Petrokazakhstan 6-K Current report (foreign)

Exhibit 99.1

Earnings

PetroKazakhstan generated record earnings of over $0.5 billion in 2004, an increase of 58% versus 2003.

Cash flow

PetroKazakhstan generated record cash flow of $0.56 billion in 2004, an increase of 40% versus 2003.

4 PetroKazakhstan Inc.

5

2004 Highlights and Achievements

Achievements

4	Record financial results
4	Significant increase in oil reserves
4	Reserve recognition of substantial Natural Gas Liquids and natural gas
4	Exploration success in Kyzylkiya, Aryskum and Akshabulak
4	Introduction of a regular quarterly dividend policy
4	KAM pipeline and Dzhusaly rail loading terminal operating effectively
4	Completed construction and commissioned the Gas Utilization Project
4	Acquired additional exploration acreage
4	Increased shipments of crude oil to China
4	PetroKazakhstan’s common shares listed on the Kazakhstan Stock Exchange

FINANCIAL AND OPERATING HIGHLIGHTS

EXPRESSED IN MILLIONS OF UNITED STATES DOLLARS (EXCEPT PER SHARE AMOUNTS)

Years ended December 31	2004		2003		2002
FINANCIAL
Net Income		500.7		316.9		161.4
Per share (basic) ($)		6.40		4.06		2.00
Cash Flow		560.5		400.0		216.8
Per share (basic) ($)		7.16		5.12		2.68
EBITDA		931.6		590.5		343.6
Capital Expenditures		166.0		203.2		140.1
Total Assets		1,269.1		1,041.5		709.7
Shareholders’ Equity		890.1		571.7		266.9
Shares Outstanding at December 31		76,223,130		77,920,226		78,956,875
Number of Employees at December 31		3,001		2,610		3,306
OPERATING
Production (bopd)		151,102		151,349		135,842
Reserves (proved plusprobable) (mmboes)*		549.8		495.4		518.3

*As of January 1 of the following year

6    PetroKazakhstan Inc.

Operating Achievements

4	Replaced 180% of 2004 crude oil production
4	Five-year finding and development costs of $1.53/bbl based on proved reserves
4	Continuous operations of the 55 MW gas utilization plant
4	Exploration success in three fields
4	Yearly differential reduced by $1.49/bbl versus 2003

2005 Objectives

4	Increase production by 12.5%
4	Reduce export differential
4	Develop asset base through further exploration and appraisal work
4	Continue to improve the yield of the Shymkent refinery
4	Commission a Liquified Petroleum Gas facility
4	Implement an Enhanced Oil Recovery project

7

A Message from Mr. Bernard Isautier - President and Chief Executive Officer

Our Company has continued to generate record financial results for 2004. This was achieved through strong commodity prices, a reduction in our differential and enhanced refinery contributions.

Going beyond boundaries summarizes what the Company has achieved in 2004 and the path it will continue to follow in the future. In 2004, PetroKazakhstan focused on proving exploration concepts resulting in new oil discoveries, further exploiting its asset base through new technologies, creating new refined products such as Vacuum Gas Oil (VGO), implementing new activities in the form of electrical power generation, identifying new markets for crude oil and refined products, developing new transportation routes, investing in logistics and adding new talents and professional disciplines to our organization.   These initiatives contributed to the generation of record financial results.   ASSET AND RESERVE GROWTH In 2004, the Company was successful in significantly increasing its exploration land position from the prior year. Due to these land acquisitions the Company initiated and completed a basin study. This study has led to the identification of an exploration inventory that includes 94 independent structures which will give us many years of drilling prospects.   This increased focus on exploration led to the discovery of a new reservoir within the Aryskum field license and new channel sands on the Akshabulak license. It also proved the presence of a significant northern extension to the Kyzylkiya field and identified other highly prospective opportunities on new exploration land blocks. We plan to continue to aggressively prove up and identify other new structures and plays in 2005.   As of January 1, 2005 PetroKazakhstan’s reserves were independently determined by the Canadian company McDaniel & Associates Consultants Ltd., to be 549.8 million barrels of oil equivalent (mmboe) comprised of 502.9 million barrels (mmbbls) of crude oil, 31.2 mmboe of Natural Gas Liquids (NGLs) and 88.4 billion cubic feet (bcf) of gas on a proved plus probable basis. This represents a 197% replacement of 2004 production on a boe basis even though he more stringent Canadian standard of reserves definition and recognition as set out in National Instrument 51-101 (Standards of Disclosure for Oil and Natural Gas activities) was used.   QUARTERLY DIVIDEND POLICY AND SHARE BUY-BACKS PetroKazakhstan introduced a regular quarterly dividend in early 2004. On December 13, 2004, the Company’s Board of Directors approved a 33% increase in its quarterly dividend from C$0.15 per share to C$0.20 per share.   As an additional means of adding shareholder value, the Company has implemented, for a third year in a row, a share repurchase program approved by the Toronto Stock Exchange. This share repurchase program, called a Normal Course Issuer Bid (NCIB), allows the Company to repurchase up to 10% of its public float or 7,091,429 shares, for our most recent program, over a one year time period beginning August 13, 2004 and terminating no later than August 12, 2005. As of the end of 2004, the Company had repurchased and cancelled 1,257,500 shares. Subsequent to year end 2004, the Company has continued to repurchase and cancel shares.   In 2004 PetroKazakhstan also implemented a Dutch auction substantial issuer bid share tender. This share tender ended on July 19, 2004 and resulted in the repurchase and cancellation of 3,999,975 shares at C$40.00 per share.

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RECORD RESULTS Our Company has continued to generate record financial results for 2004. This was achieved through strong commodity prices, a reduction in our differential and enhanced refinery contributions. Some of the key financial results were:   4 Cash flow reached $560.5 million, an increase of 40% over 2003 4 Net income was $500.7 million, an increase of 58% over 2003   BROADER MARKET RECOGNITION PetroKazakhstan was successful in becoming the first foreign company to have its shares listed on the Kazakhstan Exchange as of December 27, 2004.   This listing will allow all Kazakhstan institutions and citizens, including our own employees, to become PetroKazakhstan shareholders, to become more involved in the market activities of our Company and to more generally participate in the development of the market economy in Kazakhstan.   TRANSPORTATION COSTS Transportation costs continued to be the Company’s largest operating expense and hence our largest opportunity for cost reduction throughout 2004. Effective use of our newly constructed 177 kilometer (km) Kyzylkiya, Aryskum and Maibulak (KAM) pipeline which became operational in June 2003 was key. The savings in rail transportation costs for crude oil exports, sent west to the Black Sea, has been approximately $2.00/barrel (bbl).   Shipments of crude oil and refined products to China continued to increase in 2004. After many years of planning, the governments of Kazakhstan and China broke ground and began the construction of a 1,000 km pipeline from Kazakhstan to the Chinese border. This pipeline, which is currently planned for construction completion by the end of 2005, with start-up in early 2006, will structurally change the movement and flow of oil within Kazakhstan. With an initial capacity of 200,000 bopd, expandable to 400,000 bopd and beyond, via additional construction phases, this pipeline will draw on Kazakhstan oil to feed the voracious Chinese appetite for oil. PetroKazakhstan believes it is well positioned to supply significant amounts of crude oil into this pipeline, given appropriate terms.   In 2004, crude oil produced by Turgai Petroleum (Turgai), our joint venture with Lukoil, exported via the Caspian Pipeline Consortium (CPC) pipeline, was increased. Shipments in 2004 represented 92% of our CPC contractual maximum of 31,800 bopd gross (1.5 million tonnes per year). Shipments in 2005 are expected to be greater than that achieved in 2004.   The construction of a 1,000,000 bopd pipeline originating in Azerbaijan, terminating at the Mediterranean Sea via Turkey, the Baku-Tbilisi-Ceyhan (BTC) pipeline will further lead to enhanced competition for crude oil and potential tariff cost reductions. This $4 billion pipeline, scheduled for start-up in mid 2005, will significantly increase the current take-away capacity for crude produced in the region. The Company has approached consortium partners and expressed its desire to ship crude through BTC, given the appropriate terms.   Oil exports via China, Iran, CPC, BTC and Atyrau are expected to result in further transportation cost savings.   To efficiently handle increased rail movement of exported crude, the Company expanded its fleet of controlled railcars from just over 2,000 cars at the end of 2003 to approximately 5,000 cars by year end 2004.

9

UPSTREAM OPERATIONS The Company’s 2005 annual production plan is to produce 170,000 bopd. Achievement of this technical potential remains subject to timely receipt of various regulatory approvals and the absence of unforeseen marketing constraints. This projection represents a 12.5% increase in production versus 2004 and will be accomplished through further development of a number of our existing fields.   Phase I of the Kumkol South Enhanced Oil Recovery (EOR) project will begin in 2005 as will the development of the East Kumkol field and the commissioning of the Akshabulak gas plant for Liquefied Petroleum Gas (LPG). These projects will increase our production and reserve base.   From an exploration and production perspective, PetroKazakhstan now has land interests of approximately 3.4 million acres (13,760 km2) in the South Turgai basin, where we operate, with 3.2 million acres being exploratory in nature. The South Turgai basin has long been identified as having reserve potential in the billions of barrels. To date the Company has been successful in proving up additional new exploration concepts which have led to new field discoveries. In 2005 we will continue to aggressively drill exploration wells on our exploration acreage to find and prove up additional reserves.   DOWNSTREAM OPERATIONS The downstream sector continues to be a very important aspect of our integrated business, not only from an opportunity driven basis, but also from a revenue generation perspective.   Our focus has and continues to be, enhancing the product slate of the refinery and the implementation of ongoing process improvements. The startup of the Vacuum Distillation Unit (VDU) in 2004 has led to a lower yield of heavy fuel oil (mazut). Over the course of 2004, the mazut yield has been reduced by 29%, from an average of 32.5% in 2003 of crude feedstock to an average of 23.1% for 2004. With the startup of a newly constructed boiler which generates steam required in the operations of our refinery, we have been able to achieve energy efficiencies and therefore, cost savings.   HEALTH, SAFETY AND ENVIRONMENT 2004 was the first year of continuous operations of the Company’s newly built 55-megawatt (MW) power plant located at the Kumkol field. This plant has reduced gas emissions by converting associated gas produced from the Kumkol fields into electricity. In 2005, a second natural gas project at the Company’s joint venture field at Akshabulak will be commissioned. This project will further reduce gas emissions and will also provide natural gas to the Kyzylorda region.   Improving safety is one of our primary focuses. In 2004, in our Upstream operations, we had one lost time accident and reported 10 accidents/incidents. We had no lost time accidents at our refinery for a second consecutive year, a record we are very proud of. In 2005, we will continue in our efforts to make our workplace as safe as possible.   LOOKING FORWARD PetroKazakhstan’s key objectives for 2005 and beyond will be to focused on:   4Increasing production and reserves through development, exploration and acquisitions.   4Reducing the export differential.   4Continuing to improve the product yield of the Shymkent refinery.   4Increasing the value obtained for our refined products.   4Commissioning a new Liquefied Petroleum Gas facility.   4Implementing an Enhanced Oil Recovery project.   PEOPLE GOING BEYOND BOUNDARIES As we continue to expand our businesses, we add new professional disciplines to deal with the new challenges which require much energy and commitment to resolve. I’m proud of the quality of our staff and the dedication shown by our staff in continuing to achieve excellent results for our Company. On behalf of the Board of Directors, thank-you to all of our employees.   Respectfully submitted on behalf of the Board of Directors,       (signed) BERNARD F. ISAUTIER President and Chief Executive Officer

10 PetroKazakhstan Inc.

President’s Questions and Answers

Q & A

Q4	Production for year 2004 was flat versus 2003 even though you projected production increases, why?
A4	Three unforeseen key operational factors arose in 2004 leading to this situation. Early in 2004, 19 Kumkol South wells were shut in while a mutually acceptable resolution on the operating conditions of wells located at the border between Kumkol South and Kumkol North was sought with the neighboring license holder, Turgai Petroleum. In June, all wells were back on production, although at a reduced rate from their potential. The net impact on the Company’s average annual rate of production was a decrease of 8,500 bopd. Unexpected failures of electrical submersible pumps in two prolific South Kumkol producers had a further impact of 4,500 bopd on the Company’s annual rate of production. During the fourth quarter of 2004, pumps were optimized and field production resumed at normal rates. The Company has increased the pump stock inventory to minimize individual well downtime when equipment failures occur. Lastly, a significant delay in the arrival of a drilling rig reduced the number of Aryskum development wells resulting in an additional impact of 2,300 bopd on the Company’s average annual production rate. Therefore, these three factors resulted in a total reduction of 15,300 bopd.
Q4	With these unforeseen operational factors, can you continue to increase production and grow your assets in 2005?
A4	Yes, we can. We own or operate 11 oilfields. Of these fields, a number of them are just in the initial phases of development. We have plans in place to increase production from these fields. With regard to reserves, two methods to increase them are through ongoing appraisal and extensions of existing fields and via EOR.
	We estimate that the additional possible reserve potential from EOR is anywhere from 55 to 180 million barrels. We are also looking at recovering significant LPG reserves from our fields. As of January 1, 2005, our current reserves, on a proven and probable basis, are 549.8 million barrels of oil equivalent. Independent consultants have determined we have in excess of 250 million barrels of possible oil reserves that we intend to prove up in the future through additional drilling. With regard to exploration, the basin in which we operate is still at a very early phase of maturity. There has been limited exploration in this region over the last 10 years. Independent experts, the US Geological Survey, have estimated that the remaining undiscovered oil potential of the basin is 2.7 billion barrels. Our own portfolio of exploration prospects and leads has identified over 1.0 billion barrels of potential unrisked reserves. So in the years to come, we intend to carry out a very aggressive exploration program to find additional reserves.
Q4	Are you still looking at acquisitions as another means of growth?
A4	Yes. Our philosophy is that acquisitions should add value for our shareholders. We are not driven by size for the sake of size. To this point we have been quite successful in acquiring exploration acreage. We have not yet made a large reserve acquisition because in the current high oil price environment, there is a gap between seller and buyer expectations. We are reviewing opportunities in Kazakhstan and in countries that are close to Kazakhstan, where the current operating environment may have some similarities. We are ready to move if the right opportunity materializes. Even without acquisitions, we are confident we can continue to deliver substantial internal growth to our shareholders.

12    PetroKazakhstan Inc.

Q4	How important is Kazakhstan as an oil producer and where are the markets for its products at this point? What are your strategies and opportunities?
A4	Kazakhstan is a very important country supplying oil into the international market. Three years ago, a discovery was made in the Caspian Sea, the Kashagan discovery, which could have up to 40 billion barrels of oil in place. This is the largest oil discovery made in the world over the last 35 years. So Kazakhstan is the Kuwait of Central Asia, and all international companies are interested in investing in Kazakhstan. The Kashagan discovery is not unique; there are quite a large number of prospects still to be explored with a high likelihood of success. So the question is how do you bring these resources to the international markets? Kazakhstan is a landlocked country. However, the distances from the fields in Kazakhstan to export points are similar to other producing countries in the world. Kazakhstan has a number of options for the export of its oil, and intends to capitalize on all of them - selling crude oil through pipeline via Russia to the European markets; selling through pipeline via the Black Sea, the Bosphorus and then the Mediterranean Sea; shipping across the Caspian Sea then through pipeline, directly to the Mediterranean market; possibly shipping through Iran to the Persian Gulf; and also selling to China via pipeline, the construction of which started in the fall of 2004. As a company, we as well, are pursuing all these export options.
Q4	What is your priority regarding transportation costs and continuing to reduce your export differential in 2005?
A4	One of our priorities is to continue to lower transportation costs. Transportation is the single largest operating cost we have. Our main export markets are China, the Persian Gulf, the Mediterranean and Black Seas. Even though we have significantly reduced our transportation costs to these markets over the last few years, we continue to seek further cost reduction opportunities. This implies diversification, negotiation of better tariffs and enhanced competition between various routes. We are in an environment that is moving more and more to a free competitive international market. This will benefit us and will enhance the value of our assets.
Q4	Why was PetroKazakhstan’s common stock listed on the Kazakhstan Stock Exchange in 2004 given that you are already listed on four other major exchanges, namely Canada, the United States, the United Kingdom and Germany?
A4	Over the last few years we have worked hard to raise the profile of our Company in North America, with success. By listing on the Kazakhstan Stock Exchange we hope to be able to attract new shareholders and local investment. By doing so we will become more ingrained in the daily lives of the Kazakh investor, leading to increased confidence and support.
Q4	What will you do with the build up of cash that you are experiencing?
A4	We will continue to return excess cash to our shareholders through various means. We are buying back shares and paying out dividends on a quarterly basis and we continue to review the possibility of further increasing the amount we will pay out to investors. We have made special dividend distributions in the past and don’t rule out the possibility of doing it again. We will also look at other means of effectively and efficiently enhancing shareholder value. While doing so, we are careful to maintain the flexibility to finance an acquisition or unusual capital project.
Q4	How has the dismantling of Yukos in Russia and the current Russian political situation impacted PetroKazakhstan or Kazakhstan?
A4	The dismantling of Yukos has not impacted PetroKazakhstan’s operations. Needless to say, Kazakhstan is not Russia in any respect. However, the average investor has become more sensitive to the state of affairs in Russia and as a result, additional downward pressure has been exerted on the stock prices of companies who operate near Russia, including ourselves. By continuing to effectively communicate our opportunities and challenges to investors, we believe we can help alleviate that pressure.

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Q4	Have the challenges or problems which you faced in 2004 changed and if so, how?
A4	No, not to any appreciable degree. The challenge of operating in Kazakhstan is that there are still many opportunities which are not being realized. Significant amounts of time are being spent in negotiations with officials at various levels to obtain the approvals and support needed to realize these opportunities. We are focused on this and are rising to the challenge.
Q4	What misperceptions do you still continue to face in the investment community today?
A4	The main communication challenge that we still face is the lack of familiarity with Kazakhstan. Not all investors are experts in geopolitics. Their lack of familiarity with Kazakhstan means that they attribute more “political risk” to Kazakhstan than we believe is appropriate. We feel that the risks are manageable. Kazakhstan is a country that is pro foreign investment, pro market economy and is growing rapidly. It is working on accession to the WTO. While we continue to make progress with familiarizing the investment community with Kazakhstan, we still have a long way to go.
Q4	Can you comment on your staff?
A4	We have built an outstanding team. An area where we have significantly invested in talents is marketing and transportation. We have assembled an outstanding team of traders, engineers, transportation specialists, market analysts and regulatory specialists to deal with the unique transportation issues. We also have something that many companies don’t have, a government relations and regulatory affairs group that monitors very closely the regulatory and energy policy developments in the region, not only in Kazakhstan, but in the countries where we sell our crude oil and products. These groups are supported by a team of analysts. We have the right talents to prepare professional submissions to government authorities, always advocating liberalization of the economy and for policies that promote economic development in the interest of all parties. Our Upstream team continues to deliver excellent results as new reserves have been found and developed. Our investor relations group has worked hard over the last five years to significantly increase our worldwide shareholder base. We have broadened our U.S. investor base, both institutional and retail. We have also expanded our European, Russian and emerging market shareholder base. It is most gratifying to see the skills and motivation of our executives and staff.
Q4	What are your goals with respect to being independent in an industry where there is consolidation and growth through merger and acquisition?
A4	We’d like to remain an independent company as we believe we can deliver superior value to our shareholders. The Board would not however, oppose or resist a takeover attempt if this was made on the basis of a fair assessment of our net asset value. But until this happens, we will continue to focus our work and efforts on the profitable growth of the Company.
Q4	Has your vision for PetroKazakhstan changed over the last year?
A4	No. PetroKazakhstan’s vision is to continue to be recognized as a leader in the international oil and gas industry within the Former Soviet Union; to be a leader recognized by its ability to create shareholder value, to operate in a professional manner and to be recognized in Kazakhstan as a model corporate citizen.
Q4	What changes should we expect to see in PetroKazakhstan over the next three years?
A4	We expect to be focused on further increases in production and reserves and cost reductions, especially transportation costs. We will continue to develop our Downstream operations and hope to have established another area of operation in or around Kazakhstan to support our further growth.
Q4	Why should someone invest in PetroKazakhstan today?
A4	We have an exceptional and proven track record of delivering growth. We offer a management team operating under western governance and reporting criteria. Our finding and development costs and operating costs are extremely low by world standards. We have been effective in reducing transportation costs and are delivering solid netbacks and returns to our investors. We continue to focus on value creation by buying back our shares and by paying a regular quarterly dividend. We have a history of growth in production, reserves and share price. For all these reasons, we believe PetroKazakhstan remains an outstanding investment opportunity.

14    PetroKazakhstan Inc.

Operations Overview

All of PetroKazakhstan’s exploration and production operations are located in the 80,000 km2 South Turgai basin in south central Kazakhstan. PetroKazakhstan holds working interests in four exploration licenses covering a total of over 3.4 million acres. This acreage is 10 times larger than our holdings two years ago.   PetroKazakhstan has interests in eleven fields. Within the Kumkol Area there are three developed fields, Kumkol South, Kumkol North and South Kumkol. In close proximity are two new fields in the early stages of development, East Kumkol and North Nurali. To the west of the Kumkol area are the three KAM fields which are in development. Finally, to the south of Kumkol we have interests in three fields, Akshabulak, which is under development and Nurali and Aksai, on test production for appraisal.   As of January 1, 2005, proved reserves were estimated at 392.0 mmboe. Proved plus probable reserves were 549.8 mmboe. During PetroKazakhstan’s tenure in Kazakhstan our reserve portfolio has grown by 204 mmbbls of oil in the proved plus probable category net of production of 302 mmbbls. This net production is twice the volume of proved reserves that were attributed to the Company at its inception.   Average daily oil production in 2004 was 151,102 bopd.   Our fields generally have productive zones at relatively shallow depths ranging from 760 m to 1,830 m with some of our newly drilled wells ranging from 2,300 m to 3,550 m. Most of our reservoirs have high porosity and permeability. Our reservoirs produce light, sweet crude at 37° to 44° American Petroleum Institute (API) gravity with a sulphur content of less than 0.4%. These favourable field and crude oil characteristics enable us to develop our fields and produce and refine our crude oil at a low cost.   There are three main processing facilities. A Central Processing Facility (CPF) located in South Kumkol services all production from Kumkol South, South Kumkol and Kumkol North fields and has the capacity to handle 300,000 barrels of fluid per day (bfpd). Gas is gathered from these fields and used to feed a 55 MW power plant in Kumkol.   Under construction at the Kyzylkiya and Aryskum fields are facilities that will be capable of processing all fluids from these two fields and that of the Maibulak field to the northwest. In addition, all gas produced from the KAM fields will be injected back into the Aryskum gas cap. Akshabulak crude is treated at the field facilities, which are being expanded to handle 70,000 bopd. An LPG plant is under construction and a 124 km gas line has been laid from the field, and runs south to the city of Kyzylorda.   Substantial unutilized capacity in the government controlled oil pipeline, which runs from our fields to our refinery at Shymkent, still exists. This combination of facilities and pipelines allows for continued production growth and the development of additional reserves without the need for new transportation infrastructure. In addition, the KAM pipeline, commissioned in June 2003, provides an alternative export transportation route directly to our Dzhusaly rail-loading terminal.   Beginning in early 2002, our exploration program was primarily focused on accessing stratigraphic prospects, which had not been explored to any great extent in the basin. We have been successful in proving up these concepts in discovering the North Nurali field. The exploration program has also been successful in finding reserves within current production licenses at Kyzylkiya and Aryskum. One of our recent successes has been the discovery of previously unexplored channel sands below the Aryskum gas cap. The 3-year exploration and appraisal success ratio is 73%. The Company has increased its exploration acreage by a factor of ten over the past 2 years providing excellent opportunities for further discoveries from the estimated 94 leads and prospects held therein.   As of January 1, 2005, our proved reserves are 392.0 mmboe. Proved and Probable reserves are now 549.8 mmboe which includes 15 mmboe or 88.4 bcf of gas, and 32.1 mmbbls of NGLs.   As of January 1, 2005, our proved, probable and possible reserves as determined by our independent reservoir engineering consultants totaled in excess of 800 mmboe. We intend to focus on the complete reserve base and continue to develop and bring more reserves into the proved category.

21

Upstream - Property Review

14 Kumkol South

Working interest %	100
Operator	PKKR
Acreage (acres)	18,604
2004 oil production (mbopd)	44.9
2004 gas production (mboepd)	0.6
Production wells	158
Wells drilled in 2004	0
2005 target oil production (mbopd)	39 .2

The Kumkol field was discovered in 1984 and has been producing since 1990. We are producing from six horizons, in the Cretaceous and Jurassic formations, located at depths less than 1,400 m. The crude oil is sweet and light, 42º API. The field is divided into two operating areas, Kumkol South and Kumkol North.

As the field has matured and water production has increased, significant modifications have been made to the process facilities and the water injection system. Production facilities now handle over 300,000 barrels fluid per day (bfpd) and some 200,000 barrels water per day (bwpd) are re-injected back into the reservoirs to provide pressure support.

PetroKazakhstan is evaluating the potential for EOR in all of its producing fields. A hydrocarbon miscible flood scheme utilizing excess produced gas has been developed for Kumkol South. Phase one of this EOR project is underway with injection expected to commence in the third quarter of 2005 into one of the Kumkol South reservoirs. Our independent reserve engineers have made a nominal addition of probable reserves associated with this project.

24 South Kumkol

Working interest %	100
Operator	PKKR
Acreage (acres)	2,826
2004 oil production (mbopd)	23.7
2004 gas production (mboepd)	0.1
Production wells	23
Wells drilled in 2004	0
2005 target oil production (mbopd)	22.8

The South Kumkol field was discovered in 1992 and has been producing since 1997 from the Cretaceous and Jurassic sands from an average depth of 1200 m. South Kumkol crude is processed at the Kumkol CPF. Water injection is undertaken to maintain reservoir pressure and all wells make use of downhole pumps to maximize production and reserves exploitation. EOR is being evaluated for South Kumkol.

34 Kyzylkiya

Working interest %	100
Operator	PKKR
Acreage (acres)	95,657
2004 oil production (mbopd)	9.9
Production wells	34
Wells drilled in 2004	15
2005 target oil production (mbopd)	13.5

The Kyzylkiya field was discovered in 1988. Production, which commenced in August 2000, is from the Cretaceous and Jurassic formations at depths less than 1,600 m.

3D seismic has been acquired over the entire field. Development drilling continued in 2004 within the main field structure and to the north into our Kolzhan license area. 4 wells drilled in this area have confirmed the extension of the main Kyzylkiya field to the north. The Company was successful in acquiring additional acreage to the south of the field in which seismic and exploration drilling are planned in 2005.

An integrated oil and gas gathering system is being constructed to deliver produced fluids to Aryskum for crude shipment to our KAM pipeline with gas being re-injected into the Aryskum gas cap.

22    PetroKazakhstan Inc.

44 Aryskum

Working interest %	100
Operator	PKKR
Acreage (acres)	41,634
2004 oil production (mbopd)	10.8
Production wells	34
Wells drilled in 2004	19
2005 target oil production (mbopd)	21.5

The Aryskum field was discovered in 1988 and was on test production for three years from Cretaceous horizons at 1,200 m. 3D seismic was acquired over the entire field in 2002. Full development is on-going as 34 production wells and 1 gas injection well have been drilled. Oil processing facilities are in place along with water injection and gas injection facilities. Gas injection commenced in 2004 as part of a field pressure maintenance and gas conservation program. Ultimately, gas from all the KAM fields and excess gas from the Kumkol fields will be injected into the Aryskum gas cap. The Company was successful in discovering oil in Jurassic channel sands below this gas cap. The sands, which are of excellent quality and exhibited well flowrates of up to 1,600 bopd, were not anticipated in the initial development plan and add to the reserve base for this field. The Company intends to continue its appraisal of further channel sands in the area.

54 Maibulak

Working interest %	100
Operator	PKKR
Acreage (acres)	10,263
2004 oil production (mbopd)	2.1
Production wells	9
Wells drilled in 2004	0
2005 target oil production (mbopd)	3.9

The Maibulak field was discovered in 1988 with four productive zones in the Jurassic formation identified at depths of less than 1,400 m. 3D seismic surveys have been conducted over the entire field. Test production crude has been trucked to Aryskum, some 40 km to the south east. Full development is underway where all produced fluids including gas will be piped to the Aryskum facilities. Water injection facilities are in place and operational.

64 East Kumkol

Working interest % **	80
Operator	PKKR
Acreage (acres)*	8,151
2004 oil production (mbopd) *	0.6
Production wells *	5
Wells drilled in 2004 *	0
2005 target oil production (mbopd)*	0.9

East Kumkol has been in an appraisal testing phase. 3D seismic survey acquired over the entire field confirmed that the field extends into the Kumkol North (Turgai) license area. PetroKazakhstan and Turgai have developed joint venture agreements, a joint development plan and production agreements for approval by the authorities. The field is currently not producing pending finalization of the development and production plan and necessary regulatory approvals.

74 North Nurali

Working interest %	100
Operator	PKKR
2004 oil production (mbopd)	0.4
Production wells	8
Wells drilled in 2004	3
2005 target oil production (mbopd)	2.5

Just 5 kms west of the Kumkol field, North Nurali has proved to be a success in the Company’s exploration of new concept leads in the South Turgai Basin. A total of ten wells have been drilled by PetroKazakhstan in this field to depths ranging from 2,300 m to 3,550 m. Application is being made for an extended test production program with produced fluids being tied into the Kumkol facilities.

23

84 Kumkol North

Working interest %	50
Operator	Turgai
Acreage (acres)*	40,655
2004 oil production (mbopd) *	71.5
2004 gas production (mboepd) *	2.9
Production wells *	228
Wells drilled in 2004 *	18
2005 target oil production (mbopd)*	71.6

Turgai operates Kumkol North, which is owned equally between PetroKazakhstan and Lukoil Overseas Ltd. Production and ancillary support facilities are provided by PetroKazakhstan as the operator of Kumkol South on a fee basis. The crude is commingled after a metering station at the field’s border, and then processed at the CPF. Eighteen development wells were drilled in 2004.

94 Akshabulak

Working interest %	50
Operator	Kazgermunai
Acreage (acres) *	64,118
2004 oil production (mbopd) *	40.8
Production wells *	20
Wells drilled in 2004 *	4
2005 target oil production (mbopd)*	55.0

Kazgermunai operates Akshabulak which is owned 50% by PetroKazakhstan, 25% by RWE, 17.5% by EEG and 7.5% by International Finance Corporation (IFC). The Akshabulak field was discovered in 1988 and production began in 1997. Production is currently being transported by pipeline to the Kumkol field where it ties into the Kumkol - - Karakoin pipeline. This in turn connects to the central pipeline that delivers oil to the Shymkent refinery. Kazgermunai sells all of its crude into the export market.

Full development of the field is still to be accomplished. It has been delayed by the German joint venture partners, pending assurances from the Government of Kazakhstan on marketing and transportation issues. However, full field development has progressed with the acquisition of 3D seismic and development drilling of eleven wells over the past two years. Facility expansion is ongoing which should enable production of up to 70,000 bopd by the end of 2005. An LPG plant will be commissioned in the third quarter of 2005 and dry gas will be exported to the city of Kyzylorda via a 10” pipeline.

104 Nurali and Aksai

Working interest %	50
Operator	Kazgermunai
Acreage (acres)*	164,795
2004 oil production (mbopd) *	4.6
Production wells *	15
Wells drilled in 2004 *	4
2005 target oil production (mbopd)*	5.0

Nurali and Aksai have the same ownership structure as Akshabulak. The complex geology of the Nurali and Aksai fields has led to a new assessment of the appraisal and development plan. 3D seismic has been acquired and interpreted.

Four wells were drilled and selective wells were put on test production in 2004. The development will continue in 2005 with the drilling of up to five more wells during the year based on the interim production plan approved by the authorities.

* Items are at 100% or gross working interest.  ** Subject to variation on settelment

24    PetroKazakhstan Inc.

Exploration - - 260 D1 License

This 333,841 acre license surrounds the Kumkol field and continues to be one of our focus areas for our exploration efforts. The term of this license has been extended to June 2007. Leads that were originally identified in this license area from a comprehensive basin study resulted in the discovery of the North Nurali field.

The wells identified deeper target sands in stratigraphic traps, unexplored in the basin. Well depths for all the leads range from 2,300 m to 4,000 m. The North Nurali wells have validated the concept of producible hydrocarbons from deep stratigraphic traps. Extensive exploration and appraisal work has been conducted with the acquisition of 3D seismic over the North Nurali field itself and to the north where there exists the potential for a field extension in which a well will be drilled in 2005.

The exploration program will continue in 2005 with the acquisition of 3D seismic over the Karavanchy structure (east of the Kyzylkiya field) and over an area to the north of the Kumkol main reservoir in which an exploration well is planned.

Exploration - - License 952 (Kolzhan)

The acquisition of the 122,811 acre Kolzhan license, directly north of the Kyzylkiya field, was completed in the 4th quarter of 2003 and the license term has been extended to June 2007. Well KK34, drilled to 1,500 m produced light, sweet, oil at a rate of 1,000 bopd. Well evaluation results confirm that this accumulation is an extension of the main Kyzylkiya field. 3D seismic was acquired over the western half of the block enabling mapping of the main Kyzylkiya field extension. To date, 5 wells have been drilled with at least a further 4 wells planned in 2005 and the reprocessing of 2D seismic over the eastern half of the block. We had test production of 0.3 mbopd in 2004.

Exploration - - License 951-D

PetroKazakhstan has farmed-in to acquire operatorship and a 75% equity position in two separate blocks totaling over one million acres (4,290 km²) in a joint venture with Orient Petroleum. Two exploration wells on this license previously tested oil. The license is split into two blocks, Doshan to the north and Zhamansu to the south. Following the acquisition and interpretation of 714 kms of 2D seismic over the license, some 32 leads were identified in the Zhamansu block. Four wells were drilled in this block late in 2004, 2 wells encountered hydrocarbon sands but commercial production rates could not be attained. Two wells were dry.

Interpretation of data in the Doshan has identified a number of prospects and two exploration wells are planned for 2005.

Exploration - - Karaganda License

This large (1,876,508 acre) license, lies to the north of the 260 D1 and 952 Kolzhan licenses, and has been awarded to PetroKazakhstan. We are currently awaiting confirmation of the contract terms. The combination of large structural leads and evidence of oil migration into this area (the Company has drilled a well directly to the south of this license) elevates the prospectivity. The staged worked program will start with reprocessing of 400 km of 2D seismic and the acquisition of new 2D seismic in 2005.

25

GAS RESOURCE CONSERVATION AND EXPLOITATION

The Company has addressed the issue of utilizing associated produced gas in a number of ways.

4	PetroKazakhstan has built a 55 MW power plant in the Kumkol field. This facility uses associated produced gas from the Kumkol South, South Kumkol and Kumkol North fields to produce electricity for field use and to minimize gas flaring.
4	As a joint venture partner in the Akshabulak fields, PetroKazakhstan is participating in a project to provide natural gas to the Kyzylorda region and to extract LPG. This plant will be operational in the third quarter of 2005. The gas pipeline has been built.
4	The Kumkol field’s EOR project with LPG injection will commence in the third quarter of 2005 and will use excess produced gas.
4	Aryskum gas is now re-injected back into the reservoir for gas conservation and pressure maintenance. Kyzylkiya and Maibulak produced gas will also be re-injected as part of the KAM field development program.
4	The Company has embarked on a complete gas gathering program through all its fields. NGLs will be extracted for sale, and dry gas will be re-injected back into reservoir gas caps for conservation and reservoir pressure maintenance.

McDaniel and Associates Consultants Ltd., the Company’s independent reserve engineers, have acknowledged these programs through the recognition of reserves.

HEALTH, SAFETY AND ENVIRONMENT

PetroKazakhstan is committed to the continuous improvement of its Health, Safety and the Environment (HS&E) performance. During 2004, Upstream operations experienced only one lost time accident and reported 10 accidents/incidents. The Company has paid particular attention to its contractors’ performance through routine and operations specific safety meetings, the addition of contractual HS&E obligations and implementation of a contractor safety reporting program. Training is an integral part of our HS&E program and we employ experienced HS&E staff to assist all levels of the workforce in addressing issues. We routinely test and certify staff for work in critical and hazardous operations to ensure a high level of safe working practices.

We are conducting a program of upgrading all emergency response plans that will be complete in the second quarter of 2005.

We have reduced emissions through the continued use of our 55 MW power generation plant at Kumkol which uses, previously flared, produced associated gas. In addition, the Company has commissioned the Aryskum gas re-injection facility which reduces flared emissions in the Aryskum oilfield. PetroKazakhstan implemented several other capital projects such as bio-remediation, waste water treatment and improved handling of oilfield and domestic waste programs.

The Company continues to maintain a close working relationship with local authorities to ensure continuing compliance with the Republic of Kazakhstan’s laws and regulations.

26    PetroKazakhstan Inc.

Reserves

RESERVES RECONCILIATION BY FIELD

Proved plus probable (mmboe)

	Kumkol			Kumkol			South			East			North
	South			North			Kumkol			Kumkol			Nurali			Kyzylkiya			Aryskum			Maibulak			Akshabulak			Nurali			Aksai			Total
Reserves as of Jan 1, 2004		71.9			100.3			47.1			11.7			12.8			35.3			47.7			14.0			143.5			9.9			1.3			495.5
Revisions		26.4			17.0			3.6			(1.0	)		(2.9	)		4.7			19.5			1.7			40.6			0.9			(0.2	)		110.3
Production		(16.6	)		(13.6	)		(8.7	)		(0.2	)		(0.1	)		(3.7	)		(4.0	)		(0.8	)		(7.8	)		(0.5	)		(0.0	)		(56.0	)
Reserves as of Jan 1, 2005		81.7			103.7			42.0			10.5			9.8			36.3			63.2			14.9			176.3			10.3			1.1			549.8

Total PetroKazakhstan interest by field.As at January 1, 2005. McDaniel & Associates Consultants Ltd.

						Proved +
Reserves (mmboe)	Proved		%			Probable		%
Kumkol South		60.4		15.4	%		81.7		14.9	%
Kumkol North		83.7		21.3	%		103.7		18.9	%
South Kumkol		34.6		8.8	%		42.0		7.6	%
East Kumkol		7.1		1.8	%		10.5		1.9	%
North Nurali		1.8		0.5	%		9.8		1.8	%
Kyzylkiya		21.9		5.6	%		36.3		6.6	%
Aryskum		47.4		12.1	%		63.2		11.5	%
Maibulak		7.2		1.8	%		14.9		2.7	%
Akshabulak		123.0		31.4	%		176.3		32.0	%
Nurali		4.9		1.3	%		10.3		1.9	%
Aksai		0.0		0.0	%		1.1		0.2	%
Total		392.0		100.0	%		549.8		100.0	%

RESERVE EVALUATION

Summary of remaining reserves.As at January 1, 2005. McDaniel & Associates Consultants Ltd.

	Crude Oil				Natural Gas				Natural Gas Liquids				Total Reserves
	(mmbbls)				(bcf)				(mmbbls)				(mmboe)
	Property		Company		Property		Company		Property		Company		Property		Company
	Gross		Gross*		Gross		Gross*		Gross		Gross*		Gross		Gross*
Proved developed producing		342.8		224.4		49.3		31.6		0.0		0.0		351.0		229.7
Proved developed non-producing		73.5		48.7		0.0		0.0		0.0		0.0		73.5		48.7
Proved undeveloped		135.7		84.2		54.8		27.0		36.9		24.9		181.8		113.6
Total proved		552.0		357.3		104.1		58.6		36.9		24.9		606.3		392.0
Probable		219.2		145.6		53.2		29.8		10.7		7.2		238.7		157.8
Proved plus probable		771.2		502.9		157.3		88.4		47.6		32.1		845.0		549.8
Possible		389.1		254.8										389.1		254.8
Proved plus probable plus possible		1,160.3		757.7										1,234.1		804.6

* Company gross reserves are before royalties.

28    PetroKazakhstan Inc.

 

Summary of remaining reserves and present values. As at January 1, 2005. McDaniel & Associates Consultants Ltd.

Escalating Price Assumptions

	Total Reserves		Net Present Worth Value Before Income Taxes - Unrisked
	(mmboe)		(thousandsof U.S. dollars)
	Company
	Gross*		0%		5%		10%		15%		20%
Proved developed producing		229.7		3,793,089		3,310,873		2,951,983		2,674,373		2,452,976
Proved developed non-producing		48.7		849,166		650,887		520,695		429,922		363,558
Proved undeveloped		113.6		1,409,587		1,042,773		806,970		646,100		530,957
Total proved		392.0		6,051,842		5,004,533		4,279,648		3,750,395		3,347,491
Probable		157.8		2,591,473		1,837,721		1,376,159		1,075,414		869,004
Proved plus probable		549.8		8,643,315		6,842,254		5,655,807		4,825,809		4,216,495
Possible		254.8
Proved plus probable plus possible		804.6

* Company gross reserves are before royalties.

Summary of remaining reserves and present values. As at January 1, 2005. McDaniel & Associates Consultants Ltd.

Constant Price Assumptions

	Total Reserves		Net Present Worth Value Before Income Taxes - Unrisked
	(mmboe)		(thousandsof U.S. dollars)
	Company
	Gross*		0%		5%		10%		15%		20%
Proved developed producing		229.7		4,727,816		4,044,562		3,545,453		3,166,130		2,868,555
Proved developed non-producing		48.7		1,091,466		836,676		667,538		548,911		461,993
Proved undeveloped		113.6		1,854,692		1,378,832		1,069,072		856,048		702,891
Total proved		392.0		7,673,974		6,260,070		5,282,063		4,571,089		4,033,439
Probable		157.8		3,281,302		2,344,077		1,760,493		1,375,554		1,109,133
Proved plus probable		549.8		10,955,276		8,604,147		7,042,556		5,946,643		5,142,572
Possible		254.8
Proved plus probable plus possible		804.6

* Company gross reserves are before royalties.

29

Downstream Review

Our refinery at Shymkent continues to be the best performing refinery in Kazakhstan and further improvements are being made through process improvements.

BACKGROUND PetroKazakhstan exports crude oil from a variety of loading points through a number of pipeline systems, and rail and sea routes to different markets and customers. The flexibility provided through these alternative routes continues to allow us to improve our export and domestic sales netbacks and provides security in the event that one route is closed for some unforeseen operational reason.   Our refinery at Shymkent continues to be the best performing refinery in Kazakhstan and further improvements are being made through process improvements. Our refinery is well located and designed to serve both the domestic and export markets. PetroKazakhstan refined products continue to be recognised in both the domestic and export markets as being of exceptional quality and offering excellent value.   CRUDE OIL LOGISTICS PetroKazakhstan’s and Turgai Petroleum’s crude oil export shipments increased from 3.5 million tonnes (27.1 mmbbls) in 2003 to 3.9 million tonnes (30.2 mmbbls) in 2004, an increase in average daily shipments from 9,800 tonnes per day to 10,800 tonnes per day from 2003 to 2004. Seventy two percent of these shipments were loaded through our KAM pipeline and Dzhusaly Terminal which continues to generate the $2.00/bbl savings forecasted at the time the project was conceived.   Shipments through the CPC pipeline accounted for around 36% of all shipments as volumes approached their maximum contractual limit. Deliveries to China accounted for 19% of the overall shipments. Eighty eight percent of all shipments to China were made via the state owned pipeline to Atasu, eliminating a significant rail journey and the associated costs. Shipments to the Tehran refinery under the swap agreement with the National Iranian Oil Company grew steadily until June 2004, after which the Ministry of Energy and Mineral Resources (MEMR) of the Republic of Kazakhstan imposed export limits and finally blocked all exports on this route. The dialogue between PetroKazakhstan and MEMR is continuing and we are hopeful of a positive outcome. PetroKazakhstan’s position is that the imposition of quota restrictions on this route is unjustified as we provide all the necessary logistics, there are no physical constraints on this route and such restrictions are not in the best interest of the Republic of Kazakhstan or the neighbouring transit republics of Uzbekistan and Turkmenistan and is contrary to the policy wishes of the governments of Kazakhstan and Iran.   As part of our on-going strategy to take control of and improve our logistics costs, crude oil exports on an FCA (Free Carrier) basis were completely eliminated during 2004. In support of this initiative the number of rail cars in the fleet dedicated to PetroKazakhstan grew to approximately 5,000 at the end of 2004 up significantly from 2,000 at the end of 2003. The enlarged fleet comprises a mix of owned and long and short-term leased rail cars to provide operational and financial flexibility.   CRUDE OIL TRADING Throughout 2004, the international crude oil markets remained nervous about the lead up to the elections in Iraq, production interruptions, and the level of US inventories. At the same time strong demand from China and transportation capacity limits in Russia added further upward pressure to an already rising market. As a consequence, and due to an element of speculation by traders, international crude oil prices remained at extremely high levels with an enormous level of volatility. The highest recorded daily mean for Brent dated in 2004 was $52.03/bbl with a low of $29.12/bbl producing a price spread over the year of $22.90/bbl.

31

In response to supply concerns OPEC increased their output of heavier sour crudes. While this addressed the overall supply demand balance it caused a distortion of the heavy sour/light sweet differentials. Crude grades such as Urals saw their discount against Brent rise from around $1.60/bbl at the beginning of 2004 to a high of $7.50/bbl by October 2004. This generated a strong incentive for European refineries to buy the cheaper heavier grades and consequently the Mediterranean market became long on sweet crude and prices for sweet crudes began to slide against Brent in November 2004. Grades like CPC Blend and Siberian Light fared the worst, recording a discount to Brent of up to $4.50/bbl. While Kumkol performed better, the premium against Brent which is typically between $0.50 to $0.80/bbl slipped to a discount of between $0.10 and $2.00/bbl during the last 6 weeks of 2004. Kumkol closed the year at a discount to Brent of $0.12/bbl.   The improvement in our differentials to Brent recorded for the first three quarters of 2004 were as a result of the elimination of FCA contracts, the higher utilisation of better routes and the utilization of our KAM pipeline and Dzhusaly terminal. The fourth quarter of 2004 saw a deterioration of differentials reflecting the changes in the crude oil markets as mentioned above and the seasonal impact of night-time shipping restrictions in the Bosphorus Straits and some intermittent weather problems at Aktau. This situation is expected to continue for the first quarter of 2005. Nevertheless, the average differential for 2004 was a substantial improvement over 2003.   REFINERY OPERATIONS AND REFINED PRODUCT SALES The ongoing continuous improvement program at our Shymkent refinery continues to yield significant value benefits. We measure the change in product yield value on a fixed crude and product price basis thus eliminating the variations of market prices. This measure indicates a steady trend of improvements over the last two years which has generated an improvement in refining margins in excess of $2.00/bbl.   By the second quarter of 2004 the VDU was operating at maximum capacity and regular sales were being made through the Baltic port of Tallinn. During 2005 we expect to be able to increase the yield of VGO and to develop additional outlets for this product.   Refinery per unit costs showed an increase from $0.58/bbl in 2003 to $0.80/bbl which is line with the equivalent figures for 2002. The reasons for the increase were lower throughput, the maintenance turnaround in 2004 and the additional operating costs associated with the start up of the VDU. The average price of refined products improved by $7.84/bbl compared to 2003. These improvements were as a result of firmer market prices, the improved yield of higher value products, a greater proportion of refined product exports and improved pricing management keeping a balance between Kazakh prices and Russian competitor prices. Exports of refined products were on average around 75,000 tonnes per month (approximately 19,100 bpd) destined primarily for the neighbouring republics although some products such as VGO and fuel oil were sold on the international market in the Baltic and the Mediterranean.   HEALTH, SAFETY AND ENVIRONMENT Preservation of the environment and the health and safety of our refinery employees and contractors continues to be a top management priority. Environmental and safety indicators demonstrate a continuing improvement. In 2003 and 2004, a zero Lost Time Incident rate amongst refinery employees was achieved versus five incidents in 2002.   This performance is attributed to a focused effort in passing on responsibility for safety to the supervisory level. Emphasis is placed on meeting or improving on regulatory environmental limits and education of employees and contractors regarding occupational health issues.   The oil and gas industry is a focal point for environmental performance and scrutiny by government authorities. The Republic of Kazakhstan is no exception. Our refinery faces increasingly stringent limits imposed by the Kazakh ministries.   In 2004, with the exception of a minor spill from a waste water line which posed no environmental hazard, the refinery performance continued to improve. Waste water from the refinery to off-site treatment works has declined by 43% in the last two years. Since 2002, refinery emissions have consistently been at least 10% under license limits.   We are well placed to meet future challenges. Areas of environmental focus in 2005 include projects to:   4Reduce emissions from our refined fuels. 4Further reduce Sulphur Dioxide and Nitrous Oxide emissions. 4Improve water conservation and waste water quality. 4Improve the oily waste processing facilities. 4Rehabilitate soils.

32    PetroKazakhstan Inc.

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.

34    PetroKazakhstan Inc.

HIGHLIGHTS

	Years ended December 31
							2004			2003
	2004		2003		2002		vs 2003			vs 2002
Net 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			2002
Cash flow		560,491			399,975			216,794
Changes 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

	$ millions
Net income for the year ended December 31, 2002:		161
Increase in the price of crude oil		76
Increase in net return at Kumkol for refined products		72
Increase in refined products sales volumes		23
Increase in crude oil export sales volumes		16
Increase in depletion and depreciation		(16	)
Other variances		(15	)
Net income for the year ended December 31, 2003:		317
Increase in the price of crude oil		200
Increase in net return at Kumkol for refined products		92
Improvement in differential		32
Increase in crude oil export sales volumes		24
Increase 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		2002
Production, bopd		151,102		151,349		135,842
Differential ($/bbl)		12.62		14.11		13.97
Average refinedproducts price($/bbl)		25.02		17.18		13.59
Production expense($/bbl)		1.62		1.19		1.22
Refining cost($/bbl)		0.80		0.58		0.80
General and administrative($/bbl)		1.16		1.12		1.39
Effectiveincome tax rate(%)		37.5		32.8		38.0

Production. SeeVolumetrics for a discussion of our production.

36    PetroKazakhstan 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.

38    PetroKazakhstan 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.   SensitivitiesThe following table sets forth our estimate of the impact on net income and cash flow to changes in the following.

				Net income and
	Change			cash flow after tax
				($ millions)
Crude oil	$	1/bbl in Brent			28.5
Differential	$	1/bbl change			24.5
Refined products price	$	1/bbl in overall average			15.7
Production volume		5,000 bopd			14.0
Production cost		10	%		6.1
General and administrative expenses		10	%		4.0
Refining 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.

40    PetroKazakhstan Inc.

VOLUMETRICS

UPSTREAM

Production

The following table sets forth our barrels of oil produced per day by field:

Field (bopd)	2004		2003		2002
Kumkol South		44,851		58,718		66,726
Kumkol North		35,752		29,746		22,810
South Kumkol		23,682		29,846		22,728
Kyzylkiya		9,895		7,925		6,941
Aryskum		10,835		7,000		4,330
Maibulak		2,130		1,051		824
North Nurali		398		464		-
East Kumkol		589		-		634
License #952		270		-		-
License #951		7		-		-
Kazgermunai Fields		22,693		16,599		10,849
Total		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.

42    PetroKazakhstan 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			2002
Opening inventory of crude oil		2.87			2.72			0.70
Production		55.31			55.24			49.58
Crude oil purchased from third parties		1.09			0.03			0.68
Crude oil purchased from joint ventures(50%)		0.11			0.25			2.92
Sales 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				2002
	mmbbls		%		mmbbls		%		mmbbls		%
Crude oil exports		30.30		54.9		27.99		51.3		25.89		50.7
Crude oil transferred toDownstream		14.93		27.1		18.85		34.6		16.82		32.9
Crude oil transferred to Downstream by jointventures(50%)		5.82		10.6		5.31		9.7		4.39		8.6
Crude oil tolled by joint ventures (50%)		-		-		0.35		0.7		-		-
Royalty payments		4.10		7.4		2.03		3.7		3.48		6.8
Crude oil domestic sales		-		-		-		-		0.50		1.0
Total crude oil sales ortransfers		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		2002
Feedstock refined into product		26.70		30.01		25.77
Tolled volumes		0.53		0.59		1.33
Total 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		2002
Acquired from PKKR		14.93		18.85		16.82
Purchased fromjoint ventures(100%)		11.65		10.62		8.78
Tolled 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			2002
Opening inventory of crude oil feedstock		0.03			0.20			0.34
Purchase and acquisition of feedstock		26.60			29.90			25.60
Recoverable feedstock from traps *		0.10			(0.06	)		0.03
Feedstock 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			2002
Opening inventory of refined product		0.26			0.22			0.20
Refined product from feedstock**		3.23			3.64			3.09
Refined product purchased		0.05			0.02			0.09
Refined 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.

44    PetroKazakhstan 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			13.02
Production 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			9.37
Production 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.

46    PetroKazakhstan Inc.

REVENUE

					2004
Year ended December 31 ($000’s)	2004		2003		vs 2003			%
Crude oil		992,880		621,126		371,754			59.9
Refined products		639,405		481,326		158,079			32.8
Service fees		6,484		11,532		(5,048	)		(43.8	)
Interest income		3,658		3,340		318			9.5
Total 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		29.1
Refined products		481,326		332,639		148,687		44.7
Service fees		11,532		9,646		1,886		19.6
Interest income		3,340		1,951		1,389		71.2
Total 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 realized
	sold		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
2003
Crude sales sold FCA		2.89		15.50		44,781
Crude sales sold non-FCA		19.40		23.22		450,542
Kazgermunai export sales		5.70		17.78		101,350
Royalty payments		2.03		12.05		24,453
Total		30.02		20.69		621,126
2002
Crude sales sold FCA		12.74		13.48		171,711
Crude sales sold non-FCA		10.21		22.70		231,766
Kazgermunai export sales		2.94		14.22		41,813
Royalty payments		3.48		9.27		32,247
Crude oil domestic sales		0.50		7.15		3,577
Total		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.

48    PetroKazakhstan 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		481,326
2002		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		1.19
2002		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 expenses
4	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.

50    PetroKazakhstan Inc.

ROYALTIES AND TAXES

The following table sets forth the components of royalties and taxes:

($000’s)	2004		2003		2002
Royalties and production bonus		81,185		56,016		47,892
Tax assessments		14,452		5,401		5,121
ARNM assessment		5,045		-		-
Other taxes		25,762		20,878		15,701
Royalties 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 production
				at which		Effective			Effective			Effective
				maximum royalty		average royalty			average royalty			average royalty
Field	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.

52    PetroKazakhstan 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 inOverview and Strategy, Key Performance Indicators.

The table below sets out the components of transportation costs:

($000’s)	2004		2003		2002
Pipeline		33,207		58,004		56,230
Kazgermunai transportation		31,990		18,675		8,462
Crude oil export		157,529		137,251		93,305
Refined products export		40,320		2,011		-
Other		8,763		9,046		5,804
Total		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.

54    PetroKazakhstan Inc.

Our purchases of crude oil and refined products were as follows:

($000’s)	2004		2003		2002
Crude oil		104,575		55,886		69,410
Refined products		6,764		574		3,917
Total		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		2002
Crude oil		18,084		10,495		3,471
Refined products		19,850		18,034		19,782
Total		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 oil
	administrative		produced or processed*
	($000’s)		($/bbl)
2004
Upstream		34,955		0.63
Downstream		14,493		0.53
Corporate		11,467
Total		60,915
2003
Upstream		32,721		0.59
Downstream		16,075		0.53
Corporate		5,483
Total		54,279
2002
Upstream		37,093		0.75
Downstream		17,216		0.64
Corporate		4,570
Total		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.

56    PetroKazakhstan 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			2002
9.625% Notes		14,539			11,860			-
Term facility		6,082			9,858			4,106
Commitment fees and amortization of deferred charges on $100 million committed credit facility		629			-			-
Short-term debt		790			754			1,470
12% Notes		-			8,718			24,936
Kazgermunai debt		1,331			1,657			3,447
Term loans		503			594			332
PKOP bonds		469			2,576			1,514
Less 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 and
	depletion		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 and
	depletion		depletion
	($000’s)		($/bbl*)
2003
Upstream		63,321		1.15
Downstream		18,849		0.62
Corporate		182
Total		82,352
2002
Upstream		32,970		0.66
Downstream		13,347		0.49
Corporate		94
Total		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		2002
Upstream		218,214		78,893		71,807
Downstream		75,253		72,370		18,691
Corporate		7,616		4,359		9,845
Total		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.

58    PetroKazakhstan 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 rate
Up $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			2002
Upstream
Development wells		30,898			56,767			40,489
Facilities and equipment		90,945			92,002			67,884
Exploration		27,150			34,365			23,502
Downstream
Refinery HS&E		2,242			704			773
Refinery sustaining		5,802			2,571			4,019
Refinery return projects		3,661			15,024			3,364
Marketing and other		3,982			771			71
Corporate		1,272			1,009			-
Total capital expenditure		165,952			203,213			140,102
Less 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 jointventures)		211.0
Downstream		14.0
Marketing and transportation		2.0
Corporate		16.0
Total		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.

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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 years
Long-term debt		134.9		15.5		3.7		1.9		113.8
Estimated interest payments		92.8		17.9		36.9		37.6		0.4
Operating leases		104.0		43.0		59.8		1.2		-
Capital leases		-		-		-		-		-
Future site restoration costs		32.5		-		-		-		32.5
Work 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.

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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			2003
Cash and cash equivalents		199,105			184,660
Cash flow		560,491			399,975
Working capital *		215,681			151,737
Net debt **		(48,702	)		135,220
Ratio of cash flow to net debt		-			3.0
Ratio of cash flow to fixed charges***		20.9			10.6
Ratio 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.

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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 entitledKey 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.

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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.

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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
June30		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 ended
March 31		248,923		68,552		0.87		0.83
June 30		254,601		68,430		0.88		0.84
September 30		303,152		91,150		1.17		1.12
December 31		310,648		88,808		1.14		1.09
2002, Quarter ended
March 31		143,331		22,860		0.28		0.27
June 30		177,398		33,456		0.41		0.40
September 30		247,962		60,230		0.74		0.71
December 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.

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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.

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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.

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	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 Lefèvre, 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.

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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.

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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.

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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 Lefèvre 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.

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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 guidelines
4	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.

72    PetroKazakhstan 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

2004 Consolidated Financial Statements and Notes to the Consolidated Financial Statements
Management Report			FS2
Comments by Independent Registered Public Accounting Firm to U.S. Readers on Canada - U.S. Reporting Differences			FS3
Consolidated Financial Statements for the Years Ended December 31, 2004 and 2003:
	4	Consolidated Statements of Income and Retained Earnings (Deficit)	FS4
	4	Consolidated Balance Sheets	FS5
	4	Consolidated Statements of Cash Flow	FS6
Notes to the Consolidated Financial Statements			FS7

FS1

Management Report

The accompanying consolidated financial statements and all information in the annual report are the responsibility of management.

The consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles. When alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances. The consolidated financial statements are not precise since they include certain amounts based on estimates and judgments. Management has determined such amounts on a reasonable basis in order to ensure that the consolidated financial statements are presented fairly, in all material respects. Financial information presented elsewhere in this annual report has been prepared on a basis consistent with that in the consolidated financial statements.

PetroKazakhstan Inc. maintains systems of internal accounting and administrative controls. These systems are designed to provide reasonable assurance that financial information is relevant, reliable and accurate and that the Corporation’s assets are properly accounted for and adequately safeguarded.

The Audit Committee of the Board of Directors, composed of non-management Directors, meets regularly with management, as well as the external auditors, to discuss auditing (external and internal), internal controls, accounting policy and financial reporting matters. The Audit Committee reviews the consolidated financial statements with both management and the independent auditors and reports its finding to the Board of Directors before such statements are approved by the Board.

The consolidated financial statements have been audited by TOO Deloitte & Touche, the independent auditors, in accordance with the generally accepted auditing standards on behalf of the shareholders. TOO Deloitte & Touche have full and free access to the Audit Committee.

(signed)	(signed)
Bernard F. Isautier	Clayton Clift
President and Chief Executive Officer	Senior Vice President Finance and Chief Financial Officer
March 1, 2005	March 1, 2005

FS2    PetroKazakhstan Inc.

Report of Independent Registered Public Accounting Firm

To the Shareholders of PetroKazakhstan Inc.

We have audited the consolidated balance sheets of PetroKazakhstan Inc. (“the Corporation”) as at December 31, 2004 and 2003 and the consolidated statements of income and retained earnings, and cash flows for each of the years in the three-year period ended December 31, 2004. These consolidated financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance whether the consolidated financial statements are free of material misstatements. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Corporation as at December 31, 2004 and 2003 and the results of its operations and cash flows for each of the years in the three-year period ended December 31, 2004, in accordance with Canadian generally accepted accounting principles.

The Corporation is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Corporation’s internal control over financial reporting. Accordingly, we express no such opinion.

(signed)

TOO Deloitte & Touche

Almaty, Kazakhstan

March 1, 2005

Comments by Independent Registered Public Accounting Firm

to U.S. Readers on Canada - U.S. Reporting Differences

The standards of the Public Company Accounting Oversight Board (United States) require the addition of an explanatory paragraph (following the opinion paragraph) when there are changes in accounting principles that have a material effect on the comparability of the Corporation’s consolidated financial statements and changes that have been implemented in the financial statements, such as the changes described in Note 2 to the consolidated financial statements. Our report to the shareholders dated March 1, 2005 is expressed in accordance with Canadian reporting standards, which do not require a reference to such a change in accounting principles in the report of the independent registered public accounting firm when the change is properly accounted for and adequately disclosed in the consolidated financial statements.

(signed)

TOO Deloitte & Touche

Almaty, Kazakhstan

March 1, 2005

FS3

Consolidated Statements of Income and Retained Earnings (Deficit)

Years ended December 31 - EXPRESSED IN THOUSANDS OF UNITED STATES DOLLARS (EXCEPT PER SHARE AMOUNTS)

	2004			2003			2002
				(Restated -			(Restated -
				see Note 2)			see Note 2)
REVENUE
Crude oil		992,880			621,126			481,114
Refined products		639,405			481,326			332,639
Service fee		6,484			11,532			9,646
Interest income		3,658			3,340			1,951
		1,642,427			1,117,324			825,350
EXPENSES
Production		89,339			65,516			60,596
Royalties and taxes		126,444			82,295			68,714
Transportation		271,809			224,987			163,801
Refining		21,646			17,760			21,721
Crude oil and refined product purchases		111,339			56,460			73,327
Selling		37,934			28,529			23,253
General and administrative		60,915			54,279			58,879
Interest and financing costs		24,330			35,579			35,473
Depletion, depreciation and accretion		105,520			82,352			46,411
Foreign exchange (gain) loss		(9,919	)		(5,333	)		2,233
		839,357			642,424			554,408
INCOME BEFORE UNUSUAL ITEMS		803,070			474,900			270,942
UNUSUAL ITEMS
Arbitrationsettlement(Note 18)		-			-			7,134
INCOME BEFORE INCOME TAXES		803,070			474,900			263,808
INCOMETAXES(Note 13)
Current provision		356,249			165,379			100,808
Future income tax recovery		(55,166	)		(9,757	)		(465	)
		301,083			155,622			100,343
NET INCOME BEFORE NON-CONTROLLINGINTEREST		501,987			319,278			163,465
NON-CONTROLLING INTEREST		1,319			2,338			2,068
NET INCOME		500,668			316,940			161,397
RETAINED EARNINGS (DEFICIT), BEGINNINGOF YEAR		378,819			73,143			(70,873	)
Substantialissuer bid(Note 12)		(111,335	)		-			-
Normal course issuer bid (Note 12)		(35,528	)		(11,232	)		(17,350	)
Common share dividends		(39,253	)		-			-
Preferred share dividends		(35	)		(32	)		(31	)
RETAINED EARNINGS, END OF YEAR		693,336			378,819			73,143
BASIC NET INCOME PER SHARE(Note 14)		6.40			4.06			2.00
DILUTED NET INCOME PER SHARE (Note 14)		6.28			3.90			1.92

See accompanying notes to the consolidated financial statements.

FS4    PetroKazakhstan Inc.

Consolidated Balance Sheet

As at December 31 - EXPRESSED IN THOUSANDS OF UNITED STATES DOLLARS

	2004		2003
			(Restated -
			see Note 2)
ASSETS
CURRENT
Cash		199,105		184,660
Accounts receivable(Note 5)		198,504		150,293
Inventory(Note 6)		61,242		36,920
Prepaid expenses(Note 7)		62,179		44,901
Current portion of future income tax asset(Note 13)		65,431		14,697
		586,461		431,471
Deferred charges(Note 11)		4,662		6,729
Restrictedcash(Note 8)		47,741		35,468
Future incometax asset(Note 13)		28,470		25,466
Property, plant and equipment(Note 9)		601,747		542,317
TOTAL ASSETS		1,269,081		1,041,451
LIABILITIES
CURRENT
Accounts payable and accrued liabilities(Note 10)		161,759		88,422
Short-termdebt(Note 11)		15,541		73,225
Prepayments for crude oil and refined products		9,916		6,652
		187,216		168,299
Long-term debt(Note 11)		134,862		246,655
Asset retirement obligations(Note 2)		32,499		28,625
Future incometax liability(Note 13)		9,936		13,012
		364,513		456,591
Non-controlling interest		14,411		13,091
Preferred shares of subsidiary		80		80
COMMITMENTS AND CONTINGENCIES (Note 18)
SHAREHOLDERS’ EQUITY
Sharecapital(Note 12)		191,529		191,695
Contributed surplus (Note 2)		5,212		1,175
Retained earnings		693,336		378,819
		890,077		571,689
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		1,269,081		1,041,451

See accompanying notes to the consolidated financial statements.

Approved by the Board of Directors:

(signed)	(signed)
Bernard Isautier	Jacques Lefèvre
Director	Director

FS5

Consolidated Statements of Cash Flow

Years ended December 31 - EXPRESSED IN THOUSANDS OF UNITED STATES DOLLAR

	2004			2003			2002
				(Restated -			(Restated -
				see Note 2)			see Note 2)
OPERATING ACTIVITIES
Net income		500,668			316,940			161,397
Items not affecting cash:
Depletion, depreciation and accretion		105,520			82,352			46,411
Future income tax recovery		(55,166	)		(9,757	)		(465	)
Non-controlling interest		1,319			2,338			2,068
Compensationexpense(Note 2)		4,037			1,175			-
Amortization of deferred charges		3,572			3,936			1,402
Other non-cash charges		541			2,991			5,981
Cash flow		560,491			399,975			216,794
Changes in non-cash operating working capital items(Note 17)		(24,899	)		(60,625	)		(37,816	)
Cash flow from operating activities		535,592			339,350			178,978
FINANCING ACTIVITIES
Short-termdebt proceeds(Note 17)		98,006			77,411			109,954
Short-term debt repayment(Note 17)		(171,231	)		(154,528	)		(136,564	)
Long-term debt proceeds(Note 17)		-			312,986			17,195
Long-term debt repayment(Note 17)		(97,016	)		(217,699	)		(34,853	)
Deferred charges paid		(1,674	)		(3,642	)		(2,850	)
Common share dividends		(26,665	)		-			-
Preferred share dividends		(35	)		(32	)		(31	)
Purchase of common sharesunder a normal course issuer bid(Note 12)		(38,648	)		(14,848	)		(23,549	)
Purchase of common shares under a substantial issuer bid(Note 12)		(121,117	)		-			-
Proceeds from issue of share capital, net of share issuance costs		12,736			1,588			1,417
Cash flow (used in) from financing activities		(345,644	)		1,236			(69,281	)
INVESTING ACTIVITIES
Restricted cash		(12,273	)		(35,468	)		-
Capital expenditures		(163,230	)		(196,470	)		(136,852	)
Proceeds from sale of property, plant and equipment		-			1,258			-
Long-term investment		-			-			40,000
Acquisition of subsidiary, net of cash acquired		-			(38	)		(2,853	)
Purchase of preferred shares of subsidiary		-			(4	)		(8	)
Cash flow used in investing activities		(175,503	)		(230,722	)		(99,713	)
INCREASE IN CASH		14,445			109,864			9,984
CASH, BEGINNING OF YEAR		184,660			74,796			64,812
CASH, END OF YEAR		199,105			184,660			74,796

See accompanying notes to the consolidated financial statements.

FS6    PetroKazakhstan Inc.

Notes to Consolidated Financial Statements

Years ended December 31 - EXPRESSED IN THOUSANDS OF UNITED STATES DOLLARS, TABULAR AMOUNTS IN THOUSANDS OF DOLLARS (UNLESS OTHERWISE INDICATED)

NOTE 1	4	SIGNIFICANT ACCOUNTING POLICIES
		Principles of Consolidation PetroKazakhstan Inc. (“PetroKazakhstan” or the “Corporation”), formerly known as Hurricane Hydrocarbons Ltd., is an independent integrated oil and gas corporation, operating in the Republic of Kazakhstan, engaged in the acquisition, exploration, development and production of oil and gas, refining of oil, and the sale of oil and oil products. The consolidated financial statements of PetroKazakhstan have been prepared in accordance with Canadian Generally Accepted Accounting Principles and include the accounts of the Corporation, which is incorporated under the laws of Alberta, together with the accounts of its subsidiaries which are incorporated under the laws of Canada, Cyprus, England, the Netherlands, British Virgin Islands and Kazakhstan. Intercompany transactions are eliminated upon consolidation. On August 28, 1996, the Corporation entered into a Share Sale-Purchase Agreement with the Republic of Kazakhstan for the purchase of 100% of the issued common shares of Yuzhneftegas, a state owned joint stock company, later renamed to OJSC Hurricane Kumkol Munai and then to PetroKazakhstan Kumkol Resources (“PKKR”), operating in the South Turgai Basin, located in South Central Kazakhstan. On March 31, 2000, the Corporation acquired 88.4% of the common shares of OJSC Shymkentnefteorgsyntez, later renamed to OJSC Hurricane Oil Products and then to PetroKazakhstan Oil Products (“PKOP”). The Corporation has acquired an additional 8.3% interest in PKOP and had a 96.7% interest in PKOP as at December 31, 2004. PKOP owns and operates an oil refinery located in Shymkent, a city in South Central Kazakhstan. These consolidated financial statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (“GAAP”) and have been reconciled to U.S. Generally Accepted Accounting Principles in Note 20. Use of estimates The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. These estimates are subject to measurement uncertainty. Actual results could differ from and affect the results reported in these consolidated financial statements. With respect to accounting for oil and gas properties, amounts recorded for depletion, asset retirement obligations and amounts used for impairment test calculations, are based on estimates of oil and natural gas reserves and future development costs. By their nature, these estimates of reserves and the related future cash flows are subject to measurement uncertainty, and the impact on the consolidated financial statements of future periods could be material. The Corporation is involved in litigation and claims as described in Notes 18 and 19. The determination of contingent liabilities relating to litigation and claims is a complex process that involves judgements as to the outcomes and interpretation of laws and regulations. Changes in these judgements and interpretations may result in an increase or decrease in the Corporation’s contingent liabilities in the future. The determination of the provision for income taxes is an inherently complex process requiring management to interpret continually changing regulations and to make certain judgements. While income tax filings are subject to audits and reassessments, management believes adequate provision has been made for all income tax obligations. However, changes in the interpretations or judgements made may result in an increase or decrease in the Corporation’s income tax provision in the future. Joint ventures As more fully explained in Note 4, certain of PetroKazakhstan’s activities are conducted jointly with others through incorporated joint ventures. Accordingly, these consolidated financial statements reflect PetroKazakhstan’s proportionate interest in such activities.

FS7

Foreign currency translation

Foreign currency amounts, including those of foreign subsidiaries, are translated into United States dollars using the temporal method as follows:

(a)	Monetary assets and liabilities - at the rate of exchange in effect at year end.
(b)	Non-monetary assets and liabilities - at historical rates.
(c)	Revenues and expenses - at the average exchange rates during the period, except for provisions for depletion and depreciation, which are translated on the same basis as the related assets.

Gains or losses resulting from such translations are charged to operations.

Cash

Cash may include term deposits with original maturity terms not exceeding 90 days.

Inventories

Crude oil and oil products are recorded at the lower of average cost and net realizable value. Materials and supplies are recorded at the lower of average cost and replacement cost. Cost comprises direct materials and, where applicable, direct labour costs and those overheads and costs, which have been incurred in bringing the inventories to their present location and condition. Net realizable value represents the estimated selling price less all estimated costs to completion and costs to be incurred in marketing, selling and distribution.

Deferred charges

Costs related to the issuance of long-term debt are deferred and amortized over the term of the respective debt instrument on a straight-line basis.

Property, plant and equipment

a) Petroleum and natural gas properties

PetroKazakhstan follows the full cost method of accounting for oil and gas operations whereby all acquisition, exploration and development expenditures are capitalized. Capitalized expenditures include land acquisition costs, geological and geophysical expenses, costs of drilling both productive and non-productive wells, gathering and production facilities and equipment and overhead expenses related to exploration and development activities. Interest is capitalized during the development phase of capital projects until operations or production commences. Proceeds from sales of oil and gas properties are recorded as reductions of capitalized costs, unless the cost centre’s depreciation and depletion rate would change by a factor of 20% or more, whereupon gains or losses are recognized as income. Maintenance and repair costs are expensed as incurred, while improvements and major renovations to assets are capitalized.

Accumulated oil and gas costs and the estimated future development costs are depleted using the unit-of-production method based upon estimated proved reserves before royalties. Significant development projects and expenditures on exploration properties are excluded from the depletion calculation prior to assessment of the existence of proved reserves. Other plant and equipment costs are depreciated using the straight-line method based on the estimated useful lives of the assets which range from 8 to 20 years.

b) Refining

Maintenance and repairs, including minor renewals and improvements are charged to income as incurred. The cost of major renovations and improvements, which increase useful lives, are capitalized. Direct costs incurred in the construction of fixed assets, including labour, materials and supplies are capitalized.

Depreciation is calculated using the straight-line method based upon the following estimated useful lives:

Buildings, warehouses and storage facilities	10 - 20 years
Process machinery and equipment	5 - 20 years
Transport equipment	5 - 30 years
Other tangible fixed assets	3 - 15 years

FS8    PetroKazakhstan Inc.

c) Impairment of property, plant and equipment

Impairment of petroleum and natural gas properties

On a quarterly basis, petroleum and natural gas properties are reviewed for impairment. An impairment loss is recognized when the carrying amount of a cost centre is not recoverable and exceeds its fair value. The carrying amount is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition.

For estimating the future cash flows, the Corporation uses quoted Brent benchmark prices in the futures market and estimates made by its independent reserve engineers for crude oil prices, less transportation and selling expenses, royalties, production costs, general and administrative expenses, income tax and future asset retirement obligations.

Impairment of other assets

Other assets are periodically reviewed for impairment. If the carrying value exceeds the sum of the undiscounted future cash flows, the property’s value is impaired. The property’s fair value is determined using its estimated total future cash flows, discounted for the time value of money. Any excess carrying value is charged to depletion and depreciation.

Estimates of future cash flows for other assets includes the future cash flows (cash inflows less associated cash outflows) that are directly associated with, and that are expected to arise as a direct result of, the use of the assets. Estimate of future cash flows incorporate the Corporation’s own assumptions about its use, considering all available evidence, including internal budgets.

Asset Retirement Obligations

Asset retirement obligations are the estimated fair value of legal obligations associated with dismantlement and site restoration due to the retirement of tangible long-lived assets. Asset retirement obligations are not recorded for assets which have an indeterminable life. Estimated future asset retirement obligations are discounted to estimate the fair value of the obligation and recorded as a liability when the related assets are constructed and commissioned. The fair value of the obligation is also added to the value of property, plant and equipment and depleted using the unit-of-production method based upon estimated proved reserves before royalties. Accretion expense resulting from the increase in the present value of the liability due to the passage of time is recorded as depletion, depreciation and accretion expense.

Revenue recognition

Sales of petroleum and refined products are recorded in the period in which title to the petroleum or refined product transfers to the customer. Produced but unsold petroleum and refined products are recorded as inventory until sold. In the case of FCA sales (Free Carrier), title to the crude oil passes at the point of loading. The Corporation records revenue based on a provisional Brent price at the time of delivery, then marks to market at month end to reflect increases or decreases in prevailing Brent prices and adjusts the final price, if necessary, at the bill of lading date according to the contract terms.

Derivative commodity instruments

The Corporation utilizes derivative instruments to manage the Corporation’s exposure to fluctuations in the price of crude oil as described in Note 15. These derivative financial instruments are not used for speculative purposes and a system of controls is maintained that includes a policy covering the authorization, reporting and monitoring of derivative activity.

The Corporation formally documents all derivative instruments designated as hedges, the risk management objective and the strategy for undertaking the hedge.

Hedge accounting is used when there is a high degree of correlation between movements in the fair value of the derivative instrument and the item designated as being hedged. Gains and losses on derivatives that are designated as and determined to be effective hedges are deferred and recognized in the same period as the hedged item, and are recorded in the same manner as the hedged item in the Consolidated Statement of Income.

The Corporation assesses both at inception and over the term of the hedging relationship, whether the derivative instruments used in the hedging transactions are effective in offsetting changes in the fair value of cash flows of the hedged item. If correlation ceases, hedge accounting is terminated and changes in the market value of the derivative instruments are recognized in the period of change.

FS9

		Derivative instruments that are not designated as hedges for accounting purposes are recorded on the Consolidated Balance Sheet at fair value with any resulting gain or loss recognized in the Consolidated Statement of Income and Retained Earnings in the current period. Stock-based compensation The Corporation has a stock option plan as described in Note 12. Compensation expense is recognized in the Consolidated Statements of Income for all common share options granted to employees and non-executive directors on or after January 1, 2003, with a corresponding increase in contributed surplus recorded in the Consolidated Balance Sheet. Compensation expense for options granted on or after January 1, 2003 is determined based on the fair values at the time of grant, the cost of which is recognized in the Consolidated Statement of Income over the vesting periods of the respective options. For common share stock options granted prior to January 1, 2003, compensation expense is not recognized and the Corporation discloses the pro-forma earnings impact. Income taxes Income taxes are calculated using the liability method of tax accounting. Under this method, future income tax assets and liabilities are computed based on temporary differences between the tax basis and carrying amount on the balance sheet for assets and liabilities. Future income tax assets and liabilities are calculated using tax rates anticipated to apply in the periods that the temporary differences are expected to reverse. Comparative figures The presentation of certain amounts for previous years has been changed to conform with the presentation adopted for the current year.
NOTE 2	4	CHANGES IN ACCOUNTING STANDARDS
		Stock-Based Compensation Effective January 1, 2002 the Corporation adopted the recommendations of the Canadian Institute of Chartered Accountants regarding stock based compensation. The Canadian Institute of Chartered Accountants revised their recommendations and effective January 1, 2004 recognition of compensation expense using the fair value of the equity instrument granted was required. The Corporation adopted this recommendation on a prospective basis, effective January 1, 2003 as provided under the transitional provisions. Accordingly, the Corporation recognized compensation expense for all common stock options granted to employees and non-executive directors on or after January 1, 2003 using the estimated fair value. The Corporation has recorded compensation expense of $4.0 and $1.2 million in general and administrative expenses within the consolidated statements of income and retained earnings for the years ended December 31, 2004 and 2003, respectively, with a corresponding increase in contributed surplus within shareholder’s equity. Compensation expense for options granted on or after January 1, 2003 is recognized as compensation expense over the vesting period of the respective options. For common share options granted prior to January 1, 2003 the Corporation discloses the pro forma impact on net income and net income per share as if the estimated fair value of common stock options granted had been recognized as an expense. Asset Retirement Obligations Effective January 1, 2004, the Corporation 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. Total estimated asset retirement obligations are discounted to estimate the fair value of the obligation and recorded as a liability when the related assets are constructed and commissioned. The fair value of the obligation increases the value of property, plant and equipment and is depleted using the unit-of-production method based upon estimated proved reserves before royalties. Accretion expense, resulting from the increase in the present value of the liability due to the passage of time is recorded as part of depletion, depreciation and accretion expense. Estimated cash flows are 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. The new standard has been applied retroactively, and the financial statements of prior periods have been restated.

FS10    PetroKazakhstan Inc.

Adoption of the new standard of accounting for asset retirement obligations resulted in the following changes in the consolidated balance sheet and statement of income and retained earnings.

Changes in consolidated balance sheets:

As at December 31	2004			2003
Increase / (decrease)
Future income tax asset		377			651
Property, plant and equipment		14,457			15,181
Total assets		14,834			15,832
Asset retirement obligations		21,527			22,058
Retained earnings		(6,693	)		(6,226	)
Total liabilities and shareholders’ equity		14,834			15,832

Changes in consolidated statements of income and retained earnings for the years ended December 31, 2004 and 2003: 

	Years ended December
As at December 31	2004			2003			2002
Increase / (decrease)
Accretion expense		2,433			2,124			1,789
Depletion and depreciation		(2,240	)		(1,757	)		(466	)
Income before income taxes		(193	)		(367	)		(1,323	)
Income taxes		274			181			(152	)
Net income		(467	)		(548	)		(1,171	)
Basic net income per share		-			(0.01	)		(0.01	)
Diluted net income per share		-			(0.01	)		(0.01	)

The change in asset retirement obligations is as follows:

	2004			2003
Asset retirement obligations liability,beginning of year		28,625			22,831
Revisions		1,578			3,670
Accretion expense		2,433			2,124
Settlements		(137	)		-
Asset retirement obligations liability,end of year		32,499			28,625

Full Cost Accounting

In September 2003 the CICA issued Accounting Guideline 16 “Oil and Gas Accounting - Full Cost” (“AcG 16”), which replaced Accounting Guideline 5 “Full Cost Accounting in the Oil and Gas Industry” (“AcG 5”). The most significant change between AcG 16 and AcG 5 is that under AcG 16 the carrying value of oil and gas properties should not exceed their fair value. The fair value is equal to estimated future cash flows from proved reserves, unproved properties and major development projects using future price forecasts and costs discounted at a risk-free rate. This differs from the cost recovery ceiling test under AcG 5 that used undiscounted cash flows, and constant prices, less general and administrative, financing costs and taxes. The Corporation adopted AcG 16 effective January 1, 2004 and as at December 31, 2004 there were no indications of impairment.

Impairment of Long-Lived Assets

Effective January 1, 2004, the Corporation adopted the new recommendation of the CICA issued in December 2002 on impairment of long-lived assets. This recommendation provides guidance on the recognition, measurement and disclosure of impairment of long-lived assets. There is a requirement to recognize an impairment loss for a long-lived asset when its carrying amount exceeds the sum of the undiscounted cash flows expected from its use and eventual disposition. The impairment loss is measured as the amount by which carrying amount of the asset exceeds its fair value. As at December 31, 2004 there were no indications of impairment of long-lived assets.

FS11

Hedge Accounting
Effective January 1, 2004, the Corporation adopted Accounting Guideline 13 “Hedging Relationships” (AcG 13”). AcG 13 provides guidance regarding the identification, designation, documentation and effectiveness of hedging relationships for the purposes of applying hedge accounting. This guideline establishes certain conditions for when hedge accounting may be applied. The Corporation has applied hedge accounting for the financial instruments disclosed in Note 15.
New Canadian GAAP pronouncements
In June 2003 the CICA issued Accounting Guideline 15 “Consolidation of Variable Interest Entities” (“AcG15”). AcG15 provides guidance for determining when an enterprise consolidates the assets, liabilities and results of activities of a variable interest entity (“VIEs”) in its consolidated financial statements. In general, VIEs are entities that either do not have equity investors with voting rights or have equity investors that do not provide sufficient financial resources for the entity to support its activities. AcG15 is effective for the Corporation for the interim and annual financial statements beginning on January 1, 2005. The Corporation does not expect any impact on its consolidated financial statements.
In January 2005, the CICA issued the following new pronouncements:
4	Section 1530 “Comprehensive Income”.
4	Section 3251 “Equity” (replacing Section 3050 “Surplus”.
4	Section 3855 “Financial Instruments - Recognition and Measurement”.
4	Section 3865 “Hedges”
These are the highlights of the new standards:
4	All financial instruments, including derivatives, are to be included on the balance sheet and measured, either at their fair values or, in limited circumstances when fair value may not be considered most relevant, at cost or amortized cost. The standards also specify when gains and losses as a result of changes in fair values are to be recognized in the statement of income.
4	Existing requirements for hedge accounting are extended. Currently, the CICA has requirements that specify the circumstances under which hedge accounting is permissible, but do not comprehensively specify the accounting entries.
4	A new location for recognizing certain gains and losses, “Other comprehensive income”, has been introduced. This provides an ability for certain gains and losses arising from changes in fair value to be temporarily recorded outside of the statement of income, but in a transparent manner.
These new pronouncements are effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2006. Earlier adoption is permitted only as of the beginning of a fiscal year ending on or after December 31, 2004. The Corporation has yet to evaluate the impact of these new pronouncements on its consolidated financial statements.

NOTE 3 4 SEGMENTED INFORMATION

Following the acquisition of PKOP in 2000, the Corporation became an integrated oil and gas company. All of the commercial activity of the Corporation is concentrated in the Republic of Kazakhstan in Central Asia.
On a primary basis, the business segments are:
4	Upstream comprising the exploration, development and production of crude oil and natural gas.
4	Downstream comprising the refining and marketing of refined products and the management of the marketing of crude oil.
The accounting policies of the operating segments are the same as those described in Note 1. Identifiable assets are those used in the operation of the segment.
Corporate income tax for the year ended December 31, 2004 includes withholding tax on dividends paid to Canada. The consolidated income tax impact of non-deductible interest expense of $2.6 million for the year ended December 31, 2003 ($7.5 million - 2002) has been allocated to Corporate.
The Corporation does not disclose export revenue attributable to individual foreign countries as it is impractical to obtain the information.

FS12    PetroKazakhstan Inc.

Year ended December 31, 2004	Upstream			Downstream			Corporate			Eliminations			Consolidated
REVENUE
Crude oil		1,090,815			-			-			(97,935	)		992,880
Reined products		219,348			480,318			-			(60,261	)		639,405
Service fees		3,018			3,040			426			-			6,484
Interest income		1,765			638			1,255			-			3,658
		1,314,946			483,996			1,681			(158,196	)		1,642,427
EXPENSES
Production		89,339			-			-			-			89,339
Royalties and taxes		120,042			6,402			-			-			126,444
Transportation		271,809			-			-			-			271,809
Refining		-			21,646			-			-			21,646
Crude oil and refined product purchases		86,943			182,592			-			(158,196	)		111,339
Selling		18,083			19,851			-			-			37,934
General and administrative		34,955			14,493			11,467			-			60,915
Interest and financing costs		23,848			473			9			-			24,330
Depletion, depreciation and accretion		83,927			20,338			1,255			-			105,520
Foreign exchange loss (gain)		3,963			(13,767	)		(115	)		-			(9,919	)
		732,909			252,028			12,616			(158,196	)		839,357
INCOME (LOSS) BEFORE INCOME TAXES		582,037			231,968			(10,935	)		-			803,070
INCOME TAXES
Current provision		272,863			75,770			7,616			-			356,249
Future income tax		(54,649	)		(517	)		-			-			(55,166	)
		218,214			75,253			7,616			-			301,083
NON-CONTOLLING INTEREST		-			1,139			-			-			1,319
NET INCOME (LOSS)		363,823			155,396			(18,551	)		-			500,668

Included in Upstream crude revenue are sales to one customer in the amount of $167.4 million.

Eliminations are intersegment revenue.

As at December 31, 2004	Upstream		Downstream		Corporate		Consolidated
Total assets		1,038,727		180,081		50,273		1,269,081
Total liabilities		335,591		29,431		15,982		379,004
Capital expenditures for the year		148,993		15,687		1,272		165,952

Year Ended December 31, 2004	Export		Domestic		Consolidated
Crude oil		912,854		80,026		992,880
Refined products		219,508		419,897		639,405

FS13

Year ended December 31, 2003	Upstream			Downstream			Corporate			Eliminations			Consolidated
Revenue
Crude oil		719,009			-			-			(97,883	)		621,126
Refined products		76,885			441,200			-			(36,759	)		481,326
Service fee		9,086			2,191			255			-			11,532
Interest income		936			416			1,988			-			3,340
		805,916			443,807			2,243			(134,642	)		1,117,324
EXPENSES
Production		65,516			-			-			-			65,516
Royalties and taxes		80,046			2,249			-			-			82,295
Transportation		223,000			1,987			-			-			224,987
Refining		-			17,760			-			-			17,760
Crude oil and refined product purchases		55,161			135,941			-			(134,842	)		56,460
Selling		10,508			18,021			-			-			28,529
General and administrative		32,721			16,075			5.483			-			54,279
Interest and financing costs		24,226			2,576			8,777			-			35,579
Depletion, depreciation and accretion		63,321			18,849			182			-			82,352
Foreign exchange loss (gain)		2,632			(9,863	)		1,898			-			(5,333	)
		557,131			203,595			16,340			(134,842	)		642,424
INCOME (LOSS) BEFORE INCOME TAXES		248,785			240,212			(14,097	)		-			474,900
INCOME TAXES
Current provision		86,803			74,217			4,359			-			165,379
Future income tax		(7,910	)		(1,847	)		-						(9,757	)
		78,893			72,370			4,359			-			155,622
NON-CONTROLLING INTEREST		-			2,338			-			-			2,338
NET INCOME (LOSS)		169,892			165,504			(18,456	)		-			316,940

There were no sales to an individual customer in excess of 10% of consolidated revenue.

Eliminations are intersegment revenue.

As at December 31, 2003	Upstream		Downstream		Corporate		Consolidated
Total assets		737,691		157,474		146,286		1,041,451
Total liabilities		409,145		58,554		2,063		469,762
Capital expenditures for the year		183,134		19,070		1,009		203,213

Year Ended December 31, 2003	Export		Domestic		Consolidated
Crude oil		596,673		24,453		621,126
Refined products		112,316		369,010		481,326

FS14    PetroKazakhstan Inc.

Year ended December 31, 2002	Upstream		Downstream			Corporate			Eliminations			Consolidated
REVENUE
Crude oil		566,033		-			-			(84,919	)		481,114
Refined products		97,761		266,420			-			(31,542	)		332,639
Service fee		5,610		3,423			613			-			9,646
Interest income		282		217			1,452			-			1,951
		669,686		270,060			2,065			(116,461	)		825,350
EXPENSES
Production		60,596		-			-			-			60,596
Royalties and taxes		61,400		7,314			-			-			68,714
Transportation		163,791		10			-			-			163,801
Refining		-		21,721			-			-			21,721
Crude oil and reined product purchases		68,758		121,030			-			(116,461	)		73,327
Selling		6,815		16,438			-			-			23,253
General and administrative		37,093		17,216			4,570			-			58,879
Interest and financing costs		9,023		1,514			24,936			-			35,473
Depletion. depreciation and accretion		32,970		13,347			94			-			46,411
Foreign exchange loss		1,024		995			214			-			2,233
		441,470		199,585			29,814			(116,461	)		554,408
INCOME BEFORE UNUSUAL ITEMS		228,216		70,475			(27,749	)		-			270,942
Arbitration settlement		7,134		-			-			-			7,134
INCOME (LOSS) BEFORE INCOME TAXES		221,082		70,475			(27,749	)		-			263,808
INCOME TAXES
Current provision		64,500		26,463			9,845			-			100,808
Future income tax		7,307		(7,772	)		-			-			(465	)
		71,807		18,691			9,845			-			100,343
NON-CONTROLLING INTEREST		-		2,068			-			-			2,068
NET INCOME (LOSS)		149,275		49,716			(37,594	)		-			161,397

Included in Upstream crude oil revenue are sales to one customer in the amount of $103.0 million.

As at December 31, 2002	Upstream		Downstream		Corporate		Consolidated
Total assets		506,915		169,071		33,737		709,723
Total liabilities		172,474		42,141		228,242		442,857
Capital expenditures for the year		131,875		8,227		-		140,102

Year Ended December 31, 2002	Export		Domestic		Consolidated
Crude oil		445,290		35,824		481,114
Refined products		53,111		279,528		332,639

FS15

NOTE 4 4 JOINT VENTURES

The Corporation has the following interests in two joint ventures:
a)	a 50% equity shareholding with equivalent voting power in Turgai Petroleum CJSC (“Turgai”), which operates the northern part of the Kumkol field in Kazakhstan.
b)	a 50% equity shareholding with equivalent voting power in LLP Kazgermunai (“Kazgermunai”), which operates three oil fields in Kazakhstan: Akshabulak, Nurali and Aksai.
The Corporation’s interests in these joint ventures have been accounted for using the proportionate consolidation method. Under this method, the Corporation’s balance sheets, statements of income, retained earnings and deficit and cash flow include the Corporation’s share of income, expenses, assets, liabilities and cash flows of these joint ventures.
The following amounts are included in the Corporation’s consolidated financial statements as a result of the proportionate consolidation of its joint ventures and before consolidation eliminations:

Year ended December 31, 2004	Turgai			Kazgermunai			Total
Cash		34,678			50,800			85,478
Current assets, excluding cash		103,183			57,495			160,678
Property, plant and equipment		86,791			62,555			149,346
Current liabilities		77,849			24,343			102,192
Long-term debt		-			-			-
Revenue		310,221			225,882			536,103
Expenses		206,869			140,312			347,181
Net income		103,352			85,570			188,922
Cash flow from operating activities		66,634			77,968			144,602
Cash flow used in financing activities		(46,204	)		(25,632	)		(71,836	)
Cash flow used in investing activities		(18,328	)		(11,967	)		(30,295	)

Revenue for the year ended December 31, 2004 for Turgai includes $72.9 million of crude oil sales made to Downstream and $29.9 million of crude oil sales made by Turgai to Upstream. These amounts were eliminated on consolidation.

Revenue for the year ended December 31, 2004 for Kazgermunai includes $8.1 million of crude oil sales made to Upstream and $4.6 million crude oil sales to Downstream. These amounts were eliminated on consolidation.

Year ended December 31, 2003	Turgai			Kazgermunai			Total
Cash		8,370			10,432			18,802
Current assets, excluding cash		26,890			32,875			59,765
Property, plant and equipment		82,682			66,397			149,079
Current liabilities		76,533			11,260			87,793
Long-term debt		-			37,743			37,743
Revenue		118,167			111,860			230,027
Expenses		81,623			76,675			158,298
Net income		36,544			35,185			71,729
Cash flow from operating activities		58,566			39,089			97,655
Cash flow used in financing activities		-			(9,317	)		(9,317	)
Cash flow used in investing activities		(50,503	)		(22,193	)		(72,696	)

FS16    PetroKazakhstan Inc.

Revenue for the year ended December 31, 2003 for Turgai includes $35.9 million of crude oil sales made to Downstream and $2.5 million of crude oil sales made to Upstream. These amounts were eliminated on consolidation.

Revenue for the year ended December 31, 2003 for Kazgermunai includes $0.5 million of crude oil sales made to Upstream and no crude oil sales to Downstream. This amount was eliminated on consolidation.

Year ended December 31, 2002	Turgai			Kazgermunai			Total
Cash		307			2,854			3,161
Current assets, excluding cash		14,248			14,743			28,991
Property, plant and equipment		41,602			58,853			100,455
Current liabilities		24,909			4,798			29,707
Long-term debt		-			45,231			45,231
Revenue		72,938			48,284			121,222
Expenses		47,241			37,431			84,672
Net income		25,697			10,853			36,550
Cash flow from operating activities		25,420			19,264			44,684
Cash flow used in financing activities		-			(15,837	)		(15,837	)
Cash flow used in investing activities		(26,613	)		(12,089	)		(38,702	)

		Revenue for the year ended December 31, 2002 includes $55.0 million of crude oil sales made by Turgai and $6.3 million of crude oil sales made by Kazgermunai to Downstream. These amounts were eliminated on consolidation.
NOTE 5	4	ACCOUNTS RECEIVABLE
		Accounts receivable consist of the following:

	2004		2003
Trade		150,462		70,282
Value added tax recoverable		29,316		22,864
Due from Turgai		6,942		37,231
Other		11,784		19,916
		198,504		150,293

NOTE 6	4	INVENTORY
		Inventory consists of the following:

	2004		2003
Refined products		16,682		6,626
Crude oil produced		25,275		12,502
Materials and supplies		19,285		17,792
		61,242		36,920

FS17

NOTE 7	4	PREPAID EXPENSES
		Prepaid expenses consist of the following:

	2004		2003
Advances for services and equipment		16,825		10,930
Prepayment of transportation for crude oil sales		40,911		30,422
Prepayment for pipeline tariff		4,443		3,549
		62,179		44,901

NOTE 8	4	RESTRICTED CASH
		Restricted cash comprises:

a)	Cash dedicated to a debt service reserve account for the Corporation’s term facility of $8.7 million at December 31, 2004 ($10.5 million as at December 31, 2003). On September 30, 2004 the term facility was repaid in full. The Corporation discharged all hedging liabilities related to this facility as at December 31, 2004. The debt service reserve account was repaid in January 2005.
b)	Cash dedicated to a margin account for the Corporation’s hedging program being $39.0 million at December 31, 2004 ($25.0 million as at December 31, 2003).
Restricted cash is not available for current purposes.

NOTE 9 4 PROPERTY, PLANT AND EQUIPMENT

			Accumulated
			Depletion and		Net Book
As at December 31	Cost		Depreciation		Value
2004
Oil and gas		830,977		443,369		387,608
Refining		168,674		63,902		104,772
Transportation		118,098		14,639		103,459
		1,117,749		521,910		595,839
Other		10,813		4,905		5,908
		1,128,562		526,815		601,747
2003
Oil and gas		722,015		365,349		356,666
Refining		154,402		44,483		109,919
Transportation		73,666		4,087		69,579
		950,083		413,919		536,164
Other		9,365		3,212		6,153
		959,448		417,131		542,317

Excluded from the depletable base of oil and gas properties are undeveloped properties of $24.5 million (December 31, 2003 - $17.0 million). No work in progress is excluded from the depletable base of oil and gas properties as at December 31, 2004 ($29.1 million as at December 31, 2003). During the year ended December 31, 2004 no interest was capitalized ($0.4 million in 2003).

FS18    PetroKazakhstan Inc.

The Corporation used future Brent prices for the years 2005-2009 ($40.19 per barrel in 2005, $38.26 per barrel in 2006, $36.62 per barrel for 2007, $35.04 per barrel for 2008 and $33.53 per barrel for 2009) and estimates made by its independent reserve engineers for periods thereafter for its impairment test calculation. The average annual percentage change in the prices after 2009 was 2%.

NOTE 10 4 ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

Accounts payable and accrued liabilities consist of the following:

	2004		2003
Trade		70,160		66,115
Due to Turgai		19,668		-
Royalties		18,259		16,133
Income taxes		30,175		-
Common share dividends		12,588		-
Other		10,909		6,174
		161,759		88,422

NOTE 11 4 INDEBTEDNESS

Short-term debt

	2004		2003
Current portion of term facility		-		35,692
Current portion of term loans		2,039		2,039
Joint venture loan payable		-		11,000
PKOP bonds		-		24,494
Kazgermunai debt		13,502		-
		15,541		73,225

Long-term debt

	2004		2003
Long-term portion of term facility		-		71,384
Long-term portion of term loans		9,862		12,528
9.625% bonds		125,000		125,000
Kazgermunai debt		-		37,743
		134,862		246,655

Committed credit facility

On May 25, 2004 the Corporation 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 the Corporation’s hedging program. This amount is not available for general corporate purposes. Costs related to this facility amounting to $1.5 million are recorded as deferred charges and amortized over the life of the facility.

Term facility

On January 2, 2003, PetroKazakhstan Kumkol Resources (“PKKR”) entered into a $225.0 million term facility secured by crude oil export contracts. This facility was repayable in 42 equal monthly installments commencing July 2003. The facility bore interest at a rate of LIBOR plus 3.25% per annum. PKKR drew $190.0 million under this facility and chose not to utilize the remainder. On September 30, 2004 the Corporation had fully repaid the term facility. Unamortized issue costs of $2.1 million related to the term facility have been expensed.

FS19

Joint venture loan

The joint venture loan was fully repaid on October 7, 2004.

PKOP bonds

On February 16, 2001 PetroKazakhstan Oil Products (“PKOP”) registered 250,000 unsecured bonds (par value $100) in the amount of $25.0 million with the National Securities Commission of the Republic of Kazakhstan (the “PKOP bonds”). The PKOP bonds had a three-year maturity and bore a coupon rate of 10% per annum. The PKOP bonds were listed on the Kazakh Stock Exchange.

The PKOP bonds were fully redeemed on February 26, 2004.

Term loans

PKKR has obtained secured term loans guaranteed by Export Credit Agencies for certain equipment related to the KAM pipeline and the Gas Utilization Facility. The loans are secured by the equipment purchased, bear interest at LIBOR plus 4% per annum, are repayable in equal semi-annual installments and have final maturity dates ranging from five to seven years.

9.625% Notes

On February 12, 2003, PetroKazakhstan Finance B.V., a wholly owned subsidiary of PKKR issued U.S. $125.0 million 9.625% Notes due February 12, 2010. The Notes are unsecured, unconditionally guaranteed by the Corporation, PKKR and PKOP, and were issued at a price of 98.389% of par value. Each of the guarantors has agreed to certain covenants, including limitations on indebtedness, restrictions on payments of dividends, repurchase all or any part of the notes at the holders’ discretion in the case of a change of control. On March 15, 2004 the Corporation’s Notes were approved for listing on the Kazakhstan Stock Exchange.

As at December 31, 2004 issue costs and the discount on the sale of the Notes of $3.2 million are recorded as deferred charges and are amortized over the term of the Notes.

Kazgermunai debt

The Kazgermunai debt is non-recourse to the Corporation. The amounts set out below represent the 50% of Kazgermunai’s total debt, which has been included in the consolidated financial statements on a proportionate consolidation basis (see Note 4).

	2004		2003
Subordinated debt		-		25,057
Loan from Government of Kazakhstan		13,502		12,686
		13,502		37,743

Subordinated Debt

The subordinated debt bore interest at LIBOR plus 3% and was unsecured. Accrued interest was added to the principal on a semi-annual basis. On June 24, Kazgermunai repaid $24.3 million of its outstanding subordinated debt and as at December 31, 2004 the subordinated debt was repaid in full.

Amounts Repaid	2004		2003
Principal repaid		13,655		5,224
Interest repaid		11,977		3,848
		25,632		9,072

Loan from Government of Kazakhstan

The loan from the Government of Kazakhstan relates to exploration and development work performed on the Akshabulak, Nurali and Aksai fields prior to the formation of Kazgermunai. The loan bears interest at LIBOR plus 3% and is unsecured. Accrued interest is added to the principal on a semi-annual basis. Kazgermunai expects to repay the government loan in 2005.

FS20    PetroKazakhstan Inc.

Kazgermunai is restricted from paying dividends until all outstanding loans have been repaid in full.

Repayment

Principal repayments due for each of the next five years and in total are as follows:

													Less amounts
													included in			Total
													short-term			long-term
	2005		2006		2007		2008		2009		There-after		debt			debt
Term loans		2,039		2,039		1,645		1,252		626		4,300		(2,039	)		9,862
9.625% Notes		-		-		-		-		-		125,000		-			125,000
Kazgermunai		13,502		-		-		-		-		-		(13,502	)		-
		15,541		2,039		1,645		1,252		626		129,300		(15,541	)		134,862

Interest Expense

	2004		2003		2002
Interest on long-term debt		22,539		23,375		29,897
Interest on short-term debt		1,791		12,204		5,576
		24,330		35,579		35,473

NOTE 12 4 SHARE CAPITAL

The Corporation’s common shares are listed on the New York, Toronto, London and Frankfurt Stock Exchanges. On October 21, 2004 PetroKazakhstan shares were listed on the Kazakhstan Stock Exchange.

Authorized share capital consists of an unlimited number of Class A common shares, and an unlimited number of Class B redeemable preferred shares, issuable in series.

	2004						2003
December 31	Number			Amount			Number			Amount
Balance, beginning of year		77,920,226			191,695			78,956,875			193,723
Shares repurchased and cancelled pursuant to Normal Course IssuerBid (a)		(1,257,500	)		(3,120	)		(1,477,400	)		(3,616	)
Shares repurchased and cancelled pursuant to Substantial Issuer Bid(b)		(3,999,975	)		(9,782	)		-			-
Stock options exercised forcash		3,531,821			12,726			411,275			1,608
Corresponding convertible securities, converted (c)		28,558			10			29,476			(20	)
Balance, end of year		76,223,130			191,529			77,920,226			191,695

(a)

The Corporation’s Normal Course Issuer Bid program was renewed on August 5, 2003. Under the program up to 5,775,028 common shares may be repurchased for cancellation, during the period from August 7, 2003 to August 6, 2004. In August 2004 the Corporation again renewed this program which enabled the Corporation to repurchase 7,091,429 Class A common shares during the period from August 13, 2004 to August 12, 2005. The Corporation purchased and cancelled 1,477,400 shares at an average price of C$14.69 per share during the year ended December 31, 2003 and 1,257,500 shares at an average price of C$40.00 per share during the year ended December 31, 2004. The excess of cost over the book value for the shares purchased was applied to retained earnings.

(b)

In June 2004 the Corporation commenced a Substantial Issuer Bid to repurchase, for cancellation, up to C$160 million of its Class A common shares. As at December 31, 2004, the Corporation had purchased and cancelled 3,999,975 shares at an average price of C$40.00 per share. The excess of cost over the book value for the shares purchased was applied to retained earnings.

FS21

(c)	On March 31, 2000, in connection with the acquisition of PKOP, the Corporation issued corresponding convertible securities as follows:
	Options to purchase 1,105,753 Common Shares of the Corporation at prices and terms which were identical to those options outstanding at March 31, 2000, but in each case the number of options equalled 40.80% of the outstanding options. As at December 31, 2004 there were 8,159 outstanding corresponding convertible securities (36,717 - as at December 31, 2003).
(d)	The Corporation maintains an incentive stock option plan (“plan”) under which directors, officers and key personnel may be granted options to purchase class A common shares of the Corporation. The Corporation has reserved 8,076,050 class A common shares for issuance upon the exercise of options granted under the terms of the plan (2003 - 8,076,050). The Board of Directors determines the exercise price of each option, provided that no option shall be granted with an exercise price at a discount to market. The vesting periods established under the Corporation’s stock option plan and the term of the options are set by the board of directors, subject to a maximum term for any option of 10 years. Granted options have a vesting period of 3-5 years, except for options granted to non-executive directors, which vest immediately.
A summary of the status of the Corporation’s stock option plan as of December 31, 2004 and the changes during the year ended December 31, 2004 and year ended December 31, 2003 is presented below (expressed in Canadian dollars):

				Weighted Average
	Options			Exercise Price
Outstanding at December 31, 2001		5,736,880			3.07
Granted		605,000			14.65
Exercised		(1,393,281	)		1.09
Forfeited		(98,463	)		6.73
Outstanding at December 31, 2002		4,850,136			5.01
Granted		791,000			25.82
Exercised		(440,751	)		3.76
Forfeited		(84,925	)		9.27
Outstanding at December 31, 2003		5,115,460			8.17
Granted		724,100			42.50
Exercised		(3,560,379	)		4.77
Forfeited		(192,525	)		15.94
Outstanding at December 31, 2004		2,086,656			25.17
Options exercisable as at:
December 31, 2003		2,816,683			5.14
December 31, 2004		866,903			16.29

The weighted average fair value of the 724,100 options granted during the year ended December 31, 2004 was $8.7 million.

FS22    PetroKazakhstan Inc.

All stock options outstanding as of August 3, 2001 were re-priced in connection with the special dividend that was issued by the Corporation. The exercise price was reduced by C$3.78 per share. Certain options had exercise prices less than C$3.78.

As at December 31, 2004	Outstanding Options						Exercisable Options
			Weighted
			Average		Weighted				Weighted
	Number of		Remaining		Average		Number of		Average
Range of Exercise Price	Options		Contractual Life		Exercise Price		Options		Exercise Price
(C$)						(C$)				(C$)
0 to 2.50		128,159		0.22		0.61		128,159		0.61
2.50 to 7.50		101,000		1.25		6.13		68,500		5.88
7.50 to 12.50		290,656		1.77		9.39		214,253		9.52
12.50 to 17.50		295,500		2.95		14.72		116,750		14.65
17.50 to 31.62		607,241		3.96		26.14		289,241		26.68
31.62 to 44.50		664,100		4.93		43.48		50,000		43.50
		2,086,656		3.46		25.17		866,903		16.29

The pro forma net income per share had we recognized compensation expense using the fair value of common stock options granted for all stock options outstanding prior to January 1, 2003 follows:

	2004		2003		2002
Net income
As reported		500,668		316,940		161,397
Pro forma		499,532		314,752		158,867
Basic net income per share
As reported		6.40		4.06		2.00
Pro forma		6.38		4.03		1.96
Diluted net income per share
As reported		6.28		3.90		1.92
Pro forma		6.27		3.87		1.89

The estimated fair value of the stock options issued were determined using the Black-Scholes option pricing model with the following assumptions:

	2004			2003			2002
Risk-free interest rate		3.66	%		3.91	%		3.96	%
Expected option life		5 years			5 years			5 years
Expected volatility in the price of the Corporation's common shares		32	%		38	%		68	%
Expected dividends		2	%		-			-
Weighted average fair value of options granted during the year	$	9.88		$	7.82		$	5.73

FS23

NOTE 13 4 INCOME TAXES

The Corporation and its subsidiaries are required to file tax returns in the jurisdictions in which they operate. The primary operating jurisdiction is Kazakhstan with substantially all income earned in Kazakhstan.

The provision for income taxes differs from the results, which would have been obtained by applying the statutory tax rate of 30% to PetroKazakhstan’s income before income taxes. This difference results from the following items:

	2004			2003			2002
Income before income taxes		803,070			474,900			263,808
Statutory Kazakhstan income tax rate		30	%		30	%		30	%
Expected tax expense		240,921			142,470			79,142
Excess profit tax provision		35,000			-			-
Higher tax rate for Kazgermunai		12,165			2,444			-
Non-deductible amounts, net		6,148			9,324			16,475
Withholding tax on dividends		6,849			1,384			-
Reversal of lower tax rate for SouthKumkol field		-			-			4,726
Income tax expense		301,083			155,622			100,343

The following are the major future income tax assets and liabilities arising from temporary differences between the carrying values and tax basis of the following assets and liabilities:

	2004			2003
Future income tax assets:
Fixed assets		34,487			23,126
Excess profit tax		36,647			-
Provision for inter-company profit eliminations		15,516			9,087
Provision for royalties		5,448			4,831
Provision for obsolete inventories		1,310			1,180
Provision for doubtful debts		6			1,515
Other		487			424
Total future income tax assets		93,901			40,163
Less: current portion of future income tax assets		(65,431	)		(14,697	)
Long-term future income tax assets		28,470			25,466
Future income tax liabilities:
Fixed assets		9,936			13,012

The Corporation’s principal subsidiaries, PKKR and PKOP, and the Corporation’s other subsidiaries and joint ventures operating in Kazakhstan are separate taxpayers under Kazakhstani tax legislation.

FS24    PetroKazakhstan Inc.

Taxes are payable in Kazakhstan based on financial statements prepared in accordance with the laws of Kazakhstan rather than financial statements prepared in accordance with generally accepted accounting principles in Canada. The majority of the differences between the two sets of financial statements are temporary differences where an expense or revenue item is recorded for Canadian GAAP purposes in a different period than allowed under Kazakhstani law. The provision for Kazakhstani income taxes has been calculated by applying the Kazakhstani statutory tax rate of 30% to the income of PetroKazakhstan’s Kazakhstan subsidiaries.

Excess profit tax is in addition to statutory income taxes. Excess profit tax takes effect after the field has achieved a cumulative internal rate of return higher than 20% for the specific field. The excess profit tax ranges from 0% to 30% of taxable income for the year for PKKR and from 0% to 50% for Turgai.

A provision has been made for expected excess profit tax for the 2004 tax year for Turgai. Excess profit tax paid in one year is deductible in the computation of the excess profit tax liability in the following year.

NOTE 14 4 NET INCOME PER SHARE

The income per share calculations are based on the weighted average and diluted numbers of Class A common shares outstanding during the period as follows:

	2004		2003		2002
Weighted average number of commonshares outstanding		78,285,025		78,149,904		80,853,597
Dilution from options (includingconvertible securities)		1,423,880		3,142,302		3,346,939
Diluted number of shares outstanding		79,708,905		81,292,206		84,200,536

649,100 options were excluded from the calculation of diluted number of shares outstanding for the year ended December 31, 2004 as the exercise price was in excess of the average market price for the year. 774,000 options were excluded from the calculation of diluted number of shares outstanding for the year ended December 31, 2003. No options were excluded from the calculation of diluted number of shares outstanding for the year ended December 31, 2002.

NOTE 15 4 FINANCIAL INSTRUMENTS

The nature of the Corporation’s operations and issuance of long-term debt exposes the Corporation to fluctuations in commodity prices, foreign currency exchange rates, interest rates and credit risk. The Corporation recognizes these risks and manages operations in a manner such that exposure to these risks is minimized to the extent practical.

The Corporation’s financial instruments include cash, accounts receivable, all current liabilities and long-term debt. The fair value of cash, accounts receivable and current liabilities approximates their carrying amounts due to the short-term maturity of these instruments. The fair value of Kazgermunai debt and the term loans approximates their carrying value as they bear interest at market rates. The fair value of the 9.625% Notes is $139.5 million versus the carrying value of $125.0 million as at December 31, 2004 as determined through reference to market price.

a) Commodity price risk

The Corporation has entered into a commodity-hedging program where it is utilizing derivative instruments to manage the Corporation’s exposure to fluctuations in the price of crude oil. The Corporation has entered into the following contracts with a major financial institution.

FS25

Contract					Price Ceiling or
Amount	Contract Period		Contract Type		Contracted Price		Price Floor
(bbls per month)
362,000		January 2004 to March 2004		Dated Brent		29.80-29.82		-
75,000		January 2004 to December 2004		Zero cost collar		28.00		17.00
75,000		January 2004 to December 2004		Zero cost collar		29.00		17.00
75,000		January 2004 to December 2004		Zero cost collar		29.25		17.00
37,500		January 2004 to December 2004		Zero cost collar		29.60		17.00
110,000		January 2004 to December 2004		Zero cost collar		30.20		18.00
120,000		January 2005 to March 2005		IPE Future		26.30-26.52		-
40,000		April 2005 to June 2005		IPE Future		25.92		-
458,333		January 2005 to December 2005		IPE Future		25.65-25.90		-

During the year ended December 31, 2004, the Corporation has foregone revenue of $42.1 million through these contracts ($5.0 million during the year ended December 31, 2003).

The unrealized loss on these hedges as at December 31, 2004 is $60.9 million. This amount is deferred and recognized in the consolidated statement of income when the related contract is settled. The fair value of these hedges was determined based on forward prices as at December 31, 2004.

b) Foreign currency exchange rate risk

Export revenues are denominated in U.S. dollars and domestic sales of refined products and crude oil are made in the Tenge equivalent to U.S. dollars at the time of sale. Substantial portions of the Corporation’s operating costs are denominated in Tenge. The Corporation manages this exposure by operating in a manner that minimizes the need to convert between these currencies.

The Corporation, through its Downstream operations, has foreign currency exposure as the tax basis of its assets are denominated in Tenge. For Upstream, the Corporation has the possibility to revalue the tax basis of its assets using the industrial price index through the tax stability provisions of its Hydrocarbon Contracts. There is no significant forward market for the Tenge, therefore, the Corporation does not hedge this exposure.

c) Interest rate risk

The Corporation manages its interest rate risk through utilizing fixed and floating rate debt to finance its operations. The floating rate debt exposes the Corporation to fluctuations in interest payments due to changes in interest rates.

d) Credit risk

A substantial portion of the Corporation’s accounts receivable are with customers in the energy industry and are subject to normal industry risk. The Corporation’s crude oil sales are sold on credit to purchasers with A rating and all other sales are supported by letters of credit issued by major financial institutions. The Corporation’s sales of refined products are either made on a prepayment basis or supported by letters of credit issued by major financial institutions.

FS26    PetroKazakhstan Inc.

NOTE 16 4 RELATED PARTY TRANSACTIONS

The Corporation had the following transactions with its joint ventures.

($ millions)	2004		2003		2002
Crude oil purchased from Turgai		205.5		76.8		110.0
Crude oil purchased from Kazgermunai		25.5		1.1		12.6
Services provided to Turgai		5.0		21.0		16.4

The amounts in the table above represent 100% of transactions with the joint ventures. 50% of these amounts are eliminated on consolidation of the Corporation’s 50% interest in joint ventures. The remaining 50% remains in results of operations.

As at December 31, 2004 the Corporation has an account payable to the shareholder of the Turgai joint venture amounting to $24.8 million ($16.6 million as at December 31, 2003).

NOTE 17 4 CASH FLOW INFORMATION

Interest and income taxes paid:

	2004		2003		2002
Interest paid		22,111		33,988		30,622
Income taxes paid		322,907		173,275		97,903

Changes in non-cash operating working capital items:

	2004			2003			2002
Increase in accounts receivable		(48,211	)		(57,525	)		(40,144	)
(Increase)/decrease in inventory		(20,136	)		3,565			(10,583	)
Increase in prepaid expenses		(17,278	)		(306	)		(27,275	)
Increase/(decrease) in accounts payable and accrued liabilities		57,462			(9,470	)		44,068
Increase/(decrease) in prepaymentsfor crude oil and refined products		3,264			3,111			(3,882	)
		(24,899	)		(60,625	)		(37,816	)

Changes in short-tem debt:

	2004			2003			2002
Cash movements:
Proceeds from working capital facilities		98,006			66,079			64,954
Proceeds from term facility		-			-			40,000
Proceeds from PKOP bonds		-			11,332			-
Proceeds from joint venture loan		-			-			5,000
Total proceeds		98,006			77,411			109,954
Repayment of working capital facilities		(98,006	)		(69,566	)		(92,564	)
Pepayment of term facility		(35,692	)		(82,923	)		(44,000	)
Repayment of PKOP bonds		(24,494	)		-			-
Repayment of term loans		(2,039	)		(2,039	)		-
Repayment of joint venture loan		(11,000	)		-			-
Total repayment		(171,231	)		(154,528	)		(136,564	)
Non-cash movements:		15,541			134,035			(9,640	)
Net change		(57,684	)		56,918			(36,250	)

FS27

Changes in long-term debt:

	2004			2003			2002
Cash movement:
Proceeds from term facility		-			190,000			-
Proceeds for sale of 9.625% notes		-			122,986			-
12% Notes sold, net of discount		-			-			17,195
Total proceeds		-			312,986			17,195
Repayment of term facility		(71,384	)		-			(16,000	)
Redemption of 12% Notes		-			(208,210	)		-
Repayment of Kazgermunai debt		(25,632	)		(9,489	)		(18,853	)
Total repayment		(97,016	)		(217,699	)		(34,853	)
Non-cash movement		(14,777	)		(130,429	)		18,280
Net change		(111,793	)		(35.142	)		622

Non-cash movement includes reclassifications of current portion of long-term debt to short-term debt and current liabilities.

NOTE 18 4 COMMITMENTS AND CONTINGENCIES

Agency for Regulation of Natural Monopolies and Protection of Competition (“ARNM”)

PKOP

The ARNM alleged that PKOP charged prices for refined oil products that in total were $6.3 million in excess of ARNM authorized maximum prices. PKOP initiated legal proceedings to annul the ARNM claim and the court of first instance reduced the ARNM claim to approximately $1.1 million. PKOP and the ARNM appealed this decision to the Supreme Court. The Supreme Court recognized approximately $3.6 million of the ARNM’s original assessment. This amount has been paid and recorded in the financial statements. The Corporation has no plans to appeal.

PKOP received an additional assessment from ARNM in the amount of $8.8 million for allegedly charging prices for refined products in excess of ARNM authorized maximum prices. PKOP appealed this assessment. The ARNM revoked approximately $5.2 million of the assessment and the court of the first instance recognized approximately $1.4 million of the remaining $3.6 million. PKOP appealed this decision and was unsuccessful. $1.4 million has been recorded in the financial statements as a final settlement.

PKOP’s position remains that the ARNM does not have the right to establish prices for the refinery, and the Corporation, as the party in interest under the Privatization Agreement for the Shymkent Refinery, has notified the Government of Kazakhstan that it is in breach of provisions of the Privatization Agreement. The Corporation has the right to proceed to international arbitration under the terms of the Privatization Agreement.

Group companies

The ARNM claimed $34.1 million ($31.0 million at December 31, 2003) from a group company for allegedly violating Kazakhstan’s competition law. The group company initiated legal proceedings and the court of first instance dismissed the ARNM claim. The ARNM appealed this decision; the appellate court upheld the decision of the lower court. The ARNM has filed a motion to re-open the court case on the basis of new information.

The ARNM claimed approximately $96.4 million ($91.4 million at December 31, 2003) from group companies for allegedly violating Kazakhstan’s competition law. The group companies initiated legal action, and at the Astana City Court were unsuccessful in their challenge of allegations by the ARNM that these companies had violated Kazakhstan competition laws. The initial trial court judgment upheld the ARNM determination that these group companies had received unjustified revenues totaling approximately $96.4 million.

FS28    PetroKazakhstan Inc.

The group companies appealed this judgment to the Supreme Court. The initial Supreme Court hearing on the matter was held in the second quarter of 2004 and the Court suspended the case and instructed the parties to seek an agreed settlement. During the period from April to May 13, 2004 the parties did engage in discussions aimed at a settlement, but were unable to resolve the matter through negotiations.

On May 13, 2004, after a hearing on the merits, the Supreme Court overturned the lower court decision which was in favour of the ARNM and sent the case back to the Astana City Court for a new trial. During the third quarter of 2004, the General Prosecutor’s office filed a protest regarding the May 13 decision of the Supreme Court with the Supreme Court Supervisory Panel. On August 25, 2004, the Supervisory Panel issued an opinion upholding the May 13 decision and returned the case to the Astana City Court. In September 2004, the Astana City Court issued a ruling suspending further consideration of the merits of the case pending the completion of parallel investigations being conducted by the “Agency of the Republic of Kazakhstan for Fight Against Economic and Corruption Criminality”. This suspension was removed in late 2004 and the case is currently being reviewed by economic and financial experts under order of the Court. It is currently expected that the economic and financial expertise will be concluded during the spring of 2005 and that the case will, at that point, be subject to further review and decision by the Astana City Court. No provision has been made in the consolidated financial statements for these assessments.

It remains the Corporation’s view that the allegations leveled against the group companies are without justification. A highly competitive market exists for oil products within Kazakhstan and the current level of prices reflects current world crude oil prices. Also, the prices charged by the group companies are competitive with Russian imports and with those charged by distributors of the other two refineries in Kazakhstan.

The Corporation is considering its recourse rights under the terms of the Shymkent refinery Privatization Agreement, which clearly stipulates the right to sell any and all its products in Kazakhstan and abroad at free market prices.

The Corporation will continue to seek a dialogue with the appropriate authorities to address the concerns related to the pricing of refined products and possible measures to be taken to further promote transparency and effective monitoring of the dynamics of competition, consistent with market economy principles.

Tax matters

The local and national tax environment in the Republic of Kazakhstan is subject to change and inconsistent application, interpretation and enforcement. Non-compliance with Kazakhstan laws and regulations, as interpreted by the Kazakh authorities, can lead to the imposition of fines, penalties and interest.

In response to the Corporation’s submission, the Minister of Finance initiated the creation of a high-level Working Group between its officials and the Corporation’s representatives to address and seek resolution of all outstanding tax issues through dialogue and negotiations. On January 22, 2004, the Working Group signed a memorandum that sets out the agreed resolution of several important tax issues which were pending. Certain actions, such as the approval of the amendments to hydrocarbon contracts and issuance of an instruction letter, were required to fully implement the terms of the memorandum. The hydrocarbon contract amendments were approved on July 21, 2004, but the instruction letter has not been issued. The terms of this memorandum are reflected in the following discussion of the Corporation’s tax matters.

Tax assessments for 1998 and 1999

PKKR received tax assessments for 1998 and 1999. The assessments were for a total of approximately $10.5 million including taxes, fines, interest and penalties. PKKR was successful in challenging the assessments at the first level of the court system and was unsuccessful on the majority of the issues at the Supreme Court level. Specifically, PKKR was unsuccessful in obtaining agreement of the Supervisory Panel of the Supreme Court to hear its appeal on the assessed taxes. Accordingly, the Corporation provided for $2.9 million of the $10.5 million total assessment in the consolidated financial statements for the year ended December 31, 2002.

PKKR has been disputing the remaining $7.6 million (currently $8.0 million due to strengthening of the tenge), which relates to fines and penalties assessed, because PKKR believes there was an incorrect application of the provisions of tax legislation. However, PKKR paid this amount to stop the further accumulation of fines and penalties and recorded this payment as an account receivable pending resolution of the issue. The Working Group agreed with PKKR’s position and determined that there was an incorrect application of the provisions of the tax legislation. This matter was

FS29

simultaneously appealed to the Supervisory Panel of the Supreme Court (“Supervisory Panel”) due to time limitations. The Supervisory Panel remanded the case back to the lower court for a retrial. The lower court rejected the Supervisory Panel’s instruction, a retrial was not held, and the lower court let the original decision stand. The lower court’s refusal to comply with the Supervisory Panel’s instruction was appealed to the Supervisory Panel. The Supervisory Panel refused to hear the appeal.

The Ministry of Finance has requested that the Working Group memorandum be revised to reflect the Court’s decision. The Corporation does not agree and intends to pursue this matter with the Ministry of Finance. The Corporation believes, and the Ministry of Finance has previously agreed, that there was an incorrect application of the provisions of the tax legislation. Due to the uncertainty of the outcome, the Corporation has recorded, as an expense, the remaining amount of approximately $8.0 million in the consolidated financial statements for the year ended December 31, 2004.

Tax assessments for 2000 and 2001

PKKR also received assessments for 2000 and 2001. Challenges to the assessments were divided into two court cases. The first case was for amounts totaling approximately $13.0 million and at the first level of the court system PKKR was successful on $6.8 million of the $13.0 million and was unsuccessful on the remainder. The major issue on which PKKR was unsuccessful was the assessment of royalties on flared associated gas. PKKR believes the claim for royalties on flared associated gas, which has no commercial value, contravenes the provisions of its hydrocarbon contracts. PKKR appealed to the Supreme Court and the Supervisory Panel of the Supreme Court and was unsuccessful. Royalties on flared gas were recorded in the consolidated financial statements as follows: $2.2 million in 2002, $0.2 million in 2003 and $2.1 million in 2004. As a result of the lost cases, the Corporation recorded additional $2.9 million related to royalties on gas for 2002 and 2003 in its consolidated financial statements for the year ended December 31, 2004. Additionally, the Corporation has provided for $1.6 million relating to interest charges on this tax assessment. A further provision of $1.7 million was made regarding other issues, which was recorded in 2003.

The second case was for $13.5 million, with $6.9 million related to transfer pricing sent back by the court for re-negotiation. The final assessment resulting from the court hearing held in September 2003 totalled $783,000 including the transfer pricing issue. The Ministry of Finance appealed to the Supreme Court, approximately $2.1 million of the assessment relating to the methodology used to revalue tax pools for currency fluctuations ($1.7 million) and the accelerated write-off of certain assets ($0.4 million). PKKR was unsuccessful at the Supreme Court. The Corporation had provided for these amounts in its consolidated financial statements for the year ended December 31, 2003.

Excess profit tax

The Corporation, through its subsidiary PKKR and joint venture Turgai, is subject to excess profit tax under the terms of the Hydrocarbon Exploration and Production contracts they have for oil and gas production. The contracts are specific to each field.

Excess profit tax is in addition to statutory income taxes, which are at a rate of 30%, and excess profit tax takes effect after the field has achieved a cumulative internal rate of return higher than 20% for the specific field. The excess profit tax ranges from 0% to 30% of taxable income for the year for PKKR and from 0% to 50% for Turgai. As at December 31, 2004 the Corporation through Turgai provided for excess profit tax of $35.0 million for 2004. PetroKazakhstan did not incur excess profit tax in any of its other fields in 2004. It may, however be subject to excess profit tax for the year ended December 31, 2005 and subsequent years in certain of its fields.

Turgai tax assessments

During 2004, Turgai was subject to a tax audit for the years 2002-2003 and received a tax assessment for approximately $148.0 million including penalties and interest (the Corporation’s 50% share is $74.0 million). The major issue was an assessment for excess profit taxes of approximately $100.0 million including fines (the Corporation’s 50% share is $50.0 million). The Ministry of Finance had adopted the position that expenditures relating to construction in progress are not allowed as a cash outflow when computing the internal rate of return. The Corporation believes this position is contrary to the concept of an internal rate of return calculation and counter to the legislation of the Republic of Kazakhstan. The Corporation, fellow shareholder Lukoil and Turgai entered into discussions regarding this assessment with the Ministry of Finance. As a result, the assessment was re-issued for $27.0 million (the Corporation’s 50% share is $13.5 million) and discussions will be held to determine the correct method of calculating excess profit tax and to clarify the interpretation of current legislation. A further revised assessment may be issued depending on the outcome of the discussions. The Corporation will continue to work with government authorities, Turgai, and Lukoil to resolve the dispute. No provision has been made in the financial statements for this assessment.

FS30    PetroKazakhstan Inc.

Capital expenditures commitment

Pursuant to the Share Sale-Purchase Agreement with the Republic of Kazakhstan, a commitment was made to invest, in Kazakhstan, an aggregate of $280.0 million in capital expenditures, investments or other items that may be treated as capital assets of PKKR on or before December 31, 2002. The Government of Kazakhstan audited compliance with the investment commitment and has agreed that PKKR has more than met its commitments.

The Corporation has assumed the rights and obligations under the PKOP privatization agreement, whereby the Government of Kazakhstan privatized PKOP. Under this agreement, the Corporation was required to invest, or cause PKOP to invest, the Tenge equivalent of $150.0 million in capital expenditures or investments by December 31, 2001.

As of December 31, 2004, the Corporation believes it has met this commitment. The Government of Kazakhstan agrees with the Corporation’s assertion regarding $116.0 million of this commitment and is claiming the remaining obligation has not been met. If it is established that the Corporation has not met the remaining obligation, the Corporation may be required, under the terms of the agreement, to pay a penalty of 15% of the unfulfilled obligation or $5.1 million. No provision has been made in the financial statements for this matter.

Commitments

The Corporation has entered into a number of operating leases for rail cars, certain oil field equipment and office space. As at December 31, 2004 such commitments totaled $104.0 million. The obligations for each of the next five years and in total are as follows:

($ millions)	2005		2006		2007		2008		2009		Thereafter		Total
Operating leases		43.0		38.8		21.0		1.0		0.2		-		104.0
Work commitments		3.5		2.1		0.5		-		-		-		6.1
Total		46.5		40.9		21.5		1.0		0.2		-		110.1

		Legal proceedings The Corporation was named as defendant in a claim filed by a company alleging it was retained under a consulting contract from January 17, 1997 until services were suspended in May 1999. The liquidated principal amount claimed was, in aggregate, $6.6 million and an additional unspecified amount was claimed as an alleged penalty provision, with the total claim not to exceed $35.0 million. The arbitration decision was received and the Corporation paid $7.1 million for full settlement of the claim. This amount was recorded in the consolidated financial statements for the year ended December 31, 2002. The Corporation is involved in certain other litigation and claims associated with the normal course of operations. Management believes that settlements, if any, would not have a material impact on the Corporation’s financial statements.
NOTE 19	4	SUBSEQUENT EVENTS
		In February 2005 the Corporation, through one of its operating subsidiaries in Kazakhstan received a court claim filed by Turgai for $17.0 million in damages. This claim relates to the temporary production curtailment of Turgai in late December 2004. The Corporation believes the claim is without merit and, accordingly, no provision has been made in the financial statements. In February 2005 the Corporation, through its joint venture Kazgermunai, received a court claim filed by the Kyzylorda Akimat for failure to fulfill infrastructure obligations. The claim is for approximately $102.0 million (the Corporation’s 50% share is $51.0 million), $28.1 million relating to infrastructure obligations with the remainder being interest charges. The Corporation believes the claim is without merit as a substantial portion of the obligation has been met and the agreement does not impose deadlines. Accordingly, no provision has been made for this claim in the financial statements

FS31

NOTE 20	4	RECONCILIATION OF RESULTS FROM CANADIAN GAAP TO U.S. GAAP
		These consolidated financial statements have been prepared in accordance with accounting principles generally accepted in Canada (“Canadian GAAP”) which conform in all material respects with those applicable in the United States (“U.S. GAAP”), except as set forth below: Income taxes Recommendations of the CICA with respect to accounting for future income taxes differ from U.S. GAAP due to accounting for certain tax incentives. Under the tax legislation in the Republic of Kazakhstan, the Corporation may revalue the tax pool of its upstream assets using the prescribed inflation rate. A future income tax asset is recognized to reflect such revaluation in the consolidated financial statements, which is reversed for U.S. GAAP. Foreign currency translation PetroKazakhstan’s principal operating subsidiaries are PKKR and PKOP and for Canadian GAAP are classified as integrated which leads to the use of the temporal method of translation (Note 1). Under U.S. GAAP, the Corporation, on a consolidated basis, is required to translate the accounts of its principal operating subsidiaries using the current rate method. The significant changes which result from this difference are a reduction in the carrying value of capital assets and the creation of a cumulative translation account within the equity section of the balance sheet, which reduces total equity. Accounting for commodity hedges The Corporation has entered into a commodity-hedging program where it is utilizing derivative instruments as described in Note 17. The Corporation has designated these as cash flow hedges under SFAS 133 and recognizes in earnings, changes in fair value of these derivatives in the same period as the hedged item. Any change in the fair value of these cash flow hedges before that period are recognized in other comprehensive income. For Canadian GAAP the fair value is deferred and recognized as part of sales revenue when the hedges are settled. Comprehensive income for the year ended December 31, 2004 was reduced by $58.3 million (2003 - $1.6 million). The amount recorded as accounts payable as at December 31, 2004 was $60.9 million (2003 - $2.8 million). Accounting for oil and gas properties The Corporation has completed an impairment test calculation under U.S. GAAP at December 31, September 30, June 30 and March 31, in 2004, 2003 and 2002. According to Staff Accounting Bulletin 106 (“SAB 106”) released by the U.S. Securities and Exchange Commission in September 2004, the future cash outflows associated with settling asset retirement obligations should be excluded from the computation of the present value of estimated future net revenues for the purposes of the full cost impairment calculations. As at December 31, 2004 there was no impairment of full cost assets. There are certain differences between the full cost method of accounting for oil and gas assets as applied in Canada and as applied in the United States. The Corporation has reviewed such differences and determined that no variances in financial statement balances would have resulted from the application of full cost accounting in accordance with U.S. GAAP. Canadian GAAP requires that under full cost accounting, depletion for oil and gas properties, including future development costs, should be determined using proved reserves based on estimated future prices and costs. U.S. GAAP requires that future development costs should be based on current costs. As at December 31, 2004, the difference between Canadian GAAP and U.S. GAAP requirements for depletion was immaterial. Comprehensive income U.S. GAAP utilizes the concept of comprehensive income, which includes net income and other comprehensive income. As at December 31, 2004 there was no similar concept under Canadian GAAP. Other comprehensive income represents the change in equity during the period from transactions and other events from non-owner sources and includes items such as changes in the fair value of cash flow hedges.

FS32    PetroKazakhstan Inc.

Change in accounting principles

Accounting for Asset Retirement Obligations

Effective January 1, 2003, the Corporation adopted SFAS 143, Accounting for Asset Retirement Obligations. The Corporation recognized the estimated fair value of the liability for its assets retirement obligation. As at December 31, 2003 the fair value of the obligation was estimated to be $11.0 million (including accretion expense of $0.9 million for the year ended December 31, 2003). These estimated costs were recorded as an increase in the gross book value of property, plant and equipment with a corresponding increase in the asset retirement obligation. The asset retirement obligation is depleted on a unit-of-production basis over the useful life of the related assets. Accretion expense, resulting from the increase in the present value of the liability due to the passage of time, is recorded as part of depletion, depreciation and accretion expense.

During the year ended December 31, 2004, the Corporation revised the estimated fair value of its asset retirement obligations to $32.5 million (including accretion expense of $2.4 million for the year ended December 31, 2004). The increase in the estimate was recorded as an increase in property, plant and equipment with a corresponding increase in asset retirement obligations. This change in estimate had an impact of a $2.0 million decrease in net income for the year ended December 31, 2004.

The change in asset retirement obligations is as follows:

	2004			2003
Asset retirement obligations liability, beginning of year		11,041			4,167
Beginning balance reversed for adoption of SFAS 143		-			(4,167	)
Estimate following the adoption of SFAS 143		-			10,129
Revisions		19,162			-
Accretion expense		2,433			912
Settlements		(137	)		-
Asset retirement obligations liability, end of year		32,499			11,041

Under U.S. GAAP the new accounting standard pertaining to accounting for asset retirement obligations was effective January 1, 2003. Changes to the equivalent Canadian accounting standards were effective January 1, 2004 (see Note 2), which eliminated asset retirement obligations as a GAAP difference in 2004 and for future years. Under U.S. GAAP, the cumulative effect of initial application is required to be charged to net income in the year the standard became effective. Canadian GAAP requires this change in accounting policy to be applied retroactively and prior periods presented for comparative purposes restated.

The cumulative effect from the date the liability would have been recognized at the date of adoption of SFAS 143 was $2.1 million and is included in net income for the year ended December 31, 2003.

The asset retirement obligation liability, had we applied SFAS 143 for all years presented in these financial statements, would be $10.1 million as at January 1, 2003.

The pro forma information, had we applied SFAS 143 for comparative years presented in these consolidated financial statements, would be as follows:

	2002
Net income
As reported		162,539
Pro forma		162,498
Basic net income per share:
As reported		2.01
Pro forma		2.01
Diluted net income per share:
As reported		1.93
Pro forma		1.93

FS33

Consolidation of variable interest entities

In January 2003, FASB issued Interpretation No. 46 (“FIN 46”), “Consolidation of Variable Interest Entities.” FIN 46 clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” for certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated support from other parties. This Interpretation requires variable interest entities (“VIE”) to be consolidated by the primary beneficiary, which represents the enterprise that will absorb the majority of the VIE’s expected losses if they occur, receive a majority of the VIE’s residual returns if they occur, or both. FIN 46 was effective for VIE’s created after January 31, 2003 and for VIE’s in which an enterprise obtains an interest after that date. In December 2003, the FASB issued Interpretation No. 46R (“FIN 46R”), “Consolidation of Variable Interest Entities — an interpretation of Accounting Research Bulletin No. 51 (revised December 2003),” which replaces FIN 46. FIN 46R was primarily issued to clarify the required accounting for interests in VIE’s. The Corporation has determined that the adoption of FIN 46 and FIN 46R did not have a material impact on its financial position or results of operations.

Consolidated Statements of Income

The application of U.S. GAPP would have the following effects on net income as reported:

Years ended December 31	2004			2003			2002
Net income as reported in accordance with Canadian GAAP		500,668			316,940			161,397
Accounting for income taxes		-			629			-
Amortization of debt issue costs		-			-			(29	)
Depletion, depreciation and accretion expense		(6,018	)		1,614			1,171
Future income tax		1,026			(193	)		-
Net income under U.S. GAAP before cumulative effect of initial application of SFAS 143		495,676			318,990			162,539
Cumulative effect of initial application of SFAS 143		-			(2,107	)		-
Net income under U.S. GAAP		495,676			316,883			162,539
Basic income pershareunder U.S. GAAP:
Net income under U.S. GAAP before cumulative effect of initial application of SFAS 143		6.33			4.08			2.01
Cumulative effect of initial application of SFAS 143		-			(0.03	)		-
Net income under U.S. GAAP		6.33			4.05			2.01
Diluted income per share under U.S GAAP:
Net income under U.S. GAAP before cumulative effect of initial application of SFAS 143		6.22			3.92			1.93
Cumulative effect of initial application of SFAS 143		-			(0.02	)		-
Net income under U.S. GAAP		6.22			3.90			1.93
Comprehensive income
Foreign exchange translation adjustment		57,138			35,199			(2,235	)
Fair value adjustment cash flow hedges		(58,102	)		1,594			(4,392	)
Total comprehensive income		494,712			353,676			155,912

FS34    PetroKazakhstan Inc.

Stock based compensation

The Corporation has a stock-based compensation plan as described in Note 12. During the year ended December 2003, the Corporation adopted SFAS 123 and 148, which require recognition of compensation expense using the fair value of the equity instrument granted. The Corporation has adopted this recommendation on a prospective basis, effective January 1, 2003. Accordingly, the Corporation has recognized compensation expense for all common stock options granted to employees and non-executive directors on or after January 1, 2003 using the estimated fair value. The Corporation has recorded compensation expense of $4.0 and $1.2 million in general and administrative expenses within the consolidated statements of income and retained earnings for the years ended December 31, 2004 and 2003 with a corresponding increase in contributed surplus within shareholder’s equity. Compensation expense for options granted on or after January 1, 2003 is recognized as compensation expense over the vesting period of the respective options. For common share options granted prior to January 1, 2003 the pro forma impact on net income and net income per share are as follows:

Years ended December 31	2004			2003			2002
Net income under U.S. GAAP:
As reported		495,676			316,883			162,539
Add stock-based employee compensation expense included in reported net income		4,034			1,175			-
Deduct total stock-based employee compensation expense for all awards		(5,170	)		(3,363	)		(2,530	)
Pro forma		494,540			314,695			160,009
Basic net income per share:
As reported		6.33			4.05			2.01
Pro forma		6.32			4.03			1.98
Diluted net income per share:
As reported		6.22			3.90			1.93
Pro forma		6.21			3.87			1.90
Stock options vested during period (thousands)		371			381			513
Weighted average exercise price		3.06			6.59			6.02
Weighted average fair value of options vested during the period		6.73			5.74			4.93
Weighted average fair value of options granted during the period		9.88			7.82			5.73

The foregoing information is calculated in accordance with the Black-Scholes option pricing model, using the following data and assumptions: volatility, as of the date of grant, computed using the prior one to three-year weekly average prices of the Corporation’s common shares, which ranged from 32% to 68%; expected dividend yield - 2%; option terms to expiry - 5 years as defined by the option contracts; risk-free rate of return as of the date of grant - 3.60% to 3.96%, based on five year Government of Canada Bond yields.

FS35

CONSOLIDATED BALANCE SHEETS

The application of U.S. GAAP would have the following effects on balance sheet items as reported:

			Foreign			Fair value		��
			exchange			adjustment			Accounting			Asset
	As		translation			cash flow			for income			retirement			U.S.
	reported		adjustment			hedges			taxes			obligation			GAAP
December 31, 2004
Current assets		586,461														586,461
Deferred charges		4,662														4,662
Property, plant and equipment		601,747		43,692												645,439
Restricted cash		47,741														47,741
Future income tax assets		28,470								(5,528	)					22,942
Current liabilities		187,216					60,900									248,116
Long-term debt		134,862														134,862
Future income tax liability		9,936														9,936
Provision for future site restoration		32,499														32,499
Non-controlling interest		14,411														14,411
Preferred shares of subsidiary		80														80
Shareholders' equity		890,077		43,692			(60,900	)		(5,528	)					867,341
December 31, 2003
Current assets		431,471														431,471
Deferred charges		6,729														6,729
Property, plant and equipment		542,317		(13,446	)								(11,567	)		517,304
Restricted cash		35,468														35,468
Future income tax assets		25,466								(5,528	)		(1,025	)		18,913
Current liabilities		168,299					2,798									171,097
Long-term debt		246,655														246,655
Future income tax liability		13,012														13,012
Provision for future site restoration		28,625											(17,584	)		11,041
Non-controlling interest		13,091														13,091
Preferred shares of subsidiary		80														80
Shareholders' equity		571,689		(13,446	)		(2,798	)		(5,528	)		4,992			554,909

Consolidated Statements of Income and Retained Earnings (Deficit) Reclassifications

Interest and other income is presented within revenue under Canadian GAAP, under the U.S. GAAP this would be presented as a separate line item after operating income. Interest and financing costs is presented within expenses under Canadian GAAP, under U.S. GAAP this would be presented as a separate line item after operating income. Unusual items as presented under Canadian GAAP would be included within expenses under U.S. GAAP. The “Cash flow” subtotal line would not be presented in a cash flow statement prepared under U.S. GAAP.

New U.S. GAAP pronouncements

In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123R (“SFAS 123R”) “Share Based Payment”, which is a revision of Statement of Financial Accounting Standards No. 123 “Accounting for Stock-Based Compensation”. SFAS 123R establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. SFAS 123R focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS 123R is effective for the Corporation as of June 30, 2005. The Corporation is in the process of evaluating the impact of SFAS 123R on its consolidated financial statements.

The following new U.S. GAAP pronouncements are not expected to have any impact on the Corporation’s consolidated financial statements.

4	Statement of Financial Accounting Standards No. 151 (“SFAS 151”) - Inventory Costs, an Amendment of ARB No. 43, Chapter 4.
4	Statement of Financial Accounting Standards No. 152 (“SFAS 152”) - Accounting for Real Estate Time-Sharing Transactions—an amendment of FASB Statements No. 66 and 67.
4	Statement of Financial Accounting Standards No. 153 (“SFAS 153”) - Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29.

FS36    PetroKazakhstan Inc.

Historical Financial Data

Years ended December 31 - UNAUDITED - EXPRESSED IN MILLIONS OF UNITED STATES DOLLARS (EXCEPT PER SHARE AMOUNTS)

	2004			2003			2002			2001			2000			1999			1998			1997
INCOME
Revenue		1,642.4			1,117.3			825.4			603.1			523.2			155.2			175.9			94.8
Expenses		(733.8	)		(560.1	)		(508.1	)		(323.7	)		(223.5	)		(136.8	)		(153.9	)		(56.0	)
Depletion and depreciation		(105.5	)		(82.4	)		(46.4	)		(34.8	)		(14.7	)		(2.9	)		(55.3	)		(15.9	)
Ceiling test write-downs		-			-			-			-			-			(2.1	)		(173.4	)		-
Income taxes		(301.1	)		(155.6	)		(100.3	)		(68.4	)		(99.7	)		(17.7	)		(22.6	)		(7.1	)
Unusual items		-			-			(7.1	)		(5.5	)		(20.4	)		12.8			-			-
Non-controlling interest		(1.3	)		(2.3	)		(2.1	)		(1.9	)		(10.0	)		-			-			-
Net Income (Loss)		500.7			316.9			161.4			168.8			154.9			8.5			(229.3	)		15.8
CASH FLOW
Cash flow		560.5			400.0			216.8			200.3			179.4			17.0			0.6			32.0
Proceeds from shares issued		13.1			1.6			1.4			0.7			26.7			-			2.3			0.3
Share repurchased and cancelled		38.6			14.8			23.5			-			-			-			-			-
Capital expenditures		166.0			203.2			140.1			110.2			17.0			15.2			113.0			47.3
BALANCE SHEET
Property, plant and equipment		601.7			542.3			417.6			342.9			264.5			87.6			76.8			178.8
Long-term debt		134.9			246.7			281.8			281.2			82.0			-			-			180.5
Net debt		(48.7	)		135.2			223.3			268.9			47.8			167.8			178.1			154.9
Shareholders' Equity		890.1			571.7			266.9			127.6			185.0			(87.6	)		(96.0	)		130.9
Production(mbopd)		151.1			151.3			135.8			100.9			84.1			64.3			53.1			45.0
Reserves(mmboes)(as of January 1 of the following year) (proved plus probable)		549.8			495.4			518.3			512.3			487.6			458.6			449.5			429.9
STATISTICS
Weighted average common shares outstanding(millions)		78.29			78.15			80.85			79.81			70.59			44.51			44.24			42.83
Per Share (basic)
Net income (loss)	$	6.40		$	4.06		$	2.00		$	2.12		$	2.19		$	0.19		$	(5.18	)	$	0.37
Cash flow	$	7.16		$	5.12		$	2.68		$	2.51		$	2.54		$	0.38		$	0.01		$	0.75
Market Price for shares
Toronto(C$)
High		50.58			30.93			25.70			14.30			11.25			3.65			12.00			14.40
Low		29.00			13.87			8.27			7.10			2.70			0.25			1.40			5.05
Close		44.53			29.27			16.48			10.80			7.65			3.30			1.76			11.10
United States(U.S.$)
High		42.62			23.25			16.05			9.05			7.50			2.50			8.66			10.62
Low		21.67			9.51			5.23			4.41			1.06			0.06			0.84			3.67
Close		37.10			22.51			10.42			6.82			5.08			2.23			1.16			7.80

FS37

Share Price Performance

FS38    PetroKazakhstan Inc.

Officers of PetroKazakhstan Inc.

FS39

Corporate Information

DIRECTORS   Bernard F. Isautier President and Chief Executive Officer Windsor, United Kingdom   James B.C. Doak^{(1) (3)} President and Managing Partner, Megantic Asset Management Inc. Toronto, Ontario   Nurlan J. Kapparov^{(2) (3)} Chairman, KazInvest Bank Almaty, Kazakhstan   Jacques Lefèvre^{(1) (2)} Vice Chairman, Lafarge S.A. Paris, France   Louis W. MacEachern^{(2) (3)} President, Fortune Industries Ltd. Calgary, Alberta   Jan Bonde-Nielsen⁽¹⁾ Chairman, Greenoak Holdings London, England   (1) Audit Committee Member (2) Compensation Committee Member (3) Corporate Governance CommitteeMember   OFFICERS   Bernard F. Isautier President and Chief Executive Officer   Mike Azancot Senior Vice President, Exploration and Development   Clayton J. Clift Senior Vice President, Finance and Chief Financial Officer   Anthony R. Peart Senior Vice President, General Counsel and Corporate Secretary   Dermot A. Hassett Vice President, Marketing and Transportation   Ihor P. Wasylkiw Vice President, Investor Relations SHARE TRANSFER AGENT   Computershare Trust Company of Canada Calgary, Alberta Toronto, Ontario   AUDITORS   TOO Deloitte & Touche Almaty, Kazakhstan   BANKERS   ABN Amro Bank Kazakhstan Almaty, Kazakhstan   Bank Turan Alem Almaty, Kazakhstan   Citibank Almaty, Kazakhstan London, England   National Bank of Canada Calgary, Alberta   Barclays Bank Plc Nicosia, Cyprus   LEGAL COUNSEL   Davies Ward Phillips & Vineberg LLP Toronto, Ontario   Gowling Lafleur and Henderson LLP Calgary, Alberta   Paul, Weiss, Rifkind, Wharton & Garrison New York, New York   Denton Wilde Sapte Almaty, Kazakhstan   Salans Almaty, Kazakhstan   INDEPENDENT RESERVOIR CONSULTANTS   McDaniel & Associates Consultants Ltd. Calgary, Alberta OFFICE ADDRESSES   Registered Office   PetroKazakhstan Inc. Suite 1460 Sun Life Plaza, North Tower, 140 - 4th Avenue S.W. Calgary, Alberta Canada T2P 3N3   Tel: (403) 221-8435 Fax: (403) 221-8425 Website: www.petrokazakhstan.com Email: ir@petrokazakhstan.com   Contact: Ihor P. Wasylkiw Vice President, Investor Relations   UK Representative Office   Ascot Petroleum Consulting Ltd. Hogarth House, 31 Sheet Street Windsor, Berkshire United Kingdom SL4 1BY   Tel: 44 (1753) 410 020 Fax: 44 (1753) 410 030   Contact: Jeffrey D. Auld Vice President, Treasurer   Kazakhstan Offices   PetroKazakhstan Kumkol Resources PetroKazakhstan Oil Products 204 Karasai Batyr Street Almaty, Republic of Kazakhstan, 480009   Tel: 7 (3272) 58-18-48 Fax: 7 (3272) 58-18-60   Contact: Thomas Dvorak  President   SHARE LISTINGS   The Toronto Stock Exchange S&P/TSX 4 100 Composite Index 4Energy Index 4Canadian Midcap Index   New York Stock Exchange 4NYSE Composite Index 4NYSE Energy Index   The London Stock Exchange   Frankfurt Stock Exchange Trading Symbol - PKZ   Kazakhstan Stock Exchange Trading Symbol - CA_PKZ

FS40    PetroKazakhstan Inc.

CONVERSION AND EQUIVALENCY TABLES

	Multiply by
Kilometres to Miles	0.621	C$ 1.5973 to the U.S.$1.00 as at December 31, 2001
Metric Tonnes to U.S. barrels for 40° API crude	7.746	C$ 1.5781 to the U.S.$1.00 as at December 31, 2002
Hectares to Acres	2.471	C$ 1.2854 to the U.S.$1.00 as at December 31, 2003
Metres to Feet	3.281	C$ 1.2052 to the U.S.$1.00 as at December 31, 2004

1 square km = .386 square miles	Tenge 150.76 to the U.S.$1.00 as at December 31, 2001
1 square km = 247 acres	Tenge 154.96 to the U.S.$1.00 as at December 31, 2002
1 square mile = 640 acres	Tenge 143.19 to the U.S.$1.00 as at December 31, 2003
	Tenge 130.00 to the U.S. $1.00 as at December 31, 2004

ABBREVIATIONS AND DEFINITIONS

AIF	Annual Information Form	KAM	Kyzylkiya, Aryskum and Maibulak
API	American Petroleum Institute	km	kilometre(s)
ARNM	Agency for Regulation of Natural Monopolies and Protection of Competition	km2	square kilometre(s)
bbl	barrel	LIBOR	London Inter Bank Offering Rate
bbls	barrels	LPG	Liquified Petroleum Gas
bcf	billion cubic feet	mazut	heavy fuel oil
bfpd	barrels of fluid per day	mboe	thousand barrels of oil equivalent
bopd	barrels of oil per day	mboepd	thousand barrels of oil equivalent per day
bpd	barrels per day	mbopd	thousand barrels of oil per day
Brent	Brent dated oil reference price	MEMR	Ministry of Energy and Mineral Resources
BTC	Baku, Tbilisi, Ceyhan Pipeline	mm	million
bwpd	barrels of water per day	mmbbls	million barrels
C$	Canadian dollars	mmboe	million barrels of oil equivalent
CFR	cost and freight	mmtonnes	million metric tonnes
CICA	Canadian Institute of Chartered Accountants	MW	megawatt
CIF	cost insurance and freight	NCIB	Normal course Issuer Bid
CPC	Caspian Pipeline Consortium	NGLs	Natural Gas Liquids
CPF	Central Processing Facility	NYSE	New York Stock Exchange
CPT	carriage paid to	OPEC	Organization of Petroleum Exporting Countries
DAF	delivered at frontier	PKOP	PetroKazakhstan Oil Products
DDU	delivered duty unpaid	PKKR	PetroKazakhstan Kumkol Resources
DES	delivered ex ship	RWE	RWE-DEA AG
EBITDA	Earnings before interest, income taxes, depreciation, depletion and amortization	SFAS	Statement of Financial Accounting Standards
EEG	Erdol Erdgas Gommern GmbH	tones	metric tonnes
EOR	enhanced oil recovery	Turgai	Turgai Petroleum
ERP	Enterprise Resource Planning	TSX	Toronto Stock Exchange
FCA	Free Carrier	U.S.$	United States dollars
FOB	Free On Board	VAT	Value Added Tax
GAAP	Generally accepted accounting principles	VDU	Vacuum Distillation Unit
GDP	Gross Domestic Product	VGO	Vacuum Gas Oil
GUP	Gas Utilization Project	VIEs	Variable Interest Entities
HS&E	Health, safety and environment	WTO	World Trade Organization
IFC	International Finance Corporation	$/bbl U.S.	dollars per barrel
		2D	two dimensional
		3D	three dimensional

FORWARD-LOOKING STATEMENTS

This document contains forward-looking statements that involve risks and uncertainties. These statements relate to the Corporation’s future plans, objectives, expectations and intentions. These statements are identified by the use of words such as “may”, “will”, “expect”, “anticipate”, “intend”, “plan”, “estimate”, “believe”, “continue” or other similar expressions. These forward-looking statements reflect management’s current expectations and assumptions as to future events that may not prove to be accurate. Actual results are subject to a number of risks and uncertainties and could differ materially from those discussed in these statements. In light of the many risks and uncertainties surrounding our business and operations, you should keep in mind that the forward-looking statements described in this document may not transpire. The Corporation undertakes no obligation, and does not intend, to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.