POULTON & YORDAN
ATTORNEYS AT LAW
RICHARD T. LUDLOW
January 31, 2006
H. Roger Schwall
Assistant Director
Division of Corporate Finance
Mail Stop 7010
United States Securities and Exchange Commission
Washington, D.C. 20549
Re: BMB Munai, Inc.
Registration Statement on Form SB-2
Filed October 21, 2005
File No.: 333-129199
Form 10-KSB/A for the year ended March 31, 2004
Filed October 5, 2005
File No. 000-28638
Dear Mr. Schwall:
At the request of the management of BMB Munai, Inc., (the "Company" or
"BMB Munai") and further to my conversations with Mr. Murphy and Ms.
Moncada-Terry we are responding to comments raised by the staff at the Securities
and Exchange Commission in your letters dated November 23, 2005 and November 30,
2005. Following are the responses to your comments.
LETTER OF NOVEMBER 23, 2005
Selling Security Holders, page 14
- ---------------------------------
1. Disclose how the securities being registered for resale were acquired
by the selling security holders.
The securities being registered for resale were acquired by the selling
security holders directly from the Company in either the private placement of
shares concluded by the Company in July 2004 or March 2005, pursuant to
exemption 4(2) of the Securities Act and/or Regulation S.
POULTON & YORDAN TELEPHONE: 801-355-1341
324 SOUTH 400 WEST, SUITE 250 FAX: 801-355-2990
SALT LAKE CITY, UTAH 84101 POST@POULTON-YORDAN.COM
Mr. Roger Schwall
January 31, 2006
Page 2
If the staff deems it necessary, the Company will add disclosure of
this information to the amended SB-2 registration statement.
2. Identify as underwriters all selling security holders who are
registered broker-dealers, unless you can confirm to us that such
selling security holders received their shares as compensation for
investment banking services.
Each selling security holder has confirmed that it is not a registered
broker-dealer.
Form 10-KSB/A for the year ended March 31, 2004
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Controls and Procedures, page 30
- --------------------------------
1. We note that, in addition to your disclosure that the disclosure
controls and procedures were not effective as of the end of the
reporting period covered by the amended report, you include disclosure
indicating that "your disclosure controls and procedures are now
effective." Revise to expand the disclosure to explain how management
has determined that disclosure controls and procedures are now
effective. Make similar revisions to your Form 10-QSB/A for the quarter
ended December 31, 2004.
We propose to amend the disclosure controls and procedures as follows
to explain how management has determined that disclosure controls and procedures
are now effective.
"Our chief executive officer and our chief financial officer (the
"Certifying Officers") are responsible for establishing and maintaining
disclosure controls and procedures (as defined in Exchange Act Rule
13a-15 and Rule 15d-15(e)). Such officers have concluded (based upon
their evaluations of these controls and procedures, as more fully
discussed in the following paragraphs, as of the end of the period
covered by this amended report) that our disclosure controls and
procedures are effective as of the date this amended report is filed to
ensure that information required to be disclosed by us in this report
is accumulated and communicated to management, including the Certifying
Officers as appropriate, to allow timely decisions regarding required
disclosure. During the period from the time the original report was
filed to the time we filed this amended report, we have developed
certain internal financial reporting policies and procedures such as
thorough review for compliance with requirements by completing
appropriate checklists, which to the best of our knowledge and
Mr. Roger Schwall
January 31, 2006
Page 3
understanding proved to be effective as of filing of this amended
report thus, making us, as the management, believe that disclosure
controls and procedures are effective as well."
LETTER OF NOVEMBER 30, 2005
SB-2 filed on October 21, 2005
Summary Historical Reserve and Operating Data, page 4
- -----------------------------------------------------
1. Please remove the dollar signs under the production information for
each period shown here and on page 33.
We will remove all dollar signs.
Risk Factors, page 5
A substantial or extended decline in oil and natural gas prices..page 6
-----------------------------------------------------------------------
2. Please include in this risk factor the fact that you currently receive
materially lower prices than world market prices for crude oil and your
gas price is substantially lower than that received in North America.
We propose to add the following language to the above referenced risk
factor (page 6) to the beginning of the paragraph immediately following the
second set of bullet point items:
"Until we are granted an export license from the government,
we are limited to selling our production to the domestic market in
Kazakhstan. As a result, we currently receive materially lower prices
than the world market prices for our crude oil. Similarly, the prices
we will receive for the gas we produce will be substantially lower than
prices for natural gas received in North America."
3. Please include a risk factor that states under the terms of your
current exploration contract you only have the right to produce until
the year 2007 and that 94% of your proved reserves are scheduled to be
produced after 2007. There is no guarantee whether the current license
will be extended or a new commercial exploration and production
contract will be granted.
We propose to add the following risk factor to the top of page 8:
We will be unable to produce up to 94% of our proved reserves
if we are not able to extend our current contract or obtain a new
Mr. Roger Schwall
January 31, 2006
Page 4
contract from the Republic of Kazakhstan, which would likely require us
to terminate our operations.
Under our current contract for exploration of hydrocarbons on
Aksaz, Dolinnoe and Emir fields, we have the right to produce oil and
gas only until July 2007, yet 94% of our proved reserves are scheduled
to be produced after July 2007. If we are unable to receive a
commercial production contract to which we have the exclusive right to
negotiate as per exploration contract terms, or extend our current
contract we will lose our right to produce the reserves on our current
properties. If we are unable to produce those reserves, we will be
unable to realize revenues and earnings and to fund operations and we
would most likely be unable to continue as a going concern.
Business and Properties, page 28
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Oil and Natural Gas Reserves, page 30
-------------------------------------
4. You state that Chapman Engineering used oil and natural gas prices in
effect during March 31, 2005, which you disclosed was $15.17 for the
year ended March 31, 2005. However, the reserve report uses an oil
price of approximately $21.00 per barrel, which is 38% higher than the
price you disclose in the filing. Please explain this to us.
As dictated by Section 210.4-10(a)(2), the reserve report uses an oil
price of $21.00 per barrel because that was the price per barrel of oil in the
Kazakhstan domestic oil market on March 31, 2005, the date of the reserve
report. By contrast, $15.17 reflects the average price per barrel we received
throughout the fiscal year for the oil we sold. As you point out, the price of
oil in the Kazakhstan domestic market increased significantly during the period
from March 31, 2004 to March 31, 2005, not unlike the significant increases
experienced in the world market during the same time period. As a result of the
significant price increase during the aforementioned period, the average oil
price we realized during the period from March 31, 2004 to March 31, 2005, was
lower than the price at March 31, 2005.
Production, page 31
-------------------
5. You state that you produced no natural gas during the month of August
2005, however, you disclose 41.7 BCF of proved gas reserves. Please
explain this to us.
Please see our response to comment 14 below.
Mr. Roger Schwall
January 31, 2006
Page 5
Recent Developments, page 34
----------------------------
6. You indicate that you have tested several wells such as the Dolinnoe 2
and Emir 1 wells in June 2005. Please disclose the results of this
testing and if you think it is representative of the wells' long-term
production trends. Along bring this production up to date as possible.
According to the State laws of the Republic of Kazakhstan, the Company
is required to test every prospective object on its properties separately, this
includes the completion of well surveys on different modes with various choke
sizes on each horizon. This testing can take up to three months per horizon.
In the course of well testing, when the transfer from object to object
occurs, the well must be shut in, the production activity closes for the period
of mobilization/ demobilization of workover rig, pull out of hole, run in hole,
perforation, packer installation time, etc. Oil production is temporarily
suspended due to well shut down which has the effect of artificially diminishing
production rates.
Production rates:
Cumulative total production rate from all intervals tested is shown on
the table following the response to this comment.
Aksaz -1
Status: The well is awaiting workover due to technical conditions.
Producing testing intervals: 4,428-4,253m; 4,256-4,257m; 4,261-4,265m;
4,269-4,273m
Prior to workover the single interval production rates were as follows:
139 bpd - 10 mm diameter choke. This production level was registered
with paraffin buildup. 252 bpd - 10 mm diameter choke. This production
level was registered without paraffin buildup.
Aksaz-4
Status: The well was completed in August 2005.
Producing testing intervals: 4,311-4,299m and 4,294.3-4,292.8m
Mr. Roger Schwall
January 31, 2006
Page 6
Current production rates from single interval testing are as follows:
126 bpd - 6 mm diameter choke with paraffin buildup
220 bpd - 6 mm diameter choke without paraffin buildup
Dolinnoe-1
Status: Engaged in test production. The Company plans to increase
production from the Dolinnoe-1 well through hydraulic fracturing with
acid treatment and, if necessary, horizontal or deviated drilling from
existing wellbores will be conducted.
Producing testing intervals: 3,550-3,565m and 3,521-3,532m
Current single interval production rates are as follows:
114 bpd - 6 mm diameter choke with paraffin buildup
189 bpd - 6 mm diameter choke without paraffin buildup
Dolinnoe-2
Status: Engaged in test production. The Company plans to increase
production from the Dolinnoe-2 well through hydraulic fracturing with
acid treatment and, if necessary, horizontal or deviated drilling from
existing wellbores will be conducted.
Producing testing intervals: 3,574.5-3,577m, 3,578.4-3,582m,
3,600-3,609m; 3,611.5-3,613.5m; 3,616-3,627m; 3,640-3,641m
Current single interval production rates are as follows:
126 bpd - 4 mm diameter choke with paraffin buildup
Dolinnoe-3
Status: While testing various intervals, we determined that the current
interval from which solid production rates occurred is 24 m, but only
17 m were perforated. After perforation of the 17m a blowout occurred
and we could not run in hole with the pipe. We are in the process of
killing the well. After killing the well we will clean the bottomhole
zone, run in hole with a perforator and will perforate the remaining 7
m in the producing interval. After perforation we will lower tubing and
start testing again in order to determine the proper rate.
Mr. Roger Schwall
January 31, 2006
Page 7
Producing testing intervals: 3,614.5-3,603m and 3,600.6-3,594.5m
Current single interval production rates are as follows:
756 bpd - 4 mm diameter choke with paraffin buildup
1260 bpd - 8 mm diameter choke with paraffin buildup
Emir -1
Based on logging, 4 prospective objects were identified and perforated
and all 4 objects were tested. This well is awaiting a service rig to
perform workover as discussed in our response to comment 17 below.
Producing testing intervals: 2,863-2,871m; 2,922-2,924m; 2,930-2,975m;
3,009-3,017m
Current single interval production rate is 40-50 bpd.
With current completions, which include only one zone per well, the
overall daily production rate range from the 6 wells is 1,266 to 2,100 bpd,
depending on choke sizes and well bore conditions on the wells, etc. This, of
course, is not representative of the cumulative total production rate from all
of the tested intervals in each of the wells. The accumulated total for the
tests on these wells are shown below:
- ----------------------------------------------------------------------------------------------------------------
Choke size,
Well Interval, m Influx Mm Oil, bpd Average
- ----------------------------------------------------------------------------------------------------------------
6 184
Aksaz 1 4249-4307 Oil and gas flow 8 250 245
10 300
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Total 245
- ----------------------------------------------------------------------------------------------------------------
4296-4293, 4 107
4272-4266, Oil and gas flow 6 126 151
Aksaz 4 4261-4257 8 220
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4304.9-4311, 4 76
4299-4305.1, Oil and gas flow 6 113.4 105
4298.8-4294.3 (high water) 8 126
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Total 256
- ----------------------------------------------------------------------------------------------------------------
3521 - 3532 Production 5/04 to 3/05 172 172
Dolinnoe 1 3550 -3570 Production 4/05 133 133
3631 - 3647 Production 5/05 146 146
-----------------------------------------------------------------------------------------------
Total 451
- ----------------------------------------------------------------------------------------------------------------
3574.5-3577;
3578.4-3582; 6 83
3592 - 3597.4;
Dolinnoe 2 3600-3609; Oil and gas flow 8 100 97
- ----------------------------------------------------------------------------------------------------------------
Mr. Roger Schwall
January 31, 2006
Page 8
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3611.5-3613.5;
3616-3627;
3628-3635.5;
3640.6-3641.7 10 107
-----------------------------------------------------------------------------------------------
6 239
3510.5-3512; Oil and gas flow 8 252 243
3513-3522 10 239
-----------------------------------------------------------------------------------------------
Total 340
- ----------------------------------------------------------------------------------------------------------------
6 84
3665.5-3682 Oil and gas flow 8 132 117
10 135
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6 299
Dolinnoe 3 3639.7-3658.3; Oil and gas flow 8 303 303
3660-3663.6 10 306
-----------------------------------------------------------------------------------------------
6 1,415
3594.5-3600.6; 8 1,604
3603-3614.5 Oil and gas flow 10 1,667 1,580
12 1,635
-----------------------------------------------------------------------------------------------
Total 2,000
- ----------------------------------------------------------------------------------------------------------------
Emir 1 2933 - 2977 Production 7/05 (ave) 100 100
-----------------------------------------------------------------------------------------------
Total 100
- ----------------------------------------------------------------------------------------------------------------
The total capacity, based on cumulative test data for each well to
date, is approximately 3,147 bpd.
Please note that all the tests and production rates for these wells are
for production that is flowing from greater than 10,000 feet against a choked
wellhead, prior to any stimulation. Because of the high reservoir pressure it
has not been necessary to introduce artificial lift in any of the ADE Block
fields, however, conventional stimulation techniques to improve production rates
are being considered.
Chapman Petroleum Engineering Ltd has performed an Inflow Performance
Relationship study to examine the maximum flow rates implied by the existing
test data, assuming the wells were completely optimized with pumping equipment
from the sand face up. Again this analysis would reflect pre-stimulation rates.
The results indicate absolute maximum rates for the total of these wells
including all combined zones of 8,814 STB/d. These rates, of course, are not
realistically achievable, but the study demonstrates meaningful rate improvement
potential with the implementation of conventional equipment.
The results of the study are tabulated on Appendix 1, attached hereto.
The Company proposes to incorporate much of the above information into
the amended SB-2 filing under the sub-heading "Production" on page 32 to provide
Mr. Roger Schwall
January 31, 2006
Page 9
additional disclosure about the results of testing and whether the Company
believes these results are representative of the wells' long-term production
trends.
Our Properties, page 36
-----------------------
7. You disclose that you own a 100% interest in a production license and
the current royalty rate is 2%. You further disclose that when a
commercial license is negotiated royalty rates can range from 2% to 6%.
This would appear to give you a 94 to 98% net interest. However, we are
not aware of any production contracts that are so beneficial to the
grantee of the license. Disclose whether at any time the government has
an option to participate or increase their net interest in the subject
reserves. Provide us a copy of this contract or revise your document to
make any corrections necessary in this disclosure. We may have further
comment.
We own a 100% interest in an exploration license and the current
royalty rate is 2%.
In accordance with the Kazakhstani fiscal regime, royalty rates vary
from 2% to 6% depending on annual production volume. (Please see the following
royalty rate scale).
The amount of government participation in our revenues is stipulated by
our contract. The government is obligated to follow the contract terms and
cannot increase its share of participation without changing appropriate
legislation.
In addition to the royalty explained above, under the tax regime, the
government collects corporate income tax of 30%. The government also collects an
excess profits tax, which is applied after a number of deductions, and can be as
high as 60% of the profits in excess of a prescribed rate of return for the
Company.
Under this regime the Republic of Kazakhstan derives a share of
production, which is comparable to many production sharing agreements around the
world. The calculation of these taxes is presented in the Chapman Report. Also,
a summary of the royalty provisions and applicable rates follows:
- ------------------------------------------------------------------------------------------------------------------------
Royalty Exploration Production Rates
- ------------------------------------------------------------------------------------------------------------------------
Royalties shall be paid by a Royalty rates for hydrocarbons shall be
user of mineral resources established on a sliding scale as a percentage,
separately for each type of determined in accordance with the extraction
minerals extracted on the X X volume, for each year of activity, based on one of
territory of the Republic of the following rates:
Kazakhstan, regardless of
whether they are sold Up to 500,000 tons - 2 percents;
(shipped) to buyers or used 500,000 tons to 1,000,000 tons - 2.5%
- ------------------------------------------------------------------------------------------------------------------------
Mr. Roger Schwall
January 31, 2006
Page 10
- ------------------------------------------------------------------------------------------------------------------------
for ones own needs. 1,000,000 tons to 1,500,000 tons - 3%
1,500,000 tons to 2,000,000 tons - 3.5%
2,000,000 tons to 2,500,000 tons - 4%
2,500,000 tons to 3,500,000 tons - 4.5%
3,500,000 tons to 4,500,000 tons - 5 %
4,500,000 tons to 5,000,000 tons - 5.5%
More than 5,000,000 tons - 6%
- ------------------------------------------------------------------------------------------------------------------------
8. Please revise your filing to give the results of the well work you
disclose such as the re-entering well in the Aksaz, Emir and Dolinnoe
fields and the two new wells drilled in the Dolinnoe field.
Please see our response to comment 6 above. We propose to incorporate
this information into the amended SB-2 filing.
9. Tell us if you are the operator of all of your oil and gas properties.
The Company is the operator of all of its oil and gas properties.
Title to Properties, page 39
----------------------------
10. You state that you believe you have satisfactory title to all our
properties. As we understand you have an interest in a license to use
subsurface mineral resources and a hydrocarbon exploration contract.
However, this does not imply you have title or ownership in any
reserves but only a contractual right to explore and produce. Please
clarify your document as necessary.
We propose to revise the "Title to Properties" disclosure as follows:
Title to Properties
We hold an exploration contract from the Republic of
Kazakhstan that grants us the right for exploration and test production
of hydrocarbons on the ADE Block and the Extended Territory. Our rights
to these properties will terminate in June 2007 unless we are able to
negotiate an extension of our current exploration contract or we are
granted a commercial production contract.
Results of Operations, page 42
- ------------------------------
Costs and Operating Expense, page 44
------------------------------------
11. You state that you incurred $206,929 in "selling expenses" during the
fiscal year ended March 31, 2005 but these costs were not included as
operating costs. Please explain to us what this is.
Mr. Roger Schwall
January 31, 2006
Page 11
We did not exclude "selling expenses" from operating costs. Selling
expenses are included in the loss from operations as disclosed in the
Consolidated Statements of Loss. If, however, the staff feels the current
presentation is confusing, we would propose to revise this disclosure
prospectively to present a single line item for "oil and gas operating expenses"
that discloses all oil and gas operating expenses in a single line item,
including selling expenses. The selling expenses were primarily transportation
costs.
Revenue and Production, page 46
-------------------------------
12. As you produced 41,456 barrels of oil for the three months ended June
30, 2005 and derived revenues of $662,637 in the same period it would
appear that your average oil price was $15.98 per barrel and not $17.98
as you disclose. Also for the three months ended June 30, 2004 it
appears the average oil price should be $10.43 per barrel. Please
revise your document or explain to us why it is not necessary.
During the three months ended June 30, 2005 we produced 41,456 barrels
of oil but only sold 36,854 barrels. The remaining barrels were placed into
storage at our oil storage facility. Average oil price was calculated based the
number of barrels sold, not the number of barrels produced. In other words,
during the period we produced 41,456 we sold 36,854 barrels and realized revenue
of $662,637, which equates to average price of $17.98 per barrel and retained in
storage 4,602 barrel in storage.
The same situation occurred during the three months ended June 30,
2004, when we produced 11,405 barrels of oil but sold only 8,995 barrels of oil.
The difference was placed in storage.
We propose to amend the SB-2 filing to provide a footnote to "Average
Sales Price" to disclose that the Company may, at times, produce more barrels
than it sells in a given period. The average sales price is calculated based on
the average sales price per unit sold, not per unit produced.
Notes to the Consolidated Financial Statements, page F-7
- --------------------------------------------------------
Long Term Liabilities, page F-16
--------------------------------
13. Tell us who PGS Reservoir Consultants are and the services they provide
to you.
PGS Reservoir Consultants, a division of Petro Geo-Services ASA, is an
independent service engineering company retained by the Company to interpret and
analyze 2D Soviet seismic data of the ADE Block.
Mr. Roger Schwall
January 31, 2006
Page 12
Supplementary Financial Information on Oil and Natural Gas Exploration
Development and Production Activities (unaudited), page F-23
- ----------------------------------------------------------------------
14. Tell us why if you had 41.7 BCF of proved developed gas reserves, you
had no gas production during FY 2005. Unless you can show evidence of
long term gas contracts or a robust spot market we do not believe the
gas reserves can be classified as proved. Tell us the source of the
$0.50 per Mcf gas price used by the consultant in his report.
Gas reserves in the amount of 41.7 Bcf represents solution gas being
produced with the oil. The gas is being measured with production in the case of
the producing wells and is currently being flared. The gas reserves have not
been assigned to the producing category, because the fields are not currently
tied-in to the gas pipeline and currently gas is not being sold. Gas is shown in
the developed non-producing category and the undeveloped category depending on
the category of oil to which they relate.
The Company has been approached by a third party company with a
proposal to install and jointly own gas processing facilities and to tie-in to
the gas pipeline. The Company is currently performing due diligence with regard
to the technology and the third party. The Company has also received
correspondence from the local energy authority in Aktau, Kazakhstan, (the
nearest city to the Company's fields) requesting that it tie its gas into the
pipeline because of the need for gas in Aktau. The Company expects to tie the
fields in with the gas pipeline and to be selling gas to the local market by the
end of the 2006 calendar year.
The Company believes that its presentation of these reserves as proved
(proved developed non-producing and proved undeveloped) is appropriate. Based on
your comments, however, that gas cannot be considered proved until there is a
contract in place for the sale of the gas, we agree to a reclassification of the
41.7 Bcf gas reserves from proven to probable in the Reserve Report of Chapman
Petroleum and propose to make appropriate revisions in the amendment to the
SB-2.
15. It appears from your oil production during FY 2005 it will take 198
years to produce just your developed oil reserves and 33 years to
produce the proved producing reserves assuming oil production does not
change. As all production will decline over time explain to us how this
amount of developed reserves meets the requirements of reasonable
certainty to be produced under Rule 4-10(a) of Regulation S-X.
While you are correct that based on our production during fiscal 2005
it would take 198 years to produce our develop oil reserves, that overlooks the
fact that most of our developed reserves were still shut in at the time of our
report. The proved developed reserves value of 13,614 MSTB would correspond to
Mr. Roger Schwall
January 31, 2006
Page 13
an initial rate of about 1,950 STB/d at predicted initial rates for the total
proved developed wells, once they are placed on production. This amounts to a
reserve life index of 19 years. Of course, with declines the real life will be
longer.
We agree with your calculated life of 33 years for the proved producing
from the reserve value of 3,702 MSTB and a current rate of about 300 STB/d.
Please note that at the time of the report, the Dolinnoe 2 & 3 wells
were not on production and the Emir 1 well was shut in, but all of these wells
were classed as proved developed because they had already been drilled and were
being tested. We estimated initial rates of about 500 STB/d per well for the
Dolinnoe 2 & 3 wells, based on the cumulative tests for Dolinnoe 1. Dolinnoe 1
has never been on production from more than one individual interval, during
2005, but totaling rates from all the intervals tested results in greater than
500 STB/d.
These reserves qualify as proved reserves under Rule 4-10(a) of
Regulation S-X on the basis that only zones in existing wells that have been
tested or placed on production have been assigned reserves. Reserves have been
established based on volumetric analysis, utilizing digital computerized log
analysis and reasonable drainage areas and recovery factors. Zones that have
been tested in one of the wells and correlate to the other wells, but that have
not been tested in the other wells, have been considered tested in the
accumulation. These wells are directly adjacent to each other.
16. There are several material differences between the undiscounted and
discounted before and after tax cash flow numbers in the reserve report
compared to the SMOG numbers in the filing. Please explain.
We have reviewed the SMOG numbers in the filing against the numbers in
the reserve report and cannot identify any material discrepancies. Would you
please provide us additional details as to which numbers you are referring?
Reserve Report as of April 1, 2005
17. We note for the proved developed consolidation of the 5 wells on the
ADE Block you have assumed production will increase from 874.4 barrels
of oil per day to 1,887.5 barrels of oil per day. Tell us what the
current production from these wells are and the basis of assuming
production from the existing wells will more than double in 2006.
The report assumes the non-producing Dolinnoe 2 & 3 wells would
commence production by September 2005 at 500 STB/d each, as discussed above. We
also expected a work-over of the Emir 1 well to result in 300 STB/d. This
Mr. Roger Schwall
January 31, 2006
Page 14
resulted in the average production on the cash flow analysis, over the period
from April to December 2005, to be 874 STB/d. In 2006 it was assumed that
Dolinnoe 1 would be reconfigured to allow all zones to produce at once at a
total rate of 500 STB/d, bringing the total yearly average to about 1,887.5
STB/d.
As disclosed in our response to comment 6, Emir 1 is currently
producing less than our expectation. However, as we also disclosed in our
response to comment 6, after the report date, the Dolinnoe 3 well, alone tested
at cumulative rates from all zones of about between 1,500-1,625 STB/d depending
on choke size. We are confident that production rates at Emir-1 can be increased
and we plan to carry out additional activities, such as hydrofracturing and acid
treatment, to increase production at that well.
For information regarding the production rates of each of our wells,
please refer to our response to comment 6.
18. You have estimated each of these proved developed wells to have proved
reserves of over 2.7 million barrels per well. Tell us how you arrived
at this estimate and why it meets the requirements of reasonable
certainty under Rule 4-10(a) of Regulation S-X.
As was stated in response to comment 15 above, the reserves qualify as
proved reserves under Rule 4-10(a) of Regulation S-X on the basis that only
zones in existing wells that have been tested or placed on production have been
assigned reserves. Reserves have been established based on volumetric analysis,
utilizing digital computerized log analysis and reasonable drainage areas and
recovery factors. Zones that have been tested in one of the wells and correlate
to the other wells, but that have not been tested in the other wells, have been
considered tested in the accumulation. These wells are directly adjacent to each
other.
There are also Triassic intervals in some wells which were identified
as pay by log analysis, but which were not assigned reserves due to a lack of
testing.
Additionally, there are significant hydrocarbons indicated by log
analysis and drilling shows in the Jurassic formation, higher up hole in all
these wells, that have had no reserves assigned because the Jurassic has not
been sufficiently investigated by testing, to date and therefore do not qualify.
The establishment of reserves in the Jurassic in this Block would have a
significant impact.
19. We note that the decline rate of the Aksaz 1, 4 and the two proved
undeveloped wells are estimated to be 2.0% per year. Tell us how you
arrived at this estimated decline rate. We also note a very modest rise
in the GOR over time for these wells. Tell us how you estimated this.
Mr. Roger Schwall
January 31, 2006
Page 15
The low decline rates result from the combination of the initial rates
scheduled in the report compared to the reserves assigned to the properties. The
reserves are well substantiated and it would not seem to be appropriate to
arbitrarily reduce the reserves to accommodate a production schedule that is not
yet fully implemented. At fully optimized rates (see Q6.) the declines and
depletion times would be much more as expected. Even though there is technical
evidence suggesting these wells are capable of higher rates, the rates used in
the report were restricted to those that have actually been achieved (at the
time of the report), as a means of maintaining a conservative approach.
The GORs were not meant to increase. We expected that the gas will be
tied-in during 2006, so it gives the appearance on the cash flows that the GOR
increases in 2007.
20. Tell us the reason you make capital investments of $2 million in the
2005 and $3,500 million in 2006 for the proved developed reserves in
the ADE Block.
The reserves were classified as developed because they were drilled,
and in some cases on production. However, there was still some capital required
for completion and testing for the two non-producing wells. We also included
capital for a gas gathering system and well site facilities.
21. You cannot reduce the fixed costs after five years based only on an
assumption that operations will "reach stability" by then. If costs are
fixed, then it cannot be assumed that they will be materially lower at
some point in the future. We are not clear on how fixed costs could
change so dramatically but if these costs actually are materially
reduced at sometime in the future, then at that time you may use lower
costs in the reserve estimates. Until then please revise your estimate
based on current fixed costs being held constant as required by Rule
4-10(a) of Regulation S-X.
Chapman Petroleum has rerun the economic analysis, as requested,
implementing current operating costs held constant throughout.
In preparing the initial evaluation there was very little operating
cost history on this property. In the absence of confirmed costs, to be
conservative, Chapman Petroleum arbitrarily included an annual cost to account
for unforeseen circumstances during the development stage of the property. After
a few years these arbitrary costs were reduced. We have been advised that this
reduction is not appropriate under SEC regulations and we acknowledge this.
To be fair, we have undertaken to reestablish the appropriate operating
costs for the property, from more extensive data now available. In the
Mr. Roger Schwall
January 31, 2006
Page 16
reassessment Chapman Petroleum has used variable costs of $2.00/STB and
$8,000/well per month, which is supported by public reporting by the Company.
The results of Chapman Petroleum's reevaluation are presented in
Appendix 2 to this Letter.
22. It is not appropriate to not attribute some general administration
costs to the field operations. Please revise your estimate to
incorporate these into your reserve estimate.
Chapman Petroleum has incorporated a G&A allocation $200,000 per month,
reflecting the cost of the Company's Emir office, to its reevaluation. This cost
was projected for the life of the project and the values are presented
separately on the Summary of Results on the Total Proved level.
23. Provide us with the oil gravity and the reasons 80 and 160 acres and
30% are reasonably certain for the drainage area and the recovery
factor for these wells. We do not feel that only anecdotal evidence
about recovery efficiency is sufficient for proved reserves. Tell us
the reservoir drive mechanism you assumed and the bubble point pressure
of each of the reservoirs. Tell us the reason for assuming the gas-oil
ratio will remain relatively stable over the productive life of the
reservoir.
The API gravity of the Emir and Dolinnoe oil is 41 degrees. The oil at
Aksaz is greater than 50 degrees API and is practically condensate.
A recovery factor of 30% has been assigned, based on input to Chapman
Petroleum from various sources, including the Company's staff, other consultants
who are familiar with the reservoirs in the basin and information from
surrounding fields. The nearest similar fields, Alatobe and North Akkar have
recognized recovery factors of 38% and 30%, respectively. These factors were
established and are supported by prolonged production from these fields.
Although it is too early to confirm the depletion mechanism in the ADE
fields, there is a high likelihood that these are water drive reservoirs. A
review of the geological reference book for RoK reveals that most Triassic
reservoirs in western Kazakhstan are influenced by water drive mechanisms. This
is true for many other reservoir types, also. These Triassic reservoirs are
located on a drape and do not have water contacts in the structurally high
wells. Rather the water legs are located down structure, surrounding the oil
accumulation providing pressure support without the risk of premature coning or
encroachment.
To confirm the recovery factor assignment Chapman Petroleum has
prepared an analysis with material balance equations based on fluid properties
and reservoir parameters, for Emir and Dolinnoe. The results of this analysis
Mr. Roger Schwall
January 31, 2006
Page 17
indicates recovery factors approaching 30% even under solution gas drive with no
water drive influence. Influence from even partial water drive would improve on
these indications. The same recovery has been assigned to Aksaz.
The technical analysis and summary of the procedure are contained in an
Appendix 3 to this response. The basic reservoir and fluid parameters are shown
below:
Emir : Initial Pressure - 5878 psi., Bubble Point Pressure - 3000 psi.,
Solution gas-oil-ratio - 673 scf/STB, Formation Volume Factor - 1.35 RB/STB
Dolinnoe : Initial Pressure - 7445 psi., Bubble Point Pressure - 4000
psi., Solution gas-oil-ratio - 1280 scf/STB, Formation Volume Factor - 1.78
RB/STB
This analysis does include the gradual increase of GOR with eventual
recovery of about 85% of the solution gas for each pool. In the economic
evalution the GOR was held at the current level, strictly to be conservative.
The reservoirs are between 30% and 40% over-pressured. The reservoirs
are of good quality and there does not appear to be a threat of premature water
encroachment, as no oil water contact can be seen in any of the wells in any
zone. A drainage area of 160 acres is supported by the "State Balance of Oil
Reserves of the Republic of Kazakhstan", which generally uses a 500 meter
drainage radius (194 acres) as a minimum in this basin. Reservoir
characteristics of the Dolinnoe oil field allow for a 1 km drainage area.
Alternatively, based on the same reserves, we could have assumed that
infill wells would be drilled to reduce drainage areas of individual wells. This
would require additional capital, but would result in higher rates and
acceleration of the reserves assigned, undoubtedly increasing the NPV of the
property. At this early stage of the development we have made the assumption of
a 160 acre drainage per well, which considering the resulting long life of the
reserves, may not be completely realistic, but is by far the most conservative
model to portray future cash flows and NPV from the reserves assigned.
24. Tell us if you have core data and what that information is. Tell us the
permeability values of the reservoirs in each field.
We have core samples from Dolinnoe 1, 2, and 3, Emir 1 and Aksaz 1 & 4.
Permeabilities range from around 5 md to over 400 md. with a mid-range value of
about 100 md. The core samples are in close agreement on water saturation and
generally demonstrate a higher porosity than used in the report for our
reserves, determined from log analysis.
Mr. Roger Schwall
January 31, 2006
Page 18
25. Tell us if you limited proved reserves to lowest and highest known oil
by well penetration.
Reserves in all zones were limited to only the pay zones that were
tested, applied to a single drainage area for each well. The structure is
reasonably flat and no water contacts have been detected in the existing wells
for any zones that have been assigned reserves.
26. Tell us the total life of the proved reserves for each reservoir.
See our response to comment 15 and 19 above.
27. We note the Dolinnoe #1 well has declined at an approximate rate of 40%
per year in 2004 and 2005. Therefore, it appears that your forecasted
rates and decline rate cannot be supported. Please revise the reserves
based on the actual performance to date.
The well was drilled during Soviet times before the Company acquired
the ADE Block. Drilling commenced on June, 1990 and was completed on July 1994.
There were two major down hole failures experienced during drilling. The well
was tested on September 1995. The well bore has 25 degree spiral-formed deviated
shape. The bottomhole area is polluted with formation debris and asphatene
precipitation. In the newer wells, we are discovering paraffin precipitation,
which is restricting production, but which is treatable. Our assumption is that
this is the reason the production rate has been declining. The reservoir
pressure was not measured since the gauge could not enter the wellbore. We think
that the rate decline is occurring due to technical conditions of the well bore.
In our opinion, reservoir energy is not declining at a rate of 40% per year.
Also, it must be remembered that the full production life includes production
from different zones, producing individually.
28. For the Emir proved undeveloped wells it is not appropriate to assume
productive rates 3 times higher than the rates actually seen in the
Emir #1 well. Please revise your estimates accordingly.
The Emir 1 well was drilled during Soviet times. When the well was
initially tested there was a near blowout with reported rates of oil and mud of
over 2,381 STB/d. The well was killed with some unknown heavy substance, which
badly damaged the well. The well was re-entered and placed on production at an
initial rate of about 180 STB/d flowing from 10,000 feet on a 4mm choke against
over 700 psi well head pressure. The foreign material that invaded the zone soon
plugged up the perforations and perhaps the immediate well bore and the well was
shut in due to non commercial rates at the time of the latest report. Chapman
Petroleum Engineering Ltd. reclassified the reserves as proved non-producing,
Mr. Roger Schwall
January 31, 2006
Page 19
assuming a workover of the well would be performed. We believe the initial
indicated rates and the surrounding wells' performance suggest the 300 STB/d
rate is reasonable expectation.
29. It is not clear to us why 2 offset PUD Emir wells will have more than 5
times the reserves of the proved developed well. If this is due only to
the initial higher production rates assigned to these wells, then the
reserves should be reduced as the rates are reduced on the comment
above. If there are other reasons for these higher reserves please
indicate them to us or alternatively reduced the reserves.
For the proved undeveloped reserves we utilized exactly the same well
bore parameters as for the Emir 1 well and the conventional 160 acre drainage
used throughout the Block. The drainage area in the Emir 1 well was reduced to
80 acres because of the damage that had occurred during Soviet times to the well
bore when killing the blowout, as discussed above. We would not expect the same
occurrence with the wells to be drilled. The reserves thus were twice as much
per well as the developed well simply due to the area assigned. Therefore,
overall, the undeveloped reserves assigned are four times the developed.
We have confidence in the Emir field, even with the poor performance of
the Emir 1 well. The technical analysis strongly supports the presence of
producible hydrocarbons, especially with comparison to the other wells in this
Block. Emir is productive from the same reservoir, the Triassic, as the Dolinnoe
and Aksaz fields. All three fields are close to each other and are in the same
geological environment. The well log analysis for all three fields demonstrate
very similar characteristics and we believe the success thus far in Dolinnoe and
Aksaz further supports the proved reserves assignment in Emir. Emir is located
in an active area where the Triassic is a common oil producer. Emir wells should
perform as well as any wells in the Block.
30. Tell us if you attribute proved reserves to the Lower Triassic interval
in any of the three fields on the ADE Block. If so, tell us which ones.
Tell us if the Lower Triassic has been production flow tested in any of
the fields. If so, tell us the fields it was tested in and the results.
The Dolinnoe field has been assigned reserves in both the Upper and
Lower Triassic, as we referred to it. Again, only tested or produced zones have
been assigned reserves and the lower Triassic has been thoroughly tested in
Dolinnoe.
We did not assign any reserves to the lower Triassic in Emir and for
Aksaz we did not attempt to differentiate between what might be called upper or
lower. The reserves here were assigned to an interval in the Lower Triassic
based on log analysis and test data.
Mr. Roger Schwall
January 31, 2006
Page 20
The Aksaz 1 and Dolinnoe wells have deposits that we assume belong to
the Lower Triassic, as mentioned above, however, the exact stratification will
be established after further paleontological research. Some of the intervals
identified on logs are now being studied.
The neighboring North-West Zhetybay field and the Oimasha field located
within 150 Km. are also productive from the Lower Triassic.
Thank you for your assistance in this matter. If you have any questions
or require additional information, please contact me directly.
Very truly yours,
POULTON & YORDAN
/s/ Richard T. Ludlow
----------------------------
Richard T. Ludlow
Attorney at Law
Appendix 1
Productivity Analysis
ADE Block, Republic of Kazakhstan
Sand
Tubing Face Product- Maximum
Reservior Gas-oil Head Flowing ivity Product-
Interval Depth Pressure Oil rete -ratio Pressure Pressure Index ivity
Well meters feet psi STB/d scf/STB psi psi - STB/d Comment
- ----------------------------------------------------------------------------------------------------------------------------------
Aksaz # 1 4250 to 4275 13995 7677 166 2358 557 2500 0.0321 246 March 05 Production data
Dolinnoe #1 3521 to 3532 11562 7445 156 1234 762 3275 0.0374 279 March 05 production data
3550 to 3570 11677 7519 133 1923 512 1925 0.0238 179 April 05 production data
3641 to 3647 11936 7686 146 1235 440 2600 0.0287 221 May 05 production data
--------- ---------
435 678
Dolinnoe #2 3510 to 3522 11545 7434 252 564 732 3700 0.0675 502 Test operations
3574 to 3643 11808 7603 100 1457 732 3500 0.0244 185 Test operations
--------- ---------
352 687
Dolinnoe #3 3594 to 3614 11821 7612 1666 600 2007 5587 0.8228 6263 Test operations
3639 to 3663 11975 7711 303 581 - 1106 0.0459 354 Test operations
3665 to 3682 12047 7757 132 957 - 4058 0.0357 277 Test operations
--------- ---------
2101 6894
Emir #1 2933 to 2977 9692 5878 100 373 732 4000 0.0532 313 July 05 production data
--------- ---------
Total Block (four wells) 3154 8818
Appendix 2
Table 1 Constant Prices & Costs
Summary of Company Reserves and Economics
Before Income Tax
April 1, 2005
BMB MUNAI, INC.
ADE Block, Republic of Kazakhstan
Net To Appraised Interest
---------------------------------------------------------------------------------------------------------
Reserves Cumulative Cash Flow (BIT) - M$
------------------------------------------------------------ -------------------------------------------
Light and Medium Oil Sales Gas NGL BOE
MSTB MMscf Mbbls Mbbls Discounted at:
----------------- ------------ ----------- -------------- -------------------------------------------
Description Gross Net Gross Net Gross Net Gross Net Undisc. 5%/year 10%/year 15%/year 20%/year
- -------------------------- ------- ------- ------ ----- ----- ----- ------ ------ -------- ------- -------- -------- --------
Proved Developed Producing
- --------------------------
Aksaz 1,861 1,824 0 0 0 0 1,861 1,824 28,982 12,465 7,652 5,563 4,408
Dolinnoe Field 1,841 1,804 0 0 0 0 1,841 1,804 32,011 20,871 15,181 11,858 9,715
------ ------ ------- ------ --- --- ------- ------- --------- ------- ------- ------- -------
Total Proved Developed
Producing 3,702 3,628 0 0 0 0 3,702 3,628 60,993 33,336 22,832 17,421 14,123
Proved Developed Non-
Producing
- --------------------------
Dolinnoe Field 6,879 6,741 0 0 0 0 6,879 6,741 121,384 66,819 45,409 34,312 27,552
Emir 3,033 2,973 0 0 0 0 3,033 2,973 52,386 25,174 15,755 11,319 8,785
------ ------ ------- ------ --- --- ------- ------- --------- ------- ------- ------- -------
Total Proved Developed Non-
Producing 9,912 9,714 0 0 0 0 9,912 9,714 173,770 91,993 61,165 45,631 36,336
------ ------ ------- ------ --- --- ------- ------- --------- ------- ------- ------- -------
Total Proved Developed 13,614 13,342 0 0 0 0 13,614 13,342 234,763 125,329 83,997 63,052 50,459
Proved Undeveloped
- --------------------------
Aksaz 5,630 5,517 0 0 0 0 5,630 5,517 74,349 22,440 8,275 2,730 47
Dolinnoe Field 2,580 2,528 0 0 0 0 2,580 2,528 38,038 16,947 9,037 5,223 3,074
Emir 12,134 11,891 0 0 0 0 12,134 11,891 209,069 54,593 22,594 11,853 6,833
------ ------ ------- ------ --- --- ------- ------- --------- ------- ------- ------- -------
Total Proved Undeveloped 20,344 19,937 0 0 0 0 20,344 19,937 321,456 93,980 39,906 19,806 9,954
------ ------ ------- ------ --- --- ------- ------- --------- ------- ------- ------- -------
Total Proved 33,958 33,279 0 0 0 0 33,958 33,279 556,219 219,309 123,903 82,857 60,413
Probable
- ---------------------------
Probable Undeveloped
Aksaz 1,877 1,839 19,921 19,522 0 0 5,197 5,093 26,517 8,441 2,424 (82) (1,262)
Dolinnoe Field 20,636 20,224 35,449 34,740 0 0 26,544 26,014 317,515 155,535 86,001 50,821 30,956
Emir 36,447 35,718 46,338 45,411 0 0 44,170 43,287 638,183 211,336 102,296 59,110 37,086
------ ------ ------- ------ --- --- ------- ------- --------- ------- ------- ------- -------
Total Probable Undeveloped 58,960 57,782 101,708 99,673 0 0 75,911 74,394 982,214 375,312 190,721 109,849 66,781
------ ------ ------- ------ --- --- ------- ------- --------- ------- ------- ------- -------
Total Proved Plus Probable 92,918 91,061 101,708 99,673 0 0 109,869 107,674 1,538,434 594,621 14,624 192,706 127,194
Gross reserves are the total of the Company's working and/or royalty interest share before deduction of royalties owned by others.
Net reserves are the total of the Company's working and/or royalty interest share after deducting the amounts attributable to
royalties owned by others.
Columns may not add precisely due to accumulative rounding of values throughout the report. Reserves quoted in BOE calculated using
a conversion of 6 Mscf/bbl (6:1).
Table 1T Constant Prices & Costs
Summary of Company Reserves and Economics
After Income Tax
April 1, 2005
BMB MUNAI, INC.
ADE Block, Republic of Kazakhstan
Net To Appraised Interest
---------------------------------------------------------------------------------------------------------
Reserves Cumulative Cash Flow (BIT) - M$
------------------------------------------------------------ -------------------------------------------
Light and Medium Oil Sales Gas NGL BOE
MSTB MMscf Mbbls Mbbls Discounted at:
----------------- ------------ ----------- -------------- -------------------------------------------
Description Gross Net Gross Net Gross Net Gross Net Undisc. 5%/year 10%/year 15%/year 20%/year
- -------------------------- ------- ------- ------ ----- ----- ----- ------ ------ -------- ------- -------- -------- --------
Proved
- ----------------------------
Total Proved (BIT) 33,958 33,279 0 0 0 0 33,958 33,279 556,219 219,309 123,903 82,857 60,413
Corporate G&A - - - - - - - - (120,000) (44,896) (24,957) (17,142) (13,144)
Corporate Income Tax - - - - - - - - (124,580) (37,431) (20,629) (14,143) (10,432)
Excess Profits Tax - - - - - - - - (137,783) (37,712) (18,846) (11,875) (8,066)
------ ------ ------- ------ --- --- ------- ------- --------- ------- ------- ------- -------
Total Proved After G&A
and Income Tax 33,958 33,279 0 0 0 0 33,958 33,279 173,857 99,270 59,472 39,697 28,771
Probable
- ------------------------------
Total Probable (BIT) 58,960 57,782 101,708 99,673 0 0 75,911 74,394 982,214 375,312 190,721 109,849 66,781
Corporate Income Tax - - - - - - - - (315,440) (91,493) (48,316) (31,806) (22,507)
Excess Profits Tax - - - - - - - - (409,953)(110,007) (54,596) (34,529) (23,642)
------ ------ ------- ------ --- --- ------- ------- --------- ------- ------- ------- -------
Total Probable After
G&A and Income Tax 58,960 57,782 101,708 99,673 0 0 75,911 74,394 256,822 173,811 87,809 43,514 20,633
------ ------ ------- ------ --- --- ------- ------- --------- ------- ------- ------- -------
Total Proved Plus
Probable After G&A
and Income Tax 92,918 91,061 101,708 99,673 0 0 109,869 107,674 430,679 273,081 147,281 83,211 49,404
------ ------ ------- ------ --- --- ------- ------- --------- ------- ------- ------- -------
Gross reserves are the total of the Company's working and/or royalty interest share before deduction of royalties owned by others.
Net reserves are the total of the Company's working and/or royalty interest share after deducting the amounts attributable to
royalties owned by others.
Columns may not add precisely due to accumulative rounding of values throughout the report. Reserves quoted in BOE calculated using
a conversion of 6 Mscf/bbl (6:1).
Table 2
EVALUATION OF: ADE Block, Kazakhstan ERGO v6.00g PETRO-SOFT SYSTEMS LTD. GRAND TOTAL
Total Proved Consolidation GLOBAL : 11-JUL-2005 3864_BMB_C$
EFF DATE: 01-APR-2005
RUN DATE: 13-JAN-2006 TIME: 17:54
FILE:
EVALUATED BY -
COMPANY EVALUATED - BMB MUNAI INC.
APPRAISAL FOR -
PROJECT - CONSTANT PRICES & COSTS
TOTAL CAPITAL COSTS - 34000000 -$-
TOTAL ABANDONMENT - 550000 -$-
Oil
MSTB
-----------------------------------------------------------
Pool Company Share
# of Price ----------------- ------------------
Year Wells $/STB MSTB/d Vol Gross Net
-----------------------------------------------------------
2005 5 21.27 0.9 240 240 236
2006 7 21.39 2.4 807 807 791
2007 11 21.29 4.1 1,072 1,072 1,051
2008 11 21.25 8.4 1,125 1,125 1,102
2009 11 21.25 10.1 1,088 1,088 1,066
2010 11 21.25 9.5 1,050 1,050 1,029
2011 11 21.24 9.1 1,014 1,014 994
2012 11 21.24 8.7 975 975 956
2013 11 21.24 8.3 940 940 921
2014 11 21.24 7.9 906 906 888
2015 11 21.23 7.6 874 874 857
2016 11 21.23 7.3 844 844 827
2017 11 21.23 7.0 815 815 799
2018 11 21.22 6.7 787 787 771
2019 11 21.22 6.4 761 761 745
-----------------------------------------------------------
SUB 13,299 13,299 13,033
REM 20,658 20,658 20,245
TOT 33,954 33,954 33,279
= POOL/TRACT = =================================== COMPANY SHARE REVENUE AND CASH FLOW =============================================
Gross Revenue Royalties Operating Costs Proc
------------------- ------------------- --------------------- & Capi- Cash Flow
Oper Capital Sales Pro- Min- Vari- Net Net Other tal ----------------
Year Costs Costs Oil Gas ducts Total Crown Other eral Fixed able Revenue back Income Costs Undisc. PW 10%
M$ M$ M$ M$ M$ M$ M$ M$ M$ % M$ M$ $/BOE M$ $/BOE M$ M$ M$ M$
- -----------------------------------------------------------------------------------------------------------------------------------
2005 721 3,500 5,114 0 0 5,114 102 0 0 2.0 240 481 3.00 4,291 17.84 0 3,500 791 763
2006 2,239 6,500 17,197 0 0 17,197 344 0 0 2.0 624 1,615 2.77 14,614 18.10 0 6,500 8,114 7,200
2007 3,073 24,000 22,824 0 0 22,824 456 0 0 2.0 928 2,145 2.87 192,29 17.99 0 24,000 (4,705) (3,795)
2008 3,306 0 23,904 0 0 23,904 478 0 0 2.0 1,056 2,250 2.94 20,121 17.89 0 0 20,121 14,756
2009 3,232 0 23,116 0 0 23,116 462 0 0 2.0 1,056 2,176 2.97 19,422 17.85 0 0 19,422 12,949
2010 3,156 0 22,308 0 0 22,308 446 0 0 2.0 1,056 2,100 3.01 18,706 17.82 0 0 18,706 11,338
2011 3,084 0 21,544 0 0 21,544 431 0 0 2.0 1,056 2,028 3.04 18,029 17.78 0 0 18,029 9,934
2012 3,007 0 20,717 0 0 20,717 414 0 0 2.0 1,056 1,951 3.08 17,297 17.73 0 0 17,297 8,664
2013 2,936 0 19,964 0 0 19,964 399 0 0 2.0 1,056 1,880 3.12 16,629 17.69 0 0 16,629 7,572
2014 2,869 0 19,247 0 0 19,247 385 0 0 2.0 1,056 1,813 3.07 15,994 17.65 0 0 15,994 6,621
2015 2,805 0 18,565 0 0 18,565 371 0 0 2.0 1,056 1,749 3.21 15,389 17.60 0 0 15,389 5,792
2016 2,744 0 17,916 0 0 17,916 358 0 0 2.0 1,056 1,688 3.25 14,813 17.55 0 0 14,813 5,068
2017 2,686 0 17,296 0 0 17,296 346 0 0 2.0 1,056 1,630 3.30 14,265 17.51 0 0 14,265 4,437
2018 2,630 0 16,705 0 0 16,705 334 0 0 2.0 1,056 1,574 3.34 13,741 17.46 0 0 13,742 3,885
2019 2,577 0 16,142 0 0 16,142 323 0 0 2.0 1,056 1,521 3.39 13,242 17.41 0 0 13,242 3,404
- ------------------------------------------------------------------------------------------------------------------------------------
SUB 41,063 34,000 282,561 0 0 282,561 5,561 0 0 2.0 14,464 26,599 235,847 0 34,000 201,847 98,588
REM 74,568 550 438,256 0 0 438,256 8,765 0 0 2.0 33,252 41,317 354,922 0 550 354,372 25,315
TOT 115,633 4,550 720,816 0 0 720,816 14,416 0 0 2.0 47,716 67,915 590,769 0 34,550 556,219 123,903
===================== PRESENT WORTH (-M$-)======================= ================= PROFITABILITY =========
Before
Discount Rate 0% 5% 10% 15% 20% COMPANY SHARE BASIS Tax
- ----------------------------------------------------------------- -----------------------------------------
Revenue ..... 590,769 250,423 152,418 109,151 84,768 Rate of Return (%) ........... 999.9
Proc & Other Income 0 0 0 0 0 Profit Index (undisc.) ....... 16.1
Capital Costs 34,000 31,052 28,506 26,29 224,354 (disc. @ 10.0%).......... 4.3
Abandonment Cost 550 62 9 2 0 (disc. @ 5.0%).......... 7
Cash Flow ....... 556,219 219,309 123,903 82,857 60,413 First Payout (years) ......... 0.7
Total Payout (years) ......... 2.6
Cost of Finding ($/BOE) ...... 1.02
PW @ 10.0% ($/BOE ) .......... 3.65
PW @ 5.0% ($/BOE ) .......... 6.46
================================COMPANY SHARE=========================================
Operating Net Capitals Cash
1st Year Averag Royaltities Costs Revenue Costs Flow
-------------------------------------------------------------------------------------
% Interest ..........100.0 100.0
% of Gross Revenue .. 2.0 16.0 82.0 4.8 77.2
Continued...
Table 2 continued
BMB Munai
Allocation of G&A
ADE Block, Republic of Kazakhstan
Undiscounted Discounted @
------------------- -------------------------------------------------------------------------------
G&A 5% 10% 15% 20%
Year M$/yr. M$ M$ M$ M$
- ------------------ ------------------- ------------------- ------------------- -------------------- --------------
2005 2,400 2,342 2,288 2,238 2,191
2006 2,400 2,231 2,080 1,946 1,826
2007 2,400 2,124 1,891 1,692 1,521
2008 2,400 2,023 1,719 1,472 1,268
2009 2,400 1,927 1,563 1,280 1,057
2010 2,400 1,835 1,421 1,113 880
2011 2,400 1,748 1,292 968 734
2012 2,400 1,665 1,174 841 611
2013 2,400 1,585 1,068 732 510
2014 2,400 1,510 970 636 425
2015 2,400 1,438 882 553 354
2016 2,400 1,369 802 481 295
2017 2,400 1,304 729 418 246
2018 2,400 1,242 663 364 205
2019 2,400 1,183 603 316 171
------------------- ------------------- ------------------- -------------------- --------------
Sub Total 36,000 25,526 19,146 15,049 12,292
Rem 84,000 19,370 5,811 2,093 852
------------------- ------------------- ------------------- -------------------- --------------
Total 120,000 44,896 24,957 17,142 13,144
Table 2 cont...
Company
Corporate Income Tax (CIT) and Excess Profit Tax (EPT)
January 1, 2005
Area, Kazakhstan
Total Proved
Deductible Costs
----------------------------------------
Operating
Gross Costs and Deductible Total Taxable Corporate
Income G&A Royalties Capital Deductions Income Income Tax
Year $M $M $M $M $M $M $M
- --------- -------- --------- --------- ---------- ---------- -------- ----------
2005 5,114 3,121 102 1,891 5,114 0 0
2006 17,197 4,639 344 9,109 14,092 3,105 932
2007 22,824 5,473 456 11,100 17,029 5,795 1,739
2008 23,904 5,706 478 11,100 17,284 6,620 1,986
2009 23,116 5,632 462 11,100 17,194 5,922 1,777
2010 22,308 5,556 446 6,400 12,402 9,906 2,972
2011 21,544 5,484 431 4,800 10,715 10,829 3,249
2012 20,717 5,407 414 0 5,821 14,896 4,469
2013 19,964 5,336 399 0 5,735 14,229 4,269
2014 19,247 5,269 385 0 5,654 13,593 4,078
2015 18,565 5,205 371 0 5,576 12,989 3,897
2016 17,916 5,144 358 0 5,502 12,414 3,724
2017 17,296 5,086 346 0 5,432 11,864 3,559
2018 16,705 5,030 334 0 5,364 11,341 3,402
2019 16,142 4,977 323 0 5,300 10,842 3,253
------- ------- -------- ------- -------- -------- -------
Sub total 282,561 77,065 5,651 55,500 138,216 144,345 43,304
Remainder 438,256 158,569 8,765 0 167,334 270,922 81,276
------- ------- -------- ------- -------- -------- -------
Total 720,816 235,634 14,416 55,500 305,550 415,267 124,580
Ratio Net Amount
Net 20% of Income to Exceeding
Income Deductions Tax Base Deductions 20% EPT Rate EPT Amount
Year $M $M $M % % % $M
- --------- -------- --------- --------- ---------- ---------- -------- ----------
2005 0 1,023 -1,023 0 0 0 0
2006 2,174 2,818 -645 15 -5 15 0
2007 4,057 3,406 651 24 4 15 98
2008 4,634 3,457 1,177 27 7 30 353
2009 4,145 3,439 707 24 4 15 106
2010 6,934 2,480 4,454 56 36 60 2,672
2011 7,580 2,143 5,437 71 51 60 3,262
2012 10,427 1,164 9,263 179 159 60 5,558
2013 9,960 1,147 8,813 174 154 60 5,288
2014 9,515 1,131 8,384 168 148 60 5,031
2015 9,092 1,115 7,977 163 143 60 4,786
2016 8,690 1,100 7,589 158 138 60 4,554
2017 8,305 1,086 7,218 153 133 60 4,331
2018 7,939 1,073 6,866 148 128 60 4,119
2019 7,589 1,060 6,529 143 123 60 3,918
------- ------- -------- ------- -------- -------- -------
Sub total 101,042 27,643 73,398 1,503 1,223 675 44,076
Remainder 189,645 33,467 156,178 113 93 60 93,707
------- ------- -------- ------- -------- -------- -------
Total 290,687 61,110 229,577 1,616 1,316 735 137,783
Net Present Values
- -------------------------------------------------------------------------
Discout Factors - %/yr.
---------------------------------------------------
0 5 10 15 20
-------- --------- -------- --------- ---------
Corporate Income Tax 124,580 37,431 20,629 14,143 10,432
Excess Profits Tax 137,783 37,712 18,846 11,875 8,066
- -------------------------------------------------------------------------
Table 3
EVALUATION OF: ADE Block, Kazakhstan ERGO v6.00g PETRO-SOFT SYSTEMS LTD. GRAND TOTAL
Total Proved Plus Probable Consolidation GLOBAL : 11-JUL-2005 3864_BMB_C$
EFF DATE: 01-APR-2005
RUN DATE: 17-JAN-2006 TIME: 15:13
FILE:
EVALUATED BY -
COMPANY EVALUATED - BMB MUNAI INC.
APPRAISAL FOR -
PROJECT - CONSTANT PRICES & COSTS
TOTAL CAPITAL COSTS - 143000000 -$-
TOTAL ABANDONMENT - 1300000 -$-
Oil Gas
MSTB MMCF
---------------------------------------------------------------------------------------
Pool Company Share Pool Company Share
# of Price -------------------------#-of--Price------------------------------------
Year Wells $/STB MSTB/d Vol Gross Net Wells $/MCF MMCF/d Vol Gross Net
---------------------------------------------------------------------------------------------
2005 5 21.31 0.9 240 240 236 0 0.50 0.0 0 0 0
2006 7 21.32 2.4 880 880 863 0 0.50 1.6 567 567 555
2007 19 21.33 4.1 1,506 1,506 1,476 0 0.50 4.6 1,680 1,680 1,646
2008 23 21.34 8.4 3,083 3,083 3,021 0 0.50 9.6 3,490 3,490 3,420
2009 26 21.34 10.1 3,679 3,679 3,606 0 0.50 11.3 4,125 4,125 4,042
2010 26 21.34 9.5 3,472 3,472 3,403 0 0.50 10.7 3,897 3,897 3,819
2011 26 21.34 9.1 3,310 3,310 3,243 0 0.50 10.2 3,717 3,717 3,643
2012 26 21.34 8.7 3,164 3,164 3,101 0 0.50 9.7 3,554 3,554 3,482
2013 26 21.34 8.3 3,027 3,027 2,966 0 0.50 9.3 3,400 3,400 3,332
2014 26 21.33 7.9 2,897 2,897 2,839 0 0.50 8.9 3,254 3,254 3,189
2015 26 21.33 7.6 2,774 2,774 2,719 0 0.50 8.5 3,116 3,116 3,054
2016 26 21.33 7.3 2,658 2,658 2,605 0 0.50 8.2 2,985 2,985 2,926
2017 26 21.33 7.0 2,547 2,547 2,497 0 0.50 7.8 2,862 2,862 2,804
2018 26 21.33 6.7 2,442 2,442 2,393 0 0.50 7.5 2,743 2,743 2,688
2019 26 21.33 6.4 2,342 2,342 2,296 0 0.50 7.2 2,632 2,632 2,579
---------------------------------------------------------------------------------------------
SUB 38,023 38,023 37,263 42,021 42,021 41,180
REM 54,895 54,895 53,797 59,687 59,687 58,493
TOT 92,918 92,918 91,060 101,708 101,708 99,673
= POOL/TRACT = =================================== COMPANY SHARE REVENUE AND CASH FLOW =============================================
Gross Revenue Royalties Operating Costs Proc
------------------- ------------------- --------------------- & Capi- Cash Flow
Oper Capital Sales Pro- Min- Vari- Net Net Other tal --------------
Year Costs Costs Oil Gas ducts Total Crown Other eral Fixed able Revenue back Income Costs Undisc. PW 10%
M$ M$ M$ M$ M$ M$ M$ M$ M$ % M$ M$ $/BOE M$ $/BOE M$ M$ M$ M$
- -----------------------------------------------------------------------------------------------------------------------------------
2005 721 4,500 5,114 0 0 5,114 102 0 0 2.0 240 481 3.00 4,291 17.84 0 4,500 (209) (202)
2006 2,479 11,000 18,759 283 0 19,042 381 0 0 2.0 624 1,855 2.54 16,182 16.60 0 11,000 5,182 4,599
2007 4,605 79,500 32,118 840 0 32,958 659 0 0 2.0 1,312 3,293 2.58 27,694 15.50 0 79,500 (51,806)(41,793)
2008 8,955 48,000 65,749 1,745 0 67,494 1,350 0 0 2.0 2,208 6,747 2.44 57,189 15.61 0 48,000 9,189 6,739
2009 10,542 0 78,524 2,062 0 80,586 1,612 0 0 2.0 2,496 8,046 2.41 68,432 15.67 0 0 68,432 45,625
2010 10,090 0 74,105 1,949 0 76,054 1,521 0 0 2.0 2,496 7,594 2.45 64,443 15.63 0 0 64,443 39,059
2011 9,735 0 70,626 1,858 0 72,484 1,450 0 0 2.0 2,496 7,239 2.48 61,299 15.60 0 0 61,299 33,777
2012 9,416 0 67,511 1,777 0 69,288 1,386 0 0 2.0 2,496 6,920 2.51 58,486 15.57 0 0 58,486 29,296
2013 9,116 0 64,579 1,700 0 66,279 1,326 0 0 2.0 2,496 6,620 2.54 55,837 15.54 0 0 55,837 25,427
2014 8,833 0 61,814 1,627 0 63,441 1,269 0 0 2.0 2,496 6,337 2.57 53,339 15.51 0 0 53,339 22,081
2015 8,564 0 59,183 1,558 0 60,741 1,215 0 0 2.0 2,496 6,068 2.60 50,962 15.47 0 0 50,962 19,179
2016 8,309 0 56,694 1,493 0 58,187 1,164 0 0 2.0 2,496 5,813 2.63 48,714 15.44 0 0 48,714 16,667
2017 8,068 0 54,340 1,431 0 55,771 1,115 0 0 2.0 2,496 5,572 2.67 46,588 15.40 0 0 46,588 14,490
2018 7,837 0 52,089 1,372 0 53,461 1,069 0 0 2.0 2,496 5,341 2.70 44,555 15.37 0 0 44,555 12,598
2019 7,620 0 49,960 1,316 0 51,276 1,026 0 0 2.0 2,496 5,124 2.74 42,630 15.33 0 0 42,630 10,958
- ------------------------------------------------------------------------------------------------------------------------------------
SUB 114,88 143,000 811,16 721,010 0 832,177 16,644 0 0 2.0 31,840 83,049 700,644 0 143,000 557,644 238,500
REM 194,18 41,300 1,170,436 429,843 01,200,279 24,006 0 0 2.0 74,446 119,738 982,090 0 1,300 980,790 76,124
TOT 309,07 144,300 1,981,603 650,854 02,032,457 40,649 0 0 2.0 106,286 202,788 1,682,735 0 144,3001,538,435 314,625
============== PRESENT WORTH (-M$-)=============== ============= PROFITABILITY ================
Before
Discount Rate 0% 5% 10% 15% 20% COMPANY SHARE BASIS Tax
- ------------------------------------------------------------------------------------------------------------------------------------
Revenue ................. 1,682,734 721,721 428,087 294,696 219,388 Rate of Return (%) ........... 90
Proc & Other Income.. 0 0 0 0 0 Profit Index (undisc.) ....... 107
Capital Costs............ 143,000 126,943 113,440 101,986 92,193 (disc. @ 10.0%) 2.8
Abandonment Costs........ 1,300 156 23 4 1 (disc. @ 5.0%) 4.7
Cash Flow ............... 1,538,434 594,621 314,624 192,706 127,194 First Payout (years) ......... 0.8
Total Payout (years) ......... 4.3
Cost of Finding ($/BOE) ...... 1.31
PW @ 10.0% ($/BOE ) .......... 2.86
PW @ 5.0% ($/BOE ) .......... 5.41
=================================== COMPANY SHARE ====================================
Operating Net Capitals Cash
1st Year Averag Royaltities Costs Revenue Costs Flow
-------------------------------------------------------------------------------------
% Interest ..........100.0 100.0
% of Gross Revenue . 2.0 15.2 82.8 7.1 75.7
Table 3 cont...
Company
Corporate Income Tax (CIT) and Excess Profit Tax (EPT)
January 1, 2005
Area, Kazakhstan
Total Proved Plus Probable
Deductible Costs
------------------------------------------
Operating
Gross Costs and Deductible Total Taxable Corporate
Income G&A Royalties Capital Deductions Income Income Tax
Year $M $M $M $M $M $M $M
- --------- -------- --------- --------- ---------- ---------- -------- ----------
2005 5,114 3,121 102 1,891 5,114 0 0
2006 19,043 4,879 381 10,109 15,369 3,674 1,102
2007 32,958 7,005 659 23,000 30,664 2,294 688
2008 67,494 11,355 1,350 32,600 45,305 22,189 6,657
2009 80,587 12,942 1,612 32,600 47,154 33,433 10,030
2010 76,054 12,490 1,521 27,700 41,711 34,343 10,303
2011 72,485 12,135 1,450 25,500 39,085 33,400 10,020
2012 69,288 11,816 1,386 9,600 22,802 46,486 13,946
2013 66,278 11,516 1,326 0 12,842 53,436 16,031
2014 63,441 11,233 1,269 0 12,502 50,939 15,282
2015 60,741 10,964 1,215 0 12,179 48,562 14,569
2016 58,187 10,709 1,164 0 11,873 46,314 13,894
2017 55,771 10,468 1,115 0 11,583 44,189 13,257
2018 53,461 10,237 1,069 0 11,306 42,155 12,647
2019 51,276 10,020 1,026 0 11,046 40,230 12,069
--------- ------- -------- ------- -------- -------- -------
Sub total 832,177 150,890 16,644 163,000 330,534 501,644 150,493
Remainder 1,200,279 211,184 24,006 0 235,190 965,090 289,527
--------- ------- -------- ------- -------- -------- -------
Total 2,032,457 362,074 40,649 163,000 565,723 1,466,734 440,020
Ratio Net Amount
Net 20% of Income to Exceeding
Income Deductions Tax Base Deductions 20% EPT Rate EPT Amount
Year $M $M $M % % % $M
- --------- -------- --------- --------- ---------- ---------- -------- ----------
2005 0 1,023 -1,023 0 0 0 0
2006 2,572 3,074 -502 17 -3 15 0
2007 1,606 6,133 -4,527 5 -15 15 0
2008 15,532 9,061 6,471 34 14 30 1,941
2009 23,403 9,431 13,972 50 30 45 6,288
2010 24,040 8,342 15,698 58 38 60 9,419
2011 23,380 7,817 15,563 60 40 60 9,338
2012 32,540 4,560 27,980 143 123 60 16,788
2013 37,405 2,568 34,837 291 271 60 20,902
2014 35,657 2,500 33,157 285 265 60 19,894
2015 33,993 2,436 31,558 279 259 60 18,935
2016 32,420 2,375 30,045 273 253 60 18,027
2017 30,932 2,317 28,615 267 247 60 17,169
2018 29,509 2,261 27,248 261 241 60 16,349
2019 28,161 2,209 25,952 255 235 60 15,571
--------- ------- -------- ------- -------- -------- -------
Sub total 351,151 66,107 285,044 2,278 1,998 705 170,620
Remainder 675,563 47,038 628,525 287 267 60 377,115
--------- ------- -------- ------- -------- -------- -------
Total 1,026,714 113,145 913,569 2,565 2,265 765 547,735
Net Present Values
- -------------------------------------------------------------------------
Discount Factors - %/yr.
---------------------------------------------------
0 5 10 15 20
-------- --------- -------- --------- ---------
Corporate Income Tax 440,020 128,925 68,945 45,949 32,938
Excess Profits Tax 547,735 147,719 73,442 46,404 31,707
- -------------------------------------------------------------------------
Appendix 3
