Highpine Oil & Gas Limited announces third quarter 2007 financial and operational results



    CALGARY, Nov. 8 /CNW/ - Highpine Oil & Gas Limited (TSX: HPX) ("Highpine"
or the "Company") announces its financial and operational results for the
third quarter ended September 30, 2007 and provides an operational update:


    
    FINANCIAL AND OPERATING RESULTS

    -------------------------------------------------------------------------
                          Three months ended          Nine months ended
    ($000s, except           September 30,               September 30,
     per share and                          %                            %
     share numbers)     2007        2006  Change     2007        2006  Change
    -------------------------------------------------------------------------

    Financial
    Total
     revenue(1)       89,439      60,205    49     279,119     187,386    49
    Cash from
     operations(2)    43,984      31,171    41     135,483      97,467    39
      Per share -
       diluted          0.65        0.49    33        2.00        1.76    14
    Net earnings
     (loss)(3)      (359,513)        514     -    (364,859)     12,399     -
      Per share -
       diluted         (5.30)       0.01     -       (5.39)       0.22     -
    Net debt(4)      170,805     123,758    38     170,805     123,758    38
    Total assets   1,044,815   1,361,249   (23)  1,044,815   1,361,249   (23)
    Capital
     expenditures(5)  37,073      56,144   (34)    137,565     149,503    (8)
    Total shares
     outstanding
     (No.)            67,878      67,641     -      67,878      67,641     -
    Weighted average
     shares
     Outstanding -
     diluted (No.)    67,856      63,356     7      67,735      55,353    22
    -------------------------------------------------------------------------
    Operating
    Average daily
     production
      Crude oil and
       NGLs (bbls/d)  10,143       6,675    52      10,637       7,184    48
      Natural gas
       (mcf/d)        34,637      24,837    39      38,593      23,708    63
    -------------------------------------------------------------------------
      Total (boe/d)   15,916      10,814    47      17,069      11,135    53
    -------------------------------------------------------------------------
    Average selling
     prices(6)
      Crude oil and
       NGLs ($/bbl)    75.28       70.71     6       68.32       69.37    (2)
      Natural gas
       ($/mcf)          6.07        6.27    (3)       7.56        6.98     8
    -------------------------------------------------------------------------
      Total ($/boe)    61.20       58.05     5       59.67       59.61     -
    -------------------------------------------------------------------------
    Wells drilled -
     gross (net) (No.)
      Oil              3(2.0)      3(2.5)    -       6(4.2)      7(5.3)    -
      Natural Gas      3(2.0)     12(8.8)    -      12(7.9)    35(20.4)    -
      Abandoned/
       other           2(1.2)      4(3.1)    -       8(5.6)     13(7.7)    -
    -------------------------------------------------------------------------
      Total            8(5.2)    19(14.4)    -     26(17.7)    55(33.4)    -
      Drilling
       success
       rate (%)           76          85     -          78          82     -
    -------------------------------------------------------------------------
    Operating
     netback
     ($/boe)
      Oil and
       natural gas
       sales           61.20       58.05     5       59.67       59.61     -
      Royalties       (17.88)     (14.02)   28      (17.22)     (17.07)    1
      Operating
       costs           (9.76)      (9.52)    3       (9.71)      (7.80)   24
      Transportation
       costs           (0.76)      (0.98)  (22)      (0.96)      (0.75)   28
      Realized
       hedging gain     0.80        1.68   (52)       0.85        1.31   (35)
    -------------------------------------------------------------------------
      Operating
       netback         33.60       35.21    (5)      32.63       35.30    (8)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Total revenue includes realized and unrealized hedging losses and
        gains.
    (2) Cash from operations is calculated as cash flow from operating
        activities before the change in non-cash working capital and
        abandonment expenditures.
    (3) Net loss for the 2007 periods includes a non-cash goodwill impairment
        charge of $358.1 million
    (4) Net debt includes working capital excluding unrealized financial
        instruments.
    (5) Capital expenditures include property acquisitions and are presented
        net of proceeds of disposals.
    (6) The average selling prices reported are before hedging activities.


    THIRD QUARTER OPERATIONAL HIGHLIGHTS - 2007

    -   For the nine months period ending September 30, 2007, production
        averaged 17,069, compared with 11,135 in the 2006 period.
        Hydrocarbon production averaged 15,916 boe/d for the quarter,
        consisting of 10,143 bbls/d of oil and NGL's and 34.64 mmcf/d of gas,
        compared to 10,814 boe/d in the third quarter of 2006, an increase of
        47 percent.

    -   Total revenue increased 49 percent to $89.4 million from
        $60.2 million in the comparable 2006 period.

    -   Cash from operations increased 41 percent to $44.0 million from
        $31.2 million in the third quarter of 2006. Cash flow per diluted
        share was $0.65.

    -   Operating netbacks after realized hedging remained strong at
        $33.60/boe for the third quarter of 2007 and $32.63/boe for the first
        nine months of 2007.

    -   Capital expenditures of $37.1 million were incurred focused mainly in
        the Pembina Nisku Fairway.

    -   Highpine obtained six (6) critical sour Nisku well licences in the
        Pembina area during the third quarter. Currently, twenty five (25)
        Nisku well licence applications are awaiting approval at the Energy
        Utilities Board ("EUB") and we have ten (10) approved licences in
        inventory.

    -   Eight (8) wells were drilled during the third quarter, resulting in
        3 (2.0 net) oil wells, 3 (2.0 net) gas wells and 2 (1.2 net) dry
        holes, resulting in a 76 percent drilling success ratio. During the
        first nine months of 2007, 26 (17.7 net) wells were drilled resulting
        in 6 (4.2 net) oil wells, 12 (7.9 net) gas wells, 2 (1.7 net) service
        wells and 6 (3.9 net) dry holes which resulted in a 78 percent
        drilling success ratio.

    -   Highpine reduced its total debt (including working capital
        deficiency) to $170.8 million from $178.0 million at the end of the
        second quarter of 2007. The amount of the bank loan at the end of the
        third quarter was $162.3 million.

    -   Highpine reduced its third quarter 2007 net general & administrative
        expenses per boe to $1.87, 18 percent lower than the third quarter of
        2006.
    

    OPERATIONS

    During the third quarter, production averaged 15,916 boe/d, despite
multiple third party gas plant turnarounds and continued production
curtailments through these facilities. Highpine successfully completed the
turnaround of its operated Violet Grove battery concurrent with the third
party gas plant turnarounds. During October, production averaged 19,185 boe/d
based on field estimates. Additional optimization of several new tie-ins will
be completed prior to year-end; as well third party gas processing facilities
are expected to be fully operational through the balance of the year.
    Since June, Highpine has cased five (4.25 net) Nisku wells in the Pembina
Nisku Fairway. Two (1.82 net) wells have been completed as condensate rich gas
wells, one (1) has been completed as an oil well and 2.0 (1.425 net) are
waiting on completion. One of the wells currently being completed is the
4200 m measured depth long reach well into the up-dip end of the Pembina Nisku
WW Pool. This well encountered a thick porous reef as expected, with no
hydrocarbon-water interface and is currently being completed as an oil well.
Production facilities are currently being constructed.
    A new Cretaceous 100% well at Joffre is on-stream at rates in excess of
500 mcf/d of gas.
    A recently completed 50% interest Cretaceous gas well at Ansell is
on-stream at a restricted gross rate of 2.8 mmcf/d, plus natural gas liquids.
We are currently completing a nearby well which indicates similar potential
production rates. Production rates at Ansell will be restricted until facility
modifications are completed in March, 2008.
    Currently, one (1) drilling rig is active on a Highpine operated well
targeting the Nisku formation. The Company plans to have 2 rigs drilling
through the balance of 2007 targeting the Nisku formation.
    Going forward into the fourth quarter, we will complete and tie-in
4 recently drilled Nisku wells including the long reach well at 16-36-48-8W5.
    Highpine has been successful in obtaining five (5) critical sour Nisku
well licences in the Pembina area during the fourth quarter. Highpine is
working on additional Nisku well licence applications that will be submitted
to the EUB for approval during the fourth quarter and the first quarter of
2008. The Company is currently in a EUB public hearing for two Nisku wells
located near the community of Rocky Rapids and has requested one additional
EUB hearing for five (5) Nisku well locations.

    FINANCIAL

    A decline in the Company's share price that in part, can be attributed to
the recent Alberta Royalty Announcement, resulted in a $358.1 million goodwill
impairment during the third quarter. Goodwill, arising from corporate
acquisitions made in prior years, represents the excess of the purchase price
paid for the acquisitions over the fair value of the net assets acquired. The
$358.1 million impairment was recorded as a non-cash charge to earnings for
the quarter ended September 30, 2007. The goodwill write-down is not an
indication of the underlying value of the Company's properties.

    ALBERTA ROYALTY ANNOUNCEMENT

    The Alberta government recently announced changes to the royalties
payable on all crown mineral rights owned by the province. In the event the
Alberta Government proposed royalty framework is enacted, on January 1, 2009
the crown royalty payable on conventional oil production will rise from
approximately 30% to 50% for wells which produce above 60 bbl/d at today's oil
prices. Based on the interpretation of publicly available information,
Highpine estimates that the new royalty would reduce cash flow by 29%,
depending on average well monthly production rates used and an oil price of
US$70 WTI per barrel. Other factors which will affect the calculation include
the actual legislation enacted, the individual well production rates,
commodity prices, foreign exchange rates, product mix, and the percentage of
production from Alberta after January 1, 2009. The Company is still working to
enact certain reductions to the conventional oil royalty based on the depth of
well, which is similar to the proposed rules for deep gas wells.
    Highpine strongly agrees with other Alberta exploration companies that
the royalty changes are discriminatory for companies engaged in high-risk deep
conventional oil exploration such as the Company's Pembina Nisku program. The
new royalties do not strike a balance between risk and reward in our composite
drilling program. The Company will adjust its drilling program by increasing
target size to find that new balance. The Company is likely to make further
adjustments to its capital program as additional information becomes
available. In making its announcement, the Government of Alberta indicated
that it would address any anomalies created by the proposals. Highpine
believes that the effect of the changes to the royalty regime governing light
oil will not only adversely affect Highpine, but will result in reduced
royalty revenue to the Province, as exploration is curtailed. Highpine
continues to discuss with the Province the effect of these proposals on all
stakeholders with a view to arriving at a solution which is fair to all
parties.

    COMMENTS AND OUTLOOK

    As our shareholders know, our journey to the 20,000 barrel per day
plateau has been slower than previously forecast. We are there now. Our cash
flow at current prices is strong. What we didn't need at this time was for the
Alberta Government to change the royalty regime under which we have been
operating. As presented it is penal to Highpine. Of the extra $1.4 billion
projected to be collected by the Alberta Treasury, $460 million will come from
conventional oil. Our internal projections indicate that of the provincial
increase, over 9% will come from Highpine alone. Clearly this is unfair,
unreasonable and surely must be an unintended consequence of these royalty
changes. We have been advancing and intend to further advance our case along
these lines directly to the Energy Minister.
    In the meantime, we intend to reduce our budget, but by no means
drastically. We have many profitable projects under the current rules and
still some very exciting new pool wildcats to drill. Over the years, the
Alberta Government has been encouraging and supportive of smaller energy
companies, particularly with Canadian roots. As optimists, we believe sooner
or later, everyone will come to their senses and legislate a system that is
fair for Highpine and other similar companies.
    In the short term, we do have to face reality. The Highpine share price
has dropped to a level that from an accounting standpoint requires a write-off
of the full amount of goodwill on our balance sheet. This amounts to $358.1
million, but this has no effect on our cash balances, cash flow, liquidity, or
banking status.
    Operationally, production is still steadily rising, our drilling results
have been excellent, and our new prospects are better than ever.

    CONFERENCE CALL

    Highpine will host a conference call to discuss its financial and
operational results at 9:00 am MST, Friday, November 9, 2007.
    The call can be accessed toll free by dialing Canada and USA:
1-800-319-4610; Outside Canada and USA: 1-604-638-5340. Please phone in 10-15
minutes prior to the start of the call. The conference call will also be
broadcast live over the internet on Highpine's website located at
www.highpineog.com Digital Playback will be available until December 1, 2007
in North America Toll Free: 1-800-319-6413, Pin Code: 2090 followed by the
number sign.

    MANAGEMENT'S DISCUSSION AND ANALYSIS

    This Management's Discussion and Analysis (MD&A) is dated and based on
information at November 7, 2007. This MD&A has been prepared by management and
should be read in conjunction with the unaudited interim consolidated
financial statements for the nine months ended September 30, 2007 and audited
consolidated financial statements for the years ended December 31, 2006 and
2005 for a complete understanding of the financial position and results of
operations of Highpine Oil & Gas Limited ("Highpine" or the "Company"). The
unaudited interim consolidated financial statements have been prepared in
accordance with generally accepted accounting principles (GAAP) in Canada. All
references to dollar values refer to Canadian dollars unless otherwise stated.
    Certain information set forth in this MD&A contains forward-looking
statements including expectations of future production, management's
assessment of the effect of changes to royalty rates in Alberta, procurement
of drilling permits, plans for and results of exploration and development
activities and other operational developments and components of cash flow and
earnings. Readers are cautioned that assumptions used in the preparation of
such statements may prove to be incorrect. Events or circumstances may cause
actual results to differ materially from those predicted, as a result of
numerous known and unknown risks, uncertainties, and other factors, many of
which are beyond the control of the Company. These risks include, but are not
limited to: the effect of changes in royalty rates, the risks associated with
the oil and natural gas industry, commodity prices, and exchange rate changes.
Industry related risks include, but are not limited to: operational risks in
exploration, development and production of oil and natural gas and production
risks associated with sour hydrocarbons, dependence on third-party owned and
operated production facilities, availability of skilled personnel and
services, failure to obtain industry partner, regulatory and other third-party
consents and approvals, delays or changes in plans, risks associated with the
uncertainty of reserve estimates, health and safety risks and the uncertainty
of estimates and projections of reserves, production, costs and expenses. The
risks outlined above should not be construed as exhaustive. Readers are
cautioned not to place undue reliance on these statements. The Company
undertakes no obligation to update or revise any forward-looking statements
except as required by applicable securities laws.
    This MD&A uses the terms "funds flow from operations," "funds flow" and
"funds flow per share," which are not recognized measures under Canadian GAAP.
Management believes that in addition to cash flow from operating activities,
funds flow is a useful supplemental measure as it demonstrates Highpine's
ability to generate cash necessary to repay debt or fund future growth through
capital investment before changes in non-cash working capital balances.
Investors are cautioned, however, that this measure should not be construed as
an alternative to cash flow from operating activities determined in accordance
with GAAP as an indication of Highpine's performance. Highpine's method of
calculating funds flow may differ from other companies, especially those in
other industries and accordingly may not be comparable to measures used by
other companies. Highpine calculates funds from operations as cash from
operating activities before the change in non-cash working capital related to
operating activities and abandonment expenditures.
    The following table reconciles the cash flow from operating activities to
funds from operations:

    
    -------------------------------------------------------------------------
                                    Three months ended     Nine months ended
                                          September 30,         September 30,

                                       2007       2006       2007       2006
    -------------------------------------------------------------------------
    ($000s)

    Cash flow from operating
     activities                      38,014      9,247    130,657     69,945
    Change in non-cash operating
     working capital                  5,699     21,918      3,810     27,470
    Abandonment expenditures            271          6      1,016         52
    -------------------------------------------------------------------------
    Funds from operations            43,984     31,171    135,483     97,467
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Highpine also uses operating netback as an indicator of operating
performance. Operating netback is calculated on a per boe basis taking the
sales price and deducting royalties, operating costs, transportation costs and
realized hedging gains and losses.
    Where amounts are expressed on a barrel of oil equivalent (boe) basis,
natural gas volumes have been converted to equivalent barrels of oil using a
conversion factor of six thousand cubic feet equal to one barrel of oil
equivalent unless otherwise indicated. This conversion ratio of 6:1 is based
on an energy equivalent conversion method primarily applicable at the burner
tip and does not represent a value equivalency at the wellhead. Boe figures
may be misleading, particularly if used in isolation.
    Additional information relating to Highpine Oil & Gas Limited, including
the Company's annual information form, is available on SEDAR at www.sedar.com
and on the Company's website at www.highpineog.com.


    Financial Results

    Oil and Natural Gas Revenue

    -------------------------------------------------------------------------
                          Three months ended          Nine months ended
                             September 30,               September 30,
                                            %                            %
                        2007        2006  Change     2007        2006  Change
    -------------------------------------------------------------------------
    ($000s)

    Crude oil and
     natural gas
     liquids (NGLs)
     revenue          70,252      43,421    62     198,376     136,040    46
    Natural gas
     revenue          19,357      14,332    35      79,669      45,163    76
    -------------------------------------------------------------------------
                      89,609      57,753    55     278,045     181,203    53
    Realized
     hedging gain      1,166       1,668   (30)      3,961       3,976     -
    Unrealized
     hedging gain
     (loss)           (1,336)        784     -      (2,887)      2,207     -
    -------------------------------------------------------------------------
    Total oil and
     natural gas
     revenue          89,439      60,205    49     279,119     187,386    49
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    For the nine months ended September 30, 2007 total oil and natural gas
revenue increased to $279.1 million from $187.4 million for the nine months
ended September 30, 2006 due to production volume increases. Total oil and
natural gas revenue was negatively impacted by $2.9 million of unrealized
hedging losses compared to $2.2 million of unrealized hedging gains in the
comparative nine month period.
    For the three months ended September 30, 2007, total oil and gas revenue
increased to $89.4 million from $60.2 million for the three months ended
September 30, 2006 due to production volume increases.

    Production

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                          Three months ended          Nine months ended
                             September 30,               September 30,
                                            %                            %
                        2007        2006  Change     2007        2006  Change
    -------------------------------------------------------------------------
    Daily
     Production
    Crude oil and
     NGLs (bbls/d)    10,143       6,675    52      10,637       7,184    48
    Natural gas
     (mcf/d)          34,637      24,837    39      38,593      23,708    63
    -------------------------------------------------------------------------
    Boe/d             15,916      10,814    47      17,069      11,135    53
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Production Mix
    Crude oil and
     NGLs                64%         62%     3         62%         65%    (5)
    Natural gas          36%         38%    (5)        38%         35%     9
    -------------------------------------------------------------------------
                        100%        100%     -        100%        100%     -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    -------------------------------------------------------------------------
                          Three months ended          Nine months ended
                             September 30,               September 30,
                                            %                            %
                        2007        2006  Change     2007        2006  Change
    -------------------------------------------------------------------------
    (boe/d)

    Daily Production
     by Area
    Pembina Nisku
     Fairway          12,163       7,381    65      13,149       7,818    68
    West Central
     Alberta
    Gas Fairway        2,996       2,825     6       3,187       2,676    19
    Bantry/Retlaw        650         452    44         606         469    29
    Other                107         156   (31)        127         172   (26)
    -------------------------------------------------------------------------
    Total             15,916      10,814    47      17,069      11,135    53
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Prior periods have been reclassified to conform with current period
    presentation.

    Production for the nine months ended September 30, 2007 increased
53 percent to 17,069 boe/d from 11,135 boe/d for the nine months ended
September 30, 2006. The increase is attributable to production from the
acquisition of Kick Energy Corporation ("Kick") on August 1, 2006 and new
production from the Company's drilling program.
    Production for the three months ended September 30, 2007 increased
47 percent to 15,916 boe/d from 10,814 boe/d for the three months ended
September 30, 2006. The increase in production is a result of bringing new
wells from the Company's drilling program on stream.
    Production for the third quarter of 2007 decreased 11 percent to
15,916 boe/d from 17,933 boe/d in the second quarter of 2007. The decrease is
attributable to a scheduled facility turnaround at Highpine's Violet Grove oil
battery which reduced production by approximately 6,000 boe/d for three weeks
combined with unscheduled turnarounds at various non-operated facilities.

    Pricing

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                          Three months ended          Nine months ended
                             September 30,               September 30,
                                            %                            %
                        2007        2006  Change     2007        2006  Change
    -------------------------------------------------------------------------
    Selling Prices
     Before Hedges
    Crude oil and
     NGLs ($/bbl)      75.28       70.71     6       68.32       69.37    (2)
    Natural gas
     ($/mcf)            6.07        6.27    (3)       7.56        6.98     8
    -------------------------------------------------------------------------
    Total combined
     ($/boe)           61.20       58.05     5       59.67       59.61     -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


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                          Three months ended          Nine months ended
                             September 30,               September 30,
                                            %                            %
                        2007        2006  Change     2007        2006  Change
    -------------------------------------------------------------------------
    Benchmark Prices
    WTI oil (US$/bbl)  75.38       70.48     7       66.08       68.22    (3)
    US$/Cdn$ exchange
     rate               0.96        0.89     8        0.91        0.88     3
    AECO natural gas
     ($/mcf) (monthly)  5.61        6.03    (7)       6.81        7.19    (5)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    An increase in the WTI benchmark price for crude oil of 7 percent resulted
in a higher realized price for the three months ended September 30, 2007
compared to the three months ended September 30, 2006. The increase in the WTI
benchmark price was partially offset by strengthening of the Canadian dollar
relative to the US dollar. Continued strengthening of the Canadian dollar
subsequent to September 30, 2007 will continue to erode increases in the WTI
benchmark price. Average AECO prices were 7 percent lower in the third quarter
of 2007 compared to the third quarter of 2006 resulting in lower realized
natural gas prices.
    The WTI benchmark price for crude oil was 3 percent lower for the first
nine months of 2007 compared to the first nine months of 2006 resulting in
lower realized prices. Highpine's realized natural gas price increased by 8
percent for the first nine months of 2007 in contrast to a decrease in average
AECO prices as a result of certain Highpine contracts being based on the daily
index which increased over the comparative period.

    Commodity Price Risk Management

    Highpine's ability to execute its business strategy is dependent on
generating cash flow that can be reinvested into its capital program. The
Company utilizes financial and physical commodity price hedges to protect cash
flow against commodity price volatility. Highpine may enter into commodity
price hedges to a maximum of 50 percent of budgeted production.


    -------------------------------------------------------------------------
    Nine months ended September 30,            2007                     2006
                                Crude Oil &    Natural      Total      Total
                                  NGLs (bbl)  Gas (mcf)      (boe)      (boe)
    -------------------------------------------------------------------------
    Average volumes hedged
     (per day)                        5,500     13,889      7,815      4,487
    Percent of production hedged        52%        36%        46%        40%
    Realized hedging gain ($)          0.42       0.26       0.85       1.31
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    For the nine months ended September 30, 2007, Highpine realized a
$2.7 million natural gas hedging gain and a $1.2 million crude oil hedging
gain. For the nine months ended September 30, 2006, Highpine realized a
$4.7 million natural gas hedging gain and a $0.8 million crude oil hedging
loss.
    For the three months ended September 30, 2007, Highpine realized a
$1.3 million unrealized hedging loss primarily related to crude oil contracts.


    -------------------------------------------------------------------------
    Nine months ended September 30,                     2007       2006
                                  Crude Oil    Natural
                                     & NGLs        Gas      Total      Total
    -------------------------------------------------------------------------
    ($000s)
    Realized hedging gain             1,230      2,731      3,961      3,976
    Unrealized hedging gain (loss)   (3,033)       146     (2,887)     2,207
    -------------------------------------------------------------------------
    Total hedging gain (loss)        (1,803)     2,877      1,074      6,183
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The following contracts were outstanding at September 30, 2007:

    -------------------------------------------------------------------------
    Term                  Contract            Volume              Fixed Price
    -------------------------------------------------------------------------
    Jan 07 to Dec 07  Oil Collar        1,750 bbls/d  US $55.00 to $86.15/bbl
    Jan 07 to Dec 07  Oil Collar        1,750 bbls/d  US $60.00 to $80.70/bbl
    Jan 07 to Dec 07  Oil Swap            500 bbls/d           Cdn $73.00/bbl
    Jan 07 to Dec 07  Oil Swap            500 bbls/d           Cdn $73.70/bbl
    Jan 07 to Dec 07  Oil Swap            500 bbls/d           Cdn $74.70/bbl
    Jan 07 to Dec 07  Oil Swap            500 bbls/d           Cdn $75.82/bbl
    Jan 07 to Dec 07  Natural Gas Swap   2,500 GJs/d             Cdn $7.55/GJ
    Jan 07 to Dec 07  Natural Gas Swap   2,500 GJs/d             Cdn $7.62/GJ
    Feb 07 to Mar 08  Natural Gas Swap   1,250 GJs/d             Cdn $7.68/GJ
    Feb 07 to Mar 08  Natural Gas Swap   1,250 GJs/d             Cdn $7.70/GJ
    Jul 06 to Mar 08  Natural Gas Collar 5,000 GJs/d   Cdn $6.00 to $11.10/GJ
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    As at September 30, 2007, the unrealized mark-to-market loss on
outstanding crude oil contracts was $1.9 million and the unrealized
mark-to-market gain on outstanding natural gas contracts was $2.2 million.

    Royalty Expense

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                          Three months ended          Nine months ended
                             September 30,               September 30,
                                            %                            %
                        2007        2006  Change     2007        2006  Change
    -------------------------------------------------------------------------
    Total royalties,
     net of ARTC      26,190      13,948    88      80,269      51,894    55
    ($000s)

    As a percent of
     oil and natural
     gas sales
     (before hedging)    29%         24%    21         29%         29%     -

    $/boe              17.88       14.02    28       17.22       17.07     1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Royalty rates as a percentage of oil and natural gas sales were higher in
the third quarter of 2007 compared to the third quarter of 2006 as a result of
a GCA adjustment received in the third quarter of 2006 related to the prior
year that reduced the 2006 royalty expense.
    Royalty rates as a percentage of oil and natural gas sales were consistent
during the first nine months of 2007 compared to the first nine months of
2006.
    On October 25, 2007, the Alberta government introduced a framework to
increase royalty rates entitled the New Royalty Framework ("NRF"). The NRF is
to be effective January 1, 2009. Under the NRF, Crown royalties payable for
crude oil will be set by a single sliding rate formula containing separate
elements that account for oil price and well production. Maximum royalty rates
for crude oil are to increase from 35 percent to 50 percent. Crown royalties
payable for natural gas will be set by a formula sensitive to price and
production volume. Natural gas royalty rates, currently 5 percent to 35
percent, are to range from 5 percent to 50 percent. If enacted as proposed,
the NRF will increase Highpine's royalty expense commencing in 2009.
    During the 2006 year the Company received $500,000 of Alberta Royalty Tax
credits (ARTC) which was discontinued for 2007.

    Operating Costs

    -------------------------------------------------------------------------
                          Three months ended          Nine months ended
                             September 30,               September 30,
                                            %                            %
                        2007        2006  Change     2007        2006  Change
    -------------------------------------------------------------------------
    Operating costs
     ($000s)          14,287       9,472    51      45,247      23,715    91
    $/boe               9.76        9.52     3        9.71        7.80    24
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    For the nine and three months ended September 30, 2007, operating costs on
a per boe basis increased 24 percent and 3 percent respectively compared to
the comparative 2006 periods. The increases were a result of higher processing
costs on increased Pembina sour production realized in 2007 including higher
processing charges on volumes processed at third party facilities. In
addition, the Company incurred increased workover costs in 2007 as well as the
turnaround costs on the Violet Grove oil battery.

    Transportation Costs

    -------------------------------------------------------------------------
                          Three months ended          Nine months ended
                             September 30,               September 30,
                                            %                            %
                        2007        2006  Change     2007        2006  Change
    -------------------------------------------------------------------------
    Transportation
     costs ($000s)     1,107         979    13       4,499       2,291    96
    $/boe               0.76        0.98   (22)       0.96        0.75    28
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    For the nine months ended September 30, 2007, transportation costs on a
per boe basis increased 28 percent compared to the comparative 2006 period.
The increase is attributable to higher sulphur transportation charges as a
result of the increase in sour oil production combined with incremental costs
due to railway interruptions during 2007.
    For the three months ended September 30, 2007, transportation costs on a
per boe basis decreased 22 percent compared to the comparative 2006 period as
a result of increasing global demand for sulphur which reduced the cost of
disposal.

    Operating Netback

    -------------------------------------------------------------------------
                          Three months ended          Nine months ended
                             September 30,               September 30,
                                            %                            %
                        2007        2006  Change     2007        2006  Change
    -------------------------------------------------------------------------
    ($/boe)
    Sales price
     before hedging    61.20       58.05     5       59.67       59.61     -
    Royalties         (17.88)     (14.02)   28      (17.22)     (17.07)    1
    Operating costs    (9.76)      (9.52)    3       (9.71)      (7.80)   24
    Transportation
     costs             (0.76)      (0.98)  (22)      (0.96)      (0.75)   28
    -------------------------------------------------------------------------
    Netback before
     hedges            32.80       33.53    (2)      31.78       33.99    (7)
    Realized hedging
     gain               0.80        1.68   (52)       0.85        1.31   (35)
    -------------------------------------------------------------------------
    Operating netback  33.60       35.21    (5)      32.63       35.30    (8)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Operating netback before realized hedging gains was $32.80/boe for the
three months ended September 30, 2007 compared to $33.53/boe for the three
months ended September 30, 2006. The $0.73/boe decrease is primarily
attributable to higher operating costs as a result of increases in processing
costs relating to increased sour oil production combined with higher workover
expenditures.
    Operating netback before realized hedging gains was $31.78/boe for the
nine months ended September 30, 2007 compared to $33.99/boe for the nine
months ended September 30, 2006. The 7 percent decrease was due to higher
operating and transportation costs.

    General and Administrative Expenses

    -------------------------------------------------------------------------
                          Three months ended          Nine months ended
                             September 30,               September 30,
                                            %                            %
                        2007        2006  Change     2007        2006  Change
    -------------------------------------------------------------------------
    Gross expenses
     ($000s)           3,578       3,005    19      11,898       8,495    40
    Capitalized
     ($000s)            (844)       (724)   17      (2,410)     (2,022)   19
    -------------------------------------------------------------------------
    Net expenses
     ($000s)           2,734       2,281    20       9,488       6,473    47
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    $/boe               1.87        2.29   (18)       2.04        2.13    (4)
    percent
     capitalized         24%         24%     -         20%         24%   (17)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Gross expenses increased 40 percent to $11.9 million in the first nine
months of 2007 from $8.5 million in the first nine months of 2006 as a result
of staff increases and employee severance costs incurred. At September 30,
2007, Highpine had 61 Calgary based office employees compared to 55 at
September 30, 2006. On a per boe basis, general and administrative expenses
decreased 4 percent to $2.04/boe from $2.13/boe in the first nine months of
2006.
    Net expenses decreased 20 percent from $3.4 million in the second quarter
of 2007 to $2.7 million in the third quarter of 2007 as a result of severance
costs incurred in the second quarter of 2007.

    Stock-Based Compensation

    Stock-based compensation expense totaled $3.3 million in the first nine
months of 2007 compared to $4.3 million in the first nine months of 2006. The
decrease is attributable to options that were cancelled in the second quarter
which resulted in a recovery of previously recognized stock-based compensation
expense.
    On March 21, 2007, 1.9 million stock options which had been granted to
non-officer employees at exercise prices ranging from $14.92 to $23.25 were
repriced to an exercise price of $12.05. The vesting period of all repriced
options was reset such that the repriced options vest as to one-quarter
thereof on each of the first, second, third and fourth anniversaries of the
repricing. An additional $5.1 million of stock based compensation expense will
be recorded over the four year vesting period of the repriced options as a
result of the reprice.

    Interest and Finance Costs

    Interest and finance costs for the first nine months of 2007 were
$7.0 million versus $3.4 million in the first nine months of 2006. This
increase was primarily due to higher average debt levels.

    Depletion, Depreciation and Accretion

    -------------------------------------------------------------------------
                          Three months ended          Nine months ended
                             September 30,               September 30,
                                            %                            %
                        2007        2006  Change     2007        2006  Change
    -------------------------------------------------------------------------
    Depletion and
     depreciation
     ($000s)          42,636      29,298    46     136,961      87,945    56

    Accretion of
     asset
     retirement
     obligation
     ($000s)             226         191    18         677         459    47
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total DD&A        42,862      29,489    45     137,638      88,404    56
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    DD&A rate $/boe   $29.27      $29.64    (1)     $29.54      $29.08     2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The depletion, depreciation, and accretion (DD&A) rate of $29.54 per boe
for the nine months ended September 30, 2007 was comparable to the $29.08 per
boe for the nine months ended September 30, 2006.

    Income Taxes

    The Company did not incur any cash taxes during the first nine months of
2007. For 2007 and subsequent years, Crown charges are fully deductible for
income tax purposes. Resource allowance which was intended to compensate
taxpayers for non-deductible Crown charges was eliminated in 2007.
    Although current tax horizons depend on product prices, production levels
and the nature, magnitude and timing of capital expenditures, the Company
currently believes no cash income tax will be payable in 2007 or 2008.

    Goodwill

    Highpine recorded goodwill on the acquisitions of Kick, White Fire Energy
Ltd., Vaquero Energy Ltd. and Rubicon Energy Corp. Goodwill represents the
excess of the purchase price of the acquired businesses over the fair value of
net assets acquired. Goodwill is assessed for impairment annually and between
annual tests when events or circumstances indicate that goodwill might be
impaired. The impairment test is carried out in two steps. In the first step,
the carrying amount of the segment is compared to its fair value. When the
carrying amount of the segment exceeds its fair value, goodwill is considered
to be impaired and the second step of the impairment test is performed. The
implied fair value of goodwill is determined in the same manner as the value
of the goodwill is determined in a business combination using the fair value
of the Company as if it were the purchase price. When the carrying amount of
the Company's goodwill exceeds the implied fair value of the goodwill, an
impairment loss is recognized in an amount equal to the excess.
    At September 30, 2007, the Company identified indicators of impairment
including a decline in the Company's share price. Goodwill was tested for
impairment and it was determined that goodwill was impaired. An impairment of
goodwill of $358.1 million was recorded to earnings representing all of the
previously recorded goodwill. The write-down is not an indication of the
underlying value of the Company's properties.

    Funds from Operations and Net Earnings (Loss)

    -------------------------------------------------------------------------
                          Three months ended          Nine months ended
                             September 30,               September 30,
                                            %                            %
                        2007        2006  Change     2007        2006  Change
    -------------------------------------------------------------------------

    Funds from
     operations
     ($000s)          43,984      31,171    41     135,483      97,467    39
      Per diluted
       share ($)        0.65        0.49    33        2.00        1.76    14
    Net earnings
     (loss) ($000s) (359,513)        514     -    (364,859)     12,399     -
      Per diluted
       share ($)       (5.30)       0.01     -       (5.39)       0.22     -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    For the nine months ended September 30, 2007, funds from operations
increased 39 percent to $135.5 million from $97.5 million for the nine months
ended September 30, 2006 due to production increases realized. Funds from
operations per diluted share increased 14 percent to $2.00.
    During the first nine months of 2007, Highpine incurred a net loss of
$364.9 million, compared to net earnings of $12.4 million for the nine months
ended September 30, 2006. The magnitude of the net loss is attributable to a
$358.1 million impairment of goodwill incurred during the three months ended
September 30, 2007. Net earnings for the nine months ended September 30, 2006
included a $9.1 million non-recurring future tax reduction realized as a
result of enacted Canadian federal and Alberta tax rate reductions.
    The NRF is not effective until January 1, 2009 and as such funds from
operations and net earnings for the years ending December 31, 2007 and 2008
will be unaffected. However, funds from operations and net earnings for the
year ending December 31, 2009 and subsequent years will be negatively impacted
by the expected higher overall royalty rates. The actual effect of the NRF on
Highpine will be determined based on the actual legislation enacted, the
production rates, commodity prices and product mix after January 1, 2009. If
the changes were enacted and applicable today and based on the Company's
interpretation of publicly available information, Highpine estimates that the
potential effect on funds from operations from current production would result
in an approximate reduction of 29 percent based on a benchmark price of WTI
USD$70/bbl and AECO CDN $6.00/MMbtu and using a par foreign exchange ratio. In
addition, an increase in forecast royalty rates used in the Company's ceiling
test calculation could result in a write-down in a future period.

    Liquidity and Capital Resources

    At September 30, 2007, the Company had a revolving term credit facility of
$230 million and a demand operating credit facility of $20 million with $162
million drawn against these facilities, thereby providing remaining credit
capacity of $88 million. At September 30, 2007, the Company had a working
capital deficiency of $8.5 million and net debt of $170.8 million. The
Company's working capital deficiency is expected to fluctuate based on the
timing of the Company's capital expenditure program which is typically most
active during the fourth quarter and first quarter. The Company's working
capital deficiency is funded from funds available from existing credit
facilities.

    -------------------------------------------------------------------------
    As at                                         September 30,  December 31,
                                                          2007          2006
    -------------------------------------------------------------------------
    ($000s)
    Capitalization
    Bank debt                                          162,266       138,890
    Working capital deficiency(1)                        8,539        30,680
    -------------------------------------------------------------------------
    Net debt                                           170,805       169,570
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Shares outstanding (No.)                            67,878        67,648
    Market price at end of period ($)                    10.20         15.70
    Market capitalization                              692,356     1,062,074
    -------------------------------------------------------------------------
    Total capitalization                               863,161     1,231,644
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net debt as a percent of total
     capitalization                                        20%           14%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Annualized funds from operations                   180,644       127,440
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net debt to annualized funds from operations ratio    0.95          1.33
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Working capital excludes unrealized financial instruments.
    

    Expenditures to be incurred on Highpine's remaining 2007 capital budget
are expected to be funded from the Company's credit facilities and funds from
operations. The Company is currently evaluating future capital expenditures in
light of the recommendations in the NRF.
    At November 7, 2007, the Company's bank debt was approximately
$167 million. The Company's lenders review the credit facilities semi-annually
and as a result of the NRF it is expected that the maximum funds available
under the facilities may be reduced.

    Capital Expenditures

    Capital expenditures, excluding corporate acquisitions, property
acquisitions, and property dispositions totaled $141.2 million for the nine
months ended September 30, 2007 compared to $121.9 million for the nine months
ended September 30, 2006. The Company's capital program is heavily weighted to
the Pembina Nisku fairway which accounted for 89 percent of capital
expenditures for the nine months ended September 30, 2007. During the third
quarter of 2007, the Company disposed of undeveloped properties in a non-core
area for proceeds of $3.6 million.

    
    -------------------------------------------------------------------------
                                             Nine months ended September 30,
                                            2007          2006      % Change
    -------------------------------------------------------------------------
    ($000s)

    Land                                  10,770        16,148           (33)
    Geologic and geophysical               7,308         6,440            13
    Drilling and completions              79,800        71,159            12
    Facilities and equipment              40,857        25,896            58
    Capitalized general and
     administrative                        2,410         2,022            19
    Office and other                          52           207           (75)
    -------------------------------------------------------------------------
    Total capital expenditures           141,197       121,872            16
    -------------------------------------------------------------------------
    Property acquisitions                      -        27,631          (100)
    -------------------------------------------------------------------------
    Property dispositions                 (3,632)            -           100
    -------------------------------------------------------------------------
    Corporate acquisitions(1)                  -       440,895          (100)
    -------------------------------------------------------------------------
    Total capital expenditures and
     acquisitions                        137,565       590,398           (77)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Represents total consideration for the transactions, including fees,
        but is prior to the related future income tax liability and asset
        retirement obligation.
    

    Outstanding Common Shares

    As at November 7, 2007, the Company had 67.9 million class A common
shares outstanding and had granted options to directors, officers, employees
and consultants to acquire a further 4.9 million class A common shares with an
average exercise price of $10.72 per share.

    Change in Accounting Policies

    Financial Instruments

    Effective January 1, 2007, the Company adopted the Canadian Institute of
Chartered Accountants ("CICA") section 3855 "Financial Instruments -
Recognition and Measurement," section 1530 "Comprehensive Income," section
3865 "Hedges" and section 3861 "Financial Instruments - Disclosure and
Presentation". The standards deal with the recognition and measurement of
financial instruments and comprehensive income. These standards have been
adopted prospectively. Adoption of these standards did not impact January 1,
2007 opening balances. See Note 2 to the consolidated financial statements.

    Critical Accounting Estimates

    The preparation of the Company's consolidated financial statements
requires management to adopt accounting policies that involve the use of
significant estimates and assumptions. These estimates and assumptions are
developed based on the best available information and are believed by
management to be reasonable under the existing circumstances. New events or
additional information may result in the revision of these estimates over
time.

    Internal Controls Over Financial Reporting
    ------------------------------------------
    Internal controls have been designed to provide reasonable assurance
regarding the reliability of the Company's financial reporting and the
preparation of financial statements together with the other financial
information for external purposes in accordance with Canadian GAAP. The
Company's Chief Executive Officer and Chief Financial Officer have designed or
caused to be designed under their supervision internal controls over financial
reporting related to the Company, including its consolidated subsidiaries.
    The Company's Chief Executive Officer and Chief Financial Officer are
required to cause the Company to disclose herein any change in the Company's
internal control over financial reporting that occurred during the Company's
most recent interim period that materially affected, or is reasonably likely
to materially affect, the Company's internal control over financial reporting.
There were no material changes in the Company's internal controls over
financial reporting during the quarter ended September 30, 2007.
    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.

    Business Risks and Uncertainties

    Highpine is exposed to numerous risks and uncertainties associated with
the exploration for and development, production and acquisition of crude oil,
natural gas and NGLs. Primary risks include:

    
    -   Changes in royalty rates;
    -   Uncertainty associated with obtaining drilling licences and other
        consents and approvals;
    -   Finding and producing reserves economically;
    -   Production risks associated with sour hydrocarbons;
    -   Marketing reserves at acceptable prices; and
    -   Operating with minimal environmental impact.

    Highpine strives to minimize and manage these risks in a number of ways,
including:

    -   Employing qualified professional and technical staff;
    -   Communicating openly with members of the public regarding its
        activities;
    -   Concentrating in a limited number of areas;
    -   Utilizing the latest technology for finding and developing reserves;
    -   Constructing quality, environmentally sensitive, safe production
        facilities;
    -   Maximizing operational control of drilling and producing operations;
        and
    -   Minimizing commodity price risk through strategic hedging.
    

    Environmental Risks
    -------------------
    All phases of the oil and natural gas business present environmental
risks and hazards and are subject to environmental regulation pursuant to a
variety of federal, provincial and local laws and regulations. Compliance with
such legislation can require significant expenditures and a breach may result
in the imposition of fines and penalties, some of which may be material.
Environmental legislation is evolving in a manner expected to result in
stricter standards and enforcement, larger fines and liability and potentially
increased capital expenditures and operating costs. In 2002, the Government of
Canada ratified the Kyoto Protocol (the "Protocol"), which calls for Canada to
reduce its greenhouse gas emissions to specified levels. There has been much
public debate with respect to Canada's ability to meet these targets and the
Government's strategy or alternative strategies with respect to climate change
and the control of greenhouse gases. Implementation of strategies for reducing
greenhouse gases whether to meet the limits required by the Protocol or as
otherwise determined, could have a material impact on the nature of oil and
natural gas operations, including those of the Company. Given the evolving
nature of the debate related to climate change and the control of greenhouse
gases and resulting requirements, it is not possible to predict either the
nature of those requirements or the impact on the Company and its operations
and financial condition.


    
    Selected Annual Information

                                            2006          2005          2004
    -------------------------------------------------------------------------
    Financial
    ($000s, except per share amounts)

    Total revenue(1)                     254,938       141,634        41,025
    Net earnings                           6,953        12,274         3,177
      Per share - basic                     0.12          0.35          0.19
      Per share - diluted                   0.12          0.34          0.19
    Funds from operations                127,440        74,550        19,773
      Per share - basic                     2.21          2.13          1.18
      Per share - diluted                   2.17          2.09          1.16
    Corporate acquisitions               379,345       257,314        51,151
    Capital expenditures(2)              222,214       153,606        61,133
    Total assets                       1,392,911       753,690       163,388
    Long-term debt                       138,890             -             -
    -------------------------------------------------------------------------
    Operating

    Average daily production
      Oil and NGLs (bbls/d)                7,554         3,984         1,578
      Natural Gas (mcf/d)                 25,350        13,823         6,423
      Total (boe/d)                       11,779         6,288         2,648
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Total revenue is after realized and unrealized hedging losses and
        gains.
    (2) Capital expenditures are net of property dispositions.



    Summary of Quarterly Results

                                                           2007
    -------------------------------------------------------------------------
                                                    Q3         Q2         Q1
    -------------------------------------------------------------------------
    Financial
    ($000s, except per share
     amounts)

    Total revenue(1)                            89,439    103,769     85,911
    Net earnings (loss)                       (359,513)     1,060     (6,406)
      Per share - basic                          (5.30)      0.02      (0.09)
      Per share - diluted                        (5.30)      0.02      (0.09)
    Funds from operations                       43,984     46,869     44,630
      Per share - basic                           0.65       0.69       0.66
      Per share - diluted                         0.65       0.68       0.66
    Corporate acquisitions                           -          -          -
    Capital expenditures(2)                     37,073     24,670     75,822
    Total assets                             1,044,815  1,415,081  1,421,510
    Long-term debt                             150,414    171,943    157,870
    -------------------------------------------------------------------------
    Operating
    Average daily production
      Oil and NGLs (bbls/d)                     10,143     11,025     10,750
      Natural Gas (mcf/d)                       34,637     41,449     39,749
      Total (boe/d)                             15,916     17,933     17,375
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                                          2006                       2005
    -------------------------------------------------------------------------
                              Q4         Q3         Q2         Q1         Q4
    -------------------------------------------------------------------------
    Financial
    ($000s, except per
     share amounts)

    Total revenue(1)      67,552     60,205     62,765     64,416     54,229
    Net earnings (loss)   (5,446)       514     10,594      1,291      4,855
      Per share - basic    (0.08)      0.01       0.20       0.03       0.11
      Per share -
       diluted             (0.08)      0.01       0.20       0.03       0.11
    Funds from
     operations           29,973     31,171     34,750     31,546     27,957
      Per share - basic     0.44       0.50       0.66       0.66       0.63
      Per share -
       diluted              0.44       0.49       0.65       0.65       0.62
    Corporate
     acquisitions              -    289,694          -     89,651          -
    Capital
     expenditures(2)      72,711     56,144     46,590     46,769     50,861
    Total assets       1,392,911  1,361,249    920,941    910,157    753,690
    Long-term debt       138,890    113,287          -          -          -
    -------------------------------------------------------------------------
    Operating
    Average daily
     production
      Oil and NGLs
       (bbls/d)            8,653      6,675      6,940      7,950      5,881
      Natural Gas
       (mcf/d)            30,221     24,837     25,562     20,681     16,006
      Total (boe/d)       13,690     10,814     11,201     11,397      8,549
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Total revenue is after realized and unrealized hedging losses and
        gains.
    (2) Capital expenditures are net of property dispositions.


    Total revenue of the Company has generally trended with average daily
production levels. During the second and third quarter of 2006, production was
negatively impacted as a result of volumes being temporarily shut-in due to
reservoir operating pressures being below the required minimum in certain
pools. Water injection schemes were implemented in the third and fourth
quarter of 2006 which brought previously shut-in production back on-stream.
Production continued to increase in the fourth quarter of 2006 and the first
two quarters of 2007 from the acquisition of Kick in August 2006 combined with
production generated from the Company's drilling program. In the third quarter
of 2007, production was negatively impacted by scheduled and unscheduled
facility turnarounds.
    Net loss for the third quarter of 2007 includes a $358.1 million non-
recurring non-cash charge as a result of the impairment of goodwill.
    Net earnings for the second quarter of 2006 include a $9.1 million non-
recurring future tax reduction as a result of substantively enacted federal
and provincial income tax reductions.

    CONSOLIDATED BALANCE SHEETS

    -------------------------------------------------------------------------
                                                  September 30,  December 31,
                                                          2007          2006
    -------------------------------------------------------------------------
    ($000s)(unaudited)

    Assets
    Current assets
      Accounts receivable                               66,364        54,944
      Prepaid expenses and deposits                      2,500         2,928
      Financial instruments (notes 2 and 8)                307         3,194
    -------------------------------------------------------------------------
                                                        69,171        61,066
    Property, plant and equipment (note 4)             974,494       972,599
    Long-term investment, at cost (note 2)               1,150         1,150
    Goodwill (note 3)                                        -       358,096
    -------------------------------------------------------------------------
                                                     1,044,815     1,392,911
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Liabilities and Shareholders' Equity
    Current liabilities
      Accounts payable and accrued liabilities          77,403        88,552
      Future income taxes                                   93           970
    -------------------------------------------------------------------------
                                                        77,496        89,522
    Long-term debt (note 5)                            162,266       138,890
    Future income taxes                                150,414       150,832
    Asset retirement obligations (note 6)               11,406        11,258
    Deferred lease inducements                             345           408

    Shareholders' equity
      Share capital (note 7)                           959,415       957,186
      Contributed surplus (note 7)                      13,479         9,962
      Retained earnings (deficit)                     (330,006)       34,853
    -------------------------------------------------------------------------
                                                       642,888     1,002,001

    -------------------------------------------------------------------------
                                                     1,044,815     1,392,911
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to the interim consolidated financial statements.



    CONSOLIDATED STATEMENTS OF OPERATIONS, COMPREHENSIVE INCOME AND RETAINED
    EARNINGS (DEFICIT)

    -------------------------------------------------------------------------
                                    Three months ended     Nine months ended
                                          September 30,         September 30,
                                       2007       2006       2007       2006
    -------------------------------------------------------------------------
    ($000s, except per share
     amounts) (unaudited)

    Revenues
      Oil and natural gas revenues   89,609     57,753    278,045    181,203
      Royalties, net of ARTC        (26,190)   (13,948)   (80,269)   (51,894)
      Financial instruments (note 8)
        Realized gains                1,166      1,668      3,961      3,976
        Unrealized (losses) gains    (1,336)       784     (2,887)     2,207
    -------------------------------------------------------------------------
                                     63,249     46,257    198,850    135,492

    Expenses
      Operating costs                14,287      9,472     45,247     23,715
      Transportation costs            1,107        979      4,499      2,291
      General and administrative      2,734      2,281      9,488      6,473
      Depletion, depreciation
       and accretion                 42,862     29,489    137,638     88,404
      Interest and finance costs      2,452      1,549      6,957      3,403
      Stock-based compensation
       (note 7)                       1,282      1,389      3,323      4,344
      Impairment of goodwill
       (note 3)                     358,096          -    358,096          -
    -------------------------------------------------------------------------
                                    422,820     45,159    565,248    128,630
    -------------------------------------------------------------------------
    Earnings (loss) before taxes   (359,571)     1,098   (366,398)     6,862
    -------------------------------------------------------------------------
    Taxes (reduction)
      Current                             -          -          -       (127)
      Future                            (58)       584     (1,539)    (5,410)
    -------------------------------------------------------------------------
                                        (58)       584     (1,539)    (5,537)
    -------------------------------------------------------------------------
    Net earnings (loss) and
     comprehensive income          (359,513)       514   (364,859)    12,399
    Retained earnings,
     beginning of period             29,507     39,785     34,853     27,900
    -------------------------------------------------------------------------
    Retained earnings (deficit),
     end of period                 (330,006)    40,299   (330,006)    40,299
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net earnings (loss) per
     share (note 7)
      Basic                       $   (5.30) $    0.01  $   (5.39) $    0.23
      Diluted                     $   (5.30) $    0.01  $   (5.39) $    0.22
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to the interim consolidated financial statements.



    CONSOLIDATED STATEMENTS OF CASH FLOWS

    -------------------------------------------------------------------------
                                    Three months ended     Nine months ended
                                          September 30,         September 30,
                                       2007       2006       2007       2006
    -------------------------------------------------------------------------
    ($000s) (unaudited)

    Cash provided by (used in):
    Operating Activities
      Net earnings (loss)          (359,513)       514   (364,859)    12,399
      Items not involving cash:
        Depletion, depreciation
         and accretion               42,862     29,489    137,638     88,404
        Future income taxes
         (reduction)                    (58)       584     (1,539)    (5,410)
        Stock-based compensation      1,282      1,389      3,323      4,344
        Unrealized losses (gains)
         on financial instruments     1,336       (784)     2,887     (2,207)
        Amortization of deferred
         lease inducements              (21)       (21)       (63)       (63)
        Impairment of goodwill
         (note 3)                   358,096          -    358,096          -
      Abandonment expenditures         (271)        (6)    (1,016)       (52)
      Change in non-cash operating
       working capital               (5,699)   (21,918)    (3,810)   (27,470)
    -------------------------------------------------------------------------
                                     38,014      9,247    130,657     69,945
    -------------------------------------------------------------------------
    Financing Activities
      Common shares issued for cash       -          -          -    100,620
      Share issue costs                   -       (260)         -     (4,606)
      Proceeds on exercise of
       stock options                    725         67      1,863      1,150
      Increase (decrease) in
       bank indebtedness             (9,677)    27,241     23,376    (20,985)
    -------------------------------------------------------------------------
                                     (8,952)    27,048     25,239     76,179
    -------------------------------------------------------------------------
    Investing Activities
      Property, plant and
       equipment additions          (40,705)   (43,191)  (141,197)  (121,872)
      Proceeds on disposal of
       property, plant and
       equipment                      3,632          -      3,632          -
      Property acquisitions               -    (12,953)         -    (27,631)
      Purchase of investments             -          -          -       (150)
      Net cash paid on business
       combination                        -       (564)         -     (1,091)
      Deferred charges                    -          -          -        251
      Change in non-cash investing
       working capital                8,011     20,413    (18,331)     4,369
    -------------------------------------------------------------------------
                                    (29,062)   (36,295)  (155,896)  (146,124)
    -------------------------------------------------------------------------
    Change in cash                        -          -          -          -
    Cash, beginning of period             -          -          -          -
    -------------------------------------------------------------------------
    Cash, end of period                   -          -          -          -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Cash interest paid                2,096      1,861      7,297      3,436
    Cash taxes paid                       -       (105)     1,025        263
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to the interim consolidated financial statements.



    NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS

    Nine months ended September 30, 2007 and 2006
    (tabular amounts in thousands of dollars, unless otherwise noted)

    1.  Significant Accounting Policies

        The interim consolidated financial statements of Highpine Oil & Gas
        Limited (the "Company") have been prepared by management in
        accordance with Canadian generally accepted accounting policies and
        follow the same accounting policies as the most recent audited annual
        consolidated financial statements, except as noted below. Certain
        disclosures normally required to be included in the notes to the
        annual consolidated financial statements have been condensed or
        omitted. The interim consolidated financial statements should be read
        in conjunction with the audited consolidated financial statements and
        the notes thereto for the years ended December 31, 2006 and 2005.

    2.  Change in Accounting Policy

        Effective January 1, 2007, the Company adopted the Canadian Institute
        of Chartered Accountants ("CICA") section 3855, "Financial
        Instruments - Recognition and Measurement," section 1530
        "Comprehensive Income," section 3865 "Hedges" and section 3861
        "Financial Instruments - Disclosure and Presentation". These
        standards have been adopted prospectively. Adoption of these
        standards did not impact January 1, 2007 opening balances.

        i)   Financial instruments

        All financial instruments must initially be recognized at fair value
        on the balance sheet date. The Company has classified each financial
        instrument into the following categories: held for trading financial
        assets and financial liabilities, loans or receivables, held to
        maturity investments, available for sale financial assets, and other
        financial liabilities. Subsequent measurement of the financial
        instruments is based on their classification. Unrealized gains and
        losses on held for trading financial instruments are recognized in
        earnings. Gains and losses on available for sale financial assets are
        recognized in other comprehensive income and are transferred to
        earnings when the asset is derecognized. The other categories of
        financial instruments are recognized at amortized cost using the
        effective interest rate method.

        Upon adoption and with any new financial instrument, an irrevocable
        election is available that allows entities to classify any financial
        asset or financial liability as held for trading, even if the
        financial instrument does not meet the criteria to designate it as
        held for trading. The Company has not elected to classify any
        financial assets or financial liabilities as held for trading unless
        they meet the held for trading criteria. A held for trading financial
        instrument is not a loan or receivable and includes one of the
        following criteria:

        -  it is a derivative, except for those derivatives that have been
           designated as effective hedging instruments;

        -  it has been acquired or incurred principally for the purpose of
           selling or repurchasing in the near future; or

        -  it is part of a portfolio of financial instruments that are
           managed together and for which there is evidence of a recent
           actual pattern of short-term profit taking.

        ii)  Derivative instruments and hedging activities

        The Company may enter into derivative instrument contracts to manage
        its commodity price exposure, foreign exchange exposure and interest
        rate exposure. The Company does not enter into derivative instrument
        contracts for trading or speculative purposes. The Company may choose
        to designate derivative instruments as hedges. Hedge accounting
        continues to be optional.


        iii) Comprehensive income

        Comprehensive income consists of net earnings and other comprehensive
        income ("OCI"). OCI comprises the change in the fair value of the
        effective portion of the derivatives used as hedging items in a cash
        flow hedge and the change in fair value of any available for sale
        financial instruments. Amounts included in OCI are shown net of tax.
        Accumulated other comprehensive income is a new equity category
        comprised of the cumulative amounts of OCI.

    3.  Goodwill

        At September 30, 2007, goodwill was tested for impairment by
        comparing the book value of net assets to the fair value. The fair
        value did not exceed the identifiable net assets at September 30,
        2007, and accordingly, the full amount of goodwill was impaired and
        $358.1 million was charged to earnings.

    4.  Property, Plant and Equipment

        ---------------------------------------------------------------------
                                    September 30, 2007     December 31, 2006

                                           Accumulated
                                             depletion
                                            and deprec-  Net book   Net book
                                       Cost     iation      value      value
        ---------------------------------------------------------------------

        Petroleum and natural
         gas properties         $ 1,308,797  $(336,926) $ 971,871  $ 969,784
        Land, buildings and
         leaseholds                   2,409       (369)     2,040      2,170
        Office equipment and
         computers                    1,036       (453)       583        645
        ---------------------------------------------------------------------
                                $ 1,312,242  $(337,748) $ 974,494  $ 972,599
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        At September 30, 2007, approximately $144.9 million (December 31,
        2006 - $152.2 million) of unproved property costs and unevaluated
        seismic costs were excluded from the depletion calculation. Future
        development costs of $30.5 million (December 31, 2006 -
        $56.4 million) were included in the depletion calculation. Salvage
        value of $54.9 million (December 31, 2006 - $23.9) was excluded from
        the depletion calculation.

        During the nine months ended September 30, 2007, cash general and
        administrative expenses of $2.4 million (nine months ended
        September 30, 2006 - $2.0 million) were capitalized. The Company also
        capitalized $1.4 million of stock based compensation expense for the
        nine months ended September 30, 2007.

    5.  Long-Term Debt

        At September 30, 2007, the Company had available a $230 million
        revolving term credit facility with a syndicate of Canadian financial
        lenders and a $20 million demand operating credit facility with a
        Canadian financial lender.

        The revolving term credit facility has a 364-day extendable revolving
        period plus a one-year maturity. The term date of the revolving term
        credit facility is May 28, 2008. In the event that the term date on
        May 28, 2008 is not extended, the balance under the facility will be
        repayable on May 27, 2009. The revolving term credit facility bears
        interest within a range of the lenders' prime rate to prime plus
        0.25 percent depending on financial ratios of the Company. The demand
        operating facility bears interest at the lenders' prime rate.

        The lenders review the credit facilities semi-annually. The
        facilities are secured by a general security agreement and a first
        floating charge over all of the Company's assets.

        Interest expense includes $6.8 million (nine months ended
        September 30, 2006 - $3.4 million) in respect of debt repayable for a
        period exceeding one year.

    6.  Asset Retirement Obligations

        At September 30, 2007, the estimated total undiscounted cash flows
        required to settle asset retirement obligations were $18.0 million
        (December 31, 2006 - $17.9 million). Expenditures to settle asset
        retirement obligations will be incurred between 2007 and 2027.
        Estimated cash flows have been discounted using an annual
        credit-adjusted risk-free interest rate of 8.0 percent per annum and
        have been inflated using an inflation rate of 2.0 percent per annum.

        Changes to asset retirement obligations were as follows:

        ---------------------------------------------------------------------
                                                   Nine months
                                                         ended    Year ended
                                                  September 30,  December 31,
                                                          2007          2006
        ---------------------------------------------------------------------

        Asset retirement obligations,
         beginning of period                            11,258         5,898
          Liabilities acquired                               -         3,980
          Liabilities incurred                             487         1,069
          Liabilities settled                           (1,016)         (368)
        Accretion expense                                  677           679
        ---------------------------------------------------------------------
        Asset retirement obligations, end of period     11,406        11,258
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    7.  Share Capital

        Authorized:

           (i)  an unlimited number of class A common shares without par
                value; and

           (ii) an unlimited number of class B common shares without par
                value issuable in series. The class B common shares are
                non-voting and are not entitled to the receipt of dividends.

                              Nine months ended            Year ended
                              September 30, 2007        December 31, 2006

                               Shares       Amount       Shares       Amount
        ---------------------------------------------------------------------
                           (thousands) ($thousands)  (thousands) ($thousands)

        Class A common shares
        Balance, beginning
         of period             67,648      957,186       44,250      479,496
          Issued to acquire
           White Fire               -            -        4,089       95,480
          Issued to acquire
           Kick                     -            -       14,831      283,269
          Issued for cash           -            -        4,300      100,620
          Stock options
           exercised              230        1,863          178        1,202
          Contributed surplus
           transferred on
           exercise of stock
           options                  -          366            -          225
          Share issue costs
           less tax effect of
           (2007 - nil;
           2006 - $1,500)           -            -            -       (3,106)
        ---------------------------------------------------------------------
        Balance, end of
         period                67,878      959,415       67,648      957,186
        ---------------------------------------------------------------------


        Per Share Amounts

        ---------------------------------------------------------------------
                              Three months ended         Nine months ended
                                 September 30,             September 30,
                                 2007         2006         2007         2006
                           (thousands)  (thousands)  (thousands)  (thousands)
        ---------------------------------------------------------------------

        Weighted average
         number of common
         shares outstanding
          Basic                67,856       62,479       67,735       54,408
          Dilutive effect of
           stock options            -          877            -          945
        ---------------------------------------------------------------------
        Diluted                67,856       63,356       67,735       55,353
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Stock Options

        The Company has a stock option plan pursuant to which options to
        purchase class A common shares of the Company may be granted to
        directors, officers, employees and consultants. The outstanding stock
        options of the Company are exercisable for a period of six years and
        vest over a period of four years.

        In March 2007, 1,850,500 stock options previously granted to
        non-officer employees at exercise prices ranging from $14.92 to
        $23.25 were repriced. The new exercise price was set at $12.05 which
        was the closing price of the Company's class A common shares on the
        day preceding the repricing. The vesting period of the repriced stock
        options, including vested stock options, was reset. As a result of
        the stock options repricing, the fair value of the stock options,
        calculated using the Black-Scholes model, increased by $5.1 million.
        The increase in the fair value of the stock options will be amortized
        over the four year vesting period of the repriced options. All other
        characteristics of the repriced options, including the expiry date,
        remain unchanged.

        A summary of changes is as follows:

        ---------------------------------------------------------------------
                                  Nine months ended          Year ended
                                  September 30, 2007      December 31, 2006
        ---------------------------------------------------------------------
                                    Class A               Class A
                                     Common                Common
                                     Shares                Shares
                                   Issuable  Weighted    Issuable   Weighted
                                       Upon   Average        Upon    Average
                                   Exercise  Exercise    Exercise   Exercise
                                 of Options     Price  of Options      Price
        ---------------------------------------------------------------------
                                 (thousands) ($/share) (thousands)  ($/share)
        Balance, beginning
         of period                    5,077     15.80       3,652      13.06
          Granted                     1,775     12.36       2,016      20.42
          Exercised                    (230)    (8.26)       (178)     (6.75)
          Cancelled                  (1,681)   (19.81)       (413)    (18.06)
          Repriced                   (1,851)   (19.67)          -          -
          Repriced                    1,851     12.05           -          -
        ---------------------------------------------------------------------
        Balance, end of period        4,941     10.71       5,077      15.80
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Exercisable, end of period    1,083      5.96       1,271       9.44
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Details of the exercise prices and expiry dates of options
        outstanding at September 30, 2007 are as follows:

        ---------------------------------------------------------------------
                             Options Outstanding         Options Exercisable
                             -------------------         -------------------
                                   Weighted   Weighted              Weighted
                          Common    Average    Average      Common   Average
        Range of          Shares   Years to   Exercise      Shares  Exercise
        Exercise price  Issuable     Expiry      Price    Issuable     Price
        ---------------------------------------------------------------------
                      (thousands)    (years)  ($/share) (thousands) ($/share)

        $2.60 - $3.50        551       1.42    $  2.76        531    $  2.74
        $4.50 - $5.00        359       2.66    $  4.76        269    $  4.76
        $8.10 - $11.00       334       3.79    $  8.93        130    $  8.41
        $11.01 - $15.50    3,437       5.43    $ 12.23         30    $ 14.00
        $17.85 - $18.00      260       3.81    $ 17.98        123    $ 17.99
        ---------------------------------------------------------------------
                           4,941       4.58    $ 10.71      1,083    $  5.96
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The fair value of stock options granted is estimated using the
        Black-Scholes option pricing model with the following assumptions.

        ---------------------------------------------------------------------
                                                           Nine months ended
                                                          September 30, 2007
        ---------------------------------------------------------------------
        Weighted average expected volatility (%)                          52
        Risk-free rate of return (%)                                     4.2
        Expected option life (years)                                       4
        Weighted average fair value ($/share)                           5.46
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The Company does not anticipate paying any dividends during the
        expected life of the options.

        Contributed Surplus

        ---------------------------------------------------------------------
                                                   Nine months
                                                         ended    Year ended
                                                  September 30,  December 31,
                                                          2007          2006
        ---------------------------------------------------------------------

        Balance, beginning of period                     9,962         3,627
          Stock-based compensation expense,
           net of recovery                               3,323         5,677
          Capitalized stock-based
           compensation expense                          1,419           883
          Recovery of capitalized stock-based
           compensation expense                           (859)            -
          Transferred to share capital on
           exercise of stock options                      (366)         (225)
        ---------------------------------------------------------------------
        Balance, end of period                          13,479         9,962
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Deferred Share Units Plan

        In 2006, the Company implemented a deferred share unit ("DSU") plan
        for non-management directors. Under the terms of the plan, DSUs
        awarded will vest immediately and will be settled with cash in the
        amount equal to the closing price of the Company's class A common
        shares on the date the non-management director specifies following
        the date the director is no longer a director of the Company.

        The Company has recorded a liability of $127,000 relating to
        12,493 DSUs outstanding at September 30, 2007.

    8.  Commodity Price Risk Management

        The Company uses a variety of derivative instruments to reduce its
        exposure to fluctuations in commodity prices. Derivative instruments
        are classified as held for trading and recorded at fair value on the
        consolidated balance sheet. No derivative instruments were designated
        as hedges during the nine months ended September 30, 2007.

        Realized Financial Instrument Gain

        The realized financial instrument gain of $4.0 million for the
        nine months ended September 30, 2007 relates to the cash settlement
        of derivative instruments.

        Unrealized Financial Instrument Gain (Loss)

        The unrealized financial instrument loss of $2.9 million for the
        nine months ended September 30, 2007 represents the change in fair
        value of the Company's financial risk management agreements from
        December 31, 2006 to September 30, 2007. The loss is calculated as
        follows:

        ---------------------------------------------------------------------
                                                           Nine months ended
                                                          September 30, 2007
        ---------------------------------------------------------------------
        Balance, beginning of period                                   3,194
        Change in fair value of derivative
         instrument contracts                                         (2,887)
        ---------------------------------------------------------------------
        Balance, end of period                                           307
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The following commodity price risk management agreements were in
        place as at September 30, 2007.

        Financial WTI Crude Oil Contracts

        ---------------------------------------------------------------------
                                                                  Unrealized
                                                                       (Loss)
                                                                       as at
                                                                September 30,
        Term              Contract   Volume         Fixed Price         2007
                                    (bbls/d)             ($/bbl)  (CDN $000s)
        ---------------------------------------------------------------------
        Jan 07 to Dec 07    Collar    1,750  US $55.00 to $86.15        (123)
        Jan 07 to Dec 07    Collar    1,750  US $60.00 to $80.70        (389)
        Jan 07 to Dec 07    Swap        500           Cdn $73.00        (434)
        Jan 07 to Dec 07    Swap        500           Cdn $73.70        (392)
        Jan 07 to Dec 07    Swap        500           Cdn $74.70        (331)
        Jan 07 to Dec 07    Swap        500           Cdn $75.82        (263)
        ---------------------------------------------------------------------


        Financial AECO Natural Gas Contracts

        ---------------------------------------------------------------------
                                                                  Unrealized
                                                                        Gain
                                                                       as at
                                                                September 30,
        Term              Contract   Volume         Fixed Price         2007
                                     (GJs/d)              ($/GJ)  (CDN $000s)
        ---------------------------------------------------------------------
        Jul 06 to Mar 08    Collar    5,000  Cdn $6.00 to $11.10         482
        Jan 07 to Dec 07    Swap      2,500            Cdn $7.55         442
        Jan 07 to Dec 07    Swap      2,500            Cdn $7.62         458
        Feb 07 to Mar 08    Swap      1,250            Cdn $7.68         373
        Feb 07 to Mar 08    Swap      1,250            Cdn $7.70         484
        ---------------------------------------------------------------------
    

    Reader Advisory

    Certain information regarding Highpine in this news release including
management's assessment of future plans and operations and the effect on
Highpine and its funds flow from changes to royalty rates in Alberta may
constitute forward-looking statements under applicable securities laws and
necessarily involve risks including, without limitation, risks associated with
oil and gas exploration, development, exploitation, production, marketing and
transportation, risks associated with sour hydrocarbons, changes to the
proposed royalty regime prior to implementation and thereafter, loss of
markets, volatility of commodity prices, currency fluctuations, imprecision of
reserve estimates, environmental risks, competition from other producers,
inability to retain drilling rigs and other services, capital expenditure
costs, including drilling, completion and facilities costs, unexpected decline
rates in wells, delays in projects and/or operations resulting from surface
conditions, wells not performing as expected, delays resulting from or
inability to obtain required regulatory approvals and ability to access
sufficient capital from internal and external sources. As a consequence,
actual results may differ materially from those anticipated in the forward-
looking statements. Readers are cautioned that the foregoing list of factors
is not exhaustive. Additional information on these and other factors that
could affect Highpine's operations and financial results are included in
reports on file with Canadian securities regulatory authorities and may be
accessed through the SEDAR website (www.sedar.com) and at Highpine's website
(www.highpineog.com). Furthermore, the forward-looking statements contained in
this news release are made as at the date of this news release and Highpine
does not undertake any obligation to update publicly or to revise any of the
forward-looking statements, whether as a result of new information, future
events or otherwise, except as may be required by applicable securities laws.

    Boes may be misleading, particularly if used in isolation. A boe
conversion ratio of six Mcf to one bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.

    The term "funds flow" is not a recognized measure under Canadian
generally accepted accounting principles ("GAAP"). Management believes that in
addition to cash flow from operating activities, funds flow is a useful
supplemental measure. Investors are cautioned, however, that this measure
should not be construed as an alternative to cash flow from operating
activities determined in accordance with GAAP as an indication of Highpine's
performance. Highpine's method of calculating funds flow may differ from other
companies, especially those in other industries and accordingly may not be
comparable to measures used by other companies. Highpine calculates funds from
operations as cash from operating activities before the change in non-cash
working capital related to operating activities and abandonment expenditures.

    Highpine is a Calgary-based oil and natural gas company engaged in
exploration for and the acquisition, development and production of natural gas
and crude oil in western Canada. Highpine's current exploration and
development efforts are focused in the West Pembina Nisku and West Central
Alberta Gas Fairway, both located in Central Alberta. The company's class A
common shares trade on the Toronto Stock Exchange under the symbol "HPX".





For further information:

For further information: A. Gordon Stollery, President and Chief
Executive Officer, Bob Rosine, Executive Vice President, Corporate
Development, Harry D. Cupric, Vice President, Finance and Chief Financial
Officer, Telephone: (403) 265-3333, Facsimile: (403) 265-3362, Website:
www.highpineog.com

Organization Profile

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