Rider Resources Ltd. - Second Quarter 2007 Results



    CALGARY, Aug. 8 /CNW/ -

    
    (TSX: RRZ)

    -------------------------------------------------------------------------
    Financial Highlights      Three Months                Six Months
                             Ended June 30               Ended June 30
    (thousands except                          %                           %
     per share amounts)  2007       2006  Change     2007       2006  Change
    -------------------------------------------------------------------------
    Oil and gas
     revenue          $  49,510  $  37,713    31  $  87,532  $  79,133    11

    Funds from
     operations(1)    $  24,163  $  21,453    13  $  44,491  $  47,058    (5)
      Per share -
       basic          $    0.46  $    0.47    (2) $    0.89  $    1.03   (14)
      Per share -
       diluted        $    0.45  $    0.45     -  $    0.87  $    0.97   (10)

    Net income        $   2,965  $  10,627   (72) $   7,402  $  20,677   (64)
      Per share -
       basic          $    0.06  $    0.23   (74) $    0.15  $    0.45   (67)
      Per share -
       diluted        $    0.06  $    0.22   (73) $    0.15  $    0.43   (65)

    Net capital
     expenditures     $ 205,993  $  25,540   707  $ 267,003  $  78,933   238

    Total assets                                  $ 593,775  $ 305,859    94

    Long term debt,
     plus working
     capital
     deficiency                                   $ 278,214  $ 104,832   165

    Shareholders'
     equity                                       $ 244,455  $ 152,656    60

    Weighted average
     shares
     outstanding
      - basic            52,588     45,853    15     49,931     45,826     9
      - diluted          53,496     48,205    11     50,858     48,299     5

    Shares
     outstanding
      - basic                                        56,032     45,858    22
      - diluted                                      61,421     49,941    23
    -------------------------------------------------------------------------

    Operational Highlights
    -------------------------------------------------------------------------
    Average daily
     production

      Natural gas (mcf)  52,294     45,442    15     46,359     42,132    10
      Natural gas
       liquids (bbls)     1,798      1,304    38      1,490      1,310    14
      Crude oil (bbls)      535        355    51        529        368    44
      Oil equivalent
       (boes 6:1)        11,048      9,233    20      9,745      8,699    12

    Average sales
     price
      Natural gas
       ($/mcf)        $    7.77  $    6.61    18  $    7.87  $    7.81     1
      Natural gas
       liquids ($/bbl)$   56.33  $   67.01   (16) $   56.02  $   63.69   (12)
      Crude oil
       ($/bbl)        $   67.03  $   72.12    (7) $   65.56  $   65.14     1

    Expenses
      Operating
       expenses
       ($/boe)        $    8.67  $    7.16    21  $    8.45  $    6.99    21
      General &
       administrative
       expenses
       ($/boe)        $    0.90  $    0.32   181  $    0.73  $    0.40    83

    Operating
     netback ($/boe)  $   29.24  $   27.35     7  $   29.35  $   31.46    (7)
    -------------------------------------------------------------------------
    Notes: (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 ended June 30, 2007.

    Property Acquisition

    On May 11, 2007, the Company closed its previously announced
$199.7 million acquisition of oil and natural gas assets in the South Wapiti
and Ferrier areas of west central Alberta (the "Acquisition"). The Acquisition
represented a unique opportunity to acquire high quality natural gas assets
adjacent to the Company's exploration areas of Karr and Waskahigan. It added
11.9 million barrels of proven plus probable reserves, 3,600 boe per day of
production, 44,000 net acres of undeveloped land and ownership in two
processing facilities. The acquired production has low operating costs and
declines. The Company has identified numerous exploration and development
opportunities on the acquired assets.
    The Acquisition was partially financed through the issuance of 7,500,000
subscription receipts, which were exchanged for an equal number of common
shares. Gross proceeds from this issue were $54.4 million. The balance of the
purchase price was initially financed with an expanded bank line and a bridge
debt facility. The Company issued US$100.0 million of second lien term debt to
replace the bridge facility and pay a portion of the bank lines. The second
lien loan has a 5 year term and is repayable at any time. The $US loan was
converted to Canadian dollars and the interest rate was fixed at 9.53 per
cent.

    Operations

    
    -   $67.3 million was invested in the Company's exploration and
        development program in the six months ended June 30, 2007, which
        included drilling 20 wells (16.9 net) with a success rate of
        79 per cent.
    -   Production grew by 12 per cent over the same period in 2006, to
        average 9,745 boe per day in the six months ended June 30, 2007
        (8,699 boe per day in same period of 2006).
    -   The Company's undeveloped land base increased to 151,000 net
        undeveloped acres.

    Financial

    -   Revenues increased by 11 per cent, to $87.5 million, in the first
        half of 2007 when compared to the same period in 2006
        ($79.1 million).
    -   Funds from operations for the six months ended June 30, 2007, totaled
        $44.5 million, down 5 per cent when compared to the same period in
        2006 ($47.1 million).
    -   Funds from operations per share were down 14 per cent to $0.89 ($0.87
        - diluted) for the six months ended June 30, 2007, as compared to
        $1.03 ($0.97 - diluted) in the same period in 2006.
    -   Net income for the six months ended June 30, 2007, was $7.4 million
        or $0.15 ($0.15 - diluted) per share, a 67 per cent decrease over the
        same period in 2006.
    -   The average natural gas price received by the Company for the six
        months ended June 30, 2007, increased by 1 per cent when compared to
        the same period in 2006.
    

    Outlook

    Natural gas prices have been weaker than anticipated through the summer
and are forecast to remain weak for the balance of 2007. High natural gas
storage levels and a strong Canadian dollar combined with increased liquefied
natural gas imports in North America have resulted in lower natural gas
prices. On the positive side, Canadian natural gas deliverability is declining
as a consequence of lower activity levels. Deliverability in the U.S. is
remaining relatively flat while underlying demand is increasing. Weather will
continue to be a key determinate in the direction global natural gas prices
take going forward. Increased cooling demand and supply disruptions as a
result of hurricanes could result in higher prices in the short term.
Commercial and residential heating demand will swing natural gas prices as we
enter the fall. Next year, Rider's natural gas price, as indicated through the
futures market, is forecast to rise to over $8.00 per mcf, approximately $0.50
per mcf higher than our 2007 natural gas price forecast.
    Crude oil prices have been very strong, rising to new record highs for
West Texas Intermediate in July 2007 and are currently trading at over 
US$70.00 per barrel. The full impact of strong oil prices for Canadian
producers has been eroded by the strong Canadian dollar.
    Rider has partially mitigated the impact of weak natural gas prices
through hedging thirty per cent of our natural gas at $7.50 per mcf. About
20 per cent of our production is comprised of crude oil and natural gas
liquids, which are receiving good prices.
    Industry costs are declining as a result of reduced activity and need to
continue to decline to restore economic returns from exploration activity.
When natural gas prices begin to recover, activity will increase but given the
severity of the current downturn, the ramp-up may occur over a longer period
of time, allowing for a more orderly pace of field activity and cost
maintenance.
    In the first half of 2007, Rider drilled 17 net wells, with only three
wells drilled in the second quarter due to very wet field conditions. We have
over 100 firm identified drilling locations, 60 of which are licensed and on
our drilling schedule. We had planned to be very active by drilling 30 wells
in the third quarter with a capital program of $60 million. Given the
uncertainty of natural gas prices, we have now elected to spend $35 million
and drill 20 wells in the third quarter. Fourth quarter capital expenditure
levels will be determined in the fall once we have a clearer picture on
industry costs and natural gas prices.
    The Acquisition, which was closed in the second quarter, provides
excellent production, plant infrastructure and undeveloped land. South Wapiti,
the primary area in the purchase, is adjacent to our existing areas and
consistent with the direction of our exploration program. Since completion of
the Acquisition, we have been busy integrating the assets into the Company and
identifying upside on the properties. We are confident that this acquisition
will provide significant future growth.
    We have drilled 8 wells thus far in the third quarter with a 100 per cent
success rate. An additional 12 wells are remaining to be drilled in the
quarter. As a result, production leaving the third quarter should be between
12,500 and 13,000 boe per day.
    We are forecasting 2007 cash flow to be approximately $100 million based
on average production of 11,000 to 11,500, with an average natural gas price
of $7.40.
    As a management group that has been through similar periods before, we
are prepared to be patient with near term capital expenditure levels while
continuing to add to our inventory of natural gas prospects. We will remain
focused on the significant opportunity provided by exposure to natural gas.
    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
    August 8, 2007



    MANAGEMENT'S DISCUSSION AND ANALYSIS

    August 8, 2007

    Management's discussion and analysis ("MD&A") of financial conditions and
results of operations should be read in conjunction with Rider's interim
consolidated financial statements for the three and six months ended June 30,
2007 and 2006 and the audited consolidated financial statements and MD&A for
the years ended December 31, 2006 and 2005. The following MD&A of financial
condition and results of operations was prepared at, and is dated August 8,
2007. Our audited consolidated financial statements, current annual
information form and other disclosure documents are filed on SEDAR at
www.sedar.com and other corporate documentation can be obtained from our
website at www.riderres.com.
    Basis of Presentation - The financial data presented below has been
prepared in accordance with Canadian Generally Accepted Accounting Principles
("GAAP"). The reporting and the measurement currency is the Canadian dollar
unless otherwise stated.
    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.

    Forward-Looking Statements - Certain information set forth in this
document, including management's assessment of Rider's future plans and
operations, contains forward-looking statements. By their nature,
forward-looking statements are subject to numerous risks and uncertainties,
some of which are beyond Rider's control, including the impact of general
economic conditions, industry conditions, volatility of commodity prices,
currency fluctuations, imprecision of reserve estimates, environmental risks,
competition from other industry participants, the lack of availability of
qualified personnel or management and services, stock market volatility and
ability to access sufficient capital from internal and external sources.
Readers are cautioned that the assumptions used in the preparation of such
information, although considered reasonable at the time of preparation, may
prove to be imprecise and, as results, performance or achievement could differ
materially from those expressed in, or implied by, these forward-looking
statements, or if any of them do so, what benefits that Rider will derive
therefrom. Rider disclaims any intention or obligation to update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise except as required by law.

    Non-GAAP Measurements - Within Management's discussion and analysis,
references are made to terms commonly used in the oil and gas industry.
Management uses funds from operations to analyze operating performance and
leverage. Funds from operations as presented does not have any standardized
meaning prescribed by Canadian GAAP and therefore it may not be comparable
with the calculation of similar measure for other entities. Funds from
operations as presented is not intended to represent operating cash flow or
operating profits for the period nor should it be viewed as an alternative to
cash flow from operating activities, net earnings or other measures of
financial performance calculated in accordance with Canadian GAAP. All
references to funds from operations throughout this report are based on cash
flow from operating activities before changes in non-cash working capital.
Funds from operations per share is calculated based on the weighted average
number of shares outstanding consistent with the calculation of net income per
share. Operating netback equals total revenues less royalties, transportation
and production expenses calculated on a boe basis. Average boe is calculated
by dividing the total number by the number of days in the period.

    
    -------------------------------------------------------------------------
                                        Three months ended  Six months ended
                                              June 30            June 30
    $ thousands                            2007     2006      2007     2006
    -------------------------------------------------------------------------
    Cash flow from operating
     activities (per GAAP)                17,758   10,932    31,877   40,375
    Change in non-cash working capital     6,405   10,521    12,614    6,683
    -------------------------------------------------------------------------
    Funds from operations                 24,163   21,453    44,491   47,058
    -------------------------------------------------------------------------
    

    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".

    
    Summary of Quarterly Results

                                                 Three months ended
    ($ thousands, except
     per share amounts)                June 30,  Mar. 31,  Dec. 31, Sept. 30,
                                          2007      2007      2006      2006
    -------------------------------------------------------------------------
    Oil and gas revenue                 49,510    38,022    37,840    37,180
    Net income                           2,965     4,437     4,272     5,362
      - per share - basic                 0.06      0.09      0.09      0.12
      - per share - diluted               0.06      0.09      0.09      0.11
    Funds from operations               24,163    20,328    21,504    21,699
      - per share - basic                 0.46      0.43      0.47      0.47
      - per share - diluted               0.45      0.42      0.45      0.45


                                                 Three months ended
    ($ thousands, except
     per share amounts)                June 30,  Mar. 31,  Dec. 31, Sept. 30,
                                          2006      2006      2005      2005
    -------------------------------------------------------------------------
    Oil and gas revenue                 37,713    41,420    55,789    45,299
    Net income                          10,627    10,050    15,589    13,795
      - per share - basic                 0.23      0.22      0.34      0.30
      - per share - diluted               0.22      0.21      0.32      0.29
    Funds from operations               21,453    25,605    35,782    30,107
      - per share - basic                 0.47      0.56      0.78      0.66
      - per share - diluted               0.45      0.53      0.74      0.63
    

    Trends

    The quarterly results will continue to be impacted by the results of the
Company's exploration and development program and volatile commodity prices.

    Acquisition

    On May 11, 2007, Rider acquired assets in the South Wapiti and Ferrier
areas of Alberta for total consideration of $199.7 (the "Acquisition"). The
Acquisition was financed through the issuance of 7,500,000 common shares for
total gross consideration of $54.4 million, the issuance of US$100 million of
second lien debt and expanded revolving bank lines.
    The Acquisition added approximately 11.9 million barrels of proved and
probable reserves, 3,600 boe per day of production and 44,000 net undeveloped
acres of land.

    
    Production

    -------------------------------------------------------------------------
                                       Three months ended
                             June 30, March 31,  Dec. 31, Sept. 30,  June 30,
                                2007      2007      2006      2006      2006
    -------------------------------------------------------------------------
    Crude oil (bbls/d)           535       523       635       495       355
    -------------------------------------------------------------------------
    Natural gas liquids
     (bbls/d)                  1,798     1,179     1,262     1,276     1,304
    -------------------------------------------------------------------------
    Total liquids (bbls/d)     2,333     1,702     1,897     1,771     1,659
    -------------------------------------------------------------------------
    Natural gas (mcf/d)       52,294    40,357    40,300    45,078    45,442
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Total (boe/d)             11,048     8,428     8,613     9,284     9,233
    -------------------------------------------------------------------------
    

    Average daily production of crude oil and natural gas liquids for the six
months ended June 30, 2007, increased to 2,019 bbls/d from 1,678 bbls/d during
the same period of 2006. For the quarter ended June 30, 2007, crude oil and
natural gas liquids production averaged 2,333 bbls/d as compared to
1,659 bbls/d in the second quarter of 2006. Average daily natural gas sales
increased in the first half of the year to 46.4 mmcf/d from 42.1 mmcf/d
recorded in the same period of the previous year. Natural gas sales averaged
52.3 mmcf/d during the second quarter of 2007 as compared to 45.4 mmcf/d for
the same quarter in 2006. Production for the first half of 2007 averaged
9,745 boe/d as compared to 8,699 boe/d in the same period of 2006. The
Company's internally generated exploration and development program and the
Acquisition have resulted in the production growth.

    
    Financial Performance

    Commodity Prices
    -------------------------------------------------------------------------
                                       Three months ended   Six months ended
                                              June 30            June 30
    Realized Prices                       2007     2006      2007      2006
    -------------------------------------------------------------------------
    Crude Oil ($/bbl)                    67.03     72.12     65.56     65.14
    Natural Gas Liquids ($/bbl)          56.33     67.01     56.02     63.69
    Natural Gas ($/mcf)                   7.77      6.61      7.87      7.81
    -------------------------------------------------------------------------
    

    The price for West Texas Intermediate crude oil averaged US$65.02 per
barrel during the second quarter of 2007 and as a result the average price
received by the Corporation for crude oil in the second quarter was $67.03 per
bbl, a 7 per cent decrease from the $72.12 per barrel received in the same
period in 2006. The Corporation's average crude oil price during the first
half of 2006 was $65.56 per bbl (2006- $65.14). The average natural gas
liquids price was $56.02 per bbl during the first half of 2007 and $56.33 per
bbl during the second quarter. Approximately half of Rider's natural gas
liquids is condensate which receives premium prices.
    The realized natural gas price averaged $7.87 per mcf during the six
months ended June 30, 2007, versus $7.81 per mcf in the same period of 2006.
For the second quarter, natural gas prices averaged $7.77 per mcf as compared
to $6.61 in 2007.

    Revenue

    Production growth as a result of the Company's exploration and
development program and the Acquisition was offset by slightly lower liquid
prices, and as a result revenues for the first half of 2007 increased to 
$87.5 from $79.1 million in the same period in 2006 and $49.5 million for the
second quarter as compared to $37.7 million for the second quarter of 2006.

    Royalties

    Royalties for the first half of 2007 totaled $20.0 million (23 per cent
of revenues), compared with $17.6 million (22 per cent of revenues) in the
same period in 2006. The Alberta royalty tax credit was discontinued at the
end of 2006 which will result in royalties forming a higher percentage of
revenue in 2007.

    Expenses

    Production expenses for the first half of 2007 were $14.9 million as
compared to $11.0 million in the same period of 2006. Production expenses for
the three months ended June 30, 2007, were $8.7 million ($6.0 million - 2006).
On a per boe basis, production expenses for the six months ended June 30,
2007, were $8.45, up 21 per cent from the same period in 2006 ($6.99 per boe).
Production expenses are up on an aggregate basis as a result of the increasing
production volumes. On a boe basis operating costs were up because of the
difficult operating conditions due to poor winter and spring weather and some
unusual one time costs. The Company expects these costs to come down
substantially for the balance of the year.
    Interest expense for the six months ended June 30, 2007, was
$4.3 million, compared with $1.7 million in the same period of 2006. The
increase in interest expense as compared to the same quarter in 2006 is due to
the increased long term debt as a result of the capital program and the
Acquisition.
    During the second quarter of 2007, the Company incurred $1.6 million of
financing fees expense related to the US$100 million second lien debt
financing.
    An unrealized foreign exchange gain of $0.5 million was recorded in the
second quarter of 2007 related to the foreign currency translation on the
second lien debt.
    For the six months ended June 30, 2007, general and administrative
expenses were $0.73 per boe, up 83 per cent from the same period of 2006.
General and administrative costs increased as a result of the growth the
Company and lower recoveries of general and administrative expenses. During
the six months ended June 30, 2007, the Company capitalized overhead charges
of $0.8 million (2006 - $0.7 million).
    Depletion and depreciation expense amounted to $32.6 million, or
$18.50 per boe, for the six months ending June 30, 2007, compared with $20.0
million or $12.74 per boe for the same period in 2006. The Company's depletion
and depreciation rate has increased mainly as a result of the higher costs of
services in the industry and the cost of adding reserves through the
Acquisition.
    A stock-based compensation expense of $0.6 million, or $0.56 per boe, was
recorded for the three months ended June 30, 2007, as compared to
$0.9 million, or $1.36 per boe, for the same period of 2006. For the six
months ended June 30, 2006, stock based compensation was $1.0 million or $0.57
per boe.

    
    Net Income and Funds from Operations per boe

                              Three Months                Six Months
                             Ended June 30              Ended June 30
    -------------------------------------------------------------------------
                                               %                           %
                         2007       2006  Change     2007       2006  Change
    -------------------------------------------------------------------------
    Revenue           $   49.24  $   44.88    10  $   49.62  $   50.26    (1)
      Royalties, net
       of ARTC           (10.81)     (9.69)   12     (11.32)    (11.20)    1
      Production
       expenses           (8.67)     (7.16)   21      (8.45)     (6.99)   21
      Transportation      (0.52)     (0.68)  (24)     (0.50)     (0.61)  (18)
    -------------------------------------------------------------------------
    Operating Netback     29.24      27.35     7      29.35      31.46    (7)
      General and
       administrative
       expenses           (0.90)     (0.32)  181      (0.73)     (0.40)   83
      Interest expense    (2.67)     (1.40)   91      (2.45)     (1.10)  123
      Financing fees      (1.60)         -     -      (0.91)         -     -
    -------------------------------------------------------------------------
    Funds from
     operations           24.07      25.63    (6)     25.26      29.95   (16)
      Depletion,
       depreciation
       and accretion     (19.36)    (13.95)   39     (18.50)    (12.74)   45
      Stock-based
       compensation
       expense            (0.56)     (1.12)  (50)     (0.57)     (1.23)  (53)
      Foreign exchange
       gain                0.46          -     -       0.26          -     -
      Future income
       taxes              (1.66)      2.09    21      (2.26)     (2.85)  (21)
    -------------------------------------------------------------------------
    Net Income        $    2.95  $   12.65   (77) $    4.20  $   13.13   (68)
    -------------------------------------------------------------------------
    

    Taxes

    In the first half of 2007, the Company recorded a future income tax
charge of $4.0 million, for an effective rate of 35%, compared to
$4.5 million, for an effective rate of 18% in the first half of 2006. The
effective rate in 2007 is more reflective of the statutory income tax rates as
an income tax recovery was recorded in 2006 to reflect a reduction in future
income tax rates which reduced the effective rate.

    Net Earnings

    Net income for the quarter ended June 30, 2007, was $3.0 million, down
from $10.6 million for the same quarter in 2006. Diluted earnings per share
for the quarter decreased to $0.06 per share from $0.22 per share for the same
period of 2006. Net income for the first half of the year was $7.4 million as
compared to $20.7 million in the first half of 2006. Funds from operations for
the first half decreased to $44.5 million ($0.87 per diluted share), compared
with $47.1 million ($0.97 per diluted share) during the same period in 2006.
Net income declined in the quarter as compared to the same quarter in 2006 as
higher production volumes did not offset higher depletion, depreciation and
accretion, operating and interest expenses.

    Liquidity and Capital Resources

    On May 11, 2007, the Company completed its acquisition of assets in South
Wapiti and the Ferrier areas of west central Alberta. The purchase price was
$199.7 million and in order to finance the Acquisition, the Company issued
7,500,000 subscription receipts at a price of $7.25 per subscription receipt
which were exchanged for an equal number of common shares for gross proceeds
of $54.4 million, expanded its bank lines of credit to $230.0 million and
established a bridge debt facility of $110.0 million.
    On June 29, 2007, a syndicate of lenders provided the Company with a 
US$100.0 million senior second lien term loan, repayable in quarterly
principal installments of US $250,000 with the balance due on maturity on 
June 29, 2012. Amounts borrowed under the senior second lien term loan are
subject to variable rate interest based on the three month LIBOR rate plus 425
basis points. This term loan is secured by second priority interests in all
acquired properties and assets of the Company and affiliated entities. The
loan is fully repayable at any time subject to a 1 per cent prepayment penalty
on prepayments made prior to June 30, 2008. As of June 30, 2007,
US$100.0 million ($106.5 million CDN) is outstanding under this facility, of
which the current portion is US $1.0 million ($1.1 million CDN) with the
balance of  US$99.0 million ($105.5 million CDN) reflected as long term debt.
At June 30, 2007, the Company's effective interest rate was 9.53 per cent.
    In conjunction with the senior second lien term loan, the Corporation
entered into a cross currency swap arrangement for the same term as the senior
second lien term. The cross currency swap arrangement establishes a fixed
foreign exchange rate on principal repayments of 1.07 CDN to 1 US dollar and a
fixed interest rate of 9.53%. As of June 30, 2007, the fair value of the cross
currency swap was nil.
    On February 15, 2007, the Company issued 1,350,000 flow through common
shares at a price of $11.00 per share for gross proceeds of $14.9 million.
    As at June 30, 2007, total long term debt plus working capital deficiency
was $278.2 million.
    The Company had set its exploration and development capital budget for
2007 at $135.0 million. This capital program will be financed through
internally generated funds from operations and the previously mentioned
financings.

    Commitments

    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 June 30, 2007:

    
                                      Payments Due by Period
                          Total     2007     2008     2009     2010  2011 and
                                                                   thereafter
    -------------------------------------------------------------------------
    Credit
     facilities(1)     $175,435 $      - $      - $175,435 $      - $      -
    Senior second
     lien debt          106,540      535    1,070    1,070    1,070  102,795
    Transportation          573      298      269        6        -        -
    Office premises       1,476      164      328      328      328      328
    -------------------------------------------------------------------------
    Total contractual
     obligations       $284,024 $    997 $  1,667 $176,839 $  1,398 $103,123
    -------------------------------------------------------------------------
    (1) Based on the existing terms of the facilities, the first payment may
        be required in June 2009.
    

    Capital Expenditures

    During the six months ended June 30, 2007, the Company spent a total of
$267.0 million on capital expenditures, a breakdown of which is outlined
below.

    
                                                    Six months ended June 30
    (thousands)                                              2007       2006
    -------------------------------------------------------------------------
    Net acquisitions (dispositions)                     $ 199,674  $    (247)
    Land and seismic                                        9,692      5,821
    Drilling                                               40,532     48,766
    Production and well equipment                           4,732      7,351
    Plant and facilities                                   11,321     16,365
    Other                                                   1,052        877
    -------------------------------------------------------------------------
                                                        $ 267,003  $  78,933
    -------------------------------------------------------------------------
    

    Off Balance Sheet Arrangements

    As at the date of this 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 natural gas physical sale costless collars in effect from
April 1, 2007 to October 31, 2007 as follows: 5,000 gigajoules per day in a
price band of $6.75 to $8.21 per gigajoule; 5,000 gigajoules per day in a
price band of $6.75 to $8.17 per gigajoule; 5,000 gigajoules per day in a
price band of $6.75 to $8.10 per gigajoule; and 5,000 gigajoules per day in a
price band of $6.75 to $8.50 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. The Company has also entered into the cross currency interest rate
swap discussed earlier in this MD&A under "Liquidity and Capital Resources".

    Common Shares Outstanding

    As at the date of this MD&A and as at June 30, 2007, the Company had
56,031,859 common shares and 5,389,268 options to purchase common shares
outstanding.

    Application of Critical Accounting Estimates

    The significant accounting policies used by Rider are disclosed in note 3
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 may 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 from 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 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 second quarter of 2007, that have materially affected, or
are reasonably likely to materially affect, its internal control over
financial reporting.

    Update on Regulatory and Financial Reporting Matters:

    Effective January 1, 2007, Rider adopted the Canadian Institute of
Chartered Accounts ("CICA") section 3855, "Financial Instruments - Recognition
and Measurement," section 3865, "Hedges," section 1530, "Comprehensive Income,
and section 3861, "Financial Instruments - Disclosure and Presentation." These
standards have been adopted with no restatement of prior periods. See note 2
to the interim consolidated financial statements.

    Business Risks

    Environmental Regulation and Risk

    All phases of the oil and natural gas business present environmental
risks and hazards and are subject to environmental regulation pursuant to a
variety of federal, provincial and local laws and regulations. Compliance with
such legislation can require significant expenditures and a breach may result
in the imposition of fines and penalties, some of which may be material.
Environmental legislation is evolving in a manner expected to result in
stricter standards and enforcement, larger fines and liability and potentially
increased capital expenditures and operating costs. In 2002, the Government of
Canada ratified the Kyoto Protocol (the "Protocol"), which calls for Canada to
reduce its greenhouse gas emissions to specified levels. There has been much
public debate with respect to Canada's ability to meet these targets and the
Government's strategy or alternative strategies with respect to climate change
and the control of greenhouse gases. Implementation of strategies for reducing
greenhouse gases, whether to meet the limits required by the Protocol or as
otherwise determined, could have a material impact on the nature of oil and
natural gas operations, including those of the Company.
    The Federal Government released on April 26, 2007, its Action Plan to
Reduce Greenhouse Gases and Air Pollution (the "Action Plan"), also known as
ecoACTION, and which includes the Regulatory Framework for Air Emissions. This
Action Plan covers not only large industry, but also regulates the fuel
efficiency of vehicles and the strengthening of energy standards for a number
of energy-using products. Regarding large industry and industry related
projects, the Government's Action Plan intends to achieve the following: (i)
an absolute reduction of 150 megatonnes in greenhouse gas emissions by 2020 by
imposing mandatory targets; and (ii) air pollution from industry is to be cut
in half by 2015 by setting certain targets. New facilities using cleaner fuels
and technologies will have a grace period of three years. In order to
facilitate compliance by companies with the Action Plan's requirements, while
at the same time allowing them to be cost-effective, innovative and adopt
cleaner technologies, certain options are provided. These are: (i) in-house
reductions; (ii) contributions to technology funds; (iii) trading of emissions
with below-target emission companies; (iv) offsets; and (v) access to Kyoto's
Clean Development Mechanism.
    On March 8, 2007, the Alberta Government introduced Bill 3, the Climate
Change and Emissions Management Amendment Act, which intends to reduce
greenhouse gas emission intensity from large industries. Bill 3 states that
facilities emitting more than 100,000 tonnes of greenhouse gases a year must
reduce their emissions intensity by 12% starting July 1, 2007; if such
reduction is not initially possible a company owning a large emitting facility
will be required to pay $15 per tonne for every tonne above the 12% target.
These payments will be deposited into an Alberta-based technology fund that
will be used to develop infrastructure to reduce emissions or to support
research into innovative climate change solutions. As an alternate option,
large emitters can invest in projects outside of their operations that reduce
or offset emissions on their behalf, provided that these projects are based in
Alberta. Prior to investing, the offset reductions offered by a prospective
operation must be verified by a third party to ensure the emission reductions
are real.
    Given the evolving nature of the debate related to climate change and the
control of greenhouse gases and resulting requirements, it is not possible to
predict the impact of those requirements on Rider, and its operations and
financial condition.

    Review of Alberta Royalty and Tax Regime

    On February 16, 2007, the Alberta Government announced that a review of
the province's royalty and tax regime (including income tax and freehold
mineral rights tax) pertaining to oil and gas resources, including oil sands,
conventional oil and gas and coalbed methane, will be conducted by a panel of
experts, with the assistance of individual Albertans and key stakeholders. The
review panel is to produce a final report that will be presented to the
Minister of Finance by August 31, 2007.


    
                            RIDER RE

SOURCES LTD. CONSOLIDATED BALANCE SHEETS (thousands) (UNAUDITED) ------------------------------------------------------------------------- June 30, December 31, 2007 2006 ------------ ------------ Assets Current assets Accounts receivable $ 29,623 $ 23,282 Prepaid expenses 595 1,209 ------------ ------------ 30,218 24,491 Investments (note 4) - 4,000 Property, plant and equipment (note 5) 563,557 327,266 ------------ ------------ $ 593,775 $ 355,757 ------------ ------------ ------------ ------------ Liabilities Current liabilities Accounts payable and accrued liabilities $ 26,457 $ 33,344 Current portion of long term debt (note 6) 1,065 - ------------ ------------ 27,522 33,344 Long term debt (note 6) 280,910 121,600 Asset retirement obligations (note 7) 7,099 6,072 Future income taxes 33,789 30,914 ------------ ------------ 349,320 191,930 ------------ ------------ Shareholders' equity Share capital (note 8) 166,908 93,029 Contributed surplus (note 8) 7,100 7,753 Retained earnings 70,447 63,045 ------------ ------------ 244,455 163,827 ------------ ------------ $ 593,775 $ 355,757 ------------ ------------ ------------ ------------ Commitments (notes 8 and 12) See accompanying notes to consolidated financial statements. RIDER RE

SOURCES LTD. CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS (thousands, except per share amounts) (UNAUDITED) ------------------------------------------------------------------------- Three Months Ended Six Months Ended June 30 June 30 2007 2006 2007 2006 ---------- ---------- ---------- ---------- Revenue Oil and gas sales $ 49,510 $ 37,713 $ 87,532 $ 79,133 Royalties, net of ARTC (10,872) (8,144) (19,962) (17,632) ---------- ---------- ---------- ---------- 38,638 29,569 67,570 61,501 ---------- ---------- ---------- ---------- Expenses Production 8,712 6,016 14,906 11,008 Transportation 533 572 892 957 Interest 2,685 1,176 4,321 1,732 Financing fees 1,607 - 1,607 - Foreign exchange gain (460) - (460) - General and administrative 901 271 1,286 645 Stock-based compensation 565 944 1,009 1,941 Depletion, depreciation and accretion 19,460 11,718 32,627 20,056 ---------- ---------- ---------- ---------- 34,003 20,697 56,188 36,339 ---------- ---------- ---------- ---------- Income before taxes 4,635 8,872 11,382 25,162 Future income taxes (reduction) (note 9) 1,670 (1,755) 3,980 4,485 ---------- ---------- ---------- ---------- Net income for the period 2,965 10,627 7,402 20,677 Retained earnings, beginning of period 67,482 42,784 63,045 32,734 ---------- ---------- ---------- ---------- Retained earnings, end of period $ 70,447 $ 53,411 $ 70,447 $ 53,411 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- Net income per share - basic $ 0.06 $ 0.23 $ 0.15 $ 0.45 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- Net income per share - diluted $ 0.06 $ 0.22 $ 0.15 $ 0.43 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- See accompanying notes to consolidated financial statements. RIDER RE

SOURCES LTD. CONSOLIDATED STATEMENTS OF CASH FLOWS (thousands) (UNAUDITED) ------------------------------------------------------------------------- Three Months Ended Six Months Ended June 30 June 30 2007 2006 2007 2006 ---------- ---------- ---------- ---------- Cash provided by (used in): Operating Net income $ 2,965 $ 10,627 $ 7,402 $ 20,677 Stock-based compensation 565 944 1,009 1,941 Depletion, depreciation and accretion 19,460 11,718 32,627 20,056 Unrealized foreign exchange gain (460) - (460) - Future income taxes (reduction) 1,670 (1,755) 3,980 4,485 Asset retirement expenditures (37) (81) (67) (101) ---------- ---------- ---------- ---------- 24,163 21,453 44,491 47,058 Net change in non-cash working capital (6,405) (10,521) (12,614) (6,683) ---------- ---------- ---------- ---------- 17,758 10,932 31,877 40,375 ---------- ---------- ---------- ---------- Financing Increase in long term debt 135,530 18,495 160,835 42,052 Issue of share capital, net of issue costs 52,705 113 70,291 506 ---------- ---------- ---------- ---------- 188,235 18,608 231,126 42,558 ---------- ---------- ---------- ---------- Investing Property acquisitions, net of dispositions (184,674) 100 (199,674) 247 Capital expenditures (21,319) (25,640) (67,329) (79,180) Disposition (purchase) of investments - (4,000) 4,000 (4,000) ---------- ---------- ---------- ---------- (205,993) (29,540) (263,003) (82,933) ---------- ---------- ---------- ---------- Change in cash - - - - Cash, beginning of period - - - - ---------- ---------- ---------- ---------- Cash, end of period $ - $ - $ - $ - ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- See accompanying notes to consolidated financial statements. Rider Resources Ltd. Notes to the Interim Consolidated Financial Statements For the Three and Six Months Ended June 30, 2007 (thousands, except per share amounts) (UNAUDITED) 1. Basis of Presentation The consolidated financial statements for the three and six months ended June 30, 2007, 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. The interim consolidated financial statements of the Corporation have been prepared following the same accounting policies, except as described in note 2, and methods of computation as the consolidated financial statements for the fiscal year ended December 31, 2006. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto for the year ended December 31, 2006. 2. Changes in accounting policies: On January 1, 2007, the Corporation adopted the new Canadian accounting standards for financial instruments - recognition and measurement, financial instruments - presentations and disclosures, hedging and comprehensive income. Prior periods have not been restated. (a) Financial instruments - recognition and measurement: This new standard requires all financial instruments within its scope, including all derivatives, to be recognized on the balance sheet initially at fair value. Subsequent measurement of all financial assets and liabilities except those held-for-trading and available for sale are measured at amortized cost determined using the effective interest rate method. Held-for-trading financial assets are measured at fair value with changes in fair value recognized in earnings. Available-for-sale financial assets are measured at fair value with changes in fair value recognized in comprehensive income and reclassified to earnings when derecognized or impaired. There were no changes to the measurement of existing financial assets and liabilities at the date of adoption. The Corporation has selected a policy of immediately expensing transaction costs incurred related to the acquisition of financial assets and liabilities. (b) Derivatives: The Corporation uses various types of derivative financial instruments to manage risks associated with crude oil and natural gas prices, foreign currency and interest rate fluctuations. These instruments are not used for trading or speculative purposes. Proceeds and costs realized from holding the related crude oil and natural gas contracts are recognized in petroleum and natural gas revenues at the time that each transaction under a contract is settled. For the unrealized portion of such contracts, the Corporation utilizes the fair value method of accounting. The fair value is based on an estimate of the amounts that would have been paid to or received from counterparts to settle these instruments given future market prices and other relevant factors. The method requires the fair value of the derivative financial instruments to be recorded at each balance sheet date with unrealized gains or losses on these contracts recorded through net earnings. The Corporation has elected to account for its commodity sales and other non-financial contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts on an accrual basis rather than as non-financial derivatives. Prior to adoption of the new standards, physical receipt and delivery contracts did not fall within the scope of the definition of a financial instrument and were also accounted for as executory contracts. (c) Embedded derivatives: On adoption, the Corporation elected to recognize, as separate assets and liabilities, only for those embedded derivatives in hybrid instruments issued, acquired or substantively modified after January 1, 2003. The Corporation has not identified any material embedded derivatives which require separate recognition and measurement. (d) Other comprehensive income: The new standards establish a new statement of comprehensive income, which is comprised of net earnings and other comprehensive income. As the Corporation currently has no comprehensive income items requiring disclosure, this statement of comprehensive income is not required. There are also two new Canadian accounting standards that have been issued which will require additional disclosure in the Corporation's financial statements commencing January 1, 2008, about the Corporation's financial instruments as well as its capital and how it is managed. 3. 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, equipment and software is provided for on a declining balance basis at an annual rate of 20%, 33% and 50%, respectively. 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. Foreign Currency Translation Monetary assets and liabilities denominated in a currency other than the Canadian dollar are translated at the rate of exchange in effect at the balance sheet date. Revenues and expenses denominated in a foreign currency are translated at the average exchange rate for the period. Translation gains and losses are included in income the period in which they arise. 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. 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. Comparative Figures Certain comparative figures have been reclassified to conform with current period presentation. 4. Investments On May 18, 2006, the Corporation acquired $4,000 principal amount of 5.0 per cent secured convertible debentures from a private company. The debentures paid interest quarterly on March 31, June 30, September 30 and December 31 and had a maturity date of July 18, 2007. The debentures were convertible, at the option of the Corporation, to 8,000 common shares at a conversion price of $0.50 per share. The investment was accounted for at cost. On March 26, 2007, the convertible debentures were redeemed at par for $4,000 plus accrued interest. 5. Property, Plant and Equipment June 30, December 31, 2007 2006 ------------------------------------------------------------------------- Cost $ 686,060 $ 417,390 Accumulated depletion and depreciation (122,503) (90,124) ------------------------------------------------------------------------- $ 563,557 $ 327,266 ------------------------------------------------------------------------- ------------------------------------------------------------------------- During the six months ended June 30, 2007, the Corporation capitalized overhead charges of $800 (2006 - $669) and stock based compensation of $821 (2006 - Nil). Costs related to unproved properties of $63,933 (2006 - $35,395) were excluded from the depletion calculation. Future development capital of $5,874 (2006 - $2,931) was included in the depletion calculation. On May 11, 2007, the Corporation acquired certain oil and natural gas properties for cash of $199,674 with associated asset retirement obligations of $571. 6. Long Term Debt Revolving and Operating Facilities At December 31, 2006, a Canadian chartered bank had provided the Corporation with a revolving line of credit of $150,000. On January 31, 2007, a syndicate of banks provided the Corporation with a revolving line of credit of $130,000 and a Canadian chartered bank provided the Corporation with an operating line of credit of $20,000. These facilities are fully secured by first priority security interests in all acquired properties and assets of the Corporation and affiliated entities. Interest on advances under these facilities is dependent on the prime interest rate or stamping fees charged by the banks and the debt to EBITDA ratio of the Corporation at the end of each quarter. On March 22, 2007, to facilitate the purchase of the oil and natural gas properties described in note 5, a syndicate of banks agreed to increase the revolving line of credit to $210,000 with the operating line of credit remaining at $20,000. The interest terms, security and covenants of these facilities remained the same. These facilities must be renewed by June 13, 2008 and, if not renewed, outstanding advances become term loans repayable on June 30, 2009. As a result, amounts outstanding under these facilities are classified as long-term. As of June 30, 2007, $175,435 (December 31, 2006 - $121,600) had been drawn under this facility at an effective interest rate of 6.30 per cent (December 31, 2006 - 5.35 per cent). Bridge Facility To facilitate the purchase of the oil and natural gas properties described in note 5, a Canadian chartered bank agreed to provide the Corporation with a $110,000 bridge credit facility which was scheduled to mature on October 2007. On May 11, 2007, the Corporation drew the full amount of the $110,000 bridge credit facility. Amounts borrowed under the bridge facility were subject to interest based on the prime interest rate plus 150 basis points. The Corporation closed the equity issue described in note 8 on May 11, 2007, and used net proceeds of $51,746 to partially repay amounts outstanding under the bridge credit facility. On June 29, 2007, the Corporation used proceeds from the second lien loan facility, described further below, to fully repay any amounts outstanding under this facility. Senior Second Lien Term Loan On June 29, 2007, a syndicate of lenders provided the Corporation with a $100,000 US senior second lien term loan, repayable in quarterly principal installments of $250 US with the balance due on maturity on June 29, 2012. Amounts borrowed under the senior second lien term loan are subject to variable rate interest based on the three month LIBOR rate plus 425 basis points. This term loan is secured by second priority interests in all acquired properties and assets of the Corporation and affiliated entities. The loan is fully repayable at any time subject to a 1 per cent penalty on prepayments made prior to June 30, 2008. As of June 30, 2007, $100,000 US ($106,540 CDN) is outstanding under this term loan of which the current portion is $1,000 US ($1,065 CDN), with the balance of $99,000 ($105,475 CDN) reflected as long term debt. At June 30, 2007, the Corporation's effective interest rate was fixed at 9.53 per cent. Future scheduled repayments are as follows: 2007 - $500 US ($534 CDN); 2008 - $1,000 US ($1,065 CDN); 2009 - $1,000 US ($1,065 CDN); 2010 - $1,000 US ($1,065 CDN); 2011 - $1,000 US ($1,065 CDN); and 2012 - $95,500 US ($101,746 CDN). In conjunction with the senior second lien term loan, the Corporation entered into a cross currency interest rate swap arrangement for the same term as the senior second lien term loan. The swap arrangement establishes a fixed foreign exchange rate on principal repayments of $1.07 CDN to $1.00 US and a fixed interest rate of 9.53 per cent. As of June 30, 2007 the fair value of the swap was nil. 7. Asset Retirement Obligations At June 30, 2007, the estimated total undiscounted amount required to settle asset retirement obligations was $17,175 (December 31, 2006 - $14,900). 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: June 30, December 31, 2007 2006 ------------------------------------------------------------------------- Asset retirement obligations, beginning $ 6,072 $ 4,565 Liabilities incurred 275 1,367 Liabilities incurred on acquisition (note 5) 571 - Liabilities settled (67) (253) Accretion 248 393 ------------------------------------------------------------------------- Asset retirement obligations, ending $ 7,099 $ 6,072 ------------------------------------------------------------------------- The asset retirement accretion expense of $248 has been included in depletion, depreciation and accretion expense. 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, 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 Exercise of stock options 1,321 4,450 Issue of flow through shares 1,350 14,355 Issue of common shares for equity financing 7,500 52,591 Stock-based compensation on exercise of stock options - 2,483 ------------ ------------ Balance at June 30, 2007 56,032 $ 166,908 ------------ ------------ ------------ ------------ On February 15, 2007, 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 $14,355 after issue costs of $495 (net of tax of $260). The commitment to spend $14,850 on exploration activity must be completed by December 31, 2008. At June 30, 2007, approximately $1,603 has been spent on exploration for flow through share purposes. The Corporation, pursuant to a prospectus, issued 7,500 subscription receipts at $7.25 per share for gross proceeds of $54,375 and net proceeds of $52,591 after issue costs of $1,784 (net of tax of $845). The proceeds were held in trust until May 11, 2007, when, upon closing of the oil and natural gas property acquisition described in note 5, the subscription receipts were exchanged for an equal number of common shares and the proceeds were released, and applied against the outstanding amount drawn on the bridge credit facility described in note 6. There were no first or second preferred shares issued as at June 30, 2007, and December 31, 2006. (a) Per Share Amounts Three months ended Six months ended Weighted average number of June 30 June 30 common shares outstanding 2007 2006 2007 2006 --------------------------------------------------------------------- Basic 52,588 45,853 49,931 45,826 Dilutive effect of options 908 2,352 927 2,473 ---------- ---------- ---------- ---------- Diluted 53,496 48,205 50,858 48,299 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- (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 weighted average closing market price of the Corporation's stock on the 5 days before the grant. Each option has a term of five years and vests one-third on each of the first three anniversary dates. Stock Options - Common Shares Number of Weighted Weighted Options Average Average Exercise Remaining Price Contractual Life in Years --------------------------------------------------------------------- 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 ---------- ---------- ---------- Granted 3,510 8.28 4.77 Cancelled (702) 10.10 2.24 Exercised (1,321) 3.37 1.25 ---------- ---------- ---------- Outstanding at June 30, 2007 5,389 $ 7.03 3.81 ---------- ---------- ---------- ---------- ---------- ---------- Options exercisable at June 30, 2007 1,358 $ 3.85 1.45 ---------- ---------- ---------- ---------- ---------- ---------- Six months ended June 30 2007 2006 ------------ ------------ Weighted average fair value of stock options granted (per option) $ 2.81 - Expected life of stock options (years) 5 - Expected volatility (weighted average) 30.0% - Risk free rate of return (weighted average) 4.0% - Expected dividend yield 0.0% - (c) Contributed Surplus - Stock-based Compensation Six months ended Year ended June 30, December 31, 2007 2006 ------------ ------------ Balance, beginning of period $ 7,753 $ 4,613 Stock-based compensation 1,830 3,468 Transfer to share capital on exercise of options (2,483) (328) ------------ ------------ Balance, end of period $ 7,100 $ 7,753 ------------ ------------ ------------ ------------ 9. Future Income Taxes The provision for future income taxes was determined as follows: Six months ended June 30 2007 2006 ------------ ------------ Income before taxes $ 11,382 $ 25,178 Tax rate (%) 32.12 34.50 ------------ ------------ Expected provision for future income taxes 3,656 8,687 Non-deductible Crown payments, net of ARTC - 1,991 Resource allowance - (1,834) Non-deductible stock-based compensation 324 670 Reduction in tax rates - (2,523) Utilization of previously unrecognized losses - (930) Other - (1,576) ------------ ------------ $ 3,980 $ 4,485 ------------ ------------ ------------ ------------ 10. Cash Taxes and Interest Paid During the six months ended June 30, 2007 and 2006, no cash taxes were paid by the Corporation. During the six months ended June 30, 2007, interest paid was $4,259 (2006 - $1,757). 11. 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 US dollar denominated prices. The Corporation's exposure to foreign currency fluctuations on its US dollar denominated debt has been mitigated through the cross currency interest rate swap arrangement which has fixed the foreign exchange rate on principal repayments. 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 revolving and operating debt facilities are at a floating rate of interest. The Corporation's exposure to interest rate fluctuations on its senior second lien term loan facility has been mitigated by the cross currency interest rate swap arrangement which has fixed the interest rate at 9.53 per cent. 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 Canadian dollar long term debt bears interest at a floating market rate and accordingly the fair market value approximates the carrying value. The Corporation's US dollar debt has been swapped into Canadian dollars and the floating interest rate has been fixed. The fair market value of the cross currency interest rate swap arrangement will vary as foreign exchange and interest rates change. Risk management activity: The Corporation had the following natural gas physical sales contracts outstanding at June 30, 2007: Fair market Term Volume Price Cost value ------------------------------------------------------------------------- April 1 to $6.75 to AECO costless October 31, 2007 5,000 GJ/d $8.21/GJ collar $ 604 April 1 to $6.75 to AECO costless October 31, 2007 5,000 GJ/d $8.17/GJ collar 660 April 1 to $6.75 to AECO costless October 31, 2007 5,000 GJ/d $8.10/GJ collar 455 April 1 to $6.75 to AECO costless October 31, 2007 5,000 GJ/d $8.50/GJ collar 465 ----------- $ 2,184 ----------- ----------- The fair market values relate to the remaining life of each contract and 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. The Corporation has elected to continue to account for these contracts as executory contracts on an accrual basis consistent with the contracts expected normal sales requirements. 12. Commitments The following is a summary of the Corporation's contractual obligations and commitments as at June 30, 2007: Payments Due by Period Total 2007 2008 2009 2010 2011 and thereafter ------------------------------------------------------------------------- Credit facilities(1) $175,435 $ - $ - $175,435 $ - $ - Senior second lien debt 106,540 535 1,070 1,070 1,070 102,795 Transportation 573 298 269 6 - - Office premises 1,476 164 328 328 328 328 ------------------------------------------------------------------------- Total contractual obligations $284,024 $ 997 $ 1,667 $176,839 $ 1,398 $103,123 ------------------------------------------------------------------------- (1) Based on the existing terms of the revolving and operating lines of credit, the first payment may be required in June, 2009. (see note 6) 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 & Registrar Stock Exchange Listing Computershare Trust Company of Canada Toronto Stock Exchange Calgary, Alberta Trading Symbol: RRZ Toronto, Ontario Toll Free 1-800-564-6253 Auditors Bankers KPMG LLP The Bank of Nova Scotia Calgary, Alberta Alberta Treasury Branches Royal Bank of Canada Société Générale (Canada Branch) Calgary, Alberta 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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RIDER RESOURCES LTD.

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