Real Resources announces 2006 financial and operating results and reserves



    CALGARY, ALBERTA, March 15, 2007 /CNW/ - Real Resources Inc. ("Real" or
the "Company"), ("RER" - "TSX") today disclosed its financial and operating
results for the quarter (unaudited) and fiscal year (audited) ended
December 31, 2006. The Company also updated its year-end reserves, based on an
independent evaluation by Sproule Associates Limited ("Sproule").

    
    -------------------------------------------------------------------------
    HIGHLIGHTS
                                 Three months ended      Twelve months ended
                                     December 31              December 31
    -------------------------------------------------------------------------
    ($ thousands, except                         %                        %
     where noted)               2006     2005 change     2006     2005 change
    -------------------------------------------------------------------------
    FINANCIAL
    Production revenue        48,556   69,765   (30)  214,275  215,271     -
    Cash flow from
     operations(*)            23,455   42,844   (45)  113,052  133,415   (15)
      Per share (basic)(*)   $  0.60  $  1.17   (49)  $  2.98  $  3.92   (24)
      Per share (diluted)(*) $  0.58  $  1.14   (49)  $  2.91  $  3.79   (23)
    Net earnings (loss)       (4,865)  17,808  (127)   23,737   49,065   (52)
      Per share (basic)      $ (0.13) $  0.49  (127)  $  0.63  $  1.44   (66)
      Per share (diluted)    $ (0.13) $  0.48  (127)  $  0.61  $  1.40   (66)
    Net debt                                          157,215   68,571   129
    Total assets                                      668,702  529,681    26
    Shareholders' equity                              381,603  322,084    18
    Net capital expenditures  26,522   67,970   (61)  231,722  269,167   (14)
    Weighted Average common
     shares outstanding
     (thousands)              38,754   37,165     4    37,961   34,031    12

    OPERATING
    Working interest
     production
      Crude oil and liquids
       (bbls/d)                5,600    5,945    (6)    5,884    5,152    14
      Natural gas (mcf/d)     29,834   34,645   (14)   31,293   31,451    (1)
      Total oil equivalent
       (boe/d)                10,573   11,719   (10)   11,100   10,394     7
    Average prices
      Crude oil and liquids
       ($/bbl)                 56.88    59.27    (4)    63.44    58.85     8
      Natural gas ($/mcf)       6.98    11.65   (40)     6.79     9.06   (25)
    Cash flow netback (before
     abandonment)(*) ($/boe)   24.30    39.90   (39)    28.13    35.27   (20)
    Operating costs ($/boe)    10.29     7.64    35      9.32     7.25    29
    General and
     administrative ($/boe)     3.91     1.85   111      2.40     1.64    46
    Wells drilled
      Gross                       20       34   (41)      114      135   (16)
      Net                       16.8     26.7   (37)     94.6    109.9   (14)
    -------------------------------------------------------------------------
    (*) Cash flow from operations is defined as cash flow from operating
        activities before changes in non-cash working capital. Cash flow from
        operations, cash flow from operations per share and corporate
        netbacks are non-GAAP terms that represent net earnings measures
        adjusted for non-cash items on a boe and per share basis. The Company
        evaluates its performance based on these measures. Real
        considers cash flow a key measure as it demonstrates Real's
        ability to generate cash flow necessary to fund future growth through
        capital investment and to repay debt, and because it measures
        profitability relative to current commodity prices. As a result,
        these measures may not be comparable to similar figures presented by
        other issuers.
    

    The operating results for the year 2006 did not achieve the solid growth
of 2004 and 2005.

    Production

    Total production averaged 11,100 boe/d in 2006, up 7% from 10,394 boe/d
in 2005. The lower production growth rate is related to 2006 natural gas
production, while crude oil and liquids production was up by 14%.
    For natural gas, the lack of volume growth was due to a decreased
emphasis on natural gas drilling, especially in the last half of 2006, because
of weak prices for this commodity. In addition, the promising initial results 
of the three gas wells discovered at Two Creeks in West Central Alberta did
not meet our expectations when placed on production.
    During the fourth quarter of 2006, crude oil and liquids production was
down relative to the same period in 2005. Real faced shut-in conditions
associated with a third party pipeline break in the fourth quarter of 2006 in
the Virginia Hills area. The facility additions at Sakwatamau in West Central
Alberta and at Hastings in Southeast Saskatchewan took longer than anticipated
to complete. Therefore, rather than having the facility additions start
operations late in the third quarter, they were not fully operational until
late in the fourth quarter.

    Financial Results

    Production revenue for 2006 was $214.3 million, compared with $215.3
million a year earlier. The gains in total production volume and in crude oil
and liquids prices were offset by the drop in natural gas prices.
    The Company's 2006 cash flow was $113.1 million, down 15% from $133.4
million a year earlier, while 2006 net income was $23.7 million, down 52% from
$49.1 million a year earlier. Operating costs rose substantially, due in part
to increased workover and repair work undertaken primarily in Central and East
Central Alberta. A number of other factors contributed to higher operating
expenses, including inflationary pressures related to the overheated Alberta
economy in 2006. Non-operating expenses were also higher, especially general
and administrative expenses, stock-based compensation expenses and interest on
long-term debt. We believe that the increase in expenses was unavoidable given
Real's business commitments and Alberta's economic environment.
    For the fourth quarter of 2006 production revenue was $48.6 million, down
30% from $69.8 million a year earlier. With this decline, the impact of higher
expenses was especially marked. The result was fourth quarter 2006 cash flow
of $23.5 million, down 45% from $42.8 million a year earlier, and a fourth
quarter 2006 net loss of $4.9 million compared with net income of
$17.8 million a year earlier.

    Reserves

    The Company's December 31, 2006 reserves report was prepared by
independent reserves evaluator Sproule Associates Limited and the preceding
year's reserves report was prepared by our previous reserves evaluator,
Paddock, Lindstrom & Associates Ltd., in each case in accordance with National
Instrument ("NI") 51-101.

    
    Summary of Company Gross Oil and Gas Reserves - Forecast Prices and
     Costs(1)(2)

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                                                           Natural
                                         Crude   Natural       Gas
                                           Oil       Gas   Liquids     Total
                                        (mbbls)    (mmcf)   (mbbls)    (mboe)
    -------------------------------------------------------------------------
    Proved
    -------------------------------------------------------------------------
      Developed producing                7,883    40,584       897    15,544
    -------------------------------------------------------------------------
      Developed non-producing              482     3,939        79     1,218
    -------------------------------------------------------------------------
      Undeveloped                        2,709    18,808       324     6,167
    -------------------------------------------------------------------------
    Total proved                        11,073    63,331     1,300    22,928
    -------------------------------------------------------------------------
    Probable                             5,977    24,500       678    10,738
    -------------------------------------------------------------------------
    Total proved plus
     probable                           17,050    87,831     1,978    33,666
    -------------------------------------------------------------------------
    Note:  May not add due to rounding
      (1)  Gross reserves represent the Company's interest before deducting
           royalties and without including any royalty interest of the
           Company.
      (2)  Where amounts are expressed on a barrel of oil equivalent basis,
           gas volumes have been converted to barrels of oil at 6,000 cubic
           feet per barrel (6mcf/bbl)


    Before Tax Net Present Value of Reserves - Forecast Prices and Costs(1)

    -------------------------------------------------------------------------
                                           Dis-      Dis-      Dis-      Dis-
                               Undis-  counted   counted   counted   counted
                             counted     at 5%    at 10%    at 15%    at 20%
    -------------------------------------------------------------------------
    Proved
    -------------------------------------------------------------------------
       Developed producing   451,313   388,172   343,733   310,762   285,210
    -------------------------------------------------------------------------
       Developed
        non-producing         26,505    22,583    19,679    17,442    15,666
    -------------------------------------------------------------------------
       Undeveloped           139,103   108,187    86,261    70,047    57,633
    -------------------------------------------------------------------------
    Total proved             616,921   518,942   449,674   398,252   358,510
    -------------------------------------------------------------------------
    Probable                 320,827   225,973   173,077   139,564   116,367
    -------------------------------------------------------------------------
    Total proved plus
     probable                937,747   744,915   622,751   537,815   474,877
    -------------------------------------------------------------------------
    Note:  May not add due to rounding
      (1)  As required by NI 51-101, undiscounted well abandonment costs of
           $24.5 million for total proved reserves and $28.8 million for
           total proved plus probable reserves are included in the Net
           Present Value determination.


    Reserves Reconciliation - Forecast Prices and Costs

    -------------------------------------------------------------------------
                                         Heavy             Natural
                               Crude     Crude   Natural       Gas
                                 Oil       Oil       Gas   Liquids     Total
                              (mbbls)   (mbbls)    (mmcf)   (mbbls)    (mboe)
    -------------------------------------------------------------------------
    Total Proved
    -------------------------------------------------------------------------
      Opening balance -
       December 31, 2005      11,482         -    83,459     1,222    26,614
    -------------------------------------------------------------------------
      Discovery                   97         -     4,326        42       859
    -------------------------------------------------------------------------
      Extension                4,289         -    19,525       527     8,069
    -------------------------------------------------------------------------
      Improved Recovery          765         -        31         2       772
    -------------------------------------------------------------------------
      Revisions               (3,618)        -   (32,588)     (286)   (9,335)
    -------------------------------------------------------------------------
      Acquisitions                 -         -         -         -         -
    -------------------------------------------------------------------------
      Dispositions                 -         -         -         -         -
    -------------------------------------------------------------------------
      Production              (1,941)        -   (11,422)     (207)   (4,051)
    -------------------------------------------------------------------------
    Closing balance -
     December 31, 2006        11,073         -    63,331     1,300    22,928
    -------------------------------------------------------------------------
    Total Proved plus
     Probable
    -------------------------------------------------------------------------
      Opening balance -
       December 31, 2005      15,393         -   126,213     1,832    38,261
    -------------------------------------------------------------------------
      Discovery                  156         -     5,293        54     1,092
    -------------------------------------------------------------------------
      Extension                6,985       132    29,137       827    12,800
    -------------------------------------------------------------------------
      Improved Recovery          905         -        43         3       915
    -------------------------------------------------------------------------
      Revisions               (4,578)        -   (61,433)     (532)  (15,350)
    -------------------------------------------------------------------------
      Acquisitions                 -         -         -         -         -
    -------------------------------------------------------------------------
      Dispositions                 -         -         -         -         -
    -------------------------------------------------------------------------
      Production              (1,941)        -   (11,422)     (207)   (4,051)
    -------------------------------------------------------------------------
    Closing balance -
     December 31, 2006        16,918       132    87,831     1,978    33,666
    -------------------------------------------------------------------------
    Note:  May not add due to rounding. Where amounts are expressed on a
           barrel of oil equivalent basis, gas volumes have been converted to
           barrels of oil at 6,000 cubic feet per barrel (6mcf/bbl).
    

    Reserve Life Index

    The Company's reserve life index using 2006 average annual production is
5.7 years for total proved reserves and 8.3 years for total proved plus
probable reserves.

    Comments on Reserves

    The net present value of total proved plus probable reserves at
December 31, 2006 (before income taxes and discounted at 10% per year) is $623
million, essentially unchanged from $627 million estimated as at December 31,
2005 by the previous year's independent reserves evaluator. The value of
Real's reserves and NAV/share (see table below) has remained intact since the
percentage of reserves that are comprised of oil and natural gas liquids
(NGLs) has increased substantially over the last year. At December 31, 2006,
oil and NGLs comprised 57% of the Company's proved and probable reserves, up
from the 45% estimated by our former independent reserves evaluator at
December 31, 2005.
    Total proved plus probable reserves at December 31, 2006 were
33.7 million barrels of oil equivalent at the end of 2006, compared with
38.3 million barrels a year earlier, a volume reduction of 12%. Overall, oil
reserves were higher in 2006 than 2005, but this was more than offset by a
significant downward revision of natural gas reserves due in part to
production performance.
    In the five years prior to December 31, 2006,  Real's total proved
reserves and total proved plus probable reserves grew by volume at annualized
compound rates of 14% per year and 19% per year, respectively.

    Net Asset Value at December 31, 2006

    In the following table, Real's net asset value is calculated with
reference to the before tax net present value of future cash flows from
reserves, as estimated by Sproule. The calculation is shown using the Sproule
December 31, 2006 escalated price and cost forecasts.

    
    ($ thousands, except per share amounts)
    -------------------------------------------------------------------------
    Before Tax Net Present Value
    of Proved plus Probable Reserves discounted at 10%               622,751
    -------------------------------------------------------------------------
    Undeveloped Lands(1)                                              84,238
    -------------------------------------------------------------------------
    Seismic - 100% Proprietary(2)                                     73,028
    -------------------------------------------------------------------------
    Net Debt                                                        (157,215)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net Asset Value                                                  622,802
    -------------------------------------------------------------------------
    Net Asset Value per Basic Share ($/share)                          16.05
    -------------------------------------------------------------------------
    Net Asset Value per Fully Diluted Share ($/share)                  15.98
    -------------------------------------------------------------------------
    (1)    As estimated by Seaton-Jordan & Associates Ltd. as of December 31,
           2006
    (2)    As estimated by Boyd Exploration Consultants Ltd. as of
           December 31, 2006
    

    Capital Program

    Capital spending totaled $231.7 million in 2006, down 14% from
$269.2 million in 2005. Real spent more in 2006 than in 2005 on drilling,
completions, facilities, equipment and pipelines, all of which enhance value.
Having established a deep inventory of opportunities, in 2006 Real shifted
towards increased drilling and capital expenditures were reduced in the
following areas:

    
    -   acquisitions ($5.4 million in 2006, down 92% from $68.5 million
        in 2005);
    -   land ($22.3 million in 2006, down 37% from $35.6 million in 2005);
        and
    -   seismic ($26.5 million in 2006, down 16% from $31.5 million in 2005).
    

    During 2006 Real drilled 114 wells (94.6 net), compared with 135 wells
(109.9 net) in 2005. However, wells drilled in 2006 were deeper and more
expensive than in 2005, when a substantial number of shallow gas wells were
drilled.

    Outlook for 2007

    In first quarter of 2007 Real drilled 20 (19.8 net) wells, resulting in
10 (10.0 net) oil wells, 4 (3.75 net) gas wells, 1 (1.0 net) service well and
5 (5.0 net) dry holes. A total of 11 (10.8 net) exploratory wells were drilled
resulting in a new discovery in the Devonian in West Central Alberta, a
Glauconitic gas success in Central Alberta and a new oil pool identified in
Southeast Saskatchewan. All three of these discoveries have follow up
development drilling opportunities.
    In 2007, Real intends to maintain capital expenditures within cash flow.
Real will reduce it's capital expenditures on the acquisition of land and
seismic data in 2007 to approximately one half the 2006 expenditure level.
Similarly, Real is reducing it's capital expenditures on facilities in 2007 to
approximately two thirds of the 2006 expenditure level. Accordingly, a greater
proportion of capital expenditures will be directed towards drilling.
    Real is fortunate that it has had consistent and continuous leadership
from it's senior executive team. However, changes do take place from time to
time and subsequent to our year-end, Real's VP Finance and Chief Financial
Officer Pamela Orr resigned after five years of valued service. Pam built a
strong financial team that will carry on as Real searches for her replacement.

    Summary

    Real has a long track record for success, a clear strategy for improved
results in 2007 and confidence in it's ability to deliver growth and value in
2007. As always, Real thanks you for your patience and support.


    On behalf of the Board of Directors


    Lowell E. Jackson, P.Eng.

    President, Chief Executive Officer and
    Acting Chief Financial Officer
    March 15, 2007


    Management's Discussion and Analysis

    The following discussion and analysis, which was prepared on March 13,
2007, is management's assessment of Real's historical financial and operating
results and should be read in conjunction with the audited Consolidated
Financial Statements of the Company for the years ended December 31, 2006 and
2005 together with the notes related thereto. Readers should also refer to the
Renewal Annual Information Form for the year ended December 31, 2006,
scheduled to be filed on SEDAR. The reader should be aware that historical
results are not necessarily indicative of future performance. This discussion
contains certain forward-looking statements and forward-looking information
which are based on the Company's current internal expectations, estimates,
projections, assumptions and beliefs. The use of any of the words
"anticipate", "continue", "estimate", "expect", "may", "will", "project",
"plan", "should", "believe", and similar expressions are intended to identify
forward-looking statements and forward-looking information. These statements
are not guarantees of future performance and involve known and unknown risks,
uncertainties and other factors that may cause actual results or events to
differ materially from those anticipated in such forward-looking statements or
information. The Company believes the expectations reflected in those
forward-looking statements and information are reasonable but no assurance can
be given that these expectations will prove to be correct, and such
forward-looking statements and information included in this discussion should
not be unduly relied upon. Such forward-looking statements and information
speak only as of the date of this discussion and the Company does not
undertake any obligation to publicly update or revise any forward-looking
statements or information, except as required by applicable laws.

    
    In particular, this discussion contains forward-looking statements and
information pertaining to the following:
    -   the quality of and future net revenues from the Company's reserves;
    -   oil, liquids and natural gas production levels;
    -   commodity prices, foreign currency exchange rates and interest rates;
    -   capital expenditure programs and other expenditures;
    -   supply and demand for oil, liquids and natural gas;
    -   expectations regarding the Company's ability to raise capital and to
        continually add to reserves through acquisitions and development;
    -   schedules and timing of certain projects and the Company's strategy
        for growth;
    -   the Company's future operating and financial results; and
    -   treatment under governmental and other regulatory regimes and tax,
        environmental and other laws.

    The Company's actual results could differ materially from those
anticipated in these forward-looking statements and information as a result of
both known and unknown risks, including the risk factors set forth under
"Risks and Uncertainties" in this discussion and those set forth below:
    -   volatility in market prices for oil, liquids and natural gas;
    -   changes or fluctuations in oil, liquids and natural gas production
        levels;
    -   changes in foreign currency exchange rates and interest rates;
    -   changes in capital and other expenditure requirements and debt
        service requirements;
    -   liabilities and unexpected events inherent in oil and natural gas
        operations, including geological, technical, drilling and processing
        problems;
    -   uncertainties associated with estimating reserves;
    -   competition for, among other things, capital, acquisition of
        reserves, undeveloped lands and skilled personnel;
    -   incorrect assessments of the value of acquisitions;
    -   the Company's success at acquisition, exploitation and development of
        reserves;
    -   changes in general economic, market and business conditions in
        Canada, North America and worldwide;
    -   actions by governmental or regulatory authorities including changes
        in income tax laws or changes in tax laws and incentive programs
        relating to the oil and natural gas industry; and
    -   changes in environmental or other legislation applicable to the
        Company's operations, and the Company's ability to comply with
        current and future environmental and other laws.

    Many of these risk factors and other specific risks and uncertainties are
discussed in further detail throughout this discussion and analysis as well as
the Renewal Annual Information Form. Additional information related to the
Company, including the Company's Renewal Annual Information Form, is available
through the Internet on the Company's SEDAR profile at www.sedar.com. Readers
are also referred to the risk factors described in other documents the Company
files from time to time with securities regulatory authorities. Copies of
these documents are available without charge from the Company.


    2006 SUMMARY

    Crude oil and liquids production in 2006 increased by 14 percent to
5,884 bbls/d from 5,152 bbls/d in 2005. Natural gas production in 2006
decreased marginally to 31.3 mmcf/d from 31.5 mmcf/d in 2005. Total production
on a boe basis grew by seven percent to 11,100 boe/d in 2006 from 10,394 boe/d
in 2005. The Company's 2006 drilling program and the full year impact of the
2005 drilling program continued to add crude oil production volumes, however
natural gas production was essentially flat. The absence of growth in natural
gas production is the direct result of the implementation of the Company's
strategy that saw a decreased emphasis on natural gas drilling pending
commodity price recovery in the natural gas markets.

    DETAILED FINANCIAL ANALYSIS

    PRODUCTION REVENUE

    Production revenue summary                     Years ended December 31
    -------------------------------------------------------------------------
    ($ thousands)                                   2006      2005  % change
    -------------------------------------------------------------------------
    Crude oil and liquids revenue                136,265   110,638        23
    Natural gas revenue                           77,535   103,960       (25)
    -------------------------------------------------------------------------
                                                 213,800   214,598         -
    Royalty income                                   475       673       (30)
    -------------------------------------------------------------------------
    Total production revenue                     214,275   215,271         -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Production revenue from crude oil, liquids and natural gas sales remained
at approximately the same level as the previous year at $214.3 million in 2006
as compared to $215.3 million in 2005. Higher crude oil production volumes and
to a lesser extent, higher realized crude oil prices were offset by lower
realized natural gas prices. The variance analysis table following the price
analysis summarizes the factors contributing to the slight decrease.
    Average crude oil and liquids production for the year increased by
732 bbls/d (14 percent) to 5,884 bbls/d from 5,152 bbls/d in 2005. Crude oil
and liquids production in 2006 included the full year impact of the successful
2005 drilling program in Central and West Central Alberta as well as the 2006
drilling activity in the Southeast Saskatchewan area. Average natural gas
production for the year decreased marginally to 31.3 mmcf/d from 31.5 mmcf/d
in 2005. The full year impact of the 2005 drilling program in Southern Alberta
as well as the tie-in of the Two Creeks properties in West Central Alberta
contributed approximately 3.5 mmcf/d to average production levels. These
natural gas production additions were offset by natural declines on the
existing production base, mainly in the Scandia area.

    The following table summarizes the commodity prices realized during 2006
and 2005:

                                                   Years ended December 31
    -------------------------------------------------------------------------
    Average realized price                          2006      2005  % change
    -------------------------------------------------------------------------
    Crude oil and liquids ($/bbl)                  63.44     58.85         8
    Natural gas ($/mcf)                             6.79      9.06       (25)
    -------------------------------------------------------------------------
    Total average realized price ($/boe)           52.77     56.57        (7)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

                                                   Years ended December 31
    -------------------------------------------------------------------------
    Average realized price ($/boe)                  2006      2005  % change
    -------------------------------------------------------------------------
    Production revenue                             52.77     56.57        (7)
    Royalty income                                  0.13      0.18       (28)
    -------------------------------------------------------------------------
    Total average realized price                   52.90     56.75        (7)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    West Texas Intermediate ("WTI") is the benchmark for North American oil
prices and is the crude type against which NYMEX futures contracts are priced.
Canadian crude oil prices are based upon refiners' postings at Alberta hubs
such as Edmonton and Hardisty. These postings represent the WTI price at
Cushing, Oklahoma less a transportation differential, the Canadian/US foreign
exchange rate, and an adjustment for regional market conditions.
    Real's average field prices reflect the refiners' posted price at the
market centers less adjustments for product quality relative to the posted
product and includes the quality differential on natural gas liquids.

                                                   Years ended December 31
    -------------------------------------------------------------------------
    Crude oil and liquids prices ($/bbl)            2006      2005  % change
    -------------------------------------------------------------------------
    WTI ($US)(*)                                   66.22     56.56        17
    Average exchange rate ($Cdn/$US)(*)             1.13      1.21        (7)
    -------------------------------------------------------------------------
    WTI (converted to $Cdn)                        74.83     68.44         9
    Differential WTI to Edmonton ($Cdn)            (2.06)     0.28       736
    -------------------------------------------------------------------------
    Edmonton light sweet posting ($Cdn)(*)         72.77     68.72         6
    Quality differential (including NGL
     differential)                                 (9.33)    (9.87)       (5)
    -------------------------------------------------------------------------
    Average realized price ($Cdn)                  63.44     58.85         8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (*) Source - CAPP Crude Oil Report - Refiner postings, Bank of Canada
        noon spot rate

    The sizable increase in the WTI benchmark price for crude oil during 2006
was partially offset by the impact of a stronger Canadian dollar when compared
to the corresponding period in 2005. The differential between WTI converted to
Canadian dollars and the Edmonton light sweet posting showed a marked
deterioration during the first quarter of 2006 as compared to 2005, returned
to comparable 2005 levels during the second and third quarters of 2006 and
deteriorated again during the fourth quarter of 2006 versus 2005. The Company
realized an average crude oil and liquids price of $63.44 per bbl in 2006,
eight percent higher than the $58.85 per bbl realized in 2005.
    Alberta natural gas prices are typically referenced to AECO "C".

                                                   Years ended December 31
    -------------------------------------------------------------------------
    Natural gas prices ($/mcf)                      2006      2005  % change
    -------------------------------------------------------------------------
    AECO "C"(*)                                     6.54      8.77       (25)
    Variance: Real pool price vs. spot              0.25      0.29       (14)
    -------------------------------------------------------------------------
    Average realized natural gas price              6.79      9.06       (25)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (*) Source - CAPP Natural Gas Report - calendar month average of daily
        cash prices (weighted)

    The significant weakening in the gas markets caused a 25 percent decrease
in average AECO "C" prices and was the primary contributing factor in the
Company's lower average realized price of $6.79 per mcf in 2006 compared to
$9.06 per mcf in 2005.
    During the fourth quarter of 2006 the Company initiated a more active
marketing program with a balanced portfolio of AECO daily index sales, AECO
monthly index sales and a selection of fixed forward sales contracts (which
expire at the end of the first quarter of 2007). Details of these contracts
can be found in Note 6 to the Financial Statements.
    The following table summarizes the impact of the Company's production
activities and prices on oil and gas revenue:

    Variance analysis                                  ($ millions) % change
    -------------------------------------------------------------------------
    Reported 2005 production revenue                         215.3
    -------------------------------------------------------------------------
    Increase due to crude oil and liquids volumes             15.5     1,550
    Increase due to realized crude oil and liquids price       9.9       990
    Decrease due to realized gas price                       (25.9)   (2,590)
    Decrease due to gas production volumes                    (0.5)      (50)
    -------------------------------------------------------------------------
    Total decrease, net                                       (1.0)     (100)
    -------------------------------------------------------------------------
    Reported 2006 production revenue                         214.3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    ROYALTY EXPENSE

    Total royalties (net of ARTC) increased by two percent to $42.2 million in
2006 from $41.4 million in 2005. Total royalties reported (net of ARTC) as a
percentage of gross revenue increased to 19.7 percent in 2006 from
19.2 percent in 2005. Included in the Crown royalty expense for 2006 are
$2.2 million in recoveries that relate to 2005 and prior years. The prior year
recoveries include $1.0 million from properties that were exempt from Crown
royalties, $0.4 million related to overpaid freehold oil and gas production
taxes, as well as $0.8 million due to prior year West Provost and gas cost
allowance amendments recorded in the fourth quarter of 2006. The average
royalty rate for 2006 excluding these recoveries was 20.9 percent compared to
the 2005 average rate (adjusted for these recoveries) of 18.2 percent. The
increase in the adjusted royalty rate is primarily due to higher average
freehold and gross over-riding royalty rates. This is mainly due to increased
production from freehold properties in Saskatchewan.

    Royalty expense                                Years ended December 31
    -------------------------------------------------------------------------
    ($ thousands, except where noted)               2006      2005  % change
    -------------------------------------------------------------------------
    Crown                                         27,322    29,262        (7)
    Freehold and GORR                             15,388    12,585        22
    -------------------------------------------------------------------------
    Total royalties                               42,710    41,847         2
    ARTC                                            (500)     (487)        3
    -------------------------------------------------------------------------
    Total royalties, net of ARTC                  42,210    41,360         2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total royalties ($/boe)                        10.54     11.03        (4)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total royalties, net of ARTC ($/boe)           10.42     10.90        (4)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Average royalty rates                          Years ended December 31
    -------------------------------------------------------------------------
    (% of revenue)                                  2006      2005  % change
    -------------------------------------------------------------------------
    Crown                                           12.8      13.6        (6)
    Freehold and GORR                                7.2       5.8        24
    -------------------------------------------------------------------------
    Total royalties                                 20.0      19.4         3
    ARTC                                            (0.2)     (0.2)        -
    -------------------------------------------------------------------------
    Total royalties, net of ARTC                    19.8      19.2         3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    OPERATING EXPENSES

    Operating expenses in 2006 increased by 37 percent to $37.7 million
compared to $27.5 million in 2005. Operating costs increased mainly due to
increased workover and repair work undertaken primarily in the Central and
East Central areas of Alberta. Higher emulsion trucking charges were incurred
at Virginia Hills in West Central Alberta as a direct result of a third party
pipeline break that resulted in emulsion being trucked out of the area
temporarily. Electricity costs also increased substantially due to the higher
rates experienced during a good portion of the year. The increased operating
costs were reflected in higher unit-of-production rates. Operating expenses on
a unit-of-production basis increased to $9.32 per boe in 2006 from $7.25 per
boe in 2005. Inflationary pressures also continued to drive up the industry's
overall operating cost structure when compared to 2005.

    Operating expenses                             Years ended December 31
    -------------------------------------------------------------------------
    ($ thousands, except where noted)               2006      2005  % change
    -------------------------------------------------------------------------
    Operating expenses                            37,749    27,502        37
    Operating expenses ($/boe)                      9.32      7.25        29
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    TRANSPORTATION COSTS

    Transportation costs in 2006 increased by 28 percent to $3.7 million from
$2.9 million in 2005. Transportation costs on a unit-of-production basis
increased 20 percent to $0.91 per boe in 2006 from $0.76 per boe in 2005. The
unit-of-production rate increased primarily due to the increase in the amount
and unit cost of transporting clean oil in the Ferrybank area.

    Transportation costs                           Years ended December 31
    -------------------------------------------------------------------------
    ($ thousands, except where noted)               2006      2005  % change
    -------------------------------------------------------------------------
    Transportation costs                           3,703     2,898        28
    Transportation costs ($/boe)                    0.91      0.76        20
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    OPERATING NETBACK

    Operating netbacks (excluding ARTC) decreased 15 percent to $32.13 per boe
for 2006 compared to $37.71 per boe for 2005. This decrease was primarily due
to lower realized natural gas prices and higher operating expenses offset
partially by higher realized crude oil prices.

    Operating netback(*)                           Years ended December 31
    -------------------------------------------------------------------------
    ($/boe)                                         2006      2005  % change
    -------------------------------------------------------------------------
    Production revenue                             52.77     56.57        (7)
    Royalty income                                  0.13      0.18       (28)
    -------------------------------------------------------------------------
                                                   52.90     56.75        (7)
    Total royalties (excluding ARTC)              (10.54)   (11.03)       (4)
    Operating expenses                             (9.32)    (7.25)       29
    Transportation costs                           (0.91)    (0.76)       20
    -------------------------------------------------------------------------
    Operating netback                              32.13     37.71       (15)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Operating netback - crude oil properties       Years ended December 31
    -------------------------------------------------------------------------
    ($/bbl)                                         2006      2005  % change
    -------------------------------------------------------------------------
    Production revenue                             62.78     58.66         7
    Royalty income                                  0.10      0.14       (29)
    -------------------------------------------------------------------------
                                                   62.88     58.80         7
    Total royalties (excluding ARTC)              (11.54)   (10.39)       11
    Operating expenses                            (10.07)    (9.48)        6
    Transportation costs                           (1.02)    (0.76)       34
    -------------------------------------------------------------------------
    Operating netback                              40.25     38.17         5
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Operating netback - natural gas properties     Years ended December 31
    -------------------------------------------------------------------------
    ($/equivalent mcf)(*)                           2006      2005  % change
    -------------------------------------------------------------------------
    Production revenue                              7.16      9.22       (22)
    Royalty income                                  0.02      0.03       (33)
    -------------------------------------------------------------------------
                                                    7.18      9.25       (22)
    Total royalties (excluding ARTC)               (1.59)    (1.90)      (16)
    Operating expenses                             (1.43)    (0.99)       44
    Transportation costs                           (0.14)    (0.13)        8
    -------------------------------------------------------------------------
    Operating netback                               4.02      6.23       (35)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (*) equivalent mcf includes natural gas liquids production converted on a
        basis of 1 bbl equals 6 mcf


    GENERAL AND ADMINISTRATIVE EXPENSES

    Gross general and administrative expenses increased 33 percent to
$15.9 million in 2006 compared to $11.9 million in 2005. The increase is
primarily due to increased staffing levels associated with the Company's
capital program. Also included in 2006 are unusual costs related to the
following: $0.3 million - legal fees associated with a legal dispute related
to a producing property; $0.4 million - additional costs associated with the
CBM resource evaluation conducted by the Company's reserves evaluators as well
as one-time costs associated with the change in the evaluator that took place
this year; $0.4 million - marketing strategy costs related to long term crude
oil and natural gas marketing initiatives; and $0.2 million associated with
Canadian Securities regulatory compliance matters related to documenting the
design of financial controls. Also included in the first quarter of 2005 was a
one-time charge of $0.6 million related to a corporate restructuring. On a
unit-of-production basis, net general and administrative expenses increased
46 percent to $2.40 per boe from $1.64 per boe.

    General and administrative expenses             Years ended December 31
    -------------------------------------------------------------------------
    ($ thousands)                                   2006     2005   % change
    -------------------------------------------------------------------------
    Gross expense                                 15,903    11,930        33
    Overhead recoveries                           (3,257)   (3,114)        5
    -------------------------------------------------------------------------
    Subtotal                                      12,646     8,816        43
    Capitalized expense                           (2,920)   (2,607)       12
    -------------------------------------------------------------------------
    Net expense                                    9,726     6,209        57
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Average cost per barrel of oil equivalent       Years ended December 31
    -------------------------------------------------------------------------
    ($/boe)                                         2006      2005  % change
    -------------------------------------------------------------------------
    Gross expense                                   3.92      3.14        25
    Overhead recoveries                            (0.80)    (0.82)       (2)
    -------------------------------------------------------------------------
    Subtotal                                        3.12      2.32        34
    Capitalized expense                            (0.72)    (0.68)        6
    -------------------------------------------------------------------------
    Net expense                                     2.40      1.64        46
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    STOCK-BASED COMPENSATION

    Stock-based compensation costs increased significantly in 2006 from 2005.
Included in 2006 is the expense associated with the options that were granted
during the second quarter of 2006 as part of the Company's normal compensation
program. The valuation of these options increased due to higher strike prices
(based on the Black-Scholes option pricing model). Included in 2006 was an
adjustment of $0.4 million related to 2005 and prior years resulting from the
change in the amortization assumptions underlying the expense.

    Stock-based compensation                        Years ended December 31
    -------------------------------------------------------------------------
    ($ thousands, except where noted)               2006      2005  % change
    -------------------------------------------------------------------------
    Stock-based compensation                       5,223     1,437       263
    Stock-based compensation ($/boe)                1.29      0.38       239
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    INTEREST EXPENSE

    Interest expense for 2006 increased 199 percent to $5.3 million from
$1.8 million in 2005. Average debt levels during 2006 were 140 percent higher
than during 2005, a direct result of the Company's capital expenditure
program. The all-inclusive cost of borrowing averaged 5.3 percent in 2006
compared to 4.2 percent in 2005, the direct result of the increase in prime
lending rates.

    Interest expense                                Years ended December 31
    -------------------------------------------------------------------------
    ($ thousands, except where noted)               2006      2005  % change
    -------------------------------------------------------------------------
    Interest expense                               5,318     1,776       199
    Interest expense ($/boe)                        1.31      0.47       179
    Average debt outstanding                     100,600    41,800       140
    Average effective interest rate (%)              5.3       4.2        26
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    DEPLETION, DEPRECIATION AND ACCRETION (DD&A)

    DD&A expense increased 48 percent to $86.8 million in 2006 from
$58.6 million in 2005 mainly due to a higher average depletion rate per boe.
The DD&A rate increased to $21.42 per boe during 2006 compared to $15.45 per
boe in 2005. The higher DD&A rate reflects the impact of the Company's 2006
capital spending program of $231.7 million which added approximately
9.7 million proved barrels of oil equivalent reserves, offset by downward
revisions of approximately 9.4 proved barrels relating to 2006 property
production performance, particularly in our gas properties, as well as the
evaluation parameters utilized by the new reserve evaluators in 2006. Lastly,
the DD&A rate was also impacted by continued upward pressure on capital costs
in 2006 due to the increased overall industry activity.

    Depletion, depreciation and accretion           Years ended December 31
    -------------------------------------------------------------------------
    ($ thousands, except where noted)               2006      2005  % change
    -------------------------------------------------------------------------
    Depletion and depreciation                    85,529    57,638        48
    Accretion on asset retirement obligation       1,240       971        28
    -------------------------------------------------------------------------
                                                  86,769    58,609        48
    -------------------------------------------------------------------------
    Depletion, depreciation and accretion
     ($/boe)                                       21.42     15.45        39
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    CEILING TEST

    Real performs a ceiling test calculation at least annually in accordance
with the Canadian Institute of Chartered Accountants' full cost accounting
guidelines. The recovery of costs is tested by comparing the carrying amount
of the oil and natural gas assets to the undiscounted cash flows from those
assets using proved reserves and expected future prices and costs. If the
carrying amount exceeds the recoverable amount, then an impairment would be
recognized on the amount by which the carrying amount of the assets exceeds
the present value of expected cash flows using proved and probable reserves
and expected future prices and costs. No write-down was required for the years
ended December 31, 2006 and December 31, 2005. The following table summarizes
the expected future commodity prices that were used in the ceiling test
calculation:

                                 Oil Price       Gas Price       NGL Price
    -------------------------------------------------------------------------
    Year ending December 31     2006    2005    2006    2005    2006    2005
    -------------------------------------------------------------------------
    2006                           -   62.16       -   10.35       -   54.63
    2007                       65.90   59.22    7.79    9.31   53.95   51.98
    2008                       68.47   56.33    8.61    8.12   56.31   49.52
    2009                       61.43   53.48    7.75    7.50   51.28   47.13
    2010                       57.16   50.69    7.56    6.88   48.04   44.34
    2011                       54.02   47.99    7.73    7.02   45.69   42.15
    Thereafter                 61.57   55.04    8.71    8.29   53.19   50.35
    Average                    62.84   56.12    8.23    8.49   52.20   50.09
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    TAXES

    In 2006 the Company had a future income tax net recovery of $1.8 million
as compared to a $24.7 million expense recorded in 2005, which represented a
decrease of 107 percent. This is primarily due to lower earnings before tax as
well as the 2006 recovery from reduced future corporate income tax rates
announced in the second quarter of 2006. During the second quarter a number of
corporate tax initiatives were announced by the Alberta, Saskatchewan and
federal Governments. Details of these reductions are disclosed in the
Company's June 30, 2006 Management's Discussion and Analysis. These
announcements resulted in the recovery of $10.7 million that was recognized in
the Company's future tax obligation during the second quarter of 2006.
    The Company's capital tax expense of $1.7 million for 2006 represents a
decrease of 6 percent from $1.8 million in the preceding year. The capital tax
expense is currently comprised only of the Saskatchewan surcharge on
properties operated in that province. Real paid no current income tax in 2006.

    Taxes                                           Years ended December 31
    -------------------------------------------------------------------------
    ($ thousands, except where noted)               2006      2005  % change
    -------------------------------------------------------------------------
    Future income taxes                           (1,817)   24,659      (107)
    Effective income tax rate (%)                   (7.7)     32.7      (124)
    Capital taxes                                  1,657     1,756       (94)
    -------------------------------------------------------------------------
    Total taxes                                     (160)   26,415      (101)
    -------------------------------------------------------------------------
    Total taxes ($/boe)                            (0.04)     6.96      (101)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    At the end of 2006, Real had approximately $342.8 million of accumulated
tax pools that are available for deduction against future earnings compared to
$226.2 million at December 31, 2005, as a result of the capital expenditure
program in 2006. Outstanding commitments relating to the July 2006 flow
through share offering amounted to $18.9 million at December 31, 2006.

    Summary of tax pools at December 31, 2006
    -------------------------------------------------------------------------
                                                       Maximum       Maximum
                                                     available        annual
    ($ thousands)                                      balance     deduction
    -------------------------------------------------------------------------
    Canadian exploration expense                             0          100%
    Canadian development expense                       105,787           30%
    Canadian oil & gas property expense                116,429           10%
    Undepreciated capital cost                         112,408         4-30%
    Non-capital loss                                     2,053           10%
    Share issue costs                                    6,142           20%
    Other                                                    6            7%
    -------------------------------------------------------------------------
    Total                                              342,825
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    NET EARNINGS, NETBACKS AND CASH FLOW FROM OPERATIONS

    Net Earnings

    Net earnings decreased 52 percent to $23.7 million in 2006 from
$49.1 million in 2005. Net earnings per basic share decreased 66 percent to
$0.63 per share in 2006 from $1.44 per share in 2005. Similarly, net earnings
per diluted share decreased 66 percent to $0.61 per share in 2006 from $1.40
per share in 2005.

    Netbacks(*)

                                                    Years ended December 31
    -------------------------------------------------------------------------
    ($/boe)                                         2006      2005  % change
    -------------------------------------------------------------------------
    Production revenue                             52.90     56.75        (7)
    Net royalties                                 (10.42)   (10.90)       (4)
    Operating expenses                             (9.32)    (7.25)       29
    Transportation costs                           (0.91)    (0.76)       20
    -------------------------------------------------------------------------
    Operating netback                              32.25     37.84       (15)
    General and administrative expenses            (2.40)    (1.64)       46
    Interest expense                               (1.31)    (0.47)      179
    Current taxes                                  (0.41)    (0.46)      (11)
    -------------------------------------------------------------------------
    Cash flow netback (before abandonment)         28.13     35.27       (20)
    Depletion, depreciation and accretion         (21.42)   (15.45)       39
    Future income taxes                             0.45     (6.50)     (107)
    Stock-based compensation                       (1.29)    (0.38)      239
    -------------------------------------------------------------------------
    Corporate netback (before abandonment)          5.87     12.94       (55)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (*) equivalent mcf includes natural gas liquids production converted on a
        basis of 1 bbl equals 6 mcf

    Cash Flow from Operations

    Cash flow from operations decreased 15 percent to $113.1 million in 2006
from $133.4 million in 2005. Cash flow from operations per weighted-average
basic share decreased 24 percent to $2.98 per share in 2006 from $3.92 per
share in 2005. Cash flow from operations per diluted share decreased
23 percent to $2.91 per share from $3.79 per share. The decrease in cash flow
from operations during 2006 was mainly due to the decreased realized natural
gas price, as well as the increase in operating expenses, partially offset by
the Company's increased oil production and the higher realized oil price.

                                                    Years ended December 31
    -------------------------------------------------------------------------
    ($ thousands)                                   2006      2005  % change
    -------------------------------------------------------------------------
    Net earnings                                  23,737    49,065       (52)
    Non cash items:
      Depletion, depreciation and accretion       86,769    58,609        48
      Future income tax expense                   (1,817)   24,659      (107)
      Stock-based compensation                     5,223     1,437       263
    Abandonment expenditures                        (860)     (355)      142
    -------------------------------------------------------------------------
    Cash flow from operations                    113,052   133,415       (15)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                                                    Years ended December 31
    -------------------------------------------------------------------------
    (thousands)                                     2006      2005  % change
    -------------------------------------------------------------------------
    Weighted average outstanding shares
      Basic                                       37,961    34,031        12
      Diluted                                     38,875    35,170        11
    Outstanding shares at December 31
      Basic                                       38,803    37,252         4
      Diluted                                     39,717    38,391         3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                                                    Years ended December 31
    -------------------------------------------------------------------------
    Per share information ($ thousands,
     except where noted)                            2006      2005  % change
    -------------------------------------------------------------------------
    Net earnings                                  23,737    49,065       (52)
      Basic ($/share)                               0.63      1.44       (66)
      Diluted ($/share)                             0.61      1.40       (66)

    Cash flow from operations                    113,052   133,415       (15)
      Basic ($/share)                               2.98      3.92       (24)
      Diluted ($/share)                             2.91      3.79       (23)

    Total assets                                 668,702   529,681        26
      Basic ($/share)                              17.62     15.56        13
      Diluted ($/share)                            17.20     15.06        14

    Book value (shareholders' equity)            381,603   322,084        18
      Basic ($/share)                              10.05      9.46         6
      Diluted ($/share)                             9.82      9.16         7
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    CAPITAL EXPENDITURES

    Real executes its strategy through exploration, exploitation and
development activities supplemented with strategic property and corporate
acquisitions. Net capital expenditures in 2006 before asset retirement
obligations were $231.7 million compared to $269.2 million in 2005.
Approximately one half of the facilities, equipment and pipeline expenditures
related to the installation of infrastructure in the Two Creeks and Sakwatamau
areas in West Central Alberta. All expenditures are summarized as follows:

    Capital expenditures                            Years ended December 31
    -------------------------------------------------------------------------
    ($ thousands)                                   2006      2005  % change
    -------------------------------------------------------------------------
    Exploration and development expenditures
      Lease acquisition                           22,330    35,629       (37)
      Geological and geophysical                  26,511    31,535       (16)
      Drilling and completion                    108,453    99,737         9
      Facilities, equipment and pipelines         68,234    33,022       107
    -------------------------------------------------------------------------
    Total exploration and development
     expenditures                                225,528   199,923        13
      Other expenditures                             821       778         6
    -------------------------------------------------------------------------
    Gross capital expenditures                   226,349   200,701        13
      Corporate acquisition (note 3 for 2005
       comparatives)                                   -    31,606      (100)
      Property acquisitions (note 3 for 2005
       comparatives)                               5,378    36,938       (85)
      Proceeds from property dispositions             (5)      (78)      (94)
    -------------------------------------------------------------------------
    Net capital expenditures before
     the following:                              231,722   269,167       (14)
      Asset retirement obligation                  1,525     3,187       (52)
      Asset retirement obligation on
       corporate acquisition                           -       458      (100)
      Future income tax gross-up on
       corporate acquisition                           -    13,709      (100)
      Future income tax gross-up on property
       acquisitions                                    -     5,666      (100)
    -------------------------------------------------------------------------
    Net capital expenditures                     233,247   292,187       (20)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Funding for capital expenditures and acquisitions was provided for by cash
flow from operations, current debt lines and the net proceeds received by the
Company from the issuance of equity.


    CAPITALIZATION AND FINANCIAL RE

SOURCES On November 3, 2006 the Company completed a review of its financing commitment with its banking syndicate which is made up of three Canadian chartered banks. At that time the commitment was increased to $185 million from $180 million. This commitment provides for an extendible revolving term credit facility. At the end of the year, Real had drawn $132.4 million of this facility. In addition to this debt, Real had a working capital deficiency of $24.8 million for a total net debt of $157.2 million. The ratio of total net debt as at December 31, 2006 to 2006 cash flow was 1.4 times and the ratio of total net debt as at December 31, 2006 to the annualized fourth quarter 2006 cash flow was 1.7 times. The Company anticipates no unusual working capital requirements in 2007. There are currently no capital commitments and no known unusual trends or liquidity issues at March 13, 2007. The Company expects to be able to meet future obligations associated from on-going operations from cash flow from operations and amounts that are currently available under the consolidated syndicated and operating facility. OUTSTANDING SHARE DATA The Company is authorized to issue an unlimited number of common shares without par value, and an unlimited number of first, second, third and fourth class preferred shares issuable in series. As at December 31, 2006, Real had 38.8 million outstanding common shares compared to 37.3 million outstanding shares at December 31, 2005. Real had no preferred shares outstanding during these periods. Employees and directors have been granted options to purchase common shares under the Company's Stock Option Plan. This plan and its terms and outstanding balance are disclosed in note 7(g) to the Consolidated Financial Statements. As at March 13, 2007 there are 38.8 million common shares and 2.8 million options outstanding. The Company obtained approval from the Toronto Stock Exchange to purchase common shares under four consecutive Normal Course Issuer Bids ("Bid") which commenced in June 2002 and will continue until June 2007. In 2006, Real had not purchased any shares under the current Bid. As of December 31, 2006, Real was entitled to purchase for cancellation 1.9 million common shares which is the entire allotment under the current Bid. CONTRACTUAL OBLIGATIONS The Company has entered into various commitments primarily related to the Calgary office lease. The following table summarizes the outstanding contractual obligations of the Company for the next five years and thereafter: There- ($ thousands) 2007 2008 2009 2010 2011 after Total ------------------------------------------------------------------------- Office lease 443 563 930 1,070 1,070 1,516 5,592 Other 349 55 - - - - 404 ------------------------------------------------------------------------- 792 618 930 1,070 1,070 1,516 5,996 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Real is also committed to spend $18.9 million prior to December 31, 2007 for Canadian Exploration Expenditures related to the issuance of flow-through shares on July 13, 2006. Lastly, Real is committed to maintain contractual obligations under the financing agreement with the banking syndicate. At the end of the year, the Company had drawn $132.4 million of this facility. OFF-BALANCE SHEET ARRANGEMENTS AND RELATED PARTY TRANSACTIONS The Company has not entered into any off-Balance Sheet transactions or into any related party transactions. CRITICAL ACCOUNTING ESTIMATES Management is often required to make judgements, assumptions and estimates in the application of generally accepted accounting principles that have a significant impact on the financial results of the Company. A comprehensive discussion of the Company's significant accounting policies is contained in note 2 to the annual Consolidated Financial Statements. The following is a discussion of the accounting estimates that are critical in determining the Company's financial results. (a) Full cost accounting The Company follows the full cost method of accounting for exploration and development activities whereby all costs associated with these activities are capitalized, whether successful or not. The aggregate of capitalized costs, net of certain costs related to unproven properties, and estimated future development costs is amortized using the unit-of-production method based on estimated proved reserves. Changes in estimated proved reserves or future development costs have a direct impact on depletion and depreciation expense. Certain costs related to unproved properties and major development projects may be excluded from costs subject to depletion until proved reserves have been determined or their value is impaired. These properties are reviewed quarterly to determine if proved reserves should be assigned, at which point the costs are included in the total cost base for purposes of calculating depletion and for evaluating impairment. The alternative method of accounting for oil and natural gas properties and equipment is the successful efforts method. The major difference in applying the successful efforts method is that exploratory dry holes and geological and geophysical exploration costs are charged against net earnings in the year incurred rather than being capitalized to property, plant and equipment. (b) Oil and natural gas reserves Approximately 86% of the Company's proved oil and gas reserves are evaluated and reported by an independent petroleum engineering consultant. The remaining 14% are internally evaluated by the company and then reviewed for reasonableness by the same independent petroleum engineering consultant. The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, estimated commodity price forecasts and the timing of future expenditures, all of which are subject to a number of uncertainties and various interpretations. The Company expects that over time its reserve estimates will be revised upward or downward based on updated information such as the results of future drilling, testing and production levels. Reserve estimates can have a significant impact on net earnings, as they are a key component in the calculation of depletion and depreciation. A revision to the reserve estimate could result in a higher or lower DD&A charge to net earnings. Downward revisions to reserve estimates could also result in a write-down of oil and natural gas property, plant and equipment under the ceiling test. (c) Full cost accounting ceiling test The carrying value of property, plant and equipment is reviewed annually for impairment. Impairment is determined when the carrying value of the Company's property, plant and equipment exceeds the sum of the undiscounted cash flows expected to result from the Company's proved reserves. Cash flows are calculated based on third-party quoted forward prices and are adjusted for the Company's contract prices and quality differentials. If impairment is deemed to occur, the magnitude is calculated by comparing the carrying value of property, plant and equipment to the estimated net present value of future cash flows from proved plus probable reserves. A risk-free interest rate is used to arrive at the net present value of the future cash flows. Any excess carrying value above the net present value of future cash flows would be recorded as a permanent impairment and charged as additional depletion expense in the Consolidated Statement of Earnings. No write-down was required at December 31, 2006. (d) Asset retirement obligation The Company recognizes the fair value of its asset retirement obligation (ARO) in the period in which it is incurred and when a reasonable estimate of its obligation can be made. The fair value of the estimated ARO is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on a unit-of-production basis over the life of the reserves. The liability amount is increased each reporting period with the passage of time and the amount of this accretion is charged to earnings in the period. Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost would also result in an increase or decrease to the ARO. Actual costs incurred upon settlement of the ARO are charged against the ARO to the extent of the liability recorded. Any difference between the actual cost incurred upon settlement of the ARO and the recorded liability is recognized as a gain or loss in the Company's earnings in the period in which the settlement occurs. Determinations of the original undiscounted costs are based on engineering estimates using current costs and technology in accordance with existing legislation and industry practice. The estimation of these costs can be affected by factors such as the number of wells drilled, well depth and area-specific environmental legislation. (e) Future income tax The Company follows the liability method of accounting for income taxes. Under this method income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements and their respective tax base, using substantively enacted future income tax rates. During the second quarter of 2006 a number of corporate tax initiatives were announced by both the Alberta and federal Governments, including the elimination of the federal Large Corporations Tax effective January 1, 2006, the elimination of the federal surtax effective January 1, 2008 and a scheduled reduction in federal corporate income tax rates from 21 percent to 19 percent commencing January 1, 2008 through January 1, 2010. The total impact for 2006 on the Company's future tax obligation as a result of these announcements was a recovery of $11.7 million, most of which was recognized in the second quarter of 2006. The forecasts of estimated net revenue streams are utilized to calculate the future tax provision and, as such, are subject to revisions, both upwards and downwards, that are not known at this time. In addition to these revisions, future capital activities can impact the timing of the reversal of any temporary differences. These differences can have an impact on the amount of future taxes determined at a point in time. To the extent that these differences are created, they can impact the charge against earnings for future income taxes. (f) Stock-based compensation The Company's Stock Option Plan provides for the granting of options to directors, officers and employees. The Company uses the fair value method for valuing stock option grants. Compensation costs attributable to share options granted are measured at fair value at the grant date and are expensed over the expected vesting time-frame with a corresponding increase to contributed surplus. Upon exercise of stock options, consideration paid by the option holder, together with the amount previously recognized in contributed surplus, is recorded as an increase in share capital. IMPACT OF NEW ACCOUNTING PRONOUNCEMENTS Effective January 1, 2007, Real will be required to adopt the following CICA sections: a) Section 1530 - Comprehensive Income b) Section 3855 - Financial Instruments - Recognition and Measurement c) Section 3865 - Hedges Starting in 2007, Section 1530 will require Comprehensive Income to be separated into two components: a) Net Income; and b) Other Comprehensive Income. Also, Section 3855 has defined the relevant models for valuing financial assets and liabilities in 2007, depending on the nature of the instruments. Lastly, Section 3865 defines the criteria needed in 2007 to qualify for hedge accounting, and the timing for recognition of applicable hedge gains and losses. These new standards are intended to harmonize Canadian standards with those of the United States and international standards. At this time, it is anticipated that these new accounting requirements will have no material impact on Real's financial statements. RISKS AND UNCERTAINTIES There are a number of risks facing participants in the Canadian oil and gas industry. Some of the risks are common to all businesses while others are specific to the sector. The following discussion reviews the general and specific risks as well as Real's approach to managing these risks. The Company is engaged in the exploration, development, production and acquisition of crude oil and natural gas. Real's business is inherently risky and there is no assurance that hydrocarbon reserves will be discovered and economically produced. Financial risks associated with the petroleum industry include fluctuations in commodity prices, interest rates, and currency exchange rates. Operational risks include competition, environmental factors, reservoir performance uncertainties, a complex regulatory environment and safety concerns. The Company minimizes its business risks by operating a large number of its properties. This enables Real to control the timing, direction and costs related to exploration and development opportunities. Real's geological focus is on areas in which the prospects are well understood by management. Technological tools are regularly used to reduce risk and increase the probability of success. The Company closely follows all government regulations and has an up-to-date emergency response plan that has been communicated to field operations by management. Real also carries insurance coverage to protect itself against potential losses. Maintaining a highly motivated and talented staff of petroleum and natural gas professionals further minimizes the business risk. Real relies on various sources of funding to support its growing capital expenditure program: - Internally-generated cash flow provides a minimum level of funding on which the Company's annual capital expenditure program is based; - Debt may be utilized to expand capital programs when appropriate; and - New equity, if available on favourable terms, may be utilized to expand exploration programs. The Company is exposed to commodity price and market risk for its principal products of petroleum and natural gas. Commodity prices are influenced by a wide variety of factors, most of which are beyond Real's control. To manage this risk, the Company has in the past entered into a number of short-term financial derivatives for hedging purposes. These derivatives included contracts related to oil and gas prices, as well as foreign exchange rates. Real has also minimized its exposure to increased rates by entering into short-term contacts for interest rate swaps. The Company also enters, from time to time, into fixed physical contracts that are generally less than one year in duration. The Company continues to monitor the cost and associated benefit of these instruments and contracts as well as debt levels and utilization rates on bank lines and will utilize these derivatives and contracts when warranted. Inflation risks subject the Company to potential erosion of product netbacks. For example, increasing domestic prices for oil and natural gas production equipment and services can inflate the costs of operations. The supply of service and production equipment at competitive prices is critical to the ability to add reserves at a competitive cost and produce them in an economic and timely fashion. In periods of increased activity, these services and supplies can become difficult to obtain. The Company attempts to mitigate this risk by developing strong long-term relationships with suppliers and contractors and maintaining an appropriate inventory of production equipment. Demand for crude oil and natural gas produced by the Company exists within Canada and the United States; however, crude oil prices are affected by worldwide supply and demand fundamentals while natural gas prices are affected by North American supply and demand fundamentals. Demand for natural gas liquids is influenced mainly by the demand for petrochemicals in North American and off-shore markets. Real mitigates these risks as follows: - Crude oil production is of a high quality and hence not subject to adverse quality differentials; - Natural gas is connected to a mature pipeline infrastructure that operates with minimal interruptions; - Exploration efforts target high-quality oil and liquids-rich natural gas reserves; - Exploration efforts are concentrated in core regions where marketing expertise levels are highest. Marketing synergies can be achieved with the existing production base; - Sale arrangements vary in term and pricing structure creating a diverse portfolio that minimizes risk of exposure to any one market; and - Financial instruments may be used where appropriate to manage commodity price volatility. In 1994, the United Nations' Framework on Climate Change came into force and three years later led to the Kyoto Protocol, which requires nations to reduce their emissions of carbon dioxide and, therefore, green house gases. The Government of Canada has ratified the Kyoto Protocol. Producers in geographic areas where Real operates may be required to reduce greenhouse gases. This could result in, among other things, increased operating and capital expenditures for those producers. This could make certain production of crude oil or natural gas by those producers uneconomic, resulting in reductions in such production. The Company is unable to predict the effect on its future earnings of the ratification of the Kyoto Protocol by the Federal Government. The Company is committed to maximizing shareholder value in an environmentally and socially responsible and safe manner. To this end, Real is actively involved in the Canadian Petroleum Producers (CAPP) Stewardship initiative. This voluntary initiative encourages members to continually improve their environment, health and safety performance and to report their progress to all stakeholders. The Company is pleased to report that CAPP has recognized Real's participation at a Gold level, which acknowledges an open and transparent account of our environment, health and safety performance on a yearly basis and a leadership role in the improvement of these issues. SELECTED ANNUAL INFORMATION Years ended December 31 ------------------------------------------------------------------------- ($ thousands, except per share amounts) 2006 2005 2004 ------------------------------------------------------------------------- Working interest production Crude oil and liquids (bbls/d) 5,884 5,152 3,293 Natural gas (mcf/d) 31,293 31,451 24,478 Total oil equivalent (boe/d) 11,100 10,394 7,373 Production revenue 214,275 215,271 108,103 Cash flow from operations 113,052 133,415 56,173 Per share - basic $ 2.98 $ 3.92 $ 2.09 Per share - diluted $ 2.91 $ 3.79 $ 2.03 Net earnings 23,737 49,065 16,155 Per share - basic $ 0.63 $ 1.44 $ 0.60 Per share - diluted $ 0.61 $ 1.40 $ 0.58 Long-term financial liabilities 132,450 35,225 46,235 Total assets 668,702 529,681 279,656 Total net debt 157,215 68,571 58,498 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Overall, 2006 total production (boe/d) was seven percent higher than 2005 and 51 percent higher than 2004. The 2006 cash flow from operations declined 15 percent from 2005 due mainly to lower realized natural gas prices, but was 101 percent higher than 2004. The 2006 net earnings declined 23 percent from 2005 again mainly due to lower gas prices, but was 134 percent higher than 2004. Total 2006 assets are 26 percent higher than 2005 and 139 percent higher than 2004 as a result of exploration and development capital expenditures made by the Company in 2006. The 2006 net debt is 129 percent higher than 2005 and 173 percent higher than 2004 as a result of the significant capital expenditure program undertaken by Real in 2006. SUMMARY OF QUARTERLY RESULTS Three months ended 2006 Annual ------------------------------------------------------------------------- ($ thousands, except per share amounts) March 31 June 30 Sept 30 Dec 31 2006 ------------------------------------------------------------------------- Working interest production Crude oil and liquids (bbls/d) 5,729 5,951 6,255 5,600 5,884 Natural gas (mcf/d) 32,802 30,697 31,867 29,834 31,293 Total oil equivalent (boe/d) 11,196 11,067 11,566 10,573 11,100 Production revenue 52,896 54,712 58,111 48,556 214,275 Cash flow from operations 27,191 29,350 33,056 23,455 113,052 Per share - basic $ 0.73 $ 0.78 $ 0.87 $ 0.60 $ 2.98 Per share - diluted $ 0.71 $ 0.77 $ 0.85 $ 0.58 $ 2.91 Net earnings 5,456 16,524 6,622 (4,865) 23,737 Per share - basic $ 0.15 $ 0.44 $ 0.17 $ (0.13) $ 0.63 Per share - diluted $ 0.14 $ 0.44 $ 0.16 $ (0.13) $ 0.61 Total assets 606,848 639,662 670,012 668,702 668,702 Total net debt 138,925 163,363 154,510 157,215 157,215 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Three months ended 2005 Annual ------------------------------------------------------------------------- ($ thousands, except per share amounts) March 31 June 30 Sept 30 Dec 31 2005 ------------------------------------------------------------------------- Working interest production Crude oil and liquids (bbls/d) 4,150 5,198 5,290 5,945 5,152 Natural gas (mcf/d) 25,998 32,532 32,521 34,645 31,451 Total oil equivalent (boe/d) 8,483 10,620 10,710 11,719 10,394 Production revenue 35,259 49,443 60,804 69,765 215,271 Cash flow from operations 19,570 32,234 38,767 42,844 133,415 Per share - basic $ 0.66 $ 0.98 $ 1.11 $ 1.17 $ 3.92 Per share - diluted $ 0.64 $ 0.94 $ 1.07 $ 1.14 $ 3.79 Net earnings 5,775 11,903 13,579 17,808 49,065 Per share - basic $ 0.20 $ 0.36 $ 0.39 $ 0.49 $ 1.44 Per share - diluted $ 0.19 $ 0.35 $ 0.38 $ 0.48 $ 1.40 Total assets 335,732 431,685 474,766 529,681 529,681 Total net debt 68,305 87,631 43,915 68,571 68,571 ------------------------------------------------------------------------- ------------------------------------------------------------------------- During 2005 Real increased production, revenue, cash flow, and earnings each quarter during the year as the company benefited from relatively high natural gas prices. At that time, Real's strategy was to maintain the production mix between oil and gas at approximately 50/50. During 2006 overall production was relatively flat as oil production increases were offset by natural declines in gas production. Revenue, cash flow, and earnings declined mainly due to reduced natural gas prices. Due to the pricing environment in 2006, the Corporation's production mix became weighted more to oil than gas as a direct result of the Company's strategy to reduce emphasis on natural gas production until there was a recovery in the natural gas markets. FOURTH QUARTER 2006 RESULTS Capital expenditures totalled $26.5 million for the fourth quarter and included drilling 20 (16.8 net) wells. Real spent $2.9 million on land and property acquisitions, $2.3 million on seismic, $10.9 million on drilling and completions and $10.4 million on pipelines and facilities. The capital program was financed through funds generated primarily from operations. Average production decreased to 10,573 boe/d in the fourth quarter from 11,719 boe/d in the fourth quarter of 2005. Crude oil production decreased to 5,600 bbls/d from 5,945 bbls/d in the fourth quarter of 2005 primarily due to reduced production in the Virginia Hills area related to shut-in conditions associated with a third party pipeline break. Production additions were recorded in Southeast Saskatchewan as a result of Real's 2006 drilling program but these were offset by the reintroduction of production limitations that were temporarily removed by the Alberta government in 2005 in response to supply interruptions that resulted from Hurricane Katrina as well as natural declines in the Company's existing asset base. Overall, natural gas production decreased to 29.8 mmcf/d from 34.6 mmcf/d. This reduction was the direct result of the implementation of the Company's strategy to limit drilling on natural gas prospects pending the recovery of natural gas commodity prices. The reduction in average production levels partially contributed to a reduction in production revenue, but the main factor in the revenue reduction was a 40 percent reduction in realized natural gas prices resulting from the weakening commodity market for natural gas. Royalty costs recorded in the fourth quarter of 2006 compared to the fourth quarter of 2005 were lower as a percentage of revenue due to two factors. The first factor was the change in the Company's crude oil production mix. A lower percentage of production came from Alberta Crown properties which attract maximum royalty rates as well as a higher percentage of production coming from incentived wells in Southeast Saskatchewan which attract a 2.5 percent royalty rate on the first 6,000 m3 of production. The second factor was the lower realized rate recorded on natural gas revenue due to the Company receiving a 16 percent higher average price on its production when compared to the Alberta Reference Price which is the determining price in the calculation of royalties. This higher gas price is the result of higher than average quality natural gas as well as the proceeds from certain fixed price physical contracts that were in place for the fourth quarter (see Note 6 to the Consolidated Financial Statements). Also included in fourth quarter reported royalties is a $0.8 million recovery related to the underaccrual of Gas Crown Allowance (2005) and royalty amendments in the West Provost area (2003 to 2005). Operating expenses increased on a unit basis primarily due to higher emulsion trucking costs incurred in Virginia Hills as a result of the third party pipeline break as well as higher electricity costs experienced during the fourth quarter of 2006. General and administrative charges are higher in the fourth quarter of 2006 compared to the fourth quarter of 2005 due to higher wages (associated with wage increases and additional staff), higher legal fees (associated with the ongoing litigation related to a producing property), higher engineering costs (related to the transition to a new independent engineering evaluator) and lower capital recoveries (related to lower capital expenditures). Interest expense was higher in the fourth quarter of 2006 compared to the fourth quarter of 2005 due to higher average debt levels. These factors resulted in a reduction in cash flow in the fourth quarter of 2006 to $23.5 million compared to the fourth quarter of 2005 of $42.8 million. Depletion, depreciation and accretion in the fourth quarter of 2006 of $28.0 million was higher compared to the $20.2 million in the fourth quarter of 2005. This increase reflects the impact of the 2006 capital spending program of $231.7 million which added approximately 9.7 million barrels of proved oil equivalent reserves, offset by downward revisions of approximately 9.4 million proved barrels relating to 2006 property production performance, particularly in our gas properties, as well as the evaluation parameters utilized by the new reserve evaluators in 2006. As a result, the 2006 fourth quarter DD&A rate was $28.80 per boe as compared to $18.70 per boe in the fourth quarter of 2005. Future income taxes recovery of $1.1 million in the fourth quarter of 2006 was lower than the $4.6 million future income tax expense in the fourth quarter of 2005. This is reflective of the pre-tax loss of $5.6 million in the fourth quarter of 2006 as compared to the $23.0 million pre-tax income in 2005. Netbacks(*) Years ended December 31 ------------------------------------------------------------------------- ($/boe) 2006 2005 % change ------------------------------------------------------------------------- Production revenue 49.93 64.71 (23) Net royalties (8.15) (13.85) (41) Operating expenses (10.29) (7.64) 35 Transportation costs (1.10) (0.73) 51 ------------------------------------------------------------------------- Operating netback 30.39 42.49 (28) General and administrative expenses (3.91) (1.85) 111 Interest expense (1.76) (0.24) 633 Current taxes (0.42) (0.50) (16) ------------------------------------------------------------------------- Cash flow netback (before abandonment) 24.30 39.90 (39) Depletion, depreciation and accretion (28.80) (18.70) 54 Future income taxes 1.13 (4.27) 126 Stock-based compensation (1.62) (0.41) 295 ------------------------------------------------------------------------- Corporate netback (before abandonment) (4.99) 16.52 (130) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (*) equivalent mcf includes natural gas liquids production converted on a basis of 1 bbl equals 6 mcf MANAGEMENT'S EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES Disclosure Controls and Procedures The Chief Executive Officer and Acting Chief Financial Officer evaluated the effectiveness of the Company's disclosure controls and procedures as at the financial year ended December 31, 2006. Based on that evaluation, the Chief Executive Officer and Acting Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective as at December 31, 2006 to provide reasonable assurance that material information relating to the Company, including its consolidated subsidiaries, would be made known to them by others within those entities. The Chief Executive Officer and Acting Chief Financial Officer believe that the Company's disclosure controls and procedures provide a reasonable level of assurance that they are effective, however they do not expect that the disclosure controls and procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Internal Control over Financial Reporting As at the financial year ended December 31, 2006, the Chief Executive Officer and Acting Chief Financial Officer evaluated the design of the Company's internal control over financial reporting. Based on that evaluation, the Chief Executive Officer and the Acting Chief Financial Officer concluded that the design of internal control over financial reporting was effective as at December 31, 2006 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. There have been no changes in the Company's internal control over financial reporting that occurred during the most recent interim period ended December 31, 2006 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting. CEO CERTIFICATION I, Lowell E. Jackson, President and Chief Executive Officer of Real Resources Inc. certify that: (1) I have reviewed the annual filings (as this term is defined in Multilateral Instrument 52-109 Certification of disclosure in Issuers' Annual and Interim Filings) of Real Resources Inc. (the "issuer") for the year ending December 31, 2006; (2) Based on my knowledge, the annual filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the annual filings; (3) Based on my knowledge, the annual financial statements together with other financial information included in the annual filings fairly present in all material respects the financial condition, results of operations and cash flows of the issuer, as of the date and for the periods presented in the annual filings; (4) The issuer's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures and internal control over financial reporting for the issuer, and we have: a) designed such disclosure controls and procedures, or caused them to be designed under our supervision, to provide reasonable assurance that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which the annual filings are being prepared; b) designed such internal control over financial reporting, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer's GAAP; and c) evaluated the effectiveness of the issuer's disclosure controls and procedures as of the end of the period covered by the annual filings and have caused the issuer to disclose in the annual MD&A our conclusions about the effectiveness of the disclosure controls and procedures as of the end of period covered by the annual filing based on such evaluation; and (5) I have caused the issuer to disclose in the annual MD&A any change in the issuer's internal control over financial reporting that occurred during the issuer's most recent interim period that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting. March 13, 2007 Lowell E. Jackson, P. Eng President and Chief Executive Officer CFO CERTIFICATION I, Lowell E. Jackson, Acting Chief Financial Officer of Real Resources Inc. certify that: (1) I have reviewed the annual filings (as this term is defined in Multilateral Instrument 52-109 Certification of disclosure in Issuers' Annual and Interim Filings) of Real Resources Inc. (the "issuer") for the year ending December 31, 2006; (2) Based on my knowledge, the annual filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the annual filings; (3) Based on my knowledge, the annual financial statements together with other financial information included in the annual filings fairly present in all material respects the financial condition, results of operations and cash flows of the issuer, as of the date and for the periods presented in the annual filings; (4) The issuer's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures and internal control over financial reporting for the issuer, and we have: a) designed such disclosure controls and procedures, or caused them to be designed under our supervision, to provide reasonable assurance that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which the annual filings are being prepared; b) designed such internal control over financial reporting, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer's GAAP; and c) evaluated the effectiveness of the issuer's disclosure controls and procedures as of the end of the period covered by the annual filings and have caused the issuer to disclose in the annual MD&A our conclusions about the effectiveness of the disclosure controls and procedures as of the end of period covered by the annual filing based on such evaluation; and (5) I have caused the issuer to disclose in the annual MD&A any change in the issuer's internal control over financial reporting that occurred during the issuer's most recent interim period that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting. March 13, 2007 Lowell E. Jackson, P. Eng Acting Chief Financial Officer MANAGEMENT'S RESPONSIBILITY STATEMENT To the Shareholders of Real Resources Inc. The accompanying consolidated financial statements and all other financial information presented in this annual report are the responsibility of Real's management. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles. Management has developed and maintains systems of internal accounting controls, policies and procedures in order to provide for the safeguarding of assets and preparation of relevant, reliable and timely financial information. External auditors, appointed by the shareholders, have examined the consolidated financial statements. The Audit Committee reviews these statements with management and the auditors and reports to the Board of Directors who approve the financial statements. LOWELL E. JACKSON, P. Eng. President & Chief Executive Officer Calgary, Alberta, Canada March 13, 2007 AUDITORS' REPORT To the Shareholders of Real Resources Inc. We have audited the consolidated balance sheets of Real Resources Inc. as at December 31, 2006 and 2005 and the consolidated statements of operations and retained earnings and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also included assessing the accounting principles used and significant estimates made by management, as well evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2006 and 2005 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles. Chartered Accountants Calgary, Alberta, Canada March 13, 2007 CONSOLIDATED BALANCE SHEETS ------------------------------------------------------------------------- December 31 ($ thousands) 2006 2005 ------------------------------------------------------------------------- Assets Current assets Accounts receivable 21,542 30,470 Prepaid expenses 2,001 1,770 ------------------------------------------------------------------------- 23,543 32,240 Property, plant and equipment (note 4) 645,159 497,441 ------------------------------------------------------------------------- 668,702 529,681 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Liabilities and shareholders' equity Current liabilities Accounts payable and accrued liabilities 48,308 65,586 Long-term debt (note 5) 132,450 35,225 Asset retirement obligation (note 10) 19,801 17,896 Future income taxes (note 8) 86,540 88,890 Shareholders' equity Share capital (note 7) 250,689 219,763 Contributed surplus (note 11) 6,933 2,077 Retained earnings 123,981 100,244 ------------------------------------------------------------------------- 381,603 322,084 ------------------------------------------------------------------------- 668,702 529,681 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Commitments (see note 9) See accompanying notes to Consolidated Financial Statements Robert B. Michaleski, CA Frans Burger Director Director CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS Years ended December 31 ($ thousands, except per share amounts) 2006 2005 ------------------------------------------------------------------------- Revenue Production revenue 214,275 215,271 Royalties (42,210) (41,360) ------------------------------------------------------------------------- 172,065 173,911 ------------------------------------------------------------------------- Expenses Operating 37,749 27,502 Transportation costs 3,703 2,898 General and administrative 9,726 6,209 Stock-based compensation 5,223 1,437 Interest on long-term debt 5,318 1,776 Depletion, depreciation and accretion 86,769 58,609 ------------------------------------------------------------------------- 148,488 98,431 ------------------------------------------------------------------------- Earnings before taxes 23,577 75,480 Taxes (note 8) Future income taxes (1,817) 24,659 Current 1,657 1,756 ------------------------------------------------------------------------- (160) 26,415 ------------------------------------------------------------------------- Net earnings 23,737 49,065 Retained earnings, beginning of year 100,244 51,179 ------------------------------------------------------------------------- Retained earnings, end of year 123,981 100,244 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Basic earnings per share (note 7(g)) $ 0.63 $ 1.44 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Diluted earnings per share (note 7(g)) $ 0.61 $ 1.40 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to Consolidated Financial Statements CONSOLIDATED STATEMENTS OF CASH FLOWS Years ended December 31 ($ thousands) 2006 2005 ------------------------------------------------------------------------- Cash provided by (used in): Operating activities Net earnings 23,737 49,065 Items not involving cash: Depletion, depreciation and accretion 86,769 58,609 Stock-based compensation 5,223 1,437 Future income taxes (note 8) (1,817) 24,659 Abandonment expenditures (860) (355) ------------------------------------------------------------------------- Cash flow from operations 113,052 133,415 Changes in non-cash working capital: Decrease (increase) in trade and other receivables 6,399 (12,821) Increase in prepaid expenses (231) (604) Increase (decrease) in trade and other payables (3,441) 7,975 ------------------------------------------------------------------------- 115,779 127,965 ------------------------------------------------------------------------- Financing activities Issue of common shares 30,014 95,030 Issue of share capital on exercise of stock options 1,804 2,243 Repurchase of shares (note 7(g)) - - Share issue costs (1,792) (5,431) Increase (decrease) in long-term debt 97,225 (12,477) ------------------------------------------------------------------------- 127,251 79,365 Investing activities Additions to capital assets (226,349) (200,701) Corporate acquisition - (6,978) Property acquisitions (5,378) (26,019) Proceeds on property dispositions 5 78 ------------------------------------------------------------------------- (231,722) (233,620) Changes in non-cash working capital: Decrease (increase) in trade and other receivables 2,529 (86) Increase (decrease) in trade and other payables (13,837) 26,376 ------------------------------------------------------------------------- (243,030) (207,330) ------------------------------------------------------------------------- Change in cash - - Cash, beginning of year - - ------------------------------------------------------------------------- Cash, end of year - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- Supplementary disclosure Cash interest paid 5,595 1,844 Capital taxes paid 539 928 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to Consolidated Financial Statements Notes to the Consolidated Financial Statements December 31, 2006 and 2005 (Tabular amounts in thousands of dollars, unless otherwise noted) 1. NATURE OF BUSINESS Real Resources Inc. (Real or the Company) is a public company whose business is the exploration for and development of crude oil and natural gas in Western Canada. Real is incorporated under the Business Corporations Act (Alberta) and is listed on the Toronto Stock Exchange. Effective January 1, 2006, Real and Freemont Exploration Corp. (a wholly owned subsidiary of Real) were amalgamated under the Business Corporations Act (Alberta) and continued under the name Real Resources Inc. 2. ACCOUNTING POLICIES The Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in Canada. The preparation of the Consolidated Financial Statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenue and expenses during the reported period. Actual results may differ from these estimates. (a) Principles of consolidation The Consolidated Financial Statements include the accounts of the Company, its wholly owned subsidiary and its partnership. (b) Joint operations Significant portions of the Company's oil and gas activities are conducted jointly with others and accordingly, these financial statements reflect only the Company's proportionate interest in such activities. (c) Measurement uncertainty The amounts recorded for depletion and depreciation of petroleum and natural gas property, plant and equipment and the provision for asset retirement obligations are based on estimates. Stock based compensation expense is based on assumptions and estimates inherent in the valuation model. Also, the calculation of future taxes is predicated on estimates and assumptions. Lastly, the ceiling test is based on estimates of proved reserves, production rates, petroleum and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be significant. (d) Property, plant and equipment ("PP&E") The Company follows the full-cost method of accounting for exploration and development expenditures. All costs of exploring, developing and acquiring petroleum and natural gas properties, including asset retirement costs, are capitalized and accumulated in one cost centre as all of the Company's operations are in Canada. Maintenance and repairs are charged against income and renewals and enhancements which extend the economic life of the PP&E are capitalized. Gains and losses are not recognized upon disposition of petroleum and natural gas properties unless such a disposition would alter the rate of depletion by 20 percent or more. (e) Depletion and depreciation Depletion of petroleum and natural gas properties and depreciation of production equipment are calculated on the unit-of-production which is based on: (i) total estimated proved reserves calculated in accordance with National Instrument 51-101; (ii) total capitalized costs plus estimated future development costs of proved undeveloped reserves including discounted asset retirement costs, less the estimated net realizable value of production equipment and facilities after the proved reserves are fully produced; and (iii) relative volumes of petroleum and natural gas reserves and production before royalties, converted at the energy equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of oil. (f) Impairment The Company places a limit on the aggregate carrying value of PP&E. Impairment is recognized if the carrying amount of the PP&E exceeds the sum of the undiscounted cash flows expected to result from the Company's proved reserves. Cash flows are calculated based on third-party quoted forward prices, adjusted for the Company's contract prices and quality differentials. Upon recognition of impairment, the Company would then measure the amount of impairment by comparing the carrying amounts of the PP&E to the fair value of PP&E which is the estimated net present value of future cash flows from proved plus probable reserves. The Company's risk-free interest rate is used to arrive at the net present value of future cash flows. Any excess carrying value above the net present value of the Company's future cash flows would be recorded as a permanent impairment. (g) Asset retirement obligation The Company recognizes the fair value of its asset retirement obligation ("ARO") in the period in which it is incurred and when a reasonable estimate of fair value can be made. The fair value of the estimated ARO is recorded as a long-term liability with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on a unit-of-production basis over the life of the reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings in the period. Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost would also result in an increase or decrease to the ARO. Actual costs incurred upon settlement of the ARO are charged against the ARO to the extent of the liability recorded. Any difference between the actual costs incurred upon settlement of the ARO and the recorded liability is recognized as a gain or loss in the Company's earnings in the period in which the settlement occurs. (h) Derivative financial instruments The Company may use various derivative financial instruments from time to time to manage its commodity price, foreign exchange and interest rate exposures. The Company does not use these instruments for trading purposes. The derivative financial instruments are initiated within the guidelines of the Company's risk management policy. When it is deemed appropriate, the Company hedges its exposure to petroleum and natural gas commodity prices by entering into crude oil and natural gas swap contracts, options or collars. These derivative contracts are not accounted for as hedges under Accounting Guideline 13 and are recorded at fair value on the Company's Consolidated Balance Sheet, with changes in fair value recorded in earnings. The Company may also enter into foreign exchange forward contracts to hedge anticipated US dollar denominated petroleum and natural gas sales. (i) Revenue recognition Revenues from sales of petroleum and natural gas are recorded when title passes from the Company to external parties. (j) Income taxes The Company follows the liability method of accounting for income taxes. Under this method, the Company records future income taxes to account for the effect of any differences between the accounting and the income tax basis of an asset or liability using income tax rates substantively enacted at the Balance Sheet date. The effect of a change in income tax rates on the future income tax assets and liabilities is recognized in income in the period of the change. (k) Stock-based compensation plan The Company's Option Plan provides for granting of stock options to directors, officers and employees. The Company uses the fair value method for valuing stock option grants. Compensation costs attributed to share options granted are measured at fair value at the grant date and are expensed over the expected vesting time-frame with a corresponding increase to contributed surplus. Upon exercise of the stock options, consideration paid by the option holder together with the amount previously recognized in contributed surplus is recorded as an increase to share capital. (l) Per share information Per share information is calculated on the basis of the weighted average number of common shares outstanding during the fiscal year. Diluted per share information reflects the potential dilution that could occur if securities or other contracts to issue common shares were exercised or converted to common shares. Diluted per share information is calculated using the treasury stock method that assumes any proceeds received by the Company upon the exercise of in-the-money stock options would be used to buy back common shares at the average market price for the period. (m) Flow-through shares The resource expenditure deductions for income tax purposes related to exploratory activities funded by flow-through share arrangements are renounced to investors in accordance with tax legislation. A future tax liability is recognized upon the filing of the renunciation with the tax authorities and share capital is reduced by the estimated costs of the renounced tax deductions. 3. ACQUISITIONS a) On April 8, 2005, the Company acquired all of the issued and outstanding shares of Freemont Exploration Corp. ("Freemont"), a private oil and gas company. The operating results and corresponding cash flow and earnings related to this acquisition were included in the Company's consolidated financial statements effective April 9, 2005. Total consideration paid of $29.9 million was comprised of the issuance of 1.637 million common shares at a deemed value of $14.00 per share and $7.0 million in cash (including acquisition costs of $0.5 million). The 2005 acquisition was accounted for by the purchase method and the purchase price was allocated based on fair values as follows: --------------------------------------------------------------------- Non-cash working capital (244) Property, plant and equipment 45,773 Long-term debt (1,467) Asset retirement obligation (458) Future income taxes (13,709) --------------------------------------------------------------------- Total consideration 29,895 --------------------------------------------------------------------- Consideration was comprised of: Issue of 1,636,907 common shares at $14.00 per share 22,917 Cash 6,978 --------------------------------------------------------------------- Total consideration 29,895 --------------------------------------------------------------------- b) Concurrent with this transaction, additional oil and gas assets in the same area ("additional assets") were acquired from multiple private companies. The consideration paid by the Company was an aggregate of 0.780 million common shares and $3.9 million in cash for a deemed aggregate value of $14.8 million. 4. PROPERTY, PLANT AND EQUIPMENT 2006 2005 --------------------------------------------------------------------- Oil and gas property, plant and equipment 904,492 672,271 Other 2,928 1,902 --------------------------------------------------------------------- 907,420 674,173 Less: accumulated depletion and deprecation 262,261 176,732 --------------------------------------------------------------------- 645,159 497,441 --------------------------------------------------------------------- --------------------------------------------------------------------- At December 31, 2006, oil and gas properties included $72.0 million (2005: $59.1 million) relating to unproved properties and unevaluated proprietary seismic data which have been excluded from the depletion and depreciation calculation. Future development costs on proved undeveloped reserves of $90.2 million (2005: $35.0 million) are included in the depletion calculation. Included in the Company's property, plant and equipment balance is $9.3 million (2005: $9.6 million) net of accumulated depletion relating to the asset retirement obligation. In 2006, the Company capitalized $2.9 million (2005: $2.6 million) of overhead directly related to exploration and development activities. Real performs a ceiling test calculation at least annually in accordance with the Canadian Institute of Chartered Accountants' full cost accounting guidelines. No write-down was required for the year ended December 31, 2006 and December 31, 2005 based on expected realized future commodity prices. Oil Price Gas Price NGL Price --------------------------------------------------------------------- Year ending December 31 2006 2005 2006 2005 2006 2005 --------------------------------------------------------------------- 2006 - 62.16 - 10.35 - 54.63 2007 65.90 59.22 7.79 9.31 53.95 52.08 2008 68.47 56.33 8.61 8.12 56.31 49.60 2009 61.43 53.48 7.75 7.50 51.28 47.21 2010 57.16 50.69 7.56 6.88 48.04 44.41 2011 54.02 53.99 7.73 8.12 45.69 49.11 Thereafter 61.57 53.99 8.71 8.12 53.19 49.11 Average 62.84 56.12 8.23 8.49 52.20 50.15 --------------------------------------------------------------------- --------------------------------------------------------------------- 5. LONG-TERM DEBT At December 31, 2006, the Company had a financing commitment with three Canadian chartered banks which provided for a consolidated syndicated and operating facility of $185 million. The credit facility revolves and fluctuates at the Company's option for a maximum of 364 days after the date of the banks' consent. If the revolving facility is not renewed at the end of the current revolving phase on May 30, 2007, the facility would move into the term phase whereby the credit facility would be permanently reduced by one payment on the 366th day following the last day of the revolving phase, which is the maturity date, in an amount equal to the outstanding principal. The credit facility provides that advances may be made by way of direct advances, bankers' acceptances or US dollar LIBOR advances which bear interest at prevailing bankers' acceptances or LIBOR rates plus an applicable bank fee per annum or bank's prime lending rate, depending on the nature of the advance. The authorized limit is subject to a semi-annual review and re-determination of the Company's borrowing base by the bank. The Company's borrowing base was last reviewed on November 1, 2006. Collateral pledged for the facility consists of a fixed and floating charge demand-debenture in the principal amount of $250 million conveying a floating charge on all of the property and assets of the Company. 6. FORWARD CONTRACTS Real Resources entered into three firm physical natural gas contracts as summarized in the following table. Pursuant to these agreements the Company will deliver the following quantities of natural gas: Volume AECO "C" price/gj Term --------------------------------------------------------------------- 5,000 gj/d $7.54 November 1, 2006 to March 31, 2007 5,000 gj/d $7.27 November 1, 2006 to March 31, 2007 5,000 gj/d $7.50 November 3, 2006 to March 31, 2007 --------------------------------------------------------------------- --------------------------------------------------------------------- 7. SHARE CAPITAL (a) Authorized Unlimited number of voting common shares without par value. Unlimited number of first, second, third and fourth class preferred shares, issuable in series. (b) Common shares issued 2006 2005 --------------------------------------------------------------------- Number Amount Number Amount of Shares ($ of Shares ($ (thousands) thousands) (thousands) thousands) --------------------------------------------------------------------- Balance at beginning of year 37,252 219,763 29,090 91,767 Issue of common shares(c) - - 5,195 95,030 Issue of common shares(d) 1,177 30,014 - - Issuance of shares for corporate acquisition (note 3) - - 1,637 22,917 Issuance of shares for property acquisitions (note 3) - - 780 10,919 Issued for cash on exercise of stock options(e) 374 1,804 550 2,243 Stock-based compensation - 367 - 408 Share issue costs (net of tax effect) - (1,259) - (3,521) --------------------------------------------------------------------- Balance at end of year 38,803 250,689 37,252 219,763 --------------------------------------------------------------------- --------------------------------------------------------------------- (c) On March 1, 2005 the Company closed a common share equity offering of 2.527 million common shares at a price of $13.85 per share for total gross proceeds of approximately $35.0 million ($32.9 million net of costs). On August 24, 2005 the Company closed a common share equity offering of 2.668 million common shares at a price of $22.50 per share for total gross proceeds of approximately $60.0 million ($56.8 million net of costs). (d) On July 13, 2006 the Company closed a flow-through share equity offering for a total of 1.177 million common shares at a price of $25.50 per share for total gross proceeds of approximately $30.0 million ($28.3 million net of costs). Real committed to spending $30.0 million in qualifying Canadian Exploration Expenditures pursuant to this flow-through share issue prior to December 31, 2007. All of the expenditures were renounced effective December 31, 2006. As at December 31, 2006 approximately $11.1 million of the qualifying expenditures had been incurred. (e) Stock-based compensation plan The Company has a stock option plan that provides for the issuance of options to its directors, officers and employees to acquire up to 2.978 million common shares as at December 31, 2006. The options typically vest evenly over a three-year period and expire five years from the date of grant. Compensation costs attributable to share options granted are measured at their fair value at the grant date and are expensed over the expected vesting time-frame with a corresponding increase to contributed surplus. Upon exercise of the stock options, consideration paid by the option holder together with the amount previously recognized in contributed surplus is recorded as an increase to share capital. The stock-based compensation expense does not include compensation costs associated with stock options granted prior to January 1, 2002. The fair value of each option granted is estimated on the date of grant using the Black-Scholes options pricing model with the following weighted average assumptions: 2006 2005 --------------------------------------------------------------------- Fair value of options granted ($/share) 5.89 4.76 Risk-free interest rate (%) 3.3 2.3 Expected life (years) 3.2 3.4 Expected volatility (%) 40 39 Expected dividend yield (%) - - --------------------------------------------------------------------- Stock option plan A summary of the status of the Company's stock option plan as of December 31, 2006 and 2005, and changes during the years ended on those dates is presented below: 2006 2005 --------------------------------------------------------------------- Weighted Weighted Average Average Number of Exercise Number of Exercise Options Price Options Price (thousands) ($/share) (thousands) ($/share) --------------------------------------------------------------------- Balance, beginning of year 2,433 10.59 1,932 4.85 Granted 1,027 22.34 1,152 17.18 Exercised (374) (4.83) (550) (4.08) Expired/cancelled (108) (17.97) (101) (11.41) --------------------------------------------------------------------- Balance, end of year 2,978 15.10 2,433 10.59 --------------------------------------------------------------------- Exercisable at end of year 1,168 8.69 827 4.60 --------------------------------------------------------------------- --------------------------------------------------------------------- The following table summarizes information regarding stock options outstanding at December 31, 2006: Options Exercisable Options Outstanding at December 31, 2006 at December 31, 2006 -------------------------------------------- ----------------------- Weighted Average Weighted Weighted Remaining Average Average Range of Number Contractual Exercise Number Exercise Exercise Outstanding Life Price Exercisable Price Prices (thousands) (years) ($/share) (thousands) ($/share) -------------------------------------------- ----------------------- $3.80 - $4.70 593 1.3 4.41 593 4.41 $5.09 - $9.45 357 2.4 7.08 231 6.91 $13.08 - $16.75 814 3.4 14.89 242 14.75 $18.53 - $28.18 1,214 4.2 22.82 102 23.27 -------------------------------------------- ----------------------- 2,978 3.2 15.10 1,168 8.69 -------------------------------------------- ----------------------- -------------------------------------------- ----------------------- (f) Normal Course Issuer Bid On June 17, 2004 the Company announced its intention to make a Normal Course Issuer Bid (the "Bid") through the facilities of the Toronto Stock Exchange to acquire for cancellation up to 1.391 million common shares of the Company, which represented approximately five percent of the Company's issued and outstanding common shares. The Bid commenced on June 21, 2004 and terminated on June 20, 2005. During 2005, the Company did not purchase any common shares under this Bid. On June 15, 2005 the Company announced its intention to make a Normal Course Issuer Bid through the facilities of the Toronto Stock Exchange to acquire for cancellation up to 1.704 million common shares of the Company, which represented approximately five percent of the Company's issued and outstanding common shares. The Bid commenced on June 21, 2005 and terminated on June 20, 2006. The Company did not purchase any common shares under this Bid. On June 19, 2006 the Company announced its intention to make a Normal Course Issuer Bid through the facilities of the Toronto Stock Exchange to acquire for cancellation up to 1.866 million common shares of the Company, which represented approximately five percent of the Company's issued and outstanding common shares. The Bid commenced on June 21, 2006 and will terminate on June 20, 2007. As at March 13, 2007, the Company had not purchased any shares under this Bid. (g) Per share amounts The following table summarizes the basis for determining basic and diluted per share amounts: 2006 2005 --------------------------------------------------------------------- Weighted average shares outstanding (thousands) 37,961 34,031 Dilutive stock options outstanding (thousands) 1,827 2,156 Shares repurchased with proceeds from dilutive stock options and returned to treasury (thousands) (913) (1,017) --------------------------------------------------------------------- Weighted average diluted common shares outstanding (thousands) 38,875 35,170 --------------------------------------------------------------------- Net earnings per common share Net earnings 23,737 49,065 Basic ($/share) 0.63 1.44 Diluted ($/share) 0.61 1.40 --------------------------------------------------------------------- --------------------------------------------------------------------- During 2006, 1.151 million stock options were anti-dilutive and were omitted from the weighted average diluted common shares outstanding calculation (2005: 0.277 million). 8. TAXES The difference between the expected income tax provision based on the combined federal and provincial statutory tax rate of 35.3 percent (2005: 38.7 percent) and the amount actually provided for is as follows: 2006 2005 --------------------------------------------------------------------- Expected future income taxes 8,323 29,226 Non-deductible Crown payment (257) 3,999 Alberta Royalty Tax Credit - (124) Resource allowance 501 (5,128) Crown royalty adjustments - (1,152) Rate differential between current and future income tax rates (11,705) (3,058) Non-deductible stock-based compensation expense 1,844 556 Other (523) 340 --------------------------------------------------------------------- Total future income taxes (1,817) 24,659 Capital taxes 1,657 1,756 --------------------------------------------------------------------- Total taxes (160) 26,415 --------------------------------------------------------------------- --------------------------------------------------------------------- The Company's future income tax liability as at December 31, 2006 and 2005 is comprised of the following: 2006 2005 --------------------------------------------------------------------- Property, plant and equipment having different income tax and accounting basis 95,115 97,395 Asset retirement obligation (6,065) (6,205) Share issue cost (1,881) (2,300) Non-capital loss (629) - --------------------------------------------------------------------- 86,540 88,890 --------------------------------------------------------------------- --------------------------------------------------------------------- Note that non-capital losses can be carried forward for a maximum of 20 years. 9. COMMITTMENTS Real is committed to payments under operating leases for office space and vehicles as follows: 2007 792 2008 618 2009 930 2010 1,070 2011 1,070 Thereafter 1,516 --------------------------------------------------------------------- 5,996 --------------------------------------------------------------------- --------------------------------------------------------------------- Real is also committed to spend approximately $18.9 million prior to December 31, 2007 for Canadian Exploration Expenditures related to the issuance of flow-through shares on July 13, 2006. 10. ASSET RETIREMENT OBLIGATION The total future asset retirement obligation was estimated based on the Company's net ownership interest in all wells and facilities, estimated costs to reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred in future periods. The Company has estimated the net present value of its total asset retirement obligations to be $19.8 million at December 31, 2006 based on a total future liability of $36.9 million. These payments are expected to be made over the next 25 years with the majority of costs incurred between 2014 and 2018. The Company's credit adjusted risk-free rate of seven percent (2005: seven percent) and an inflation rate of two percent were used to calculate the net present value of the asset retirement obligation. The following table reconciles the Company's total asset retirement obligation: 2006 2005 --------------------------------------------------------------------- Balance at January 1 17,896 13,635 Increase in liabilities 1,525 1,702 Increase in liabilities - corporate acquisition - 458 Increase in liabilities - property acquisitions - 1,485 Settlement of liabilities (860) (355) Accretion expense 1,240 971 --------------------------------------------------------------------- Balance at December 31 19,801 17,896 --------------------------------------------------------------------- --------------------------------------------------------------------- 11. CONTRIBUTED SURPLUS The following table reconciles the Company's contributed surplus: 2006 2005 --------------------------------------------------------------------- Balance at January 1 2,077 1,048 Stock-based compensation expense 5,223 1,437 Options exercised (367) (408) --------------------------------------------------------------------- Balance at December 31 6,933 2,077 --------------------------------------------------------------------- --------------------------------------------------------------------- 12. FINANCIAL INSTRUMENTS The Company's financial instruments recognized in the Consolidated Balance Sheets consist of accounts receivable, accounts payable, accrued assets and liabilities and long-term debt. The carrying value of these balances approximates their fair market value. A substantial portion of the Company's accounts receivable are with customers and joint-venture partners in the oil and gas industry and are subject to normal industry credit risks. Purchasers of the Company's oil, gas and natural gas liquids are subject to an internal credit review to minimize the risk of non-payment. The Company is exposed to interest rate risk to the extent that changes in market interest rates will impact the Company's cash and cash equivalents that have a floating interest rate. The bank facility is also based on a floating interest rate. The Company had no interest rate swaps or hedges at December 31, 2006. Real Resources Inc. is a Calgary based oil and natural gas company active in the exploration, development and production of crude oil and natural gas in Western Canada. The Company has grown through exploration, development and strategic acquisitions. Real 2007 Disclosure -------------------- This new release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "might", and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward- looking information and statement pertaining to the following: - estimated volumes and timing of future production; - business plans for drilling, exploration and development; - estimated dates for seismic and other programs; and - other expectations, beliefs, plans, goals, objectives, assumptions, information and statements about possible future events, conditions, results of operations and performance. Various assumptions were used in drawing the conclusions or making the forecasts and projections contained in the forward-looking statements throughout this news release. Statements which discuss business plans for drilling, exploration and development in 2007 and beyond assume that the extraction of crude oil, natural gas and natural gas liquids remains at current economic levels. The forward-looking information and statements contained in this news release reflect several material factors, expectations and assumptions including, without limitation: - the quantity of reserves; - oil and natural gas production levels; - commodity prices, foreign currency exchange rates and interest rates; - capital expenditure programs and other expenditures; - supply and demand for oil and natural gas; - expectations regarding Real's ability to raise capital and to continually add to reserves through acquisitions and development; - schedules and timing of certain projects and Real's strategy for growth; - Real's future operating and financial results; and - treatment under governmental regulatory regimes and tax, environmental and other laws. The forward-looking information and statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties, which could cause actual results to differ materially from those anticipated and described in the forward-looking statements. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation: - volatility in market prices for oil and natural gas; - volatility or fluctuations in oil and natural gas production levels; - volatility in exchange rates for the Canadian dollar relative to other world currencies; - liabilities and risks inherent in oil and natural gas operations including geological, technical, drilling and processing problems; - uncertainties associated with estimating reserves; - competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; - incorrect assessments of the value of acquisitions; - Real's success at acquisition, exploitation and development of reserves; - changes in general economic, market and business conditions in Canada, North America and worldwide; and - actions by governmental or regulatory authorities including changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry. We caution that the foregoing list of assumptions, risks and uncertainties is not exhaustive. Additional information on these and other factors which could affect operations or financial results are included under the heading "Risk Factors" in Real's Annual Information Form as filed under Real's profile on www.sedar.com. Additional information may also be found in Real's other reports on file with Canadian securities regulatory authorities. The forward-looking information and statements contained in this news release speak only as of the date of this new release, and we assume no obligation to publicly update or revise them to reflect news events or circumstances, except as may be required pursuant to applicable laws. %SEDAR: 00004883E

For further information:

For further information: interested parties may contact: Lowell E.
Jackson, President & CEO, Real Resources Inc., Telephone: (403) 262-9077, Fax:
(403) 262-6403

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REAL RESOURCES INC.

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