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. |
| 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 that the proved reserves assigned to each entity meet the SEC definition that they are the estimated quantities of crude oil, natural gas and natural gas liquids which engineering and geological data indicate with reasonable certainty to be recovered in future years. | |
| We have also reviewed the reserves assigned by volumetric techniques in the report and no adjustment to the proved reserves assigned in our report is required to meet the SEC proved reserve definition which requires that hydrocarbon in-place values be based on only the measured depth to which hydrocarbons have been proven to exist on logs/cores. All of the entities that were assigned reserves using volumetrics had net pay values which represent the actual observed oil/water contact from drilling into the water leg (in the St. Albert Nisku and Leduc pools) or there was no underlying water which was substantiated by drilling through the entire porous interval into the underlying formation (e.g. Mantario East). | |
| We have not provided a reconciliation table comparing reserves estimated using NI 51-101 regulations to those that would be assigned using SEC definitions as we believe that the proved reserves assigned using constant prices and costs in our report meet the SEC proved reserve definition. | |
| Sincerely, | |
| Dynamic Oil & Gas, Inc. | |
| Per: | “Michael A. Bardell” |
| Michael A. Bardell | |
| Chief Financial Officer | |
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