Highpine Oil & Gas Limited announces 2006 financial and operational results and provides 2007 operations update



    CALGARY, March 13 /CNW/ - Highpine Oil & Gas Limited (TSX: HPX)
("Highpine" or the "Company") is pleased to announce its financial and
operational results from an exceptional growth year in 2006 and provide a 2007
operations update.

    2006 Financial and Operational Highlights:
    ------------------------------------------

    
    -   Oil and gas revenue before hedging activities increased 68% to
        $247.8 million from $147.3 million in 2005.

    -   Cash flow increased 70% to $127.1 million from $74.6 million in 2005.
        Cash flow per diluted share increased 4% to $2.17 from $2.09 in 2005.

    -   Net capital expenditures, excluding corporate acquisitions, increased
        45% to $222.2 million from $153.6 million in 2005.

    -   Completed a bought-deal financing which generated $100.6 million of
        gross proceeds.

    -   Completion of a $225 million credit facility with a syndication of
        bank lenders.

    -   Average daily production increased 87% to 11,779 boe/d from
        6,288 boe/d in 2005 with a 2006 year end exit rate production of
        approximately 14,000 boe/d and March 2007 average production to-date
        in excess of 18,000 boe/d.

    -   Drilled and cased 74 (46.7 net) wells with an 85% success rate.

    -   Drilled 26 (18.7 net) wells in Pembina, resulting in 12 (8.9 net)
        successful Nisku oil and gas wells, 6 (4.4 net) Rock Creek/Ellerslie
        gas wells, 5 (3.2 net) service wells and 3 (2.2 net) dry holes.
        Success rate in wells targeting Nisku production was 80%. Of the 12
        successful Nisku wells drilled, 9 wells represent new Nisku pool
        discoveries with significant future delineation drilling potential.

    -   Drilled 48 (27.9 net) wells in the West Central Alberta Gas Fairway,
        resulting in 40 (23.1 net) successful oil and gas wells and 8
        (4.8 net) dry holes, for an overall success rate of 83%. Notable oil
        and gas discoveries were made in Ante Creek, Chip Lake and Joffre.

    -   Considerable progress in executing on operating activities in the
        Pembina Nisku Fairway including generation of fully approved Nisku
        drilling licences, implementation and operation of pressure
        maintenance (ie. water injection) schemes and reliable operation of
        Highpine's wells and facilities.

    -   Completed acquisitions of White Fire Energy Ltd. ("White Fire") and
        Kick Energy Corporation ("Kick") adding quality production, drilling
        prospects and strategic infrastructure in the Pembina Nisku Fairway.
        Experienced and knowledgeable senior management and directors were
        also added through the acquisitions complimenting Highpine's staff
        and reinforcing Highpine's ability to execute its Pembina Nisku
        focussed business plan.

    Year End Reserves and Finding, Development and Acquisition Costs ("FD&A")
    Highlights:
    -------------------------------------------------------------------------

    -   Proved plus probable reserves increased 82% in 2006 to 44.4 mmboe,
        net of production and revisions.

    -   Proved reserves increased 86% in 2006 to 29.3 million barrels of oil
        equivalent (mmboe) net of production and revisions.

    -   Reserve replacement ratios of 566 percent and 415 percent on a proved
        plus probable and total proved basis respectively.

    -   Total 2006 FD&A costs, for proved plus probable reserves, were
        $27.23/boe before changes in future capital and after revisions
        ($30.47/boe including future capital). This amount is comprised of
        Finding and Development ("F&D") costs of $17.24/boe ($24.24/boe
        including future capital) for 2006 exploration and development
        activities and $35.85/boe for 2006 acquisition activities.

    -   In the Pembina Nisku Fairway, Highpine achieved an exceptional proved
        plus probable F&D cost for exploration and development activities of
        $10.62/boe before changes in future capital and after revisions
        ($18.92/boe including future capital). Highpine is committing over
        75% of its 2007 capital expenditure budget to the Pembina Nisku
        Fairway due to ongoing success in Pembina during 2006 and hopes to
        maintain top decile F&D costs in the future as the Company drills its
        extensive inventory of Nisku locations.

    -   Acquisition costs were in line with expectations at $35.85 per boe on
        a proved plus probable reserves basis. The acquisition costs related
        to the acquisitions of White Fire and Kick, each of which added an
        inventory of quality drilling prospects.

    Undeveloped Land Holdings:
    --------------------------

    -   As of December 31, 2006, Highpine's net undeveloped land holdings
        increased 57% to 329,000 net acres from 210,000 net acres in 2005. Of
        the total 329,000 net acres, 162,000 net acres are in Pembina and
        108,000 net acres are in the West Central Alberta Gas Fairway.

    -   The undeveloped land contains Highpine's inventory of approximately
        325 gross (245 net) drilling locations of which 100 gross (80 net)
        locations are on the Pembina Nisku trend and the balance of the
        locations (225 gross (165 net)) target oil and gas in the shallow gas
        horizons in Pembina and multi-zone oil and natural gas (with liquids)
        in the West Central Alberta Gas Fairway.

    2007 Operational Highlights:
    ----------------------------

    -   Highpine's production averaged in excess of 18,000 boe/d during
        February 2007. March average production to-date continues to be in
        excess of 18,000 boe/d with several Pembina Nisku well tie-in
        projects in progress that are anticipated to be completed by the end
        of the first quarter. The stated March volume does not include
        approximately 1,500 boe/d from the Dominion operated Nisku "II" oil
        pool that was shut-in on March 1, 2007 to allow reservoir pressures
        to build above the AEUB assigned minimum operating pressure ("MOP")
        for the field. This field is expected to be curtailed for
        approximately six to eight weeks. Despite our March average
        production to-date remaining in excess of 18,000 boe/d, without
        1,500 boe/d contribution from the Nisku II pool, there remains the
        potential for short-term production reductions, particularly in
        situations where offset producers are not replacing voidage in common
        Nisku pools. An example of this, is the Nisku "WW" pool which could
        be temporarily shut-in for this reason. Highpine is replacing
        voidages in all of its operated pressure maintenance schemes in
        various Nisku pools. Overall, Nisku pools may experience production
        fluctuations during 2007 for similar reasons, however, with
        Highpine's current productive capacity, well tie-ins in progress, and
        its anticipated drilling activities, Highpine is estimating an
        average 2007 production rate in excess of 20,000 boe/d.

    -   Highpine has continued to realize excellent drilling results thus far
        in 2007. Year-to-date, Highpine has participated in 12 (8.6 net)
        wells resulting in 9 (6.4 net) potential oil and gas producing wells,
        2 (1.5 net) service wells and 1 (0.7 net) dry hole. Of the
        successful oil and gas wells, 4 (4.0 net) are in the Pembina Nisku
        Fairway. Highpine currently has 3 drilling operations in progress in
        Pembina targeting 3 potential Nisku producing wells.

    FINANCIAL AND OPERATING RESULTS

    The following table summarizes certain financial and operating information
for the periods indicated:

    -------------------------------------------------------------------------
                             Three months ended        Twelve months ended
                                 December 31,               December 31,
                                                %                          %
                            2006     2005  Change      2006     2005  Change
    -------------------------------------------------------------------------
    ($000s, except per
     share and
     $/boe amounts)

    Financial
    Total revenue(1)      67,552   54,229      25   254,938  141,634      80
    Cash flow from
     operations           29,657   27,957       6   127,072   74,550      70
      Per share - diluted   0.44     0.62     (29)     2.17     2.09       4
    Net earnings (loss)   (5,446)   4,855       -     6,953   12,274     (43)
      Per share - diluted  (0.08)    0.11       -      0.12     0.34     (65)
    Net debt(2)          169,570  109,599      55   169,570  109,599      55
    Total assets       1,392,911  753,690      85 1,392,911  753,690      85
    Corporate
     acquisitions(3)           -        -       -   379,345  257,314      47
    Capital
     expenditures(4)      72,711   50,861      43   222,214  153,606      45
    Total shares
     outstanding (No.)    67,648   44,250      53    67,648   44,250      53
    Weighted average
     shares
     outstanding (No.)
      Basic               67,643   44,239      53    57,744   35,051      65
      Diluted             67,643   44,906      51    58,674   35,718      64
    -------------------------------------------------------------------------
    Operating
    Average daily
     production
      Crude oil and
       NGLs (bbls/d)       8,653    5,881      47     7,554    3,984      90
      Natural gas
       (mcf/d)            30,221   16,006      89    25,350   13,823      83
    -------------------------------------------------------------------------
    Total (boe/d)         13,690    8,549      60    11,779    6,288      87
    -------------------------------------------------------------------------
    Average selling
     prices(5)
      Crude oil and
       NGLs ($/bbl)        58.37    67.94     (14)    66.19    67.16      (1)
      Natural gas ($/mcf)   7.24    12.45     (42)     7.06     9.84     (28)
    -------------------------------------------------------------------------
    Total ($/boe)          52.88    70.06     (25)    57.64    64.18     (10)
    -------------------------------------------------------------------------
    Wells drilled - gross
     (net) (No.)
      Oil                  8(6.2)   3(2.4)      -   15(11.5)   9(6.5)      -
      Natural Gas          8(4.6)   6(5.0)      -   43(25.0) 19(11.0)      -
      Abandoned / other    3(2.5)  11(6.6)      -   16(10.2) 28(18.9)      -
    -------------------------------------------------------------------------
      Total              19(13.3) 20(14.0)      -   74(46.7) 56(36.4)      -
      Drilling success
       rate (%)               95       63       -        85       63       -
    -------------------------------------------------------------------------
    Operating netback
     ($/boe)
      Oil and natural
       gas sales           52.88    70.06     (25)    57.64    64.18     (10)
      Royalties           (14.80)  (20.79)    (29)   (16.40)  (16.99)     (3)
      Operating costs     (10.42)   (6.14)     70     (8.57)   (6.35)     35
      Transportation
       costs               (0.62)   (1.20)    (48)    (0.71)   (1.06)    (33)
      Realized hedging
       gain (loss)          0.58    (2.32)      -      1.09    (2.88)      -
    -------------------------------------------------------------------------
      Operating netback    27.62    39.61     (30)    33.05    36.90     (10)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Notes:
    (1) Total revenue includes realized and unrealized hedging losses and
        gains.
    (2) Net debt includes working capital excluding unrealized financial
        instruments.
    (3) Corporate acquisitions only include the amounts allocated to
        property, plant and equipment.
    (4) Capital expenditures are presented net of proceeds of disposals.
    (5) The average selling prices reported are before hedging activities.
    

    2006 Financial Results:
    -----------------------

    Gross oil and gas revenue increased 68% in 2006 to $247.8 million, an
increase of $100.5 million from $147.3 million in 2005. Cash flow increased
70% in 2006 to $127.1 million ($2.17/diluted share), an increase of
$52.6 million from $74.6 million ($2.09/diluted share) in 2005. These
increases can be attributed to growth in production volumes resulting from the
acquisition of White Fire and Kick, and production increases in Highpine's
core areas of Pembina and the West Central Alberta Gas Fairway.
    Highpine's net capital expenditures in 2006 were $222.2 million,
excluding the acquisitions of White Fire and Kick. This amount represents an
increase of 45% from $153.6 million spent in 2005. The $222.2 million is
comprised of $27.8 million on land and seismic, $110.7 million on drilling,
$52.6 million on facilities and equipment, $27.5 million on property
acquisitions and $3.6 million on capitalized general and administrative
expenses and office equipment.

    2006 Operational Results:
    -------------------------

    Highpine's production increased from 11,397 boe/d in the first quarter to
a 2006 exit rate of approximately 14,000 boe/d. Highpine's operated wells and
facilities in Pembina and in the West Central Alberta Gas Fairway, ran at an
on-line efficiency rate of greater than 95% during the year. Despite strong
operating performance, average volumes for the year were negatively impacted
by delays in regulatory approvals or attainment of required services, and the
periods of down-time experienced by the Dominion operated Violet Grove
(Pembina) oil battery during the year.
    Highpine participated in the drilling of 74 (46.7 net) wells in 2006 and
achieved a drilling success rate of 85%. A total of 26 (18.7 net) wells were
drilled in the Pembina Nisku Fairway due to progress made in obtaining well
drilling licences. Results of the Pembina drilling program included 12
(8.9 net) Nisku oil and gas wells, 6 (4.4 net) shallow gas wells, 5 (3.2 net)
service wells and 3 (2.2 net) dry holes. The overall drilling success rate in
Pembina exceeded 80%.
    The balance of the wells were drilled in the West Central Alberta Gas
Fairway at an 83% overall success rate.
    Water injection commenced into several Nisku pools in 2006, including the
Nisku "GG", "II", "KK", "MM", "VV" and "SS" pools. In January 2007 water
injection commenced into the "WW" and "ZZ" pools. Highpine is currently
involved in 9 Nisku pool pressure maintenance schemes of which 7 are Company
operated. The Wabamun water source with water injection into the Nisku aquifer
has proven to be effective in maintaining reservoir pressure and increasing
oil recovery in the Nisku pools. However, it will be necessary to monitor, on
an ongoing basis, reservoir pressures in the Nisku pools and short-term
production curtailments may be required to make up voidage replacement. Recent
examples of this include the shutting-in of production from the non-operated
Nisku "SS" and "II" pools. Highpine is successfully replacing voidage in all
of its operated pressure maintenance schemes, however, there remains potential
for short-term production reduction in situations where offset producers are
not replacing voidage. The Nisku "WW" pool could be temporarily shut-in for
this reason.
    Production from various Nisku pools may fluctuate during 2007, for
similar reasons, however, with Highpine's production capacity, well tie-ins in
progress and 2007 drilling activities, the Company is estimating an average
2007 production rate in excess of 20,000 boe/d for the year.
    Highpine's continued seismic and land acquisition programs in 2006 have
maintained a multi-year inventory of future drilling opportunities. At
year-end, Highpine's undeveloped land holdings totalled 329,000 net
undeveloped acres of which 162,000 net acres (approximately 50%) are in
Pembina and 108,000 net undeveloped acres are in Highpine's West Central
Alberta Gas Fairway. Highpine also significantly increased its seismic data
during 2006 to 1,930 square miles of 3D data and 3,600 miles of 2D data.
Additional 3D seismic survey programs are being contemplated for 2007.
    Highpine continued to execute its strategy of consolidating the Pembina
Nisku Fairway by acquiring White Fire, Kick and selective assets in the Nisku
Fairway during the year. The Company will continue to evaluate further
strategic consolidation opportunities.

    Year-end Reserves Summary:
    --------------------------

    As at December 31, 2006, the Company's total proved plus probable gross
working interest reserves were 44,395 mboe, an increase of 82% compared to
24,356 mboe as at December 31, 2005.
    The growth in reserve volumes resulted principally from Highpine's
successful 2006 Pembina drilling program and the acquisition of White Fire and
Kick.
    Paddock has evaluated all of Highpine's reserves as at December 31, 2006.
The December 31, 2006 reserves presented below, include Company working
interests before royalty interests and before royalty costs. Where volumes are
expressed on a barrel of oil equivalent (boe) basis, gas volumes have been
converted to barrels of oil in the ratio of one barrel of oil to six thousand
cubic feet of natural gas.

    
     Summary of Crude Oil, NGL and Natural Gas Reserves and Net Present
     Values of Estimated Future Net Revenue as of December 31, 2006 Based
                       on Forecast Price Assumptions(*)

    -------------------------------------------------------------------------
                                                             Crude
                                                 Natural       Oil     Total
    December 31, 2006                                Gas    & NGLs     (6:1)
    -------------------------------------------------------------------------
                                                   (bcf)   (mbbls)    (mboe)
    Proved developed producing                     45.49    11,249    18,831
    Proved developed non-producing                 16.86     3,478     6,289
    Proved undeveloped                             12.59     2,037     4,135
    -------------------------------------------------------------------------
    Total proved                                   74.94    16,764    29,254
    Probable additional                            37.73     8,852    15,141
    -------------------------------------------------------------------------
    Total proved plus probable                    112.67    25,616    44,395
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (*) Highpine working interest only - does not include Highpine royalty
        interests and royalty costs


                                 Net Present Values of Future Net Revenue
                           -------------------------------------------------
                                Before Income Taxes Discounted at (%/year)
                           -------------------------------------------------
    Reserves Category          0         5         10        15        20
                           --------- --------- --------- --------- ---------
                                            (Thousand of Dollars)
    Proved
      Developed Producing    543,822   461,926   405,730   364,344   332,367
      Developed
       Non-Producing         150,028   127,734   111,676    99,547    90,055
                           --------- --------- --------- --------- ---------
      Total Developed        693,850   589,660   517,406   463,891   422,422
      Undeveloped             90,164    64,901    50,105    40,159    32,923
                           --------- --------- --------- --------- ---------
    Total Proved             784,014   654,561   567,511   504,050   455,345
    Probable                 435,116   278,815   206,469   163,100   133,629
                           --------- --------- --------- --------- ---------
    Total Proved Plus
     Probable              1,219,130   933,376   773,980   667,150   588,974
                           --------- --------- --------- --------- ---------
                           --------- --------- --------- --------- ---------

    -------------------------------------------------------------------------
    Oil & Gas Price Forecast                     WTI @ $US/$CDN
                                                 Cushing  Exchange    AECO C
                                                 $US/BBL      Rate  C$/MMBTU
    -------------------------------------------------------------------------
    Year

    2007                                           61.00      0.87      7.33
    2008                                           60.00      0.87      7.91
    2009                                           60.00      0.87      7.89
    2010                                           58.00      0.87      7.87
    2011                                           56.00      0.87      8.02
    -------------------------------------------------------------------------

    Reserves Reconciliation(*)

    -------------------------------------------------------------------------
                      Natural Gas       Crude Oil & NGLs     Combined BOE
    -------------------------------------------------------------------------
                     Total  Proved &     Total  Proved &     Total  Proved &
                    Proved  Probable    Proved  Probable    Proved  Probable
    -------------------------------------------------------------------------
                         (bcf)              (mbbls)             (mboe)
    December 31,
     2005            31.76     47.14    10,431    16,500    15,725    24,356
    Drilling
     Additions       24.05     39.84     3,928     4,691     7,936    11,331

    Acquisitions     25.96     36.58     4,591     6,969     8,917    13,065
    Dispositions         -         -         -         -         -         -
    Technical
     Revisions        2.42     (1.64)      572       214       975       (58)
    Production       (9.25)    (9.25)   (2,758)   (2,758)   (4,299)   (4,299)
    -------------------------------------------------------------------------
    December 31,
     2006            74.94    112.67    16,764    25,616    29,254    44,395
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (*) Highpine working interests only - does not include Highpine royalty
        interests and royalty costs
    

    Finding, Development and Acquisition Costs:
    -------------------------------------------

    Highpine has calculated FD&A costs for 2006 and for the three year period
from 2004 to 2006.
    The 2006 F&D costs for the exploration and development program only,
averaged $17.24 per boe for proved plus probable reserves and $21.81 per boe
for proved reserves, before changes in future capital and after revisions
($24.24 and $26.65/boe respectively including future capital).
    This 2006 F&D costs include top decile F&D costs of $10.62 per boe for
proved plus probable reserves and $14.78 per boe for proved reserves ($18.92
and $21.06/boe, respectively including future capital) in the Pembina Nisku
Fairway which yields superior reinvestment efficiency ratios of 3.2 and 2.3,
displaying the economic power of the Nisku play type. The 2006 Pembina results
support the realization of a vision of the high economic growth potential of
the Nisku Fairway when it aggressively committed up-front capital expenditures
for land, seismic and facilities during the past four years. Highpine also
realized upward reserve revisions in several of its Nisku pools, reaffirming
Highpine's confidence in the quality of its Pembina assets. Highpine expects
to allocate the majority of its capital expenditure budgets in the foreseeable
future to its Pembina Nisku Fairway to capitalize on its significant inventory
of drilling locations and its progress in procuring drilling licences.
    Despite a successful drilling year in Pembina, Corporate F&D costs of
$24.24 per boe (including future capital) for proved plus probable reserves
are higher than desired due primarily to negative performance based reserve
revisions in certain properties in the West Central Alberta Gas Fairway.
Highpine intends to allocate capital to select properties and drilling
prospects contained in this Fairway.
    The acquisition costs of $35.85 per boe proved plus probable reserves are
in line with expectations from evaluations conducted when assessing the
acquisitions. Highpine expects that these costs will decrease with future
exploitation of the drilling prospects accompanying these acquisitions. For
example, Highpine acquired 30 drillable Nisku prospects with the acquisition
of Kick.
    For the three year period ended December 31, 2006, F&D costs for the
Company's exploration and development program only, averaged $17.37 per boe
for proved plus probable reserves and $24.12 per boe for proved reserves
excluding an adjustment for future capital and after revisions ($22.00 and
$27.46/boe respectively including future capital).
    Stand alone Pembina, three year exploration and development program F&D
costs averaged $12.49 per boe for proved plus probable reserves and $18.91 per
boe for proved reserves before future capital ($17.85 and $23.04 per boe,
respectively including future capital). Re-investment efficiency ratios for
the same 3 year period are 3.0 and 2.0 for proved plus probable and total
proved reserves respectively. These strong F&D costs create a strong
re-investment efficiency ratio which clearly demonstrates Highpine's success
in developing the robust economic potential of the Pembina Nisku Fairway.
    Total 2006 FD&A costs, including changes in future capital, were $30.47
per boe for proved plus probable reserves and $39.59 per boe for proved
reserves. Average FD&A costs for the three year period ended December 31, 2006
were $30.01 per boe proved plus probable reserves and $40.95 per boe for
proved reserves. Highpine expects that its FD&A costs will improve in the
future as it allocates the majority of its capital expenditures to the Pembina
Nisku Fairway.

    
    Total Proved Finding, Development and Acquisition Costs

    -------------------------------------------------------------------------
    Years ended December 31,                        2006      2005      2004
    -------------------------------------------------------------------------
    (000s, except per unit)                            $         $         $

    Excluding effect of acquisition & dispositions
    Total exploration & development capital
     costs                                       194,394   147,306    66,000
    Net change from previous year's estimated
     future development costs                     43,104     3,773     9,520
    -------------------------------------------------------------------------
    Total estimated capital for finding &
     development costs                           237,499   151,079    75,520
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Additions to  total proven reserves (mboe)     8,911     3,673     4,318
    Finding & development costs ($/boe) -
     Before Change in Future Development Costs     21.81     40.10     15.29
    Finding & development costs ($/boe)            26.65     41.13     17.49
    Three-year average finding & development
     cost ($/boe)                                  27.46         -         -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Including effect of acquisition & dispositions
    Total exploration & development capital
     costs                                       662,751   552,606   113,747
    Net change from previous year's estimated
     future development costs                     43,104     3,773     9,520
    Total estimated capital for finding &
     development costs                           705,855   556,379   123,267
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Additions to  total proven reserves (mboe)    17,829     9,844     6,165
    Finding & development costs ($/boe) -
     Before Change in Future Development Costs     37.17     56.14     18.45
    Finding & development costs ($/boe)            39.59     56.52     19.99
    Three-year average finding & development
     cost ($/boe)                                  40.95         -         -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Total Proved Plus Probable Finding, Development and Acquisition Costs

    -------------------------------------------------------------------------
    Years ended December 31,                        2006      2005      2004
    -------------------------------------------------------------------------
    (000s, except per unit)                            $         $         $

    Excluding effect of acquisition & dispositions
    Total exploration & development capital
     costs                                       194,394   147,306    66,000
    Net change from previous year's estimated
     future development costs                     78,896    16,637    13,160
    -------------------------------------------------------------------------
    Total estimated capital for finding &
     development costs                           273,291   163,943    79,160
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Additions to total proved plus probable
     reserves (mboe)                              11,273     5,399     6,804
    Finding & development costs ($/boe)
     - Before Change in Future Development Costs   17.24     27.28      9.70
    Finding & development costs ($/boe)            24.24     30.36     11.63
    Three-year average finding & development
     cost ($/boe)                                  22.00         -         -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Including effect of acquisition & dispositions
    Total estimated exploration & development
     capital costs                               662,751   552,606   113,747
    Net change from previous year's estimated
     future development costs                     78,896    16,637    13,160
    -------------------------------------------------------------------------
    Total estimated capital for finding &
     development costs                           741,647   569,243   126,907
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Additions to  total proved plus probable
     reserves (mboe)                              24,338    14,474     9,106
    Finding & development costs ($/boe) -
     Before Change in Future Development Costs     27.23     38.18     12.49
    Finding & development costs ($/boe)            30.47     39.33     13.94
    Three-year average finding & development
     cost ($/boe)                                  30.01         -         -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Note: The aggregate of the exploration and development costs incurred in
    the most recent financial year and the change during that year in
    estimated future development costs generally will not reflect total
    finding and development costs related to reserve additions for that year.

    2007 Outlook:
    -------------

    The Company is positioned to achieve its most successful operating year
in its history. The 2006 Pembina drilling success was an important step
towards achieving the long term vision of being a high growth exploration and
production company targeting Devonian reefs. Year to date, production has
increased from approximately 16,000 boe/d in January, to in excess of
18,000 boe/d in February. Current production continues to be in excess of
18,000 boe/d without contribution from the Nisku II pool. Several Pembina
Nisku wells are expected to be tied-in and brought on stream prior to the end
of March. Highpine is estimating an average 2007 production rate in excess of
20,000 boe/d. The production forecast remains conservative because of the
possibility of production fluctuations associated with the ongoing need to
monitor reservoir pressures in certain Nisku pools and/or additional downtime
in major gas processing facilities, both of which may result in short-term
shut-ins.
    The 2007 capital expenditure program will be approximately $200 million,
which includes the drilling of approximately 50 to 60 gross (42 to 50 net)
wells. Approximately $150 million (75%) of the capital budget is targeted for
drilling, facilities and well tie-ins in the Pembina Nisku Fairway, including
the drilling of approximately 30 to 35 gross (25 to 30 net) wells that will
target production from the Nisku formation. Approximately $20 million of the
capital budget has been allocated for exploration and development activity in
the West Central Alberta Gas Fairway and $30 million for unallocated land and
seismic purchases.
    In 2007 to date, 12 (8.6 net) wells were drilled resulting in 4 (4.0 net)
potential Nisku oil and gas wells, 5 (2.4 net) potential gas wells, 2 (1.5
net) service wells and 1 (0.7 net) dry holes achieving a 100% success rate in
production targeted wells.
    Highpine has posted an updated corporate presentation on its website at
www.highpineog.com.

    MANAGEMENT'S DISCUSSION AND ANALYSIS

    This Management's Discussion and Analysis (MD&A) is dated and based on
information at March 12, 2007. This MD&A has been prepared by management and
should be read in conjunction with the 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").
    Certain information set forth in this MD&A contains forward-looking
statements including expectations of future production, 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 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 "cash flow from operations," "cash flow", "cash
flow per share," and "operating netback" which are not recognized measures
under Canadian generally accepted accounting principles (GAAP). Management
believes that in addition to net earnings, cash flow is a useful supplemental
measure as it provides an indication of the results generated by Highpine's
principal business activities before the consideration of how these activities
are financed or how the results are taxed. Investors are cautioned, however,
that this measure should not be construed as an alternative to net earnings
determined in accordance with GAAP as an indication of Highpine's performance.
Highpine's method of calculating cash 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 cash from operations as
cash from operating activities before the change in non-cash working capital
related to operating activities. Highpine also uses operating netback as an
indicator of operating performance. Operating netback is calculated on a per
boe (as defined below) 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.
    All references to dollar values refer to Canadian dollars unless
otherwise stated.
    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        Twelve months ended
                                      December 31,               December 31,
                           2006     2005 % Change     2006     2005 % Change
    -------------------------------------------------------------------------
    ($000s)
    Crude oil and natural
     gas liquids (NGLs)
     revenue             46,469   36,760       26  182,509   97,674       87
    Natural gas revenue  20,132   18,336       10   65,295   49,629       32
    -------------------------------------------------------------------------
                         66,601   55,097       21  247,804  147,303       68
    Realized hedging
     gain (loss)            727   (1,823)       -    4,703   (6,613)       -
    Unrealized hedging
     gain (loss)            224      955      (77)   2,431      944      158
    -------------------------------------------------------------------------
    Total oil and
     natural gas
     revenue             67,552   54,229       25  254,938  141,634       80
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    For the twelve months ended December 31, 2006, total oil and natural gas
revenue rose to $254.9 million from $141.6 million in the 2005 twelve-month
period. The increase was due primarily to production increases which resulted
in a $116.0 million increase in revenues. Decreases in commodity prices,
primarily natural gas were partially offset by the Company's commodity price
risk management program.

    Production
    -------------------------------------------------------------------------
                               Three months ended        Twelve months ended
                                      December 31,               December 31,
                           2006     2005 % Change     2006     2005 % Change
    -------------------------------------------------------------------------
    Daily Production
    Crude oil and
     NGLs (bbls/d)        8,653    5,881       47    7,554    3,984       90
    Natural gas (mcf/d)  30,221   16,006       89   25,350   13,823       83
    -------------------------------------------------------------------------
    Boe/d                13,690    8,549       60   11,779    6,288       87
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Production Mix
    Crude oil and NGLs      63%      69%        -      64%      63%        -
    Natural gas             37%      31%        -      36%      37%        -
    -------------------------------------------------------------------------
                           100%     100%        -     100%     100%        -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                               Three months ended        Twelve months ended
                                      December 31,               December 31,
                           2006     2005 % Change     2006     2005 % Change
    -------------------------------------------------------------------------
    (boe/d)
    Daily Production
     by Area
    Pembina Nisku
     Fairway              9,740    6,090       60    8,324    3,927      112
    West Central
     Alberta              3,166    1,597       98    2,640    1,492       77
    Gas Fairway
    Bantry / Retlaw         492      565      (13)     475      576      (18)
    Other                   292      297       (2)     340      293       16
    -------------------------------------------------------------------------
    Total                13,690    8,549       60   11,779    6,288       87
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Production for the twelve months ended December 31, 2006 increased
87 percent to 11,779 boe/d from 6,288 boe/d in 2005. The acquisition of White
Fire Energy Ltd. ("White Fire") contributed 600 boe/d from February 22, 2006
onward. The acquisition of Kick Energy Corporation ("Kick") added 3,600 boe/d
from August 1, 2006 onwards. Additional production gains are attributable to a
full year of production from the acquisition of Vaquero Energy Ltd.
("Vaquero") which was completed on May 31, 2005, bringing on new production
from the Company's drilling program and property acquisitions.
    The Company is estimating that bringing currently shut-in volumes
on-stream and continued drilling success should result in its average 2007
production rate exceeding 20,000 boe/d.

    
    Pricing
    -------------------------------------------------------------------------
                               Three months ended        Twelve months ended
                                      December 31,               December 31,
                           2006     2005 % Change     2006     2005 % Change
    -------------------------------------------------------------------------
    Selling Prices Before
     Hedges
    Crude oil and NGLs
     ($/bbl)              58.37    67.94      (14)   66.19    67.16       (1)
    Natural gas ($/mcf)    7.24    12.45      (42)    7.06     9.84      (28)
    -------------------------------------------------------------------------
    Total combined
     ($/boe)              52.88    70.06      (25)   57.64    64.18      (10)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                               Three months ended        Twelve months ended
                                      December 31,               December 31,
                           2006     2005 % Change     2006     2005 % Change
    -------------------------------------------------------------------------
    Benchmark Prices
    WTI oil (US$/bbl)     60.22    60.05        -    66.25    56.61       17
    US$/Cdn$ exchange
     rate                  0.87     0.85        2     0.88     0.83        6
    AECO natural gas
     ($/mcf)               6.91    11.37      (39)    6.51     8.73      (34)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    An increase in the WTI benchmark price for crude oil of 17 percent was
offset by a stronger Canadian dollar. A 34 percent decrease in average AECO
prices was the primary driver of the decrease in realized natural gas prices.

    Commodity Price Risk Management

    The Company enters into derivative instruments to manage its commodity
price exposure. The Company does not enter into derivative instrument
contracts for trading or speculative purposes.

    -------------------------------------------------------------------------
                               Three months ended        Twelve months ended
                                      December 31,               December 31,
                           2006     2005 % Change     2006     2005 % Change
    -------------------------------------------------------------------------

    Average volumes
     hedged (boe/d)       5,500      868      534    4,736    1,086      336
    Percent of production
     hedged                 40%      10%      300      40%      17%      135

    Realized hedging gain
     (loss)                 727   (1,823)       -    4,703   (6,613)       -
    ($000s)
    Realized hedging gain
     (loss) ($/boe)        0.58    (2.32)       -     1.09    (2.88)       -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    For the twelve months ended December 31, 2006, Highpine realized a
$5.3 million natural gas hedging gain and a $0.6 million crude oil hedging
loss.


    The following contracts are outstanding at December 31, 2006:

    -------------------------------------------------------------------------
    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
    Jun 06 to Mar 07  Natural Gas Collar 5,000 GJs/d  Cdn $5.40 to $12.00/GJ
    Jul 06 to Mar 08  Natural Gas Collar 5,000 GJs/d  Cdn $6.00 to $11.10/GJ
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    As at December 31, 2006, the unrealized mark-to-market gain on
outstanding crude oil contracts was $1.1 million and the unrealized mark-to-
market gain on outstanding natural gas contracts was $2.1 million. The
unrealized mark-to-market gain has been recorded as a current asset in the
consolidated balance sheets.

    
    Royalty Expense
    -------------------------------------------------------------------------
                               Three Months Ended        Twelve Months Ended
                                      December 31,               December 31,
                           2006     2005 % Change     2006     2005 % Change
    -------------------------------------------------------------------------
    Total royalties, net
     of ARTC ($000s)     18,635   16,352       14   70,529   38,995       81
    As a percent of
     oil and natural
     gas sales (before
     hedging)               28%      30%       (7)     28%      26%        8
    $/boe                 14.80    20.79      (29)   16.40    16.99       (3)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Royalty rates as a percentage of oil and natural gas sales were higher in
2006 than in 2005 due to gross overriding royalties on certain Pembina wells
along with a higher proportion of the Company's production coming from Pembina
which attracts higher Crown royalties.

    
    Operating Costs
    -------------------------------------------------------------------------
                               Three Months Ended        Twelve Months Ended
                                      December 31,               December 31,
                           2006     2005 % Change     2006     2005 % Change
    -------------------------------------------------------------------------
    Operating costs
     ($000s)             13,124    4,827      172   36,839   14,575      153
    $/boe                 10.42     6.14       70     8.57     6.35       35
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    For the twelve month period ended December 31, 2006, operating costs on a
per boe basis increased 35 percent over 2005. The increases were a result of
the Company incurring fixed costs at the Violet Grove oil battery while
certain Pembina volumes were shut-in, increased costs at Pembina associated
with sour oil production and higher overall processing costs on some of the
Company's properties.

    
    Transportation Costs
    -------------------------------------------------------------------------
                               Three Months Ended        Twelve Months Ended
                                      December 31,               December 31,
                           2006     2005 % Change     2006     2005 % Change
    -------------------------------------------------------------------------
    Transportation
     costs ($000s)          778      947      (18)   3,069    2,439       26
    $/boe                  0.62     1.20      (48)    0.71     1.06      (33)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    For the twelve months ended December 31, 2006, transportation costs
decreased 33 percent to $0.71/boe from $1.06/boe in 2005. Transportation costs
for the 2005 twelve-month period were higher as a $0.4 million sulphur
trucking charge related to 2004 production was included in 2005.

    
    Operating Netback
    -------------------------------------------------------------------------
                               Three Months Ended        Twelve Months Ended
                                      December 31,               December 31,
                           2006     2005 % Change     2006     2005 % Change
    -------------------------------------------------------------------------
    ($/boe)

    Sales price before
     hedging              52.88    70.06      (25)   57.64    64.18      (10)
    Royalties            (14.80)  (20.79)     (29)  (16.40)  (16.99)      (3)
    Operating costs      (10.42)   (6.14)      70    (8.57)   (6.35)      35
    Transportation
     costs                (0.62)   (1.20)     (48)   (0.71)   (1.06)     (33)
    -------------------------------------------------------------------------
    Netback before
     hedges               27.04    41.93      (36)   31.96    39.78      (20)
    Realized hedging
     gain (loss)           0.58    (2.32)       -     1.09    (2.88)       -
    -------------------------------------------------------------------------
    Operating netback     27.62    39.61      (30)   33.05    36.90      (10)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Operating netback before realized hedging gains or losses was $31.96/boe
for the twelve months ended December 31, 2006 compared to $39.78/boe in 2005.
The 20 percent decrease was due to lower realized natural gas prices as well
as higher operating costs.
    Operating netback for the year ended December 31, 2006 was positively
impacted by realized natural gas hedging gains.

    
    General and Administrative Expenses
    -------------------------------------------------------------------------
                               Three Months Ended        Twelve Months Ended
                                      December 31,               December 31,
                           2006     2005 % Change     2006     2005 % Change
    -------------------------------------------------------------------------
    Gross expenses
     ($000s)              4,436    2,510       77   12,931    7,154       81
    Capitalized ($000s)  (1,227)    (690)      78   (3,249)  (1,377)     136
    -------------------------------------------------------------------------
    Net expenses ($000s)  3,209    1,820       76    9,682    5,777       68
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    $/boe                  2.55     2.31       10     2.25     2.52      (11)
    percent capitalized     28%      27%        4      25%      19%       32
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Net expenses rose 68 percent to $9.7 million in 2006 from $5.8 million in
2005 as a result of salaries related to personnel obtained from the corporate
acquisitions made during the year as well as staff increases necessary to
manage the growth of the Company. At December 31, 2006, Highpine had 55
Calgary based office employees compared to 39 at December 31, 2005. On a per
boe basis, general and administrative expenses decreased 11 percent to
$2.25/boe in 2006 from $2.52/boe in 2005.

    Stock-Based Compensation

    Stock-based compensation expense totaled $5.7 million in 2006 compared to
$3.2 million in 2005. The increase was primarily the result of stock options
that were granted to new employees as well as to former Vaquero and White Fire
employees who remained with the Company.

    Interest and Finance Costs

    Interest and finance costs for 2006 were $5.1 million versus $3.6 million
in 2005. The 42 percent increase was due to higher average debt levels and an
increase in the prime interest rate.

    
    Depletion, Depreciation and Accretion
    -------------------------------------------------------------------------
                               Three Months Ended        Twelve Months Ended
                                      December 31,               December 31,
                           2006     2005 % Change     2006     2005 % Change
    -------------------------------------------------------------------------
    Depletion and
     depreciation
     ($000s)             36,682   19,180       91  124,627   53,566      133
    Accretion of asset
     retirement
     obligation ($000s)     220      110      100      679      327      108
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total DD&A           36,902   19,290       91  125,306   53,893      133
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    DD&A rate $/boe       29.31    24.53       19    29.15    23.48       24
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    The depletion, depreciation, and accretion (DD&A) rate increased to
$29.15/boe from $23.48/boe in 2005. The higher DD&A rate is primarily
attributable to the White Fire and Kick acquisitions for which Highpine
recorded a higher proportionate cost per barrel of proved reserves compared to
the Company's existing properties.

    Income Taxes

    For the twelve months ended December 31, 2006, a future tax reduction of
$8.0 million was realized due to a decrease in the Canadian federal and
Alberta tax rates, which resulted in a non-recurring $9.1 million tax
reduction.
    Although current tax horizons depend on product prices, production levels
and the nature, magnitude and timing of capital expenditures, Highpine's
management currently believes no cash income tax will be payable in 2007 or
2008.

    
    Cash Flow and Net Earnings
    -------------------------------------------------------------------------
                               Three Months Ended        Twelve Months Ended
                                      December 31,               December 31,
                           2006     2005 % Change     2006     2005 % Change
    -------------------------------------------------------------------------
    Cash from
     operations ($000s)  29,657   27,957        6  127,072   74,550       70
      Per diluted
       share ($)           0.44     0.62      (29)    2.17     2.09        4
    Net earnings (loss)
     ($000s)             (5,446)   4,855        -    6,953   12,274      (43)
      Per diluted
       share ($)          (0.08)    0.11        -     0.12     0.34      (65)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    For the twelve months ended December 31, 2006, cash flow increased
70 percent to $127.1 million from $74.6 million in the 2005 twelve-month
period. Cash flow per diluted share increased 4 percent to $2.17 in 2006 from
$2.09 in 2005.
    During 2006, net earnings totaled $7.0 million, a 43 percent decrease
from 2005. Net earnings for 2006 include a $9.1 million non-recurring future
tax reduction realized as a result of enacted Canadian federal and Alberta tax
rate reductions. Earnings were negatively impacted by higher DD&A and lower
natural gas prices.

    Liquidity and Capital Resources

    In the third quarter of 2006 the Company increased its syndicated credit
facilities to $205 million. The repayment terms of the revolving term credit
facility were amended such that in the event that the term date is not
extended, the balance under the facility would be repayable 365 days after the
term date. As a result of the amendment, the balance outstanding under the
facility has been reclassified as long-term in the consolidated balance sheet.
The next term date is May 29, 2007.
    At December 31, 2006, the Company had a revolving term credit facility of
$205 million and a demand operating credit facility of $20 million with
$138.9 million drawn against these facilities, thereby providing remaining
credit capacity of $86.1 million. At December 31, 2006, the Company had a
working capital deficiency of $30.7 million and net debt of $169.6 million.
The ratio of December 31, 2006 net debt to 2006 cash flow was 1.33 times.

    
    -------------------------------------------------------------------------
    As at                                          December 31,  December 31,
                                                          2006          2005
    -------------------------------------------------------------------------
    ($000s)

    Capitalization
    Bank debt                                          138,890       104,707
    Working capital deficiency(1)                       30,680         4,892
    -------------------------------------------------------------------------
    Net debt                                           169,570       109,599
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Shares outstanding (No.)                            67,648        44,250
    Market price at end of period ($)                    15.70         20.70
    Market capitalization                            1,062,074       915,975
    -------------------------------------------------------------------------
    Total capitalization                             1,231,644     1,025,574
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net debt as a  percent of total capitalization         14%           11%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Cash flow                                          127,072        74,550
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net debt to cash flow ratio                           1.33          1.47
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Working capital excludes unrealized financial instruments.
    

    Highpine's 2007 capital budget of $200 million is expected to be funded
from the Company's existing credit facilities and cash flow from operations.
    At March 12, 2007, the Company's bank debt was approximately
$142 million.

    Capital Expenditures

    Capital expenditures, excluding corporate acquisitions and property
dispositions, totaled $194.8 million for the twelve months ended December 31,
2006 compared to $149.9 million for 2005.
    Highpine acquired White Fire in February 2006 for total consideration of
$114.3 million. The Company acquired Kick in August 2006 for total
consideration of $326.6 million. Both White Fire and Kick had operations
focused in Highpine's Pembina Nisku fairway.
    Highpine also completed property acquisitions totaling $27.5 million in
2006. The property acquisitions were in Pembina, Brazeau River and Ante Creek.
    Highpine drilled 74 gross (46.7 net) wells in 2006.

    
    -------------------------------------------------------------------------
                                             Twelve months ended December 31,
                                                      2006     2005 % Change
    -------------------------------------------------------------------------
    ($000s)

    Land                                            17,392   42,346      (59)
    Geologic and geophysical                        10,431   14,064      (26)
    Drilling and completions                       110,665   53,233      108
    Facilities and equipment                        52,649   36,441       44
    Capitalized general and administrative           3,258    1,202      171
    Office and other                                   358    2,610      (86)
    -------------------------------------------------------------------------
    Total capital expenditures                     194,753  149,896       30
    -------------------------------------------------------------------------
    Property acquisitions                           27,461    4,119      567
    -------------------------------------------------------------------------
    Property dispositions                                -     (409)       -
    -------------------------------------------------------------------------
    Corporate acquisitions(1)                      440,895  399,415       10
    -------------------------------------------------------------------------
    Total capital expenditures and acquisitions    663,109  553,021       20
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Represents total consideration for the transactions, including fees,
        but is prior to the related future income tax liability and asset
        retirement obligation.
    

    Shareholders' Equity

    On August 1, 2006, the Company issued 14.8 million Common Shares to
acquire all of the issued and outstanding shares of Kick for $283.3 million.
    On February 21, 2006, the Company issued 4.1 million Common Shares to
acquire all of the issued and outstanding shares of White Fire for
$95.5 million.
    On February 22, 2006, Highpine issued 4.3 million Common Shares at a
price of $23.40 per share for gross proceeds totaling $100.6 million. Costs
associated with the issuance of the Common Shares totaled $4.3 million
resulting in net proceeds of $96.3 million.

    Outstanding Common Shares

    As at March 12, 2007, the Company had 67.7 million Common Shares
outstanding and had granted options pursuant to its stock option plan to
optionees to acquire a further 4.5 million Common Shares with an average
exercise price of $15.31 per share.

    FOURTH QUARTER REVIEW

    Highpine increased its average production to 13,690 boe/d in the fourth
quarter of 2006 compared to 8,549 boe/d in the fourth quarter of 2005. The
increase in production is attributable to the White Fire and Kick acquisitions
as well as the Company's drilling programs.
    Highpine incurred $72.8 million of capital expenditures in the fourth
quarter of 2006 compared to $50.8 million in the fourth quarter of 2005.
Capital expenditures were focused on the Company's drilling programs and tie-
ins of wells.
    Highpine's cash flow per diluted share decreased 29 percent in the
quarter as a result of realizing significantly lower commodity prices as well
as incurring higher operating costs. Highpine incurred a net loss of
$5.4 million in the fourth quarter of 2006 primarily as a result of higher
DD&A expense.

    Future Accounting Change

    Financial Instruments

    The Canadian Institute of Chartered Accountants (CICA) has issued new
accounting standards, CICA Handbook section 3855, "Financial Instruments
Recognition and Measurement," CICA Handbook section 1530 "Comprehensive
Income," and CICA Handbook section 3865 "Hedges." The standards deal with the
recognition and measurement of financial instruments and comprehensive income.
The new standards are effective for fiscal years beginning on or after
October 1, 2006. The Company is currently assessing the impact of these
standards on its financial statements.

    Critical Accounting Estimates

    The preparation of the Company's 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.

    Depletion, Depreciation and Accretion

    Highpine follows CICA accounting guideline AcG-16 on full cost accounting
in the oil and natural gas industry to account for oil and natural gas
properties. Under this method, all costs associated with the acquisition of,
exploration for, and the development of crude oil and natural gas reserves are
capitalized and costs associated with production are expensed. The capitalized
costs are depleted using the unit-of-production method based on estimated
proved reserves using management's best estimate of future prices. Reserves
estimates can have a significant impact on earnings, as they are a key
component in the calculation of depletion.

    Asset Impairment

    Producing properties and unproved properties are assessed for impairment
annually, or as economic events dictate. The cash flows used in the impairment
assessment require management to make estimates and assumptions as to
recoverable reserves, future commodity prices and operating costs. Changes in
any of the estimates or assumptions could result in an impairment of the
carrying value of producing properties and unproved properties.

    Asset Retirement Obligations

    Asset retirement obligations require that management make estimates and
assumptions regarding future liabilities and cash flows involving
environmental reclamation and remediation. Estimates of future liabilities and
cash flows are subject to uncertainty associated with the method of
reclamation and remediation, environmental legislation, the timing of
reclamation and remediation activities and the cost of reclamation and
remediation activities.

    Purchase Price Allocation

    Business acquisitions are accounted for by the purchase method of
accounting. Under this method, the purchase price is allocated to the assets
acquired and the liabilities assumed based on the fair value at the time of
acquisition. The excess purchase price over the fair value of identifiable
assets and liabilities acquired is goodwill. The determination of fair value
often requires management to make assumptions and estimates about future
events. The assumptions and estimates with respect to determining the fair
value of property, plant and equipment acquired generally require the most
judgment and include estimates of reserves acquired, future commodity prices
and discount rates. Future net earnings can be affected as a result of changes
in future depletion and depreciation, asset impairment or goodwill impairment.

    Goodwill Impairment

    Goodwill is subject to impairment tests annually, or as economic events
dictate, by comparing the fair value of the reporting entity to its carrying
value, including goodwill. If the fair value of the reporting entity is less
than its carrying value, a goodwill impairment loss is recognized as the
excess of the carrying value of the goodwill over the implied value of the
goodwill. The determination of fair value requires management to make
assumptions and estimates about recoverable reserves, future commodity prices,
operating costs, production profiles and discount rates. Changes in any of
these assumptions, such as a downward revision in reserves, a decrease in
future commodity prices, an increase in operating costs or an increase in
discount rates could result in an impairment of all or a portion of the
goodwill carrying values in future periods.

    Accounting for Stock Options

    The Company recognizes compensation expense on options granted pursuant
to its stock option plan. Compensation expense is based on the theoretical
fair value of each option at its grant date, the estimation of which requires
management to make assumptions about the future volatility of the Company's
stock price, future interest rates and the timing of optionee's decisions to
exercise the options. The effects of a change in one or more of these
variables could result in a materially different fair value.

    Disclosure Controls

    Disclosure controls and procedures have been designed to ensure that
information required to be disclosed by the Company is accumulated and
communicated to the Company's management as appropriate to allow timely
decisions regarding required disclosure. The Company's Chief Executive Officer
and Chief Financial Officer have concluded, based on their evaluation that the
Company's disclosure controls and procedures were operating effectively during
2006 to provide reasonable assurance that material information related to the
Company, including its consolidated subsidiaries, is made known to them by
others within those entities.

    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.
During 2006, the Company engaged external consultants to assist in documenting
and assessing the Company's design of internal control over financial
reporting. No material changes were identified in Company's internal control
of financial reporting during the three months ended December 31, 2006, that
had materially affected, or are reasonably likely to materially affect, the
Company's internal control of financial reporting.
    It should be noted that a control system, including the Company's
disclosure and internal controls and procedures, no matter how well conceived
can provide only reasonable, but not absolute, assurance that the objectives
of the control system will be met and it should not be expected that the
disclosure and internal controls and procedures will prevent all errors or
fraud.

    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:

    
    -   Uncertainty associated with obtaining drilling licenses 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
    Cash flow from operations                  127,072     74,550     19,773
      Per share - basic                           2.20       2.13       1.18
      Per share - diluted                         2.17       2.09       1.16
    Corporate acquisitions                     379,840    257,314     51,151
    Capital expenditures(2)                    222,214    153,606     61,133
    Long-term debt                             138,890          -          -
    Total assets                             1,392,911    753,690    163,388
    -------------------------------------------------------------------------
    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
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Notes:
    (1) Total revenue is after realized and unrealized hedging losses and
        gains.
    (2) Capital expenditures are net of property dispositions.



    Summary of Quarterly Results
    -------------------------------------------------------------------------
                                                        2006
                                         Q4         Q3         Q2         Q1
    -------------------------------------------------------------------------
    Financial
    ($000s, except per
     share amounts)

    Total revenue(1)                 67,552     60,205     62,765     64,416
    Net earnings (loss)              (5,446)       514     10,594      1,291
      Per share - basic               (0.08)      0.01       0.20       0.03
      Per share - diluted             (0.08)      0.01       0.20       0.03
    Cash flow from operations        29,657     31,165     34,704     31,546
      Per share - basic                0.44       0.50       0.66       0.66
      Per share - diluted              0.44       0.49       0.65       0.65
    Corporate acquisitions                -    289,694          -     89,651
    Capital expenditures(2)          72,711     56,144     46,590     46,769
    Long-term debt                  138,890    113,287          -          -
    Total assets                  1,392,911  1,361,249    920,941    910,157
    -------------------------------------------------------------------------
    Operating
    Average daily production
      Oil and NGLs (bbls/d)           8,653      6,675      6,940      7,950
      Natural Gas (mcf/d)            30,221     24,837     25,562     20,681
      Total (boe/d)                  13,690     10,814     11,201     11,397
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


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

    Total revenue(1)                 54,229     51,495     21,817     14,093
    Net earnings (loss)               4,855      6,683        (32)       768
      Per share - basic                0.11       0.15      (0.00)      0.04
      Per share - diluted              0.11       0.15      (0.00)      0.04
    Cash flow from operations        27,957     29,796      9,856      6,941
      Per share - basic                0.63       0.67       0.31       0.32
      Per share - diluted              0.62       0.65       0.31       0.32
    Corporate acquisitions                -          -    257,314          -
    Capital expenditures(2)          50,861     48,149     19,839     34,757
    Long-term debt                        -          -          -          -
    Total assets                    753,690    715,360    677,834    198,599
    -------------------------------------------------------------------------
    Operating
    Average daily production
      Oil and NGLs (bbls/d)           5,881      5,562      2,617      1,816
      Natural Gas (mcf/d)            16,006     18,277     11,593      9,293
      Total (boe/d)                   8,549      8,608      4,549      3,365
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Notes:
    (1) Total revenue is after realized and unrealized hedging losses and
        gains.
    (2) Capital expenditures are net of property dispositions.



    CONSOLIDATED BALANCE SHEETS

    -------------------------------------------------------------------------
    As at December 31                                     2006          2005
    -------------------------------------------------------------------------
    ($000s) (unaudited)

    Assets
    Current assets
      Accounts receivable                               54,944        40,716
      Prepaid expenses and deposits                      2,928         1,795
      Financial instruments (note 10)                    3,194           763
    -------------------------------------------------------------------------
                                                        61,066        43,274
    Property, plant and equipment (note 4)             972,599       493,330
    Long-term investment, at cost (note 5)               1,150         1,000
    Deferred charges                                         -           251
    Goodwill (note 3)                                  358,096       215,835
    -------------------------------------------------------------------------
                                                     1,392,911       753,690
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Liabilities and Shareholders' Equity
    Current liabilities
      Accounts payable and accrued liabilities          88,552        47,403
      Bank indebtedness                                      -       104,707
    -------------------------------------------------------------------------
                                                        88,552       152,110
    Long-term debt (note 6)                            138,890             -
    Future income taxes (note 11)                      151,802        84,167
    Asset retirement obligations (note 7)               11,258         5,898
    Deferred lease inducements                             408           492

    Shareholders' equity
      Share capital (note 8)                           957,186       479,496
      Contributed surplus (note 8)                       9,962         3,627
      Retained earnings                                 34,853        27,900
    -------------------------------------------------------------------------
                                                     1,002,001       511,023
    Commitments (note 9)
    -------------------------------------------------------------------------
                                                     1,392,911       753,690
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to the consolidated financial statements.



    CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS

    -------------------------------------------------------------------------
                                    Three months ended   Twelve months ended
                                           December 31,          December 31,
                                       2006       2005       2006       2005
    -------------------------------------------------------------------------
    ($000s, except per share amounts)
    (unaudited)

    Revenues
      Oil and natural gas revenues   66,601     55,097    247,804    147,303
      Royalties, net of ARTC        (18,635)   (16,352)   (70,529)   (38,995)
      Financial instruments
        Realized gains (losses)         727     (1,823)     4,703     (6,613)
        Unrealized gains                224        955      2,431        944
    -------------------------------------------------------------------------
                                     48,917     37,877    184,409    102,639
    Interest and other income            27          1         85          7
    -------------------------------------------------------------------------
                                     48,944     37,878    184,494    102,646
    Expenses
      Operating costs                13,124      4,827     36,839     14,575
      Transportation costs              778        947      3,069      2,439
      General and administrative      3,209      1,820      9,682      5,777
      Depletion, depreciation
       and accretion                 36,902     19,290    125,306     53,893
      Interest and finance costs      1,615      1,192      5,076      3,631
      Stock-based compensation
       (note 8)                       1,333      1,299      5,677      3,151
    -------------------------------------------------------------------------
                                     56,961     29,375    185,649     83,466
    -------------------------------------------------------------------------
    Earnings (loss) before taxes     (8,017)     8,503     (1,155)    19,180
    -------------------------------------------------------------------------
    Taxes (reduction)
      Current                             -        173       (127)       723
      Future (note 11)               (2,571)     3,475     (7,981)     6,183
    -------------------------------------------------------------------------
                                     (2,571)     3,648     (8,108)     6,906
    -------------------------------------------------------------------------
    Net earnings (loss)              (5,446)     4,855      6,953     12,274
    Retained earnings, beginning
     of period                       40,299     23,045     27,900     23,992
    Stock dividend and adjustment
     (note 8)                             -          -          -     (8,366)
    -------------------------------------------------------------------------
    Retained earnings, end
     of period                       34,853     27,900     34,853     27,900
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net earnings (loss) per
     share (note 8)
      Basic                        $  (0.08)  $   0.11   $   0.12   $   0.35
      Diluted                      $  (0.08)  $   0.11   $   0.12   $   0.34
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to the consolidated financial statements.



    CONSOLIDATED STATEMENTS OF CASH FLOWS

    -------------------------------------------------------------------------
                                    Three months ended   Twelve months ended
                                           December 31,          December 31,
                                       2006       2005       2006       2005
    -------------------------------------------------------------------------
    ($000s) (unaudited)

    Cash provided by (used in):
    Operating Activities
      Net earnings (loss)            (5,446)     4,855      6,953     12,274
      Items not involving cash:
        Depletion, depreciation
         and accretion               36,902     19,290    125,306     53,893
        Future income taxes
         (reduction)                 (2,571)     3,475     (7,981)     6,183
        Stock-based compensation      1,333      1,299      5,677      3,151
        Unrealized (gains) on
         financial instruments         (224)      (955)    (2,431)      (944)
        Abandonment expenditures       (316)         -       (368)         -
        Amortization of deferred
         lease inducements              (21)        (7)       (84)        (7)
    -------------------------------------------------------------------------
                                     29,657     27,957    127,072     74,550
      Change in non-cash
       operating working capital      9,452     11,488    (18,018)   (18,017)
    -------------------------------------------------------------------------
                                     39,109     39,445    109,054     56,533
    -------------------------------------------------------------------------
    Financing Activities
      Common shares issued for cash       -          -    100,620     72,000
      Share issue costs                   -          -     (4,606)    (4,811)
      Proceeds on exercise of
       stock options                     52         72      1,202        176
      Increase in bank debt          25,603     15,039      4,618     32,857
    -------------------------------------------------------------------------
                                     25,655     15,111    101,834    100,222
    -------------------------------------------------------------------------
    Investing Activities
      Property, plant and
       equipment additions          (72,806)   (46,669)  (194,753)  (149,896)
      Property acquisitions              95     (4,119)   (27,461)    (4,119)
      Purchase of investments             -          -       (150)         -
      Net cash paid on business
       combination (note 3)               -          -     (1,091)      (429)
      Proceeds on the disposition
       of property, plant and
       equipment                          -        (73)         -        409
      Deferred lease inducements          -        581          -        581
      Deferred charges                    -       (251)       251       (251)
      Change in non-cash investing
       working capital                7,947     (4,025)    12,316     (3,050)
    -------------------------------------------------------------------------
                                    (64,764)   (54,556)  (210,888)  (156,755)
    -------------------------------------------------------------------------
    Change in cash                        -          -          -          -
    Cash, beginning of period             -          -          -          -
    -------------------------------------------------------------------------
    Cash, end of period                   -          -          -          -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Cash interest paid                1,429      1,124      4,865      3,070
    Cash taxes paid                       -        138        263        494
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to the consolidated financial statements.



    NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

    Twelve months ended December 31, 2006 and 2005
    (unaudited) (tabular amounts in thousands of dollars, unless otherwise
    noted)

    1.  Description of Business

        Highpine Oil & Gas Limited (the "Company") was incorporated under the
        laws of the Province of Alberta on April 2, 1998. The Company is
        engaged in the exploration for, and the development and production of
        crude oil, natural gas and natural gas liquids in Western Canada.

    2.  Significant Accounting Policies

        a) Principles of consolidation

           These consolidated financial statements include the accounts of
           the Company and its subsidiaries.

        b) Property, plant and equipment

           The Company follows the full cost method of accounting for
           exploration and development expenditures wherein all costs related
           to the exploration for and the development of oil and natural gas
           reserves are capitalized and accumulated in one cost centre. These
           costs include lease acquisition costs, geological and geophysical
           expenses, carrying charges of unproved properties, costs of
           drilling and completing wells and oil and natural gas production
           equipment.

           Proceeds received from the disposal of properties are normally
           credited against accumulated costs unless this would result in a
           significant change in the depletion rate of more than 20 percent,
           in which case a gain or loss is computed and reflected in the
           consolidated statement of earnings.

           Depletion, depreciation and amortization

           Depletion of exploration and development costs and depreciation of
           production equipment are provided on the unit-of-production method
           based upon estimated proved oil and natural gas reserves before
           royalties in each cost centre as determined by independent
           engineers. For purposes of this calculation, reserves and
           production of natural gas are converted to common units based on
           their approximate relative energy content. The cost of acquiring
           and evaluating unproved properties is initially excluded from the
           depletion calculation. These properties are assessed periodically
           for impairment. When proved reserves are assigned or the property
           is considered to be impaired, the cost of the property or the
           amount of the impairment is added to the costs subject to
           depletion.

           Office furniture, equipment and computers are depreciated on a
           declining balance basis at 20 percent per year. Leasehold
           improvements are amortized on a straight line basis over the lease
           term. Buildings are amortized on a straight line basis over 20
           years. Land is not depreciated.

           Ceiling test

           The Company places a limit on the carrying value of property,
           plant and equipment which may be depleted against revenues of
           future periods (the "ceiling test"). The ceiling test is an
           impairment test whereby the carrying amount of property, plant and
           equipment is compared to the sum of the undiscounted cash flows
           expected from the production of proved reserves and the lower of
           cost and market of unproved properties. If the carrying amount
           exceeds the undiscounted cash flows, an impairment loss would be
           determined by comparing the carrying amount to the sum of the net
           present value of future pre-tax cash flows from proved plus
           probable reserves and the lower of cost or market value of the
           Company's unproved properties. The impairment loss would be
           recorded in earnings.


        c) Asset retirement obligations

           The Company recognizes the fair value of an Asset Retirement
           Obligation (ARO) in the period in which it is incurred. The fair
           value of the estimated ARO is recorded as a liability on a
           discounted basis, with a corresponding increase in the carrying
           amount of the related asset. The capitalized amount is depleted
           using the unit-of-production method based on proved reserves. The
           liability amount is increased each reporting period due to the
           passage of time and the amount of accretion is expensed to
           earnings in the period. Actual costs incurred upon the settlement
           of the ARO are charged against the ARO.

        d) Goodwill

           The Company records goodwill when the purchase price of an
           acquired business exceeds the sum of the amounts allocated to the
           assets acquired, less liabilities assumed, based on their fair
           values. Goodwill is not amortized and is tested for impairment
           annually or more frequently if events or changes in circumstances
           indicate that the asset 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 fair value
           of the segment exceeds its carrying amount, goodwill is considered
           not to be impaired and the second step of the impairment test is
           unnecessary. The second step is carried out when the carrying
           amount of the Company's goodwill exceeds its fair value, in which
           case the implied fair value of the Company's goodwill is compared
           with its carrying amount to measure the amount of the impairment
           loss, if any. 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.

        e) Revenue recognition

           Revenues from the sale of crude oil, natural gas and natural gas
           liquids are recorded when title passes to the customer.

        f) Long-term investment

           The Company's long-term investment is accounted for by the cost
           method (see note 5). The net income of this company is reflected
           in the determination of the net earnings of the Company only to
           the extent of dividends received.

           The carrying value of the Company's long-term investment is
           periodically reviewed by management to determine if the facts and
           circumstances suggest that the investment may be impaired. Any
           impairment identified through this assessment would result in a
           write-down of the investment and a corresponding charge to
           earnings.

        g) Financial instruments

           The Company may enter into derivative instrument contracts to
           manage its commodity price exposure. The Company does not enter
           into derivative instrument contracts for trading or speculative
           purposes. When the Company enters into a hedge, it formally
           assesses both at the hedge's inception and on an ongoing basis
           whether the hedge is highly effective in offsetting charges in
           cash flows of the hedged item. Financial instruments that are
           considered highly effective are not recognized on the balance
           sheet and realized gains and losses are recognized in revenues in
           the same period in which the revenues associated with the hedged
           transactions are recorded. Financial instruments that do not
           qualify as effective hedges for accounting purposes or were not
           designated as effective hedges at inception are recorded on a
           mark-to-market basis with the resulting gains or losses taken into
           earnings.

        h) Future income taxes

           The Company follows the liability method of accounting for income
           taxes. Under this method, future income tax liabilities and future
           income tax assets are recorded based on the differences between
           the carrying amount of assets and liabilities in the consolidated
           balance sheet and their tax basis using income tax rates
           substantively enacted at the balance sheet date. The effect of a
           change in rates on future income tax liabilities and assets is
           recognized in the period in which the change occurs.

        i) Stock-based compensation plans

           The Company has a stock option plan. The Company records
           compensation expense using the fair value method. Under the fair
           value method, a compensation cost is measured at fair value at the
           grant date and expensed over the vesting period with a
           corresponding increase to contributed surplus. Upon the exercise
           of the stock options, consideration received together with the
           amount previously recorded in contributed surplus is recorded as
           an increase to share capital.

           The Company has a deferred share unit plan. The Company accrues a
           liability equal to the closing price of the Company's class A
           common shares ("Common Shares") for each unit issued under the
           plan.

        j) Flow-through shares

           The tax attributes of expenditures financed by the issuance of
           flow-through shares are renounced to investors in accordance with
           income tax legislation. A future tax liability is recognized upon
           the renunciation of tax pools and share capital is reduced by a
           corresponding amount.

        k) Cash equivalents

           The Company considers all highly liquid investments with a
           maturity of three months or less at the time of purchase to be
           cash equivalents and therefore classifies them with cash.

        l) Earnings per share

           Basic earnings per Common Share are computed by dividing earnings
           by the weighted average number of Common Shares outstanding for
           the period. Diluted per share amounts reflect the potential
           dilution that could occur if securities or other contracts to
           issue Common Shares were exercised or converted to Common Shares.
           The treasury stock method is used to determine the dilutive effect
           of stock options and other dilutive instruments. The treasury
           stock method assumes that proceeds received from the exercise of
           in-the-money stock options are used to repurchase Common Shares at
           the average market price for the reporting period.

        m) Joint interests

           Substantially all of the Company's exploration and development
           activities are conducted jointly with others. Accordingly, the
           financial statements reflect only the Company's proportionate
           interest in such activities.

        n) Measurement uncertainty

           The amounts recorded for the depletion and depreciation of oil and
           natural gas properties and for the determination of asset
           retirement obligations are based on estimates. The ceiling test
           calculation and the goodwill impairment test are based on
           estimates of proved reserves, production rates, oil and natural
           gas prices, future costs and other relevant assumptions. By their
           nature, these estimates are subject to measurement uncertainty and
           the effects of changes in such estimates in future years on
           financial statements could be significant.

        o) Deferred lease inducements

           Deferred lease inducements are accounted for as a reduction of
           rent expense over the term of the lease.

    3.  Acquisitions

        On August 1, 2006, Highpine acquired Kick Energy Corporation ("Kick")
        for consideration of 14.8 million Common Shares at $283.3 million.
        Kick was a publicly traded oil and natural gas exploration and
        production company active in the Western Canada Sedimentary Basin.
        The transaction has been accounted for using the purchase method with
        the allocation of the purchase price as follows:

        ---------------------------------------------------------------------
        Net assets acquired and liabilities assumed
          Property, plant and equipment (including unproved
           properties totaling $27,092 and seismic
           totaling $5,477)                                      $   289,694
          Goodwill                                                   106,215
          Working capital (deficiency)                               (17,680)
          Bank indebtedness                                          (25,095)
          Asset retirement obligations                                (2,835)
          Future income taxes                                        (66,466)
        ---------------------------------------------------------------------
                                                                 $   283,833
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Consideration
          Acquisition costs                                      $       564
          Class A common shares issued                               283,269
        ---------------------------------------------------------------------
                                                                 $   283,833
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        On February 21, 2006, Highpine acquired White Fire Energy Ltd.
        ("White Fire") for consideration of 4.1 million Common Shares at
        $95.5 million. White Fire was a publicly traded oil and natural gas
        exploration and production company active in the Western Canada
        Sedimentary Basin. The transaction has been accounted for using the
        purchase method with the allocation of the purchase price as follows:

        ---------------------------------------------------------------------
        Net assets acquired and liabilities assumed
          Property, plant and equipment (including unproved
           properties totaling $25,800)                          $    89,651
          Goodwill                                                    36,046
          Working capital (deficiency)                               (13,810)
          Bank indebtedness                                           (4,470)
          Asset retirement obligations                                (1,145)
          Future income taxes                                        (10,265)
        ---------------------------------------------------------------------
                                                                 $    96,007
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Consideration
          Acquisition costs                                      $       527
          Class A common shares issued                                95,480
        ---------------------------------------------------------------------
                                                                 $    96,007
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        On May 31, 2005, the Company acquired Vaquero Energy Ltd. ("Vaquero")
        for consideration of 19.5 million Common Shares at $350.9 million.
        Vaquero was a publicly traded oil and natural gas exploration and
        production company active in the Western Canada sedimentary basin.
        The transaction has been accounted for using the purchase method with
        the allocation of the purchase price as follows:

              ---------------------------------------------------------------
              Net assets acquired and liabilities assumed

                Property, plant and equipment (including unproved
                 properties totalling $78,657)                   $   257,314
                Goodwill                                             201,754
                Working capital (deficiency)                         (11,062)
                Bank indebtedness                                    (37,028)
                Asset retirement obligations                          (1,903)
                Financial instruments                                   (181)
                Future income taxes                                  (57,569)
              ---------------------------------------------------------------
                                                                 $   351,325
              ---------------------------------------------------------------

              Consideration

                Acquisition costs                                $       429
                Class A common shares issued                         350,896
              ---------------------------------------------------------------
                                                                 $   351,325
              ---------------------------------------------------------------
              ---------------------------------------------------------------

    4.  Property, Plant and Equipment
        ---------------------------------------------------------------------
                                                   Accumulated
                                                 depletion and      Net book
        2006                                Cost  depreciation         value
        ---------------------------------------------------------------------

        Petroleum and natural gas
         properties                  $ 1,169,995   $   200,211   $   969,784
        Land, buildings and leaseholds     2,389           219         2,170
        Office equipment and computers     1,002           357           645
        ---------------------------------------------------------------------
                                     $ 1,173,386   $   200,787   $   972,599
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        2005

        Petroleum and natural gas
         properties                  $   566,538   $    75,869   $   490,669
        Land, buildings and leaseholds     2,358            41         2,317
        Office equipment and computers       594           250           344
        ---------------------------------------------------------------------
                                     $   569,490   $    76,160   $   493,330
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        At December 31, 2006, approximately $152.2 million (December 31,
        2005 - $112.4 million) of unproved property costs and unevaluated
        seismic costs were excluded from the depletion calculation. Future
        development costs of $56.4 million (December 31, 2005 -
        $13.3 million) were included in the depletion calculation. Salvage
        value of $23.9 million (December 31, 2005 - $nil) was excluded from
        the depletion calculation. During the twelve months ended
        December 31, 2006, general and administrative expenses of
        $4.1 million (December 31, 2005 - $1.4 million) were capitalized,
        including stock-based compensation of $0.9 million.

        The Company performed a ceiling test at December 31, 2006 to assess
        the recoverable value of property, plant and equipment and other
        assets. The future oil and natural gas future prices are based on the
        commodity price forecast of the Company's independent reserve
        evaluators.

        The following table summarizes the benchmark prices used in the
        ceiling test calculation. The Canadian dollar prices have been
        adjusted for commodity quality differentials specific to the Company.

        ---------------------------------------------------------------------
                                     Oil  Natural Gas  Condensate       NGLs
                                  ($/bbl)     ($/mcf)     ($/bbl)     ($/bbl)
        ---------------------------------------------------------------------
        2007                     $ 63.88     $  7.77     $ 61.76     $ 47.85
        2008                       62.84        8.41       60.69       46.97
        2009                       62.76        8.37       60.65       46.94
        2010                       60.50        8.34       58.55       45.30
        2011                       58.12        8.49       56.48       43.68
        2012 and thereafter        61.70        9.23       61.13       47.68

        Prices after 2011 escalate at approximately 1% to 2% per annum
        ---------------------------------------------------------------------

    5.  Long-Term Investment

        At December 31, 2006 the Company's long-term investment of
        $1.2 million was comprised of 1,080,000 common shares of In Depth
        Resources Ltd., a privately held oil and natural gas company in which
        the Chairman of the Company is a director. The investment represents
        approximately 10 percent of the outstanding common shares of In Depth
        Resources Ltd. The Company has a right of first refusal to
        participate in certain prospects generated by In Depth Resources Ltd.

    6.  Long-Term Debt

        At December 31, 2006, the Company had available a $205 million
        revolving term credit facility with a syndicate of Canadian
        financial institutions and a $20 million demand operating credit
        facility with its primary financial institution.

        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 29, 2007. In the event that the term date of
        May 29, 2007 is not extended, the balance under the facility will be
        repayable on May 28, 2008. 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 $5.0 million (2005 - $3.6 million) in
        respect of debt initially incurred for a period exceeding one year.

    7.  Asset Retirement Obligations

        At December 31, 2006, the estimated total undiscounted cash flows
        required to settle asset retirement obligations were $17.9 million
        (December 31, 2005 - $10.0 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:

        ---------------------------------------------------------------------
                                                        Twelve        Twelve
                                                  months ended  months ended
                                                   December 31,  December 31,
                                                          2006          2005
        ---------------------------------------------------------------------
        Asset retirement obligations,
         beginning of period                             5,898         1,974
          Liabilities acquired                           3,980         1,903
          Liabilities incurred                           1,069         1,694
          Liabilities settled                             (368)            -
          Accretion expense                                679           327
        ---------------------------------------------------------------------
        Asset retirement obligations,
         end of period                                  11,258         5,898
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    8.  Share Capital

        (a) 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.

                                 Twelve months ended     Twelve months ended
                                  December 31, 2006       December 31, 2005
                                  Shares      Amount      Shares      Amount
    -------------------------------------------------------------------------
                                  (thou-     ($thou-      (thou-     ($thou-
                                   sands)      sands)      sands)      sands)

    Class A common shares
    Balance, beginning of period  44,250     479,496      15,208      24,247
      Issued to acquire
       Vaquero (note 3)                -           -      19,494     350,896
      Issued to acquire White
       Fire (note 3)               4,089      95,480           -           -
      Issued to acquire Kick
       (note 3)                   14,831     283,269           -           -
      Issued for cash              4,300     100,620       4,000      72,000
      Conversion of Class B
       shares                          -           -       1,271           1
      Special warrants
       exercised                       -           -       3,300      28,582
      Stock dividend and
       adjustment                      -           -         930       8,366
      Flow-through shares
       renounced                       -           -           -      (1,613)
      Stock options exercised        178       1,202          47         176
      Contributed surplus
       transferred on exercise
       of stock options                -         225           -          35
      Share issue costs less tax
       effect of (2006 - $1,500;
       2005 - $1,617)                  -      (3,106)          -      (3,194)
    -------------------------------------------------------------------------
    Balance, end of period        67,648     957,186      44,250     479,496
    -------------------------------------------------------------------------
    Class B common shares:
    Balance, beginning of period       -           -       1,271           1
      Conversion of class B
       shares                          -           -      (1,271)         (1)
    -------------------------------------------------------------------------
    Balance, end of period             -           -           -           -
    -------------------------------------------------------------------------
    Special warrants:
    Balance, beginning of period       -           -       3,300      28,582
      Exercised                        -           -      (3,300)    (28,582)
    -------------------------------------------------------------------------
    Balance, end of period             -           -           -           -
    -------------------------------------------------------------------------
    Total                                    957,186                 479,496
    -------------------------------------------------------------------------

        On August 1, 2006, the Company issued 14.8 million Common Shares to
        acquire all of the issued and outstanding shares of Kick for
        $283.3 million.

        On February 21, 2006, the Company issued 4.1 million Common Shares to
        acquire all of the issued and outstanding shares of White Fire for
        $95.5 million.

        On February 22, 2006, the Company issued 4.3 million Common Shares at
        a price of $23.40 per share for gross proceeds totalling
        $100.6 million. Costs associated with the issuance of the Common
        Shares totalled $4.3 million resulting in net proceeds of
        $96.3 million.

        On May 31, 2005, the Company issued 19.5 million Common Shares to
        acquire all of the issued and outstanding shares of Vaquero.

        On April 5, 2005, 4.0 million Common Shares of the Company were
        issued pursuant to the Company's initial public offering. Costs
        associated with the initial public offering totalled approximately
        $4.8 million.

        On March 31, 2005, 3.5 million Common Shares of the Company were
        issued upon the exercise of the special warrants.

        On February 15, 2005, the Company declared a stock dividend in the
        amount of $7.0 million which resulted in 0.047 of a Common Share
        being issued for each issued and outstanding Common Share. In
        accordance with the terms of the issued and outstanding special
        warrants of the Company the stock dividend resulted in an additional
        0.2 million Common Shares being issuable upon exercise of the
        outstanding special warrants.

        On February 3, 2005, the Company filed Articles of Amendment to amend
        the provisions of the series 1 class B shares and as such, the series
        1 class B shares were automatically converted into Common Shares on
        February 4, 2005.

        Per Share Amounts
        ---------------------------------------------------------------------
                                  Three months ended     Twelve months ended
                                      December 31,            December 31,
                                    2006        2005        2006        2005
                              (thousands) (thousands) (thousands) (thousands)
        ---------------------------------------------------------------------
        Weighted average number
         of Common Shares
         outstanding
          Basic                   67,643      44,239      57,744      35,051
          Dilutive effect of
           stock options               -         667         930         667
        ---------------------------------------------------------------------
        Diluted                   67,643      44,906      58,674      35,718
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Anti-dilutive options excluded from the calculation of diluted
        earnings per share were 3.2 million (2005 - 232,000).

        Stock Options

        The Company has a stock option plan pursuant to which options to
        purchase 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.

        A summary of changes is as follows:

        ---------------------------------------------------------------------
                               Twelve months ended      Twelve months ended
                                December 31, 2006        December 31, 2005
        ---------------------------------------------------------------------
                            Common Shares   Weighted  Common Shares  Weighted
                            Issuable Upon    Average  Issuable Upon   Average
                               Exercise     Exercise     Exercise    Exercise
                              of Options      Price     of Options    Price
                              (thousands)   ($/share)  (thousands)  ($/share)
        ---------------------------------------------------------------------
        Balance, beginning
         of period                 3,652       13.06       1,542        5.26
          Granted                  2,016       20.42       2,308       18.96
          Exercised                 (178)      (6.75)        (47)      (3.89)
          Cancelled                 (413)     (18.06)       (224)     (17.00)
          Stock dividend
           adjustment                  -           -          73           -
        ---------------------------------------------------------------------
        Balance, end of period     5,077       15.80       3,652       13.06
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Exercisable, end
         of period                 1,271        9.44         556        4.33
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        Details of the exercise prices and expiry dates of options
        outstanding at December 31, 2006 are as follows:

    -------------------------------------------------------------------------
                      Options Outstanding               Options Exercisable
                      -------------------               -------------------
                                Weighted    Weighted                Weighted
                      Common     Average     Average      Common     Average
    Range of          Shares    Years to    Exercise      Shares    Exercise
     Exercise       Issuable      Expiry       Price    Issuable       Price
     price        (thousands)     (years)   ($/share) (thousands)   ($/share)
    -------------------------------------------------------------------------
    $2.60 - $5.00      1,023        2.74    $   3.68         676    $   3.43
    $8.10 - $14.00       463        4.00    $  10.32         191    $   9.55
    $16.35 - $23.25    3,591        4.97    $  19.96         404    $  19.43
    -------------------------------------------------------------------------
                       5,077        4.43    $  15.80       1,271    $   9.44
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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

        ---------------------------------------------------------------------
                                                          2006          2005
        ---------------------------------------------------------------------
        Weighted average expected volatility (%)            34            45
        Risk-free rate of return (%)                       4.9           4.5
        Expected option life (years)                         4             4
        Weighted average fair value ($/share)             7.39          7.43
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

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

        Contributed Surplus
        ---------------------------------------------------------------------
                                                 Twelve months Twelve months
                                                         ended         ended
                                                   December 31,  December 31,
                                                          2006          2005
        ---------------------------------------------------------------------
        Balance, beginning of period                     3,627           511
          Stock-based compensation expense, net of
           recovery                                      5,677         3,151
          Capitalized stock-based compensation expense     883             -
          Transferred to share capital on exercise of
           stock options                                  (225)          (35)
        ---------------------------------------------------------------------
        Balance, end of period                           9,962         3,627
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Deferred Share Units Plan

        In 2006, the Company implemented a deferred share unit (DSU) plan for
        outside 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 Common Shares on the date the
        director specifies upon tendering their resignation from the Board.

        The Company has recorded $137,000 of expense in the year relating to
        DSUs and there are 8,800 DSUs outstanding at year-end.

    9.  Commitments

        The Company is committed to operating leases for office space and
        equipment annually as follows:

        ---------------------------------------------------------------------

        2007                                                        $  1,309
        2008                                                           1,247
        2009                                                           1,243
        2010                                                           1,212
        2011                                                           1,212
        Thereafter                                                     1,112
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    10. Financial Instruments

        a) Commodity Price Risk Management

           The Company uses a variety of derivative instruments to reduce its
           exposure to fluctuations in commodity prices. The derivative
           instruments have been accounted for as an asset on the
           consolidated balance sheets based on their fair value. The
           following commodity price risk management agreements were in place
           as at December 31, 2006.

    Financial WTI Crude Oil Contracts
    -------------------------------------------------------------------------
                                                                  Unrealized
                                                                  Gain (Loss)
                                                                       As at
                                                                 December 31,
                                    Volume        Fixed Price           2006
    Term               Contract    (bbls/d)         ($/bbl)       (CDN $000s)
    -------------------------------------------------------------------------
    Jan 07 to Dec 07    Collar      1,750    US $55.00 to $86.15         643
    Jan 07 to Dec 07    Collar      1,750    US $60.00 to $80.70       1,206
    Jan 07 to Dec 07      Swap        500         Cdn $73.00            (419)
    Jan 07 to Dec 07      Swap        500         Cdn $73.70            (295)
    Jan 07 to Dec 07      Swap        500         Cdn $74.70            (116)
    Jan 07 to Dec 07      Swap        500         Cdn $75.82              83
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Financial AECO Natural Gas Contracts
    -------------------------------------------------------------------------
                                                                   Unrealized
                                                                  Gain (Loss)
                                                                       As at
                                                                 December 31,
                                    Volume        Fixed Price           2006
    Term               Contract     (GJs/d)         ($/GJ)        (CDN $000s)
    -------------------------------------------------------------------------
    Jun 06 to Mar 07    Collar      5,000    Cdn $5.40 to $12.00          36
    Jul 06 to Mar 08    Collar      5,000    Cdn $6.00 to $11.10         481
    Jan 07 to Dec 07      Swap      2,500          Cdn $7.55             756
    Jan 07 to Dec 07      Swap      2,500          Cdn $7.62             819
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

        Subsequent to December 31, 2006, the Company entered into the
        following financial AECO natural gas contracts:

                                    Volume        Fixed Price
        Term           Contract     (GJs/d)          ($/GJ)
        -----------------------------------------------------
        Feb 07 to Mar 08   Swap     1,250          Cdn $7.68
        Feb 07 to Mar 08   Swap     1,250          Cdn $7.70
        -----------------------------------------------------
        -----------------------------------------------------

        b) Credit Risk

           A substantial portion of the Company's accounts receivable are
           with customers and joint venture partners in the oil and natural
           gas industry and are subject to normal industry credit risks.

        c) Fair Value

           The carrying values of the Company's financial assets and
           liabilities, with the exception of the Company's long-term
           investment (note 5), approximated their fair values as at
           December 31, 2006 and 2005. The fair value of the Company's long-
           term investment was considered undeterminable due to the inability
           to apply a valuation method or obtain market prices.

        d) Interest Rate Risk

           The Company is exposed to interest rate risk on debt instruments
           to the extent of changes in the prime rate.

        e) Foreign Currency Exchange Risk

           The Company is exposed to foreign currency fluctuations as crude
           oil and natural gas prices received are referenced to U.S. dollar-
           denominated prices.

    11. Income Taxes

        The provision for income taxes differs from the result that would be
        obtained by applying the combined Canadian federal and provincial
        income tax rate of 34.50 percent (2005 - 37.62 percent) to earnings
        (loss) before taxes. The difference results from the following:

        ---------------------------------------------------------------------
                                                            2006        2005
        ---------------------------------------------------------------------
        Statutory income tax rate                         34.50%      37.62%

        Computed expected income taxes (reduction)      $   (397)   $  7,216

        Add (deduct)
          Non-deductible Crown payments,
           net of Alberta Royalty Tax Credits                  4       5,326
        Resource allowance                                  (222)     (4,466)
        Large corporation tax                               (127)        723
        Stock based compensation                           1,958       1,185
        Effect of change in tax rate and other            (9,324)     (3,085)
        ---------------------------------------------------------------------
                                                        $ (8,108)   $  6,906
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The components of the future income tax liability at December 31,
        2006 and 2005 are as follows:

        ---------------------------------------------------------------------
                                                            2006        2005
        ---------------------------------------------------------------------

        Property, plant and equipment                   $133,018    $ 68,203
        Partnership deferral                              39,770      28,182
        Asset retirement obligations                      (3,419)     (1,983)
        Attributed royalty income deductible for
         provincial taxes                                 (3,678)     (2,074)
        Share issue costs                                 (2,710)     (2,758)
        Loss carryforward                                (12,186)     (5,700)
        Financial instruments                                970         257
        Long-term investments                                 37          40

        ---------------------------------------------------------------------
        Future income tax liability                     $151,802    $ 84,167
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The provision for future income taxes for the twelve months ended
        December 31, 2006 was reduced by $9.1 million due to the
        substantively enacted reduction in Canadian federal and Alberta
        provincial corporate income tax rates. The reduction was recorded in
        the second quarter of 2006.

    12. Comparative Balances

        Certain of the comparative balances have been reclassified to conform
        to the current period's presentation.
    

    Message from Management:
    ------------------------

    Highpine thanks its shareholders for their patience and support as it
overcomes the challenges associated with developing one of the extraordinary
plays in western Canada. The Company is well positioned to realize superior
economic growth potential from the Pembina Nisku Fairway due to the
infrastructure base and operations team which it established during 2006.
    Shareholders are invited to attend the Annual General Meeting of
Shareholders on Wednesday, May 9, 2007 in the Grand Lecture Theatre of the
Metropolitan Centre, 333 - 4th Avenue S.W., Calgary, Alberta, commencing at
10:00 a.m. (MDT).

    READER ADVISORY

    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 aggregate of the
exploration and development costs incurred in the Company's financial year
ended December 31, 2006 and the change during that year in estimated future
development costs generally will not reflect total finding and development
costs related to reserve additions for that year.
    Statements in this news release contain forward-looking information
including expectations of future production, 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 information 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 risks
associated with the oil and 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 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 this forward-looking information. The
Company undertakes no obligation to update or revise any forward-looking
statements except as required by applicable securities laws.
    Readers are further cautioned that the preparation of financial
statements in accordance with Canadian generally accepted accounting
principles ("GAAP") requires management to make certain judgments and
estimates that affect the reported amounts of assets, liabilities, revenues
and expenses. Estimating reserves is also critical to several accounting
estimates and requires judgments and decisions based upon available
geological, geophysical, engineering and economic data. These estimates may
change, having either a negative or positive effect on net earnings as further
information becomes available, and as the economic environment changes.
    The terms Cash flow from operations "cash flow", and "cash flow per
share" and "operating netbacks" are not recognized measures under GAAP.
Management believes that in addition to net earnings, cash flow is a useful
supplemental measure as it provides an indication of the results generated by
Highpine's principal business activities before the consideration of how these
activities are financed or how the results are taxed. Investors are cautioned,
however, that this measure should not be construed as an alternative to net
earnings determined in accordance with GAAP as an indication of Highpine's
performance. Highpine's method of calculating cash 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 cash from
operations as cash from operating activities before the change in non-cash
working capital related to operating activities. Highpine also uses operating
netback as an indicator of operating performance. Operating netback is
calculated on a per boe (as defined below) basis taking the sales price and
deducting royalties, operating costs, transportation costs and realized
hedging gains and losses.

    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 Pembina Nisku and West Central Alberta
Gas Fairways, both located in Central Alberta. The Company's class "A" common
shares trade on the Toronto Stock Exchange under the symbol "HPX".

    The Toronto Stock Exchange has neither approved nor disapproved the
    information contained herein.




For further information:

For further information: Greg Baum, President and Chief Operating
Officer; Bob Rosine, Executive Vice President, Corporate Development; Harry
Cupric, Vice President, Finance and Chief Financial Officer, Telephone: (403)
265-3333, Facsimile: (403) 265-3362; Media Contact: Shauna MacDonald, (403)
538-5645

Organization Profile

Highpine Oil & Gas Limited

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