Highpine Oil & Gas Limited announces record financial and operational results for the fourth quarter and year-end 2007



    CALGARY, March 11 /CNW/ - Highpine Oil & Gas Limited (TSX: HPX)
("Highpine" or the "Company") announces its record financial and operational
results for the fourth quarter and year ended December 31, 2007.

    
    2007 HIGHLIGHTS AND RESULTS

    -   Production averaged 17,736 boe/d in 2007, up 51% from 11,779 boe/d in
        2006. In the fourth quarter of 2007 average production of
        19,716 boe/d represented a 44% increase over the 13,690 boe/d
        recorded in the same period in 2006. The 2007 production mix
        consisted of 64% liquids and 36% natural gas. Both the average annual
        and the fourth quarter volumes for 2007 represent production records
        for Highpine.

    -   Liquids prices realized in 2007 increased 9.5% to $72.50/boe compared
        to $66.19/boe for the 2006 year. Average natural gas price
        realization for the year increased 4.7% to $7.39/mcf compared to
        $7.06/mcf for 2006. For 2008, no oil hedges are in place with
        7,500 GJ/d of gas hedged to October 31, 2008, at an average $8.01/GJ
        through the summer months.

    -   Production increases and improved price realizations contributed to
        strong revenue growth in 2007. Oil and natural gas revenues before
        hedging activities increased 63% for the 2007 year to $403.6 million
        from $247.8 million in 2006, fourth quarter revenues in 2007 improved
        89% to $125.6 million from $66.6 million in 2006. For the 2007 year,
        cash from operations of $193.8 million ($2.83 per diluted share)
        represented a 52% increase from the $127.4 million ($2.17 per diluted
        share) recorded in 2006. In the fourth quarter of 2007 cash from
        operations increased 95% to $58.4 million ($0.85 per diluted share)
        from $30.0 million ($0.44 per diluted share) in the fourth quarter of
        2006.

    -   Operating costs in 2007 averaged $10.34/boe compared to $8.57/boe in
        2006. Despite higher volumes, increases in processing costs, workover
        expenses, as well as costs associated with turnarounds at several
        facilities all contributed to the higher per unit operating costs
        of $10.34/boe.

    -   Operating netbacks in 2007 were $33.28/boe compared to $33.05/boe in
        2006. Fourth quarter operating netbacks were $34.98/boe compared to
        $27.62/boe for the same period in 2006.

    -   Net capital expenditures for the year amounted to $199.5 million,
        with $61.9 million alone attributable to fourth quarter activity.
        Approximately 90% of the years expenditures were incurred in the
        Pembina area.

    -   Highpine participated in drilling 34 gross wells (24.9 net) at a
        84% success rate in 2007 with 8 gross wells (7.2 net) drilled in the
        fourth quarter at a 100% success rate. In 2007, Highpine received
        23 new well license approvals in the Pembina Nisku area. This
        activity level constituted Highpine's most active year.

    -   Capital expenditures in 2007 were focused on reserve development,
        facility expansions, land and seismic. Highpine's 2007 finding,
        development and acquisition costs (FD&A) per boe, including net
        changes in future development capital, were $30.04 proved and
        $30.23 proved plus probable.

    -   Net general & administrative expenses (G&A) per boe of $1.88 for the
        year 2007 were reduced by 16% compared to 2006. In the fourth
        quarter, 2007 net G&A of $1.48 represented a decrease of 42% compared
        to the same period in 2006. Net G&A expenses for 2007 were
        $12.2 million compared to $9.7 million in 2006.

    -   In 2007, a $358.1 million non-cash goodwill impairment charge in the
        year resulted in a net loss of $345.1 million, compared to net
        earnings of $7.0 million in 2006.

    -   At year end, net debt of $174.8 million, expressed as a ratio to
        (trailing) cash flow, was 0.9:1 compared to 1.3:1 at
        December 31, 2006.
    

    2007 OPERATIONS

    Highpine's production increased from 17,375 boe/d in the first quarter of
2007 to a fourth quarter rate of 19,716 boe/d. A production base capable of
producing in excess of 20,000 boe/d was established late in 2007 through
successful drilling and facility improvements. Highpine's operated wells and
facilities ran at an on-time efficiency rate of greater than 95% during the
year. In 2007, the equipping and pipelining of 22 wells were completed in
Pembina that added significant capability to Highpine's production base. This
operating capability was tempered by delays in regulatory approvals and
periods of unexpected down-time and curtailments imposed by third party
midstream processing facilities, which ultimately affected sales volumes.
    Highpine participated in the drilling of 34 wells in 2007 and achieved a
drilling success rate of 84%. A total of 28 (21.8 net) wells were drilled in
the Pembina Nisku Fairway as Highpine continued to be successful in obtaining
sour well drilling licences. Drilling results of the Pembina program included
13 (11.4 net) oil and gas wells, 7 (4.8 net) shallow gas wells, 2 (1.7 net)
service wells and 6 (3.9 net) dry holes with an overall drilling success rate
in excess of 80%. The most significant was the drilling and completion of the
4,200 metre directional 16-36-48-8W5 well drilled into the Pembina Nisku WW
pool. This well is currently producing at a restricted rate of 1,000 boe/d
with GPP approval expected to be received in the second quarter. The balance
of the wells in 2007 were drilled in the West Central Alberta Gas Fairway at a
100% success rate.
    At year-end, Highpine's undeveloped land holdings totalled 309,000 net
undeveloped acres of which approximately 56% or 174,000 net acres were in
Pembina. Highpine also significantly increased its seismic data during 2007 to
2,069 square miles of 3D data and 3,672 miles of 2D data.

    2007 YEAR-END RESERVES

    Year end 2007 total proved reserves of 28.6 million barrels of oil
equivalent (mmboe) and total proved plus probable reserves of 44.2 mmboe
remained relatively flat compared to the year end 2006 reserves of 44.4 mmboe.
Highpine's 2007 capital program replaced 120% of production on a total proved
and probable basis, before revisions and the net effect of acquisitions and
dispositions.
    Poor production performance primarily at Ante Creek resulted in negative
revisions to both total proved and proved plus probable gas and natural gas
liquids reserves of 1.45 mmboe. Remaining reserves at Ante Creek now represent
less than 1% of Highpine's total proved plus probable reserve base with little
further downside risk. Positive revisions to total proved oil reserves of
1.40 mmbbls were largely due to the movement of probable additional reserves
to the total proved category through successful drilling.
    In 2007, $199.5 million of capital was incurred with $83.1 million spent
on facilities, land and seismic, and the balance related to drilling and
completions. Approximately $180 million was spent in the Pembina area, largely
focused on the Nisku.
    Total 2007 finding, development and acquisition costs ("FD&A"), excluding
the net change in future development capital, for total proved reserves were
$34.33/boe and for total proved plus probable reserves were $31.87/boe.
Including the net change in future development capital, the FD&A cost for
total proved reserves were $30.04/boe and for total proved plus probable
reserves were $30.23/boe.
    During 2007 a large number of the Nisku wells drilled were focused on
infill and step-out locations, which generally target smaller reserves when
compared to new pool discoveries. 2007 Nisku drilling resulted in reserves of
approximately 500 mboe per well, which had an impact on the finding and
development costs. Due to delays in well licensing along the NE extension of
the Nisku trend, a number of Highpine's more attractive prospects from a new
reserve potential, were not able to be drilled during 2007. A significant
amount of Highpine's 2008 plans and capital program are focused on this high
potential area where wells are currently drilling, being licensed and
undergoing consultation.
    Lower services costs currently being encountered in the industry and an
internal focus on operational efficiency are expected to moderate the growing
cost structure experienced by Highpine to date. These factors combined with
drilling higher impact Nisku prospects in 2008 are expected to result in
improved go forward F&D costs and recycle ratios.
    Paddock, Lindstrom & Associates Ltd. ("Paddock") has evaluated the
Company's reserves as at December 31, 2007. The 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, 2007 Based on Forecast
                             Price Assumptions(*)

    -------------------------------------------------------------------------
                                    Natural  Crude Oil      NGL's      Total
    December 31, 2007                   Gas                             (6:1)
                                       (bcf)    (mbbls)    (mbbls)     (mboe)
    -------------------------------------------------------------------------
    Proved developed producing        48.81     10,394      3,877     22,405
    Proved developed non-producing     8.94      1,411        639      3,540
    Proved undeveloped                12.04        167        472      2,646
    -------------------------------------------------------------------------
    Total proved                      69.79     11,972      4,988     28,592
    Probable additional               42.78      6,094      2,371     15,594
    -------------------------------------------------------------------------
    Total proved plus probable       112.57     18,066      7,359     44,186
    -------------------------------------------------------------------------
    (*) 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         816,117    707,311    630,623    572,789    527,231
      Developed Non-
       Producing         118,344    100,031     87,162     77,547     70,052
                      ---------- ---------- ---------- ---------- -----------
      Total Developed    934,461    807,342    717,785    650,336    597,283
      Undeveloped         65,188     43,090     30,933     23,254     17,970
                      ---------- ---------- ---------- ---------- -----------
    Total Proved         999,649    850,432    748,718    673,590    615,253
    Probable             489,183    339,953    256,873    203,917    167,196
                      ---------- ---------- ---------- ---------- -----------
    Total Proved Plus
     Probable          1,488,832  1,190,385  1,005,591    877,507    782,449
                      ---------- ---------- ---------- ---------- -----------
                      ---------- ---------- ---------- ---------- -----------



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

    2008                   90.00       1.00       6.80      53.25      71.00
    2009                   88.00       1.00       7.28      52.04      69.38
    2010                   84.00       1.00       7.43      49.62      66.16
    2011                   82.00       1.00       7.58      48.40      64.54
    2012                   80.00       1.00       7.73      47.19      62.92
    -------------------------------------------------------------------------
    Prices escalated at 2% per year from 2012


    Reserves Reconciliation(*)

    -------------------------------------------------------------------------
                       Natural Gas          Crude Oil            NGL's
    -------------------------------------------------------------------------
                     Total  Proved &     Total  Proved &     Total  Proved &
                    Proved  Probable    Proved  Probable    Proved  Probable
    -------------------------------------------------------------------------
                         (bcf)              (mbbls)             (mbbls)
    Dec. 31, 2006    74.94    112.67    11,081    17,552     5,683     8,064
    Discoveries and
     extensions      12.89     22.73     2,262     2,986       566       962
    Acquisitions      1.77      2.19         -         -       203       251
    Dispositions      2.59      3.06        58        74       312       369
    Revisions        (3.19)    (7.93)    1,403       318       268      (129)
    Production      (14.03)   (14.03)   (2,716)   (2,716)   (1,420)   (1,420)
    -------------------------------------------------------------------------
    Dec. 31, 2007    69.79    112.57    11,972    18,066     4,988     7,359
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    ----------------------------------
                       Combined BOE
    ----------------------------------
                      Total  Proved &
                     Proved  Probable
    ----------------------------------
                          (mboe)
    Dec. 31, 2006    29,254    44,395
    Discoveries and
     extensions       4,976     7,736
    Acquisitions        498       616
    Dispositions        801       953
    Revisions         1,139    (1,134)
    Production       (6,474)   (6,474)
    ----------------------------------
    Dec. 31, 2007    28,592    44,186
    ----------------------------------
    ----------------------------------
    (*) Highpine working interests only - does not include Highpine royalty
        interests and royalty costs
    

    NEW ROYALTY FRAMEWORK (NRF)

    On October 25, 2007, the Government of Alberta announced a proposed NRF
for oil and natural gas royalties in the Province of Alberta effective
January 1, 2009. Highpine requested that Paddock estimate the impact to the
reserve evaluation based on currently released information on the proposed
NRF. To date the Government of Alberta has not provided enough clarity on a
number of issues that would permit Paddock to provide a precise calculation of
net reserves and net present values under the proposed NRF. In addition, it is
possible that the announced changes may be amended before coming into effect.
Under the forecast price assumptions, Paddock has estimated that the NRF
change to the before tax net present value, discounted at 10%, of the net
estimated future revenue from proved plus probable reserves would be a
reduction of approximately 20% as at December 31, 2007. The NRF will impact
future drilling decisions in order for the Company to maintain acceptable
rates of return on its capital deployed.

    
    2008 OUTLOOK
                                      2008 Guidance      2007 Actuals
                                     -----------------------------------

    Average production (boe/d)        20,500-21,000      17,736
    Capital expenditures              $150 million       $199.5 million
    Operating costs (/boe)            $10.50-$10.75      $10.34
    G&A (/boe)                        $1.60-$1.80        $1.88
    

    Highpine's production growth is expected to continue into 2008, bringing
on production proven through 2007 drilling as well as new 2008 projects.
    A significant portion of Highpine's production comes from the Pembina
Nisku Fairway which is highly dependent upon four major gas processing
facilities in the vicinity. A strong focus of the Company in 2008 is to work
closely with its service providers, and partners in the area, to improve
on-time performance, reliability and flexibility within the complicated
Pembina network. Downtime associated with a lack of acid gas injection
capacity at a Brazeau area facility in January and February will result in
first quarter 2008 production averaging approximately 18,000 boe/d. This
specific issue was mitigated in February, in part due to the disposition of a
Highpine wellbore for acid injection to the facility operator.
    During the first week of March 2008, production has ramped up to an
estimated 20,000 boe/d with the Violet Grove facility at full volume, the
upgraded Brazeau 6-29 compressor station back on line and continued
optimization of the Paddy Creek sales line. In addition, several Pembina Nisku
wells are expected to be tied-in and brought on stream prior to the end of
March. Other projects, initiated by Keyera at their Brazeau facility, are
aimed at allowing acid gas to be off-loaded to other facilities in their
system with the objective of minimizing curtailments at Brazeau in the future
with respect to acid gas issues. All of these projects, focused in the first
quarter of 2008, are expected to contribute to supporting production volumes
for the remaining quarters of 2008 in excess of 20,000 boe/d per quarter.
    In 2008 to date, Highpine has participated in drilling 11 (4.8 net) wells
resulting in 1 (1.0 net) potential Nisku oil/gas well, 9 (3.6 net) potential
gas wells and 1 (0.2) dry hole at a 98% success rate. Highpine currently has
three drilling operations in progress, two in Pembina targeting the Nisku and
one in Joffre.
    A significant portion of the 2008 capital expenditures (up to
$70 million), is focused on exploration and development activities in the
northeast portion of the Pembina Nisku Fairway: Tomahawk, Highvale and Rocky
Rapids. This capital allocation accounts for up to 21 (19 net) wells and
substantial pipelining and associated infrastructure. This area is northeast
of the established productive Nisku trend of which Highpine has extensive land
holdings and seismic coverage. Two notable discoveries have been made in this
area in the past year, substantially reducing risk and increasing the
prospectivity for finding oil in the area. Public consultation has been
ongoing and continues in the area as several well licenses have been applied
for with many others in the process of application. Two well licenses in the
Rocky Rapids area, from the Alberta Energy Resources Conservation Board
(ERCB), have been received with the first Nisku well drilled by Highpine in
this area to be initiated prior to spring break-up. Due to the long lead-times
required for licensing, building new infrastructure, bring on production in
this area, and other regulatory matters, no meaningful production volumes are
expected to be contributed from this area in 2008.
    Approximately $50 million of the 2008 capital expenditures is earmarked
for other exploration and development activity in the Pembina Nisku Fairway
including development of the WW South pool and new exploration.
    It is expected that cash flow generated in 2008 will exceed capital
expenditures given the stronger than expected commodity price environment we
are experiencing early in 2008. Highpine has recently entered into three
natural gas swaps for summer gas, covering the period April 2008 -
October 2008, for 7,500 GJ/d at an average of Cdn $8.01/GJ. Representing
approximately 20% of Highpine's daily gas production, this support along with
generally higher natural gas pricing, has prompted Highpine to internally
review gas projects planned for later in the year as well as those currently
not budgeted. Natural gas hedges of 2,500 GJ/d at an average swap price of
Cdn $7.69/GJ remain through to the end of March 2008, as does a natural gas
collar, of no consequence, for 5,000 GJ/d at Cdn $6.00 - Cdn $11.10. Highpine
currently has no oil hedges in place. Baring any changes to Highpine's planned
capital expenditures, any cash in excess of capital requirements will be
applied against bank debt. The impact of proposed royalty changes in Alberta,
technical results from activity undertaken early in 2008, commodity prices,
regulatory requirements, or any other unforeseen event, may impact the capital
expenditures for any of the activity areas described above.
    Jonathan Lexier, President and CEO explains:
    "2008 represents both an exciting and interesting year for Highpine. We
have reduced our capital exposure and at the same time are focusing a
disproportionate share of that capital program on a lightly explored and
undeveloped area with little expectation of meaningful production in this
calendar year. This area represents the next phase our growth in the Nisku
fairway and we are very excited about the prospects that lay ahead and the
potential for volume growth in 2009 and beyond. In 2008, despite the much
reduced capital spent in our traditional focus areas (Violet Grove, Brazeau
and Easyford), we are still anticipating the potential for approximately
15% growth or greater on our existing production base. Our focus in 2008 will
be on improving our capital efficiency and operating reliability while still
delivering a growth profile with an eye to 2009 and beyond."

    CONFERENCE CALL

    -------------------------------------------------------------------------
    Highpine will host a conference call for analysts, investors and
    interested parties, to discuss its financial and operational results at
    8:30 am MDT, on Wednesday, March 12, 2008. Jonathan Lexier, President and
    Chief Executive Officer, as well as members of Highpine's executive team,
    will be in attendance.

    The call can be accessed toll free by dialing Canada and USA:
    1-800-319-4610; Outside Canada and USA: 1-604-638-5340. Please phone in
    10-15 minutes prior to the start of the call. The conference call will
    also be broadcast live over the internet on Highpine's website located at
    www.highpineog.com. Digital Playback will be available until
    April 11, 2008 in North America Toll Free: 1-800-319-6413, Pin Code: 6639
    followed by the No. sign.
    -------------------------------------------------------------------------

    CORRECTION

    As stated in the March 10, 2008 press release, Jonathan Lexier will be
presenting at the FirstEnergy/Société Générale East Coast Canadian Energy
Conference taking place March 12 to 14, 2008 in New York City, New York at the
Waldorf Astoria. Please be advised that Jonathan will be presenting @ 9:47 am
(EDT) on Friday, March 14, 2008 (instead of 10:04 am EDT). To listen and view
this online event, please visit http://remotecontrol.jetstreammedia.com/14711.
The presentation will be available in an archived version at this link for 30
days following the live presentation. For more information on the webcast,
please visit www.firstenergy.com.


    
    -------------------------------------------------------------------------
                        Three months ended          Twelve months ended
    ($000s, except          December 31,                 December 31,
     per share and                            %                            %
     share numbers)      2007       2006 Change       2007       2006 Change
    -------------------------------------------------------------------------

    Financial
    Total revenue(1)  122,178     67,552     81    401,297    254,938     57
    Cash from
     operations(2)     58,357     29,973     95    193,840    127,440     52
      Per share -
       diluted           0.85       0.44     93       2.83       2.17     30
    Net earnings
     (loss)(3)         19,805     (5,446)     -   (345,054)     6,953      -
      Per share -
       diluted           0.29      (0.08)     -      (5.09)      0.12      -
    Net debt(4)       174,821    169,570      3    174,821    169,570      3
    Total assets    1,062,576  1,392,911    (24) 1,062,576  1,392,911    (24)
    Capital
     expenditures(5)   61,948     72,711    (15)   199,513    222,214    (10)
    Total shares
     outstanding (No.) 67,886     67,648      -     67,886     67,648      -
    Weighted average
     shares
     Outstanding
     - diluted (No.)   68,408     68,522      -     68,456     58,674     17
    -------------------------------------------------------------------------
    Operating
    Average daily
     production
      Crude oil and
       NGLs (bbls/d)   13,394      8,653     55     11,332      7,554     50
      Natural gas
       (mcf/d)         37,930     30,221     26     38,426     25,350     52
    -------------------------------------------------------------------------
      Total (boe/d)    19,716     13,690     44     17,736     11,779     51
    -------------------------------------------------------------------------
    Average selling
     prices(6)
      Crude oil and
       NGLs ($/bbl)     82.38      58.37     41      72.50      66.19     10
      Natural gas
       ($/mcf)           6.89       7.24     (5)      7.39       7.06      5
    -------------------------------------------------------------------------
      Total ($/boe)     69.22      52.88     31      62.34      57.64      8
    -------------------------------------------------------------------------
    Wells drilled -
     gross (net)
     (No.)
      Oil               4(3.9)     8(6.2)     -     10(8.1)   15(11.5)     -
      Natural Gas       4(3.3)     8(4.6)     -    16(11.2)   43(25.0)     -
      Abandoned/other     -(-)     3(2.5)     -      8(5.6)   16(10.2)     -
    -------------------------------------------------------------------------
      Total             8(7.2)    19(3.3)     -    34(24.9)   74(46.7)     -
      Drilling success
       rate (%)           100         95      -         84         85      -
    -------------------------------------------------------------------------
    Operating netback
     ($/boe)
      Oil and natural
       gas sales        69.22      52.88     31      62.34      57.64      8
      Royalties        (20.13)    (14.80)    36     (18.04)    (16.40)    10
      Operating costs  (11.96)    (10.42)    15     (10.34)     (8.57)    21
      Transportation
       costs            (0.23)     (0.62)   (63)     (0.76)     (0.71)     7
      Realized hedging
       gain (loss)      (1.92)      0.58      -       0.08       1.09    (93)
    -------------------------------------------------------------------------
      Operating
       netback          34.98      27.62     27      33.28      33.05      1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Total revenue includes realized and unrealized hedging losses and
        gains.
    (2) Cash from operations is calculated as cash flow from operating
        activities before the change in non-cash working capital and
        abandonment expenditures.
    (3) Net loss for the 2007 periods includes a non-cash goodwill impairment
        charge of $358.1 million
    (4) Net debt includes working capital excluding unrealized financial
        instruments.
    (5) Capital expenditures include property acquisitions and are presented
        net of proceeds of disposals.
    (6) The average selling prices reported are before hedging activities.
    

    MANAGEMENT'S DISCUSSION AND ANALYSIS

    This Management's Discussion and Analysis (MD&A) is dated and based on
information at March 11, 2008. This MD&A has been prepared by management and
should be read in conjunction with the audited consolidated financial
statements for the year ended December 31, 2007 and audited consolidated
financial statements and MD&A for the year ended December 31, 2006 for a
complete understanding of the financial position and results of operations of
Highpine Oil & Gas Limited ("Highpine" or the "Company"). The audited
consolidated financial statements have been prepared in accordance with
generally accepted accounting principles (GAAP) in Canada. All references to
dollar values refer to Canadian dollars unless otherwise stated.
    This MD&A uses the terms "funds flow from operations," "funds flow" and
"funds flow per share," which are not recognized measures under Canadian GAAP.
Management believes that in addition to cash flow from operating activities,
funds flow is a useful supplemental measure as it demonstrates Highpine's
ability to generate cash necessary to repay debt or fund future growth through
capital investment before changes in non-cash working capital balances.
Investors are cautioned, however, that this measure should not be construed as
an alternative to cash flow from operating activities determined in accordance
with GAAP as an indication of Highpine's performance. Highpine's method of
calculating funds flow may differ from other companies, especially those in
other industries and accordingly may not be comparable to measures used by
other companies. Highpine calculates funds from operations as cash from
operating activities before the change in non-cash working capital related to
operating activities and abandonment expenditures.

    
    The following table reconciles the cash flow from operating activities to
funds from operations:

    -------------------------------------------------------------------------
                                                   Three              Twelve
                                            months ended        months ended
                                             December 31,        December 31,
                                          2007      2006      2007      2006
    -------------------------------------------------------------------------
    ($000s)

    Cash flow from operating
     activities                         55,912    39,109   186,569   109,054
    Change in non-cash operating
     working capital                     1,989    (9,452)    5,799    18,018
    Abandonment expenditures               456       316     1,472       368
    -------------------------------------------------------------------------
    Funds from operations               58,357    29,973   193,840   127,440
    -------------------------------------------------------------------------
    

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

    
    Financial Results

    Oil and Natural Gas Revenue
    -------------------------------------------------------------------------
                            Three months ended           Twelve months ended
                                   December 31,                  December 31,
                      2007      2006  % Change      2007      2006  % Change
    -------------------------------------------------------------------------
    ($000s)

    Crude oil and
     natural gas
     liquids (NGLs)
     revenue       101,520    46,469       118   299,896   182,509        64
    Natural gas
     revenue        24,033    20,132        19   103,702    65,295        59
    -------------------------------------------------------------------------
                   125,553    66,601        89   403,598   247,804        63
    Realized hedging
     gain (loss)    (3,474)      727         -       487     4,703       (90)
    Unrealized
     hedging gain
     (loss)             99       224       (56)   (2,788)    2,431         -
    -------------------------------------------------------------------------
    Total oil and
     natural gas
     revenue       122,178    67,552        81   401,297   254,938        57
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    For the twelve months ended December 31, 2007 total oil and natural gas
revenue increased to $401.3 million from $254.9 million for the twelve months
ended December 31, 2006 due to production volume increases combined with
higher commodity prices received in 2007. Total oil and natural gas revenue
was negatively impacted by $2.8 million of unrealized hedging losses compared
to $2.4 million of unrealized hedging gains in the comparative twelve month
period.

    Production
    -------------------------------------------------------------------------
                            Three months ended           Twelve months ended
                                   December 31,                  December 31,
                      2007      2006  % Change      2007      2006  % Change
    -------------------------------------------------------------------------
    Daily Production
    Crude oil and
     NGLs (Bbls/d)  13,394     8,653        55    11,332     7,554        50
    Natural gas
     (Mcf/d)        37,930    30,221        26    38,426    25,350        52
    -------------------------------------------------------------------------
    BOE/d           19,716    13,690        44    17,736    11,779        51
    -------------------------------------------------------------------------
    Production Mix
    -------------------------------------------------------------------------
    Crude oil and
     NGLs              68%       63%         8       64%       64%         -
    Natural gas        32%       37%       (14)      36%       36%         -
    -------------------------------------------------------------------------
                      100%      100%         -      100%      100%         -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                            Three months ended           Twelve months ended
                                   December 31,                  December 31,
                      2007      2006  % Change      2007      2006  % Change
    -------------------------------------------------------------------------
    (BOE/d)

    Daily Production
     by Area
    Pembina Nisku
     Fairway        15,800     9,700        63    13,817     8,293        67
    West Central
     Alberta Gas
     Fairway         3,203     3,399        (6)    3,191     2,858        12
    Bantry/Retlaw      573       492        16       598       475        26
    Other              140        99        41       130       153       (15)
    -------------------------------------------------------------------------
    Total           19,716    13,690        44    17,736    11,779        51
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Prior periods have been reclassified to conform with current period
    presentation.
    

    Production for the twelve months ended December 31, 2007 increased
51 percent to 17,736 BOE/d from 11,779 BOE/d for the twelve months ended
December 31, 2006. The increase is attributable to a full year of production
from the acquisition of Kick Energy Corporation ("Kick") on August 1, 2006 and
new production from the Company's drilling program. The majority of the
increases were from the Pembina Nisku fairway where 28 (21.8 net) wells were
drilled out of the Company's total for 2007 of 34 (24.9 net) wells.
    Highpine's original guidance for 2007 was production targeted in excess
of 20,000 BOE/d. The 11 percent shortfall is primarily attributable to
unexpected downtime and curtailments at certain non-operated midstream
processing facilities as a result of unscheduled turnarounds and maintenance.
Highpine is taking proactive steps to improve all of its recipient sour gas
plant operations for 2008 as well as other facilities optimization initiatives
including installing an additional booster compressor on one of its major
production pipelines leaving the Violet Grove oil battery.

    
    Pricing
    -------------------------------------------------------------------------
                            Three months ended           Twelve months ended
                                   December 31,                  December 31,
                      2007      2006  % Change      2007      2006  % Change
    -------------------------------------------------------------------------
    Selling Prices
     Before Hedges
    Crude oil and
     NGLs ($/Bbl)    82.38     58.37        41     72.50     66.19        10
    Natural gas
     ($/Mcf)          6.89      7.24        (5)     7.39      7.06         5
    -------------------------------------------------------------------------
    Total combined
     ($/BOE)         69.22     52.88        31     62.34     57.64         8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                            Three months ended           Twelve months ended
                                   December 31,                  December 31,
                      2007      2006  % Change      2007      2006  % Change
    -------------------------------------------------------------------------
    Benchmark Prices
    WTI oil
     (US$/Bbl)       90.77     60.22        51     72.27     66.25         9
    US$/Cdn$
     exchange rate    1.02      0.87        17      0.94      0.88         7
    AECO natural gas
     ($/Mcf)
     (monthly)        6.02      6.91       (13)     6.65      6.51         2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    The WTI benchmark price for crude oil was 9 percent higher for
2007 compared to 2006 resulting in higher realized prices. Highpine's realized
natural gas price increased for 2007 in response to a 2 percent increase in
the AECO benchmark price.

    Commodity Price Risk Management

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

    
    -------------------------------------------------------------------------
    Twelve months ended December 31,                2007               2006
                                     Crude Oil   Natural
                                        & NGLs       Gas    Total      Total
                                          (Bbl)     (Mcf)    (BOE)      (BOE)
    -------------------------------------------------------------------------

    Average volumes hedged (per day)     5,500    13,542     7,757     4,736
    Percent of production hedged           49%       35%       44%       40%
    Realized hedging gain (loss) ($)     (0.91)     0.30      0.08      1.09
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    For the twelve months ended December 31, 2007, Highpine realized a
$4.2 million natural gas hedging gain which was largely offset by a
$3.7 million crude oil hedging loss. 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.

    -------------------------------------------------------------------------
    Twelve months ended December 31,                2007               2006
                                     Crude Oil   Natural
                                        & NGLs       Gas    Total      Total
    -------------------------------------------------------------------------
    ($000s)

    Realized hedging gain (loss)        (3,748)    4,235       487     4,703
    Unrealized hedging gain (loss)      (1,103)   (1,685)   (2,788)    2,431
    -------------------------------------------------------------------------
    Total hedging gain (loss)           (4,851)    2,550    (2,301)    7,134
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The following contracts were outstanding at December 31, 2007:

    -------------------------------------------------------------------------
    Term                    Contract        Volume          Fixed Price
    -------------------------------------------------------------------------
    Feb 07 to Mar 08    Natural Gas Swap  1,250 GJs/d           Cdn $7.68/GJ
    Feb 07 to Mar 08    Natural Gas Swap  1,250 GJs/d           Cdn $7.70/GJ
    Jul 06 to Mar 08  Natural Gas Collar  5,000 GJs/d Cdn $6.00 to $11.10/GJ
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    As at December 31, 2007, the unrealized mark-to-market gain on outstanding
natural gas contracts was $0.4 million. The unrealized mark-to-market gain
reflects the market price Highpine would receive if the counterparty were to
buy out the outstanding contracts. The determination of the fair value of
outstanding contracts at December 31, 2007 requires assumptions to be made of
the underlying future commodity prices.

    Subsequent to December 31, 2007, Highpine entered into the following
    contracts:

    -------------------------------------------------------------------------
    Term                    Contract        Volume          Fixed Price
    -------------------------------------------------------------------------
    Apr 08 to Oct 08    Natural Gas Swap  2,500 GJs/d           Cdn $8.01/GJ
    Apr 08 to Oct 08    Natural Gas Swap  2,500 GJs/d           Cdn $7.94/GJ
    Apr 08 to Oct 08    Natural Gas Swap  2,500 GJs/d           Cdn $8.10/GJ
    -------------------------------------------------------------------------


    Royalty Expense
    -------------------------------------------------------------------------
                            Three months ended           Twelve months ended
                                   December 31,                  December 31,
                      2007      2006  % Change      2007      2006  % Change
    -------------------------------------------------------------------------
    Total royalties,
     net of ARTC    36,515    18,635        96   116,784    70,529        66
    ($000s)

    As a percent of
     oil and natural
     gas sales
     (before
     hedging)          29%       28%         4       29%       28%         4

    $/BOE            20.13     14.80        36     18.04     16.40        10
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

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

    
    Operating Costs
    -------------------------------------------------------------------------
                            Three months ended           Twelve months ended
                                   December 31,                  December 31,
                      2007      2006  % Change      2007      2006  % Change
    -------------------------------------------------------------------------
    Operating costs
     ($000s)        21,690    13,124        65    66,937    36,839        82
    $/BOE            11.96     10.42        15     10.34      8.57        21
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    For the twelve months ended December 31, 2007, operating costs on a per
BOE basis increased 21 percent compared to the twelve months ended
December 31, 2006. The increases were a result of several factors including
higher gas processing costs as a result of increased gas production volumes in
the Pembina area, higher power costs due to the increasing utilization of
electric submersible pumps and increases in repair and maintenance and
contract operating costs. In addition, the Company incurred increased workover
costs largely related to electric submersible pumps as well as the turnaround
costs on the Violet Grove oil battery.

    
    Transportation Costs
    -------------------------------------------------------------------------
                            Three months ended           Twelve months ended
                                   December 31,                  December 31,
                      2007      2006  % Change      2007      2006  % Change
    -------------------------------------------------------------------------
    Transportation
     costs ($000s)     426       778       (45)    4,925     3,069        60
    $/BOE             0.23      0.62       (63)     0.76      0.71         7
    -------------------------------------------------------------------------

    For the twelve months ended December 31, 2007, transportation costs on a
per BOE basis increased 7 percent compared to the comparative 2006 period
primarily as a result of higher sulphur transportation charges. Increased sour
oil production resulted in larger quantities of sulphur which was transported
by truck and rail to Vancouver, British Columbia and other disposal locations.
Railway interruptions during 2007 further increased the cost of shipping
sulphur volumes.

    Operating Netback
    -------------------------------------------------------------------------
                            Three months ended           Twelve months ended
                                   December 31,                  December 31,
                      2007      2006  % Change      2007      2006  % Change
    -------------------------------------------------------------------------
    ($/BOE)

    Sales price
     before hedging  69.22     52.88        31     62.34     57.64         8
    Royalties       (20.13)   (14.80)       36    (18.04)   (16.40)       10
    Operating costs (11.96)   (10.42)       15    (10.34)    (8.57)       21
    Transportation
     costs           (0.23)    (0.62)      (63)    (0.76)    (0.71)        7
    -------------------------------------------------------------------------
    Netback before
     hedges          36.90     27.04        36     33.20     31.96         4
    Realized hedging
     gain (loss)     (1.92)     0.58         -      0.08      1.09       (93)
    -------------------------------------------------------------------------
    Operating
     netback         34.98     27.62        27     33.28     33.05         1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Operating netback before realized hedging gains was $33.20/BOE for the
twelve months ended December 31, 2007 compared to $31.96/BOE for the twelve
months ended December 31, 2006. Increases in commodity prices were largely
offset by higher royalties and operating costs.

    General and Administrative Expenses
    -------------------------------------------------------------------------
                            Three months ended           Twelve months ended
                                   December 31,                  December 31,
                      2007      2006  % Change      2007      2006  % Change
    -------------------------------------------------------------------------
    Gross expenses
     ($000s)         3,586     4,436       (19)   15,484    12,931        20
    Capitalized
     ($000s)          (903)   (1,227)      (26)   (3,313)   (3,249)        2
    -------------------------------------------------------------------------
    Net expenses
     ($000s)         2,683     3,209       (16)   12,171     9,682        26
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    $/BOE             1.48      2.55       (42)     1.88      2.25       (16)
    percent
     capitalized       25%       28%       (11)      21%       25%       (16)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Gross expenses increased 20 percent to $15.5 million for the twelve
months ended December 31, 2007 from $12.9 million in 2006 primarily as a
result of higher personnel costs. Average employee and consultant count
increased commensurate with the growth of the Company. At December 31, 2007,
Highpine had 60 Calgary based office employees compared to 55 at
December 31, 2006. In addition, Highpine incurred higher severance costs and
recruiting costs and implemented a defined contribution retirement plan for
employees. On a per BOE basis, general and administrative expenses decreased
16 percent to $1.88/BOE from $2.25/BOE in 2006 as a result of higher
production.

    Stock-Based Compensation

    Stock-based compensation expense totaled $4.5 million in 2007 compared to
$5.7 million in 2006. The decrease is attributable to options that were
cancelled in 2007 which resulted in a recovery of previously recognized
stock-based compensation expense.
    On March 21, 2007, 1.9 million stock options which had been granted to
non-officer employees at exercise prices ranging from $14.92 to $23.25 were
repriced to an exercise price of $12.05. The vesting period of all repriced
options was reset such that the repriced options vest as to one-quarter
thereof on each of the first, second, third and fourth anniversaries of the
repricing. An additional $5.1 million of stock based compensation expense will
be recorded over the four year vesting period of the repriced options as a
result of the reprice.

    Interest and Finance Costs

    Interest and finance costs for 2007 were $9.4 million versus $5.0 million
in 2006. This increase was primarily due to higher average debt levels.

    
    Depletion, Depreciation and Accretion
    -------------------------------------------------------------------------
                            Three months ended           Twelve months ended
                                   December 31,                  December 31,
                      2007      2006  % Change      2007      2006  % Change
    -------------------------------------------------------------------------
    Depletion and
     depreciation
     ($000s)        56,341    36,682        54   193,302   124,627        55
    Accretion of
     asset retirement
     obligation
     ($000s)           228       220         4       905       679        33
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total DD&A      56,569    36,902        53   194,207   125,306        55
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    DD&A rate $/BOE  31.19     29.31         6     30.00     29.15         3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    The depletion, depreciation, and accretion (DD&A) rate of $30.00 per BOE
for the twelve months ended December 31, 2007 was comparable to the $29.15 per
BOE for the twelve months ended December 31, 2006.

    Income Taxes

    The Company received a refund of $46,000 in 2007 in respect of Large
Corporation tax which was over-paid in a prior year. The Company also paid
cash taxes of $1.4 million in 2007 as a result of the reassessment of the
2004 and 2005 tax years of Kick. The reassessment did not impact Highpine's
current tax expense, net earnings or funds flow as the tax liability had been
recorded in 2006 in the Kick purchase equation.
    The Company recorded a reduction in future taxes of $20.9 million in
2007. The reduction is primarily attributable to a $22.8 million reduction in
Highpine's future income tax liability as a result of a substantively enacted
reduction in Canadian federal income tax rates. Canadian federal income tax
rates will decrease from 22.1 percent in 2007 to 15 percent in 2012. In 2006,
Highpine realized a future tax reduction of $8.0 million primarily due to a
decrease in Canadian federal and Alberta tax rates which resulted in a
$9.1 million tax reduction.
    Although current tax horizons depend on product prices, production
levels, royalty rates and the nature, magnitude and timing of capital
expenditures, the Company currently believes no cash income tax will be
payable in 2008 or 2009.

    Goodwill

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

    
    Funds from Operations and Net Earnings (Loss)

    -------------------------------------------------------------------------
                            Three months ended           Twelve months ended
                                   December 31,                  December 31,
                      2007      2006  % Change      2007      2006  % Change
    -------------------------------------------------------------------------
    Funds from
     operations
     ($000s)        58,357    29,973        95   193,840   127,440        52
      Per diluted
       share ($)      0.85      0.44        93      2.83      2.17        30
    Net earnings
     (loss)
     ($000s)        19,805    (5,446)        -  (345,054)    6,953         -
      Per diluted
       share ($)      0.29     (0.08)        -     (5.09)     0.12         -
    -------------------------------------------------------------------------
    

    For the twelve months ended December 31, 2007, funds from operations
increased 52 percent to $193.8 million from $127.4 million for the twelve
months ended December 31, 2006 due to production increases and crude oil price
increases. Funds from operations per diluted share increased 30 percent to
$2.83.
    During the twelve months of 2007, Highpine incurred a net loss of
$345.1 million, compared to net earnings of $7.0 million for the twelve months
ended December 31, 2006. The magnitude of the net loss is attributable to a
$358.1 million impairment of goodwill incurred during the three months ended
September 30, 2007. Net earnings for the twelve months ended December 31, 2007
included a $22.8 million (2006 - $9.1 million) non-recurring future tax
reduction realized as a result of enacted Canadian federal and Alberta tax
rate reductions.
    The NRF is proposed to be effective January 1, 2009 and as such funds
from operations and net earnings for the year ended December 31, 2007 and the
year ending December 31, 2008 will be unaffected. However, funds from
operations and net earnings for the year ending December 31, 2009 and
subsequent years will be negatively impacted by the expected higher overall
royalty rates. The actual effect of the NRF on Highpine will be determined
based on the actual legislation enacted, the production rates, commodity
prices and product mix after January 1, 2009. If the changes were enacted and
applicable today and based on the Company's interpretation of publicly
available information, Highpine estimates that the potential effect on funds
from operations from current production would result in an approximate
reduction of 29 percent based on a benchmark price of WTI US$70/Bbl and AECO
Cdn$6.00/MMbtu and using a par foreign exchange ratio.

    Long-Term Investment

    The Company's long-term investment of $1.2 million is comprised of
1,080,000 common shares of In-Depth Resources Ltd., a privately held oil and
natural gas company. At December 31, 2007, Highpine assessed the carrying
amount of its investment for impairment which resulted in the Company
recording an impairment provision of $300,000 against the carrying amount
which was charged to earnings.

    Liquidity and Capital Resources

    At December 31, 2007, the Company had a revolving term credit facility of
$230 million and a demand operating credit facility of $20 million with
$147 million drawn against these facilities, thereby providing remaining
credit capacity of $103 million. At December 31, 2007, the Company had a
working capital deficiency of $28.1 million and net debt of $174.8 million.
The Company's working capital deficiency is expected to fluctuate based on the
timing of the Company's capital expenditure program which is typically most
active during the first and fourth quarters. The Company's working capital
deficiency is funded from funds available from existing credit facilities and
funds flow from operations.

    
    -------------------------------------------------------------------------
    As at                                          December 31,  December 31,
                                                          2007          2006
    -------------------------------------------------------------------------
    ($000s)
    Capitalization
    Bank debt                                          146,675       138,890
    Working capital deficiency(1)                       28,146        30,680
    -------------------------------------------------------------------------
    Net debt                                           174,821       169,570
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Shares outstanding (No.)                            67,886        67,648
    Market price at end of period ($)                     9.98         15.70
    Market capitalization                              677,502     1,062,074
    -------------------------------------------------------------------------
    Total capitalization                               852,323     1,231,644
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net debt as a percent of total capitalization          21%           14%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Funds from operations                              193,840       127,440
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net debt to trailing funds from operations ratio      0.90          1.33
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Working capital excludes unrealized financial instruments.
    

    At March 11, 2008, the Company's bank debt was approximately
$138 million.
    In light of the uncertainty surrounding the New Royalty Framework, the
Board of Directors has approved a capital budget for 2008 of $150 million,
being an amount which is below anticipated 2008 funds flow. The Company's
lenders review the credit facilities semi-annually and as a result of the New
Royalty Framework it is expected that the maximum funds available under the
facilities may be reduced. The capital budget will enable Highpine to reduce
its debt in anticipation of a reduction in the maximum funds available under
the Company's credit facilities. If clarification of the NRF can be obtained
which removes the uncertainty surrounding deep oil drilling in Alberta, the
capital budget may be expanded.

    Commitments and Contractual Obligations

    The Company enters into contractual obligations in the normal course of
operations including purchase of assets and services, joint operating
agreements, transportation commitments, sales commitments, royalty
obligations, lease rental obligations and employment agreements. These
obligations are of a recurring and consistent nature and impact funds flow in
an ongoing manner. The Company was committed to make less routine future
payments pursuant to contractual obligations at December 31, 2007 as follows:

    
    -------------------------------------------------------------------------
    ($ thousands)          Total       2008  2009/2010  2011/2012 After 2013
    -------------------------------------------------------------------------
    Operating leases(1)    6,370      1,484      2,566      2,320          -
    Long-term debt(2)    146,675          -    146,675          -          -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    1) Operating leases include leases for office space and field equipment.
    2) In the event that the credit facilities are not extended, the amount
       outstanding would be repayable on May 26, 2009. Management fully
       anticipates that the credit facilities will be extended.
    

    Capital Expenditures

    Capital expenditures, excluding corporate acquisitions, property
acquisitions, and property dispositions totaled $202.7 million for the twelve
months ended December 31, 2007 compared to $194.8 million for the twelve
months ended December 31, 2006. The Company's capital program is heavily
weighted to the Pembina Nisku fairway which accounted for 87 percent of
capital expenditures for the twelve months ended December 31, 2007. During the
twelve months ended December 31, 2007, Highpine drilled 34 (24.9 net) wells
which resulted in 10 (8.1 net) oil wells, 16 (11.2 net) gas wells, 2 (1.7 net)
water source wells and 6 (3.9 net) dry holes. During the third quarter of
2007, the Company disposed of undeveloped properties in a non-core area for
proceeds of $3.6 million.

    
    In 2008, the Company plans to participate in 34 (28 net) wells.

    -------------------------------------------------------------------------
                                          Twelve months ended December 31,
                                              2007         2006     % Change
    -------------------------------------------------------------------------
    ($000s)

    Land                                    11,292       17,392          (35)
    Geologic and geophysical                 7,663       10,431          (27)
    Drilling and completions               119,453      110,665            8
    Facilities and equipment                60,943       52,649           16
    Capitalized general and administrative   3,313        3,258            2
    Office and other                            70          358          (80)
    -------------------------------------------------------------------------
    Total capital expenditures             202,734      194,753            4
    -------------------------------------------------------------------------
    Property acquisitions                      495       27,461          (98)
    -------------------------------------------------------------------------
    Property dispositions                   (3,716)           -          100
    -------------------------------------------------------------------------
    Corporate acquisitions(1)                    -      440,895         (100)
    -------------------------------------------------------------------------
    Total capital expenditures and
     acquisitions                          199,513      663,109          (70)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Represents total consideration for the transactions, including fees,
        but is prior to the related future income tax liability and asset
        retirement obligation.
    

    Outstanding Common Shares

    As at March 11, 2008, the Company had 67.9 million class A common shares
outstanding and had granted options to directors, officers, employees and
consultants to acquire a further 5.0 million class A common shares with an
average exercise price of $10.40 per share.

    FOURTH QUARTER REVIEW

    Highpine increased its average production to 19,716 BOE/d in the fourth
quarter of 2007 compared to 13,690 BOE/d in the fourth quarter of 2006. The
increase in production is attributable to the Company's drilling programs.
Production in the fourth quarter of 2007 was curtailed due to operational
issues at certain recipient gas plants. Highpine is taking steps to improve
all of its recipient gas plant operations for 2008 including installing an
additional booster compressor on one of its major sales lines from the Violet
Grove oil battery to increase throughput capacity of sour natural gas.
    Operating netback before hedging activities increased 36 percent to
$36.90/BOE in the fourth quarter of 2007 compared to $27.04/BOE in the fourth
quarter of 2006. The increase is primarily attributable to stronger benchmark
crude oil prices which increased 51 percent to US$90.77/Bbl in the fourth
quarter of 2007 compared to the fourth quarter of 2006. The increase in crude
oil prices was partially offset by a 17 percent increase in the value of the
Canadian dollar relative to the US dollar. Highpine's operating costs on a per
BOE basis were 15 percent higher than the comparable 2006 period as a result
of higher processing costs and higher workover costs. Highpine's
transportation costs were 63 percent lower than the comparable 2006 period.
The decrease in transportation costs is attributable to strengthening sulphur
prices which significantly reduced the cost of disposing of sulphur.
    Highpine incurred $61.9 million of capital expenditures in the fourth
quarter of 2007 compared to $72.7 million in the fourth quarter of 2006.
Highpine drilled 8 (7.2 net) wells consisting of 4 (3.9 net) oil wells and 4
(3.3) gas wells. No dry holes were drilled in the fourth quarter. The 94
percent owned 16-36-048-08W5M long reach well was completed and commenced
production on December 21. The well was shut-in at year end awaiting
regulatory approval of a production allowable.
    Highpine's funds flow per diluted share increased 93 percent in the
quarter as a result of higher production volumes and higher realized crude oil
prices. Highpine generated net earnings of $19.8 million in the fourth quarter
of 2007 as a result of a $22.8 million future tax reduction as a result of
enacted Canadian federal tax rate reductions.

    Change in Accounting Policies

    Financial Instruments

    Effective January 1, 2007, the Company adopted the Canadian Institute of
Chartered Accountants ("CICA") section 3855 "Financial Instruments -
Recognition and Measurement," section 1530 "Comprehensive Income," section
3865 "Hedges" and section 3861 "Financial Instruments - Disclosure and
Presentation". The standards deal with the recognition and measurement of
financial instruments and comprehensive income. These standards have been
adopted prospectively. Adoption of these standards did not impact January 1,
2007 opening balances. See Note 3 to the consolidated financial statements.

    Future Accounting Changes

    On December 1, 2006, the CICA issued three new accounting standards:
Section 1535, "Capital Disclosures", Section 3862, "Financial Instruments -
Disclosures", and Section 3863, "Financial Instruments - Presentation". These
new standards will be effective on January 1, 2008.
    Section 1535 specifies the disclosure of an entity's objectives, policies
and processes for managing capital, quantitative data about what the entity
regards as capital, whether the entity has complied with any capital
requirements, and if it has not complied, the consequences of such
non-compliance. This section is expected to have minimal impact on the
Company's financial statements.
    Sections 3862 and 3863 specify a revised and enhanced disclosure on
financial instruments. These sections will require the Company to increase
disclosure on the nature and extent of risks arising from financial
instruments and how the entity manages those risks.

    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.

    Revenues, Royalties and Operating Costs

    The Company estimates revenues, royalties and operating costs on
production as at specific reporting dates for which actual revenues and costs
have not been received.

    Capital Expenditures

    The Company estimates capital expenditures incurred on projects that are
in progress.

    Ceiling Test

    The carrying amount of property, plant and equipment is reviewed
quarterly for impairment. Impairment occurs when the carrying value of the
assets is not recoverable by the future undiscounted cash flows. The ceiling
test calculation is based on estimates of proved and probable reserves,
production rates, oil and natural gas prices, royalty rates, future costs and
other relevant assumptions. Highpine's December 31, 2007 ceiling test was
prepared using cash flows that incorporated the Alberta government's New
Royalty Framework as interpreted by management and the Company's reserve
evaluators. Changes to the New Royalty Framework could significantly impact
future cash flows. By their nature, these estimates are subject to measurement
uncertainty and the effects of changes in such estimates in future periods on
financial statements could be significant. Any impairment would be charged to
earnings.

    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
amount, including goodwill. If the fair value of the reporting entity is less
than its carrying amount, a goodwill impairment loss is recognized as the
excess of the carrying amount of the goodwill over the implied fair value of
the goodwill. The determination of fair value requires management to make
assumptions and estimates about recoverable reserves, future commodity prices,
operating costs, royalty rates, production profiles and discount rates.

    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.

    Future Income Taxes

    The Company records future income tax liabilities and future income tax
assets 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. As substantively
enacted tax rates decline between 2008 and 2012, the determination of the
income tax rate to apply to temporary differences requires management to
forecast the reversal of temporary differences over the five year period.

    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
2007 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.
There were no material changes in the Company's internal controls over
financial reporting during the quarter ended December 31, 2007.
    It should be noted that a control system, including the Company's
disclosure and internal controls and procedures, no matter how well conceived
can provide only reasonable, but not absolute, assurance that the objectives
of the control system will be met and it should not be expected that the
disclosure and internal controls and procedures will prevent all errors or
fraud.

    Business Risks and Uncertainties

    Highpine is exposed to numerous risks and uncertainties associated with
the exploration for and development, production and acquisition of crude oil,
natural gas and NGL. Primary risks impacting Highpine are as follows:

    
    -   Government royalties have a significant impact on Highpine's
        financial results. If the New Royalty Framework proposed by the
        Alberta government on October 25, 2007 is enacted as proposed,
        Highpine's royalty rates are expected to increase significantly
        commencing in 2009. The increase in royalty rates could result in a
        reduction of funds available under existing credit facilities and
        impact the Company's ability to raise funds through capital markets.
        Higher royalty rates could also make certain of the Company's future
        prospects uneconomic.

    -   A significant portion of Highpine's portfolio of producing oil and
        natural gas properties are comprised of sour hydrocarbons. A sour gas
        leak could result in personal injury or significant damage to oil and
        gas properties, equipment and the environment. In addition, obtaining
        drilling licenses for sour hydrocarbons is complex and there is no
        certainty that attempts to obtain drilling licenses will be
        successful.

    -   The sour nature of Highpine's production results in significant
        processing. Other companies operate certain of the processing
        facilities that Highpine is dependent on. As a result, Highpine has a
        limited ability to exercise influence over the operation of these
        assets. Downtime at these facilities has resulted in curtailment of
        the Company's production in past periods. Downtime at these
        facilities in the future could result in further curtailments and
        could significantly impact Highpine's performance.

    -   The prices received for Highpine's crude oil, natural gas and NGL
        fluctuate due to many factors including local and global market
        supply and demand, weather patterns, pipeline transportation and
        political stability.

    -   The long-term commercial success of Highpine depends on its ability
        to find, acquire, develop and commercially produce oil and natural
        gas reserves. Without the continual addition of new reserves,
        existing reserves and the production therefrom will decline over time
        as such existing reserves are exploited. Future oil and natural gas
        exploration may involve unprofitable efforts, not only from dry
        wells, but also from wells that are productive but do not produce
        sufficient petroleum substances to return a profit after drilling,
        completion and operating costs.

    -   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. In 2007, the Federal Government
        announced a new climate change plan that calls for greenhouse gas
        emissions to be reduced by 20 percent below current levels by 2020.
        In 2007, the Alberta government introduced legislation to reduce
        greenhouse gas emission intensity; supporting this, in January of
        2008, it announced a new climate change action plan based on three
        areas: (i) carbon capture and storage; (ii) energy conservation and
        efficiency; and (iii) greening production through increased
        investment in clean energy technology. Implementation of strategies
        for reducing greenhouse gases 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.

    These factors should not be considered to be exhaustive. Additional risks
are outlined in the Annual Information Form of the Company available on SEDAR.


    Selected Annual Information
                                              2007         2006         2005
    -------------------------------------------------------------------------
    Financial
    ($000s, except per share amounts)
    Total revenue(1)                       401,297      254,938      141,634
    Net earnings (loss)                   (345,054)       6,953       12,274
      Per share - basic                      (5.09)        0.12         0.35
      Per share - diluted                    (5.09)        0.12         0.34
    Funds from operations                  193,840      127,440       74,550
      Per share - basic                       2.86         2.21         2.13
      Per share - diluted                     2.83         2.17         2.09
    Corporate acquisitions                       -      379,345      257,314
    Capital expenditures(2)                199,513      222,214      153,606
    Total assets                         1,062,576    1,392,911      753,690
    Long-term debt                         146,675      138,890            -
    -------------------------------------------------------------------------
    Operating
    Average daily production
      Oil and NGLs (Bbls/d)                 11,332        7,554        3,984
      Natural Gas (Mcf/d)                   38,426       25,350       13,823
      Total (BOE/d)                         17,736       11,779        6,288
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Summary of Quarterly Results

    -------------------------------------------------------------------------
                                                    2007
                                      Q4          Q3          Q2          Q1
    -------------------------------------------------------------------------
    Financial
    ($000s, except per share
     amounts)
    Total revenue(1)             122,178      89,439     103,769      85,911
    Net earnings (loss)           19,805    (359,513)      1,060      (6,406)
      Per share - basic             0.29       (5.30)       0.02       (0.09)
      Per share - diluted           0.29       (5.30)       0.02       (0.09)
    Funds from operations         58,357      43,984      46,869      44,630
      Per share - basic             0.86        0.65        0.69        0.66
      Per share - diluted           0.85        0.64        0.68        0.65
    Corporate acquisitions             -           -           -           -
    Capital expenditures(2)       61,948      37,073      24,670      75,822
    Total assets               1,062,576   1,044,815   1,415,081   1,421,510
    Long-term debt               146,675     150,414     171,943     157,870
    -------------------------------------------------------------------------
    Operating
    Average daily production
      Oil and NGLs (Bbls/d)       13,394      10,143      11,025      10,750
      Natural Gas (Mcf/d)         37,930      34,637      41,449      39,749
      Total (BOE/d)               19,716      15,916      17,933      17,375
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                                    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
    Funds from operations         29,973      31,171      34,750      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
    Total assets               1,392,911   1,361,249     920,941     910,157
    Long-term debt               138,890     113,287           -           -
    -------------------------------------------------------------------------
    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
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Total revenue is after realized and unrealized hedging losses and
        gains.
    (2) Capital expenditures are net of property dispositions.


    Discussion of Quarterly Trends

    Total revenue of the Company has generally trended with average daily
production levels and commodity prices. During the second and third quarter of
2006, production was negatively impacted as a result of volumes being
temporarily shut-in due to reservoir operating pressures being below the
required minimum in certain pools. Water injection schemes were implemented in
the third and fourth quarter of 2006 which brought previously shut-in
production back on-stream. Production continued to increase in the fourth
quarter of 2006 and the first two quarters of 2007 from the acquisition of
Kick in August 2006 combined with production generated from the Company's
drilling program. In the third quarter of 2007, production was negatively
impacted by scheduled and unscheduled facility turnarounds. Production
increased in the fourth quarter of 2007 as facility downtime was reduced.
    Net earnings for the fourth quarter of 2007 include a $22.8 million future
tax reduction as a result of substantively enacted federal rate reductions.
Net loss for the third quarter of 2007 includes a $358.1 million non-recurring
non-cash charge as a result of the impairment of goodwill. Net earnings for
the second quarter of 2006 include a $9.1 million future tax reduction as a
result of substantively enacted federal and provincial income tax reductions.


    CONSOLIDATED BALANCE SHEETS

    -------------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2007          2006
    -------------------------------------------------------------------------
    ($000s)(unaudited)
    Assets
    Current assets
      Accounts receivable                               75,772        54,944
      Prepaid expenses and deposits                      4,642         2,928
      Financial instruments (notes 3 and 11)               406         3,194
    -------------------------------------------------------------------------
                                                        80,820        61,066
    Property, plant and equipment (note 6)             980,906       972,599
    Long-term investment (notes 3 and 7)                   850         1,150
    Goodwill (note 5)                                        -       358,096
    -------------------------------------------------------------------------
                                                     1,062,576     1,392,911
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Liabilities and Shareholders' Equity
    Current liabilities
      Accounts payable and accrued liabilities         108,560        88,552
      Future income taxes (note 13)                        105           970
    -------------------------------------------------------------------------
                                                       108,665        89,522
    Long-term debt (note 8)                            146,675       138,890
    Future income taxes (note 13)                      131,249       150,832
    Asset retirement obligations (note 9)               11,378        11,258
    Deferred lease inducements                             324           408
    Shareholders' equity
      Share capital (note 10)                          959,456       957,186
      Contributed surplus (note 10)                     15,030         9,962
      Retained earnings (deficit)                     (310,201)       34,853
    -------------------------------------------------------------------------
                                                       664,285     1,002,001
    Commitments (note 12)
    -------------------------------------------------------------------------
                                                     1,062,576     1,392,911
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to the consolidated financial statements.



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

    -------------------------------------------------------------------------
                                  Three months ended     Twelve months ended
                                         December 31,            December 31,
                                    2007        2006        2007        2006
    -------------------------------------------------------------------------
    ($000s, except per share
     amounts) (unaudited)
    Revenues
      Oil and natural gas
       revenues                  125,553      66,601     403,598     247,804
      Royalties, net of ARTC     (36,515)    (18,635)   (116,784)    (70,529)
      Financial instruments
       (note 11)
        Realized (losses) gains   (3,474)        727         487       4,703
        Unrealized (losses)
         gains                        99         224      (2,788)      2,431
    -------------------------------------------------------------------------
                                  85,663      48,917     284,513     184,409

    Expenses
      Operating costs             21,690      13,124      66,937      36,839
      Transportation costs           426         778       4,925       3,069
      General and administrative   2,683       3,209      12,171       9,682
      Depletion, depreciation
       and accretion              56,569      36,902     194,207     125,306
      Interest and finance costs   2,433       1,588       9,390       4,991
      Stock-based compensation
       (note 10)                   1,140       1,333       4,463       5,677
      Impairment of goodwill
       (note 5)                        -           -     358,096           -
      Impairment of long-term
       investment (note 7)           300           -         300           -
    -------------------------------------------------------------------------
                                  85,241      56,934     650,489     185,564
    -------------------------------------------------------------------------
    Earnings (loss) before taxes     422      (8,017)   (365,976)     (1,155)
    -------------------------------------------------------------------------
    Taxes (reduction) (note 13)
      Current                        (46)          -         (46)       (127)
      Future                     (19,337)     (2,571)    (20,876)     (7,981)
    -------------------------------------------------------------------------
                                 (19,383)     (2,571)    (20,922)     (8,108)
    -------------------------------------------------------------------------
    Net earnings (loss)           19,805      (5,446)   (345,054)      6,953
    Retained earnings (deficit),
     beginning of period        (330,006)     40,299      34,853      27,900
    -------------------------------------------------------------------------
    Retained earnings (deficit),
     end of period              (310,201)     34,853    (310,201)     34,853
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net earnings (loss) per
     share (note 10)
      Basic                    $    0.29   $   (0.08)  $   (5.09)  $    0.12
      Diluted                  $    0.29   $   (0.08)  $   (5.09)  $    0.12
    -------------------------------------------------------------------------
    See accompanying notes to the consolidated financial statements.



    CONSOLIDATED STATEMENTS OF CASH FLOWS
    -------------------------------------------------------------------------
                                  Three months ended     Twelve months ended
                                         December 31,            December 31,
                                    2007        2006        2007        2006
    -------------------------------------------------------------------------
    ($000s) (unaudited)
    Cash provided by (used in):
    Operating Activities
      Net earnings (loss)         19,805      (5,446)   (345,054)      6,953
      Items not involving cash:
        Depletion, depreciation
         and accretion            56,569      36,902     194,207     125,306
        Future income tax
         reduction               (19,337)     (2,571)    (20,876)     (7,981)
        Stock-based compensation   1,140       1,333       4,463       5,677
        Unrealized losses (gains)
         on financial instruments    (99)       (224)      2,788      (2,431)
        Amortization of deferred
         lease inducements           (21)        (21)        (84)        (84)
        Impairment of goodwill
         (note 5)                      -           -     358,096           -
        Impairment of long-term
         investment (note 7)         300           -         300           -
      Abandonment expenditures      (456)       (316)     (1,472)       (368)
    Change in non-cash operating
     working capital              (1,989)      9,452      (5,799)    (18,018)
    -------------------------------------------------------------------------
                                  55,912      39,109     186,569     109,054
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Financing Activities
      Common shares issued for
       cash                            -           -           -     100,620
      Share issue costs                -           -           -      (4,606)
      Proceeds on exercise of
       stock options                  31          52       1,894       1,202
      Increase (decrease) in
       bank indebtedness         (15,591)     25,603       7,785       4,618
    -------------------------------------------------------------------------
                                 (15,560)     25,655       9,679     101,834
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Investing Activities
      Property, plant and
       equipment additions       (61,537)    (72,806)   (202,734)   (194,753)
      Proceeds on disposal of
       property, plant and
       equipment                      84           -       3,716           -
      Property acquisitions         (495)         95        (495)    (27,461)
      Purchase of investments          -           -           -        (150)
      Net cash paid on business
       combination                     -           -           -      (1,091)
      Deferred charges                 -           -           -         251
      Change in non-cash
       investing working
       capital                    21,596       7,947       3,265      12,316
    -------------------------------------------------------------------------
                                 (40,352)    (64,764)   (196,248)   (210,888)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Change in cash                     -           -           -           -
    Cash, beginning of period          -           -           -           -
    -------------------------------------------------------------------------
    Cash, end of period                -           -           -           -
    -------------------------------------------------------------------------
    Cash interest paid             2,290       1,429       9,587       4,865
    Cash taxes paid                  353           -       1,378         263
    -------------------------------------------------------------------------
    See accompanying notes to the consolidated financial statements.


    NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

    Twelve months ended December 31, 2007 and 2006
    (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 amount 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 7). 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 investment is classified as
           available for sale.

           The carrying amount 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
           other-than-temporary impairment identified through this assessment
           would result in a write-down of the investment and a corresponding
           charge to earnings.

        g) Derivative instruments

           The Company may enter into derivative instrument contracts to
           manage its commodity price exposure, foreign exchange exposure and
           interest rate exposure. The Company does not enter into derivative
           instrument contracts for trading or speculative purposes.
           Derivative instruments are recognized on the balance sheet at
           their fair value. 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. Changes in the fair value of the
           effective portion of derivative instruments are recorded in other
           comprehensive income and the ineffective portion is recorded in
           earnings. Changes in the fair value of derivative instruments that
           do not qualify as effective hedges for accounting purposes or were
           not designated as effective hedges at inception are recorded in
           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 preparation of financial statements in accordance with
           Canadian GAAP requires management to make estimates and
           assumptions about the reported amounts of assets and liabilities
           at the date of the financial statements and revenues and expenses
           for the period then ended. 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 and probable
           reserves, production rates, oil and natural gas prices, royalty
           rates, future costs and other relevant assumptions. Amounts
           recorded for future income taxes are based on estimates of the
           timing of the reversal of temporary differences in future periods.
           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.  New Accounting Policies

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

        i)   Financial instruments

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

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

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

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

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

        ii)  Derivative instruments and hedging activities

        The Company may choose to designate derivative instruments as hedges.
        Hedge accounting continues to be optional. No derivatives have been
        designated as hedge instruments.

        iii) Comprehensive income

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

        Future Accounting Changes

        On December 1, 2006, the CICA issued three new accounting standards:
        Section 1535, "Capital Disclosures", Section 3862, "Financial
        Instruments - Disclosures", and Section 3863, "Financial Instruments
        - Presentation". These new standards will be effective on
        January 1, 2008.

        Section 1535 specifies the disclosure of an entity's objectives,
        policies and processes for managing capital, quantitative data about
        what the entity regards as capital, whether the entity has complied
        with any capital requirements, and if it has not complied, the
        consequences of such non-compliance. This section is expected to have
        minimal impact on the Company's financial statements.

        Sections 3862 and 3863 specify a revised and enhanced disclosure on
        financial instruments. These sections will require the Company to
        increase disclosure on the nature and extent of risks arising from
        financial instruments and how the entity manages those risks.

    4.  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
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


    5.  Goodwill

        Pursuant to impairment tests performed at September 30, 2007, it was
        determined that goodwill was impaired and consequently an amount of
        $358.1 million was charged to earnings.

    6.  Property, Plant and Equipment

        ---------------------------------------------------------------------
                                       December 31, 2007         December 31,
                                                                        2006
                                         Accumulated
                                           depletion
                                          and depre-    Net book    Net book
                                    Cost     ciation       value       Value
        ---------------------------------------------------------------------
        Petroleum and natural
         gas properties       $1,371,532  $ (393,184) $  978,348  $  969,784
        Land, buildings and
         leaseholds                2,409        (419)      1,990       2,170
        Office equipment and
         computers                 1,054        (486)        568         645
        ---------------------------------------------------------------------
                              $1,374,995  $ (394,089) $  980,906  $  972,599
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        At December 31, 2007, approximately $83.7 million (December 31, 2006
        - $152.2 million) of unproved property costs and unevaluated seismic
        costs were excluded from the depletion calculation. Future
        development costs of $31.5 million (December 31, 2006 -
        $56.4 million) were included in the depletion calculation. Salvage
        value of $44.4 million (December 31, 2006 - $23.9) was excluded from
        the depletion calculation.

        During the twelve months ended December 31, 2007, cash general and
        administrative expenses of $3.3 million (twelve months ended
        December 31, 2006 - $3.2 million) were capitalized. The Company also
        capitalized $1.8 million (twelve months ended December 31, 2006 -
        $0.9 million) of stock based compensation expense for the twelve
        months ended December 31, 2007.

        The Company performed a ceiling test at December 31, 2007 to assess
        the recoverable value of property, plant and equipment. The future
        oil and natural gas prices are based on the commodity price forecast
        of the Company's independent reserve evaluators. The ceiling test
        incorporated the New Royalty Framework as interpreted by 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.

        ---------------------------------------------------------------------
                                             Natural
                                     Oil         Gas  Condensate        NGLs
                                  ($/bbl)     ($/mcf)     ($/bbl)     ($/bbl)
        ---------------------------------------------------------------------
        2008                   $   84.96   $    7.25   $   86.07   $   58.12
        2009                       83.05        7.77       84.14       56.65
        2010                       79.09        7.93       80.25       54.00
        2011                       76.97        8.08       78.29       52.66
        2012                       74.18        8.23       76.35       51.35
        2013 and thereafter        81.42        9.46       84.33       58.65

        Prices after 2012 escalate at approximately 2% per annum
        ---------------------------------------------------------------------


    7.  Long-Term Investment

        At December 31, 2007, 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.
        Highpine's Chief Executive Officer from inception of the Company
        until February 1, 2008, is a director of In-Depth Resources Ltd. At
        December 31, 2007, Highpine recorded an impairment provision of
        $300,000 against the carrying amount of this investment, which was
        charged to earnings.

    8.  Long-Term Debt

        At December 31, 2007, the Company had available a $230 million
        revolving term credit facility with a syndicate of Canadian financial
        lenders and a $20 million demand operating credit facility with a
        Canadian financial lender.

        The revolving term credit facility has a 364-day extendable revolving
        period plus a one-year maturity. The term date of the revolving term
        credit facility is May 27, 2008. In the event that the term date on
        May 27, 2008 is not extended, the balance under the facility will be
        repayable on May 26, 2009. The revolving term credit facility bears
        interest within a range of the lenders' prime rate to prime plus
        0.25 percent depending on financial ratios of the Company. The demand
        operating facility bears interest at the lenders' prime rate.

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

        Interest expense includes $9.3 million (twelve months ended
        December 31, 2006 - $5.0 million) in respect of debt repayable for a
        period exceeding one year.

    9.  Asset Retirement Obligations

        At December 31, 2007, the estimated total undiscounted cash flows
        required to settle asset retirement obligations were $18.0 million
        (December 31, 2006 - $17.9 million). Expenditures to settle asset
        retirement obligations will be incurred between 2008 and 2028.
        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 months Twelve months
                                                         ended         ended
                                                   December 31,  December 31,
                                                          2007          2006
        ---------------------------------------------------------------------
        Asset retirement obligations, beginning
         of period                                      11,258         5,898
          Liabilities acquired                               -         3,980
          Liabilities incurred                             687         1,069
          Liabilities settled                           (1,472)         (368)
          Accretion expense                                905           679
        ---------------------------------------------------------------------
        Asset retirement obligations, end of period     11,378        11,258
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    10. Share Capital

        Authorized:

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

                                 Twelve months ended     Twelve months ended
                                   December 31, 2007       December 31, 2006
                                  Shares      Amount      Shares      Amount
        ---------------------------------------------------------------------
                              (thousands)($thousands) (thousands)($thousands)
        Class A common shares
        Balance, beginning of
         period                   67,648     957,186      44,250     479,496
          Issued to acquire
           White Fire (note 4)         -           -       4,089      95,480
          Issued to acquire
           Kick (note 4)               -           -      14,831     283,269
          Issued for cash              -           -       4,300     100,620
          Stock options
           exercised                 238       1,894         178       1,202
          Contributed surplus
           transferred on
           exercise of stock
           options                     -         376           -         225
          Share issue costs
           less tax effect of
           (2007 - nil; 2006 -
           $1,500)                     -           -           -      (3,106)
        ---------------------------------------------------------------------
        Balance, end of period    67,886     959,456      67,648     957,186
        ---------------------------------------------------------------------


        Per Share Amounts

        ---------------------------------------------------------------------
                                 Three months ended     Twelve months ended
                                    December 31,            December 31,
                                    2007        2006        2007        2006
                              (thousands) (thousands) (thousands) (thousands)
        ---------------------------------------------------------------------
        Weighted average number
         of common shares
         outstanding
          Basic                   67,884      67,643      67,772      57,744
          Dilutive effect of
           stock options             524         879         684         930
        ---------------------------------------------------------------------
        Diluted                   68,408      68,522      68,456      58,674
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Anti-dilutive options excluded from the calculation of diluted
        earnings per share in 2007 were 4.8 million (2006 - 3.2 million).

        Stock Options

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

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

        A summary of changes is as follows:

        ---------------------------------------------------------------------
                               Twelve months ended     Twelve months ended
                                December 31, 2007       December 31, 2006
        ---------------------------------------------------------------------
                                 Class A                 Class A
                                  Common                  Common
                                  Shares                  Shares
                                Issuable    Weighted    Issuable    Weighted
                                    Upon     Average        Upon     Average
                                Exercise    Exercise    Exercise    Exercise
                              of Options       Price  of Options       Price
        ---------------------------------------------------------------------
                              (thousands)   ($/share) (thousands)   ($/share)
        Balance, beginning of
         period                    5,077       15.80       3,652       13.06
          Granted                  1,785       12.34       2,016       20.42
          Exercised                 (238)      (8.11)       (178)      (6.75)
          Cancelled               (1,822)     (19.21)       (413)     (18.06)
          Repriced                (1,851)     (19.67)          -           -
          Repriced                 1,851       12.05           -           -
        ---------------------------------------------------------------------
        Balance, end of period     4,802       10.68       5,077       15.80
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Exercisable, end of
         period                    1,146        6.10       1,271        9.44
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        Details of the exercise prices and expiry dates of options
        outstanding at December 31, 2007 are as follows:

        ---------------------------------------------------------------------
                              Options Outstanding        Options Exercisable
                              -------------------        -------------------
                                   Weighted   Weighted              Weighted
                          Common    Average    Average     Common    Average
        Range of          Shares   Years to   Exercise     Shares   Exercise
        Exercise price  Issuable     Expiry      Price   Issuable      Price
        ---------------------------------------------------------------------
                      (thousands)    (years)  ($/share)(thousands)  ($/share)
        $2.60 - $3.50        544       1.16    $  2.76        531    $  2.74
        $4.50 - $5.00        359       2.41    $  4.76        269    $  4.76
        $8.10 - $11.00       342       3.61    $  8.92        193    $  8.41
        $11.01 - $15.50    3,297       5.17    $ 12.24         30    $ 14.00
        $17.85 - $18.00      260       3.56    $ 17.98        123    $ 17.99
        ---------------------------------------------------------------------
                           4,802       4.31    $ 10.68      1,146    $  6.10
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

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

        ---------------------------------------------------------------------
                                                        Twelve        Twelve
                                                        months        months
                                                         ended         ended
                                                   December 31,  December 31,
                                                          2007          2006
        ---------------------------------------------------------------------
        Weighted average expected volatility (%)            52            34
        Risk-free rate of return (%)                       4.2           4.9
        Expected option life (years)                         4             4
        Weighted average fair value ($/share)             5.46          7.39
        ---------------------------------------------------------------------

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

        Contributed Surplus

        ---------------------------------------------------------------------
                                                        Twelve        Twelve
                                                        months        months
                                                         ended         ended
                                                   December 31,  December 31,
                                                          2007          2006
        ---------------------------------------------------------------------
        Balance, beginning of period                     9,962         3,627
          Stock-based compensation expense, net of
           recovery                                      4,463         5,677
          Capitalized stock-based compensation expense   1,840           883
          Recovery of capitalized stock-based
           compensation expense                           (859)            -
          Transferred to share capital on exercise
           of stock options                               (376)         (225)
        ---------------------------------------------------------------------
        Balance, end of period                          15,030         9,962
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Deferred Share Units Plan

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

        The Company has recorded a liability of $196,000 as at December 31,
        2007 (2006 - $137,000) relating to 19,595 DSUs outstanding at
        December 31, 2007 (2006 - 8,800).

    11. Financial Instruments

        a) Commodity Price Risk Management

        The Company uses a variety of derivative instruments to reduce its
        exposure to fluctuations in commodity prices. Derivative instruments
        are classified as held for trading and recorded at fair value on the
        consolidated balance sheet. No derivative instruments were designated
        as hedges during the twelve months ended December 31, 2007.

        Realized Financial Instrument Gain

        The realized financial instrument gain of $0.5 million for the twelve
        months ended December 31, 2007 relates to the cash settlement of
        derivative instruments.

        Unrealized Financial Instrument Gain (Loss)

        The unrealized financial instrument loss of $2.8 million for the
        twelve months ended December 31, 2007 represents the change in fair
        value of the Company's financial risk management agreements from
        December 31, 2006 to December 31, 2007. The loss is calculated as
        follows:

        ---------------------------------------------------------------------
                                       Twelve months ended December 31, 2007
        ---------------------------------------------------------------------
        Balance, beginning of period                                   3,194
        Change in fair value of derivative instrument contracts       (2,788)
        ---------------------------------------------------------------------
        Balance, end of period                                           406
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        The following commodity price risk management agreements were in
        place as at December 31, 2007.

        Financial AECO Natural Gas Contracts

        ---------------------------------------------------------------------
                                                                  Unrealized
                                                                  Gain as at
                                                                 December 31,
        Term               Contract  Volume         Fixed Price         2007
                                     (GJs/d)          ($/GJ)      (CDN $000s)
        ---------------------------------------------------------------------
        Jul 06 to Mar 08    Collar    5,000    Cdn $6.00 to $11.10        38
        Feb 07 to Mar 08     Swap     1,250          Cdn $7.68           156
        Feb 07 to Mar 08     Swap     1,250          Cdn $7.70           212
        ---------------------------------------------------------------------

        Subsequent to December 31, 2007, Highpine entered into the following
        contracts:

        --------------------------------------------------------
        Term               Contract  Volume         Fixed Price
                                     (GJs/d)          ($/GJ)
        --------------------------------------------------------
        Apr 08 to Oct 08     Swap     2,500          Cdn $8.01
        Apr 08 to Oct 08     Swap     2,500          Cdn $7.94
        Apr 08 to Oct 08     Swap     2,500          Cdn $8.10
        --------------------------------------------------------

        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 approximated their fair values as at December 31, 2007
           and 2006 with the exception of the Company's long-term investment
           at December 31, 2006 which was carried at cost.

        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.

    12. Commitments

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

        ---------------------------------------------------------------------
        2008                                                       $   1,484
        2009                                                           1,340
        2010                                                           1,226
        2011                                                           1,210
        2012                                                           1,110
        Thereafter                                                         -
        ---------------------------------------------------------------------

    13. 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 32.12 percent (2006 - 34.50 percent) to loss
        before taxes. The difference results from the following:

        ---------------------------------------------------------------------
                                                          2007          2006
        ---------------------------------------------------------------------

        Statutory income tax rate                       32.12%        34.50%

        Computed expected income taxes (reduction)   $(117,550)    $    (397)

        Add (deduct)

        Resource allowance                                   -          (222)
        Large corporation tax                              (46)         (127)
        Stock based compensation                         1,433         1,958
        Impairment of goodwill                         115,020             -
        Effect of change in tax rate and other         (19,779)       (9,320)
        ---------------------------------------------------------------------
                                                     $ (20,922)    $  (8,108)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The components of the future income tax liability at December 31,
        2007 and 2006 are as follows:

        ---------------------------------------------------------------------
                                                          2007          2006
        ---------------------------------------------------------------------
        Property, plant and equipment                $ 100,460     $ 133,018
        Partnership deferral                            44,828        39,770
        Asset retirement obligations                    (2,950)       (3,419)
        Attributed royalty income deductible for
         provincial taxes                               (1,671)       (3,678)
        Share issue costs                               (2,365)       (2,710)
        Loss carryforward                               (7,044)      (12,186)
        Financial instruments                              105           970
        Long-term investments                               (9)           37

        ---------------------------------------------------------------------
        Future income tax liability                  $ 131,354     $ 151,802
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The provision for future income taxes for the year ended December 31,
        2007 was reduced by $22.8 million due to the substantively enacted
        reduction in Canadian federal corporate income tax rates. The
        reduction was recorded in the fourth quarter of 2007.

        The provision for future income taxes for the year 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.

        At December 31, 2007, Highpine had $27.2 million of non-capital loss
        carryforwards remaining. These non-capital losses can be carried
        forward ten to twenty years, depending on the date generated, and can
        be used to offset future taxable income. The loss carryforwards at
        December 31, 2007 expire as follows:

        ---------------------------------------------------------------------
        Year of Expiration                                    Amount of Loss
        ---------------------------------------------------------------------
        2014                                                           6,289
        2015                                                           9,107
        2026                                                          11,760
        ---------------------------------------------------------------------
    

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

    Reader Advisory

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

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

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





For further information:

For further information: Jonathan A. Lexier, President and Chief
Executive Officer, Tel: (403) 508-9550, jlexier@highpineog.com; Harry D.
Cupric, VP Finance & CFO, Tel: (403) 508-9595, hcupric@highpineog.com, Fax:
(403) 508-9503, Website: www.highpineog.com

Organization Profile

Highpine Oil & Gas Limited

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