Exhibit
99.2


**Management s
      Discussion and Analysis**
 
 *The
following Management s Discussion and Analysis ( MD&A ) of the financial
condition and results of our operations should be read in conjunction with our
consolidated financial statements and notes relating thereto that are included
elsewhere in this report. Our financial statements have been prepared in
accordance with Canadian generally accepted accounting principles ( GAAP ). This
discussion and analysis contains forward-looking statements, which involve risks
and uncertainties. Our actual results could differ materially from those
anticipated in the forward-looking statements.*
 
 *These
forward-looking statements can generally be identified by the use of statements
that include phrases such as  believe ,  expect ,  anticipate ,  intend ,
 plan ,  likely ,  will  or similar words or phrases. Similarly, statements that
describe our objectives, plans or goals are or may be forward-looking
statements. These forward-looking statements are based on our current
expectations and projections about future events. However, whether actual
results and developments will conform with our expectations and projections is
subject to a number of risks and uncertainties, including, among other things,
the risks and uncertainties described under section  Risk Analysis  and the risk
factors described in our Annual Information Form for the year ended December 31,
2004 under the heading  Risk Factors . These are not necessarily all of the
important factors that could cause actual results to differ materially from
those expressed in any of our forward-looking statements. Other known or
unpredictable factors could also harm our results. Consequently, there can be no
assurance that the actual results or developments anticipated by us will be
realized or, even if substantially realized, that they will have the expected
consequences to, or affects on, us. Unless otherwise required by applicable
securities law, we disclaim any intention or obligation to publicly update or
revise any forward-looking statements, whether as a result of new information,
future events or otherwise.*
 
 *In
our MD&A we use certain terms, which are specific to the oil and gas
industry, including  net return  and  cash flow . These are non-GAAP terms
defined within our MD&A.*
 
 *Except
as otherwise required by the context, reference in this MD&A to  our ,  we
or  us  refer to the combined business of PetroKazakhstan Inc. and all of its
subsidiaries and joint ventures.*
 
 *Additional
information filed with Canadian securities commissions and the United States
Securities and Exchange Commission, including our quarterly and annual reports
and our Annual Information Form (AIF/40-F), are available on line at
www.sedar.com and www.sec.gov.*
 
 ***All
numbers are in U.S. Dollars unless otherwise
indicated.***
 33
 
 
 
 **OVERVIEW
AND STRATEGY**
 
 PetroKazakhstan
Inc. is an integrated oil company that owns and operates oil and gas production
and a refinery in Kazakhstan. We use the term  Upstream  to refer to the
exploration for and production of oil and gas from our licenses in the South
Turgai Basin, Kazakhstan. We use the term  Downstream  to refer to the
operations of our refinery located in Shymkent, Kazakhstan and the marketing and
transportation of refined products and the management of the marketing and
transportation of crude oil for Upstream.
 
 **BUSINESS
STRATEGY**
 
 PetroKazakhstan
strives to be the leading integrated oil and gas company in the Former Soviet
Union and an exemplary corporate citizen. Our goal is to create superior value
for our shareholders and the Republic of Kazakhstan while protecting the health
and safety of our people and the environment.
 
 The
primary elements of our strategy are to:
 
 4
    *Explore
      our undeveloped properties.*We
      have approximately 3,400,000 acres of land that we intend to explore and
      develop.4
    *Capitalize
      on development opportunities.*We
      intend to bring our proved undeveloped reserves into production in a
      timely, efficient and profitable manner.4
    *Fully
      exploit our reserves.*We
      intend to focus on the complete reserve base and continue to develop and
      bring more reserves into the proved category.4
    *Seek
      selective acquisition opportunities.*As part of our strategy to increase reserves and production, we are
      pursuing opportunities to acquire additional reserves from third parties.
      Our acquisition strategy has focused on acreage and assets, both producing
      and of exploration potential, within the vicinity of our current oil
      fields and throughout Kazakhstan.4
    *Open
      new transportation routes to international markets and reduce our
      transportation costs.*In
      2004, approximately 55% of crude oil sales went to export markets. Though
      we have been successful in reducing our transportation costs to these
      markets, they still remain our single largest cost of
      operations.4
    *Improve
      the operational performance of our refinery.*Since the acquisition of the refinery in 2000, we have been implementing
      projects designed to increase product quality and production yields and to
      improve the refinery s product mix.4
    *Control
      and reduce our overhead and operating costs.*Overlaps
      in the operations of our principal operating subsidiaries, PKKR and PKOP,
      have been essentially eliminated by establishing a joint marketing and
      transportation team. We have divested non-core activities and continue to
      aim at reduction of our operating costs.4
    Manage
      our environmental and social responsibilities to ensure that we earn
      support from all stakeholders for PetroKazakhstan s growth and operating
      plans.In
      late 2003 we commissioned our gas utilization project designed to reduce
      the flaring of gas produced from our Kumkol fields and the consequential
      release of pollutants into the environment. We also plan to complete the
      construction of a gas processing plant in our Akshabulak field in 2005,
      which will further reduce gas
flaring.
  34PetroKazakhstan
      Inc.
 
 
 
 **HIGHLIGHTS**
 
 Years
      ended December 31**2004**
    
    2003**2004**
    
    2003
    
    2002
    
    **vs
      2003**
    
    vs
      2002Net
      income*($000 s)*
    
    
    **500,668**
    
    
    316,940
    
    
    161,397
    
    
    **58**
    **%**
    
    96
    %Cash
      flow*($000 s)*1
    
    
    **560,491**
    
    
    399,975
    
    
    216,794
    
    
    **40**
    **%**
    
    84
    %Basic
      net income per share
    
    
    **6.40**
    
    
    4.06
    
    
    2.00
    
    
    **58**
    **%**
    
    103
    %Basic
      cash flow per share
    
    
    **7.16**
    
    
    5.12
    
    
    2.68
    
    
    **40**
    **%**
    
    91
    %Production,
      bopd2
    
    
    **151,102**
    
    
    ****151,349
    
    
    135,842
    
    
    -
    
    
    11
    %Capital
      expenditures
    
    
    **165,952**
    
    
    203,213
    
    
    140,102
    
    
    **(18**
    **%)**
    
    45
    %Total
      assets
    
    
    **1,269,081**
    
    
    ****1,041,451
    
    
    709,723
    
    
    **22**
    **%**
    
    47
    %Long-term
      debt
    
    
    **134,862**
    
    
    246,655
    
    
    281,797
    
    
    **(45**
    **%)**
    
    (12
    %)Cash
      dividends declared
    
    
    **39,253**
    
    
    -
    
    
    -
    
    
    **100**
    **%**
    
    -Common
      shares outstanding
    
    
    **76,223,130**
    
    
    77,920,226
    
    
    78,956,875
    
    
    **(2**
    **%)**
    
    (1
    %)
  
  *1*
    *Cash
      flow: We evaluate our operations based upon our net income and cash flow.
      Cash flow is a non-GAAP measure that represents cash generated from
      operating activities before changes in non-cash working capital. We
      consider this to be a key measure as we use this measure to evaluate our
      ability to generate cash to fund our growth through capital expenditures
      and our ability to repay debt. The comparable GAAP measure is cash flow
      from operating activities. The following table reconciles our non-GAAP
      measure cash flow to the comparable GAAP measure  Cash flow from operating
      activities . Cash flow does not have any standardized meaning prescribed
      by Canadian GAAP and is, therefore, unlikely to be comparable to similar
      measures presented by other
issuers.*
 
 Years
      ended December 31*($000 s)*
    
    **2004**
    
    2003
    
    2002Cash
      flow
    
    
    **560,491**
    
    
    399,975
    
    
    216,794Changes
      in non-cash operating working capital items
    
    
    **(24,899**
    **)**
    
    (60,625
    )
    
    (37,816
    )Cash
      flow from operating activities
    
    
    **535,592**
    
    
    339,350
    
    
    178,978
 *2*
    *We
      report production before royalties as we measure our Upstream operations
      on this basis, which is consistent with industry practice in Canada.*
 
 35
 
 
 **NET
INCOME VARIANCES**
 
 $
      millionsNet
      income for the year ended December 31, 2002:
    
    
    161Increase
      in the price of crude oil
    
    
    76Increase
      in net return at Kumkol for refined products
    
    
    72Increase
      in refined products sales volumes
    
    
    23Increase
      in crude oil export sales volumes
    
    
    16Increase
      in depletion and depreciation
    
    
    (16
    )Other
      variances
    
    
    (15
    )Net
      income for the year ended December 31, 2003:
    
    
    317Increase
      in the price of crude oil
    
    
    200Increase
      in net return at Kumkol for refined products
    
    
    92Improvement
      in differential
    
    
    32Increase
      in crude oil export sales volumes
    
    
    24Increase
      in prices for crude oil purchases
    
    
    (38
    )Excess
      profit tax
    
    
    (35
    )Hedging
    
    
    (26
    )Decrease
      in refined products sales volumes
    
    
    (22
    )Increase
      in depletion and depreciation
    
    
    (16
    )Higher
      income tax rate for Kazgermunai
    
    
    (12
    )Other
      variances
    
    
    (15
    )**Net
      income for the year ended December 31, 2004:**
    
    
    **501**
 
 Higher
prices for crude oil and refined products in 2003 and 2004 were the major reason
for our record results. Our efforts to improve our differential in 2004 added an
additional $32.0 million to our net income. These gains were partially offset by
the foregone revenue from our hedging program and the increased prices paid for
crude oil purchased from third parties. Lower throughput volumes and the
refinery turnaround led to lower sales of refined products in 2004.
 
 **KEY
PERFORMANCE INDICATORS**
 
 We
measure the performance of our Upstream and Downstream operations using the
following key performance indicators:
 
 Years
      ended December 31**2004**
    
    2003
    
    2002Production,
      bopd
    
    
    **151,102**
    
    
    151,349
    
    
    135,842Differential*($/bbl)*
    
    
    **12.62**
    
    
    14.11
    
    
    13.97Average
      refined**products
      price*($/bbl)*
    
    
    **25.02**
    
    
    17.18
    
    
    13.59Production
      expense*($/bbl)*
    
    
    **1.62**
    
    
    1.19
    
    
    1.22Refining
      cost*($/bbl)*
    
    
    **0.80**
    
    
    0.58
    
    
    0.80General
      and administrative*($/bbl)*
    
    
    **1.16**
    
    
    1.12
    
    
    1.39Effective**income
      tax rate*(%)*
    
    
    **37.5**
    
    
    32.8
    
    
    38.0
 
 ***Production.***  See *Volumetrics* for a
discussion of our production.
 
 36PetroKazakhstan
      Inc.
 
 
 
 
 ***Strategy:
Open new transportation routes to international markets and reduce our
transportation costs***
 
 
 ***Differentials.*** The
graph below shows the evolution of our differential.
 
 
 ***
    *Our
      differential is calculated as the difference between the average Brent
      price for crude oil export sales received by PKKR and Turgai, and our net
      return at Kumkol. Differential is a non-GAAP measure that is the sum of
      the costs and discounts incurred in order to transport and sell our crude
      oil to international markets. The sales revenue used in this measure
      differs from sales revenue in the statement of net income and the net
      return table for the following reasons:**4*
    *The
      differential does not include Kazgermunai sales over which we have limited
      control. Kazgermunai is excluded because the differential is used to
      measure the performance of our internal marketing
    group.**4*
    *The
      differential is calculated using finalized sales transactions. Our
      financial statements include estimates that may or may not reflect the
      finalized transactions.**The
      term  differential  does not have a standardized meaning prescribed by
      Canadian GAAP and is, therefore, unlikely to be comparable to similar
      measures presented by other
companies.*
 
 Our
differential constitutes our single largest expenditure and the management of
this cost is one of our primary objectives. To achieve this, we have a dedicated
crude oil marketing and logistics team whose objective is to sell our crude oil
to end users and to obtain a greater understanding and control over our export
routes. To accomplish this, we have acquired a fleet of approximately 5,000
purchased and leased rail cars, obtained access to loading facilities and ports
and we have opened new transportation routes.
 
 We
export crude oil in all geographical directions, north to Atyrau through our
Dzhusaly terminal and then onward through the CPC pipeline, east to China via
the Atasu terminal, south to Uzbekistan and Iran and west through Aktau to the
port of Batumi and some onward shipments to ports in the
Mediterranean.
 37
 
 
 We have
made greater use of pipelines thereby reducing our rail costs. Specifically, our
KAM pipeline and the KTO pipeline to Atasu with onward rail to
China.
 
 In the
third quarter of 2004, the combination of different routes, increased
utilisation of pipelines, having railcars under our control, and reduced
discounts negotiated with buyers led to our overall crude differential reaching
its lowest level in four years at $11.66/bbl.
 
 In the
fourth quarter of 2004 our differential increased by $0.79/bbl over the fourth
quarter of 2003 and increased by $2.17/bbl over the third quarter of 2004.
 
 Increased
demand for sour crudes in the Mediterranean as a result of increases in the
differential between sweet and sour crudes, changed the average premium of
Kumkol over Brent of $0.68/bbl in the third quarter of 2004 to a discount of
$0.38/bbl by the fourth quarter of 2004, an impact of $1.06/bbl.
 
 Increased
shipping rates and demurrage costs for vessels, a seasonal factor, were
exacerbated by the hurricanes in the United States during the fall of 2004,
which led to worldwide increased shipping rates charged by crude oil purchasers
during the fourth quarter of 2004. For cargoes of approximately 80,000 metric
tonnes average freight and demurrage rates increased from $1.06/bbl in the third
quarter of 2004 to $3.37/bbl in the fourth quarter of 2004. Approximately 68% of
completed sales during the fourth quarter of 2004 were affected by these rate
increases.
 
 To
address this issue, we have chartered our own vessels on better terms than those
obtained through our crude oil purchasers, and our cargoes are being delivered
by us directly into the Mediterranean. We have also concentrated our efforts on
selling into markets that are not affected by this increase in shipping rates,
including Central Asia and China.
 
 The
Kumkol premium to Brent during the fourth quarter of 2003 was $0.37/bbl. The
improved discounts we have negotiated on our sales and the impact of increased
volumes on routes with better differentials were offset by the year over year
$0.75/bbl change in the premium/discount of Kumkol crude oil to Brent, and our
increased shipping and demurrage costs when comparing the fourth quarter of 2004
with 2003.
 
 ***Outlook:***  *Expectations
going forward are that the differential will remain between $13.50/bbl and
$14.00/bbl until the end of the first quarter of 2005, with a return to the
$12.00/bbl mark for the second and third quarters of 2005. The seasonal factors
discussed above will likely increase our fourth quarter differential in 2005,
though it is difficult to predict by how much and we will take all possible
steps to mitigate these factors.*
 
 38PetroKazakhstan
      Inc.
 
 
 
 
 
 ***Average
      refined products price***
      Our
      average refined product price received in 2004 was $7.84 higher than the
      average price we received in 2003. This was due to improvements in our
      yield such that we obtain greater volumes of higher value products per
      each barrel of crude oil refined. In addition, international crude oil
      prices influence refined product prices, as does economic growth within
      Kazakhstan. The price of refined products in Russia has a significant
      impact on the market price in Kazakhstan as products from Russia move
      across the border with relative ease and if refined product prices rise
      above Russian prices the Kazakhstan market is oversupplied with refined
      products from Russia.
      
      ***Outlook:****Refined
      product prices will be determined by market prices, including refined
      product prices in Russia and world oil prices.*
      
      ******
      ******
      ******
      ***Strategy:
      Control and reduce our overhead and operation
      costs***
      
      ***Production
      expenses***
      Production
      expenses were higher in 2004 compared to 2003 due to a number of factors.
      We continued to use temporary power generators to operate single well
      batteries in the KAM fields pending construction of infrastructure. The
      water cut in a number of our fields including our joint venture Turgai
      continued to increase resulting in higher production expenses. The number
      of wells and facilities commissioned in 2004 was higher compared to 2003.
      During 2004, we drilled 54 new production wells, including 25 wells that
      were drilled by our joint ventures.
      
      ***Outlook:****During
      2005 we will be installing flowlines to tie in the single wells at the KAM
      fields to our main facilities and we are also planning to increase the
      capacity of existing facilities to handle the increasing water production.
      Our Upstream operations have embarked on a program focused on reducing
      production expenses. A number of initiatives have been identified and we
      are in the process of implementation.*
      
      
      
      ***Refining
      cost***
      Refining
      costs in 2004 reflected the impact of the first major turnaround since
      2002. Major repairs were performed on the main crude processing units,
      visbreaker and storage facilities. Annual purchased energy costs were also
      marginally higher due to the operation of the Vacuum Distillation Unit
      (VDU) brought online in January 2004.
      
      ***Outlook:****We
      do not plan to have a major turnaround in 2005. Refining costs should
      therefore be lower.*
 **
  39
 
 
 
 ***General
      and administrative expenses*********
      Our
      general and administrative expenses are virtually unchanged in 2004, as
      most of our expenses are fixed in nature. The per barrel decrease in 2003
      compared to 2002 was mainly due to increased production levels. Our
      Upstream field office is in Kyzylorda, the majority of our Upstream staff
      is located there, and all related costs are classified as general and
      administrative as opposed to production expenses.
      
      ***Outlook:****We
      do not expect a significant change in our general and administrative
      expenses in 2005.*
      
      
      
      ******
      ***Effective
      income tax rate*********
      The
      statutory tax rate in Kazakhstan, where all of our operations are located,
      is 30%. Our effective tax rate differs due to certain expenses, which
      cannot be deducted for statutory tax purposes. Our tax rate as a
      percentage of net income before tax of 37.5% in 2004 increased from 32.8%
      in 2003, mainly due to excess profit tax provided for in Turgai and the
      higher marginal tax rate in Kazgermunai. Our tax rate as a percentage of
      net income before tax of 32.8% in 2003 decreased from 38.0% in 2002,
      mainly because we refinanced our debt, increasing the deductibility of our
      interest expense.
      
      ***Outlook:****It
      remains our goal to minimize our non-deductible expenses and manage our
      excess profit tax exposure. Our goal is to maximize deductions, consistent
      with the applicable tax legislation for each of our hydrocarbon production
      contracts.*
      
      ***Sensitivities***The
      following table sets forth our estimate of the impact on net income and
      cash flow to changes in the
following.
 
 Net
      income andChange
    
    cash
      flow after tax*($
      millions)*Crude
      oil
    
    $
    1/bbl
      in Brent
    
    
    28.5Differential
    
    $
    1/bbl
      change
    
    
    24.5Refined
      products price
    
    $
    1/bbl
      in overall average
    
    
    15.7Production
      volume
    
    
    5,000
      bopd
    
    
    14.0Production
      cost
    
    
    10
    %
    
    6.1General
      and administrative expenses
    
    
    10
    %
    
    4.0Refining
      cost
    
    
    10
    %
    
    1.9
 
 4
    The
      variable with the most significant impact on our business is the
      international price for crude oil. This directly impacts the value of our
      exports, and has a significant influence on refined product
      prices.4
    The
      differential has an equivalent per barrel impact as Brent on our exports
      of crude oil, while average refined product prices impact the value
      obtained for refined products sales.4
    Production
      volumes impact our results as we have more or less crude oil to sell or
      refine.4
    Changes
      in our production, general and administrative and refining costs are less
      significant because these costs represent a relatively low percentage of
      our total costs.
 
 40PetroKazakhstan
      Inc.
 
 
 
 **VOLUMETRICS**
      
      **UPSTREAM**
      
      ***Production***
      The
      following table sets forth our barrels of oil produced per day by
      field:
 
 Field*(bopd)*
    
    **2004**
    
    2003
    
    2002Kumkol
      South
    
    
    **44,851**
    
    
    58,718
    
    
    66,726Kumkol
      North
    
    
    **35,752**
    
    
    29,746
    
    
    22,810South
      Kumkol
    
    
    **23,682**
    
    
    29,846
    
    
    22,728Kyzylkiya
    
    
    **9,895**
    
    
    7,925
    
    
    6,941Aryskum
    
    
    **10,835**
    
    
    7,000
    
    
    4,330Maibulak
    
    
    **2,130**
    
    
    1,051
    
    
    824North
      Nurali
    
    
    **398**
    
    
    464
    
    
    -East
      Kumkol
    
    
    **589**
    
    
    -
    
    
    634License
      #952
    
    
    **270**
    
    
    -
    
    
    -License
      #951
    
    
    **7**
    
    
    -
    
    
    -Kazgermunai
      Fields
    
    
    **22,693**
    
    
    16,599
    
    
    10,849Total
    
    
    **151,102**
    
    
    151,349
    
    
    135,842
 
 ***Strategy:
      Fully and effectively exploit our reserves***
      
      *2004
      versus 2003*
      
      ***Kumkol
      South****-
      decrease of 13,867 bopd.*
      The
      decrease in Kumkol South production in 2004 was mainly due to 19 wells
      that border the Kumkol North field that were shut-in for the first four
      months of 2004 and are now on a reduced production scheme designed to
      equalize the reservoir pressure between the fields. The net impact of the
      reduced production scheme on our average annual rate of production was a
      decrease of 8,500 bopd. Additionally, during the fourth quarter of 2004
      water injection capacity was a limiting factor in optimizing our
      production due to increased water production from our Kumkol South, South
      Kumkol and Kumkol North fields.
      
      ***Outlook:****We
      expect to produce 39,200 bopd per day from Kumkol South in 2005 and plan
      to improve our surface water handling facilities by looping lines, adding
      further injection pumping capacity and debottlenecking existing
      facilities.*
      
      
      
      ***Kumkol
      North****-
      increase of 6,006 bopd.*
      Increases
      in production from our Kumkol North field were due to an increase in the
      number of production wells and installation of artificial
      lift.
      
      ***Outlook:****We
      do not plan to increase the level of production in 2005, and our
      expectation for the next year is 35,800
  bopd.*
 
 
 41
 
 
 
 ***South
      Kumkol****-
      decrease of 6,164 bopd.*
      South
      Kumkol production decreased due to declining reservoir pressure which
      necessitated the conversion of three of our producing wells to water
      injection wells. Unexpected failures of electrical pumps had an impact of
      4,500 bopd on our rate of production. During the fourth quarter of 2004,
      pumps were optimized and field production resumed at normal
      rates.
      
      ***Outlook:****We
      plan to maintain our production levels at 22,800 bopd in 2005 by
      constructing a new water injection facility to maintain reservoir
      pressure.*
      
      
      ***KAM
      fields****-
      increase of 6,884 bopd.*
      The
      increase in production from our KAM fields (Kyzylkiya, Aryskum, Maibulak)
      was due to the increased number of wells put on production and
      implementation of our artificial lift program. A significant delay in the
      arrival of a drilling rig reduced the number of Aryskum development wells
      resulting in a negative impact of 2,300 bopd on our average annual
      forecasted production rate.
      
      ***Outlook:****We
      expect to further increase production to 38,900 bopd in 2005 through
      continued investment in these fields including new development drilling
      and infrastructure investment.*
      
      ******
      ***East
      Kumkol****-
      increase of 589 bopd.*
      East
      Kumkol volume was produced on an extended production test, pending
      completion of a hydrocarbon production contract.
      
      ***Outlook:****Our
      expectation is to start commercial production in the second quarter of
      2005 with our share of production from this field to average 900 bopd over
      the year.*
      
      
      ******
      ***Kazgermunai
      fields****-
      increase of 6,094 bopd.*
      Kazgermunai
      completed surface facility debottlenecking measures in late 2003, leading
      to the increase in 2004 production.
      
      ***Outlook:****We
      expect the production level in our Kazgermunai fields to be at 30,000 bopd
      in 2005, which will be achieved due to the installation of parallel
      production facilities.*
      
      
      
      *2003
      versus 2002:*
      
      Production
      levels in 2003 were affected by a number of factors unrelated to the
      technical performance of our fields. These included weather related issues
      in the Caspian and Black Seas, which reduced producers  ability to export
      crude oil, restrictions in the transportation system and the temporary
      suspension of production at the Aryskum field in mid-year. The fourth
      quarter also saw a temporary reduction of production in order to harmonize
      the operation of certain wells at the border of Kumkol South and Kumkol
      North fields.
 
 42PetroKazakhstan
      Inc.
 
 
 ***Crude
oil volumetrics***
 The
following table sets forth the movements in inventory for our Upstream
operations for the years ended December 31:
 
 *(mmbbls)*
    
    **2004**
    
    2003
    
    2002Opening
      inventory of crude oil
    
    
    **2.87**
    
    
    2.72
    
    
    0.70Production
    
    
    **55.31**
    
    
    55.24
    
    
    49.58Crude
      oil purchased from third parties
    
    
    **1.09**
    
    
    0.03
    
    
    0.68Crude
      oil purchased from joint ventures*(50%)*
    
    
    **0.11**
    
    
    0.25
    
    
    2.92Sales
      or transfers
    
    
    **(55.15**
    **)**
    
    (54.53
    )
    
    (51.08
    )Field
      and transportation losses
    
    
    **(0.28**
    **)**
    
    (0.19
    )
    
    (0.08
    )Return
      of purchased crude
    
    
    **-**
    
    
    (0.65
    )
    
    -Closing
      inventory of crude oil
    
    
    **3.95**
    
    
    2.87
    
    
    2.72
 
 In
2002, our Upstream operations purchased 2.9 mmbbls of crude oil from Turgai. In
2004 and 2003 almost all crude oil acquired from Turgai was purchased by our
Downstream operations.
 
 Under
the terms of an agreement with the company assigned by the government to market
royalty-in-kind volumes for 2002 we purchased 0.65 mmbbls of crude oil, which
was in our inventory at December 31, 2002. This oil was returned in the first
quarter of 2003.
 
 The
following table sets out our total crude oil sales and transfers from Upstream
operations for the years ended December 31:
 
 **2004**
    
    2003
    
    2002mmbbls
    
    %
    
    mmbbls
    
    %
    
    mmbbls
    
    %Crude
      oil exports
    
    
    **30.30**
    
    
    **54.9**
    
    
    27.99
    
    
    51.3
    
    
    25.89
    
    
    50.7Crude
      oil transferred to****Downstream
    
    
    **14.93**
    
    
    **27.1**
    
    
    18.85
    
    
    34.6
    
    
    16.82
    
    
    32.9Crude
      oil transferred to Downstream by joint**ventures*(50%)*
    
    
    **5.82**
    
    
    **10.6**
    
    
    5.31
    
    
    9.7
    
    
    4.39
    
    
    8.6Crude
      oil tolled by joint ventures*(50%)*
    
    
    **-**
    
    
    **-**
    
    
    0.35
    
    
    0.7
    
    
    -
    
    
    -Royalty
      payments
    
    
    **4.10**
    
    
    **7.4**
    
    
    2.03
    
    
    3.7
    
    
    3.48
    
    
    6.8Crude
      oil domestic sales****
    
    
    **-**
    
    
    **-**
    
    
    -
    
    
    -
    
    
    0.50
    
    
    1.0Total
      crude oil sales or****transfers
    
    
    **55.15**
    
    
    **100.0**
    
    
    54.53
    
    
    100.0
    
    
    51.08
    
    
    100.0
 
 **DOWNSTREAM**
 
 ***Refining***
 The
refinery at Shymkent has a total operating capacity of 6.6 million tonnes per
year or about 51.1 million barrels per year. Crude oil feedstock for our
refinery is primarily acquired from our Upstream operations, but purchases are
also made from third parties. Feedstock is refined into a number of products,
which are generally sold domestically. The refinery also refines crude oil on
behalf of third parties for a processing fee. Due to the size of the available
market for refined products in Kazakhstan, the refinery operated at 53% of
capacity or 27.2 million barrels in 2004, 60% capacity or 30.6 million barrels
in 2003 and 53% capacity or 27.1 million barrels in 2002.
 
 Our
total processed volumes were as follows:
 
 *(mmbbls)*
    
    **2004**
    
    2003
    
    2002Feedstock
      refined into product
    
    
    **26.70**
    
    
    30.01
    
    
    25.77Tolled
      volumes
    
    
    **0.53**
    
    
    0.59
    
    
    1.33Total
      processed volumes *
    
    
    **27.23**
    
    
    30.60
    
    
    27.10
 ***
    *The
      total processed volumes are used for our per barrel
      calculations*
  43
 
 
 ***Strategy:
Improve the operational performance of our refinery***
 
 The
refinery continued to focus on the improvement of yields while minimizing the
production of heavier end and lower value products. The production of mazut
(heavy fuel oil), a low value product, has been further reduced year-over-year.
Mazut yield in 2004 averaged 23.1% versus 32.5% in 2003 (35.9% in 2002). Our
Vacuum Distillation Unit was brought on stream in January 2004, resulting in a
significant decline in mazut production.
 
 ***Outlook:***  *We
continue working on the improvement of our refinery yields and quality of
products. In 2005 we expect to increase the quality of our high-grade gasoline
by using high-value additives.*
 
 Sources
of feedstock supplies for our refinery were as follows:
 
 *(mmbbls)*
    
    **2004**
    
    2003
    
    2002Acquired
      from PKKR
    
    
    **14.93**
    
    
    18.85
    
    
    16.82Purchased
      from**joint
      ventures*(100%)*
    
    
    **11.65**
    
    
    10.62
    
    
    8.78Tolled
      by joint ventures*(50%)**
    
    
    **-**
    
    
    0.35
    
    
    -Purchased
      from third parties
    
    
    **0.02**
    
    
    0.08
    
    
    -Total
      feedstock acquired
    
    
    **26.60**
    
    
    29.90
    
    
    25.60
 ***
    *50%
      of volumes tolled by our joint ventures are attributable to our joint
      venture partners and are not included in our inventory movements and
      ending inventory.*
 
 ***Feedstock
and refined products volumetrics***
 The
movements in our feedstock inventory at our refinery were as
follows:
 
 *(mmbbls)*
    
    **2004**
    
    2003
    
    2002Opening
      inventory of crude oil feedstock
    
    
    **0.03**
    
    
    0.20
    
    
    0.34Purchase
      and acquisition of feedstock
    
    
    **26.60**
    
    
    29.90
    
    
    25.60Recoverable
      feedstock from traps *
    
    
    **0.10**
    
    
    (0.06
    )
    
    0.03Feedstock
      refined into product
    
    
    **(26.70**
    **)**
    
    (30.01
    )
    
    (25.77
    )Closing
      inventory of feedstock
    
    
    **0.03**
    
    
    0.03
    
    
    0.20
 ***
    *This
      represents trapped oil processed, net of trapped oil recovered. During
      2003 the trapped oil tank was emptied for
  repairs.*
 
 The
movement in inventory of refined products was as follows:
  *(mmtonnes)**
    
    **2004**
    
    2003
    
    2002Opening
      inventory of refined product
    
    
    **0.26**
    
    
    0.22
    
    
    0.20Refined
      product from feedstock**
    
    
    **3.23**
    
    
    3.64
    
    
    3.09Refined
      product purchased
    
    
    **0.05**
    
    
    0.02
    
    
    0.09Refined
      product sold
    
    
    **(3.30**
    **)**
    
    (3.62
    )
    
    (3.16
    )Refined
      product internal use and yield losses
    
    
    **(0.03**
    **)**
    
    -
    
    
    -Closing
      inventory of refined product
    
    
    **0.21**
    
    
    0.26
    
    
    0.22
 ***
    *The
      inventory of products represents a mix of products for which no unique
      conversion from barrels to tonnes exists. The standard conversion used by
      us for crude oil is 7.746 barrels to the tonne.*****
    *Refined
      products from feedstock are presented as actual output from refined
      volumes of crude oil.*
  44PetroKazakhstan
      Inc.
 ****
 **RESULTS
OF OPERATIONS**
 
 **NET
RETURN PER BARREL**
 ****
 Set
forth below are the details of the average net return achieved for crude oil
export sales and sales derived from the refining of our own crude. Net return
per barrel is a non-GAAP measure that shows averages across all types of sales
contracts and illustrates the relationship between exports of crude oil versus
refining our own crude oil and marketing refined crude oil products. Net return
per barrel does not have a standardized meaning prescribed by Canadian GAAP and
is therefore unlikely to be comparable to similar measures presented by other
companies.
 
 Crude
      oil
    
    Own
      crude oil*($/bbl)*
    
    exports
    
    refined
      and sold***Year
      ended December 31, 2004***Net
      realized price
    
    
    **30.12**
    
    
    **25.02**Transportation
      costs
    
    
    **(6.94**
    **)**
    
    **(2.66**
    **)**Selling
      costs
    
    
    **(0.60**
    **)**
    
    **(0.78**
    **)**Crude
      utilized in refining **
    
    
    **-**
    
    
    **(1.36**
    **)**Refining
      cost
    
    
    **-**
    
    
    **(0.80**
    **)**Royalties
      and taxes - Downstream
    
    
    **-**
    
    
    **(0.71**
    **)**General
      and administrative costs - Downstream****
    
    
    **-**
    
    
    **(0.53**
    **)**Net
      return at Kumkol ***
    
    
    **22.58**
    
    
    **18.18**Production
      cost
    
    
    **(1.62**
    **)**
    
    **(1.62**
    **)**Royalties
      and taxes - Upstream
    
    
    **(1.94**
    **)**
    
    **(1.94**
    **)**General
      and administrative costs - Upstream
    
    
    **(0.63**
    **)**
    
    **(0.63**
    **)**Net
      return per barrel
    
    
    **18.39**
    
    
    **13.99***Year
      ended December 31, 2003*Net
      realized price
    
    
    21.32
    
    
    17.20*Transportation
      costs
    
    
    (7.21
    )
    
    (1.09
    )Selling
      costs
    
    
    (0.38
    )
    
    (0.64
    )Crude
      utilized in refining **
    
    
    -
    
    
    (0.94
    )Refining
      cost
    
    
    -
    
    
    (0.58
    )Royalties
      and taxes - Downstream
    
    
    -
    
    
    (0.40
    )General
      and administrative costs - Downstream
    
    
    -
    
    
    (0.53
    )Net
      return at Kumkol ***
    
    
    13.73
    
    
    13.02Production
      cost
    
    
    (1.19
    )
    
    (1.19
    )Royalties
      and taxes - Upstream
    
    
    (1.27
    )
    
    (1.27
    )General
      and administrative costs - Upstream
    
    
    (0.59
    )
    
    (0.59
    )Net
      return per barrel
    
    
    10.68
    
    
    9.97
 *See
notes on page 46*
 
 45
 
 
 
 Crude
      oil
    
    Own
      crude oil*($/bbl)*
    
    exports
    
    refined
      and sold*Year
      ended December 31, 2002*Net
      realized price
    
    
    17.20
    
    
    13.81*Transportation
      costs
    
    
    (5.04
    )
    
    (0.94
    )Selling
      costs
    
    
    (0.23
    )
    
    (0.67
    )Crude
      utilized in refining **
    
    
    -
    
    
    (0.98
    )Refining
      cost
    
    
    -
    
    
    (0.80
    )Royalties
      and taxes - Downstream
    
    
    -
    
    
    (0.41
    )General
      and administrative costs - Downstream
    
    
    -
    
    
    (0.64
    )Net
      return at Kumkol ***
    
    
    11.93
    
    
    9.37Production
      cost
    
    
    (1.22
    )
    
    (1.22
    )Royalties
      and taxes - Upstream
    
    
    (1.16
    )
    
    (1.16
    )General
      and administrative costs - Upstream
    
    
    (0.75
    )
    
    (0.75
    )Net
      return per barrel
    
    
    8.80
    
    
    6.24
 ***
    *Net
      realized price shown in these tables does not include the price received
      for purchased refined products resold.*****
    *Crude
      utilized in refining is our fuel consumption and yield loss percentage
      from refining our crude oil applied to the overall sales price received
      for our products.******
    *Average
      Brent or a similar index for each respective period does not reflect our
      average realized Brent price because of the timing of recognition of sales
      for financial statement purposes and the terms of the sales. Financial
      statement sales revenue is the basis used to determine the net sales price
      achieved in these tables. Therefore, a comparison of average Brent or
      similar index to our net return at Kumkol cannot be used to determine our
      differential.*
 
 *2004
versus 2003:*
 
 *Net
return for crude oil exports increased by $7.71/bbl in 2004 primarily due
to:*
 
 4
    Significant
      increase in market prices, with average Brent in 2004 of $38.27/bbl
      compared to $28.83/bbl in 2003. This was partially offset
    by:4
    Foregone
      revenue due to our hedging program, which had a negative impact of $1.39
      per barrel sold in 2004 compared to $0.16/bbl for 2003. See Note 15 to our
      consolidated financial statements.4
    Royalties
      and taxes, which increased by $0.67/bbl due to the increase in royalties
      as a result of higher crude oil
prices.
  *Net
return for own crude oil refined and sold increased by $4.02/bbl in 2004
primarily due to:*
 
 4
    Higher
      sales prices on all products and an improved yield, whereby more higher
      value products were produced.4
    The
      sale of VGO, a new high value product, accounted for 8% of total sales
      volumes in 2004.4
    Transportation
      costs increased by $1.57/bbl with a corresponding increase in our sales
      price due to refined products export sales on non-FCA
    terms.
 
 *2003
versus 2002:*
 
 During
2003, our net return for crude oil exports increased by $1.88/bbl compared to
2002 due to an increase in market prices (average Brent was $28.83/bbl compared
to $25.02/bbl in 2002) and transportation cost reductions after the start up of
the KAM pipeline. These were partially offset by an increase in pipeline and
railway tariffs. The increase in non-FCA sales of 19.40 million barrels or 90%
in 2003 versus 2002, increased both the net sales price achieved and our
transportation costs, as our sales point for crude oil, where title is
transferred, was closer to the final destination. Our net return for own crude
oil refined and sold increased by $3.73/bbl compared to 2002 due to an
improvement in yields and higher sales prices.
  46PetroKazakhstan
      Inc.
 
 
 **REVENUE**
 
 2004*Year
      ended December 31 ($000 s)*
    
    **2004**
    
    2003
    
    vs
      2003
    
    %Crude
      oil
    
    
    **992,880**
    
    
    621,126
    
    
    371,754
    
    
    59.9Refined
      products
    
    
    **639,405**
    
    
    481,326
    
    
    158,079
    
    
    32.8Service
      fees
    
    
    **6,484**
    
    
    11,532
    
    
    (5,048
    )
    
    (43.8
    )Interest
      income
    
    
    **3,658**
    
    
    3,340
    
    
    318
    
    
    9.5Total
      revenue
    
    
    **1,642,427**
    
    
    1,117,324
    
    
    525,103
    
    
    47.0
 
 2003*Year
      ended December 31 ($000 s)*
    
    2003
    
    2002
    
    vs
      2002
    
    %Crude
      oil
    
    
    621,126
    
    
    481,114
    
    
    140,012
    
    
    29.1Refined
      products
    
    
    481,326
    
    
    332,639
    
    
    148,687
    
    
    44.7Service
      fees
    
    
    11,532
    
    
    9,646
    
    
    1,886
    
    
    19.6Interest
      income
    
    
    3,340
    
    
    1,951
    
    
    1,389
    
    
    71.2Total
      revenue
    
    
    1,117,324
    
    
    825,350
    
    
    291,974
    
    
    35.4
 
 We
derive our revenues principally from the sale of crude oil and refined products.
To a much lesser extent, we also derive revenue from refining crude oil on
behalf of third parties for which we receive processing fees, and production and
ancillary support services provided to our joint venture Turgai Petroleum on a
fee basis. Our results are dependent on the levels of our oil production and on
prevailing world prices for crude oil and Kazakhstani prices for refined
products. Prices for crude oil and refined products are subject to large
fluctuations in response to a variety of factors beyond our
control.
 
 ***Crude
oil***
 We
market and sell our crude oil for export under a variety of contracts. Crude
production can be sold to third parties within Kazakhstan, normally at rail
terminals in Kazakhstan. Under these contracts, called Free Carrier Agreements
( FCA ) sales title to the crude oil passes to the buyer at the point of loading
the crude into rail cars. The price achieved for these export sales is shown net
of a differential to the prevailing Brent price at the time of the sale. The
differential reflects a number of factors, the most significant of which relates
to rail transportation costs. In the following tables included in our MD&A,
these sales are shown as  Crude sales sold FCA .
 
 Alternatively,
we can sell crude at points closer to a final delivery point. Under this type of
sale, whereby contracts are concluded on various alternative bases, including
delivery at frontier ( DAF ), delivered duty unpaid ( DDU ), cost, insurance and
freight ( CIF ), cost and freight ( CFR ), delivered ex ship ( DES ), carriage
paid to ( CPT ) and free on board ( FOB ), we arrange and assume all of the
costs and obligations of transportation. The sales price reflects the Brent
price less a differential. As with FCA sales, this differential reflects a
number of factors, the most significant being remaining transportation costs to
the final delivery point. With this type of sale, title to the crude oil does
not pass to the buyer until the crude is loaded into an oil tanker at a port or
the rail cars pass the borders of Kazakhstan or reach a specific destination
point. We do not record the associated revenue until title to the crude oil
passes to the buyer. This leads to significant volumes in transit, recorded as
inventory. These sales are shown in the tables as  Crude sales sold non-FCA .
 
 For
2004 there were large fluctuations in world crude oil prices due to increased
demand for crude oil and various political instabilities. The benchmark price
that we use on all of our crude sales contracts, regardless of destination and
the sales or Incoterms used, is Brent. Brent closed the year over the $40.00/bbl
mark, with an average for the year of $38.27/bbl. For 2003 the average was
$28.83/bbl. There was a lot of volatility, with the spread between high and low
daily Platts quotes of some $22.96/bbl in 2004 with a much lower spread in 2003
of $11.90/bbl.
 47
 
 
 The
average quarterly quotes for Brent were as follows:
 
 
 
 The
table below sets out the crude oil revenue, volumes sold and net realized
prices:
 
 Quantity
    
    Net
      realizedsold
    
    price
    
    Revenue*(mmbbls)*
    
    *($/bbl)*
    
    *($000's)***2004**Crude
      sales sold FCA
    
    
    **-**
    
    
    **-**
    
    
    **-**Crude
      sales sold non-FCA
    
    
    **23.32**
    
    
    **31.18**
    
    
    **727,221**Kazgermunai
      export sales
    
    
    **6.98**
    
    
    **26.59**
    
    
    **185,632**Royalty
      payments
    
    
    **4.10**
    
    
    **19.52**
    
    
    **80,027**Total
    
    
    **34.40**
    
    
    **28.86**
    
    
    **992,880**2003Crude
      sales sold FCA
    
    
    2.89
    
    
    15.50
    
    
    44,781Crude
      sales sold non-FCA
    
    
    19.40
    
    
    23.22
    
    
    450,542Kazgermunai
      export sales
    
    
    5.70
    
    
    17.78
    
    
    101,350Royalty
      payments
    
    
    2.03
    
    
    12.05
    
    
    24,453Total
    
    
    30.02
    
    
    20.69
    
    
    621,1262002Crude
      sales sold FCA
    
    
    12.74
    
    
    13.48
    
    
    171,711Crude
      sales sold non-FCA
    
    
    10.21
    
    
    22.70
    
    
    231,766Kazgermunai
      export sales
    
    
    2.94
    
    
    14.22
    
    
    41,813Royalty
      payments
    
    
    3.48
    
    
    9.27
    
    
    32,247Crude
      oil domestic sales
    
    
    0.50
    
    
    7.15
    
    
    3,577Total
    
    
    29.87
    
    
    16.11
    
    
    481,114
 
 As in
our net return discussion, net realized prices are dependent on the world price
for crude oil, the export route used and the point of sale or terms of sales,
all of which may vary significantly from period to period. Our differential from
Brent is our key performance indicator.
 
 48PetroKazakhstan
      Inc.
 
 
 *2004
versus 2003:*
 
 4
    Our
      increase of $371.8 million in crude oil sales for 2004 compared to 2003
      was due to the increased market price for crude oil (average Brent for
      2004 increased by $9.44/bbl) and higher sales volumes realized on non-FCA
      terms.4
    The
      positive effect from the increase in market prices was partially offset by
      higher hedging expenses that decreased our revenue by $42.1
      million.4
    Royalty
      payment volumes are physical deliveries made quarterly in arrears for all
      fields with the exception of our North Kumkol and Kazgermunai fields.
      There were no royalty in-kind volumes in first half of 2003, because we
      settled our royalty obligations with cash
  payments.
 
 *2003
versus 2002:*
 
 4
    Our
      increase of $140.0 million in crude oil revenue for 2003 compared to 2002
      was due to the increase in the average price we receive for our exported
      crude oil. Our total volumes of crude oil sold were virtually unchanged as
      our increase in production was processed through our refinery.4
    We
      increased our net realized price by $4.58/bbl. We achieved this increase
      mainly because average Brent for the year was $3.81/bbl higher when
      compared to 2002. Additionally, we increased our non-FCA volumes, which
      obtain a higher price, as the sale is made closer to the final
      destination.4
    Kazgermunai
      also contributed to the increase because they increased crude oil revenue
      by $59.5 million due to an almost doubling of export volumes and a $3.56
      increase in the price received per barrel.4
    We
      have dramatically increased the percentage of our oil export sales sold
      through non-FCA contracts in 2003, which were 64.6% in 2003 (34.2% in
      2002). By the end of 2003 there were no crude oil sales sold on an FCA
      basis.
 
 ***Refined
products***
 The
tables below set forth the related tonnes of refined products sold, the average
prices obtained and revenues received for 2004, 2003 and 2002:
 
 Tonnes
    
    Average*Year
      ended December 31*
    
    sold
    
    price
    
    Revenue*($/tonne)*
    
    *($000's)***2004**
    
    
    **3,298,956**
    
    
    **193.82**
    
    
    **639,405**2003
    
    
    3,617,085
    
    
    133.07
    
    
    481,3262002
    
    
    3,160,062
    
    
    105.26
    
    
    332,639
 
 *2004
versus 2003:*
 
 Refined
product revenues of $639.4 million in 2004 showed an increase of $158.1 million
as compared to 2003. The main contributing factors were as follows:
 
 4
    Strong
      world crude oil prices during the period, which resulted in higher average
      product prices in Kazakhstan and its neighboring countries. This increased
      revenues by $160.1 million in 2004.4
    The
      shift from FCA to non-FCA export terms during the period. A portion of the
      non-FCA sales price includes the recovery of transportation costs to the
      delivery point where title transfers to the customer, usually at the
      Kazakhstan border. This transfer to non-FCA terms added approximately
      $40.3 million to refined products revenues.4
    The
      sale of our new product VGO, a product not produced or sold in 2003. The
      commissioning of the Vacuum Distillation Unit at our Shymkent refinery in
      January 2004 allowed us to further refine Mazut, a low-grade product, into
      VGO, which realizes a considerably higher price on the export market. VGO
      sales generated $66.6 million of revenues in 2004.4
    The
      foregoing factors were partially offset by $42.3 million due to the
      decrease in sales of refined
products.
 49
 **
 *2003
versus 2002:*
 
 The
revenue increase in 2003 of $148.7 million was due to our higher average
realized price of $133.07/tonne (compared to $105.26/tonne in 2002) and our
higher sales volumes of 3.6 million tonnes (compared to 3.2 million tonnes in
2002).We were able to obtain higher prices and volumes for 2003 as compared to
2002, as demand in Kazakhstan increased.
 
 We
increased our refinery throughput in 2003, as we were experiencing interruptions
in our ability to export crude oil at the beginning of the year. This led to a
457,023 tonne, or 14.5%, increase in refined product sales. Our average price
increase of $27.81/tonne was mainly due to increases in prices received for
gasoline and diesel.
 
 **PRODUCTION
EXPENSES**
 
 Production
expenses relate to the cost of producing crude oil in our Upstream operations.
Based on the number of barrels of oil produced, these costs were as
follows:
 
 Production
    
    Per
      barrel of*Year
      ended December 31*
    
    expenses
    
    oil
      produced*($000 s)*
    
    *($/bbl)***2004**
    
    
    **89,339**
    
    
    **1.62**2003
    
    
    65,516
    
    
    1.192002
    
    
    60,596
    
    
    1.22
 
 *2004
versus 2003:*
 
 Production
expenses increased by $23.8 million, or $0.43/bbl, for the year ended December
31, 2004. The main contributing factors were as follows:
 
 4
    The
      continued increase in water cut at our Kumkol South, South Kumkol and
      Kumkol North fields and additional wells placed on artificial lift
      resulted in increased expenditures of $5.9 million, or $0.11/bbl.
      Additional investments will be made during 2005 on water handling
      facilities which we expect to reduce our production expenses4
    In
      our KAM fields, we are operating single well batteries pending completion
      of infrastructure. We also commissioned a number of new facilities:
      Aryskum central processing facility, Aryskum gas compressor for gas
      re-injection, Maibulak water injection, Aryskum pumping station on our KAM
      pipeline, and we commenced installation of artificial lift, all of which
      led to higher costs of approximately $6.8 million, or
      $0.12/bbl.4
    Direct
      production expenses in our joint ventures did not significantly change in
      2004 compared to 2003. However, our production expenses in 2003 included
      adjustments in our Turgai joint venture related to 2002 and the reversal
      of over accrued insurance costs, which reduced 2003 expenses by $2.3
      million. There were also significant changes in the levels of inventory in
      Turgai that impacted our production expenses. These factors had an impact
      of $0.13/bbl on our consolidated production
  costs.
 
 *2003
versus 2002:*
 
 Production
expenses increased by $4.9 million in 2003. The main reason was the 11.4%
increase in production volumes, which led to an increase of $3.8 million. The
remaining $1.1 million was due to increased costs because of the increasing
production of formation water.
 
 50PetroKazakhstan
      Inc.
 
 
 **ROYALTIES
AND TAXES**
 
 The
following table sets forth the components of royalties and taxes:
 
 *($000 s)*
    
    **2004**
    
    2003
    
    2002Royalties
      and production bonus
    
    
    **81,185**
    
    
    56,016
    
    
    47,892Tax
      assessments
    
    
    **14,452**
    
    
    5,401
    
    
    5,121ARNM
      assessment
    
    
    **5,045**
    
    
    -
    
    
    -Other
      taxes
    
    
    **25,762**
    
    
    20,878
    
    
    15,701Royalties
      and taxes
    
    
    **126,444**
    
    
    82,295
    
    
    68,714
 
 ***Royalties
and production bonus***
 Royalties
are levied at differing rates for each of our oil fields. The table below sets
forth the parameters for each production field. Royalty terms remain the same
throughout the term of the license.
 
 Annual
      productionat
      which
    
    Effective
    
    Effective
    
    Effectivemaximum
      royalty
    
    average
      royalty
    
    average
      royalty
    
    average
      royaltyField
    
    Range
    
    rate
      is charged
    
    rate
      for 2004
    
    rate
      for 2003****
    
    rate
      for 2002****Kumkol
      South
    
    
    3.0
      - 15.0
    %
    
    11.62
      mmbbls
    
    
    **8.9**
    **%**
    
    10.3
    %
    
    10.9
    %Kumkol
      North
    
    
    9
    %
    
    Flat
    
    
    **9.0**
    **%**
    
    9.0
    %
    
    9.0
    %South
      Kumkol
    
    
    10
    %
    
    Flat
    
    
    **10.0**
    **%**
    
    10.0
    %
    
    10.0
    %Kyzylkiya
    
    
    1.5
      - 2.5
    %
    
    24.8
      mmbbls*
    
    
    **1.5**
    **%**
    
    1.5
    %
    
    1.5
    %Aryskum
    
    
    1.5
      - 2.5
    %
    
    52.7
      mmbbls*
    
    
    **1.5**
    **%**
    
    1.5
    %
    
    1.5
    %Maibulak
    
    
    3.0
      - 6.0
    %
    
    3.9
      mmbbls
    
    
    **3.0**
    **%**
    
    3.0
    %
    
    3.0
    %Kazgermunai
      Fields
    
    
    3.0
      - 15.0
    %
    
    11.62
      mmbbls
    
    
    **8.94**
    **%**
    
    6.12
    %
    
    4.5
    %
 ***
    *Royalty
      rate is based upon cumulative life of field
    production.*
 
 Royalties
and production bonus for the year ended December 31, 2004 were $81.2 million,
which represented an effective overall royalty rate of 7.9% excluding production
bonuses of $0.7 million for our Kumkol North field. Royalties and production
bonus for 2003 were $56.0 million, which represented an effective overall
royalty rate of 8.6% excluding production bonuses of $1.4 million for Kumkol
North, Kumkol South and South Kumkol fields. The main reason for the lower
overall royalty rate was that a higher proportion of production came from fields
with lower royalty rates. Despite the decrease in the average rate, royalties
and taxes increased due to the increase in crude oil prices.
 
 Royalties
and production bonus for 2002 were $47.9 million, an overall royalty rate of
9.0%, after excluding the production bonuses of $4.0 million. The reason for the
lower overall royalty rate in 2003 was that a higher proportion of production
came from fields with lower royalty rates.
 
 Our
production bonus expense was $0.7 million in 2004, $1.4 million in 2003 and $4.0
million in 2002. In 2004 production bonus expenses related only to our North
Kumkol field. In 2003 and 2002 our production bonuses were related to our Kumkol
South, South Kumkol and North Kumkol fields. The bonus decreased by $2.6 million
in 2003, because we paid the final amount for our Kumkol South field in February
of 2003 and on our South Kumkol field in October of 2003. We have to pay a
further $1.0 million (our 50% share) for North Kumkol when the cumulative
production reaches 15,000,000 tonnes (116.2 million barrels), which we expect to
occur in 2005.
 
 51
 
 
 ***Tax
assessments***
 Our tax
assessments of $14.5 million in 2004 included the following
amounts:
 
 4
    $8.0
      million in fines and penalties on road fund taxes related to assessments
      for 1998-1999 and $2.1 million for royalties on associated gas related to
      tax assessments for 2000-2001. See Note 18 to our consolidated financial
      statements for the year ended December 31, 2004.4
    Additional
      $2.9 million provided for 2002 and 2003, because we lost the tax cases on
      royalties on associated gas for 2000-2001. An additional provision of $1.6
      million for penalties was recorded relating to interest charges on this
      tax assessment.
 
 Tax
assessments of $5.4 million in 2003 included the following amounts related to
the tax assessments for 2000 and 2001:
 
 4
    $2.1
      million of the assessments related to the revaluation of assets for tax
      purposes.4
    $1.7
      million of social and employment fund taxes.4
    $0.2
      million on royalties on associated gas.4
    $0.8
      million of the assessments related to transfer pricing and $0.6 million of
      other taxes.
 
 Tax
assessments of $5.1 million in 2002 include $2.9 million related to assessments
for 1998 and 1999 and $2.2 million related to assessments for 2000 and
2001.
 
 See
Note 18 to our consolidated financial statements for the year ended December 31,
2004.
 
 ***ARNM
assessment***
 The
Agency for Regulation of Natural Monopolies and Protection of Competition
( ARNM ) alleged that PetroKazakhstan Oil Products ( PKOP ), our subsidiary that
operates our refinery, charged prices for refined oil products that in total
were $6.3 million in excess of ARNM authorized maximum prices. In April 2004,
following a Supreme Court decision, we paid $3.6 million to satisfy the
assessment. PKOP provided an additional $1.4 million in December 2004. See Note
18 to our consolidated financial statements for the year ended December 31,
2004.
 
 ***Other
taxes***
 Other
taxes of $25.8 million in 2004 included:
 
 4
    Excise
      tax on refined products ($12.9 million in 2004 compared to $12.4 million
      in 2003).4
    Payment
      to satisfy an environmental claim ($2.0 million in 2004, nil in
      2003).4
    Non-recoverable
      value added tax on crude oil ($4.3 million in 2004 compared to $4.1
      million in 2003).4
    Various
      taxes, including property taxes, road fund and other ($6.6 million in 2004
      compared to $4.4 million in 2003).
 
 The
increase in other taxes for 2003 compared to 2002 of $5.2 million was mainly due
to $4.1 million of expensed VAT and various other taxes. Tax legislation
amendments introduced at the beginning of 2003 required the expensing of a
portion of VAT for crude oil purchases made by the refinery.
  52PetroKazakhstan
      Inc.
 
 
 **TRANSPORTATION**
 
 Transportation
costs are the costs of shipping crude oil from our central processing facility
located at South Kumkol ( CPF ) to our Shymkent refinery, our rail terminals at
Tekesu (adjacent to our refinery), Dzhusaly and the terminal at Atasu for oil
destined for China. It also includes the costs of trucking crude oil from our
KAM fields to the CPF, railway transportation, vessels chartering and pipeline
costs under non-FCA crude sales contracts and for the export of refined
products. Transportation costs also include transportation of crude produced by
our Kazgermunai joint venture to its export customers.
 
 As
noted in our net return discussion, the changes in our transportation and
selling costs are largely dependent on our choice of export routes and the terms
of sales, which vary from period to period. Our differential from Brent is the
key performance indicator, which can be used to assess the results of our
exports. Please see the discussion of our differential in *Overview
and Strategy, Key Performance Indicators.*
 
 The
table below sets out the components of transportation costs:
 
 *($000 s)*
    
    **2004**
    
    2003
    
    2002Pipeline
    
    
    **33,207**
    
    
    58,004
    
    
    56,230Kazgermunai
      transportation
    
    
    **31,990**
    
    
    18,675
    
    
    8,462Crude
      oil export
    
    
    **157,529**
    
    
    137,251
    
    
    93,305Refined
      products export
    
    
    **40,320**
    
    
    2,011
    
    
    -Other
    
    
    **8,763**
    
    
    9,046
    
    
    5,804Total
    
    
    **271,809**
    
    
    224,987
    
    
    163,801
 
 ***Pipeline***
 Pipeline
costs decreased by $24.8 million during 2004 compared to 2003 primarily
reflecting the following:
 
 4
    Decrease
      of $19.8 million, as a result of a decrease in volumes sold for export
      through the Kumkol - Shymkent pipeline (2.5 mmbbls in 2004 compared to
      15.7 mmbbls in 2003), partially offset by higher tariffs for the Kumkol -
      Shymkent pipeline in 2004 ($1.66/bbl in 2004 compared to $1.52/bbl in
      2003) due to the strengthening of the Tenge to the U.S.
      dollar.4
    Decrease
      of $10.5 million in non-FCA pipeline costs (nil for 2004 compared to $10.5
      million in 2003) because we did not use the Atyrau - Samara
      pipeline.4
    Decrease
      of $1.2 million, as a result of a decrease of 4.2 mmbbls in crude oil
      volumes sent to the refinery through the Kumkol - Shymkent
      pipeline.4
    A
      partial offset attributable to an increase of $6.7 million on volumes
      shipped through our KAM pipeline and through the Atasu terminal for China.
      Our KAM pipeline became operational in the third quarter of 2003; hence
      our expenses related to the KAM pipeline are higher by $4.0 million for
      2004 compared to 2003, as there were no expenses for the first half of
      2003. Our transportation expenses through Atasu terminal were higher by
      $2.0 million as we shipped 5.0 mmbbls in 2004 compared to 2.8 mmbbls in
      2003.
 
 Pipeline
costs slightly increased by $1.8 million during 2003 compared to 2002 primarily
reflecting the following:
 
 4
    $2.7
      million increase attributable to higher volumes supplied to Downstream for
      processing (24.51 mmbbls in 2003 compared to 21.21 mmbbls in
      2002).4
    $2.5
      million due to the increased export tariff to Shymkent ($1.52/bbl in 2003
      versus $1.41/bbl in 2002).4
    $1.6
      million increase in non-FCA pipeline costs ($10.5 million for 2003
      compared to $8.9 million for 2002) because of our use of the Atyrau-Samara
      pipeline for the first six months of 2003.4
    These
      increases were partially offset by $5.0 million in savings from using our
      KAM pipeline, when compared to exports of crude oil through our Tekesu
      rail terminal located in Shymkent.
 
 53
 
 
 ***Kazgermunai
transportation***
 Kazgermunai
transportation increased by $13.3 million in 2004 compared to 2003 due to a 22%
increase in sales volumes and increases in railway tariffs.
 
 ***Crude
oil export***
 Export
transportation of crude oil increased by $20.3 million in 2004, as we moved our
sales points closer to end-users. This included $8.2 million for sea freight and
demurrage fees, as we chartered our own vessels for crude deliveries into the
Mediterranean, and $3.6 million of additional railcar lease expenses in line
with our strategy of securing control over our transportation. The remaining
increase was the combination of higher crude export sales volumes and a
different mix of routes.
 
 Export
transportation of crude oil increased by $44.0 million or 47.1% for 2003
compared to 2002 due to our increase in non-FCA sales. Non-FCA sales increased
by 90.0% in 2003 compared to 2002 (19.40 mmbbls versus 10.21 mmbbls).
Additionally, the ARNM approved a 6% increase in rail tariffs effective January
1, 2003.
 
 ***Refined
products export***
 In 2004
export transportation of refined products increased by $38.3 million, as we
exported 435,800 tonnes of various products on a non-FCA basis as compared to
only 22,000 tonnes during 2003.
 
 ***Other***
 Other
transportation costs are mainly trucking costs incurred to transport crude oil
from the KAM fields to the CPF located at Kumkol.
 
 **REFINING**
 
 Refining
costs represent the direct costs related to processing all crude oil including
tollers  volumes at the refinery.
 
 Refining
costs for 2004 were $21.6 million ($0.80/bbl) compared to $17.8 million
($0.58/bbl) in 2003. The main reasons for the $3.8 million increase in refining
costs were higher repair costs incurred during the turnaround and to a lesser
extent, additional purchased steam and electric power related to the start-up
and operation of the Vacuum Distillation Unit during 2004. Major repairs of the
main crude processing units, visbreaker and storage facilities were also
completed throughout the year.
 
 Refining
costs for 2003 were $17.8 million ($0.58/bbl) compared to $21.7 million
($0.80/bbl) in 2002. The main reason for the $3.9 million decrease in refining
costs was that purchased steam costs were lower as a result of process
improvements and equipment upgrades combined with a lower price per unit. With
no major turnaround in 2003, the refinery s repairs, maintenance and other
expenses were also $1.0 million lower.
 
 **CRUDE
OIL AND REFINED PRODUCT PURCHASES**
 
 Crude
oil and refined product purchases represent the expensed portion of crude oil
purchased for the refinery from third parties, as well as refined products
purchased for resale. Purchases and sales between our Upstream and Downstream
business units are eliminated on consolidation.
 
 54PetroKazakhstan
      Inc.
 
 
 Our
purchases of crude oil and refined products were as follows:
 
 *($000 s)*
    
    **2004**
    
    2003
    
    2002Crude
      oil
    
    
    **104,575**
    
    
    55,886
    
    
    69,410Refined
      products
    
    
    **6,764**
    
    
    574
    
    
    3,917Total
    
    
    **111,339**
    
    
    56,460
    
    
    73,327
 
 Crude
oil purchases are higher by $48.7 million in 2004 as compared to 2003. During
the first quarter of 2004 we repurchased royalty-in-kind volumes for $17.1
million and subsequently resold them. The remaining purchases of crude oil were
made from our joint ventures for further refining. The volumes purchased from
the joint ventures during 2004 and 2003 are approximately the same, however, the
increase in world crude oil prices led to higher purchase costs.
 
 **SELLING**
 
 Selling
expenses for crude oil are comprised of customs, quality inspection and costs
related to the export of crude oil. Selling expenses for refined products are
comprised of the costs of operating the regional distribution centres and other
administrative costs related to our Downstream operations.
 
 *($000 s)*
    
    **2004**
    
    2003
    
    2002Crude
      oil
    
    
    **18,084**
    
    
    10,495
    
    
    3,471Refined
      products
    
    
    **19,850**
    
    
    18,034
    
    
    19,782Total
    
    
    **37,934**
    
    
    28,529
    
    
    23,253
 
 *2004
versus 2003:*
 
 The
increase in crude oil selling expenses in 2004 was mainly due to marketing
management fees of $3.8 million charged by our partner in Turgai related to
Turgai s export sales through the CPC pipeline.
 
 In
addition, Turgai selling expenses includes unloading fees, for crude oil sold at
the CPC pipeline inlet at Atyrau. These loading fees were $1.4 million for 2004.
The remaining increases in crude oil selling expenses are attributable to the
administrative costs of our marketing and transportation business unit due to
the increased level of activity.
 
 Selling
expenses related to refined products increased in 2004 due to increases in
storage fees, transportation security fees and personnel costs. We did, however,
take measures in the fourth quarter of 2004 to rationalize the domestic
wholesale business resulting in the closure of two low volume distribution
outlets and other cost reduction measures.
 
 *2003
versus 2002:*
 
 The
increase in crude oil selling expenses during 2003 compared to 2002 was the
direct result of increased export sales volumes related to non-FCA routes, for
which all selling costs are borne by us, as well as the increase in Kazgermunai
sales and a reclassification of certain crude oil marketing costs to selling
from general and administrative expenses.
 
 The
decrease in selling expenses on refined products during 2003 was due to the fact
that in 2002 Downstream refunded $1.1 million of transportation discounts it had
received, as it had not met the throughput obligations under a transportation
contract. This contract is no longer in effect.
 
 55
 
 
 **GENERAL
AND ADMINISTRATIVE**
 
 The
table below analyzes total general and administrative costs for Upstream,
Downstream and Corporate. In the case of Upstream and Downstream the general and
administrative costs are also reflected on a per barrel basis.
 
 General
      and
    
    Per
      barrel of oiladministrative
    
    produced
      or processed**($000 s)*
    
    *($/bbl)***2004**Upstream
    
    
    **34,955**
    
    
    **0.63**Downstream
    
    
    **14,493**
    
    
    **0.53**Corporate
    
    
    **11,467**Total
    
    
    **60,915**2003Upstream
    
    
    32,721
    
    
    0.59Downstream
    
    
    16,075
    
    
    0.53Corporate
    
    
    5,483Total
    
    
    54,2792002Upstream
    
    
    37,093
    
    
    0.75Downstream
    
    
    17,216
    
    
    0.64Corporate
    
    
    4,570Total
    
    
    58,879
 **
Including tollers  volumes*
 
 *2004
versus 2003:*
 
 4
    Downstream
      general and administrative expenses were lower in 2004, because in 2003 we
      recorded severance payments to the employees of the non-core business
      units divested in 2003 and related divestiture
    expenditures.4
    The
      increase in corporate expenses was mainly due to $4.0 million of
      compensation cost being recognized for stock options pursuant to a new
      accounting standard. See Note 2 to our consolidated financial statements.
      The remaining increase in corporate and Upstream expenses is attributable
      to increased activity levels.
 
 *2003
versus 2002:*
 
 4
    Upstream
      expenses decreased by $4.4 million in 2003 due to the reclassification of
      certain costs relating to crude oil marketing to selling
      expenses.
 
 
 56PetroKazakhstan
      Inc.
 
 
 **INTEREST
AND FINANCING**
 
 The
following table sets forth our interest and financing costs and any related
amortization of debt issue costs or discounts upon issuance of the debt
instrument:
 
 *($000 s)*
    
    **2004**
    
    2003
    
    20029.625%
      Notes
    
    
    **14,539**
    
    
    11,860
    
    
    -Term
      facility
    
    
    **6,082**
    
    
    9,858
    
    
    4,106Commitment
      fees and amortization of deferred charges on $100 million committed credit
      facility
    
    
    **629**
    
    
    -
    
    
    -Short-term
      debt
    
    
    **790**
    
    
    754
    
    
    1,47012%
      Notes
    
    
    **-**
    
    
    8,718
    
    
    24,936Kazgermunai
      debt
    
    
    **1,331**
    
    
    1,657
    
    
    3,447Term
      loans
    
    
    **503**
    
    
    594
    
    
    332PKOP
      bonds
    
    
    **469**
    
    
    2,576
    
    
    1,514Less
      portion capitalized
    
    
    **(13**
    **)**
    
    (438
    )
    
    (332
    )Total
    
    
    **24,330**
    
    
    35,579
    
    
    35,473
 
 *2004
versus 2003:*
 
 4
    Our
      9.625% Notes interest expense increased in 2004 by $2.7 million, as the
      Notes were issued in February 2003.4
    Our
      term facility interest expense decreased by $3.8 million in 2004 due to
      the full repayment of the facility.4
    PKOP
      bonds were fully redeemed on February 26, 2004.4
    Our
      12% Notes interest expense in 2003 was $8.7 million including $6.6 million
      of issue costs that were expensed when we redeemed these notes on February
      2, 2003.
 
 *2003
versus 2002:*
 
 4
    Our
      9.625% Notes interest expense arose only in 2003 as these notes were
      issued in February 2003.4
    Our
      term facility interest expense increased by $5.8 million due to the
      repayment of the previous $60.0 million facility and entering a new $225.0
      million facility.4
    Our
      12% Notes interest expense in 2003 is $8.7 million including $6.6 million
      of issue costs that were expensed when we redeemed these notes, whereas
      2002 includes interest for the entire year.4
    Interest
      on our Kazgermunai debt decreased by $1.8 million due to an $18.3 million
      (our 50% share) repayment of the debt.4
    Interest
      on our PKOP bonds increased by $1.1 million due to the issuance of the
      remaining 115,200 bonds in February
2003.
  DEPRECIATION
AND DEPLETION
 
 Depreciation
      and
    
    Depreciation
      anddepletion
    
    depletion*($000 s)*
    
    *($/bbl*)***2004**Upstream
    
    
    **83,927**
    
    
    **1.52**Downstream
    
    
    **20,338**
    
    
    **0.89**Corporate
    
    
    **1,255**Total
    
    
    **105,520**
 ***
    *Downstream
      includes tollers  volumes*
 57
 
 
 
 Depreciation
      and
    
    Depreciation
      anddepletion
    
    depletion*($000 s)*
    
    *($/bbl*)*2003Upstream
    
    
    63,321
    
    
    1.15Downstream
    
    
    18,849
    
    
    0.62Corporate
    
    
    182Total
    
    
    82,3522002Upstream
    
    
    32,970
    
    
    0.66Downstream
    
    
    13,347
    
    
    0.49Corporate
    
    
    94Total
    
    
    46,411
 ***
    *Downstream
      includes tollers  volumes*
 
 The
increase in Upstream depreciation and depletion expense of $20.6 million was
mainly due to the increase in our depletable assets and future development
costs. Our Upstream depletion expense for 2004 includes accretion expense
relating to our asset retirement obligations of $2.4 million ($2.1 million in
2003 and $1.8 million in 2002).
 
 Upstream
depreciation and depletion increased by $30.4 million during 2003 compared to
2002. This increase was mainly due to an increase in the amounts subject to
depletion or depreciation as a result of capital expenditures. Our 11.4%
increase in production and 10.4% decline in proved producing reserves also
increased our depletion charge. Downstream depreciation increased by $5.5
million in 2003 compared to 2002 mainly due to additional depreciation for
assets, which were under construction in 2002.
 
 **UNUSUAL
ITEMS**
 
 There
were no unusual items in 2004 and 2003.
 
 We were
named as defendants in a claim filed by a company alleging it was retained under
a consulting contract. The arbitration decision was received in 2002 and we
accrued and paid $7.1 million for full settlement of the claim.
 
 **INCOME
TAXES**
 
 **2004**
    
    2003
    
    2002Upstream
    
    
    **218,214**
    
    
    78,893
    
    
    71,807Downstream
    
    
    **75,253**
    
    
    72,370
    
    
    18,691Corporate
    
    
    **7,616**
    
    
    4,359
    
    
    9,845Total
    
    
    **301,083**
    
    
    155,622
    
    
    100,343
 
 Income
taxes increased by $145.5 million in 2004 compared to 2003 mainly due to the
following:
 4
    $98.5
      million was due to an increase in income before taxes.4
    We
      provided for $35.0 million of excess profit tax in Turgai for 2004. See
      Note 18 to our consolidated financial statements.4
    $10.1
      million of tax assessments settled in 2004 are not deductible for
      tax.4
    In
      Kazgermunai we incurred an additional $12.2 million of income tax because
      the marginal tax rate exceeded the statutory tax rate resulting in the
      effective tax rate becoming 38.6% for 2004. See Kazgermunai discussion in
      the following paragraphs.
 The
increase in income taxes of $55.3 million in 2003 was mainly the result of the
increase in sales volumes and in the price of crude oil and refined products,
which led to an increase in income before income taxes of $211.1 million.
 
 58PetroKazakhstan
      Inc.
 
 
 Kazakhstani
income taxes are based upon stabilized tax regimes under the terms of our
hydrocarbon contracts. The majority of the differences are temporary differences
where an expense item is recorded for Canadian GAAP purposes in a different
period than allowed under the terms of our hydrocarbon contracts. The income tax
rate is 30%.
 
 The
foundation agreement for Kazgermunai provides for a tax on the profits of
Kazgermunai with respect to its operations in the Akshabulak, Nurali and Aksai
fields. The foundation agreement provides for taxes of:
 
 Range*($ millions)*
    
    Income
      tax rateUp
      $20.0
    
    
    25
    %$20.0
      - $30.0
    
    
    30
    %$30.0
      - $40.0
    
    
    35
    %Over
      $40.0
    
    
    40
    %
 
 Income
taxes in our corporate segment are the withholding taxes on the dividends paid
from subsidiaries in Kazakhstan to Canada.
 
 Excess
profit tax has been negotiated with the Kazakhstani government in each
hydrocarbon contract with the exception of the Kazgermunai licenses. With
respect to the Kumkol South, South Kumkol and KAM fields, we are subject to
excess profit tax at rates that vary from 0% to 30% based on the cumulative
internal rate of return. With respect to North Kumkol, we are subject to excess
profit tax at rates that vary from 0% to 50% based on the cumulative internal
rate of return.
 
 We have
provided $70.0 million (our 50% share) for excess profit tax for North Kumkol in
2004. This amount is included in our current income taxes. Because excess profit
tax is deductible in the following year, we have recorded a future income tax
asset of $35.0 million, which represents 50% of our provision for excess profit
tax.
 
 We did
not incur excess profit taxes in 2004 for any of our other fields.
 
 ***Strategy:
Capitalize on development opportunities and explore our undeveloped
properties***
 
 **CAPITAL
EXPENDITURES AND COMMITMENTS**
 
 The
table below sets forth a breakdown of our capital expenditures in 2004, 2003 and
2002:
 
 **2004**
    
    2003
    
    2002UpstreamDevelopment
      wells
    
    
    **30,898**
    
    
    56,767
    
    
    40,489Facilities
      and equipment
    
    
    **90,945**
    
    
    92,002
    
    
    67,884Exploration
    
    
    **27,150**
    
    
    34,365
    
    
    23,502DownstreamRefinery
      HS&E
    
    
    **2,242**
    
    
    704
    
    
    773Refinery
      sustaining
    
    
    **5,802**
    
    
    2,571
    
    
    4,019Refinery
      return projects
    
    
    **3,661**
    
    
    15,024
    
    
    3,364Marketing
      and other
    
    
    **3,982**
    
    
    771
    
    
    71Corporate
    
    
    **1,272**
    
    
    1,009
    
    
    -Total
      capital expenditure
    
    
    **165,952**
    
    
    203,213
    
    
    140,102Less
      accrued amounts
    
    
    **(2,722**
    **)**
    
    (6,743
    )
    
    (3,250
    )Total
      cash capital expenditure
    
    
    **163,230**
    
    
    196,470
    
    
    136,852
 
 Capital
expenditures amounted to $166.0 million for the year 2004, compared to our
budget of $176.0 million.
 59
 
 
 *Development
wells.* In
2004 we continued developing our KAM fields and invested approximately $12.3
million in drilling 23 wells. At North Nurali, we have completed stimulation,
testing and evaluation work at 3 wells and drilled an additional 2 wells, all of
which amounted to $2.7 million. Turgai invested approximately $8.0 million (our
50% share) in drilling new wells. We have also spent $7.2 million (our 50%
share) in Kazgermunai on further development of the Akshabulak, Aksai and Nurali
fields.
 
 *Facilities
and equipment.* We
spent approximately $24.6 million for facilities under our KAM fields
development program, which included construction of flowlines and road
facilities, installation of gas re-injection facilities in the Aryskum field as
well as installation of artificial lift on certain wells. We have invested $10.0
million in upgrades, tanks, storage facilities and equipment for our crude
loading facilities at Dzhusaly and continued to expand our railcar fleet by
investing $30.0 million for an additional 800 railcars. Kazgermunai spent $5.9
million (our 50% share) on the first phase of our gas utilization plant in our
Akshabulak field and we plan to spend $5.6 million in 2005 to complete the
facility.
 
 *Exploration.* Our
2004 exploration program focused on our Aryskum, Kolzhan, Zhamansu and Doshan
licences. We acquired and analyzed seismic data and drilled exploration wells,
investing $27.2 million in 2004. We have drilled 5 wells in Aryskum in 2004 and
discovered a new reservoir, which will be further appraised in 2005. We have
also carried out two seismic programs and drilled 5 wells on our Kolzhan
license, all of which encountered hydrocarbons. This program proved that we have
a northern extension to our Kyzylkiya field. An appraisal program is planned
over this area in 2005. In 2004 we became the operator of two blocks, Zhamansu
and Doshan in license 951 with a 75% interest. We spent $6.0 million on drilling
exploration wells in these blocks, which remain highly prospective and will be
further explored in 2005.
 
 Our
2005 capital expenditure program is currently allocated as follows:
 
 Business
      Unit
    
    (*$
      millions)*Upstream*(including joint**ventures)*
    
    
    211.0Downstream
    
    
    14.0Marketing
      and transportation
    
    
    2.0Corporate
    
    
    16.0Total
    
    
    243.0
 
 The key
items included within the capital budget are:
 
 ***Upstream***
 4
    Continued
      full field development of the KAM fields.4
    An
      exploration and appraisal program, including the drilling of 17
      wells.4
    Significant
      seismic programs, both 3D and 2D.4
    Development
      of the East Kumkol field.4
    Pilot
      test production phase of the North Nurali field.4
    Kumkol
      South infill drilling and production facilities
    enhancements.4
    Phase
      1 of the Kumkol South enhanced oil recovery ( EOR )
    project.4
    Commissioning
      of the Akshabulak gas plant for LPG production.4
    Commissioning
      of additional Akshabulak facilities for increased
    production.4
    Completion
      of Kumkol North development drilling and facilities
      enhancements.
 
 The
firm exploration and appraisal budget has been set at a base level of $20.0
million with additional funds available for potential appraisal wells and new
opportunities.
 
 ***Downstream***
 4
    Additional
      refinery equipment installation and process
  optimizations.4
    Expansion
      of retail stations.4
    Upgrading
      of equipment at distribution
centers.
 
 60PetroKazakhstan
      Inc.
 
 
 ***Corporate***
 4
    First
      phase of construction of a head office in Astana, subject to obtaining a
      building permit.
 
 We have
a commitment for construction of a gas plant at Kazgermunai; our 50% share is
$11.5 million. These commitments are included in our capital budget for 2005.
The remainder of our capital budget can be modified, if necessary, to meet
changing circumstances.
 
 Capital
investments are judged against our internal investment criteria that require
that:
 4
    Investments
      generate a real internal rate of return of 15%.4
    That
      the present value discounted at 10% of the return from the investment is
      sufficient to repay the investment plus a 50% premium.4
    The
      long term real Brent oil price is
$25.00/bbl.
 
 ***Contractual
commitments***
 In
addition to the above, we have the following contractual obligations as at
December 31, 2004:
 
 Total
      commitments by period*($
      millions)*
    
    Total
    
    Within
      1 year
    
    1-3
      years
    
    4-5
      years
    
    After
      5 yearsLong-term
      debt
    
    
    134.9
    
    
    15.5
    
    
    3.7
    
    
    1.9
    
    
    113.8Estimated
      interest payments
    
    
    92.8
    
    
    17.9
    
    
    36.9
    
    
    37.6
    
    
    0.4Operating
      leases
    
    
    104.0
    
    
    43.0
    
    
    59.8
    
    
    1.2
    
    
    -Capital
      leases
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -Future
      site restoration costs
    
    
    32.5
    
    
    -
    
    
    -
    
    
    -
    
    
    32.5Work
      commitments
    
    
    6.1
    
    
    3.5
    
    
    2.6
    
    
    -
    
    
    -Purchase
      obligations
    
    
    12.2
    
    
    12.2
    
    
    -
    
    
    -
    
    
    -Total
    
    
    382.5
    
    
    92.1
    
    
    103.0
    
    
    40.7
    
    
    146.7
 
 Long-term
debt - please refer to Note 11 in our consolidated financial statements for the
year ended December 31, 2004.
 
 Estimated
interest payments relate to our outstanding debt balances as at December 31,
2004.
 
 Operating
leases are mainly for rail cars that we use to transport our crude oil and
refined products and certain equipment used in our Upstream operations. Although
we are committed to lease rail cars, our contracts allow the termination with a
30-day notice. We have no capital leases.
 
 We have
an obligation of $32.5 million for future site restoration costs as at December
31, 2004, which are the estimated future cash outflows discounted at 8.5%. The
total undiscounted estimated cash flows required to settle the obligations are
$77.4 million with the expenditures being incurred over ten years commencing in
2014.
 
 Work
commitments are non-discretionary expenditures for seismic and drilling that we
have contractually committed to under the terms of our Hydrocarbons Licenses.
 
 Purchase
obligations represent contractual obligations for goods and services for which
the services have yet to be provided or for which we have not yet taken title to
the goods. All other purchase commitments are discretionary.
 
 ***Sales
commitments***
 We have
sales commitments under contracts with two customers to supply an agreed volume
of crude oil within the first four months of 2005. The estimated value of these
commitments is approximately $43.1 million.
 
 61
 
 
 
 **LIQUIDITY**
 
 The
levels of cash, current assets and current liabilities as at December 31, 2004
and December 31, 2003 are set out below:
 
 *As
      at December 31 ($000 s)*
    
    **2004**
    
    2003Cash
      and cash equivalents
    
    
    **199,105**
    
    
    184,660Cash
      flow
    
    
    **560,491**
    
    
    399,975Working
      capital *
    
    
    **215,681**
    
    
    151,737Net
      debt **
    
    
    **(48,702**
    **)**
    
    135,220Ratio
      of cash flow to net debt
    
    
    **-**
    
    
    3.0Ratio
      of cash flow to fixed charges***
    
    
    **20.9**
    
    
    10.6Ratio
      of earnings to fixed charges ****
    
    
    **30.9**
    
    
    13.6
 ***
    *Working
      capital is net of cash and short-term debt*****
    *Net
      debt includes short-term and long-term debt less
  cash******
    *Fixed
      charges include interest expense and preferred dividends before
      tax*******
    *Earnings
      is income before income taxes plus fixed
  charges*
 
 Our net
working capital has increased mainly due to increases in our accounts
receivable, inventory and prepaid expenses, partly offset by an increase in
accounts payable. Our accounts receivable increased mainly because we sold 1.5
mmbbls of crude oil close to year end with payment due 30 days after the sale.
Build up of unsold volumes of crude oil increased our inventory and prepaid
expenses. The main components of the increase in accounts payable are income and
excess profit tax, accrued dividends payable and amounts owed for crude oil
purchased from one of our joint ventures.
 
 Our
restricted cash is $47.7 million as at December 31, 2004 ($35.5 million at
December 31, 2003). Restricted cash includes $8.7 million of cash dedicated to a
debt service reserve account for our term facility and $39.0 million of cash
dedicated to a margin account for our hedging program. Though our term facility
was fully repaid as at December 31, 2004, we still have a balance in our debt
service reserve account because our hedging liability has not been discharged in
full (see Note 8 to our consolidated financial statements).
 
 The
restricted cash balance related to our hedging program increased by $14.0
million compared to December 31, 2003 due to the change in the market value of
our hedging contracts. Cash dedicated to our hedging margin account fluctuates
on a weekly basis with fluctuations in the future Brent price for crude oil. As
the year progresses we will settle our hedges, and the cash dedicated to our
hedging margin account will likely reduce and is expected to be nil by December
31, 2005. See discussion of our hedging contracts in Note 15 to our consolidated
financial statements for the year ended December 31, 2004.
 
 Our
long-term debt decreased substantially from $246.7 million at December 31, 2003
to $134.9 million at December 31, 2004, as we fully repaid our term facility at
the end of September.
 
 During
the year ended December 31, 2004 Kazgermunai repaid $25.6 million of its
long-term debt. Turgai repaid its shareholder loans of $22.0 million to us and
$22.0 million to our partner. Turgai also paid each partner dividends of $25.5
million in the fourth quarter of 2004.
 
 Our
9.625% Notes have a credit rating of B+ from Standard and Poors and Ba3 from
Moody s. We are in compliance with our debt covenants as of December 31,
2004.
 
 62PetroKazakhstan
      Inc.
 
 
 On May
25, 2004 we entered into a five and one half year $100.0 million committed
credit facility. This facility is unsecured, bears interest at LIBOR plus 2.65%
and is subject to annual review. $30.0 million of this facility has been
dedicated to cover margin calls under our hedging program. In the event our
credit rating decreases by 2 or more notches, we may be required to secure this
facility with crude oil export contracts.
 
 We also
have available working capital facilities of $67.0 million. We believe we have
sufficient funding and liquidity to meet our needs in 2005 through our cash flow
and available credit facilities.
 
 We have
$93.9 million in future income tax assets, the recoverability of which is
dependent on generating sufficient taxable income in our operating subsidiaries
to realize our future income tax assets. Seventy percent of our future income
tax assets are current and, accordingly, we expect to realize them within the
next year.
 
 **RISK
ANALYSIS**
 
 **BUSINESS
RISKS**
 
 ***Reserves
and production***
 The
addition of oil and gas reserves and our ability to develop these reserves is
one of the key factors to our success. New exploration acreage must be acquired
through acquisitions or obtaining additional licenses. We are actively pursuing
acquisitions while adhering to our investment criteria. We have successfully
acquired new exploration acreage in 2003 and 2004, including the Kolzhan,
Zhamansu, Doshan and Karaganda blocks. We believe we are well positioned to
continue to succeed as we have a demonstrated track record in discovering and
developing reserves, continual involvement with the industry in Kazakhstan and
with the Government of Kazakhstan and we have the financial capacity to execute
transactions. This is a highly competitive process.
 
 Our
ability to discover new reserves and develop our reserves is another key to our
success. We have introduced and continue to utilize Western technology in
exploring for and developing reserves. We have the financial capacity to acquire
and implement this technology but we compete for the staff and intellectual
capacity necessary to fully utilize this technology. We have successfully
addressed this through offering competitive compensation and recruiting on a
worldwide basis. The recruitment of staff is a highly competitive
process.
 
 ***Evaluation
of oil and gas reserves***
 The
process of estimating our oil and gas reserves is complex and requires
significant assumptions and decisions in the evaluation of engineering,
geological, geophysical and financial information. On an annual basis McDaniel
& Associates Consultants Ltd. of Calgary, Alberta, perform an independent
evaluation of our reserves. This reserve evaluation may change substantively
from year to year as a result of numerous factors, including but not limited to
the development and economic conditions, under which we operate our business. As
a result, despite all reasonable efforts involved in the process of evaluation,
the estimation of our reserves may materially change from period to period.
 
 ***Key
performance indicators***
 Please
refer to the section entitled *Key
Performance Indicators* of our
MD&A for a discussion of these indicators and their impact on our
business.
 
 ***Taxes***
 We have
been engaged in litigation and disputes related to tax assessments. Future tax
assessments could be significant as we experience inconsistent application and
interpretation of the tax legislation applicable to each of our hydrocarbon
contracts. The tax legislation applicable to each of our hydrocarbon contracts
is stabilized at the legislation in effect on the date of signing the contract,
all of which were signed from 1996 through 1998. As the legislation applicable
to our contracts is from five to eight years old, the expertise pertaining to
this legislation is diminishing within the tax inspectorate.
 63
 
 
 ***Kazakhstan
environment and legislation***
 We have
received assessments from the ARNM relating to the sale of refined products in
Kazakhstan. The impact of these assessments will be significant, if we do not
prevail in our view with respect to these assessments.
 
 We
believe we are currently in compliance with all existing environmental laws and
regulations. However, as new environmental laws are enacted and the old laws are
repealed, interpretation, application and enforcement of the laws may become
inconsistent. Compliance in the future could require significant expenditures,
which may adversely effect our operations.
 
 **MARKETING
RISKS**
 
 ***Commodity
prices***
 Commodity
price risk related to conventional crude oil prices is our most significant
market risk exposure. Crude oil prices are influenced by such worldwide factors
as Organization of Petroleum Exporting Countries actions, political events and
supply and demand fundamentals.
 
 **FINANCIAL
RISKS**
 
 See
Note 15 to our consolidated financial statements.
 
 **CRITICAL
ACCOUNTING ESTIMATES**
 
 **PROPERTY,
PLANT AND EQUIPMENT**
 
 We
follow the full cost method of accounting for oil and gas operations whereby all
acquisition, exploration and development expenditures are capitalized. This may
lead to the capitalization of costs for which no direct future benefit will be
obtained.
 
 We
perform an impairment test on a quarterly basis to assess whether the carrying
amount of our assets is recoverable from our undiscounted cash flow. This test
is based on a number of estimates. We use our independent reservoir engineer s
estimate of our production from our proved reserves, forecasts of crude oil
prices and estimated costs to produce our reserves and run our operations. All
of these estimates are subject to uncertainty.
 
 We use
the unit of production method for calculating depletion of our oil and gas
assets. Our reserve estimates, production volumes and estimated future
development costs have a significant impact on our depletion
expense.
 
 **ASSET
RETIREMENT OBLIGATIONS**
 
 As
described in Note 2 to our consolidated financial statements, effective January
1, 2004, we adopted the new recommendation of the Canadian Institute of
Chartered Accountants ( CICA ) regarding asset retirement obligations. This new
standard changes the method of estimating and accounting for future site
restoration costs, and requires recording the fair value of asset retirement
obligations when the related asset is brought into service rather than accruing
the obligation over the useful life of the asset.
 
 We have
estimated the fair value of our asset retirement obligations based on existing
laws, current costs and industry practices. Our estimate can be affected by
changes in laws, costs and industry practice.
 64PetroKazakhstan
      Inc.
 
 
 
 **CONTROL
ENVIRONMENT**
 
 PetroKazakhstan
maintains disclosure controls and procedures and internal control over financial
reporting designed to ensure that information required to be disclosed in the
reports filed under the United States Securities Exchange Act ( Exchange Act )
of 1934, as amended, and Multilateral Instrument 52-109 - Certificate of
Discloser in Issuers  Annual and Interim Filings ( MI 52-109 ) is recorded,
processed, summarized and reported within the time periods specified in the
Securities and Exchange Commission s rules and forms. PetroKazakhstan s Chief
Executive Officer and Chief Financial Officer, after evaluating the
effectiveness of PetroKazakhstan s disclosure controls and procedures (as
defined in Exchange Act Rule 13a-15 (e) and in MI 52-109) as of December 31,
2004, concluded that as of such date PetroKazakhstan s disclosure controls and
procedures were effective for the purpose for which they were
designed.
 
 During
the fiscal year ended December 31, 2004, there were no changes in
PetroKazakhstan s internal control over financial reporting that have materially
affected, or are reasonably likely to materially affect, PetroKazakhstan s
internal control over financial reporting.
 
 We are
in the process of implementing a number of major modifications to our ERP
system. We are also in the process of undertaking a comprehensive review of our
existing controls over financial reporting to facilitate compliance with Section
404 of the United States Sarbanes-Oxley Act of 2002. We expect that these
initiatives will lead to significant business process redesign, some of which
will relate to controls over financial reporting.
 
 **QUARTERLY
INFORMATION**
 
 The
table below sets out selected quarterly information for 2004, 2003 and
2002:
 
 *Net
      Income Per Share**($000 s)*
    
    Total
      revenue
    
    Net
      income
    
    Basic
    
    Diluted**2004,
      Quarter ended**March
      31
    
    
    **320,193**
    
    
    **87,485**
    
    
    **1.11**
    
    
    **1.08**June****30
    
    
    **398,501**
    
    
    **122,028**
    
    
    **1.54**
    
    
    **1.51**September
      30
    
    
    **518,602**
    
    
    **176,218**
    
    
    **2.30**
    
    
    **2.27**December
      31
    
    
    **405,131**
    
    
    **114,937**
    
    
    **1.51**
    
    
    **1.49**2003,
      Quarter endedMarch
      31
    
    
    248,923
    
    
    68,552
    
    
    0.87
    
    
    0.83June
      30
    
    
    254,601
    
    
    68,430
    
    
    0.88
    
    
    0.84September
      30
    
    
    303,152
    
    
    91,150
    
    
    1.17
    
    
    1.12December
      31
    
    
    310,648
    
    
    88,808
    
    
    1.14
    
    
    1.092002,
      Quarter endedMarch
      31
    
    
    143,331
    
    
    22,860
    
    
    0.28
    
    
    0.27June
      30
    
    
    177,398
    
    
    33,456
    
    
    0.41
    
    
    0.40September
      30
    
    
    247,962
    
    
    60,230
    
    
    0.74
    
    
    0.71December
      31
    
    
    256,659
    
    
    44,851
    
    
    0.56
    
    
    0.54
 
 The
historical quarterly information presented in these tables was restated due to
the adoption of new accounting standards as described in Note 2 to our
consolidated financial statements.
 65
 
 
 
 *Quarterly
highlights:*
 
 In the
first quarter of 2004, our production decreased to 142,919 bopd from 164,559 in
the previous quarter, a 13% decline. Throughout the quarter 19 Kumkol South
wells were shut-in due to the border well issue with Turgai. There were also
weather related restrictions, which led to reduced export shipments. The
increased average Brent price of $32.03/bbl offset these decreases.
 
 Our
production levels in the last three quarters of 2004 remained at a lower level
than our historical high at the end of 2003 due to increased water cut and the
reduced production scheme for our Kumkol South field resulting from our border
well dispute with Turgai. Our revenues and net income continued to grow in the
second quarter and the third quarter of 2004 due to the increases in world crude
oil prices, improvement of our differential and the production of VGO, our new
product which decreased the production of low-value mazut. Average Brent was
$35.32/bbl in the second quarter, $41.54/bbl in the third quarter and $43.85/bbl
in the fourth quarter of 2004.
 
 The
last quarter of 2004 had lower revenues and net income than expected, because of
deterioration in our differential and our inventory build up.
 
 Increased
world prices for crude oil in the first quarter of 2003 ($31.49/bbl) and
improved prices for our refined products resulted in a 53% increase in our net
income for the first quarter of 2003. However, because of transportation
difficulties due to seasonal factors our crude oil exports were restricted, and
we had to curtail our production to 140,765 bopd, a 10% decrease over the
previous quarter.
 
 During
the last three quarters of 2003, we were continuously increasing our production
in all fields (145,066 bopd in the second quarter, 154,712 bopd in the third
quarter and 164,559 bopd in the fourth quarter of 2003). Together with the
stable Brent price for crude oil (average $26.03/bbl in the second quarter,
$28.38/bbl in the third quarter and $29.43/bbl in the fourth quarter of 2003)
and improving prices for our refined products, we had steadily growing revenues
and net income. Our refinery was fully operational throughout the year, as there
was no major turnaround in 2003.
 
 Our
second quarter of 2002 results improved slightly compared to the first quarter
of 2002 due to the increased average Brent crude oil price of $25.07/bbl as
compared to $21.08/bbl in the previous quarter. This was offset in part by a
30-day shutdown of our refinery for a turnaround in the second quarter of 2002.
Our production in the second quarter of 2002 was 117,844 bopd versus 123,372
bopd in the first quarter of 2002, mainly because of the major refinery
turnaround.
 
 We had
a substantial increase in our sales and net income in the third quarter of 2002.
Though the world crude oil prices did not increase materially ($26.91/bbl versus
$25.07/bbl), our production reached 143,175 bopd and we also achieved record
export sales. These achievements were partially offset by the continuing
disappointing prices for refined products throughout 2002.
 
 The
transfer to non-FCA terms and a build up of inventory of crude oil in transit by
the end of 2002 caused approximately $13.0 million of net income deferred from
the fourth quarter of 2002 to the first quarter of 2003. This was the main
reason for the decline in net income in the quarter. The Brent price was almost
the same as in the third quarter of 2002 ($26.81/bbl), and our production
reached 157,268 bopd.
 66PetroKazakhstan
      Inc.
 
  **Statement
      of Corporate Governance
Practices**
 ****
 
 The
Board of Directors and senior management of the Corporation consider good
corporate governance to be central to the effective and efficient operation of
the Corporation and its business. The Board of Directors and management are
committed not only to satisfying legal and regulatory requirements, but also to
developing and maintaining corporate governance practices that reflect evolving
best practices standards as appropriate to the Corporation and its
business.
 
 The
Board of Directors and management have been following developments in corporate
governance requirements and best practices standards in both Canada and the
United States closely. The Corporation is listed on the New York Stock Exchange
(the  NYSE ). Although it is not required to comply with many of the corporate
governance listing requirements imposed by the NYSE for domestic listed issuers,
the Corporation has aligned its governance practices with those requirements.
The Board of Directors and management have reviewed the corporate governance
policy (Multilateral Instrument 58-201) released by certain of the Canadian
securities regulators for comment in January 2004. To the extent necessary, the
Corporation intends to adapt its governance practices to the best practices set
out in the final form of that policy.
 
 **TSX
CORPORATE GOVERNANCE POLICY GUIDELINES**
 
 The 14
corporate governance guidelines set out in the TSX Corporate Governance Policy
and a brief discussion of the Corporation s corporate governance practices with
reference to each guideline is set out below.
 
 ***1.***
    ***The
      Board of Directors should explicitly assume responsibility for the
      stewardship of the Corporation, and specifically for: (a) adoption of a
      strategic planning process, (b) identification of principal risks and
      ensuring the implementation of appropriate systems to manage these risks,
      (c) succession planning, including appointing, training and monitoring
      senior management, (d) communications policy for the Corporation, and (e)
      integrity of the Corporation s internal control and management information
      systems.***The
      mandate of the Board of Directors is to manage the business and affairs of
      the Corporation. Pursuant to this mandate, it has explicitly assumed
      responsibility for the stewardship of the Corporation and, as part of the
      overall stewardship responsibility, has assumed the responsibilities
      described below.a)
    The
      Board of Directors provides input to management in the development of the
      Corporation s strategic plan, approves that plan and monitors management s
      execution of that plan. As part of the Board of Directors  responsibility
      for the strategic planning process, the Board of Directors establishes the
      goals of the business of the Corporation with the input of management and
      strategies and policies within which the Corporation is managed.
      Management is required to seek approval of the Board of Directors for
      material deviations, financial or otherwise, from the approved business
      goals, strategies and policies.b)
    It
      is management s responsibility to identify the principal risks to the
      Corporation s business and to develop strategies to manage those risks.
      The Board of Directors receives regular reports from management on those
      risks, the systems in place to manage those risks and the effectiveness of
      those systems.
 67
 
 
 
 c)
    The
      Board of Directors is responsible for the appointment, appraisal and
      monitoring of the Corporation s senior management. The Corporation s
      policy is to attract management personnel whose prior experience results
      in them having been well trained for their responsibilities with the
      Corporation. The Board of Directors discusses succession issues with the
      CEO on a regular basis and becomes acquainted with other members of senior
      management, their experience and skill sets. The Board of Directors
      encourages senior management to participate in appropriate professional
      and personal development activities, courses and programs, and supports
      management s commitment to the training and development of all permanent
      employees.d)
    The
      Board of Directors oversees the policy of communications by the
      Corporation with its shareholders and, in conjunction with management,
      continues to review the Corporation s approach to communications with its
      shareholders, regulatory bodies, governments, media and the
      public.e)
    The
      Board of Directors oversees the integrity of the Corporation s internal
      control and management information systems, including through reports from
      management, from the external auditors and from the Audit Committee. In
      addition, a Disclosure Committee, composed of non-director members
      including financial officers of the Corporation, has been established to
      assist and advise the Chief Executive Officer and Chief Financial Officer
      with respect to the Corporation s internal controls and disclosure of
      financial information.***2.***
    ***Majority
      of directors should be  unrelated  (free from conflicting
      interest).***The
      TSX Guidelines provide that the term  unrelated director  means a director
      who is independent of management and is free from any interest and any
      business or other relationship which could, or could reasonably be
      perceived to, materially interfere with the director s ability to act with
      a view to the best interests of the Corporation, other than interests and
      relationships arising from shareholdings. The Board of Directors consists
      of six members, five of whom are unrelated directors and one who is a
      related director.***3.***
    ***Disclose
      for each director whether he or she is related, and how that conclusion
      was reached.***The
      current Board of Directors is comprised of six directors, five of whom are
      unrelated to management. As the Corporation s Chief Executive Officer,
      Bernard F. Isautier is a related director. The remaining directors, Louis
      W. MacEachern, James B.C. Doak, Jacques Lefvre, Nurlan J. Kapparov and
      Jan Bonde Nielsen have no relationship with the Corporation other than as
      a director or a security holder and accordingly are all unrelated
      directors. The Corporation does not have a significant
      shareholder.***4.***
    ***Appointment
      of a committee responsible for appointment/assessment of directors and
      that is comprised exclusively of outside (i.e. non-management) directors,
      a majority of whom are unrelated
  directors.***The
      Corporate Governance Committee of the Board of Directors, which is
      comprised entirely of outside and unrelated directors, has been given the
      responsibility of assessing the effectiveness of the Board of Directors
      and its individual members as well as the committees of the Board of
      Directors. In addition, the Corporate Governance Committee has
      responsibility for identifying prospective nominees for the Board of
      Directors and recommending them to the Board of Directors and for
      establishing criteria for Board of Directors membership and retirement
      therefrom.
 68PetroKazakhstan
      Inc.
 
 
 
 ***5.***
    ***Implement
      a process for assessing the effectiveness of the Board of Directors as a
      whole and its committees and individual
      directors.***The
      Corporate Governance Committee of the Board of Directors assesses, at
      least annually, the effectiveness of the Board of Directors and the
      committees of the Board of Directors. The assessments are carried out
      through one-on-one discussions between the Chair of the Corporate
      Governance Committee and each individual director. This process does not
      focus specifically on assessing the effectiveness of individual directors,
      but it provides an opportunity for each director to provide feedback on
      the effectiveness of the other directors. The Chair of the Corporate
      Governance Committee reports on the results of this process to the full
      Board of Directors.***6.***
    ***Provide
      orientation and education programs for new
      directors.***The
      directors who joined the Board of Directors most recently were provided
      with an orientation to the Corporation and education about the
      Corporation s business and the environment in which it operates through
      discussions with the CEO and other members of management and a review of
      certain corporate records. As new directors join the Board of Directors in
      the future, they will receive similar orientation and
      education.***7.***
    ***Consider
      the size of the Board of Directors and the impact of the number on the
      Board of Directors  effectiveness.***The
      Corporation s articles require that the Board of Directors be comprised of
      three to nine directors. The number of directors is currently set at six.
      The Board of Directors is satisfied that this number allows for the
      balance of skill sets and experience appropriate to the effective
      discharge of the Board of Directors  oversight
      responsibilities.***8.***
    ***The
      Board of Directors should review the adequacy and form of the compensation
      of directors to ensure compensation realistically reflects
      responsibilities and risks involved.***The
      Compensation Committee, which is comprised entirely of outside and
      unrelated directors, regularly reviews the adequacy and form of
      compensation of directors of the Corporation. Based on a review of the
      compensation paid to directors of Canadian companies of comparable size
      and on discussions among the directors, the Board of Directors is
      satisfied that it realistically reflects the responsibilities and risks
      involved.***9.***
    ***Committees
      of the Board of Directors should generally be composed of outside
      directors, a majority of whom are unrelated, although some committees,
      such as the executive committee, may include one or more inside
      directors.***The
      Board of Directors has established three committees: the Audit Committee,
      the Compensation Committee and the Corporate Governance Committee. All
      committees are comprised of outside directors, all of whom are also
      unrelated directors.
 
 69
 
 
 
 ***10.***
    ***The
      Board of Directors should expressly assume responsibility for, or assign
      to a committee of directors, the general responsibility for developing the
      Corporation s approach to governance
  issues.***The
      Corporate Governance Committee has the responsibility of developing the
      Corporation s approach to governance issues, and administering the Board
      of Directors  relationship with management. This includes responsibility
      for: (i) assessing, at least annually, the effectiveness of the Board of
      Directors as a whole and the committees of the Board of Directors, (ii)
      reviewing annually the mandates of the Board of Directors and its
      committees and making recommendations for change, (iii) recommending
      procedures to permit the Board of Directors to function independently from
      management, (iv) reviewing and, if appropriate, approving requests from
      directors for the engagement of outside advisors, (v) preparing and
      maintaining corporate governance policies for the Corporation, and (vi)
      identifying prospective nominees for the Board of Directors and
      recommending them to the Board of Directors and establishing criteria for
      the Board of Directors  membership and retirement
    therefrom.***11.***
    ***The
      Board of Directors should define limits to management s responsibilities
      by developing (a) mandates for the Board of Directors and the Chief
      Executive Officer of the Corporation and (b) the corporate objectives for
      which the Chief Executive Officer is
      responsible.***The
      Board of Directors is responsible for the overall stewardship of the
      Corporation and in furtherance thereof supervises the officers of the
      Corporation in their management of the business and affairs of the
      Corporation and manages the Corporation s strategic planning process. The
      Board of Directors has developed mandates and corporate objectives for
      which the Chief Executive Officer is responsible. The Board of Directors
      requires the Chief Executive Officer and other management of the
      Corporation to keep the Board of Directors informed in a timely and candid
      manner of the progress towards the achievement of the established goals
      and of any material deviation from such goals and from the Corporation s
      strategies and policies as approved by the Board of
    Directors.***12.***
    ***Establish
      procedures to enable the Board of Directors to function independently of
      management.***The
      importance of the independence of the Board of Directors from management
      is fully endorsed by the Corporation and its management. The Board of
      Directors considers it important to the ability of the CEO to function
      most effectively in Kazakhstan, that the CEO also be the Chairman of the
      Board of Directors. The Board of Directors discharges the responsibilities
      which are central to its oversight function through the Audit,
      Compensation and Corporate Governance Committees, each of which is
      comprised entirely of unrelated directors. Well-developed mandates for
      these committees, position descriptions for the Board of Directors and the
      CEO, Board of Directors assessment processes and ongoing discussions about
      effective governance and evolving best practices also support the
      independence of the Board of Directors from management. In addition to the
      CEO, each of the other directors are established businesspersons who are
      each satisfied that they discharge their responsibilities to the
      Corporation in an independent-minded way and do not believe that other,
      more formal procedures are
necessary.
 70PetroKazakhstan
      Inc.
 
 
 
 ***13.***
    ***Establish
      an audit committee with a specifically defined mandate and direct
      communication channels with internal and external auditors, with all
      members being outside directors. The audit committee s duties should
      include oversight responsibility for management reporting on internal
      control and should ensure that management has designed and implemented an
      effective system of internal control.***The
      Board of Directors has an Audit Committee, all the members of which are
      outside directors. The roles and responsibilities of the Audit Committee
      include responsibility for reviewing and making recommendations to the
      Board of Directors on (i) financial statements and the related reports of
      management and external auditors, (ii) accounting and financial reporting
      procedures and methods, (iii) internal audit procedures and reports, and
      (iv) matters relating to external auditors, including the appointment and
      terms of engagement of external auditors and their reports relating to
      accounting, financial and internal audit matters. The Audit Committee has
      direct communication channels with the external auditors. The Corporation
      has an internal audit function and the Audit Committee has a direct
      communication channel with the internal audit.The
      U.S. Securities and Exchange Commission (the  SEC ) requires that a
      company filing under the U.S. Securities Exchange Act of 1934 (the  Act )
      disclose whether its board of directors has determined that there is at
      least one  audit committee financial expert  as defined by the SEC, on its
      audit committee. The Board of Directors of the Company has determined that
      Jacques Lefvre is such an  audit committee financial expert  fulfilling
      this requirement. The SEC further requires, pursuant to Rule 10A-3 of the
      Act, that each member of the audit committee be  independent  as that term
      is defined by the SEC. All of the members of the audit committee are
       independent  as required by the SEC.***14.***
    ***Implement
      a system to enable an individual director to engage outside advisors at
      the Corporation s expense. The engagement of the outside advisor should be
      subject to the approval of an appropriate committee of the Board of
      Directors.***Any
      member of the Board of Directors may engage an outside advisor at the
      expense of the Corporation in appropriate circumstances, subject to the
      approval of the Corporate Governance
Committee.
 71
 
 
 **DIFFERENCES
IN CORPORATE GOVERNANCE PRACTICES OF THE CORPORATION COMPARED TO NYSE STANDARDS
APPLICABLE TO U.S. DOMESTIC ISSUERS**
 
 As a
Canadian company, the Corporation is not required to comply with many of the
corporate governance listing requirements imposed by the NYSE for U.S. domestic
issuers. The Corporation must however, provide a brief description of any
significant difference between its corporate governance practices and those
followed by U.S. companies under the NYSE listing standards. The following
provides a summary of the significant differences between the Corporation s
domestic practice and the NYSE rules.
 
 4
    Section
      303A.01 of the NYSE corporate governance rules requires a majority of
      directors of a U.S. domestic issuer to be  independent  and Section
      303A.02 sets forth the independence standards for such directors. The TSX
      guidelines provide that the board of directors of a company should have a
      majority of  unrelated  directors. The principles for determining whether
      a director is  unrelated  differ significantly from the NYSE s
       independence  standards. The Corporation follows the TSX
      guidelines4
    Section
      303A.03 of the NYSE corporate governance rules requires non-management
      directors of a U.S. domestic issuer to meet at regularly scheduled
      executive sessions without management. Although non-management directors
      of the Corporation meet without management, such meetings do not currently
      follow a regular schedule.4
    Section
      303A.05 of the NYSE corporate governance rules requires the compensation
      committee of a U.S. domestic issuer to review and approve corporate goals
      and objectives relevant to the Chief Executive Officer s compensation,
      evaluate the Chief Executive Officer s performance in light of these goals
      and, either as a committee or together with the other independent
      directors, determine and approve the Chief Executive Officer s
      compensation level based on this evaluation. The TSX guidelines provide
      that the board of directors should approve or develop the corporate
      objectives which the Chief Executive Officer is responsible for meeting.
      The Corporation follows the TSX guidelines relating to corporate
      objectives for which the Chief Executive Officer is responsible.4
    Section
      303A.09 of the NYSE corporate governance rules requires a U.S. domestic
      issuer to adopt and disclose a set of corporate governance guidelines and
      to post such guidelines on the company s website. The Corporation has
      aligned its corporate governance practices with TSX guidelines as well as
      the policies released by certain Canadian securities regulators for
      comment in January 2004. The Corporate Governance Committee has not
      however, codified its corporate governance principles into formal
      guidelines in order to post them on its website.4
    Section
      303A.12(a) of the NYSE corporate governance rules requires the Chief
      Executive Officer of a U.S. domestic issuer to annually certify that he or
      she is not aware of any violation by the company of NYSE corporate
      governance standards. As a Canadian company, the Corporation (and its
      Chief Executive Officer) is not subject to this requirement. However, in
      accordance with NYSE rules applicable to both U.S. domestic and foreign
      private issuers, the Chief Executive Officer is required to promptly
      notify the NYSE in writing after any executive officer becomes aware of
      any material non-compliance with the NYSE corporate governance standards
      applicable to the Corporation.
 72PetroKazakhstan
      Inc.
 
 
 
 **Corporate
      Structure**
 
 The
following diagram shows the principal operating subsidiaries of PetroKazakhstan
Inc., their respective jurisdictions of incorporation and the percentage
ownership PetroKazakhstan has, directly or indirectly, The Company conducts
virtually all of its operations through, and virtually all its assets are held,
directly or indirectly, by PKKR, Turgai, Kazgermunai, PKOP and PetroKazakhstan
Marketing Ltd.
 
 
 
 **PetroKazakhstan
      Inc.**(Canada)
      is our registered head office that directly or indirectly owns all of the
      other companies within the PetroKazakhstan group.
      
      **PetroKazakhstan
      Overseas (Cyprus) Limited**(Cyprus)
      is an intermediate holding company.
      
      **PetroKazakhstan
      Kumkol Limited**(Cyprus)
      is an intermediate holding company.
      
      **PetroKazakhstan
      Marketing Limited******(Cyprus)
      is a crude oil marketing subsidiary of the PetroKazakhstan
      group.
      
      **AO
      PetroKazakhstan Kumkol Resources**(Kazakhstan)
      is engaged in developing the Kumkol South, South Kumkol, KAM, East Kumkol,
      North Nurali fields and our exploration blocks.
      
      **TOO
      Kazgermunai**(Kazakhstan)
      is a 50% joint venture with RWE-DEA AG (RWE) (25%), Erdol-Erdgas Gommern
      GmbH (EEG) (17.5%), and International Finance Corporation (IFC) (7.5%)
      engaged in developing the Akshabulak, Nurali and Aksai
    fields.
    
    **PetroKazakhstan
      Finance B.V.(**Netherlands),
      a special purpose entity, is a wholly owned subsidiary of
      PKKR.
      
      **CJSC
      Turgai Petroleum**(Kazakhstan)
      is a 50% joint venture with Lukoil Overseas Ltd., engaged in developing
      the North Kumkol field.
      
      **Valsera
      Holdings B.V.**(Netherlands)
      is an intermediate holding company for our refining
      activities.
      
      **OAO
      PetroKazakhstan Oil Products**(Kazakhstan)
      is the company in which our refining activities take place.
      
      **Ascot
      Petroleum Consulting Ltd.**(England)
      provides management services to companies in the PetroKazakhstan
      group.
      
      **PetroKazakhstan
      Overseas Services Inc.**(Canada
      and Kazakhstan) supplies international goods and services for
      PetroKazakhstan s Kazakhstani operations and provides personnel services
      to the group.
 
 73