Edgar Filing: PETROKAZAKHSTAN INC

6-K

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 6-K
REPORT OF FOREIGN PRIVATE ISSUER
PURSUANT TO RULE 13a-16 OR 15d-16 UNDER
THE SECURITIES EXCHANGE ACT OF 1934

For the month of August 29, 2003

PetroKazakhstan Inc.

(Translation of registrant’s name into English)

140-4th Avenue S.W. #1460, Calgary, Alberta, Canada T2P 3N3

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form20-F or Form40-F:

Form20-F |_| Form40-F |X|

Indicate by check mark whether by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes |_| No |X|

If “ Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): 82-

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant, has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date:

August 29, 2003
PetroKazakhstan Inc.

By:
/s/ Ihor Wasylkiw

Ihor P. Wasylkiw, P.Eng.,
Vice President Investor Relations

Quarter 2, 2003 Interim Report

Message to the shareholders

HIGHLIGHTS

PetroKazakhstan’s Second Quarter 2003 highlights included the following:

•

Second consecutive quarter of record earnings and cash flow

•

KAM pipeline completed and operational

•

Record crude oil export shipments

•

Increasing quarterly production of 145,066 barrels of oil per day

•

New reserves found in Aryskum and Maibulak fields

•

Gas utilization project progressing and on schedule

FINANCIAL HIGHLIGHTS

(EXPRESSED IN MILLIONS OF US$ EXCEPT PER SHARE AMOUNTS)		Six months ended June 30				Three months ended June 30
		2003		2002		2003		2002
Gross Revenue	$	498.7	$	320.7	$	252.1	$	177.4
Net income		136.4		56.9		68.2		33.8
Per share (basic)		1.74		0.70		0.87		0.42
Per share (diluted)		1.67		0.67		0.84		0.40
Cash flow		180.0		81.3		91.0		45.3
Per share (basic)		2.29		1.00		1.17		0.56
Per share (diluted)		2.20		0.96		1.12		0.53
Weighted Average Shares Outstanding
Basic		78,538,671		80,911,226		78,000,877		81,196,383
Diluted		81,676,831		84,405,177		81,173,957		84,690,334
Shares Outstanding at End of Period		77,653,139		81,371,497		77,653,139		81,371,497

PetroKazakhstan (or the “Company”) is pleased to announce its financial results for the second quarter of 2003 with $68.2 million of net income, a 101.8% increase over the quarter ended June 30, 2002 and $91.0 million of cash flow, a 100.8% increase over the quarter ended June 30, 2002. This represents basic net income per share of $0.87 and basic cash flow per share of $1.17 for the quarter. The comparable figures for the quarter ended June 30, 2002 were $0.42 basic net income per share and $0.56 basic cash flow per share.

For the six months ended June 30, 2003 net income was $136.4 million, a 139.7% increase over the same period of 2002, and cash flow of $179.9 million, a 121.3% increase over the same period of 2002. This represents basic net income per share of $1.74 and basic cash flow per share of $2.29. The comparable figures for the six months ended June 30, 2002, were net income per share of $0.70 and basic cash flow per share of $1.00.

PetroKazakhstan’s second quarter 2003 average production was 145,066 barrels of oil per day (“bopd”). This represents a 23.1% increase as compared to 117,844 bopd in the second quarter of 2002.

The Company’s share repurchase program, in effect since August 7, 2002 will terminate on August 6, 2003. The Company is in the process of renewing the repurchase program for a second year.

UPSTREAM OPERATIONS REVIEW

KAM PIPELINE

The 177 kilometre, 16-inch pipeline from Kumkol to Druzhaly via the KAM fields has been completed and now operational with the first railcars loaded on June 20th. The pipeline is capable of transporting and loading into rail cars 140,000 bopd and negates some 1,300 kilometres of pipeline and rail transportation currently in use. This material development has shown transportation cost savings in the region of $2.40 to $2.50 per barrel for the initial shipments. These cost savings may vary depending on the ultimate destination of future shipments. Full utilization of this facility is expected to be achieved in the third quarter of 2003 providing additional transportation and marketing capacity and flexibility in addition to the cost savings.

PRODUCTION

During the second quarter of 2003, PetroKazakhstan’s production volumes totaled 13.20 million barrels or an average of 145,066 barrels of oil per day (“bopd”). This represents a 23.1% increase over the second quarter 2002 production of 117,844 bopd and a 3.1% increase over the first quarter of 2003 production rates of 140,765 bopd. Adverse transportation conditions restricted crude oil exports, necessitating production restrictions in the early part of the second quarter. In addition, a temporary production injunction from the authorities, which has since been lifted, reduced production from the Aryskum field by some 9,000 bopd. Due to these deferrals in the first half of the year, the Company anticipates that the average production over the full year will now be in the region of 155,000 bopd representing a 14.1% increase over 2002 average production of 135,842. The revised production target for 2003 represent a 6.1% reduction from the original 2003 target of 165,000 bopd. For the week ending July 26, 2003, production had increased to approximately 162,000 bopd. PetroKazakhstan currently has 8 service rigs operating that are conducting repair and maintenance work on wells to optimize daily production.

KUMKOL FACILITIES AND FIELDS

Construction started on 2 new Free Water Knockout (FWKO) facilities. When commissioned later in the third quarter of 2003, these facilities will further enhance the fluid handling capabilities within the field as water production gradually increases.

Additional down hole pumps are due to be installed in Kumkol South and South Kumkol wells, which will result in production increases.

An additional high pressure pump has been installed in the Kumkol South Water Injection Facility and will result in an increased injection capacity of over 20,000 barrels per day. Final electrical and instrumentation connections are in progress and will be completed in July.

EXPLORATION

The exploration of the Company’s 260 D1 license, in which we are targeting previously unexplored stratigraphic plays continued on the discovery field, North Nurali, with the acquisition and interpretation of 3D seismic. The existence of the North Nurali field confirms the Company’s opinion that stratigraphic plays work in this region. Well locations have been selected and the first of three appraisal wells to delineate the field has reached total depth in July. The well has been logged confirming the extension of the reservoir and is being prepared for testing.

Four additional exploration wells, targeting stratigraphic plays in the basin, are planned for 2003; three in deep prospects and one shallow. All wells are expected to be completed by the first quarter of 2004.

GAS UTILIZATION

The 55 megawatt gas power plant at Kumkol is 96.0% complete and on schedule for commissioning during the third quarter of 2003. This project will enable PetroKazakhstan to utilize associated produced gas and to establish a more reliable source of electricity within its fields. Excess electricity will be provided for sale into the Kazakhstan domestic market. The gas utilization project is jointly owned, with PetroKazakhstan and Turgai Petroleum CJSC (“Turgai”), each having an equal share.

APPRAISAL AND DEVELOPMENTS

East Kumkol

Joint Venture agreements with Turgai for the development and operation of the East Kumkol field, which extends unto the Kumkol North license, continue to progress. Production is planned to resume in the fourth quarter of 2003.

KAM Fields

Six new wells were drilled in the KAM fields during the second quarter, three producers in Aryskum and three injectors in Maibulak. The Aryskum wells targeted possible category reserves along the oil rim and were each successful in proving additional reserves and tested at over 1,400 bopd. The three Maibulak well locations, selected for injectors based on 3D seismic and reservoir modeling, have each encountered new multiple productive sections and are being flow tested. The 6-inch pipeline connecting Kyzylkiya to Aryskum is complete and the upgrade of the processing facility to handle water production is on schedule for completion in the third quarter.

Construction of the Aryskum 8-inch pipeline to the main KAM pipeline is in progress as well as the Aryskum truck offloading facility and oil processing facility. Completion of the Aryskum construction is on schedule for the third quarter.

Equipment has been procured for the Maibulak water injection system; construction is expected to be completed by the end of the third quarter. Pumps have been installed on two producing wells and artificial lift will commence in July.

Kumkol North

A 27 well 2003 drilling program is progressing with 8 wells having been drilled to the end of June. Work has started on a new water injection plant due for commissioning in the third quarter and a new FWKO facility will be on line at the same time.

Kazgermunai

The program designed to increase field production by de-bottlenecking the system continued with the installation of larger export pumps. In addition, construction is underway for a water injection facility to be on-line in the fourth quarter. By the end of the year three production wells will be drilled, one in each of the Nurali, Aksai and Akshabulak East fields.

DOWNSTREAM MARKETING, TRADING AND REFINING

CRUDE OIL MARKETING AND TRANSPORTATION

The operational problems seen in the first quarter of 2003 and for the first month of the second quarter at various ports were vastly improved during the last two months of the second quarter. Shipments of crude increased to 7.04 million barrels or 77,317 bopd (908,352 tonnes) in the second quarter of 2003 compared to 5.25 million barrels or 58,354 bopd (677,983 tonnes) in the first quarter of 2003 and 6.71 million barrels or 73,778 bopd (866,708 tonnes) in the second quarter of 2002. That represents an increase of 34.0% versus the first quarter of 2003 and an increase of 4.8% versus the second quarter of 2002.

Shipments to China increased by approximately 6.0% versus the first quarter of 2003. The Company has also initiated, in late May, shipments to China from the terminal of Atasu, owned and operated by KazTransOil. The use of the Atasu terminal reduces rail distance to the Chinese border by about 435 kilometres, as compared to the southern route via the Company’s terminal at Tekesu. Shipments to the Fergana refinery in Uzbekistan, a new outlet, grew in the second quarter of 2003.

Progress on the modifications at the unloading Ray Terminal, located near the Tehran refinery, continues for the Iranian swap. Exports of crude oil by this route are expected to commence in the fourth quarter of 2003. Kumkol crude will be transported by rail from Shymkent through Uzbekistan and Turkmenistan and on to the Tehran refinery via the Sarakhs border crossing station. The swap contract includes compensation to recognise the higher quality of Kumkol crude compared to Iranian Light. A minor amount of work is required at the Ray Terminal to receive Kumkol crude at the Tehran refinery. The work is being financed and carried out by the refining and distribution arm of National Iranian Oil Company (NIOC) and the national railway company.

Crude oil sales volumes recorded in the second quarter of 2003 increased by 17.9% or 1.1 million barrels (142,023 tonnes) as compared to the first quarter of 2003.

Although generally lower than the first quarter of 2003, Brent quotations in the second quarter remained buoyant throughout the quarter despite the cessation of hostilities in Iraq. US oil stocks remained low on the back of the Venezuelan strike and the civil disturbances in Nigeria. In addition the market did not expect a rapid return of Iraqi oil to the market place and this together with the US oil stocks issue kept world prices firm. The average Brent quotation for the second quarter was $26.03 per barrel compared to $31.51 during the first. The spread of the daily average quotations during the second quarter was a little over $6.00 per barrel with a low of $22.88 per barrel and a high of $28.96 per barrel.

REFINING AND REFINED PRODUCT SALES

Refined product sales were up 6.7% in the second quarter of 2003 versus the first quarter of 2003. The opportunity was taken to optimize returns when domestic netbacks were better than export netbacks for short periods during the second quarter. As a result of this opportunity, the maintenance shutdown planned for June 2003 was postponed. The next maintenance shutdown is planned for the fourth quarter of 2003. The refinery processed 7.5 million barrels or 82,659 bopd of crude during the second quarter of 2003 compared to 8.3 million barrels or 91,746 bopd during the first quarter of 2003. No third party crude was processed in either the second quarter of 2003 or second quarter of 2002 while 0.23 million barrels were refined for third parties in the first quarter of 2003 and is included in this production. The reduction in volumes processed is due to higher processing rates during the first quarter required in part as a result of the export problems faced during the first quarter. Comparison to the second quarter of 2002 is not meaningful as the refinery maintenance shutdown took place during that period.

A number of the efficiency improvement programs initiated at the refinery continued to yield more benefits through improved energy usage and cost reductions. The project to revamp and bring on stream the Vacuum Distillation Unit continues to progress and is on track for completion later in 2003. The completion of this upgrade will allow the refinery to increase its production of higher valued distillates and reduce the overall production of lower value Mazut fuel oil.

Product prices continued to improve in the second quarter versus the first. Weighted average prices were approximately $1.20 per barrel ($9.31 per tonne) better against the first quarter of 2003 and $2.44 per barrel ($18.90 per tonne) better than the same period last year.

Respectfully submitted on behalf of the board of Directors,

(signed)

Bernard F. Isautier
President and Chief Executive Officer July 29, 2003

MANAGEMENT’S DISCUSSION AND ANALYSIS

Our Corporation, PetroKazakhstan Inc., was previously known as Hurricane Hydrocarbons Ltd. Our main operating subsidiaries Hurricane Kumkol Munai (“HKM”) and Hurricane Oil Products (“HOP”) were renamed PetroKazakhstan Kumkol Resources (“PKKR”) and PetroKazakhstan Oil Products (“PKOP”), respectively.

The following Management’s Discussion and Analysis (“MD&A”) of the financial condition and results of our operations should be read in conjunction with the unaudited consolidated financial statements of the Corporation included in this report and our MD&A and audited consolidated financial statements for the year ended December 31, 2002. Our financial statements have been prepared in accordance with Canadian 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.

In our Management’s Discussion and Analysis we use certain terms, which are specific to the oil and gas industry, including “netback” and “cash flow”. These are non-GAAP terms and are defined within our document. Cash flow is defined as cash generated from operating activities before changes in non-cash working capital.

Except as otherwise required by the context, reference in this Management’s Discussion and Analysis to “our”, “we” or “us” refer to the combined business of PetroKazakhstan Inc. and all of its subsidiaries and joint ventures.

All numbers are in U.S. Dollars unless otherwise indicated.

RESULTS OF OPERATIONS

For the quarter ended June 30, 2003 we generated $68.2 million of net income, a 101.8% increase over the quarter ended June 30, 2002 and $91.0 million of cash flow, a 100.8% increase over the quarter ended June 30, 2002. This represents basic net income per share of $0.87 and basic cash flow per share of $1.17 for the quarter. The comparable figures for the quarter ended June 30, 2002 were $0.42 basic net income per share and $0.56 basic cash flow per share.

For the six months ended June 30, 2003 our net income was $136.4 million, a 139.7% increase over the same period of 2002, and our cash flow was $179.9 million, a 121.3% increase over the same period of 2002. This represents basic net income per share of $1.74 and basic cash flow per share of $2.29. The comparable figures for the six months ended June 30, 2002, were net income per share of $0.70 and basic cash flow per share of $1.00.

We had average production of 145,066 barrels of oil per day (“bopd”) in the quarter, which represents a 23.1% increase as compared to 117,844 bopd for the same period last year.

The KAM pipeline was operational late in the second quarter with the first railcars loaded on June 20 with cost savings of $2.40 to $2.50 per barrel (“/bbl”) depending upon the destination. Our gas utilization project is on schedule for commissioning during the third quarter and our vacuum distillation unit is on schedule for commissioning in the fourth quarter.

The second quarter of 2003 also saw a significant increase in non-Free Carrier (“non-FCA”) sales as compared to the same period in 2002. As at June 30, 2003, approximately 1.3 million barrels of non-FCA sales were incomplete and hence, included in inventory. The effect of this was to cause an estimated $11.0 million of net income to be deferred into the third quarter of 2003. As at March 31, 2003 approximately 1.3 million barrels of non-FCA sales were incomplete and included in inventory. The net income realized in the second quarter from these sales was $8.6 million, as opposed to the $12.8 million, which was the reported expectation in the first quarter of 2003. This difference arose because of a difference between the expected price of $28.08/bbl and the realized price of $23.53/bbl. Market prices recovered at the end of the second quarter to $28.33/bbl.

REVENUE, PRODUCTION AND SALES

Total revenue was $252.1 million for the three months ended June 30, 2003, which represented an increase of $74.7 million over total revenue of $177.4 million for the three months ended June 30, 2002. Our increase in total revenue is due to a $21.0 million increase in crude oil revenue and a $54.9 million increase in refined products sales, which were offset by a $1.2 million net decrease in processing fees and interest and other income.

Total revenue was $498.7 million for the six months ended June 30, 2003, which represented an increase of $178.0 million over total revenue of $320.7 million for the six months ended June 30, 2002. The increase in total revenue is due to a $100.6 million increase in crude oil revenue and a $78.2 million increase in refined products sales, which was offset by a $0.8 million net decrease in processing fees and interest and other income.

Our crude oil revenue increased because of our increased production, higher crude oil export prices and our increasing use of non-FCA sales.

Our refined product revenue increased because of increased volumes and higher prices.

UPSTREAM

Upstream production averaged 145,066 bopd or 13.2 million barrels for the three months ended June 30, 2003, a 23.1% increase over the production volumes of 117,844 bopd or 10.7 million barrels for the three months ended June 30, 2002.

Significant export restrictions contributed to lower than expected production rates from our operated fields during the second quarter of 2002. We were able to rebound from these restrictions during the second half of 2002, with the installation of additional artificial lift, and a successful drilling campaign in South Kumkol. Second quarter production levels in 2003 reflect a more stable export environment and continued optimization of existing and newly competed wells. The maintenance shutdown of the refinery in the second quarter of 2002 also had a negative impact on 2002 production levels, while for the current year the refinery shutdown is scheduled for the fourth quarter of 2003.

The following table sets out total production figures from Upstream operations.

PRODUCTION
	Three months ended June 30
	2003	2002
	(MMbbls)	(MMbbls)
Opening inventory of crude oil	2.54	1.55
Production	13.20	10.73
Crude oil purchased from third parties	—	0.29
Crude oil purchased from joint ventures (50%)	(0.21)	0.55
Sales or transfers	(13.33)	(11.51)
Pipeline losses	(0.08)	(0.02)
Return of borrowed crude	—	—
Closing inventory of crude oil	2.12	1.59

For operational reasons, we purchase crude oil from one of our joint ventures and export the crude oil. Crude oil purchased from this joint venture is eliminated against crude oil revenue, as this more accurately portrays our business.

We do not eliminate crude oil purchased from our joint venture that remains in inventory at each balance sheet date to ensure that we properly reflect the liability to our joint venture. In periods, when our sales of crude oil purchased from our joint venture are in excess of actual crude oil purchased from our joint venture, we show a negative amount in our volume reconciliation table because part of the amount sold originated from opening inventory.

		Six months ended June 30
	2003	2002
	(MMbbls)	(MMbbls)
Opening inventory of crude oil	2.72	0.70
Production	25.87	21.83
Crude oil purchased from third parties	—	0.94
Crude oil purchased from joint ventures (50%)	0.41	0.55
Sales or transfers	(26.14)	(22.40)
Pipeline losses	(0.09)	(0.03)
Return of borrowed crude	(0.65)	—
Closing inventory of crude oil	2.12	1.59

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 year-end. This oil was returned in the first quarter of 2003.

The following table sets out total crude oil sales volumes from Upstream operations for the three months ended June 30.

SALES OF CRUDE OIL
		Three months ended June 30
	2003	2003	2002	2002
	(MMbbls)	(%)	(MMbbls)	(%)
Crude oil exports	7.23	54.2%	6.69	58.1%
Crude oil transferred to Downstream	4.53	34.0%	2.84	24.7%
Crude oil transferred to Downstream by joint ventures (50%)	1.57	11.8%	1.23	10.7%
Royalty payments	—	—	0.42	3.7%
Crude oil domestic sales	—	—	0.33	2.8%
Total crude oil sales or transfers	13.33	100%	11.51	100%

		Six months ended June 30
	2003	2003	2002	2002
	(MMbbls)	(%)	(MMbbls)	(%)
Crude oil exports	13.36	51.1%	11.22	50.1%
Crude oil transferred to Downstream	9.93	38.0%	5.82	26.0%
Crude oil transferred to Downstream by joint ventures (50%)	2.85	10.9%	3.06	13.7%
Royalty payments	—	—	1.40	6.3%
Crude oil domestic sales	—	—	0.90	3.9%
Total crude oil sales or transfers	26.14	100%	22.40	100%

During the first two quarters of 2003, we did not pay royalty in kind and we had no domestic sales of crude oil.

Total consolidated revenue from crude oil sales amounted to $134.2 million during the second quarter of 2003 and $113.2 million during the second quarter of 2002 ($276.4 million during the six months ended June 30, 2003 compared to $175.8 million during the same period of 2002).

The increase in the second quarter of 2003 resulted from an increase in the average price received ($18.56/bbl in the second quarter of 2003 compared to $15.22/bbl in the second quarter of 2003), offset in part by a slight decrease in sales volumes (7.23 mmbbls in the second quarter of 2003 compared to 7.44 mmbbls in the second quarter of 2002). Crude oil sales volumes were slightly less because of restrictions on export quotas and rail car availability. These difficulties have been addressed and in May-June of 2003 we achieved record levels of shipments, including deliveries from the Dzhusaly and Atasu terminals, which are new routes, with the majority of these sales to be realized in the third quarter of 2003. The major reasons for the increase in revenue are the increase in sales volumes by our Kazgermunai joint venture and the shift to non-FCA sales (4.35 million barrels sold in the second quarter 2003 at an average price of $21.58/bbl compared to 2.16 million barrels sold in the first quarter 2002 at an average price of $22.07/bbl).

The increase of $100.6 million during the six months ended June 30, 2003 compared to the same period of 2002 resulted from an increase in the average price received ($20.69/bbl in 2003 compared to $13.00/bbl in 2002), which was due to the shift to non-FCA sales (8.24 mmbbls sold during the six months ended June 30, 2003 versus 2.28 mmbbls in the same period of 2002).

Total crude oil revenue can be analysed as follows:

THREE MONTHS ENDED JUNE 30, 2003
	Quantity sold in	Net Realized Price	Revenue
	(MMbbls)	($ per bbl)	($000’s)
Crude sales sold FCA	1.43	13.77	19,689
Crude sales sold non-FCA	4.35	21.58	93,879
Kazgermunai export sales	1.45	14.21	20,607
Royalty payments	—	—	—
Crude oil domestic sales	—	—	—
Total	7.23	18.56	134,175

THREE MONTHS ENDED JUNE 30, 2002
	Quantity sold in	Net Realized Price	Revenue
	(MMbbls)	($ per bbl)	($000’s)
Crude sales sold FCA	3.88	13.36	51,818
Crude sales sold non-FCA	2.16	22.07	47,664
Kazgermunai export sales	0.65	12.67	8,238
Royalty payments	0.42	7.12	2,990
Crude oil domestic sales	0.33	7.62	2,513
Total	7.44	15.22	113,223

SIX MONTHS ENDED JUNE 30, 2003
	Quantity sold in	Net Realized Price	Revenue
	(MMbbls)	($ per bbl)	($000’s)
Crude sales sold FCA	2.51	15.65	39,292
Crude sales sold non-FCA	8.24	23.69	195,170
Kazgermunai export sales	2.61	16.07	41,955
Royalty payments	—	—	—
Crude oil domestic sales	—	—	—
Total	13.36	20.69	276,417

SIX MONTHS ENDED JUNE 30, 2002
	Quantity sold in	Net Realized Price	Revenue
	(MMbbls)	($ per bbl)	($000’s)
Crude sales sold FCA	8.19	12.40	101,587
Crude sales sold non-FCA	2.28	21.81	49,727
Kazgermunai export sales	0.75	12.42	9,315
Royalty payments	1.40	6.51	9,107
Crude oil domestic sales	0.90	6.72	6,050
Total	13.52	13.00	175,786

DOWNSTREAM

The crude oil feedstock for the refinery is primarily acquired from Upstream operations but purchases may be made from third parties.

The following table sets out the source of feedstock supplies for our refinery:

PURCHASE AND ACQUISITION OF FEEDSTOCK
	Three months ended June 30
	2003	2002
	(MMbbls)	(MMbbls)
Acquired from PKKR	4.53	2.05
Purchased from joint ventures (100%)	3.14	2.46
Purchased from third parties	—	—
Total feedstock acquired	7.67	4.51

	Six months ended June 30
	2003	2002
	(MMbbls)	(MMbbls)
Acquired from PKKR	9.93	5.03
Purchased from joint ventures (100%)	5.70	6.12
Purchased from third parties	—	—
Total feedstock acquired	15.63	11.15

The following table sets out the source of inventory levels of feedstock:

INVENTORY LEVELS OF FEEDSTOCK
	Three months ended June 30
	2003	2002
	(MMbbls)	(MMbbls)
Opening inventory of crude oil feedstock	0.08	0.09
Purchase and acquisition of feedstock	7.67	4.51
Recoverable feedstock from traps	—	0.01
Feedstock refined into product	(7.52)	(4.53)
Closing inventory of feedstock	0.23	0.08

The following table sets out the movement in inventory of refined product:

INVENTORY MOVEMENT OF REFINED PRODUCT
	Three months ended June 30
	2003	2002
	*(MM tonnes)**	(MM tonnes*)
Opening inventory of refined product	0.24	0.17
Refined product from feedstock	0.91	0.65
Refined product acquired	0.01	0.01
Refined product sold	(1.04)	(0.66)
Refined product internal use & yield losses	—	(0.01)
Closing inventory of refined product	0.12	0.16

The inventory of products represents a mix of products for which no unique conversion from barrels to tonnes exists. The standard conversion used for crude oil by us is 7.746 barrels to the tonne.

Crude oil feedstock is refined into a number of products, which are sold as refined products.

Refined product sales revenue for the three months ended June 30, 2003 was $117.0 million (three months ended June 30, 2002 was $62.1 million). Sales of refined products in the second quarter 2003 increased by $54.9 million as compared to the second quarter 2002, as a result of price increases and increased volumes. Average realised prices rose for all refined products during the three months ended June 30, 2003 as compared to 2002. They were $113.53/tonne and $94.62/tonne, respectively. We were able to achieve overall product price increases due to the optimisation of the domestic marketing business unit, whereby more of the product margin related to the end user is now captured.

Refined product sales revenue for the six months ended June 30, 2003 was $217.6 million, which increased by $78.2 million from $139.4 million in the same period of 2002. The increase resulted from the higher average realized price of $109.02/tonne (compared to $89.21/tonne in 2002) and higher sales volumes of 2.0 mm tonnes (compared to 1.6 mm tonnes in 2002). We were able to obtain higher prices and volumes for the six months ended June 30, 2003 as compared to 2002 as refined product imports from Russia declined. As well, demand continues to increase as a result of high GDP growth and vehicle ownership in Kazakhstan. We were also able to increase our refined product export volume as compared to the same period in 2002.

The table below sets out the products sold, the volumes sold, the average price achieved and the revenue for each product.

REFINED PRODUCT REVENUE
		Three months ended June 30, 2003
Product Produced	Tonnes	Average Price	Revenue
	Sold	($/tonne)	($000’s)
Gasoline	260,309	162.86	42,396
Diesel	370,555	128.37	47,568
Mazut	306,975	39.98	12,274
LPG	44,248	96.19	4,256
Jet Fuel	48,119	217.48	10,465
Total self refined	1,030,206	113.53	116,959
Resale of purchased refined products	—	—	—
Total refined product sales	1,030,206	113.53	116,959

		Three months ended June 30, 2002
Product Produced	Tonnes	Average Price	Revenue
	Sold	($/tonne)	($000’s)
Gasoline	187,760	110.18	20,688
Diesel	185,554	116.20	21,561
Mazut	205,518	41.80	8,591
LPG	27,101	70.77	1,918
Jet Fuel	37,319	212.47	7,929
Total self refined	643,252	94.34	60,687
Resale of purchased refined products	12,647	108.64	1,374
Total refined product sales	655,899	94.62	62,061

		Six months ended June 30, 2003
Product Produced	Tonnes	Average Price	Revenue
	Sold	($/tonne)	($000’s)
Gasoline	447,747	168.00	75,220
Diesel	685,700	127.16	87,195
Mazut	689,957	39.24	27,076
LPG	77,873	100.47	7,824
Jet Fuel	94,844	214.14	20,310
Total self refined	1,996,121	109.02	217,625
Resale of purchased refined products	—	—	—
Total refined product sales	1,996,121	109.02	217,625

		Six months ended June 30, 2002
Product Produced	Tonnes	Average Price	Revenue
	Sold	($/tonne)	($000’s)
Gasoline	387,482	112.15	43,457
Diesel	444,819	114.50	50,934
Mazut	538,401	35.51	19,120
LPG	56,371	73.26	4,130
Jet Fuel	83,149	216.89	18,034
Total self refined	1,510,222	89.84	135,675
Resale of purchased refined products	52,822	71.37	3,770
Total refined product sales	1,563,044	89.21	139,445

PROCESSING FEES

In addition to revenue generated from the refining and sale of product derived from acquired feed stock, the refinery also refined crude on behalf of third parties (“Tolling”) for which it receives a fee. The refinery did not toll any volumes for third parties during the quarters ended June 30, 2003 and 2002. During these periods crude producers elected to export their volumes due to the expectation that crude market prices would remain high. The refinery tolled 0.2 million barrels of crude oil for the six months ended June 30, 2003 compared to 0.7 million barrels during the same period of 2002.

The table below sets out the total quantity of oil processed for third parties into refined products, the average fee charged and revenue earned.

2003
	Volumes Processed	Fee	Processing Revenue
	(tonnes)	($/tonne)	($000’s)
First Quarter 2003	29,361	15.29	449
Second Quarter 2003	—	—	—

2002
	Volumes Processed	Fee	Processing Revenue
	(tonnes)	($/tonne)	($000’s)
First Quarter 2002	91,521	15.64	1,431
Second Quarter 2002	—	—	3

The decrease in the processing fee is attributable to the Tenge to US dollar exchange rate.

INTEREST AND OTHER INCOME

Revenue from interest and other income decreased by $1.1 million to $1.0 million for the three months ended June 30, 2003, as an adjustment was made to correct accrued interest income generated from cash deposits during the first quarter of 2003.

Revenue from interest and other income increased slightly by $0.1 million to $4.2 million for the six months ended June 30, 2003.

PRODUCTION EXPENSES

Production expenses relate to the cost of producing crude oil in the Upstream operations and they were $16.9 million during the three months ended June 30, 2003 and $12.2 million for the same period of 2002. Based on the number of barrels of oil produced, these costs are $1.28/bbl for the second quarter of 2003 and $1.14/bbl for the second quarter of 2002.

Approximately $2.5 million of the $4.7 million increase in the second quarter of 2003 is the direct result of increased production volumes of 2.5 mmbbls over the same quarter of the previous year. The remaining $2.2 million of the increase and the per barrel increase of $0.14 is the combined effect of a number of items, including the increased number of wells with pumps compared to free flowing wells, resulting in a higher frequency of workover activity, increased volumes of produced formation water and increased utility charges due to the commissioning of new facilities.

Production expenses were $34.1 million during the six months ended June 30, 2003 ($1.32/bbl of oil produced) compared to $26.4 million for the same period of 2002 ($1.21/bbl of oil produced).

Approximately $4.0 million of the $7.7 million increase during the six months of 2003, as compared to 2002, is due to the increase in production volumes of 4.0 mmbbls. The remaining $3.7 million increase and the per barrel increase of $0.11 is the result of increased production of formation water and the inclusion of $1.2 million of 2002 costs due to a late audit adjustment from Turgai.

ROYALTIES AND TAXES

Royalties and taxes were $15.1 million during the three months ended June 30, 2003 as compared to $9.8 million for the second quarter 2002.

	Three months ended June 30
	2003	2002
	($000’s)	($000’s)
Royalties and production bonus	11,525	8,751
Tax assessments	492	(305)
Other taxes	3,100	1,349
Royalties and taxes	15,117	9,795

	Six months ended June 30
	2003	2002
	($000’s)	($000’s)
Royalties and production bonus	17,743	15,461
Tax assessments	492	5,122
Other taxes	6,396	1,588
Royalties and taxes	24,631	22,171

Royalties and production bonus for the three months ended June 30, 2003 were $11.5 million, which represented an effective overall royalty rate of 7.8% excluding production bonus. Royalties and production bonus for the three months ended June 30, 2002 were $8.8 million, an overall royalty rate of 8.2% after excluding the production bonus. The decrease in the overall royalty rate is due to the higher production from fields with lower royalty rates.

Royalties and production bonus for the six months ended June 30, 2003 were $17.7 million, which represented an effective overall royalty rate of 6.8% excluding production bonus. Royalties and production bonus for the three months ended June 30, 2002 were $15.5 million, an overall royalty rate of 6.8% after excluding the production bonus.

Royalties are levied at different rates for each of our oil fields. The table below sets out the parameters for each field.

ROYALTIES
		Annual production
		at which max.	Three months	Six months	Three months	Six months
		royalty rate	ended	ended	ended	ended
Field	Range	is charged	June 30, 2003	June 30, 2003	June 30, 2002	June 30, 2002
Kumkol South	3.0 - 15.0%	11.6 mmbbls	8.1%	6.1%	9.2%	6.8%
Kumkol North	9.0%	Flat	9.0%	9.0%	9.0%	9.0%
South Kumkol	10.0%	Flat	10.0%	10.0%	10.0%	10.0%
Kyzylkiya	1.5 - 2.5%	24.8 mmbbls*	1.5%	1.5%	1.5%	1.5%
Aryskum	1.5 - 2.5%	52.7 mmbbls*	1.5%	1.5%	1.5%	1.5%
Maibulak	3.0 - 6.0%	3.9 mmbbls	3.0%	3.0%	3.0%	3.0%
Kazgermunai Fields	3.0 - 15.0%	11.6 mmbbls	4.3%	3.7%	3.0%	3.0%

Royalty rate is based upon cumulative life of field production.

The increase in other taxes in the second quarter of 2003 compared to 2002 of $1.8 million includes $1.4 million, pertaining to unrecoverable VAT due to revisions to tax legislation ($2.8 million for the six months of 2003). In addition, during the six months

ended June 30, 2003 Upstream incurred $1.0 million of excise taxes incurred in the first quarter of 2003 on the sale of crude oil from our South Kumkol field. We did not incur additional excise taxes for crude oil sales from our South Kumkol field during the second quarter of 2003. The remaining increase is due to increased property taxes and road fund taxes.

The tax assessments of $0.5 million during the three and six months ended June 30, 2003 represents assessments on excise and other taxes for 2000 and 2001. The tax assessment of $5.1 million during the six months ended June 30, 2002 included assessments for road tax, excise and other taxes for 1998 and 1999. The negative $0.3 million of tax assessments in the second quarter of 2002 is the reversal of overestimated amounts during the first quarter of 2002.

The table below indicates the royalty and production bonus paid in kind and in cash for the first quarter 2003 and 2002.

	2003	2003	2003	2002	2002	2002
($000’s)	Royalty in Kind	Cash Royalty	Total Royalty	Royalty in Kind	Cash Royalty	Total Royalty
March 31	—	6,218	6,218	2,972	3,738	6,710
June 30	6,703	4,822	11,525	7,456	1,295	8,751
Total	6,703	11,040	17,743	10,428	5,033	15,461

TRANSPORTATION

Transportation costs are the costs of shipping crude oil from our central processing facility located at South Kumkol (“CPF”) to the Shymkent refinery, the costs of trucking crude oil from the KAM Fields to the CPF and railway transportation and pipeline cost under non-FCA sales contracts. Transportation costs also include transportation of crude produced by our Kazgermunai joint venture to its export customers.

The pipeline tariff from the CPF to Shymkent depends on the ultimate destination of the crude oil. Effective January 1, 2003, pipeline tariffs charged for the Kumkol-Shymkent pipeline were increased by the Anti-Monopoly Agency for crude oil destined for export. The official 2003 forecasted Tenge to US dollar exchange rate is now being used to determine the tariff, as opposed to the previous practice of using actual exchange rates. In the second quarter of 2003, the tariff was $1.51/bbl (second quarter 2002—$1.41/bbl), whereas the tariff for crude oil processed at the Refinery is $0.82/bbl (2002—$0.81/bbl). The table below sets out the constituent components of transportation costs.

	Three months ended June 30
	2003	2002
	($000’s)	($000’s)
Pipeline	15,505	12,254
Kazgermunai transportation	4,760	1,910
Railway	38,863	21,033
Other	1,141	1,150
Total	60,269	36,347

	Six months ended June 30
	2003	2002
	($000’s)	($000’s)
Pipeline	37,377	23,904
Kazgermunai transportation	6,110	2,722
Railway	68,783	21,315
Other	3,002	1,997
Total	115,272	49,938

Pipeline costs increased by $3.3 million in the second quarter of 2003 compared to the same quarter of 2002. The decrease in volumes sold through the Kumkol-Shymkent pipeline was offset by the increase in the transportation rate of $0.10/bbl ($1.51/bbl in 2003 versus $1.41/bbl in 2002). The combination of these two factors accounted for approximately $0.2 million of the increase in pipeline costs for Kumkol-Shymkent transportation costs between the second quarters of 2003 and 2002. Additional volumes transferred to Downstream due to our payment of royalties in cash had an impact of $1.7 million (6.1 million barrels transported in the second quarter of 2003 at $0.82/bbl compared to 4.1 million barrels transported in the same period of 2002 at $0.81/bbl). The remaining $1.4 million is due to pipeline costs associated with non-FCA sales for various export routes.

The increase in pipeline costs of $13.5 million during the six months of 2003 compared to the same period of 2002 is due to $4.9 million from increased volumes transported through the Kumkol-Shymkent pipeline (10.75 million barrels exported in 2003 versus 10.47 million barrels in 2002 and 12.78 million barrels transferred to downstream for further processing in 2003 versus 8.88 million barrels in 2002). There was an additional $8.5 million of pipeline costs for export routes related to non-FCA sales.

Railway transportation increased as compared to 2002 due to the shift to non-FCA sales and an increase in rail tariffs approved by the Anti-Monopoly Agency for all export routes by approximately 6% effective January 1, 2003. We are in the process of appealing the railway and pipeline tariff increases.

Other transportation costs are mainly trucking costs incurred to transport crude oil from the KAM fields to the central processing facility located at Kumkol. For the second quarter of 2003 these costs are $1.1 million, consistent with $1.2 million in the second quarter of 2002 due to the same production level from the KAM fields. Trucking costs have increased in the six months ended June 30, 2003 to $3.0 million from $2.0 million in the same period of 2002 due to the increase in production from the KAM fields (2.3 mmbbls in 2003 compared to 1.6 mmbbls in 2002).

REFINING

Refining costs represent the direct costs related to processing all crude oil including tollers’ volumes at the refinery. Total refining costs in the second quarter of 2003 were $4.4 million or $0.58/bbl of crude oil processed compared to $5.8 million or $1.09/bbl in the second quarter of 2002.

A reduction in purchased steam, process improvements and equipment upgrades to reduce actual steam consumption combined with a lower per unit purchase cost accounted for a $1.6 million decrease in refining costs, quarter over quarter. Staff reductions realized during the third quarter of 2002 as a result of the divestiture of several workshops resulted in salary cost savings this year. However, salary cost savings realized during the second quarter of 2003 ($0.3 million) were offset by increased third party costs ($0.3 million) for repairs and maintenance. The release of $0.2 million of inventory costs during the second quarter of 2003 increased total refining cost for the period.

Refining costs for the six months ended June 30, 2003 were $7.4 million ($0.47/bbl) and $12.3 million ($0.95/bbl). Purchased steam costs were $3.6 million less than the prior year period. The same process improvements and equipment upgrades combined with a lower per unit purchase cost, continued to favourably impact refining costs. Similarly, staff reductions realized during the third quarter of 2002 as a result of divestiture of several workshops resulted in salary cost savings of $0.4 million through the first half of 2003. Additives injected in late 2002 have not required supplementing in 2003, saving $0.4 million. The remaining decrease is attributable to a one time repair during the first six months of 2002.

CRUDE OIL AND REFINED PRODUCT PURCHASES

Crude oil and refined product purchases represent the cost of purchasing crude oil for the refinery from third parties, as well as refined product for resale. Purchases and sales between our Upstream and Downstream business units are eliminated on consolidation.

	Three months ended June 30
	2003	2002
	($000’s)	($000’s)
Crude oil	16,046	19,156
Refined products	—	1,393
Total	16,046	20,549

	Six months ended June 30
	2003	2002
	($000’s)	($000’s)
Crude oil	25,416	35,826
Refined products	—	2,823
Total	25,416	38,649

During the second quarter of 2003, 1.7 million barrels of crude oil were purchased at an average price of $9.26/bbl, as compared to 2.2 million barrels of crude purchased at an average price of $8.80/bbl in the second quarter of 2002. The purchases of crude oil in the second quarter of 2003 were made from our Turgai joint venture.

During the six months ended June 30, 2003, 3.25 million barrels of crude oil were purchased at an average price of $7.81/bbl, as compared to 5.2 million barrels of crude purchased on the domestic market at an average price of $7.49/bbl in the same period of 2002. The purchases of crude oil were made from our Turgai joint venture.

SELLING

Selling expenses for crude oil are comprised of customs, quality inspection and costs related to the export crude oil.

Selling expenses for refined products are comprised of the costs of operating the seven distribution centres of our Downstream operations. Selling expenses in the second quarter of 2003 were $6.7 million compared to $4.9 million in the second quarter 2002, and $12.2 million in six months 2003 compared to $10.6 million in six months 2002.

	Three months ended June 30
	2003	2002
	($000’s)	($000’s)
Crude oil	2,659	1,004
Refined products	4,060	3,888
Total	6,719	4,892

	Six months ended June 30
	2003	2002
	($000’s)	($000’s)
Crude oil	4,507	1,136
Refined products	7,683	9,485
Total	12,190	10,621

The increase in crude oil selling expenses during the second quarter of 2003 compared to the second quarter of 2002 is 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. Our non-FCA sales were 4.4 million barrels of crude oil during the second quarter of 2003 (second quarter of 2002 — 2.2 million barrels). Non-FCA sales for the six months of 2003 were 8.24 million barrels of crude oil compared to 2.3 million barrels in the same period of 2002. In addition, for the six months ended June 30, 2003 Upstream includes $0.9 million of allocated expenses from marketing and trading, previously allocated to general and administrative costs ($0.5 million of which relates to the second quarter of 2003).

During the six months ended June 30, 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. The remaining $0.7 million decrease for the six months of 2002 was due to one time charges in 2002, including a $0.6 settlement payment and $0.1 million in storage charges.

GENERAL AND ADMINISTRATIVE

The table below analyses total general and administrative costs between Upstream, Downstream and Corporate. In the case of Upstream and Downstream the general and administrative costs are also reflected on a per barrel basis.

THREE MONTHS ENDED JUNE 30, 2003
	General and	Per barrel of oil
	Administrative	produced or processed*
	($000’s)	($/bbl)
Upstream	7,333	0.56
Downstream	4,421	0.59
Corporate	500
Total	12,254

THREE MONTHS ENDED JUNE 30, 2002
	General and	Per barrel of oil
	Administrative	produced or processed*
	($000’s)	($/bbl)
Upstream	9,028	0.84
Downstream	4,086	0.76
Corporate	2,216
Total	15,330

SIX MONTHS ENDED JUNE 30, 2003
	General and	Per barrel of oil
	Administrative	produced or processed*
	($000’s)	($/bbl)
Upstream	15,121	0.58
Downstream	8,930	0.57
Corporate	1,523
Total	25,574

SIX MONTHS ENDED JUNE 30, 2002
	General and	Per barrel of oil
	Administrative	produced or processed*
	($000’s)	($/bbl)
Upstream	16,165	0.74
Downstream	7,424	0.57
Corporate	4,242
Total	27,831

Including tollers’ volumes

The decrease in Upstream and Corporate general and administrative expenses in the three and six months ended June 30, 2003 is due to a reduction in office and staff costs and bad debt expenses, as well as an allocation of $0.5 million in the second quarter and $0.9 million in the first six months of 2003 to selling expenses, which represent marketing and trading expenses previously recorded as general and administrative expenses.

The increase in the downstream expenses during the six months ended June 30, 2003 of $1.5 million is due to an increase in allocated Corporate charges.

INTEREST AND FINANCING

The following table sets out the interest expense, and the amortization of debt issue costs or discounts.

	Three months ended June 30
	2003	2002
	($000’s)	($000’s)
Short-term debt	173	145
Term facility	3,176	1,226
Kazgermunai debt	(327)	799
12% Notes*	—	6,319
HOP bonds	695	336
9.625% Notes	3,150	—
Total	6,867	8,825

	Six months ended June 30
	2003	2002
	($000’s)	($000’s)
Short-term debt	366	639
Term facility	5,361	1,944
Kazgermunai debt	647	1,688
12% Notes*	8,718	12,303
HOP bonds	1,182	676
9.625% Notes	4,852	—
Total	21,126	17,250

Please refer to Note 7 of the Interim Consolidated Financial Statements.

The negative interest expense for Kazgermunai in the three months ended June 30, 2003 is attributable to a $0.6 million correction of interest expense made for the previous quarter.

DEPRECIATION AND DEPLETION

Upstream depreciation and depletion has increased by $10.9 million during the three months ended June 30, 2003. This increase is due to changes in reserve estimates pertaining to proved producing reserves as of January 1, 2003 and an increase in production as compared to the second quarter of 2002. Additionally, the amount subject to depletion or depreciation has increased by $176 million since June 30, 2002 as a result of capital expenditures. During the three months ended June 30, 2003 Downstream depreciation increased mainly due to $1.5 million of depreciation on assets, which were under construction in 2002.

Upstream depreciation and depletion has increased by $17.3 million during the six months ended June 30, 2003 compared to the same period of 2002. This increase is also due to changes in reserve estimates pertaining to proved producing reserves as of January 1, 2003 and the increase in the amount subject to depletion or depreciation as a result of capital expenditures. Downstream depreciation also increased during the six months of 2003 compared to 2002 mainly due to $3.0 million of depreciation on assets, which were under construction in 2002.

THREE MONTHS ENDED JUNE 30, 2003
	Depreciation and	Depreciation and
	Depletion ($000’s)	*Depletion ($/bbl)**
Upstream	15,104	1.14
Downstream	4,651	0.62
Corporate	32
Total	19,787

THREE MONTHS ENDED JUNE 30, 2002
	Depreciation and	Depreciation and
	Depletion ($000’s)	Depletion ($/bbl*)
Upstream	6,044	0.56
Downstream	2,784	0.52
Corporate	24
Total	8,852

SIX MONTHS ENDED JUNE 30, 2003
	Depreciation and	Depreciation and
	Depletion ($000’s)	*Depletion ($/bbl)**
Upstream	29,122	1.12
Downstream	9,321	0.59
Corporate	58
Total	38,501

SIX MONTHS ENDED JUNE 30, 2002
	Depreciation and	Depreciation and
	Depletion ($000’s)	Depletion ($/bbl*)
Upstream	11,812	0.54
Downstream	5,520	0.43
Corporate	46
Total	17,378

Downstream includes tollers’ volumes.

In accordance with Canadian and United States accounting standards, and to provide comfort that anticipated future revenues are sufficient to cover the capitalised costs of properties, we perform a quarterly “ceiling test”. The ceiling test as at June 30, 2003 demonstrated that future net revenues exceed the carrying value of the Upstream properties under the full cost method of accounting.

INCOME BEFORE INCOME TAXES

As a result of the foregoing factors, we had income before income taxes of $97.2 million for the three months ended June 30, 2003, as compared to $53.8 million for the second quarter of 2002 (or $200.0 million for the six months ended June 30, 2003 as compared to $90.7 million for the six months ended June 30, 2002).

UNUSUAL ITEMS

We were named as defendants in a claim filed by a company alleging it was retained under a consulting contract, as disclosed in Note 22 to the Consolidated Financial Statements for the year ended December 31, 2002. The arbitration decision was received in 2002 and we accrued and paid $7.1 million during the six months ended June 30, 2002. No unusual items were incurred in the second quarter of 2003.

INCOME TAXES
	Three months ended June 30
	2003	2002
	($000’s)	($000’s)
Upstream	11,371	16,307
Downstream	17,085	3,189
Corporate	(104)	117
Total	28,352	19,613

	Six months ended June 30
	2003	2002
	($000’s)	($000’s)
Upstream	33,326	23,257
Downstream	28,840	8,831
Corporate	128	365
Total	62,294	32,453

The increase in income taxes is due to the increase in operations and income before income taxes in 2003. The effective tax rates were 29.2% for the second quarter of 2003 and 36.4% for the second quarter of 2002 (31.1% for the six months of 2003 compared to 35.8% for the six months of 2002). Please refer to Note 9 of the Interim Consolidated Financial Statements.

NET RETURN PER BARREL

Set out below are the details of the average net return achieved for export sales, including both FCA and non-FCA, and sales derived from the refining of our own crude.

	Three months ended June 30, 2003
	Crude Oil	Own Crude Oil
	Exports ($/bbl)	Refined and Sold ($/bbl)
Net sales price achieved	18.56	14.65
Transportation costs	(7.89)	(0.96)
Net back at Kumkol	10.67	13.69
Production and refining costs	(1.28)	(1.86)
Royalties and taxes	(1.13)	(1.15)
Selling costs	(0.19)	(0.75)
General and administrative costs	(0.56)	(1.14)
Net return per barrel	7.51	8.79

	Three months ended June 30, 2002
	Crude Oil	Own Crude Oil
	Exports ($/bbl)	Refined and Sold ($/bbl)
Net sales price achieved	16.11	12.18
Transportation costs	(4.72)	(1.03)
Net back at Kumkol	11.39	11.15
Production and refining costs	(1.14)	(2.23)
Royalties and taxes	(0.85)	(0.87)
Selling costs	(0.09)	(0.83)
General and administrative costs	(0.84)	(1.61)
Net return per barrel	8.47	5.61

During the second quarter of 2003 the net sales price achieved for crude oil exports less transportation costs decreased by $0.72/bbl compared to the same quarter of 2002 due to the increase in pipeline and railway costs during the second quarter of 2003, partially offset by a slight increase in market prices (average Platts Brent was $26.03/bbl compared to $25.03/bbl in the second quarter of 2002).

	Six months ended June 30, 2003
	Crude Oil	Own Crude Oil
	Exports ($/bbl)	Refined and Sold ($/bbl)
Net sales price achieved	20.70	14.07
Transportation costs	(7.98)	(0.93)
Net back at Kumkol	12.72	13.14
Production and refining costs	(1.32)	(1.79)
Royalties and taxes	(0.94)	(0.96)
Selling costs	(0.17)	(0.66)
General and administrative costs	(0.58)	(1.15)
Net return per barrel	9.71	8.58

	Six months ended June 30, 2002
	Crude Oil	Own Crude Oil
	Exports ($/bbl)	Refined and Sold ($/bbl)
Net sales price achieved	14.33	11.60
Transportation costs	(3.55)	(1.06)
Net back at Kumkol	10.78	10.54
Production and refining costs	(1.21)	(2.16)
Royalties and taxes	(0.98)	(0.96)
Selling costs	(0.05)	(0.78)
General and administrative costs	(0.74)	(1.31)
Net return per barrel	7.80	5.33

During the six months ended June 30, 2003 the net sales price achieved for crude oil exports less transportation costs increased by $1.94/bbl compared to the same period of 2002 due to an increase in market prices (average Platts Brent was $28.77/bbl compared to $23.09/bbl in 2002), partially offset by an increase in pipeline and railway tariffs.

COMPARISON OF COMPLETED FCA AND NON-FCA SALES
	Three months ended June 30
	2003	2002
	($/bbl)	($/bbl)
FCA
Average Brent	26.73	24.96
Differential	13.79	13.50
Netback at Kumkol	12.94	11.46
Non-FCA
Average Brent	26.34	24.74
Differential	14.57	14.48
Netback at Kumkol	11.77	10.26


	Six months ended June 30
	2003	2002
	($/bbl)	($/bbl)
FCA
Average Brent	29.67	23.96
Differential	13.67	13.42
Netback at Kumkol	16.00	10.54
Non-FCA
Average Brent	29.08	24.45
Differential	14.89	13.81
Netback at Kumkol	14.19	10.64

The table above sets out our two types of sales transactions on a completed sale basis and is mainly a comparison of the Aktau route (FCA) with all of our other routes (non-FCA). The Aktau route is supported by the government and consequently, it receives preferential rail tariffs. It compares transactions that were completed in the quarter as opposed to shipments made in the quarter. The average Brent is the average Brent price we received for all sale transactions for the quarter. Pricing is specific to the bill of lading date and the differential represents all costs to move our crude oil from Kumkol to various final destinations.

The increase in our differential for non-FCA sales of $0.09/bbl for the second quarter of 2003 compared to 2002 ($1.09/bbl for the six months ended June 2003 compared to same period of 2002) and for our FCA sales for the same periods is attributable to the increase in rail tariffs and pipeline tariffs, as previously discussed and for non-FCA sales we are utilizing new routes that on, at least an initial basis, have higher costs. The combination of FCA and non-FCA sales leads to competition and, on an overall basis a lower differential.

CAPITAL EXPENDITURES

The table below provides a breakdown of capital expenditures.

	Three months ended June 30
	2003	2002
	($000’s)	($000’s)
Upstream
Development wells	9,497	4,350
Facilities and equipment	18,811	20,362
Exploration	4,545	6,604
Downstream
Refinery HS&E	113	316
Refinery sustaining	961	123
Refinery return projects	2,579	895
Marketing & other	5	1,238
Corporate	183	107
Total Capital Expenditure	36,694	33,995

	Six months ended June 30
	2003	2002
	($000’s)	($000’s)
Upstream
Development wells	13,418	7,224
Facilities and equipment	55,546	33,813
Exploration	8,461	8,418
Downstream
Refinery HS&E	340	472
Refinery sustaining	1,755	225
Refinery return projects	7,138	1,269
Marketing & other	16	1,928
Corporate	341	155
Total Capital Expenditure	87,015	53,504

LIQUIDITY

The levels of cash, current assets and current liabilities as at June 30, 2003 and December 31, 2002 are set out below.

	As at	As at
	June 30, 2003	December 31, 2002
	($000’s)	($000’s)
Cash and cash equivalents	224,342	74,796
Cash flow	179,893	216,794
Working capital*	133,176	86,987
Net debt	192,007	217,754
Ratio of cash flow to net debt**	1.9	1.0
Ratio of cash flow to fixed charges***	8.5	6.1
Ratio of earnings to fixed charges****	7.5	8.5

*		Working capital is net of cash and short-term debt
**		Quarterly cash flow is annualized
***		Fixed charges includes interest expense and preferred dividends before tax
****		Earnings is net income plus fixed charges

Working capital excluding cash and short-term debt as at June 30, 2003 was $133.2 million ($87.0 million as at December 31, 2002). The increase is primarily due to an increase in accounts receivable.

Cash flow from our operations, together with proceeds of our new financings, provides us with sufficient means to implement our plans for 2003. Our new financings improve the structure of our balance sheet with a term of four years for our term facility with repayments of equal monthly amounts of principal commencing July 2003 and with a seven-year term on our new issue of $125.0 million principal amount 9.625% Notes (the “9.625% Notes”) due in 2010.

As at June 30, 2003 cash and cash equivalents included $15.6 million of cash dedicated to a debt service reserve account for our Term Facility (nil as at December 31, 2002). This cash is unavailable for general corporate purposes.

INTERIM CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS (DEFICIT)
(EXPRESSED IN THOUSANDS OF UNITED STATES DOLLARS, EXCEPT PER SHARE AMOUNTS)
Unaudited
	Three months ended June 30		Six months ended June 30
	2003	2002	2003	2002
REVENUE
Crude oil	134,175	113,223	276,417	175,786
Refined products	116,959	62,061	217,625	139,445
Processing fees	—	3	449	1,434
Interest and other income	967	2,111	4,244	4,064
	252,101	177,398	498,735	320,729
EXPENSES
Production	16,893	12,225	34,149	26,413
Royalties and taxes	15,117	9,795	24,631	22,171
Transportation	60,269	36,347	115,272	49,938
Refining	4,393	5,798	7,402	12,327
Crude oil and refined product purchases	16,046	20,549	25,416	38,649
Selling	6,719	4,892	12,190	10,621
General and administrative	12,254	15,330	25,574	27,831
Interest and financing costs	6,867	8,825	21,126	17,250
Depletion and depreciation	19,787	8,852	38,501	17,378
Foreign exchange (gain) loss	(3,428)	(65)	(5,526)	409
	154,917	122,548	298,735	222,987
INCOME BEFORE UNUSUAL ITEMS	97,184	54,850	200,000	97,742
UNUSUAL ITEM
Arbitration settlement	—	1,001	—	7,091
INCOME BEFORE INCOME TAXES	97,184	53,849	200,000	9061
INCOME TAXES (Note 9)
Current provision	27,080	18,360	63,252	28,348
Future income tax	1,272	1,253	(958)	4,105
	28,352	19,613	62,294	32,453
NET INCOME BEFORE MINORITY INTEREST	68,832	34,236	137,706	58,198
MINORITY INTEREST	621	428	1,271	1,281
NET INCOME	68,211	33,808	136,435	56,917
RETAINED EARNINGS (DEFICIT),
BEGINNING OF YEAR	146,245	(43,265)	78,821	(66,366)
Normal Course Issuer Bid (Note 8)	(10,440)	—	(11,232)	—
Preferred share dividends	(8)	(8)	(16)	(16)
RETAINED EARNINGS (DEFICIT), END OF PERIOD	204,008	(9,465)	204,008	(9,465)
BASIC NET INCOME PER SHARE (Note 10)	0.87	0.42	1.74	0.70
DILUTED NET INCOME PER SHARE (Note 10)	0.84	0.40	1.67	0.67

See accompanying notes to the interim consolidated financial statements.

INTERIM CONSOLIDATED BALANCE SHEETS
(EXPRESSED IN THOUSANDS OF UNITED STATES DOLLARS)
Unaudited
		June 30	December 31
		2003	2002
ASSETS
CURRENT
Cash and cash equivalents (Note 4)		224,342	74,796
Accounts receivable (Note 5)		127,192	92,431
Inventory		30,805	40,529
Prepaid expenses		41,121	44,594
Current portion of future income tax asset		9,181	9,049
		432,641	261,399
Deferred charges		7,836	5,321
Future income tax asset		23,135	24,529
Property, plant and equipment		455,888	405,479
TOTAL ASSETS		919,500	696,728

LIABILITIES
CURRENT
Accounts payable and accrued liabilities		66,879	96,076
Short-term debt (Note 6)		101,583	25,947
Prepayments for crude oil and refined products		8,244	3,540
		176,706	125,563
Long-term debt (Note 7)		314,766	266,603
Provision for future site restoration costs		6,545	4,167
Future income tax liability		14,794	17,015
		512,811	413,348
Minority interest		12,024	10,753
Preferred shares of subsidiary		80	83

COMMITMENTS AND CONTINGENCIES (Note 13)

SHAREHOLDERS’ EQUITY
Share capital (Note 8)		190,577	193,723
Retained earnings		204,008	78,821
		394,585	272,544

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		919,500	696,728

See accompanying notes to the interim consolidated financial statements.

APPROVED BY THE BOARD OF DIRECTORS.


(signed)	(signed)

BERNARD ISAUTIER	ROBERT KAPLAN
Director	Director

INTERIM CONSOLIDATED STATEMENTS OF CASH FLOW
(EXPRESSED IN THOUSANDS OF UNITED STATES DOLLARS)
Unaudited
	Three months ended June 30		Six months ended June 30
	2003	2002	2003	2002
OPERATING ACTIVITIES
Net income	68,211	33,808	136,435	56,917
Items not affecting cash:
Depletion and depreciation	19,787	8,852	38,501	17,378
Amortization of deferred charges	359	466	3,052	625
Minority interest	621	428	1,271	1,281
Other non-cash charges	770	468	1,593	1,007
Future income tax	1,272	1,253	(958)	4,105

Cash flow	91,020	45,275	179,894	81,313
Changes in non-cash operating working capital items	(61,493)	(10,668)	(42,368)	(25,148)
Cash flow from operating activities	29,527	34,607	137,526	56,165

FINANCING ACTIVITIES
Short-term debt	(33,827)	(482)	16,675	(1,938)
Purchase of common shares (Note 8)	(13,816)	—	(14,848)	—
Long-term debt	34,698	(8,760)	98,808	25,195
Deferred charges paid	(1,150)	—	(3,601)	—
Proceeds from issue of share capital,
net of share issuance costs	20	24	470	613
Preferred share dividends	(8)	(8)	(16)	(16)
Cash flow (used in) from investing activities	(14,083)	(9,226)	97,488	23,854

INVESTING ACTIVITIES
Long-term investment	—	40,000	—	40,000
Capital expenditures	(35,143)	(33,995)	(85,464)	(53,504)
Purchase of preferred shares of subsidiary	(2)	(5)	(4)	(5)
Cash flow (used in) from investing activities	(35,145)	6,000	(85,468)	(13,509)

(DECREASE)/INCREASE IN CASH	(19,701)	31,381	149,546	66,510
CASH AND CASH EQUIVALENTS
(BEGINNING OF PERIOD)	244,043	99,941	74,796	64,812
CASH AND CASH EQUIVALENTS (END OF PERIOD)	224,342	131,322	224,342	131,322

There were no cash equivalents as at June 30, 2003 and December 31, 2002.
See accompanying notes to the interim consolidated financial statements.

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS

(EXPRESSED IN UNITED STATES DOLLARS TABULAR AMOUNTS IN THOUSANDS OF DOLLARS, UNLESS OTHERWISE INDICATED) UNAUDITED

1	SIGNIFICANT ACCOUNTING POLICIES

The interim consolidated financial statements of PetroKazakhstan Inc. (“PetroKazakhstan” or the “Corporation”) have been prepared by management, in accordance with generally accepted accounting principles in Canada. PetroKazakhstan Inc. was formerly known as Hurricane Hydrocarbons Ltd. Its main operating subsidiaries Hurricane Kumkol Munai (“HKM”) and Hurricane Oil Products (“HOP”) were renamed PetroKazakhstan Kumkol Resources (“PKKR”) and PetroKazakhstan Oil Products (“PKOP”), respectively. Certain information and disclosures normally required to be included in the notes to the annual financial statements has been omitted or condensed. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto in PetroKazakhstan’s Annual Report for the year ended December 31, 2002. The accounting principles applied are consistent with those as set out in the Corporation’s annual financial statements for the year ended December 31, 2002.

The presentation of certain amounts for previous periods has been changed to conform with the presentation adopted for the current period.

2	SEGMENTED INFORMATION

On a primary basis the business segments are:

•

Upstream comprising the exploration, development and production of crude oil and natural gas.

•

Downstream comprising refining and the marketing of refined products and the management of the marketing of crude oil.

Upstream results include revenue from crude oil sales to Downstream, reflected as crude oil purchases in Downstream, as this presentation properly reflects segment results. This revenue is eliminated on consolidation.

		Three months ended June 30, 2003
	Upstream	Downstream	Corporate	Eliminations	Consolidated
REVENUE
Crude oil	162,240	—	—	(28,065)	134,175
Refined products	13,866	110,955	—	(7,862)	116,959
Processing fees	—	—	—	—	—
Interest and other income	197	357	413	—	967
	176,303	111,312	413	(35,927)	252,101
EXPENSES
Production	16,893	—	—	—	16,893
Royalties and taxes	14,911	206	—	—	15,117
Transportation	60,244	25	—	—	60,269
Refining	—	4,393	—	—	4,393
Crude oil and refined product purchases	14,816	37,157	—	(35,927)	16,046
Selling	2,490	4,229	—	—	6,719
General and administrative	7,333	4,421	500	—	12,254
Interest and financing costs	6,127	695	45	—	6,867
Depletion and depreciation	15,104	4,651	32	—	19,787
Foreign exchange (gain) loss	(2,294)	(1,484)	350	—	(3,428)
	135,624	54,293	927	(35,927)	154,917
INCOME (LOSS) BEFORE INCOME TAXES	40,679	57,019	(514)	—	97,184
INCOME TAXES
Current Provision	14,879	12,305	(104)	—	27,080
Future income tax	(3,508)	4,780	—	—	1,272
	11,371	17,085	(104)	—	28,352
MINORITY INTEREST	—	621	—	—	621
NET INCOME (LOSS)	29,308	39,313	(410)	—	68,211
INTERSEGMENT REVENUE	19,564	5,920	—	—	—

		As at June 30, 2003
	Upstream	Downstream	Corporate		Consolidated
Total assets	588,855	179,373	151,272		919,500
Total liabilities	450,800	55,018	6,993		512,811
Capital expenditures in the quarter	32,853	3,658	183		36,694

		Three months ended June 30, 2002
	Upstream	Downstream	Corporate	Eliminations	Consolidated
REVENUE
Crude oil	135,783	—	—	(22,560)	113,223
Refined products	17,812	57,659	—	(13,410)	62,061
Processing fees	—	3	—	—	3
Interest and other income	1,475	617	19	—	2,111
	155,070	58,279	19	(35,970)	177,398
EXPENSES
Production	12,225	—	—	—	12,225
Royalties and taxes	9,276	519	—	—	9,795
Transportation	36,347	—	—	—	36,347
Refining	—	5,798	—	—	5,798
Crude oil and refined product purchases	21,354	35,165	—	(35,970)	20,549
Selling	1,004	3,888	—	—	4,892
General and administrative	9,027	4,086	2,217	—	15,330
Interest and financing costs	2,170	336	6,319	—	8,825
Depletion and depreciation	6,044	2,784	24	—	8,852
Foreign exchange (gain) loss	(317)	86	166	—	(65)
	97,130	52,662	8,726	(35,970)	122,548
INCOME (LOSS) BEFORE UNUSUAL ITEMS	57,940	5,617	(8,707)	—	54,850
UNUSUAL ITEM
Arbitration settlement	1,001	—	—	—	1,001
INCOME (LOSS) BEFORE INCOME TAXES	56,939	5,617	(8,707)	—	53,849
INCOME TAXES
Current Provision	13,757	4,486	117	—	18,360
Future income tax	2,550	(1,297)	—	—	1,253
	16,307	3,189	117	—	19,613
MINORITY INTEREST	—	428	—	—	428
NET INCOME (LOSS)	40,632	2,000	(8,824)	—	33,808
INTERSEGMENT REVENUE	22,560	13,410	—	—	—

Included in Upstream crude oil revenue are sales to one customer in the amount of $30.4 million.

		As at June 30, 2002
	Upstream	Downstream	Corporate		Consolidated
Total assets	366,167	161,319	130,493		657,979
Total liabilities	173,870	48,942	218,545		441,357
Capital expenditures in the quarter	31,319	2,573	103		33,995

		Six months ended June 30, 2003
	Upstream	Downstream	Corporate	Eliminations	Consolidated
REVENUE
Crude oil	338,699	—	—	(62,282)	276,417
Refined products	14,536	212,355	—	(9,266)	217,625
Processing fees	—	449	—	—	449
Interest and other income	2,719	796	729	—	4,244
	355,954	213,600	729	(71,548)	498,735
EXPENSES
Production	34,149	—	—	—	34,149
Royalties and taxes	24,326	305	—	—	24,631
Transportation	115,272	—	—	—	115,272
Refining	—	7,402	—	—	7,402
Crude oil and refined product purchases	16,920	80,044	—	(71,548)	25,416
Selling	4,507	7,683	—	—	12,190
General and administrative	15,121	8,930	1,523	—	25,574
Interest and financing costs	11,181	1,182	8,763	—	21,126
Depletion and depreciation	29,122	9,321	58	—	38,501
Foreign exchange (gain) loss	(3,668)	(2,450)	592	—	(5,526)
	246,930	112,417	10,936	(71,548)	298,735
INCOME (LOSS) BEFORE INCOME TAXES	109,024	101,183	(10,207)	—	200,000
INCOME TAXES
Current Provision	39,048	24,076	128	—	63,252
Future income tax	(5,722)	4,764	—	—	(958)
	33,326	28,840	128	—	62,294
MINORITY INTEREST	—	1,271	—	—	1,271
NET INCOME (LOSS)	75,698	71,072	(10,335)	—	136,435
INTERSEGMENT REVENUE	62,282	9,266	—	—	—

		As at June 30, 2003
	Upstream	Downstream	Corporate		Consolidated
Total assets	588,855	179,373	151,272		919,500
Total liabilities	450,800	55,018	6,993		512,811
Capital expenditures in the half year	77,426	9,248	341		87,015

		Six months ended June 30, 2002
	Upstream	Downstream	Corporate	Eliminations	Consolidated
REVENUE
Crude oil	223,669	—	—	(47,883)	175,786
Refined products	28,799	136,195	—	(25,549)	139,445
Processing fees	—	1,434	—	—	1,434
Interest and other income	2,737	330	997	—	4,064
	255,205	137,959	997	(73,432)	320,729
EXPENSES
Production	26,413	—	—	—	26,413
Royalties and taxes	21,444	727	—	—	22,171
Transportation	49,938	—	—	—	49,938
Refining	—	12,327	—	—	12,327
Crude oil and refined product purchases	37,202	74,879	—	(73,432)	38,649
Selling	1,136	9,485	—	—	10,621
General and administrative	16,165	7,424	4,242	—	27,831
Interest and financing costs	4,271	676	12,303	—	17,250
Depletion and depreciation	11,812	5,520	46	—	17,378
Foreign exchange (gain) loss	590	(244)	63	—	409
	168,971	110,794	16,654	(73,432)	222,987
INCOME (LOSS) BEFORE UNUSUAL ITEM	86,234	27,165	(15,657)	—	97,742
UNUSUAL ITEM
Arbitration Settlement	7,091	—	—	—	7,091
INCOME (LOSS) BEFORE INCOME TAXES	79,143	27,165	(15,657)	—	90,651
INCOME TAXES
Current Provision	19,041	8,942	365	—	28,348
Future income tax	4,216	(111)	—	—	4,105
	23,257	8,831	365	—	32,453
MINORITY INTEREST	—	1,281	—	—	1,281
NET INCOME (LOSS)	55,886	17,053	(16,022)	—	56,917
INTERSEGMENT REVENUE	47,883	25,549	—	—	—

Included in Upstream crude oil revenue are sales to one customer in the amount of $62.7 million.

		As at June 30, 2002
	Upstream	Downstream	Corporate	Consolidated
Total assets	366,167	161,319	130,493	657,979
Total liabilities	173,870	48,942	218,545	441,357
Capital expenditures in the half year	49,458	3,895	151	53,504

3	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 following amounts are included in the Corporation’s consolidated financial statements as a result of the proportionate consolidation of its joint ventures before consolidation eliminations:

		Three months ended June 30, 2003
	Turgai	Kazgermunai	Total
Cash	13,206	14,123	27,329
Current assets, excluding cash	6,511	20,758	27,269
Property, plant and equipment, net	59,565	58,342	117,907
Current liabilities	26,643	6,467	33,110
Long-term debt	—	46,035	46,035

Revenue	29,494	20,653	50,147
Expenses	16,360	15,968	32,328
Net income	13,134	4,685	17,819

Cash flow from operating activities	24,255	4,930	29,185
Cash flow used in financing activities	—	(6,016)	(6,016)
Cash flow used in investing activities	(11,200)	(2,342)	(13,542)

Revenue for the three months ended June 30, 2003 includes $10.6 million of crude oil sales made by Turgai to Downstream. This amount was eliminated on consolidation.

		Three months ended June 30, 2002
	Turgai	Kazgermunai	Total
Cash	1,483	9,033	10,516
Current assets, excluding cash	5,593	15,603	21,196
Property, plant and equipment, net	22,359	54,812	77,171
Current liabilities	11,518	1,581	13,099
Long-term debt	—	62,441	62,441

Revenue	18,634	10,017	28,651
Expenses	10,868	6,989	17,857
Net income	7,766	3,028	10,794

Cash flow from operating activities	1,786	(1,306)	480
Cash flow used in financing activities	—	629	629
Cash flow used in investing activities	(2,959)	(2,010)	(4,969)

Revenue for the three months ended June 30, 2002 includes $7.0 million of crude oil sales made by Turgai and $1.9 million of crude oil sales made by Kazgermunai to Downstream. These amounts were eliminated on consolidation.

		Six months ended June 30, 2003
	Turgai	Kazgermunai	Total
Cash	13,206	14,123	27,329
Current assets, excluding cash	6,511	20,758	27,269
Property, plant and equipment, net	59,565	58,342	117,907
Current liabilities	26,643	6,467	33,110
Long-term debt	—	46,035	46,035

Revenue	59,710	42,787	102,497
Expenses	38,810	28,573	67,383
Net income	20,900	14,214	35,114

Cash flow from operating activities	34,314	17,693	52,007
Cash flow used in financing activities	—	(6,016)	(6,016)
Cash flow used in investing activities	(21,416)	(6,251)	(27,667)

Revenue for the six months ended June 30, 2003 includes $18.7 million of crude oil sales made by Turgai to Downstream. This amount was eliminated on consolidation.

		Six months ended June 30, 2002
	Turgai	Kazgermunai	Total
Cash	1,483	9,033	10,516
Current assets, excluding cash	5,593	15,603	21,196
Property, plant and equipment, net	22,359	54,812	77,171
Current liabilities	11,518	1,581	13,099
Long-term debt	—	62,441	62,441

Revenue	30,586	15,255	45,841
Expenses	18,142	13,786	31,928
Net income	12,444	1,469	13,913

Cash flow from operating activities	4,254	(968)	3,286
Cash flow used in financing activities	—	1,373	1,373
Cash flow used in investing activities	(4,270)	(2,888)	(7,158)

Revenue for the six months ended June 30, 2002 includes $15.5 million of crude oil sales made by Turgai and $5.9 million of crude oil sales made by Kazgermunai to Downstream. These amounts were eliminated on consolidation.

4	CASH AND CASH EQUIVALENTS

As at June 30, 2003 cash and cash equivalents included $15.6 million of cash dedicated to a debt service reserve account for the Corporation’s Term Facility (nil as at December 31, 2002). This cash is unavailable for general corporate purposes.

As at June 30, 2003 cash and cash equivalents included $3.1 million of cash dedicated to a margin account for the hedging program. As at December 31, 2002 the balance on this margin account was $5.7 million, which was subsequently released.

5	ACCOUNTS RECEIVABLE

Accounts receivable consist of the following:

	June 30, 2003	December 31, 2002
Trade	75,096	61,085
Value added tax recoverable	9,708	1,718
Due from Turgai	25,196	17,357
Other	17,192	12,271
	127,192	92,431

6	SHORT-TERM DEBT

	June 30, 2003	December 31, 2002
Working capital facilities	9,765	14,947
Current portion of term facility	54,285	—
Current portion of term loans	2,039	—
Joint venture loan payable	11,000	11,000
PKOP Bonds (Note 7)	24,494	—
	101,583	25,947

The working capital facilities are revolving, for terms of one to eight years, are secured and have interest rates ranging from Libor plus 3.5% per annum to 14% per annum.

7	LONG-TERM DEBT

Long-term debt is represented by:

	June 30, 2003	December 31, 2002
Term Facility	135,715	—
9.625% Notes	125,000	—
Kazgermunai debt	40,191	45,231
Term loans	13,860	—
12% Notes	—	208,210
PKOP Bonds	—	13,162
	314,766	266,603

Term Facility

On January 2, 2003, PetroKazakhstan Kumkol Resources (“PKKR”) entered into a secured $225.0 million term facility secured by crude oil export contracts. This facility is repayable in 42 equal monthly installments commencing July 2003. The facility bears interest at a rate of LIBOR plus 3.25% per annum. PKKR has drawn $190.0 million under this facility and has chosen not to utilize the remainder. PKKR has the right to repay the facility prior to its maturity, under certain terms and conditions.

As a guarantor of the facility, the Corporation must comply with certain covenants including a limitation as to total debt and certain other financial covenants. The Corporation must also maintain a minimum cash balance of $40.0 million, of which an amount equal to 3 months principal and interest payments must be maintained in a security deposit account (see Note 4).

PKKR is also required to hedge 450,000 barrels of crude oil production per month for 2004 with a minimum price of $17.0 per bbl. As PKKR has not drawn the full amount of the facility, the hedged volumes have been reduced to 372,500 barrels of crude oil per month for 2004.

Included in deferred charges as at June 30, 2003 are $3.1 million of issue costs related to the Term facility, which will be amortized over the term of the facility.

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 and on pledging of assets as security.

Issue costs of $1.8 million and the discount on the sale of the Notes of $2.0 million are recorded as deferred charges and will be amortized over the term of the Notes.

Kazgermunai Debt

The Kazgermunai debt is non-recourse to the Corporation. During the three months ended June 30, 2003, Kazgermunai repaid $11.6 million (50% — $5.8 million) of principal and interest.

Term Loans

PKKR has obtained loans guaranteed by Export Credit Agencies for certain equipment related to the Kyzylkiya, Aryskum and Maibulak (“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 semiannual installments and have final maturity dates ranging from five to seven years.

12% Notes

On February 3, 2003 the Corporation redeemed all $208.2 million of its outstanding 12% Notes due in 2006. The Notes were redeemed for an aggregate redemption price of $212.4 million, representing 102% of the principal amount of the Notes, plus accrued and unpaid interest of $12.5 million, for a total of $224.9 million. Deferred charges of $1.4 million recorded as at December 31, 2002 were expensed upon redemption.

PKOP Bonds

On March 20, 2001 PetroKazakhstan Oil Products (“PKOP”) registered 250,000 unsecured bonds (par value $100) in the amount of $25 million with the National Securities Commission of the Republic of Kazakhstan (the “PKOP bonds”). The PKOP bonds have a three-year maturity, are due on February 26, 2004 and bear a coupon rate of 10% per annum. The PKOP bonds are listed on the Kazakh Stock Exchange.

As at December 31, 2002 134,800 bonds had been issued for consideration of $13.2 million. On February 13, 2003, PKOP issued the remaining 115,200 Bonds for consideration of $11.4 million.

The PKOP bonds contain certain covenants including a limitation on indebtedness.

Repayment

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

							Less amounts	Total
							Included in	long-
							Short-term	term
	2003	2004	2005	2006	2007	Thereafter	Debt	Debt
Working Captial
Facilities	9,765	—	—	—	—	—	(9,765)	—
Joint Venture
Loan Payable	11,000	—	—	—	—	—	(11,000)	—
PKOP bonds	—	24,494	—	—	—		(24,494)	—
9.625% Notes	—	—	—	—	—	125,000	—	125,000
Term Facility	27,143	54,285	54,286	54,286	—	—	(54,285)	135,715
Kazgermaunai	—	—	—	—	—	40,191	—	40,191
Term loans	707	2,665	2,665	2,665	2,271	4,926	(2,039)	13,860
	48,615	81,444	56,951	56,951	2,271	170,117	(101,583)	314,766

The Kazgermunai debt does not have fixed repayment terms.

The fair value of long-term debt as at June 30, 2003 approximates itscarrying value, as it bears interest at market rates.

8	SHARE CAPITAL

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.

Issued Class A common shares:
	Three months ended		Three months ended
	June 30, 2003		June 30, 2002
	Number	Amount	Number	Amount
Balance, beginning of year	79,028,539	193,933	81,041,713	199,097
Shares repurchased and cancelled
pursuant to Normal Course Issuer Bid (a)	(1,379,300)	(3,376)	—	—
Stock options exercised for cash	3,900	20	232,075	(64)
Corresponding convertible securities, converted	—	—	97,709	88
Balance, end of period	77,653,139	190,577	81,371,497	199,121

	Six months ended		Six months ended
	June 30, 2003		June 30, 2002
	Number	Amont	Number	Amount
Balance, beginning of year	78,956,875	193,723	80,103,784	198,506
Shares repurchased and cancelled
pursuant to Normal Course Issuer Bid (a)	(1,477,400)	(3,616)	—	—
Stock options exercised for cash	170,400	467	1,168,125	529
Corresponding convertible securities, converted	3,264	3	107,908	97
Cancelled shares	—	—	(8,320)	(11)
Balance, end of period	77,653,139	190,577	81,371,497	199,121

(a) During the third quarter of 2002, the Corporation adopted a normal course issuer bid to repurchase, for cancellation, up to 5,253,238 common shares during the period from August 7, 2002 to August 6, 2003. As at December 31, 2002, the Corporation had purchased and cancelled 2,531,870 shares at an average price of C$14.57 per share. The Corporation purchased and cancelled an additional 98,100 at an average price of C$15.50 per share during the first 3 months of 2003. The excess of cost over the book value for the shares purchased was applied to retained earnings.

(b) The Corporation has elected to use the intrinsic value method of accounting for stock options and to disclose the pro forma results of using the fair value method.

The pro forma net income per share had we applied the fair-value based method of accounting for stock options follows:

	Three months ended		Six months ended
	June 30		June 30
	2003	2002	2003	2002
Net income
As reported	68,211	33,808	136,435	56,917
Pro forma	68,002	33,406	136,196	56,458
Basic net income per share
As reported	0.87	0.42	1.74	0.70
Pro forma	0.87	0.41	1.73	0.70
Diluted net income per share
As reported	0.84	0.40	1.67	0.67
Pro forma	0.84	0.40	1.67	0.67

A summary of the status of the Corporation’s stock option plan as of June 30, 2003 and the changes during the six months ended June 30, 2003 and year ended December 31, 2002 is presented below (expressed in Canadian dollars):

	Options	Weighted Average
		Excercise Price
Outstanding at December 31, 2001	5,736,880	3.07
Granted	605,000	14.65
Excercised	(1,393,281)	1.09
Forfeited	(98,463)	6.73
Outstanding at December 31, 2002	4,850,136	5.01
Granted	17,000	16.20
Excercised	(173,664)	0.06
Forfeited	(28,300)	9.62
Outstanding at June 30, 2003	4,665,172	5.06
Options excercisable at:
December 31, 2002 (amended)	1,908,798	3.87
June 30, 2003	2,527,127	2.82

9	INCOME TAXES

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

	Three months ended		Six months ended
	June 30		June 30
	2003	2002	2003	2002
Statutory Kazakhstan income tax rate	30%	30%	30%	30%
Expected tax expense	29,155	16,155	60,000	27,196
Non-deductible amounts, net	(803)	4,390	2,294	3,500
Lower tax rate for South Kumkol field	—	(932)	—	(1,096)
Future tax recognized	—	—	—	2,853
Income tax expense	28,352	19,613	62,294	32,453

10	NET INCOME PER SHARE

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

	Three months ended		Six months ended
	June 30		June 30
	2003	2002	2003	2002
Weighted average number of common
shares outstanding	78,000,877	81,196,383	78,538,671	80,911,226
Dilution from exercisable options
(including convertible securities)	3,173,080	3,493,951	3,138,160	3,493,951
Diluted number of shares outstanding	81,173,957	84,690,334	81,676,831	84,405,177

No options were excluded from the calculation of diluted number of shares outstanding for the three months ended June 30, 2003 and 2002, as the market price was in excess of exercise price.

11	FINANCIAL INSTRUMENTS

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.

Contract Amount	Contract	Contract	Price Ceiling	Price Floor
(bbls per month)	Period	Type	($/bbl)	($/bbl)
187,500	January 2003 to December 2003	Zero cost collar	29.00	17.00
75,000	January 2003 to December 2003	Zero cost collar	30.00	17.00
112,500	January 2003 to December 2003	Zero cost collar	29.00	18.00
75,000	January 2003 to December 2003	Zero cost collar	29.50	19.00
450,000

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
75,000	January 2004 to December 2004	Zero cost collar	30.20	18.00
35,000	January 2004 to December 2004	Zero cost collar	30.20	18.00
372,500

During the three and six months ended June 30, 2003, the Corporation has foregone revenue of $3.1 million through these contracts.

12	CASH FLOW INFORMATION

Interest and income taxes paid:

	Three months ended		Six months ended
	June 30		June 30
	2003	2002	2003	2002
Interest paid	7,363	3,202	16,832	22,505
Income taxes paid	36,050	17,246	26,292	61,468

13	COMMITMENTS AND CONTINGENCIES

Kazakhstani Environment

Kazakhstan, as an emerging market, has a business infrastructure that is not as advanced as those usually existing in more developed free market economies. As a result, operations carried out in Kazakhstan can involve risks that are not typically associated with those in developed markets.

The development of instability in the ongoing market transformation process could lead to changes in the fundamental business infrastructure in which the Corporation currently operates. Changes in the political, legal, tax or regulatory environment could adversely impact the Corporation’s operations.

Government Taxes and Legislation

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 can lead to the imposition of penalties and interest.

The Corporation through its operating subsidiaries in Kazakhstan, has disputed tax assessments received for the years 1998 through 2001.

The Corporation has been engaged in two court cases in Kazakhstan pertaining to the disputed assessments for 1998 and 1999. The first involved PKOP and was for approximately $8.8 million. PKOP has successfully argued its case at the first level of the court system in Kazakhstan and at the Supreme Court level. There is a possibility that the Ministry of State Revenue may appeal to the ultimate appellate level, the Supervisory Commission of the Supreme Court. No provision has been made in the consolidated financial statements for this assessment.

The second case involved PKKR and was for a total of approximately $10.5 million including taxes, fines, interest and penalties. PKKR was successful at the first level of the court system and was unsuccessful on the majority of the issues at the Supreme Court level. PKKR was unsuccessful in obtaining the Supervisory Commission’s agreement to hear its appeal on the assessed taxes. The Corporation provided for $2.9 million of the $10.5 million in the December 31, 2002 consolidated financial statements. PKKR is currently disputing the remaining $7.6 million of the $10.5 million, which relates to fines and penalties assessed, as PKKR believes there was an incorrect application of the provisions of the tax act. No provision has been made for the disputed penalties.

The Corporation, through its operating subsidiaries in Kazakhstan received tax assessments for 2000 and 2001 amounting to $56.0 million, which were reduced through negotiations to $45.0 million (including our 50% share of Turgai’s assessments). The Corporation does not agree with these assessments and has filed court cases disputing these amounts, hence no provision was made in the consolidated financial statements. PKOP has been successful at the first level of the court system and at the Supreme Court with respect to the entire $12.5 million of its assessment. This assessment was for withholding taxes on the acquisition of an interest in the Caspian Pipeline Consortium (“CPC”) and this transaction was not completed. Turgai has been successful at the first two levels of the court system on almost its entire assessment of $12.0 million, of which $6.0 million is our 50% share.

The PKKR court cases commenced in February of 2003. The disputed assessment was split into two 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 $3.8 million of the $13.0 million and lost on the remainder. The issues that PKKR lost were the assessment of royalties on flared associated gas (approximately $7.2 million) and a claim for social taxes under tax stability provisions of PKKR’s Hydrocarbons Contracts. This claim on social taxes was made in spite of an agreement revising this clause of the contract. There were a number of items amounting to $3.8 million upon which PKKR was successful. The Corporation has appealed to the Supreme Court and the case will be heard in the third quarter of 2003. The second case was for $13.5 million, with $6.9 million related to transfer pricing sent back by the court for renegotiation. The amount has been reduced through re-negotiation by $3.3 million to $3.6 million. The other $6.6 million is comprised of a number of items and the Corporation expects that the determination of this $6.6 million and the remaining $3.6 million related to the transfer pricing will be subject to further court proceedings.

Corporate information

DIRECTORS

Bernard F. Isautier
President and Chief Executive Officer Windsor, United Kingdom Askar Alshinbaev ^(1)(2)(3)Managing Director, OJSC Kazkommertsbank Almaty, Kazakhstan James B.C. Doak ⁽¹⁾⁽³⁾President and Managing Partner, Megantic Asset Management Inc. Toronto, Ontario Hon. Robert P. Kaplan ⁽³⁾International Business Consultant Toronto, Ontario Jacques Lefevre ⁽¹⁾⁽²⁾Vice Chairman, Lafarge S.A.
Paris, France
Louis W. MacEachern ⁽²⁾⁽³⁾President, Fortune Industries Ltd. Calgary, Alberta

⁽¹⁾

Audit Committee Member

⁽²⁾

Compensation Committee Member

⁽³⁾

Corporate Governance Committee Member

OFFICERS

Bernard F. Isautier
President and Chief Executive Officer Marlo C. Thomas Executive Vice President and Chief Operating Officer Mike Azancot Senior Vice President, Exploration Development Nicholas H. Gay Senior Vice President, Finance and Chief Financial Officer Anthony R. Peart Senior Vice President, General Counsel and Corporate Secretary Dermot 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

Deloitte & Touche 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
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

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: Marlo C. Thomas, President

SHARE LISTINGS

The Toronto Stock Exchange Trading Symbol — PKN
S&P/TSX
• 100 Composite Index • Energy Index • Canadian Midcap Index

New York Stock Exchange Trading Symbol — PKN

Germany

Frankfurt
Trading Symbol – PKZ

Website: www.petrokazakhstan.com
Email: ir@petrokazakhstan.com