Rider Resources Ltd. - Third Quarter 2007 Results



    CALGARY, Nov. 12 /CNW/ -

    
    (TSX: RRZ)

    -------------------------------------------------------------------------
    Financial Highlights      Three Months                Nine Months
                             Ended Sept 30               Ended Sept 30
    (thousands except                          %                           %
     per share amounts)  2007       2006  Change     2007       2006  Change
    -------------------------------------------------------------------------
    Oil and gas
     revenue          $  45,074  $  37,180    21  $ 132,606  $ 116,313    14

    Funds from
     operations(1)    $  20,382  $  21,699    (6) $  64,873  $  68,757    (6)
      Per share
       - basic        $    0.36  $    0.47   (23) $    1.25  $    1.50   (17)
      Per share
       - diluted      $    0.36  $    0.45   (20) $    1.23  $    1.43   (14)

    Net income
     (loss)(2)        $  (3,686) $   5,362  (169) $   3,716  $  26,039   (86)
      Per share
       - basic        $   (0.07) $    0.12  (158) $    0.07  $    0.57   (88)
      Per share
       - diluted      $   (0.07) $    0.11  (164) $    0.07  $    0.54   (87)

    Net capital
     expenditures     $  39,261  $  31,642    24  $ 306,264  $ 110,575   177

    Total assets                                  $ 604,752  $ 324,400    86

    Long term debt,
     plus working
     capital
     deficiency                                   $ 290,101  $ 114,775   153

    Shareholders'
     equity                                       $ 242,030  $ 158,873    52

    Weighted
     average shares
     outstanding
      - basic            56,036     45,858    22     51,988     45,837    13
      - diluted          56,609     47,785    18     52,797     48,128    10

    Shares
     outstanding
      - basic                                        56,059     45,858    22
      - diluted                                      61,221     49,933    23
    -------------------------------------------------------------------------
    Operational
     Highlights
    -------------------------------------------------------------------------
    Average daily
     production
      Natural
       gas (mcf)         52,755     45,078    17     48,514     43,125    12
      Natural gas
       liquids (bbls)     1,896      1,276    49      1,627      1,298    25
      Crude
       oil (bbls)           733        495    48        598        411    45
      Oil equivalent
       (boes 6:1)        11,422      9,284    23     10,311      8,896    16

    Average
     sales price
      Natural
       gas ($/mcf)    $    6.26  $    6.24     -  $    7.28  $    7.26     -
      Natural
       gas liquids
       ($/bbl)        $   55.42  $   66.99   (17) $   55.79  $   64.79   (14)
      Crude
        oil ($/bbl)   $   73.16  $   73.17     -  $   68.70  $   68.40     1

    Expenses
      Operating
       expenses
       ($/boe)        $    7.62  $    6.64    15  $    8.14  $    6.87    18
      General &
       administrative
       expenses
       ($/boe)        $    0.37  $    0.33    12  $    0.60  $    0.37    62

    Operating
     netback ($/boe)  $   25.41  $   27.50    (8) $   27.88  $   30.07    (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.
           (2) For purposes of computing the diluted net loss per share the
               basic weighted average shares outstanding of 56,036 is also


    President's Message

    Rider Resources Ltd. is very pleased to release its financial and
operating results for the quarter ended September 30, 2007.

    Operations

    -   During the second quarter of 2007, the Company closed its
        $199.7 million acquisition of oil and natural gas assets in the South
        Wapiti and Ferrier areas of west central Alberta (the "Acquisition").
        To date the assets added through the Acquisition have met or exceeded
        expectations. The Company has identified additional exploration and
        development opportunities on these assets.
    -   Capital expenditures totaled $306.3 million for the nine months ended
        September 30, 2007, this included $103.9 million which was invested
        in the Company's exploration and development program and
        $202.4 million of acquisitions.
    -   During the third quarter of 2007, the Company drilled 15 (13.1 net)
        wells with a 100 per cent success rate.
    -   Production grew by 16 per cent over the same period in 2006, to
        average 10,311 boe per day in the nine months ended September 30,
        2007 (8,896  boe per day in same period of 2006).
    -   Production in the quarter ended September 30, 2007, averaged
        11,422 boe per day, up 23 per cent from the same quarter of 2006.
        Production during the quarter was 300 boe per day lower than expected
        as a result of longer than expected turnarounds at non-operated
        production facilities.

    Financial

    -   Revenues increased by 14 per cent, to $132.6 million, in the nine
        months ended September 30, 2007, as compared to the same period in
        2006 ($116.3 million).
    -   Funds from operations for the nine months ended September 30, 2007,
        totaled $64.9 million, down 6 per cent when compared to the same
        period in 2006 ($68.8 million).
    -   Funds from operations per share were down 17 per cent to $1.25
        ($1.23 - diluted) for the nine months ended September 30, 2007, as
        compared to $1.50 ($1.43 - diluted) in the same period in 2006.
    -   Net income for the nine months ended September 30, 2007, was
        $3.7 million, or $0.07 ($0.07 - diluted) per share, an 86 per cent
        decrease over the same period in 2006. During the third quarter of
        2007, a net loss of $3.7 million was recorded, the majority of which
        was attributable to the unrealized mark to market loss on the cross
        currency interest rate swap on the US dollar debt.
    -   The average natural gas price received by the Company for the nine
        months ended September 30, 2007, was $7.28 per mcf, which is
        consistent with 2006.
    

    New Royalty Framework

    On October 25, 2007, the Government of Alberta released its New Royalty
Framework ("NRF"), which is proposed to take effect January 1, 2009. The NRF
has modified the royalty structure in Alberta to provide for significantly
increased royalties on higher productivity wells with a rapid escalation in
royalties as commodity prices increase. While Rider is not as adversely
impacted as some industry participants, we believe the decision to
retroactively alter royalties on existing production and undeveloped acreage
is extremely disappointing.
    Prior to the NRF announcement, the industry was working through the
impact of a rapidly rising Canadian dollar and weaker than anticipated natural
gas pricing. Service costs were moderating and we were optimistic that with
improving natural gas prices the industry could begin to increase drilling
activity.
    The result of the NRF will be to delay a recovery in drilling activity
while putting significant pressure on the industry to further reduce costs.
Profit margins for service providers have come down and now they will need to
begin the arduous process of reducing the cost of labour. This process will
take some time. The winter drilling season is rapidly approaching and with
continued uncertainty regarding detailed implementation of the NRF, drilling
levels will undoubtedly continue to fall.
    One of the main components of the change in natural gas royalties is to
introduce much greater sensitivity to rate of production for each well. Rider
has a wide range of wells with both lower and higher rates of production. The
higher rate wells will be subject to increasing royalty rates, while the lower
rate wells will pay decreased royalties. Utilizing a September 1, 2007,
Paddock Lindstrom price forecast, the negative impact to Rider's net asset
value is not expected to be material.
    Partially offsetting the increased royalties payable on new natural gas
wells is a depth sensitive adjustment. Wells must be drilled to at least
2,000 metres to qualify for this adjustment. The majority of Rider's acreage
has production targets that range in depth from 2,200 to over 3,000 meters. As
a consequence our royalty payable on new wells will be reduced. The amount of
royalty reduction will be dependent upon the rate of production and the price
of natural gas.
    The rate of return anticipated on our drilling inventory, as a result of
the deeper well royalty adjustment offsetting the higher royalty under the
NRF, has not been significantly altered at current natural gas prices.
However, this rate of return is not high enough to accelerate drilling levels
given current costs.

    Outlook

    Rider slowed its drilling activity beginning in September in order to
assess the direction of natural gas prices and service costs. We will remain
patient and continue to run one drilling rig, and invest slightly less than
cash flow through the fourth quarter of 2007 and first quarter of 2008. We
have seen an appreciable decline in service costs through the third quarter
for the wells drilled, and a resultant improvement in finding costs. With this
level of activity we anticipate being able to maintain production volumes in
the 12,000 to 12,500 boe per day range. The Company will continue to maintain
financial flexibility with this level of capital expenditure, and is
forecasted to have over $40 million in undrawn credit facilities at year end.
We are forecasting 2007 cash flow to be approximately $90 million based on a
production average of 10,700 boe per day and an average natural gas price of
$7.00 per mcf. Rider has a strong and growing inventory of projects that
deliver acceptable economic returns now and as the cost structure of the
industry improves will provide growth in the future.
    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
    November 12, 2007



    MANAGEMENT'S DISCUSSION AND ANALYSIS

    November 12, 2007

    Management's discussion and analysis ("MD&A") of financial conditions and
results of operations should be read in conjunction with Rider Resources
Ltd.'s ("Rider" or the "Company") interim consolidated financial statements
for the three and nine months ended September 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 November 12, 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 the MD&A, 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      Nine months ended
                                      September 30            September 30
    ($ thousands)                   2007        2006        2007        2006
    -------------------------------------------------------------------------
    Cash flow from operating
     activities (per GAAP)        28,742      20,477      60,619      60,852
    Change in non-cash
     working capital              (8,360)      1,222       4,254       7,905
    -------------------------------------------------------------------------
    Funds from operations         20,382      21,699      64,873      68,757
    -------------------------------------------------------------------------

    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        Sept. 30,    June 30,    Mar. 31,    Dec. 31,
     per share amounts)             2007        2007        2007        2006
    -------------------------------------------------------------------------
    Oil and gas revenue           45,074      49,510      38,022      37,840
    Net income (loss)             (3,686)      2,965       4,437       4,272
      - per share - basic          (0.07)       0.06        0.09        0.09
      - per share - diluted        (0.07)       0.06        0.09        0.09
    Funds from operations         20,382      24,163      20,328      21,504
      - per share - basic           0.36        0.46        0.43        0.47
      - per share - diluted         0.36        0.45        0.42        0.45


                                              Three months ended

    ($ thousands, except        Sept. 30,    June 30,    Mar. 31,    Dec. 31,
     per share amounts)             2006        2006        2006        2005
    -------------------------------------------------------------------------
    Oil and gas revenue           37,180      37,713      41,420      55,789
    Net income (loss)              5,362      10,627      10,050      15,589
      - per share - basic           0.12        0.23        0.22        0.34
      - per share - diluted         0.11        0.22        0.21        0.32
    Funds from operations         21,699      21,453      25,605      35,782
      - per share - basic           0.47        0.47        0.56        0.78
      - per share - diluted         0.45        0.45        0.53        0.74

    Trends

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

    Acquisition

    On May 11, 2007, Rider acquired assets in the South Wapiti and Ferrier
areas of Alberta for total consideration of $199.7 million (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
                            Sept. 30,  June 30, March 31,  Dec. 31, Sept. 30,
                                2007      2007      2007      2006      2006
    -------------------------------------------------------------------------
    Crude oil (bbls/d)           733       535       523       635       495
    Natural gas
     liquids (bbls/d)          1,896     1,798     1,179     1,262     1,276
    Total liquids (bbls/d)     2,629     2,333     1,702     1,897     1,771
    Natural gas (mcf/d)       52,755    52,294    40,357    40,300    45,078
    -------------------------------------------------------------------------

    Total (boe/d)             11,422    11,048     8,428     8,613     9,284
    -------------------------------------------------------------------------

    Average daily production of crude oil and natural gas liquids for the nine
months ended September 30, 2007, increased to 2,225 bbls/d from 1,709 bbls/d
during the same period of 2006. For the quarter ended September 30, 2007,
crude oil and natural gas liquids production averaged 2,629 bbls/d as compared
to 1,771 bbls/d in the third quarter of 2006. Production during the quarter
was lower than forecast as a result of longer than expected turnarounds at
non-operated facilities. Average daily natural gas sales increased in the nine
months ended September 30, 2007, to 48.5 mmcf/d from 43.1 mmcf/d recorded in
the same period of the previous year. Natural gas sales averaged 52.8 mmcf/d
during the third quarter of 2007 as compared to 45.1 mmcf/d for the same
quarter in 2006. Production for the nine months ended September 30, 2007,
averaged 10,311 boe/d as compared to 8,896 boe/d in the same period of 2006.
The Company's internally generated exploration and development program and the
Acquisition have caused the production growth.

    Financial Performance

    Commodity Prices

    -------------------------------------------------------------------------
                                   Three months ended      Nine months ended
                                      September 30            September 30
    Realized Prices                 2007        2006        2007        2006
    -------------------------------------------------------------------------
    Crude Oil ($/bbl)              73.16       73.17       68.70       68.40
    Natural Gas Liquids ($/bbl)    55.42       66.99       55.79       64.79
    Natural Gas ($/mcf)             6.26        6.24        7.28        7.26
    -------------------------------------------------------------------------
    

    The price for West Texas Intermediate crude oil was very strong,
averaging US$74.91 per barrel during the third quarter of 2007. However, the
strong Canadian dollar eroded the price increase and as a result the average
price received by the Company for crude oil in the third quarter was
$73.16 per bbl which was basically the same price as received in the three
months ended September 30, 2006. The Company's average crude oil price during
the nine months ended September 30, 2007, was $68.70 per bbl (2006- $68.40).
The average natural gas liquids price was $55.79 per bbl during the nine
months ended September 30, 2007, as compared to $64.75 per bbl for the nine
months ended September 30, 2006. The average natural gas liquids price was
$55.42 per bbl during the third quarter of 2007. The average price for natural
gas liquids declined because the natural gas liquid volumes added through the
Acquisition do not receive premium prices.
    The realized natural gas price averaged $7.28 per mcf during the nine
months ended September 30, 2007, versus $7.26 per mcf in the same period of
2006. For the third quarter, natural gas prices averaged $6.26 per mcf as
compared to $6.24 per mcf in the same period in 2006.

    Revenue

    Production growth as a result of the Company's exploration and
development program and the Acquisition, offset by slightly lower liquid
prices, resulted in revenues for the nine months ended September 30, 2007,
increasing to $132.6 million from $116.3 million in the same period in 2006,
and $45.1 million for the third quarter as compared to $37.2 million for the
third quarter of 2006.

    Royalties

    Royalties for the nine months ended September 30, 2007, totaled
$29.8 million (22.5 per cent of revenues), compared with $25.1 million
(21.5 per cent of revenues) in the same period in 2006.

    Expenses

    Production expenses for the nine months ended September 30, 2007, were
$22.9 million as compared to $16.7 million in the same period of 2006.
Production expenses for the three months ended September 30, 2007, were
$8.0 million ($5.7 million - 2006). Production expenses are up on an aggregate
basis as a result of increasing production volumes. On a per boe basis,
production expenses for the nine months ended September 30, 2007, were $8.14,
up 18 per cent from the same period in 2006 ($6.87 per boe). In the third
quarter of 2007, operating costs were $7.62 per boe as compared to $6.64 per
boe in the same quarter in 2006. On a boe basis, operating costs were up due
to increased industry costs.
    Interest expense for the nine months ended September 30, 2007, was
$10.1 million, compared with $3.2 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 that latter of which also bears a higher interest rate.
    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 that it elected to expense immediately.
    An unrealized foreign exchange gain of $7.0 million was recorded in the
third quarter of 2007 related to the foreign currency translation on the
second lien debt and an unrealized loss on financial instruments of
$11.3 million was recorded on the fair valuation of the cross currency
interest rate swap related to the second lien debt. The Company entered into
this contract as a hedge against foreign currency and interest rate
fluctuations. From a business perspective, we believe an economic hedge has
been achieved however, due to overly stringent and onerous requirements for
hedge accounting we have chosen to fair value account for the cross currency
interest rate swap which has, and may continue to significantly impact
earnings.
    For the nine months ended September 30, 2007, general and administrative
expenses were $0.60 per boe, up 62 per cent from the same period of 2006.
General and administrative costs increased as a result of the growth in the
Company, lower recoveries of general and administrative expenses and higher
costs in the industry. During the nine months ended September 30, 2007, the
Company capitalized overhead charges of $1.2 million (2006 - $1.0 million).
    Depletion and depreciation expense amounted to $53.2 million, or
$18.90 per boe, for the nine months ending September 30, 2007, compared with
$32.3 million or $13.28 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 $0.8 million, or $0.74 per boe, was
recorded for the three months ended September 30, 2007, as compared to
$0.9 million, or $1.00 per boe, for the same period of 2006. For the nine
months ended September 30, 2007, stock based compensation was $1.8 million or
$0.64 per boe.

    
    Net Income and Funds from Operations per boe

                              Three Months                Nine Months
                           Ended September 30          Ended September 30
    -------------------------------------------------------------------------
                                               %                           %
                         2007       2006  Change     2007       2006  Change
    -------------------------------------------------------------------------
    Revenue           $   42.89  $   43.53    (1) $   47.11  $   47.89    (2)
      Royalties,
       net of ARTC        (9.35)     (8.70)    7     (10.58)    (10.32)    3
      Production
       expenses           (7.62)     (6.64)   15      (8.14)     (6.87)   18
      Transportation      (0.51)     (0.69)  (26)     (0.51)     (0.63)  (19)
    -------------------------------------------------------------------------
    Operating Netback     25.41      27.50    (8)     27.88      30.07    (7)
      General and
       administrative
       expenses           (0.37)     (0.33)   12      (0.60)     (0.37)   62
      Interest expense    (5.53)     (1.70)  225      (3.59)     (1.32)  172
      Financing fees          -          -     -      (0.57)         -     -
    -------------------------------------------------------------------------
    Funds from
     operations           19.51      25.47   (23)     23.12      28.37   (19)
      Depletion,
       depreciation
       and accretion     (19.57)    (14.28)   37     (18.90)    (13.28)   42
      Stock-based
       compensation
       expense            (0.74)     (1.00)  (26)     (0.64)     (1.16)  (45)
      Foreign exchange
       gain                6.70          -     -       2.66          -     -
      Unrealized loss
       on financial
       instruments       (10.72)         -     -      (4.00)         -     -
      Future income
       taxes               1.31      (3.91)  134      (0.93)     (3.22)  (71)
    -------------------------------------------------------------------------
    Net Income
     (loss)           $   (3.51) $    6.28  (156) $    1.31  $   10.72   (88)
    -------------------------------------------------------------------------
    

    Taxes

    In the nine months ended September 30, 2007, the Company recorded a
future income tax charge of $2.6 million, for an effective rate of 41%,
compared to $7.8 million, for an effective rate of 23% in the same period 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 (Loss)

    The net loss for the quarter ended September 30, 2007, was $3.7 million,
down from net income of $5.4 million for the same quarter in 2006. Included in
net income was a foreign exchange gain of $7.0 million and an unrealized loss
on financial instruments of $11.3 million (See "Expenses"). Diluted loss per
share for the quarter was $0.07 per share compared to diluted net income of
$0.11 per share for the same period of 2006. Net income for the nine months
ended September 30, 2007, was $3.7 million as compared to $26.0 million for
the same period in 2006. Funds from operations for the nine months ended
September 30, 2007, decreased to $64.9 million ($1.23 per diluted share),
compared with $68.8 million ($1.43 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 and due to the
significant loss on the mark to market of the cross currency swap.

    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 for a purchase price of
$199.7 million. 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 September 30, 2007, $99.2 million (US$99.8 million) is outstanding
under this facility, of which the current portion is $1.0 million (US$1.0
million) with the balance of $98.2 million (US$98.8 million) reflected as long
term debt. At September 30, 2007, the Company's effective interest rate was
9.53 per cent. The facility covenants include a requirement that total proved
reserves value is 1.5 times debt, determined semi-annually, and EBITDA must
exceed interest expense by 3.5 times.
    In conjunction with the senior second lien term loan, the Company 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 September 30, 2007, the fair value of the cross
currency swap was a loss of $11.3 million.
    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 September 30, 2007, total long term debt plus working capital
deficiency was $290.1 million.
    The Company had set its exploration and development capital budget for
the balance of 2007 equal to cash flow.

    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 September 30, 2007:

    
                                      Payments Due by Period

                     Total      2007      2008      2009      2010   2011 and
                                                                   thereafter
    -------------------------------------------------------------------------
    Credit
     facil-
     ities(1)     $186,270  $      -  $      -  $186,270  $      -  $      -
    Senior
     second lien
     debt          106,733       268     1,070     1,070     1,070   103,255
    Transportation     424       149       269         6         -         -
    Office
     premises        1,394        82       328       328       328       328
    -------------------------------------------------------------------------
    Total
     contractual
     obligations  $294,821  $    499  $  1,667  $187,674  $  1,398  $103,583
    -------------------------------------------------------------------------
    (1) Based on the existing terms of the facilities, the first payment may
        be required in June 2009.

    Capital Expenditures

    During the nine months ended September 30, 2007, the Company spent a total
of $306.3 million on capital expenditures, a breakdown of which is outlined
below.

                                              Nine months ended September 30
    (thousands)                                           2007          2006
    -------------------------------------------------------------------------
    Net acquisitions (dispositions)                  $ 202,380     $    (256)
    Land and seismic                                    15,575         8,188
    Drilling                                            64,998        71,050
    Production and well equipment                        7,717         8,967
    Plant and facilities                                14,056        21,394
    Other                                                1,538         1,232
    -------------------------------------------------------------------------
                                                     $ 306,264     $ 110,575
    -------------------------------------------------------------------------
    

    Off Balance Sheet Arrangements

    As at the date of this MD&A, 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 MD&A, 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 had 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 September 30, 2007, the Company had
56,058,526 common shares and 5,162,601 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 MD&A 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 third 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.
    In Alberta, the Climate Change and Emissions Management Amendment Act,
came into effect in July 1, 2007, which intends to reduce greenhouse gas
emission intensity from large industries. Alberta 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 October 25, 2007, the Alberta Government released The New Royalty
Framework ("NRF") which summarizes the government's decision on Alberta's new
royalty regime pertaining to oil and gas resources, including oil sands,
conventional oil and gas and coalbed methane. The NRF was the Alberta
government's response to the recommendations recently put forth by the Alberta
Royalty Review Panel. The NRF is proposed to take effect on January 1, 2009.
Rider has reviewed the modifications proposed by the Government of Alberta to
its royalty regime and is continuing to assess the impact of the new royalty
regime on its operations. While Rider cannot determine the full potential
impact of these changes to the royalty rate on its operations at this time, it
is able to make the following observations. The Company expects the NRF, if
enacted as proposed, to increase its average royalty rate commencing
January 1, 2009, subject to transitional rules which have not yet been made
available to the Company. The Company anticipates that the proposed increases
to royalties will also have a negative impact on net earnings, funds from
operations, cash flow from operating activities, operating netbacks, could
create uncertainty as to the recoverability of the carrying value of the
Company's petroleum and natural gas assets.


    
                            RIDER RE

SOURCES LTD. CONSOLIDATED BALANCE SHEETS (thousands) (UNAUDITED) ------------------------------------------------------------------------- September 30, December 31, 2007 2006 ------------- ------------- Assets Current assets Accounts receivable $ 21,135 $ 23,282 Prepaid expenses 447 1,209 ------------- ------------- 21,582 24,491 Investments (note 4) - 4,000 Property, plant and equipment (note 5) 583,170 327,266 ------------- ------------- $ 604,752 $ 355,757 ------------- ------------- ------------- ------------- Liabilities Current liabilities Accounts payable and accrued liabilities $ 26,181 $ 33,344 Current portion of long term debt (note 6) 995 - ------------- ------------- 27,176 33,344 Long term debt (note 6) 284,507 121,600 Asset retirement obligations (note 7) 7,358 6,072 Fair value of financial instruments (note 6) 11,267 - Future income taxes 32,414 30,914 ------------- ------------- 362,722 191,930 ------------- ------------- Shareholders' equity Share capital (note 8) 166,918 93,029 Contributed surplus (note 8) 8,351 7,753 Retained earnings 66,761 63,045 ------------- ------------- 242,030 163,827 ------------- ------------- $ 604,752 $ 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 Nine Months Ended September 30 September 30 2007 2006 2007 2006 ---------- ---------- ---------- ---------- Revenue Oil and gas sales $ 45,074 $ 37,180 $ 132,606 $ 116,313 Royalties, net of ARTC (9,822) (7,433) (29,784) (25,065) ---------- ---------- ---------- ---------- 35,252 29,747 102,822 91,248 ---------- ---------- ---------- ---------- Expenses Production 8,005 5,672 22,911 16,680 Transportation 543 585 1,435 1,542 Interest 5,807 1,453 10,128 3,185 Financing fees - - 1,607 - Foreign exchange gain (7,041) - (7,501) - Unrealized loss on financial instruments 11,267 - 11,267 - General and administrative 391 281 1,677 926 Stock-based compensation 780 855 1,789 2,796 Depletion, depreciation and accretion 20,561 12,198 53,188 32,254 ---------- ---------- ---------- ---------- 40,313 21,044 96,501 57,383 ---------- ---------- ---------- ---------- Income (loss) before taxes (5,061) 8,703 6,321 33,865 Future income taxes (reduction) (note 9) (1,375) 3,341 2,605 7,826 ---------- ---------- ---------- ---------- Net income (loss) for the period (3,686) 5,362 3,716 26,039 Retained earnings, beginning of period 70,447 53,411 63,045 32,734 ---------- ---------- ---------- ---------- Retained earnings, end of period $ 66,761 $ 58,773 $ 66,761 $ 58,773 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- Net income (loss) per share - basic $ (0.07) $ 0.12 $ 0.07 $ 0.57 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- Net income (loss) per share - diluted $ (0.07) $ 0.11 $ 0.07 $ 0.54 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- See accompanying notes to consolidated financial statements. RIDER RE

SOURCES LTD. CONSOLIDATED STATEMENTS OF CASH FLOWS (thousands) (UNAUDITED) ------------------------------------------------------------------------- Three Months Ended Nine Months Ended September 30 September 30 2007 2006 2007 2006 ---------- ---------- ---------- ---------- Cash provided by (used in): Operating Net income (loss) $ (3,686) $ 5,362 $ 3,716 $ 26,039 Stock-based compensation 780 855 1,789 2,796 Depletion, depreciation and accretion 20,561 12,198 53,188 32,254 Unrealized foreign exchange gain (7,041) - (7,501) - Unrealized loss on financial instruments 11,267 - 11,267 - Future income taxes (reduction) (1,375) 3,341 2,605 7,826 Asset retirement expenditures (124) (57) (191) (158) ---------- ---------- ---------- ---------- 20,382 21,699 64,873 68,757 Net change in non-cash working capital 8,360 (1,222) (4,254) (7,905) ---------- ---------- ---------- ---------- 28,742 20,477 60,619 60,852 ---------- ---------- ---------- ---------- Financing Increase in long term debt 10,568 11,165 171,403 53,217 Issue of share capital, net of issue costs (49) - 70,242 506 ---------- ---------- ---------- ---------- 10,519 11,165 241,645 53,723 ---------- ---------- ---------- ---------- Investing Property acquisitions, net of dispositions (2,706) 9 (202,380) 256 Capital expenditures (36,555) (31,651) (103,884) (110,831) Disposition (purchase) of investments - - 4,000 (4,000) ---------- ---------- ---------- ---------- (39,261) (31,642) (302,264) (114,575) ---------- ---------- ---------- ---------- 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 Nine Months Ended September 30, 2007 (thousands, except per share amounts) (UNAUDITED) 1. Basis of Presentation The consolidated financial statements for the three and nine months ended September 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, future interest rates and future foreign exchange rates 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 September 30, December 31, 2007 2006 ------------------------------------------------------------------------- Cost $ 726,091 $ 417,390 Accumulated depletion and depreciation (142,921) (90,124) ------------------------------------------------------------------------- $ 583,170 $ 327,266 ------------------------------------------------------------------------- ------------------------------------------------------------------------- During the nine months ended September 30, 2007, the Corporation capitalized overhead charges of $1,197 (2006 - $1,003) and stock based compensation of $1,351 (2006 - Nil). Costs related to unproved properties of $65,232 (2006 - $37,814) were excluded from the depletion calculation. Future development capital of $7,000 (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 September 30, 2007, $186,270 (December 31, 2006 - $121,600) had been drawn under these facilities at an effective interest rate of 6.20 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 in 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 US$100,000 senior second lien term loan, repayable in quarterly principal installments of US$250 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 September 30, 2007, $99,232 (US$99,750) is outstanding under this term loan of which the current portion is $995 (US $1,000), with the balance of $98,237 (US$98,750) reflected as long term debt. At September 30, 2007, the Corporation's effective interest rate was fixed at 9.53 per cent. Future scheduled repayments have been fixed in Canadian dollars as follows: 2007 - $249 (US$250); 2008 - $995 (US$1,000); 2009 - $995 (US$1,000); 2010 - $995 (US$1,000); 2011 - $995 (US$1,000); and 2012 - $95,003 (US$95,500). 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 September 30, 2007, the fair value of the swap was a loss of $11,267. 7. Asset Retirement Obligations At September 30, 2007, the estimated total undiscounted amount required to settle asset retirement obligations was $17,830 (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: September 30, December 31, 2007 2006 ------------------------------------------------------------------------- Asset retirement obligations, beginning $ 6,072 $ 4,565 Liabilities incurred 515 1,367 Liabilities incurred on acquisition (note 5) 571 - Liabilities settled (191) (253) Accretion 391 393 ------------------------------------------------------------------------- Asset retirement obligations, ending $ 7,358 $ 6,072 ------------------------------------------------------------------------- The asset retirement accretion expense of $391 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 1,348 4,522 Issue of flow through shares 1,350 14,355 Issue of common shares for equity financing 7,500 52,470 Stock-based compensation on exercise of stock options - 2,542 ---------- ---------- Balance at September 30, 2007 56,059 $ 166,918 ---------- ---------- ---------- ---------- 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 September 30, 2007, approximately $4,381 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 $52,470 after issue costs of $1,905 (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 September 30, 2007 and December 31, 2006. (a) Per Share Amounts Weighted average number Three Months Ended Nine Months Ended of common shares September 30 September 30 outstanding 2007 2006 2007 2006 ------------------------------------------------------------------------- Basic 56,036 45,858 51,988 45,837 Dilutive effect of options - 1,927 809 2,291 ---------- ---------- ---------- ---------- Diluted 56,036 47,785 52,797 48,128 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- 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. Weighted Average Weighted Remaining Average Contractual Number of Exercise Life in Stock Options - Common Shares Options Price 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 3,515 8.28 4.52 Cancelled (907) 9.38 1.70 Exercised (1,348) 3.35 0.99 ------------ ------------ ------------ Outstanding at September 30, 2007 5,162 $ 7.00 3.55 ------------ ------------ ------------ ------------ ------------ ------------ Options exercisable at September 30, 2007 1,331 $ 3.87 1.22 ------------ ------------ ------------ ------------ ------------ ------------ Nine months ended September 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 Nine months ended Year ended September 30, December 31, 2007 2006 ------------- ------------ Balance, beginning of period $ 7,753 $ 4,613 Stock-based compensation 3,140 3,468 Transfer to share capital on exercise of options (2,542) (328) ------------- ------------ Balance, end of period $ 8,351 $ 7,753 ------------- ------------ ------------- ------------ 9. Future Income Taxes The provision for future income taxes was determined as follows: Nine months ended September 30 2007 2006 ------------------------------------------------------------------------- Income before taxes $ 6,321 $ 33,865 Tax rate (%) 32.12 34.50 ------------- ------------ Expected provision for future income taxes 2,030 11,683 Non-deductible Crown payments, net of ARTC - 2,839 Resource allowance - (2,638) Non-deductible stock-based compensation 575 965 Reduction in tax rates - (2,523) Utilization of previously unrecognized losses - (930) Other - (1,570) ------------- ------------ $ 2,605 $ 7,826 ------------- ------------ ------------- ------------ 10. Cash Taxes and Interest Paid During the nine months ended September 30, 2007 and 2006, no cash taxes were paid by the Corporation. During the nine months ended September 30, 2007, interest paid was $11,002 (2006 - $3,210). 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 September 30, 2007: Fair market Term Volume Price Cost value ------------------------------------------------------------------------- April 1 to AECO costless October 31, 2007 5,000 GJ/d $6.75 to $8.21/GJ collar $ 274 April 1 to AECO costless October 31, 2007 5,000 GJ/d $6.75 to $8.17/GJ collar 281 April 1 to AECO costless October 31, 2007 5,000 GJ/d $6.75 to $8.10/GJ collar 274 April 1 to AECO costless October 31, 2007 5,000 GJ/d $6.75 to $8.50/GJ collar 274 -------- $ 1,103 -------- -------- 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 September 30, 2007: Payments Due by Period 2011 and there- Total 2007 2008 2009 2010 after ------------------------------------------------------------------------- Credit facilities(1) $186,270 $ - $ - $186,270 $ - $ - Senior second lien debt 106,733 268 1,070 1,070 1,070 103,255 Transportation 424 149 269 6 - - Office premises 1,394 82 328 328 328 328 ------------------------------------------------------------------------- Total contractual obligations $294,821 $ 499 $ 1,667 $187,674 $ 1,398 $103,583 ------------------------------------------------------------------------- (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 Computershare Trust Company of Canada Calgary, Alberta Toronto, Ontario Toll Free 1-800-564-6253 Stock Exchange Listing Toronto Stock Exchange Trading Symbol: RRZ Auditors KPMG LLP Calgary, Alberta Bankers The Bank of Nova Scotia 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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