD $ 16,508 $ 54,839 $ 16,508 $ 54,839 ------------------------------------------------------------------------- EARNINGS PER SHARE (Note 9(a)) Basic $ 0.15 $ 0.03 $ (0.03) $ 0.02 Diluted $ 0.14 $ 0.03 $ (0.03) $ 0.02 ------------------------------------------------------------------------- CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited) Three months ended Six months ended June 30 June 30 ------------------------------------------------------------------------- ($000) 2009 2008 2009 2008 ------------------------------------------------------------------------- Net earnings (loss) $ 39,966 $ 6,683 $ (6,878) $ 4,850 Foreign currency translation adjustment (12,999) (429) (8,568) 3,080 ------------------------------------------------------------------------- Comprehensive income (loss) $ 26,967 $ 6,254 $ (15,446) $ 7,930 ------------------------------------------------------------------------- CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Unaudited) Three months ended Six months ended June 30 June 30 ------------------------------------------------------------------------- ($000) 2009 2008 2009 2008 ------------------------------------------------------------------------- Balance, beginning of period $ 12,233 $ (10,127) $ 7,802 $ (13,636) Foreign currency translation adjustment (12,999) (429) (8,568) 3,080 ------------------------------------------------------------------------- Balance, end of period $ (766) $ (10,556) $ (766) $ (10,556) ------------------------------------------------------------------------- CONSOLIDATED STATEMENTS OF CASH FLOW (Unaudited) Three months ended Six months ended June 30 June 30 ------------------------------------------------------------------------- ($000) 2009 2008 2009 2008 ------------------------------------------------------------------------- Cash provided by (used in) the following activities: OPERATING Net earnings (loss) $ 39,966 $ 6,683 $ (6,878) $ 4,850 Items not involving cash: Depletion, depreciation and accretion 16,538 13,825 32,987 21,289 Stock-based compensation 551 1,181 1,821 2,697 Finance charges - non cash portion 1,134 4,058 2,175 5,307 Employee future benefits 107 114 294 227 Future income tax provision (recovery) 5,369 373 (6,801) (1,790) Unrealized loss on risk management contracts 8,243 - 16,510 - Unrealized foreign exchange loss (gain) (61,482) 3,317 (33,616) 5,209 Gain on repurchase of Second Lien Senior Notes - - (475) - Equity interest in Petrolifera earnings (856) (935) (1,139) (1,390) Dilution gain (Note 9(d)) - (8,066) - (8,024) ------------------------------------------------------------------------- Cash flow from operations before changes in non- cash working capital and other changes 9,570 20,550 4,878 28,375 Changes in non-cash working capital (Note 9(b)) (26,364) (12,863) (50,668) 8,907 Asset retirement expenditures (29) (83) (133) (206) Pension funding (234) - (234) - ------------------------------------------------------------------------- (17,057) 7,604 (46,157) 37,076 ------------------------------------------------------------------------- FINANCING Issue of common shares (Note 7(a)) 172,586 - 172,586 - Share issue costs (8,785) - (8,785) - Exercise of stock options (Note 7) 160 675 160 692 Issuance of First Lien Senior Notes 226,475 - 226,475 - Debt issue costs (20,858) - (20,858) - Repurchase of Second Lien Senior Notes - - (309) - Deferred financing costs - 5 - (77) ------------------------------------------------------------------------- 369,578 680 369,269 615 ------------------------------------------------------------------------- INVESTING Acquisition and development of oil and gas properties (39,620) (73,139) (102,764) (187,194) Decrease (increase) in restricted cash - 33,546 (10,000) 30,773 Change in non-cash working capital (Note 9(b)) (14,155) (25,249) (49,523) (12,849) ------------------------------------------------------------------------- (53,775) (64,842) (162,287) (169,270) ------------------------------------------------------------------------- NET INCREASE (DECREASE) IN CASH 298,746 (56,558) 160,825 (131,579) Foreign exchange gains (losses) on U.S. dollar cash balances held 6,194 (615) 6,672 2,785 CASH, BEGINNING OF PERIOD 86,220 257,489 223,663 329,110 ------------------------------------------------------------------------- CASH, END OF PERIOD $ 391,160 $ 200,316 $ 391,160 $ 200,316 ------------------------------------------------------------------------- Supplementary information - Note 9 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (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. ("MRCI"), the company is in the business of exploring, developing, producing, refining and marketing crude oil, bitumen 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, 2008, except as described 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, 2008. 3. NEW ACCOUNTING STANDARDS In February 2008, the Canadian Institute of Chartered Accountants ("CICA") issued Section 3064, "Goodwill and Intangible Assets", replacing Section 3062, "Goodwill and Other Intangible Assets". The new Section has been applied since January 1, 2009. Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit- oriented enterprises. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062 and, therefore, did not have any impact on the company's consolidated financial statements. In January 2009, the CICA Emerging Issues Committee ("EIC") issued EIC- 173, "Credit risk and the fair value of financial assets and liabilities", which requires that an entity's own credit risk and counterparty credit risk be taken into account in determining the fair value of financial assets and liabilities, including derivative financial instruments. The provisions of EIC-173 apply to all financial assets and liabilities measured at fair value in interim and annual financial statements for periods ending on or after January 20, 2009. The adoption of this standard had no material impact on the company's consolidated financial statements. In June 2009, the CICA issued amendments to CICA Handbook Section 3862, Financial Instruments - Disclosures. The amendments include enhanced disclosures related to the fair value of financial instruments and the liquidity risk associated with financial instruments. The amendments will be effective for annual financial statements for fiscal years ending after September 30, 2009 and are consistent with recent amendments to financial instrument disclosure standards in IFRS. The company will include these additional disclosures in its annual consolidated financial statements for the year ending December 31, 2009. Over the next two years the CICA will adopt its new strategic plan for the direction of accounting standards in Canada, which was ratified in January 2006. As part of the plan, Canadian GAAP for public companies will converge with International Financial Reporting Standards ("IFRS") with an effective date of January 1, 2011. The company continues to monitor and assess the impact of the convergence of Canadian GAAP with IFRS. 4. FINANCIAL INSTRUMENTS AND CAPITAL RISK MANAGEMENT FINANCIAL INSTRUMENTS Financial assets and financial liabilities "held-for-trading" are measured at fair value with changes in those fair values recognized in net earnings. Financial assets "available-for-sale" are measured at fair value, with changes in those fair values recognized in Other Comprehensive Income ("OCI"). Financial assets "held-to-maturity," "loans and receivables" and "other financial liabilities" are measured at amortized cost using the effective interest rate method of amortization. The company has classified all of its financial instruments, with the exception of the First and Second Lien Senior Notes and the Convertible Debentures as "held for trading". This classification has been chosen due to the nature of the company's financial instruments, which, except for the First and Second Lien Senior Notes 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. The First and Second Lien Senior Notes and the Convertible Debentures have been classified as "other financial liabilities" and are accounted for on the amortized cost method, with transaction costs being amortized over the life of the instruments using the effective interest rate method. CAPITAL RISK MANAGEMENT The company is exposed to financial risks on a range of financial instruments including its cash, accounts receivable and payable, amounts due from Petrolifera, the Convertible Debentures and the First and Second Lien Senior Notes. The company is also exposed to risks in the way it finances its capital requirements. The company manages these financial and capital structure risks by operating in a manner that minimizes its exposures to volatility of the company's financial performance. These risks affecting the company are discussed below. (a) Credit risk Credit risk is the risk that a contracting entity will not fulfill its obligations under a financial instrument and cause a financial loss to the company. To help manage this risk, the company has a policy for establishing credit limits, requiring collateral before extending credit to customers where appropriate and monitoring outstanding accounts receivable. The company's financial assets subject to credit risk arise from the sale of crude oil, bitumen, natural gas and refined products to a number of large integrated oil companies and product retailers and are subject to normal industry credit risks. The fair value of accounts receivable and accounts payable closely approximates their carrying values due to the relatively short periods to maturity of these instruments. The maximum exposure to credit risk is represented by the carrying amount on the consolidated balance sheet. The company regularly assesses its financial assets for impairment losses. There are no material financial assets that the company considers past due and no allowance for uncollectible accounts is considered necessary. The majority of the company's upstream revenues are composed of bitumen sales. Substantially all of the company's bitumen sales were made to two customers in the first half of 2009. (b) Market risk Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market prices. The company is exposed to market risk as a result of potential changes in the market prices of its crude oil, bitumen, natural gas and refined product sales volumes. A portion of this risk is mitigated by Connacher's integrated business model. The cost of purchasing natural gas for use in its oil sands and refinery operations is offset by the company's monthly conventional natural gas sales; and the selling price of the company's dilbit sales largely equates to the purchase price of heavy crude oil required for processing at its refinery. Petroleum commodity futures contracts, price swaps and collars may be utilized to reduce exposure to price fluctuations associated with the sales of additional natural gas and crude oil sales volumes and for the sale of refined products. Risk Management Contracts In November 2008, Connacher entered into a foreign exchange collar which sets a floor of CAD$1.1925 per U.S.$1.00 and a ceiling of CAD$1.30 per U.S.$1.00 on a notional amount of U.S.$10 million of production revenue per month throughout 2009. At June 30, 2009 the fair value of this contract was an asset of $3.1 million, which is recorded in accounts receivable on the consolidated balance sheet. For the year to date, an unrealized foreign exchange gain of $1.3 million and a realized foreign exchange gain of $1.1 million was included in the net foreign exchange gain on the consolidated statement of operations in respect of this contract. A $0.01 change on the USD/CAD exchange rate would result in a $500,000 change in the fair value of the collar. Connacher has entered into derivative contracts to fix the WTI crude oil price on a portion of its production at a price of U.S.$46.00/bbl on a notional volume of 2,500 barrels per day until August 31, 2009 and at a price of U.S.$49.50/bbl on a notional volume of 2,500 bbl/d until December 31, 2009. On June 30, 2009, Connacher put in place a WTI crude oil "collar" contract on a notional volume of 2,500 bbl/d of bitumen production from September 1 to December 31, 2009 with a floor of U.S.$60.00/bbl and a ceiling of U.S.$84.00/bbl. At June 30, 2009 the fair value of these derivative contracts was a liability of $16.5 million and a $16.5 million loss was recorded in upstream revenue on the consolidated statement of operations for the year to date. A U.S.$1.00 change in WTI would result in a $815,000 change in the value of the derivatives, resulting in a similar impact on earnings. (c) Interest rate risk Interest rate risk refers to the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market interest rates. The company's First and Second Lien Senior Notes and Convertible Debentures have fixed interest rate obligations and, therefore, are not subject to changes in variable interest rates. (d) Currency risk Currency risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in foreign exchange rates. As Connacher incurs the majority of its expenditures in Canadian dollars, it is exposed to the impact of fluctuations in the U.S./Canadian dollar exchange rate on pricing of its sales of crude oil and bitumen (which are generally priced by reference to U.S. dollars but settled in Canadian dollars) and for the translation of its U.S. refining operating results, its U.S. dollar cash holdings and its U.S. dollar denominated First and Second Lien Senior Notes to Canadian dollars for financial statement reporting purposes. In 2009, we had unrealized foreign exchange translation gains of $61.5 million in the second quarter and $33.6 million for the year to date; and we realized foreign exchange gains of $3.9 million in the second quarter and in the year to date, 2009 from the foreign exchange revenue collar and upon the settlement of U.S. dollar denominated obligations. Throughout most of 2008, we had a cross-currency swap in place to hedge one-half of the foreign exchange exposure on our U.S. dollar debt. This insulated us from some foreign currency volatility and reduced the impact of a weaker Canadian dollar, which resulted in the unrealized foreign exchange translation losses reported in the comparative 2008 periods. Relative to the company's U.S. dollar cash balances, its crude oil and bitumen revenue receivables, and its First and Second Lien Senior Notes, a $0.01 change in the Canadian dollar exchange rate would have resulted in a change in net earnings of $5.7 million for the six months ended June 30, 2009 (six months ended June 30, 2008 - $900,000). (e) Liquidity risk Liquidity risk is the risk that the company will not have sufficient funds to repay its debts and fulfill its financial obligations. To manage this risk, the company follows a conservative financing philosophy, pre-funds major development projects, monitors expenditures against pre-approved budgets to control costs, regularly monitors its operating cash flow, working capital and bank balances against its business plan, usually maintains accessible revolving banking lines of credit and maintains prudent insurance programs to minimize exposure to insurable losses. On June 16, 2009, the company issued U.S.$200 million face value of 11.75 percent First Lien Senior Secured Notes (the "First Lien Senior Notes") at a price of 93.678 percent for gross proceeds of U.S.$187.4 million. The First Lien Senior Notes are not repayable until July 15, 2014 and are secured on a first priority basis (subject to specified liens up to U.S.$50 million for prior ranking senior debt) by liens on all of the company's assets, excluding Connacher's investment holding in Petrolifera. The long-term nature of the company's debt repayment obligations is structured to be aligned to the long-term nature of its assets. The Convertible Debentures do not mature until June 30, 2012, unless converted to common shares earlier and principal repayments are not required on the First Lien Senior Notes until July 15, 2014 and on the Second Lien Senior Notes until their maturity date of December 15, 2015. This affords Connacher the opportunity to deploy its conventional, oil sands and refining cash flow to fund the development of further expansion projects over the next few years without having to make principal payments or raise new capital unless expenditures exceed cash flow and credit capacity. At June 30, 2009, the fair values of the Convertible Debentures, the First Lien Senior Notes and Second Lien Senior Notes were $57 million, $224 million and $406 million, respectively, based on their quoted market prices. As at June 30, 2009, the company's long-term debt was repayable as follows: - Convertible Debentures - June 30, 2012 in the amount of $100,014,000, unless converted into common shares prior thereto; - First Lien Senior Notes - July 15, 2014 in the amount of U.S.$200 million; and - Second Lien Senior Notes - December 15, 2015 in the amount of U.S.$591.3 million. Connacher's 13.1 million shares held in Petrolifera, which trade on the TSX, also provides liquidity, as they have not been collateralized. Although it is not Connacher's intention to sell these shares in the foreseeable future, the shareholding provides Connacher an additional margin of financial flexibility. (f) Capital risks Connacher's objectives in managing its cash, debt and equity (its capital or capital structure) and its future capital requirements are to safeguard its ability to meet its financial obligations, to maintain a flexible capital structure that allows multiple financing options when a financing need arises and to optimize its use of short-term and long-term debt and equity at an appropriate level of risk. The company manages its capital structure and follows a financial strategy that considers economic and industry conditions, the risk characteristics of its underlying assets and its growth opportunities. It strives to continuously improve its credit rating and reduce its cost of capital. Connacher monitors its capital using a number of financial ratios and industry metrics to ensure its objectives are being met. Connacher's long-term debt contains no financial or maintenance covenants. In March 2009, the company cancelled its Revolving Credit Facility and put in place a $20 million demand operating banking facility ("the L/C facility") for the purposes of issuing letters of credit. The L/C facility is secured by cash of $10 million and a first lien claim on certain assets of the company and contains no financial or maintenance covenants. At June 30, 2009, the L/C Facility secured letters of credit in the amount of $5.9 million. Connacher's current capital structure and certain financial ratios are noted below. As at As at June 30, December 31, 2009 2008 ------------------------------------------------------------------------- ($000) ------------------------------------------------------------------------- Long term debt(1) $ 960,593 $ 778,732 Shareholders' equity Share capital, contributed surplus and equity component 606,493 437,899 Accumulated other comprehensive income (loss) (766) 7,802 Retained earnings 16,508 23,386 ------------------------------------------------------------------------- Total $ 1,582,828 $ 1,247,819 ------------------------------------------------------------------------- Debt to book capitalization(2) 61% 62% Debt to market capitalization(3) 71% 81% ------------------------------------------------------------------------- (1) Long-term debt is stated at its carrying value, which is net of transaction costs and the Convertible Debentures' equity component value. (2) Calculated as long-term debt divided by the book value of shareholders' equity plus long-term debt. (3) Calculated as long-term debt divided by the period end market value of shareholders' equity plus long-term debt. Connacher currently has a high calculated ratio of debt to capitalization. This is due to pre-funding the full cost of Algar. As at June 30, 2009, the company's net debt (long-term debt, net of cash on hand) was $559.4 million and its calculated ratio of net debt to book capitalization was 47 percent and its net debt to market capitalization was 59 percent. 5. INVENTORIES Inventories consist of the following: June 30, December 31, ($000) 2009 2008 ------------------------------------------------------------------------- Crude oil $ 5,572 $ 3,433 Other raw materials and unfinished products(1) 1,860 1,762 Refined products(2) 37,565 18,901 Process chemicals(3) 3,670 8,110 Repairs and maintenance supplies and other(4) 3,827 3,787 ------------------------------------------------------------------------- $ 52,494 $ 35,993 ------------------------------------------------------------------------- (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, transportation and direct production costs. (3) Process chemicals include catalysts, additives and other chemicals. The inventory carrying value includes the cost of the purchased chemicals and related freight. (4) Repair and maintenance supplies in crude refining and oil sands supplies. Inventories are valued at the lower of cost and net realizable value. At December 31, 2008, net realizable value was lower than cost and therefore, net realizable values were used to value most refined inventory products. At June 30, 2009, the net realizable value of most refined products was higher than their cost, so average cost was used to value most refined inventory products. As a result, refined inventory product values at June 30, 2009 increased from December 31, 2008 by approximately $11 million and downstream crude oil purchases and operating costs were lower than they otherwise would have been by $11 million in the first half of 2009. Included in downstream crude oil purchases and operating costs for the three months ended June 30, 2009 was approximately $58 million of inventory costs (three months ended June 30, 2008 - $110 million) and for the six months ended June 30, 2009, this amount was approximately $79 million (six months ended June 30, 2008 - $174 million). 6. ASSET RETIREMENT OBLIGATIONS The following table reconciles the beginning and ending aggregate carrying amount of the obligation associated with the company's retirement of its oil sands and conventional petroleum and natural gas properties and facilities. Six months Year ended ended June 30, December 31, ($000) 2009 2008 ------------------------------------------------------------------------- Asset retirement obligations, beginning of period $ 26,396 $ 24,365 Liabilities incurred 483 1,496 Liabilities settled (133) (209) Change in estimated future cash flows - (960) Accretion expense 981 1,704 ------------------------------------------------------------------------- Asset retirement obligations, end of period $ 27,727 $ 26,396 ------------------------------------------------------------------------- Liabilities incurred in 2009 have been estimated using a discount rate of 10 percent reflecting the company's credit-adjusted risk free interest rate given its current capital structure and an inflation rate of two percent. The company has not recorded an asset retirement obligation for the Montana refinery as it is currently the company's intent to maintain and upgrade the refinery so that it will be operational for the foreseeable future. Consequently, it is not possible to estimate a date or range of dates for settlement of any asset retirement obligation related to the refinery. 7. SHARE CAPITAL, CONTRIBUTED SURPLUS AND EQUITY COMPONENT Authorized The authorized share capital comprises the following: - Unlimited number of common voting shares - Unlimited number of first preferred shares - Unlimited number of second preferred shares Issued Only common shares have been issued by the company. Number of Amount Shares ($000) ------------------------------------------------------------------------- Share Capital, December 31, 2008 211,181,815 $ 395,023 Issued for cash in public offering(a) 191,762,500 172,586 Issued upon exercise of options in 2009(b) 266,504 160 Assigned value of options exercised in 2009 63 Issued to directors under share award plan(c) 327,623 301 Conversion of debentures(d) 7,200 37 Share issue costs, net of income taxes (6,489) ------------------------------------------------------------------------- Share Capital, June 30, 2009 403,545,642 561,681 ------------------------------------------------------------------------- Contributed Surplus, December 31, 2008 26,053 Stock based compensation for share options in 2009 2,005 Assigned value of options exercised in 2009 (63) ------------------------------------------------------------------------- Contributed Surplus, June 30, 2009 27,995 ------------------------------------------------------------------------- Equity component of Convertible Debentures, December 31, 2008 16,823 Conversion of debentures(d) (6) ------------------------------------------------------------------------- Equity Component, June 30, 2009 16,817 ------------------------------------------------------------------------- Total Share Capital, Contributed Surplus and Equity Component December 31, 2008 437,899 ------------------------------------------------------------------------- June 30, 2009 606,493 ------------------------------------------------------------------------- (a) June 2009 Common Share Issue In June 2009, the company issued from treasury 191,762,500 common shares at $0.90 per common share, for gross proceeds of $172.6 million. (b) Stock Options A summary of the company's outstanding stock options, as at June 30, 2009 and 2008 and changes during those periods is presented below: For the six months ended June 30 2009 2008 ------------------------------------------------------------------------- Weighted Weighted Average Average Number of Exercise Number of Exercise Options Price Options Price ------------------------------------------------------------------------- Outstanding, beginning of period 16,383,104 $ 3.16 17,432,717 $ 3.60 Granted 4,375,947 $ 0.72 2,743,792 $ 3.22 Exercised (266,504) $ 0.60 (946,934) $ 0.81 Expired (4,913,598) $ 4.77 (155,782) $ 3.85 ------------------------------------------------------------------------- Outstanding, end of period 15,578,949 $ 2.01 19,073,793 $ 3.68 ------------------------------------------------------------------------- Exercisable, end of period 9,880,984 $ 2.44 13,254,013 $ 3.70 ------------------------------------------------------------------------- All stock options have been granted for a period of five years. Options granted under the plan are generally fully exercisable after three years. The table below summarizes unexercised stock options. ------------------------------------------------------------------------- Weighted Average Remaining Contractual Number Life at Range of Exercise Prices Outstanding June 30, 2009 ------------------------------------------------------------------------- $0.20 - $0.99 4,952,934 4.0 $1.00 - $1.99 4,436,940 3.4 $2.00 - $3.99 5,231,566 2.4 $4.00 - $5.56 957,509 2.0 ------------------------------------------------------------------------- 15,578,949 3.2 ------------------------------------------------------------------------- In the second quarter of 2009 a non-cash charge of $551,000 million (2008 - $1.2 million) was expensed, reflecting the fair value of stock options amortized over the vesting period and the fair value of shares granted to directors. A further $114,000 (2008 - $224,000) was capitalized to property and equipment. During the first half of 2009 a non-cash charge of $1.8 million (2008 - $2.7 million) was expensed, reflecting the fair value of stock options amortized over the vesting period and the fair value of shares granted to directors. A further $507,000 (2008 - $1.0 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: For the six months ended June 30 2009 2008 ------------------------------------------------------------------------- Risk free interest rate 1.3% 3.1% Expected option life (years) 3 3 Expected volatility 67% 48% ------------------------------------------------------------------------- The weighted average fair value at the date of grant of all options granted in the first six months of 2009 was $0.32 per option (2008 - $1.14) and for the three months ended June 30, 2009 was $0.52 per option (2008 - $1.40). (c) Share award plan for non-employee directors Under the share award plan, share units may be granted to non-employee directors of the company in amounts determined by the Board of Directors on the recommendation of the Governance Committee. Payment under the plan is made by delivering common shares to non-employee directors either through purchases on the TSX or by issuing common shares from treasury, subject to certain limitations. The Board of Directors may alternatively elect to pay cash equal to the fair market value of the common shares to be delivered to non-employee directors upon vesting of such share units in lieu of delivering common shares. In January 2009, 108,975 common shares were issued to non-employee directors in respect of the share units which were then vested. In March 2009, the Board of Directors, on the recommendation of the Governance Committee, voted to accelerate the vesting of 218,648 share units originally scheduled to vest on January 1, 2010 and January 1, 2011 such that they vested immediately. Concurrently, an additional 478,872 share units were granted with vesting on January 1, 2010. In April, 218,648 common shares were issued to non-employee directors. In the first quarter of 2009, 54,662 share units held by a deceased director were cancelled. A total of 489,292 share awards were outstanding at June 30, 2009 and have vested or vest on the following dates: ------------------------------------------------------------------------- Vested 5,210 December 31, 2009 5,210 January 1, 2010 478,872 ------------------------------------------------------------------------- 489,292 ------------------------------------------------------------------------- In the second quarter of 2009, a non-cash charge of $164,000 (2008 - $388,000) was accrued as a liability and expensed in respect of shares yet to be issued under the share award plan. In the first six months of 2009, a non-cash charge of $323,000 (2008 - $433,000) was accrued as an expense and a liability in respect of shares to be issued under the plan. (d) Conversion of debentures In June 2009, $36,000 principal amount of Convertible Debentures were converted to 7,200 common shares. A portion of each of the liability and equity components of the debenture together with the principal amount were transferred to share capital. No gain or loss was recorded. 8. SEGMENTED INFORMATION The company has two business segments. In Canada, the company is in the business of exploring for and producing crude oil, natural gas and bitumen. In the U.S., the company is in the business of refining and marketing petroleum products. Three months ended June 30 Inter- Upstream Downstream segment Canada Oil USA Elimin- ($000) and Gas Refining ation(1) Total ------------------------------------------------------------------------- 2009 Revenues, net of royalties $ 33,882 $ 69,094 (3,003) $ 99,973 Equity interest in Petrolifera earnings 856 - 856 Interest and other income 57 189 246 Finance charges 8,819 58 8,877 Depletion, depreciation and accretion 14,723 1,815 16,538 Tax provision (recovery) 5,773 (283) 5,490 Net earnings (loss) 40,413 (447) 39,966 Property and equipment, net 967,786 85,685 1,053,471 Goodwill 103,676 - 103,676 Capital expenditures 36,724 3,512 40,236 Total assets $1,543,740 $ 179,630 $1,723,370 ------------------------------------------------------------------------- 2008 Revenues, net of royalties $ 83,483 $ 117,820 $ 201,303 Equity interest in Petrolifera earnings 935 - 935 Dilution gain 8,066 - 8,066 Interest and other income 605 108 713 Finance charges 10,199 99 10,298 Depletion, depreciation and accretion 12,429 1,396 13,825 Tax provision (recovery) 2,532 (1,499) 1,033 Net earnings (loss) 9,230 (2,547) 6,683 Property and equipment, net 788,042 61,729 849,771 Goodwill 103,676 - 103,676 Capital expenditures 75,475 4,928 80,403 Total assets $1,183,469 $ 155,236 $1,338,705 ------------------------------------------------------------------------- Six months ended June 30 Inter- Upstream Downstream segment Canada Oil USA Elimin- ($000) and Gas Refining ation(1) Total ------------------------------------------------------------------------- 2009 Revenues, net of royalties $ 62,028 $ 102,246 (3,472) $ 160,802 Equity interest in Petrolifera earnings 1,139 - 1,139 Interest and other income 791 383 1,174 Finance charges 17,676 361 18,037 Depletion, depreciation and accretion 29,323 3,664 32,987 Tax provision (recovery) (5,361) (1,147) (6,508) Net earnings (loss) (5,238) (1,640) (6,878) Property and equipment, net 967,786 85,685 1,053,471 Goodwill 103,676 - 103,676 Capital expenditures 97,723 6,768 104,491 Total assets $1,543,740 $ 179,630 $1,723,370 ------------------------------------------------------------------------- 2008 Revenues, net of royalties $ 111,409 $ 189,719 $ 301,128 Equity interest in Petrolifera earnings 1,390 - 1,390 Dilution gain 8,024 - 8,024 Interest and other income 1,311 233 1,544 Finance charges 14,571 158 14,729 Depletion, depreciation and accretion 18,645 2,644 21,289 Tax provision (recovery) 1,830 (2,143) (313) Net earnings (loss) 7,361 (2,511) 4,850 Property and equipment, net 788,042 61,729 849,771 Goodwill 103,676 - 103,676 Capital expenditures 188,432 7,956 196,388 Total assets $1,183,469 $ 155,236 $1,338,705 ------------------------------------------------------------------------- (1) Intersegment transactions are eliminated on consolidation. 9. SUPPLEMENTARY INFORMATION (a) Per share amounts The following table summarizes the common shares used in earnings per share calculations. For the three months ended June 30 (000) 2009 2008 ------------------------------------------------------------------------- Weighted average common shares outstanding 266,425 210,658 Dilutive effect of stock options, share units under the non-employee directors share award plan and Convertible Debentures 20,560 3,872 ------------------------------------------------------------------------- Weighted average common shares outstanding - diluted 286,985 214,530 ------------------------------------------------------------------------- For the six months ended June 30 (000) 2009 2008 ------------------------------------------------------------------------- Weighted average common shares outstanding 239,008 210,446 Dilutive effect of stock options and share units under the non-employee directors share award plan and Converible Debentures - 2,878 ------------------------------------------------------------------------- Weighted average common shares outstanding - diluted 239,008 213,324 ------------------------------------------------------------------------- The Convertible Debentures, stock options and share units were anti-dilutive to the loss per share calculation for the six months ended June 30, 2009. (b) Net change in non-cash working capital For the three months ended June 30 ------------------------------------------------------------------------- ($000) 2009 2008 ------------------------------------------------------------------------- Accounts receivable $ (25,477) $ (6,847) Inventories (1,287) 492 Due from Petrolifera 2 44 Prepaid expenses 5,640 192 Accounts payable and accrued liabilities (19,823) (32,260) Income taxes payable/recoverable 426 267 ------------------------------------------------------------------------- Total $ (40,519) $ (38,112) ------------------------------------------------------------------------- Summary of working capital changes: Operations $ (26,364) $ (12,863) Investing (14,155) (25,249) ------------------------------------------------------------------------- $ (40,519) $ (38,112) ------------------------------------------------------------------------- For the six months ended June 30 2009 2008 ------------------------------------------------------------------------- ($000) ------------------------------------------------------------------------- Accounts receivable $ (27,449) $ (34,344) Due from Petrolifera (33) 37 Prepaid expenses (2,696) 1,184 Inventories (19,819) (19,162) Accounts payable and accrued liabilities (49,063) 48,664 Income taxes payable/recoverable (1,131) (321) ------------------------------------------------------------------------- Total $ (100,191) $ (3,942) ------------------------------------------------------------------------- Summary of working capital changes: Operations $ (50,668) $ 8,907 Investing (49,523) (12,849) ------------------------------------------------------------------------- $ (100,191) $ (3,942) ------------------------------------------------------------------------- (c) Supplementary cash flow information For the three months ended June 30 2009 2008 ------------------------------------------------------------------------- ($000) ------------------------------------------------------------------------- Interest paid $ 36,805 $ 34,953 Income taxes paid 19 245 ------------------------------------------------------------------------- For the six months ended June 30 2009 2008 ------------------------------------------------------------------------- ($000) ------------------------------------------------------------------------- Interest paid $ 37,532 $ 35,336 Income taxes paid 1,363 1,372 ------------------------------------------------------------------------- At June 30, 2009 cash of $10 million was restricted to provide cash collateral to support letters of credit (Note 4(f)). (d) Dilution gain In June 2008, Petrolifera issued an additional 4.4 million common shares to raise $40 million. Connacher did not subscribe for any of these shares. Consequently, Connacher's equity interest in Petrolifera was reduced from 26 percent to 24 percent. As a result, a dilution gain of $8 million was recognized by Connacher in the second quarter of 2008. (e) Defined benefit pension plan In the first six months of 2009, $294,000 (2008 - $227,000) three months ended June 30, 2009 - $107,000 (2008 - $114,000) was changed to expense in relation to MRCI's defined benefit pension plan.

For further information:

For further information: Richard A. Gusella, President and Chief
Executive Officer; OR Grant D. Ukrainetz, Vice President, Corporate
Development, Phone: (403) 538-6201, Fax: (403) 538-6225,
inquiries@connacheroil.com, Website: www.connacheroil.com


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