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   Filed by Automated Filing Services Inc. (604) 609-0244 - Dynamic Oil & Gas, Inc. - Corresp

September 14, 2005

United States Securities
     and
Exchange Commission
Division of Corporate Finance
Mail Stop
05-05
Washington, D.C. 20549-0405

Re: Dynamic Oil & Gas, Inc.
(“Dynamic”)
       Form 20-F for Fiscal
Year Ended December 31, 2004
       Filed March
31, 2005
       File No.
0-17551
       Your Letter Dated
August 15, 2005 In Review
       Of Our
August 9, 2005 Response Letter

Dear Sirs:

     In connection with the
above-referenced comment letter, our responses are as follows:

Form 20-F for the Fiscal Year Ended December 31,
2004

Engineering Comments

Estimated Reserves of Crude Oil, Natural Gas and Natural Gas
Liquids, page 28

SEC comment:

    1.

      As to response number 1 of your letter dated August 9,
        2005, it appears that reserves were assigned based on decline curve analysis
        of only short-term production data. Tell us how past depletion was accounted
        for in each case and tell us the calculated recovery factors when taking
        the 2003 proved reserve estimates for these wells and offset wells into
        account. We may have further comments.

Management’s response:

    The following response has been provided by Dynamic’s
        independent evaluation engineers, Sproule Associates Limited of Calgary,
        Alberta, and reviewed by Dynamic’s management.

    Please note that the production forecast curves shown
        on the rate-time plots provided with the August 9th response were provided
        for illustrative purposes per the SEC request and they were not intended
        to suggest that decline analysis was used to determine reserves for these
        wells. The 2003 year-end reported reserves for each of the 8 wells for
        which the SEC requested rate-time plots were estimated from analogy to
        offset wells, from volumetrics, or from performance prediction as described
        more fully below. The 2003 production forecast line was created by using
        the initial production rate from the 2003 year-end report and assumed
        an exponential decline to the assigned reserves for each well.

    Chowade d-38-E/94-B-9

    The Baldonnel zone in this well commenced production
        in mid-2003. This well flow tested at 4.1 MMcfpd at a tubing-head pressure
        of 2003 psia. Log analysis of the Baldonnel and Charlie Lake zones in
        this well indicated extensive fracture development similar to offset wells.
        As meaningful volumetric parameters could not be accurately determined,
        the proved reserves were assigned by performance prediction assuming a
        30% decline rate from the year-end 2003 production rate. Proved plus probable
        reserves were assigned by analogy based on the average well gross ultimate
        recovery of 4,500 MMCF in the adjacent Cypress/Chowade Baldonnel pools.

    In 2004, the water-gas ratio increased sharply, possibly
        due to coning water up through the fracture system. Unsuccessful water
        shut-off workovers were completed in March and July 2004. The well was
        shut-in during December 2004, producing 400 Mcfpd with a water-gas ratio
        of 180 barrels per MMCF. Proved reserves were not assigned in the 2004
        year-end report based on well performance. The company has indicated plans
        to reactivate the well. Probable developed reserves of 500 MMCF were assigned
        in the 2004 year-end report based on the well being reactivated and maintaining
        consistent economic production. The probable reserves were estimated based
        on material balance using the initial reservoir pressure and the July
        2004 static gradient of 1,724 psia. A 50% recovery factor of the gas in
        place was used for the probable reserve assignment.

    Cypress a-70-F/94-B-15 (c-59-F/94-B-15/2)

    This well was completed in the Charlie Lake-Kobes
        zone in late 2003 and tested at 2,270 Mcfpd with a water-gas ratio of
        23 barrels per MMCF. As the well was not on production at year-end 2003
        proved developed non-producing reserves were assigned by volumetrics in
        the 2003 year-end report. The volumetric assignment assumed a drainage
        area of 525 acres for proved developed non-producing reserves and a drainage
        area of 700 acres for proved plus probable reserves. A recovery factor
        of 50% was used for both proved and proved plus probable reserves due
        to the water production experienced after initial completion and workover
        of the well.

    In the 2004 year-end report proved and proved plus
        probable reserves were assigned by volumetrics. The recovery factor of
        50% and the aerial extent of 350 acres for proved reserves and 500 acres
        for proved plus probable reserves was influenced by the increasing water-gas
        ratios since the well came on production. At year-end 2004 the cumulative
        production from this well was 272 MMCF representing a 21% recovery factor
        of the 2004 year-end proved gas in place estimate.

    Cypress d-67-F/94-B-15/0

    A DST of the Halfway zone flowed gas at 6,630 Mcfpd
        and appeared to be cleaning up. The zone was perforated and after 58 hours
        of flow was tested at 4,035 Mcfpd at a flowing wellhead pressure of 1,985
        psia. The Halfway zone did not come on production until February 2004.
        Year-end 2003 proved developed non-producing and proved plus probable
        reserves were based on analogy to the depleted Halfway producer at d-91-E/94-B-15,
        which recovered 3,600 MMCF and is currently shut-in. The 2003 year-end
        proved reserves assigned were 75% of the d-91-E analogy ultimate recovery
        (2,700 MMCF), and the proved plus probable reserves assigned were based
        on the analogous d-91-E well ultimate recoverable gas (3,600 MMCF).

    In 2004, production rates have declined sharply from
        the Halfway zone in this well. Year-end 2004 proved and proved plus probable
        reserves were assigned based on an estimated material balance using the
        initial pressures from d-67-F and b-87-F, the recently-drilled

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    offset. Recovery factors of 65/75 percent for proved
        and proved plus probable reserves were assigned to the original recoverable
        gas in place of 1,750 MMCF. All the remaining reserves at year-end 2004
        were assigned to d-67-F because b-87-F is not on production and competing
        for reserves. At year-end 2004 the cumulative production from this well
        is 910 MMCF representing 52% recovery of the gas in place estimated from
        material balance.

    Cypress B-A027-K/94-B-15

    The Halfway zone in this well was drill-stem tested
        over two separate intervals at flow rates of 4,800 and 1,670 Mcfpd. The
        initial and final shut-in pressures were consistent at 2,534 psia. The
        geological assessment indicates that the Halfway zone has two fractured
        zones and also two feet of net gas pay. The Halfway zone was completed
        in October 2003 with seven perforation intervals shot between 5,492 and
        5,756 feet KB. The final flow rate on test was 4,250 Mcfpd at a flowing
        tubing-head pressure of 1,650 psia. Year-end 2003 proved undeveloped and
        proved plus probable gas reserves were assigned based on analogy with
        d-91-E/94-B-15, a nearby shut-in Halfway gas well which recovered 3,600
        MMCF. The proved undeveloped case represents 75% of the reserves recovered
        by the analogous d-91-E well (2,700 MMCF), and the proved plus probable
        reserves assigned are the same as that recovered by the analogous d-91-E
        well.

    The well started producing in May 2004 and by September
        the WGR had increased to 387 barrels per MMCF. A workover to shut off
        the water was done in October 2004, and the Halfway zone came back on
        production at 1,000 Mcfpd with a water-gas ratio of two barrels per MMCF.
        During November 2004 the water-gas ratio increased to over 100 barrels
        per MMCF and was shut-in. The original gas in place was estimated based
        on a calculated material balance using the original pool pressure and
        the October 2004 post workover static gradients. The reservoir pressure
        estimated from the static gradients was 1,790 psia and it is unlikely
        that the well was fully built up as the workover was completed on October
        5, 2004. No proved reserves were assigned in the 2004 year- end report
        to this well. Probable developed gas reserves of 500 MMCF were assigned
        based on another water shut-off workover being done and the Halfway zone
        resuming production at economic rates for a short period.

    St. Albert 03/13-25-53-26W4/6

    The 03/13-25-53-26W4/6 Nisku D-2A well came on production
        in November 2003 and at year end 2003 was producing at 235 bopd at 33%
        water cut. Year-end 2003 proved oil reserves were estimated for the Nisku
        D-2A pool by volumetric methods using the net oil pay isopach map and
        the existing oil-water contact. A proved recovery factor of 50% was used
        based on the high oil rate, low water cut and low reserve life index from
        the pool producers at year-end 2003. The resulting reserves were allocated
        to the wells 0/11-25-53-26W4/3 and 03/13-25-53-26W4/6 based on their relative
        year-end 2003 oil production rates. Proved plus probable reserves for
        the Nisku D-2A pool were based on a 65% recovery factor and reserves were
        allocated to the two existing producers and to the recompletion candidate
        in 0/6-25-53-26W4 based on expected relative oil production rates.

    Year end 2004 proved and proved plus probable reserves
        were assigned to 00/11-25-53-26W4/3 by decline analysis. The ultimate
        recoverable proved and proved plus probable reserves for the Nisku D-2A
        pool were estimated from a log oil cut versus cumulative oil production
        plot. The pool remaining reserves were allocated between the 03/13-25-53-26W4/6
        and 00/06-25-53-26W4/7 wells based on relative oil production rates. Cumulative
        production from the pool at December 31, 2004 was 107.5 Mbbl. which represents
        a 31% recovery factor of the OIP estimate of 344.6 Mbbl. for the pool
        calculated in the 2003 year-end report.

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    St. Albert 00/06-25-53-26W4/6

    The 00/6-25-53-26W4/6 well is part of the Leduc D-3A
        south pool and was producing at about 100 bopd just prior to year-end
        2003. Year-end 2003 reserves were assigned to the Leduc D-3A south pool
        by volumetric methods using the net oil pay isopach map with existing
        oil-water contacts. A proved recovery factor of 40% was used and the resulting
        oil reserves were allocated to the shut-in 00/06-25-53-26W4/6 well and
        the producing 03/5-25-53-26W4 well based on relative oil production rates.
        Proved plus probable oil reserves were based on a pool recovery factor
        of 45%.

    Year-end 2004 reserves were assigned to the Leduc
        D-3A South pool by volumetric methods using the net oil pay isopach map
        generated at year-end 2003 and a proved recovery factor of 30% and a proved
        plus probable recovery factor of 45%. All of the remaining Leduc D-3A
        south pool reserves were assigned to 03/5-25-53-26W4/3 as the 00/6-25-53-26W4/6
        well has been recompleted to the Nisku D-2A zone. Cumulative production
        from the D-3A south pool wells at year-end 2004 was 297 Mbbl. which represents
        a 25% recovery factor of the oil in place from the year-end 2003 net pay
        isopach maps for the pool.

    St. Albert 00/15-36-53-26W4/2

    The 00/15-36-53-26W4/2 well was recompleted in January
        2004 and was swabbing oil at 17 barrels per hour at a 35% water cut after
        the workover. Year-end 2003 proved undeveloped reserves were assigned
        to this well based on an initial rate of 75 bopd for the proved case and
        100 bopd for the proved plus probable case and an assumed decline rate
        influenced by the historical production performance prior to being recompleted.

    Year-end 2004 reserves were assigned by decline analysis
        using the pre-recompletion and post-recompletion stabilized average daily
        oil rate performance. The 00/15-26-53-26W4/2 well is part of the Wabamun
        D-1D pool. The estimated original oil in place for this pool based on
        a reservoir simulation study by Epic Consulting Services is 12,095 Mbbl.
        Cumulative production from the pool as of December 31, 2004 is 1,288.3
        Mbbl., which equates to a recovery factor of 10.5 percent.

    St. Albert 02/03-01-54-26W4/3

    The 02/03-01-54-26W4/3 well was assigned proved undeveloped
        reserves in the 2003 year-end report based on pool volumetrics for the
        Nisku D-2B pool and the relative oil production rate expected for the
        well versus other wells in the pool. Proved and probable oil reserves
        in the Nisku D-2B pool were estimated by volumetric methods using the
        net oil pay isopach map for the pool. A proved recovery factor of 50%
        was used and the resulting oil reserves were allocated to the wells 03/10-36-53-26W4,
        02/03-01-54-25W4/3, and the location 05/03-01-54-26W4 based on estimated
        capture by each well. Proved plus probable reserves for the pool were
        estimated using a 65% recovery factor.

    The 02/03-01-54-26W4/3 well came on production in
        February 2004 at 300 bfpd but the water cut quickly increased to 99%.
        The well was shut-in during October 2004 due to high water cut. No reserves
        were assigned to this well in the year-end 2004 report.

    SEC comment:

    2.
    Regarding response number 2, the rules for 20-F filers
        require the calculation of proved reserves under Rule 4-10(a) of Regulation
        S-X. Our rules also will allow the disclosure of probable reserves where
        the home jurisdiction has a law requiring the disclosure of probable reserves.
        However, this does not alleviate the necessity to calculate proved reserves
        under

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    Rule 4-10(a) of Regulation S-X. As previously requested,
        please revise your document to reconcile the reported reserves with those
        calculated under Rule 4-10(a) of Regulation S-X.

    Management’s response:

    The following response has been provided by Dynamic’s
        independent evaluation engineers, Sproule Associates Limited of Calgary,
        Alberta, and reviewed by Dynamic’s management.

    In our opinion the 2004 year-end reserves report
        was prepared in accordance with standards set out in the Canadian Oil
        and Gas Evaluation Handbook (COGE Handbook). We have reviewed the proved
        reserve assignment for the entities included in the year-end 2004 report
        to determine if modifications to the proved reserves are necessitated
        to reflect the definitions and standards under the U.S. Financial Accounting
        Standards Board policies (FASB standards). Our assessment is that the
        proved reserves assigned as of December 31, 2004 (using available engineering
        and geological data as of December 31, 2004) in the 2004 year-end report
        using Constant Prices and Costs, and using Canadian NI 51-101 regulations,
        will meet the SEC proved reserve definition listed in rule 4-10(a) of
        Regulation S-X.

    We have reviewed the proved reserves assigned in
        the year-end 2004 report using decline analysis and analogy techniques
        (74% of the assigned reserves). We believe