Rider Resources Ltd. Year End 2006 Results



    TSX: RRZ

    CALGARY, March 22 /CNW/ -

    
    -------------------------------------------------------------------------
    Financial Highlights     Three Months Ended        Twelve Months Ended
                                December 31                December 31
    (thousands except                         %                           %
     per share amounts)   2006       2005  Change     2006       2005  Change
    -------------------------------------------------------------------------

    Oil and gas
     revenue          $  37,840  $  55,789   (32) $ 154,153  $ 152,820     1

    Funds from
     operations(1)    $  21,504  $  35,782   (40) $  90,261  $  94,118    (4)
      Per share
       - basic        $    0.47  $    0.78   (40) $    1.97  $    2.08    (5)
      Per share
       - diluted      $    0.45  $    0.74   (39) $    1.88  $    1.97    (5)

    Net income        $   4,272  $  15,589   (73) $  30,311  $  38,902   (22)
      Per share
       - basic        $    0.09  $    0.34   (74) $    0.66  $    0.86   (23)
      Per share
       - diluted      $    0.09  $    0.32   (72) $    0.63  $    0.81   (22)

    Net capital
     expenditures     $  37,192  $  41,379   (10) $ 147,767  $ 124,649    19

    Total assets                                  $ 355,757  $ 249,029    43

    Long term debt,
     plus working
     capital
     deficiency                                   $ 130,453  $  69,463    87

    Shareholders'
     equity                                       $ 163,827  $ 129,532    26

    Weighted average
     shares outstanding
      - basic            45,859     45,612     1     45,842     45,240     1
      - diluted          47,637     48,272    (1)    48,005     47,756     5

    Shares outstanding
      - basic                                        45,861     45,700     1
      - diluted                                      49,763     49,955    (4)
    -------------------------------------------------------------------------
    Operational
     Highlights
    -------------------------------------------------------------------------
    Average daily
     production

      Natural gas (mcf)  40,300     38,577     4     42,413     32,897    29
      Natural gas
       liquids (bbls)     1,262      1,458   (13)     1,289      1,203     7
      Crude oil (bbls)      635        339    87        467        357    31
      Oil equivalent
       (boes 6:1)         8,613      8,226     5      8,825      7,042    25

    Average sales
     price
      Natural gas
       ($/mcf)             7.53      12.76   (41)      7.32       9.84   (26)
      Natural gas
       liquids ($/bbl)    53.57      62.96   (15)     62.02      59.83     4
      Crude oil
       ($/bbl)            62.41      62.42     -      66.35      61.38     8

    Expenses
      Production
       expenses ($/boe)    7.31       6.80     8       6.98       7.12    (2)
      General &
       administrative
       expenses ($/boe)    2.31       0.58   298       0.85       1.00   (15)

    Operating netback
     ($/boe)              31.57      48.94   (35)     30.44      38.64   (21)
    -------------------------------------------------------------------------

    Note:  (1) Funds from operations and funds from operations per share are
           not recognized measures under Canadian generally accepted
           accounting principles.

           See Management's Discussion and Analysis for disclaimer.

    President's Message

    Rider Resources Ltd. is very pleased to release its financial and
operating results for the quarter and year ended December 31, 2006.

    Operations

    -   $147.8 million was invested in the Company's exploration and
        development program in the year ended December 31, 2006, which
        included drilling 55 wells (43 net) with a success rate of
        97 per cent.

    -   Production grew by 25 per cent over 2005, to average 8,825 boe per
        day in the year ended December 31, 2006.  Production for the three
        months ended December 31, 2006 grew by 5 per cent over the fourth
        quarter of 2005, to average 8,613 boe per day.

    -   Operating costs continued to decline, averaging $6.98 per boe in the
        year ended December 31, 2006, down 2 per cent over the same period in
        2005 while averaging $7.31 per boe in the fourth quarter, up
        8 per cent over the same period in 2005.

    -   The finding and development costs for the year were $20.67 per boe
        proven plus probable, with future capital and after revisions.

    Financial

    -   The average natural gas price received by the Company in 2006
        declined by 26 per cent, as a result revenues increased only by
        1 per cent, to $154.2 million, for the year ended December 31, 2006
        when compared to 2005, and funds from operations for the year ended
        December 31, 2006 totaled $90.3 million, down 4 per cent when
        compared to 2005.

    -   Diluted funds from operations per share were down 5 per cent to
        $1.88 per share for the year ended December 31, 2006 as compared to
        $1.97 per share in 2005.

    -   Net income for the year ended December 31, 2006 was $30.3 million, or
        $0.63 per share on a diluted basis, a 22 per cent decrease over the
        same period in 2005.

    -   The balance sheet remained strong with long term debt (plus working
        capital deficiency) of $130.5 million.
    

    Outlook

    Last year was a challenging year for our industry. Finding and
development costs increased significantly with rapid escalation in all service
costs due to high levels of industry activity. Commodity prices, particularly
for natural gas, declined during the year. Property acquisition costs were
extremely high, driven primarily by income trust purchasers as they filled
their need to add assets. Faced with these factors, which were limiting our
ability to grow, in September we reached an agreement to sell the majority of
our production to an income trust and retain a small production portfolio.
However, with the announcement in October by the Government of Canada to make
changes to the taxation of income trusts, we elected in December to cancel the
agreement and focus on growing the Company.
    As 2006 drew to a close, natural gas storage levels were at historic
highs, winter weather in key heating regions had not yet appeared and most
industry participants were uncertain as to their corporate direction. Thus far
in 2007, equity market valuation for oil and gas producers have been very
negative, with stock prices falling throughout the first quarter, as the
results of 2006 weigh on investors' perception of the sector.
    However, at Rider, we view the prospects for creating value in the oil
and gas business with great optimism. Winter weather has shrunk natural gas
inventories and reduced drilling activity, and the resulting declining supply
has boosted natural gas prices. Based on the futures market, we currently
estimate Rider's 2007 average gas price will increase 9 per cent over 2006,
with winter 2007/2008 expected to be 20 per cent higher than this winter.
    Strengthening our optimistic view is the fact that land costs are lower,
access to farmin opportunities has improved and service costs are
approximately 20 per cent lower in the first quarter, with half of these cost
reductions gained through improved efficiency. We anticipate further cost
reductions after spring break up.
    As a result of the proposed income trust taxation changes and subsequent
market decline of that sector, oil and gas property acquisition costs have
declined significantly. Acquisition metrics are now at levels which will
generate good returns, and we are actively reviewing opportunities to make
acquisitions which complement our drilling program.
    We have a very active $50 million first quarter capital program with 20
to 22 wells expected to be completed. We are planning to invest $135 million
on our exploration and development program in 2007.
    We are forecasting an average production rate of 10,000 boe per day for
2007. Using a $8.00 per thousand cubic feet natural gas price and a
US$60 WTI per barrel oil price, for 2007 we are forecasting funds from
operations of about $110 million, earnings of approximately $32 million and
projected year end debt of $135 million.
    We have added three professional staff, along with five field staff, to
manage the 2007 capital program and ensure we are ready for growth into 2008
through the expansion of our exploration program.
    We encourage anyone interested in further details of our properties,
operations and financial performance to visit our website at www.riderres.com.

    Craig Stewart
    President and Chief Executive Officer
    March 22, 2007



    MANAGEMENT'S DISCUSSION AND ANALYSIS

    March 22, 2007

    This Management's Discussion and Analysis ("MD&A") should be read in
conjunction with the audited consolidated financial statements and MD&A for
the years ended December 31, 2006 and 2005. This MD&A contains
"Forward-Looking Statements". Please see the disclaimer regarding forward
looking statements on page 23.
    Funds from operations and funds from operations per share are not
recognized measures under Canadian generally accepted accounting principles
("GAAP"). Management believes that in addition to net income, funds from
operations is a useful supplemental measure as it provides an indication of
the results generated by the Company's principal business activities prior to
the consideration of how those activities are financed or how the results are
taxed. Investors should be cautioned, however, that these measures should not
be construed as an alternative to net income determined in accordance with
GAAP as an indication of the Company's performance. The Company's method of
calculation of these measures may differ from other companies, and
accordingly, they may not be comparable to measures used by other companies.
    This MD&A presents and discusses results on a boe basis. This
presentation may be misleading, particularly if used in isolation. A boe
conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead. All boe conversions in this report are derived by
converting natural gas to oil in the ratio of six thousand cubic feet of
natural gas to one barrel of oil.

    Oil and Gas Reserves

    The oil and gas reserve estimates are made using all available geological
and reservoir data as well as historical production data. Estimates are
reviewed and revised as appropriate. Revisions occur as a result of changes in
prices, costs, fiscal regimes, reservoir performance or a change in the
Company's plans. The effect of changes in proved oil and gas reserves on the
financial results and position of the Company is described under the heading
"Full Cost Accounting for Oil and Gas Activities".

    
    Selective Annual Information

    ($thousands, except
     per share amounts)                     2006          2005          2004
    -------------------------------------------------------------------------
    Oil and gas revenue                  154,153       152,820        50,727
    Net income                            30,311        38,902        11,478
      - per share - basic                   0.66          0.86          0.26
      - per share - diluted                 0.63          0.81          0.26
    Total assets                         355,757       249,029       143,975
    Long term debt                       121,600        60,146        37,100


    Summary of Quarterly Results

                                   2006                        2005
    ($thousands,
     except per
     share amounts)      Q4     Q3     Q2     Q1     Q4     Q3     Q2     Q1
    -------------------------------------------------------------------------
    Oil and gas
     revenue         37,840 37,180 37,713 41,420 55,789 45,299 31,482 20,250
    Net income        4,272  5,362 10,627 10,050 15,589 13,795  6,205  3,313
      - per share
       - basic         0.09   0.12   0.23   0.22   0.34   0.30   0.14   0.07
      - per share
       - diluted       0.09   0.11   0.22   0.21   0.32   0.29   0.13   0.07
    Funds from
     operations      21,504 21,699 21,453 25,605 35,782 30,107 17,370 10,859
      - per share
       - basic         0.47   0.47   0.47   0.56   0.78   0.66   0.39   0.24
      - per share
       - diluted       0.45   0.45   0.45   0.53   0.74   0.63   0.37   0.23


    Trends

    The quarterly results will continue to be impacted by an expanded
exploration and development program and volatile commodity prices.

    Production

                                  Three Months Ended           Year Ended
                                      December 31             December 31
                                    2006        2005        2006        2005
    -------------------------------------------------------------------------

    Crude Oil (bbls/d)               635         339         467         357
    Natural Gas Liquids (bbls/d)   1,262       1,458       1,289       1,203
    Total Liquids (bbls/d)         1,897       1,797       1,756       1,560

    Natural Gas (mcf/d)           40,300      38,577      42,413      32,897
    -------------------------------------------------------------------------
    Total (boe/d)                  8,613       8,226       8,825       7,042
    -------------------------------------------------------------------------
    

    Average daily production of crude oil and natural gas liquids for the
year ended December 31, 2006, increased to 1,756 bbls/d from 1,560 bbls/d
during 2005. For the quarter ended December 31, 2006, crude oil and natural
gas liquids averaged 1,897 bbls/d as compared to 1,797 bbls/d during the
fourth quarter of 2005. Average daily natural gas sales increased for the
quarter to 40,300 mcf/d from 38,577 mcf/d recorded in the same period of the
previous year. Natural gas sales averaged 42,413 mcf/d during the year as
compared to 32,897 mcf/d in 2005. On a boe basis production for the year
averaged 8,825 boes/d and the fourth quarter average production was
8,613 boes/d. The Company's internally generated exploration and development
program has provided all of the production growth.

    
    Financial Performance

                                Three Months Ended           Year Ended
                                    December 31             December 31
                                  2006        2005        2006        2005
    -----------------------------------------------------------------------
    Realized Prices
    Crude Oil ($/bbl)            62.41       62.42       66.35       61.38
    Natural Gas Liquids ($/bbl)  53.57       62.96       62.02       59.83
    Natural Gas ($/mcf)           7.53       12.76        7.32        9.84
    


    Commodity Prices

    The price for West Texas Intermediate averaged U.S. $66.25 per barrel for
the 2006 year as a result of very strong world demand for crude oil. The
average price received by the Corporation for crude oil during the year was
$66.35 per bbl, an 8 per cent increase over 2005. The average crude oil price
during the fourth quarter was $62.41 per bbl. The average natural gas liquids
price was $62.02 per bbl for the year ended December 31, 2006 and
$53.57 per bbl during the fourth quarter.
    The NYMEX price averaged US$6.98 per mmbtu during the year while the AECO
natural gas price averaged $6.54 per mmbtu. The realized natural gas price for
the Corporation averaged $7.32 per mcf during the year ended December 31,
2006, versus $9.84 per mcf in 2005. For the fourth quarter, natural gas prices
averaged $7.53 per mcf as compared to $12.76 per mcf in 2005. North American
natural gas prices during 2006 were very volatile. NYMEX began the year at
over US$10.00 per mmbtu and reached a low of US$4.20 per mmbtu in September.
The following factors contributed to the volatility in natural gas prices;
production which was interrupted as a result of hurricanes in the fall of 2005
came back on stream; production increases as a result of high industry
activity levels and historically high levels of natural gas in storage.

    
    Revenue

    Revenues by Product

    thousands                                             2006          2005
    -------------------------------------------------------------------------

    Natural Gas                                    $   113,359   $   118,151
    Crude Oil                                           11,316         7,993
    Natural Gas Liquids                                 29,179        26,268
    Other                                                  299           408
    -------------------------------------------------------------------------
    Total Revenue                                  $   154,153   $   152,820
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    With the production growth as a result of the Company's exploration and
development program, revenues for the year increased to $154.2 million as
compared to $152.8 million in 2005 despite much weaker natural gas prices. 
During the fourth quarter, revenues totaled $37.8 million as compared to
$55.8 million in the fourth quarter of 2005.

    Royalties

    Royalties for 2006, net of the ARTC, totaled $31.6 million (21 per cent
of revenues), compared with $33.5 million (22 per cent of revenues) in 2005.

    Expenses

    Production expenses for the year were $22.5 million. On a per boe basis,
production expenses were $6.98, as compared to $7.12 in 2005. For the three
months ended December 31, 2006 production costs were $7.31 per boe as compared
to $6.80 per boe in the same period in 2005. The Company's operating costs
per boe have remained relatively unchanged in spite of significant increases
in the cost of services in the industry.
    In the fourth quarter of 2006 transportation costs totaled $0.5 million,
as compared to $0.2 million in the same quarter in 2005. For the year ended
December 31, 2006, transportation costs were $2.0 million, as compared to
$1.7 million for 2005. These costs have increased as a result of production
volume growth.
    Interest expense for the year was $4.8 million compared with $2.5 million
for 2005. Interest expense during the fourth quarter was $1.6 million compared
with $0.8 million for the same period of 2005. Interest expense has increased
as a result of the higher debt levels in the Company during 2006.
    General and administrative expenses for the year ended December 31, 2006,
were $2.7 million or $0.85 per boe. This compares with $2.6 million or
$1.00 per boe for the year ended December 31, 2005. For the fourth quarter,
general and administrative expenses were $2.31 per boe. Included in the fourth
quarter general and administration expense is $1.6 million in costs associated
with the cancelled arrangement with Shiningbank Energy Income Fund.
    Depletion and depreciation expense amounted to $45.1 million or
$14.00 per boe for the year ended December 31, 2006, compared with
$26.6 million or $10.35 per boe for 2005. The Company's depletion and
depreciation rate increased in 2006 as a result of higher costs in adding new
reserves.
    A stock-based compensation expense of $3.2 million or $0.99 per boe, was
recorded for the year ended December 31, 2006 as compared to $3.2 million, or
$1.23 per boe, for the year ended December 31, 2005.

    
    Net Income and Funds from Operations per boe

                          Three      Three
                         Months     Months             Year       Year
                          Ended      Ended            Ended      Ended
                       December   December    %    December   December    %
                       31, 2006   31, 2005 Change  31, 2006   31, 2005 Change
    -------------------------------------------------------------------------
    Revenue           $   47.75  $   73.71   (35) $   47.86  $   59.45   (19)
      Royalties, net
       of ARTC             8.28      17.68   (53)      9.82      13.02   (25)
      Transportation
       expenses            0.58       0.29   100       0.62       0.67    (7)
      Production
       expenses            7.31       6.80     8       6.98       7.12    (2)
    -------------------------------------------------------------------------
    Operating Netback     31.57      48.94   (35)     30.44      38.64   (21)
      General and
       administrative
       expenses            2.31       0.58   298       0.85       1.00   (15)
      Interest expense     2.01       1.02    97       1.48       0.96    54
      Large
       corporations tax       -       0.01     -          -       0.02     -
    -------------------------------------------------------------------------
    Funds from
     Operations           27.26      47.33   (42)     28.10      36.66   (29)
      Depletion,
       depreciation and
       accretion          16.22      11.74    38      14.00      10.35    35
      Stock-based
       compensation
       expense             0.48       1.29   (63)      0.99       1.23   (19)
      Future income
       taxes               5.16      13.70   (62)      3.70       9.97   (63)
    -------------------------------------------------------------------------
    Net Income        $    5.40  $   20.60   (74) $    9.41  $   15.11   (38)
    -------------------------------------------------------------------------

    Taxes

    The Company's future tax provision for the year was $11.9 million
(28.2 per cent effective rate) as compared to $26.6 million (39.6 per cent
effective rate) in 2005. The Large Corporations Tax was eliminated in 2006.
The Company has the following federal tax pools as at December 31, 2006:

    (thousands)                                                         2006
    -------------------------------------------------------------------------

    Canadian Exploration Expense                                           -
    Canadian Development Expense                                 $   101,085
    Canadian Oil and Gas Property Expense                             75,907
    Undepreciated Capital Cost                                        91,390
    Other                                                              4,486
    Capital Losses                                                    22,827
    -------------------------------------------------------------------------
    Total Tax Pools                                              $   295,695
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Net Earnings

    Net income for the year ended December 31, 2006 was $30.3 million, down
from $38.9 million for the year ended December 31, 2005. Diluted earnings per
share for the year ended December 31, 2006, decreased to $0.63 from $0.81 per
share for the year ended 2005. In the fourth quarter net income was
$4.3 million as compared to $15.6 million for the same period in 2005. Net
income decreased to $0.09 per diluted share during the fourth quarter as
compared to $0.32 per share for the same period in 2005. Funds from operations
for the year decreased to $90.3 million ($1.88 per diluted share) compared
with $94.1 million ($1.97 per diluted share) for 2005. Funds from operations
during the three months ended December 31, 2006 were $21.5 million ($0.45 per
diluted share) as compared to $35.8 million ($0.74 per share) in the fourth
quarter of 2005. Primary reasons for the decrease in cash flow for the year
were the lower commodity prices in 2006 when compared to 2005, which were not
offset by production growth.

    Net Asset Value Before Tax(1)

    Rider's net asset value per share at December 31, 2006 was $8.74 per
basic share and on a diluted basis $8.78 per share using Paddock Lindstrom &
Associates ("PLA") forecasted prices discounted at 10 per cent, and $11.83 per
basic share and $11.72 per diluted share using PLA forecasted prices
discounted at five per cent. The PLA Report has been prepared in accordance
with the standards contained in the COGE Handbook and the reserve definitions
contained in NI 51-101.

    
                                                              2006
    (thousands - except per share amounts)             PV 5%        PV 10%
    -------------------------------------------------------------------------

    Proved plus probable reserve value
     (10% discount before tax)(2)                  $   626,313   $   484,778
    Undeveloped acreage(3)                              37,778        37,778
    Seismic(4)                                           8,918         8,918
    Long term debt plus working capital deficiency    (130,453)     (130,453)
                                                  ---------------------------
    Net asset value - Basic                            542,556       401,021
    Exercise of stock options                           20,350        20,350
                                                  ---------------------------
    Net asset value - Diluted                      $   562,906   $   421,371
                                                  ---------------------------
                                                  ---------------------------
    Common shares outstanding
      - Basic                                           45,861        45,861
      - Diluted                                         49,763        49,763
    Net asset value per common share
      - Basic                                      $     11.83   $      8.74
      - Diluted                                    $     11.31   $      8.49

    (1)  The Company's net asset value before tax is measured with reference
         to the present value of future estimated net cash flows from
         reserves estimated by PLA, the independent reserve engineers, and
         including land, seismic data, adjustments for working capital
         deficiency and bank debt at year end. This calculation can vary
         significantly depending on the natural gas and oil price assumptions
         used by PLA. This calculation does not represent a "going-concern"
         value since it only assumes the reserves contained in the PLA
         report.

    (2)  Reserve values are based on before tax estimates of future cash
         flows as evaluated by our independent qualified reserve evaluators,
         PLA, using their future commodity price forecast as presented in the
         pricing assumptions (see 2006 Annual Information Form).

    (3)  Undeveloped land values are based on internal estimates of market
         value considering recent sales of similar properties in the same
         general area.

    (4)  Seismic inventory values are an internal estimate of replacement
         value.

    (5)  Calculated using outstanding common shares and options at year-end.
    

    Liquidity and Capital Resources

    As at December 31, 2006, total long term debt plus working capital
deficiency was $130.5 million. Net debt to 2006 funds from operations is
1.4 times. The Company has a committed credit facility of $150.0 million with
a syndicate of banks. The facility is a borrowing base facility which is
determined among other things by the Company's current reserve report, results
of operations, commodity prices and the economic environment.
    A capital budget of $135.0 million has been approved by the Board of
Directors for 2007. This capital program will be financed through internally
generated cash flow, a flow-through share offering of $14.8 million completed
in February, 2007 and the Company's bank lines of credit.
    The Company manages the pace of its capital spending program by
monitoring production and commodity prices and resulting funds generated from
operations. Should circumstances affect funds generated from operations in a
detrimental way, the Company is capable of reducing capital activity levels.

    Contractual Obligations

    In the normal course of business, Rider is obligated to make future
payments. These obligations represent contracts and other commitments that are
known and non-cancellable.
    The following is a summary of the Corporation's contractual obligations
and commitments as at December 31, 2006:

    
                                      Payments Due by Period
                        Total     2007      2008     2009     2010  2011 and
                                                                       there-
                                                                       after
    -------------------------------------------------------------------------
    Debt
     repayments(1)    $121,600  $     -  $121,600  $     -  $     -  $     -
    Transportation         871      596       269        6        -        -
    Office premises      1,640      328       328      328      328      328
    -------------------------------------------------------------------------
    Total
     contractual
     obligations      $124,111  $   924  $122,197  $   334  $   328  $   328
    -------------------------------------------------------------------------

    (1)  Based on the existing terms of the revolving credit facility, the
         first payment may be required in June 2008. However it is expected
         the revolving credit facility will be extended and no repayments
         will be required. (see note 5)

    Capital Expenditures

    During the year ended December 31, 2006, the Company spent a total of
$147.8 million on capital expenditures, a breakdown of which is outlined
below.

                                                    Year ended    Year ended
                                                   December 31,  December 31,
    (thousands)                                           2006          2005
    -------------------------------------------------------------------------
    Net acquisitions                               $      (256)  $    (2,186)
    Land and seismic                                    10,919        21,503
    Drilling                                            97,319        64,298
    Production and well equipment                       10,782         8,649
    Plant and facilities                                27,244        29,316
    Other                                                1,759         3,069
    -------------------------------------------------------------------------
                                                   $   147,767   $   124,649
    -------------------------------------------------------------------------
    

    Off Balance Sheet Arrangements

    As at the date of the Management's Discussion and Analysis, Rider did not
have any off balance sheet arrangements.

    Related Party Transactions

    A director of the Company is also a partner in a law firm which is used
extensively for legal work related to the Company's activities. Fees for this
work were charged at the law firm's standard billing rates.

    Proposed Transactions

    As at the date of this Management's Discussion and Analysis, the Company
is not in discussions on any transactions outside the normal course of
business. As part of the Company's normal course of business it continually
reviews acquisition opportunities.

    Financial Instruments

    The Company has a natural gas physical sale costless collar in effect
from April 1, 2007 to October 31, 2007 on 5,000 gigajoules per day in a price
band of $6.75 to $8.21 per gigajoule and from April 1, 2007 to October 31,
2006 on 5,000 gigajoules per day in a price band of $6.75 to $8.17 per
gigajoule. The Company may use, from time to time, financial instruments to
hedge its commodity prices to ensure it has sufficient capital resources to
carry out its exploration and development program.

    Common Shares Outstanding

    As at the date of this Management's Discussion and Analysis, the Company
had 48,281,860 common shares and 4,161,269 options to purchase common shares
outstanding.

    Application of Critical Accounting Estimates

    The significant accounting policies used by Rider are disclosed in note 2
to the Consolidated Financial Statements. Certain accounting policies require
that management make appropriate decisions with respect to the formulation of
estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses. The following discusses such accounting
policies and is included in Management's Discussion and Analysis to aid the
reader in assessing the critical accounting policies and practices of the
Company and the likelihood of materially different results being reported.
Rider's management reviews its estimates regularly. However, the emergence of
new information and changed circumstances may result in actual results or
changes to estimated amounts that differ materially from current estimates.
    The following assessment of significant accounting policies is not meant
to be exhaustive. The Company might realize different results from the
application of new accounting standards promulgated, from time to time, by
various rule-making bodies.

    Petroleum and Natural Gas Reserves

    All of Rider's petroleum and natural gas reserves are evaluated and
reported on by independent petroleum engineering consultants in accordance
with Canadian Securities Administrator's National Instrument 51-101
("NI-51-101"). The evaluation of reserves is a subjective process. Forecasts
are based on engineering data, projected future rates of production, commodity
prices and the timing of future expenditures, all of which are subject to
numerous uncertainties and various interpretations. The Company expects that
its estimates of reserves will change to reflect updated information. Reserve
estimates can be revised upward or downward based on the results of future
drilling, testing, production levels and changes in costs and commodity
prices.

    Depletion Expense

    The Company uses the full cost method of accounting for exploration and
development activities. All costs associated with exploration and development
are capitalized, into a single Canadian cost centre, whether successful or
not. The aggregate of net capitalized costs and estimated future development
costs less estimated salvage values is amortized using the unit-of-production
method based on estimated proved oil and gas reserves.

    Unproved Properties

    Certain costs related to unproved properties are excluded from costs
subject to depletion until proved reserves have been established or impairment
occurs. These properties are reviewed quarterly and any impairment is
transferred to the costs being depleted.

    Full Cost Accounting Ceiling Test

    The carrying value of property, plant and equipment is reviewed at least
annually for impairment. Impairment occurs when the carrying value of assets
is not recoverable by the future undiscounted cash flows. The cost recovery
ceiling test is based on estimates of proved reserves, production rate,
petroleum and natural gas prices, future costs and other relevant assumptions.
By their nature, these estimates are subject to measurement uncertainty and
the impact on the financial statements could be material. Any impairment would
be charged as additional depletion and depreciation expense.

    Future Taxes

    The Company uses the liability method of tax allocation. Differences
between the tax basis of an asset or liability and its carrying amount on the
balance sheet are used to calculate future income tax liabilities or assets.
Future income tax assets or liabilities are calculated using the substantially
enacted tax rates anticipated to apply in the period that the temporary
differences are expected to reverse.

    Asset Retirement Obligations

    The asset retirement obligation is estimated based on existing laws,
contracts or other policies. The fair value of the obligation is based on
estimated future costs for abandonment and reclamation discounted at a credit
adjusted risk free rate. The liability is adjusted each reporting period to
reflect the passage of time, with the accretion charged to earnings and for
revisions to the estimated future cash flows. By their nature, these estimates
are subject to measurement uncertainty and the impact on the financial
statements could be material.

    Legal, Environment Remediation and Other Contingent Matters

    The Company is required to both determine whether a loss is probable
based on judgment and interpretation of laws and regulations and determine
that the loss can reasonably be estimated. When the loss is determined it is
charged to earnings. The Company's management must continually monitor known
and potential contingent matters and make appropriate provisions by charges to
earnings when warranted by circumstance.

    Acquisition Accounting

    Acquisitions are accounted for using the purchase method, whereby the
acquiring company includes the fair value of the assets of the acquired entry
on its balance sheet. The determination of fair value necessarily involves
many assumptions. The valuation of oil and gas properties primarily relies on
placing a value on the oil and gas reserves. The valuation of oil and gas
reserves entails the process described above under the caption "Oil and Gas
Reserves" but in contrast incorporates the use of economic forecasts that
estimate future changes in price and costs. In addition this methodology is
used to value unproved oil and gas reserves. The valuation of these reserves,
by their nature, is less certain than the valuation of proved reserves.

    Disclosure of Controls and Procedures

    Disclosure controls and procedures have been designed to ensure that
information required to be disclosed by Rider is accumulated and communicated
to the Company's management as appropriate to allow timely decisions regarding
required disclosures. The Company's Chief Executive Officer and Chief
Financial Officer have concluded, based on their evaluation as of the end of
the period covered by the annual filings, that the Company's internal controls
over financial reporting are effective to provide reasonable assurance that
material information related to the issuer, is made known to them by others
within the Company. It should be noted that while the Company's Chief
Executive Officer and Chief Financial Officer believe that the Company's
internal controls and procedures provide a reasonable level of assurance that
they are effective, they do not expect that these 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.
    No changes were made in the Company's internal control over financial
reporting during the year ended December 31, 2006, that have materially
affected, or are reasonably likely to materially affect, its internal control
over financial reporting.

    
    Update on Regulatory and Financial Reporting Matters:

    a)  New accounting policies:

        In April, 2005, a series of new accounting standards were released
        which established guidance for the recognition and measurement of
        financial instruments. These new standards include Section 1530
        "Comprehensive Income", Section 3855 "Financial Instruments -
        Recognition and Measurements", and Section 3865 "Hedges". The new
        standards also resulted in a number of significant consequential
        amendments to other accounting standards to accommodate the new
        sections. The standards require all applicable financial instruments
        to be classified into one of several categories including; financial
        assets and financial liabilities held for trading, held-to-maturity
        investments, loans and receivables, available-for-sale financial
        assets, or other financial liabilities. The financial instruments are
        then included on a company's balance sheet and measured at fair
        value, cost or amortized value, depending on the classification.
        Subsequent measurement and recognition of changes in value of the
        financial instruments also depends on the initial classification.
        These standards are effective for interim and annual financial
        statements for fiscal years beginning on or after October 1, 2006 and
        must be implemented simultaneously. The Company is still assessing
        the impact, if any, of these standards on the consolidated financial
        statements in preparation for adoption of the new standards on
        January 1, 2007.

    b)  Internal control reporting:

        In March 2006 Canadian Securities Administrators decided to not
        proceed with proposed Multilateral Instrument 52-111 Reporting on
        Internal Control over Financial Reporting and instead proposed to
        expand Multilateral Instrument 52-109 Certification of Disclosure in
        Issuers' Annual and Interim Filings. The major changes resulting from
        this is the Chief Executive Officer and Chief Financial Officer will
        be required to certify in the annual certificates that they have
        evaluated the effectiveness of internal controls over financial
        reporting ("ICOFR") as of the end of the financial year and disclose
        in the annual MD&A their conclusions about the effectiveness of
        ICOFR. There will be no requirement to obtain an internal control
        audit opinion from the issuer's auditors concerning management's
        assessment of the effectiveness of ICOFR. There is also no
        requirement to design and evaluate internal controls against a
        suitable control framework. This proposed amendment is expected to
        apply for the year ended December 31, 2008. Rider is continuing with
        its evaluation of ICOFR to ensure it meets the criteria for the
        proposed certification for December 31, 2008.
    

    Outlook for 2007

    The last year was a difficult year for the oil and gas industry.
Commodity prices saw unprecedented volatility and costs of services and
acquisitions were extremely high. So far in 2007 we have seen a decline in
activity in the industry and as a result service costs have declined. The
outlook for natural gas prices looks favorable as natural gas inventories have
declined and supply growth has not occurred as drilling has been curtailed. As
a result the margins in the industry should improve. In addition the changes
to the income trust rules appear to have reduced the cost of acquisitions. For
Rider these industry conditions will allow us to invest our capital with good
returns and to look at acquisitions with which will enhance our exploration
program.
    With a budgeted capital program of $135 million, which would result in
forecasted production averaging 10,000 boe per day in 2007. The capital
program will be invested in the Company's traditional core areas located in
West Central Alberta.



    
                             RIDER RE

SOURCES LTD. CONSOLIDATED BALANCE SHEETS (thousands) (UNAUDITED) ------------------------------------------------------------------------- December 31, December 31, 2006 2005 ------------- ------------- Assets Current assets Accounts receivable $ 23,282 $ 25,486 Prepaid expenses 1,209 981 ------------ ------------- 24,491 26,467 Investments (note 3) $ 4,000 - Property, plant and equipment (note 4) 327,266 222,562 ------------ ------------- $ 355,757 $ 249,029 ------------ ------------- ------------ ------------- Liabilities Current liabilities Accounts payable and accrued liabilities $ 33,344 $ 35,784 Long term debt (note 5) 121,600 60,146 Asset retirement obligations (note 6) 6,072 4,565 Future income taxes (note 7) 30,914 19,002 ------------ ------------- 191,930 119,497 ------------ ------------- Shareholders' equity Share capital (note 8) 93,029 92,185 Contributed surplus (note 8) 7,753 4,613 Retained earnings 63,045 32,734 ------------ ------------- 163,827 129,532 ------------ ------------- $ 355,757 $ 249,029 ------------ ------------- ------------ ------------- Commitments (note 11) Subsequent events (Notes 8 & 10) See accompanying notes to consolidated financial statements. RIDER RE

SOURCES LTD. CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS (DEFICIT) (thousands, except per share amounts) (UNAUDITED) ------------------------------------------------------------------------- Three Months Ended Years Ended December 31 December 31 2006 2005 2006 2005 ----------- ----------- ----------- ----------- Revenue Oil and gas sales $ 37,840 $ 55,789 $ 154,153 $ 152,820 Royalties, net of ARTC (6,561) (13,381) (31,626) (33,459) ----------- ----------- ----------- ----------- 31,279 42,408 122,527 119,361 ----------- ----------- ----------- ----------- Expenses Production 5,796 5,150 22,476 18,290 Transportation 463 222 2,005 1,713 Interest 1,591 773 4,776 2,459 General and administrative 1,830 436 2,756 2,568 Stock-based compensation 384 974 3,180 3,151 Depletion, depreciation and accretion 12,857 8,884 45,111 26,598 ----------- ----------- ----------- ----------- 22,921 16,439 80,304 54,779 ----------- ----------- ----------- ----------- Income before taxes 8,358 25,969 42,223 64,582 Taxes Large corporations tax - 10 - 61 Future income taxes (note 7) 4,086 10,370 11,912 25,619 ----------- ----------- ----------- ----------- 4,086 10,380 11,912 25,680 ----------- ----------- ----------- ----------- Net income 4,272 15,589 30,311 38,902 Retained earnings (deficit), beginning 58,773 17,145 32,734 (6,168) ----------- ----------- ----------- ----------- Retained earnings, ending $ 63,045 $ 32,734 $ 63,045 $ 32,734 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Net income per share - basic $ 0.09 $ 0.34 $ 0.66 $ 0.86 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Net income per share - diluted $ 0.09 $ 0.32 $ 0.63 $ 0.81 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- See accompanying notes to consolidated financial statements. RIDER RE

SOURCES LTD. CONSOLIDATED STATEMENTS OF CASH FLOWS (thousands) (UNAUDITED) ------------------------------------------------------------------------- Three Months Ended Years Ended December 31 December 31 2006 2005 2006 2005 ----------- ----------- ----------- ----------- Cash provided by (used in): Operating Net income $ 4,272 $ 15,589 $ 30,311 $ 38,902 Stock-based compensation 384 974 3,180 3,151 Future income taxes 4,086 10,370 11,912 25,619 Depletion, depreciation and accretion 12,857 8,884 45,111 26,598 Asset retirement expenditures (95) (35) (253) (152) ----------- ----------- ----------- ----------- 21,504 35,782 90,261 94,118 Net change in non-cash working capital 7,441 7,970 (464) 4,778 ----------- ----------- ----------- ----------- 28,945 43,752 89,797 98,896 ----------- ----------- ----------- ----------- Financing Increase (decrease) in long term debt 8,237 (2,867) 61,454 23,046 Issue of share capital, net of issue costs 10 494 516 2,707 ----------- ----------- ----------- ----------- 8,247 (2,373) 61,970 25,753 ----------- ----------- ----------- ----------- Investing Capital expenditures (37,192) (42,935) (148,023) (126,835) Proceeds on disposition of properties - 1,556 256 2,186 Purchase of investments - - (4,000) - ----------- ----------- ----------- ----------- (37,192) (41,379) (151,767) (124,649) ----------- ----------- ----------- ----------- Change in cash - - - - Cash, beginning - - - - ----------- ----------- ----------- ----------- Cash, ending $ - $ - $ - $ - ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- See accompanying notes to consolidated financial statements. Rider Resources Ltd. Notes to the Consolidated Financial Statements For the Year Ended December 31, 2006 (UNAUDITED) (thousands, except per share amounts) 1. Basis of Presentation The consolidated financial statements for the year ended December 31, 2006 include the accounts of Rider Resources Ltd. (the "Corporation"), its wholly-owned subsidiary Roberts Bay Resources Ltd. and the jointly owned Rider 2001 Energy Partnership. All intercompany transactions and balances have been eliminated. 2. Significant Accounting Policies Use of Estimates The consolidated financial statements of the Corporation have been prepared by management in accordance with Canadian generally accepted accounting principles. Since the determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of these financial statements requires the use of estimates and assumptions, which have been made with careful judgment. Specifically, the amounts recorded for depletion and depreciation of property, plant and equipment and the provision for asset retirement obligations and abandonment costs are based on estimates. The ceiling test is based on estimates of 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 such changes in such estimates in future periods could be significant. In the opinion of management, these financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies summarized below. Petroleum and Natural Gas Properties A portion of the exploration, development and production activities of the Corporation is conducted jointly with others. The consolidated financial statements reflect only the Corporation's proportionate interest in such activities. The Corporation follows the full cost method of accounting for its petroleum and natural gas properties. All costs directly related to the exploration for and development of petroleum and natural gas reserves, whether producing or non-producing, are capitalized into a single Canadian cost center. Such costs include land acquisition, geological and geophysical expenditures, lease rental costs on non-producing properties, drilling costs of both producing and non-producing wells, production equipment, asset retirement costs and overhead charges directly related to these activities. Proceeds of disposals are normally deducted from the full cost pool without recognition of a gain or loss, unless a change of 20% or more in the depletion and depreciation rate occurs. Depletion and Depreciation Petroleum and natural gas properties and related equipment are depleted and depreciated using the unit-of-production method, based on estimated proven reserves of oil and natural gas before royalties, as determined by independent consulting engineers. For the purpose of this calculation, production and reserves of natural gas are converted to barrels of oil equivalent based on relative energy content of six thousand cubic feet of natural gas to one barrel of oil. Costs of unproved properties are excluded from the calculation until proved reserves are established or impairment occurs. These properties are assessed periodically to ascertain whether impairment has occurred. Depreciation of office furniture and equipment is provided for on a declining basis at an annual rate between 20% and 33%. Ceiling Test The recoverability of a cost centre is tested by comparing the carrying value of the cost centre to the sum of the undiscounted cash flows expected from the production of proved reserves and the lower of cost and market of unproved properties. If the carrying value is unrecoverable the cost centre is written down to its fair value using the expected present value approach. This approach incorporates risks and uncertainties in the expected future cash flows from proved and probable reserves and the lower of cost and market of unproved properties which are discounted using a risk free rate. The cash flows are estimated using expected future product prices and costs. Asset Retirement Obligations This standard requires the recognition of the fair value of obligations associated with the retirement of tangible long-lived assets be recorded in the period the asset is put into use, constructed or purchased, with a corresponding increase to the carrying amount of the related asset. The obligations recognized are statutory, contractual or legal obligations. The liability is accreted over time for changes in the fair value of the liability through charges to asset retirement accretion which is included in depletion, depreciation and accretion expense. The costs capitalized to the related assets are amortized to earnings in a manner consistent with the depreciation, depletion and amortization of the underlying asset. Actual costs incurred upon settlement of the retirement obligations are charged against the obligation to the extent of the liability recorded. Financial Instruments The Corporation may use, from time to time, derivative financial instruments to manage exposure related to changes in oil and natural gas commodity prices. They are not used for trading or speculative purposes. The Corporation marks to market these instruments based on prevailing forward commodity prices in effect at the end of each reporting period. The resulting unrealized gain or loss is expensed in the current period and a corresponding receivable or liability is reported with the tax effect included in the future income tax provision and liability accounts. Realized gains or losses on changes in oil and natural gas commodity prices are recognized in income in the same period and in the same financial statement category as the income or expense arising from corresponding commodity contracts. Income Taxes Future income taxes are calculated using the liability method of tax allocation. Differences between the tax basis of an asset or liability and its carrying amount on the balance sheet are used to calculate future income tax liabilities or assets. Future income tax assets or liabilities are calculated using the substantially enacted tax rates anticipated to apply in periods that the temporary differences are expected to reverse. Flow-through Shares The Corporation has financed a portion of its exploration and development activity through the issue of flow-through shares. Under the terms of the flow-through share agreements, the tax attributes of the related expenditures are renounced to the subscribers. The estimated value of the tax pools foregone is reflected as a reduction to share capital and a corresponding increase in future income tax liability when the expenditures are renounced. Revenue Recognition Oil and gas sales revenue is recognized when the title and risks pass to the purchaser. Oil and gas sales have been presented prior to transportation costs and a separate expense for transportation costs has been presented in the consolidated statement of operations. Stock-based Compensation The Corporation uses the fair value method for valuing stock option grants. The fair value is measured at the grant date and charged to income over the vesting period with a corresponding increase in contributed surplus. Consideration paid on exercise of options is credited to share capital together with the amount of previously recognized compensation expense included in contributed surplus. Compensation cost attributable to awards to employees that call for settlement in cash or other assets are measured at intrinsic value and recognized over the vesting period. Changes in intrinsic value between the grant date and the measurement date result in a change in the measure of compensation cost. Per Share Amounts Basic per share amounts are computed by dividing net income by the weighted average number of shares outstanding for the period. Diluted per share amounts are calculated using the treasury stock method where the weighted average number of shares outstanding is adjusted for the dilutive effect of options. The dilutive effect of options is calculated as the net change in common shares resulting from the notional exercise of all in-the-money options assuming the proceeds are used to repurchase common shares at the average trading price during the period. 3. Investments On May 18, 2006, the Corporation acquired $4.0 million principal amount of 5.0 per cent secured convertible debentures from a private company. The debentures pay interest quarterly on March 31, June 30, September 30 and December 31 and have a maturity date of July 18, 2007. The debentures are convertible, at the option of the Corporation, to 8.0 million common shares at a conversion price of $0.50 per share. The investment is accounted for at cost. As of December 31, 2006 the market value of the investment was not significantly different from that of cost. 4. Property, Plant and Equipment December 31, December 31, 2006 2005 ------------------------------------------------------------------------- Cost $ 417,390 $ 267,968 Accumulated depletion and depreciation 90,124 45,406 ------------------------------------------------------------------------- $ 327,266 $ 222,562 ------------------------------------------------------------------------- ------------------------------------------------------------------------- During the year ended December 31, 2006, the Corporation capitalized overhead charges of $1,483 (2005 - $2,576). Costs related to unproved properties of $40,108 (2005 - $33,981) were excluded from the depletion calculation. Future development costs of proved reserves of $5,874 (2005 - $2,931) have been included in the depletion calculation. The following table summarizes the future benchmark prices and the Corporation's prices used in the ceiling test which determined that there is no impairment in the value of the Corporation's assets at December 31, 2006. Corpor- Corpor- Foreign Edmonton ation's ation's WTI Oil Exchange Par Oil Oil Price AECO Gas Gas Price ($US/bbl) Rate ($Cdn/bbl) ($Cdn/bbl) ($Cdn/mcf) ($Cdn/mcf) ------------------------------------------------------------------------- 2007 $ 61.00 0.87 $ 68.58 $ 65.04 $ 7.33 $ 7.91 2008 $ 60.00 0.87 $ 67.40 $ 64.33 $ 7.91 $ 8.55 2009 $ 60.00 0.87 $ 67.37 $ 64.33 $ 7.89 $ 8.54 2010 $ 58.00 0.87 $ 65.04 $ 62.07 $ 7.87 $ 8.53 2011 $ 56.00 0.87 $ 62.71 $ 59.83 $ 8.02 $ 8.70 2012 $ 57.12 0.87 $ 63.97 $ 61.20 $ 8.19 $ 8.90 Annual escal- ation there- after 2% 2% 2% 2% 2% ------------------------------------------------------------------------- 5. Long Term Debt At December 31, 2006, a Canadian chartered bank had provided the Corporation with a revolving line of credit of $150.0 million. Subsequent to December 31, 2006, a syndicate of banks has provided the Corporation with a revolving line of credit of $130.0 million and a Canadian chartered bank has provided the Corporation with an operating line of credit of $20 million. Advances under these facilities bear interest up to 0.5 per cent over the bank's prime lending rate and, bankers' acceptances bear a stamping fee between 0.9 per cent and 1.5 per cent depending upon the debt to EBITDA ratio of the Corporation. The credit facilities are subject to annual renewal and are secured with a first floating charge debenture on the Corporation's assets and a general security agreement. If the facilities are not renewed by June 14, 2007, outstanding advances become term loans repayable on June 30, 2008. At December 31, 2006 the Corporation's effective interest rate was 5.35 per cent per annum. 6. Asset Retirement Obligations At December 31, 2006, the estimated total undiscounted amount required to settle asset retirement obligations was $14.9 million. These obligations will be settled based on the useful lives of the underlying assets, which currently extend up to 21 years into the future. This amount has been discounted using a credit adjusted risk-free interest rate of 8.0 per cent and inflation rate of 2.0 per cent. Changes to asset retirement obligations were as follows: December 31, December 31, 2006 2005 ------------------------------------------------------------------------- Asset retirement obligations, beginning $ 4,565 $ 3,575 Liabilities incurred 1,367 838 Liabilities settled (253) (152) Accretion 393 304 ------------------------------------------------------------------------- Asset retirement obligations, ending $ 6,072 $ 4,565 ------------------------------------------------------------------------- The asset retirement accretion expense of $393 has been included in depletion, depreciation, and accretion expense. 7. Future Income Taxes (a) The provision for future income taxes was determined as follows: Three Months Ended Years Ended December 31 December 31 2006 2005 2006 2005 ------------------------------------------------------------------------- Income before taxes $ 8,358 $ 25,969 $ 42,223 $ 64,582 Tax rate (%) 34.50 37.60 34.50 37.60 ----------- ----------- ----------- ----------- Expected provision for future income taxes 2,884 9,764 14,567 24,283 Non-deductible Crown payments, net of ARTC 750 3,071 3,590 7,441 Resource allowance (752) (2,831) (3,390) (7,290) Non-deductible stock- based compensation 132 366 1,097 1,185 Reduction in tax rates - - (2,523) - Utilization of previously recognized losses - - (930) - Other 1,072 - (499) - ----------- ----------- ----------- ----------- Future income taxes $ 4,086 $ 10,370 $ 11,912 $ 25,619 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- (b) Net Future Income Tax Asset (Liability) The tax effects of temporary differences that give rise to significant portions of the future income tax asset at December 31 are presented below: December 31, December 31, 2006 2005 ------------------------------------------------------------------------- Future income tax assets (liabilities): Capital assets, differences between net book value and value for tax purposes $ (17,624) $ (13,175) Timing of partnership items (15,391) (7,685) Asset retirement obligations 1,950 1,535 Share issue costs and other 151 323 ------------- ------------- Net future income tax (liability) $ (30,914) $ (19,002) ------------- ------------- ------------- ------------- 8. Share Capital Authorized - unlimited number of common shares - unlimited number of first and second preferred shares Common Shares --------------------------- Number of Shares Amount --------------------------- Balance at December 31, 2004 44,923 $ 90,705 Tax effect of flow-through shares issued in 2004 - (2,667) Exercise of stock options 777 2,707 Stock-based compensation on exercise of stock options - 1,440 ------------- ------------- Balance at December 31, 2005 45,700 $ 92,185 Exercise of stock options 161 516 Stock-based compensation on exercise of stock options - 328 ------------- ------------- Balance at December 31, 2006 45,861 $ 93,029 ------------- ------------- ------------- ------------- Subsequent to December 31, 2006, the Corporation issued 1,350 flow-through common shares at a price of $11.00 per share for gross proceeds of $14,850 and net proceeds of approximately $14,100 after issue costs of $490 (net of tax of $260). The commitment to spend $14,850 on exploration activity must be completed by December 31, 2008. (a) Per Share Amounts Three Months Ended Years Ended Weighted average number of December 31 December 31 common shares outstanding 2006 2005 2006 2005 ------------------------------------------------------------------------- Basic 45,859 45,612 45,842 45,240 Dilutive effect of options 1,778 2,660 2,163 2,516 ----------- ----------- ----------- ----------- Diluted 47,637 48,272 48,005 47,756 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- (b) Stock Options The Corporation has implemented a stock option plan for directors, officers, employees and consultants for up to 10 per cent of outstanding common shares. Under this plan, the exercise price of each option equals the closing market price of the Corporation's stock on the day before the grant. Each option has a term of five years and vests one-third on each of the first three anniversary dates. Weighted Average Weighted Remaining Average Contrac- Number of Exercise tual Life Stock Options - Common Shares Options Price in Years ------------------------------------------------------------------------- Outstanding at December 31, 2004 3,808 $ 3.64 3.87 Granted 1,224 14.89 4.60 Exercised (777) 3.48 2.66 ----------- ----------- ----------- Outstanding at December 31, 2005 4,255 $ 6.90 3.38 ----------- ----------- ----------- Granted 501 $ 8.30 4.94 Cancelled (693) 18.27 3.86 Exercised (161) 3.21 1.58 ----------- ----------- ----------- Outstanding at December 31, 2006 3,902 $ 5.22 2.48 ----------- ----------- ----------- ----------- ----------- ----------- Options exercisable at December 31, 2006 2,655 $ 4.05 1.90 ----------- ----------- ----------- (c) Contributed Surplus - Stock-based Compensation Years ended December 31 2006 2005 ------------- ------------- Balance, beginning $ 4,613 $ 2,902 Stock-based compensation 3,468 3,151 Transfer to share capital on exercise of options (328) (1,440) ------------- ------------- Balance, ending $ 7,753 $ 4,613 ------------- ------------- ------------- ------------- Years ended December 31 2006 2005 ------------- ------------- Weighted average fair value of stock options granted (per option) $ 2.82 $ 5.15 Expected life of stock options (years) 5 5 Expected volatility (weighted average) 30% 31.0% Risk free rate of return (weighted average) 4.0% 3.7% Expected dividend yield 0% 0% 9. Cash Taxes and Interest Paid During the year ended December 31, 2006, cash taxes paid by the Corporation were $91 (2005 - $61) and interest paid was $5,037 (2005 - $2,625). 10. Financial Instruments Foreign currency exchange risk: The Corporation is exposed to foreign currency fluctuations as crude oil and natural gas prices received are referenced to U.S. dollar denominated prices. Credit risk: A substantial portion of the Corporation's accounts receivable are with customers and joint venture partners in the oil and natural gas industry and are subject to normal industry credit risks. Purchasers of the Corporation's natural gas, crude oil and natural gas liquids are subject to internal credit review to minimize the risk of non-payment. Interest rate risk: The Corporation is exposed to interest rate risk to the extent that long term debt is at a floating rate of interest. Fair value of financial instruments: The fair values of accounts receivable, prepaid expenses and accounts payable and accrued liabilities approximate their carrying values due to their short-terms to maturities. The Corporation's long term debt bears interest at a floating market rate and accordingly the fair market value approximates the carrying value. Risk management activity: The Corporation had the following natural gas physical sales contracts outstanding at December 31, 2006: Fair market value December 31, 2006 AECO cost- April 1 to $6.75 to less collar October 31, 2007 5,000 GJ/d $8.21/GJ $674 AECO cost- April 1 to $6.75 to less collar October 31, 2007 5,000 GJ/d $8.17/GJ $559 Subsequent to December 31, 2006, the following natural gas physical sales contracts were entered into: AECO cost- April 1 to $6.75 to less collar October 31, 2007 5,000 GJ/d $8.10/GJ AECO cost- April 1 to $6.75 to less collar October 31, 2007 5,000 GJ/d $8.50/GJ The unrealized gains are not recorded in the financial statements and do not increase the Corporation's funds from operations as they are not derived from a financial instrument. 11. Commitments The following is a summary of the Corporation's contractual obligations and commitments as at December 31, 2006: Payments Due by Period Total 2007 2008 2009 2010 2011 and there- after ------------------------------------------------------------------------- Debt repayments(1) $ 121,600 $ - $121,600 $ - $ - $ - Transportation 871 596 269 6 - - Office premises 1,640 328 328 328 328 328 ------------------------------------------------------------------------- Total contractual obligations $ 124,111 $ 924 $122,197 $ 334 $ 328 $ 328 ------------------------------------------------------------------------- (1) Based on the existing terms of the revolving credit facility, the first payment may be required in June 2008. However it is expected that the revolving credit facility will be extended and no repayments will be required. (see note 5) FORWARD LOOKING STATEMENTS This disclosure contains certain forward looking statements that involve substantial known and unknown risks and uncertainties, some of which are beyond Rider Resources Ltd.'s control, including: the impact of general economic conditions in Canada and in the United States, industry conditions, changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced, increased competition, the lack of availability of qualified personnel or management, fluctuations in foreign exchange or interest rates, stock market volatility and market valuations of companies with respect to announced transactions and the final valuations thereof, and obtaining required approvals of regulatory authorities. Rider Resources Ltd.'s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward looking statements and, accordingly, no assurances can be given that any of the events anticipated by the forward looking statements will transpire or occur, or if any of them do so, what benefits, including the amount of proceeds, that Rider Resources Ltd. will derive therefrom. CORPORATE INFORMATION Transfer Agent & Stock Exchange Registrar Listing Auditors Banker Computershare Trust Toronto Stock KPMG LLP The Bank of Company of Canada Exchange Calgary, Alberta Nova Scotia Calgary, Alberta Trading Symbol: Calgary, Alberta Toronto, Ontario RRZ Toll Free 1-800-564-6253 ABBREVIATIONS Crude Oil and Natural Gas Liquids Natural Gas --------------------------------- ----------- bbls barrels mcf thousand cubic feet bbls/d barrels per day mmcf million cubic feet NGLs natural gas liquids mcf/d thousand cubic feet per day mmcf/d million cubic feet per day Other ----- boe barrels of oil equivalent converting 6 mcf of natural gas to one barrel of oil equivalent (this conversion factor is not based on current prices). ARTC Alberta Royalty Tax Credit EBITDA earnings before interest, taxes, depletion, depreciation and amortization Rider Resources Ltd. Suite 1701, 333 - 7th Ave. SW Calgary, Alberta T2P 2Z1 Phone: (403) 266-0844 Fax: (403) 266-0846 e-mail address: info.rider@riderres.com www.riderres.com

For further information:

For further information: Craig W. Stewart, President and Chief Executive
Officer, (403) 781-2445; John W. Ferguson, Vice President, Chief Financial
Officer and Corporate Secretary, (403) 781-2446

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