Petrokazakhstan 6-K Message to the shareholders

Exhibit 99.1

 

Message to the shareholders

HIGHLIGHTS

PetroKazakhstan’s Second Quarter 2004 highlights included the following:

Ø	Strong earnings and cash flow continue in the second quarter 2004
Ø	Continued reduction of export differential
Ø	Additional drilling in Kyzylkiya confirms further field extension to the north
Ø	Aryskum gas injection facility commissioned and operational
Ø	VGO exports commenced

FINANCIAL HIGHLIGHTS

(EXPRESSED IN MILLIONS OF US $ EXCEPT PER SHARE AMMOUNTS)	Six months ended June 30				Three months ended June 30
		2004		2003		2004		2003
Gross Revenue	$	721.4	$	503.5	$	399.9	$	254.6
Net income		209.5		137.0		122.0		68.4
Per share (basic)		2.64		1.74		1.54		0.88
Per share (diluted)		2.60		1.68		1.51		0.84
Cash flow		256.2		179.9		141.6		91.0
Per share (basic)		3.23		2.29		1.78		1.17
Per share (diluted)		3.18		2.20		1.75		1.12
Weighted Average Shares Outstanding
Basic		79,257,431		78,538,671		79,442,775		78,000,877
Diluted		80,484,892		81,676,831		80,721,531		81,173,957
Shares Outstanding at End of Period		80,597,166		77,653,139		80,597,166		77,653,139

PetroKazakhstan is pleased to announce its financial results for the second quarter of 2004 achieving $122.0 million of net income and $141.6 million of cash flow. This represents basic net income per share of $1.54 and basic cash flow per share of $1.78 for the quarter. The comparable figures for the quarter ended June 30, 2003 were $0.88 basic net income per share and $1.17 basic cash flow per share.

For the six months ended June 30, 2004 net income was $209.5 million and cash flow was $256.2 million. This represented basic net income per share of $2.64 and basic cash flow per share of $3.23. The comparable figures for the six months ended June 30, 2003 were net income per share of $1.74 and basic cash flow per share of $2.29.

SUBSTANTIAL ISSUER BID

The Company’s substantial issuer bid share tender, which ended on July 19, 2004, has resulted in the repurchase of 3,999,975 shares at C$40.00 per share. After giving effect to the repurchase and cancellation of the repurchased shares, the Company will have 76,597,191 shares outstanding.

2

UPSTREAM OPERATIONS REVIEW PRODUCTION During the second quarter of 2004, PetroKazakhstan’s production volumes totaled 13.75 million barrels or an average of 151,104 barrels of oil per day (“bopd”) representing an increase of 4.2% over the second quarter 2003 average production of 145,066 bopd and a 5.7% increase over the first quarter of 2004 average production rates of 142,919 bopd. Kumkol South production has gradually increased in the quarter as all but one of the 19 wells shut in late in 2003 were brought back on line. A resolution has been agreed with the neighbouring license holder Turgai Petroleum and the Government authorities on mutually acceptable operating conditions of wells located at the border between Kumkol South and Kumkol North. New development wells in Kumkol North and the KAM fields have also contributed to the increase in production. FIELD DEVELOPMENTS Five production wells were drilled in the Kyzylkiya field and the neighbouring Kolzhan license to the north this quarter bringing the total number of wells drilled this year to nine. Of particular interest are wells Kyzylkiya-26 (drilled in the first quarter of 2004) and 34, which have been tested at rates of 1,600 bopd and 1,050 bopd respectively and have confirmed an extension of the main field to the north. Four more development wells should be drilled by the end of the year. Maibulak wells continue to perform at higher rates following the successful fracture stimulation. Maibulak-01 for example was produced at 910 bopd, a 550% increase over previously recorded rates. Water injection facilities for reservoir pressure maintenance with a total injection capacity of 7,000 barrels of water a day (“bwpd”) were commissioned and are in operation. The Aryskum drilling campaign commenced with 3 wells completed in the second quarter of 2004. Up to thirteen more wells will be drilled in the second half of the year, one of which will be a horizontal well for enhanced production and reserves exploitation. A gas injection system for the Aryskum field development has been commissioned and is operational. This is the first stage of the facilities that will eventually enable complete re-injection of Aryskum produced gas to minimize flaring and contribute to pressure maintenance of the reservoir. Work has commenced on the upgrade of the Akshabulak processing facilities that will enable production rates to increase to over 60,000 bopd (30,000 bopd net) by mid 2005. In addition, a water injection system has been commissioned to stabilize reservoir pressure and allow increased production off-take. Development of and production from the East Kumkol field is expected to recommence in the third quarter of 2004, subject to regulatory approvals. EXPLORATION AND APPRAISAL A total of 215 square kilometres (“km2”) of 3D seismic was acquired over the northern and southern areas of the Kyzylkiya field along with 300 kilometres (“kms”) of 2D seismic over the eastern half of the Kolzhan license to the northeast. This information will enable selection of appraisal/exploration well locations to prove up further reservoir extensions and possible satellite accumulations of the Kyzylkiya field within the recently acquired Kolzhan license. Further enhanced seismic interpretation of the North Nurali field is close to completion. This will enable the selection of two follow-on appraisal wells which should be drilled before year-end. Temporary single well production units have been installed at two wells enabling extended testing for reservoir delineation purposes with combined rates of up to 1,800 bopd. A well drilled to 4,244 metres (“m”) within the Aryskum license area encountered hydrocarbon bearing sands. In the lower sections, the sands were tight and not tested. In the upper well section several zones are still being evaluated to determine possible hydrocarbon potential. PetroKazakhstan is now the operator and 75% equity partner of the License 951-D which covers two blocks (the Doshan block and the Zhamansu block) in the South Turgai Basin over a total area of 4,290 km2. 600 kms of 2D seismic data has been acquired over the two blocks. An exploration well was drilled to 2,350 m in the northern Doshan block south of the Aryskum field. Despite encountering oil shows whilst drilling and the presence of unusually thick reservoir intervals, the well failed to encounter hydrocarbons within the main reservoir units. The existing D-3 well within the Doshan Block has been put back on test at low rates – currently around 100 bopd. This well is being considered for future fracture stimulation. At least two wells are planned in the southern Zhamansu block later in 2004. EXPLOITATION OF GAS RESOURCES Following the completion of the 55 megawatt power plant in Kumkol, which exploits part of the gas previously flared from Kumkol South, South Kumkol and Kumkol North reservoirs, PetroKazakhstan continues to assess additional methods to increase gas utilization. Evaluation has commenced on the feasibility of gas usage for miscible hydrocarbon injection for enhanced oil recovery. A pilot project is being designed for one of the Kumkol fields. In parallel, assessment is being made of a Liquefied Petroleum Gas (“LPG”) facility in Kumkol.

3

PetroKazakhstan, as a 50% partner in the Kazgermunai Joint Venture, is also participating in Kazgermunai’s LPG extraction plant for the Akshabulak field. The 30 million standard cubic feet per day (“mmscfd”) plant will provide 2,900 bopd of LPG and 600 bopd of condensate. Facilities design has commenced and long lead item orders placed. Civil works including road and site grading have also commenced and piling and transportation contracts have been awarded. The dry gas will be provided to the city of Kyzylorda through a pipeline to be constructed by KazTransGaz. DOWNSTREAM MARKETING, TRANSPORTATION AND REFINING
CRUDE OIL LOGISTICS The volume of crude oil exported during the second quarter of 2004 was 6.99 mmbbls (902.3 thousand tonnes) representing a decrease of approximately 3% compared to the second quarter of 2003 and an 11% decline as compared to the first quarter of 2004. This performance reflects the operational problems with the Atasu pipeline and terminal, which occurred mid February 2004 and were finally resolved mid May 2004 together with a limitation on export quotas issued by the Ministry of Energy and Mineral Resources (“MEMR”) in Kazakhstan. The volume accounted for by our Dzhusaly terminal continued to grow reaching 78% of all shipments during the second quarter as compared to 70% during the first quarter. Our Dzhusaly terminal came into operation at the end of the second quarter in 2003 and therefore accounted for less than 1% of the shipments during the same period in 2003. Deliveries to China during the second quarter of 2004 represented 83% of the equivalent shipments during the first quarter and 74% of the volumes shipped during the same quarter in 2003. Again, this performance reflects a combination of the operational issues surrounding the Atasu pipeline and terminal and the export quotas issued by MEMR. Deliveries via the CPC pipeline continued to grow and were up by 5% compared to the first quarter of 2004. There are no comparative numbers for 2003 as deliveries via CPC did not commence until September of that year. Shipments to the Tehran refinery under our swap contract continued to grow albeit at a slower rate than anticipated due to the export quota restrictions imposed by MEMR during April and May. The facilities are now in place to handle the maximum contractual volumes and, in the absence of any further export quota restrictions, the maximum volumes will be achieved during the third quarter of 2004. CRUDE OIL PRICES AND TRANSPORTATION DIFFERENTIALS   International crude oil prices remained high with an extremely high volatility. The average of the daily mean of the Platts quotations for Brent was $35.32 per barrel in the second quarter as compared to $26.03 per barrel in the same period of 2003. The spread of the mean of the daily quotations in the second quarter of 2004 was much higher than that seen during the first quarter registering $8.44 per barrel and $5.85 per barrel respectively. The highest mean of the daily quotations seen during the second quarter was $39.36 per barrel as compared to $34.97 per barrel during the first quarter. Net returns, measured fully costed at the Kumkol field gate, continued to improve on the back of an improved combination of transportation routes, better pricing received from our customers, and better world market prices. REFINING AND REFINED PRODUCT SALES The volumes of refined products processed at our refinery were 7.7 mmbbls and were marginally higher in the second quarter of 2004 than in the first quarter when volumes processed stood at 7.1 mmbbls. The equivalent figure in 2003 was 7.5 mmbbls. However, refined product sales volumes were significantly higher in the second quarter of 2004 than had been in the first quarter of 2004. Though average prices of key product fell in the quarter the change in mix of sales to the higher value products caused an increase in refined product revenue. Following the resolution with the customs authorities of the classification of Vacuum Gasoil (VGO) as distinct from diesel, the Vacuum Distillation Unit was restarted during the second quarter. The first export sales of VGO were successfully made via the port of Tallinn in Estonia and to China. The production of VGO has had a positive effect on weighted average refined product prices. Refined product exports to neighbouring countries were further developed and in most cases we are now selling either direct to end users or at the border station of the receiving country. As a consequence we are beginning to see improved prices on exports of refined products. Respectfully submitted on behalf of the board of Directors, (signed) Bernard F. Isautier President and Chief Executive Officer July 29, 2004

4

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following Management’s Discussion and Analysis (“MD&A”) of the financial condition and results of our operations should be read in conjunction with 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, 2003. 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 MD&A we use certain terms including “netback” and “cash flow”. These are non-GAAP terms with cash flow defined as cash generated from operating activities before changes in non-cash working capital and netback is defined within our MD&A.

Except as otherwise required by the context, reference in this MD&A to “our”, “we” or “us” refer to the combined business of PetroKazakhstan Inc. and all of its subsidiaries and joint ventures.

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

HIGHLIGHTS

	Three months ended June 30
		2004	2003
Net income ($000's)		122,028	68,430
Cash flow ($000's)1		141,552	91,020
Basic net income per share		1.54	0.88
Basic cash flow per share		1.78	1.17
BOPD		151,104	145,066
Capital expenditures ($000's)		27,291	36,694

Six months ended June 30
	2004	2003
Net income ($000's)	209,513	136,982
Cash flow ($000's)1	256,233	179,893
Basic net income per share	2.64	1.74
Basic cash flow per share	3.23	2.29
BOPD	147,012	142,928
Capital expenditures ($000's)	66,416	87,015

¹ Cash flow: We evaluate our operations based upon our net income and cash flow. Cash flow is a non-GAAP measure that represents cash flow from operations before changes in working capital. We consider this to be a key measure as we use this measure to evaluate our ability to generate cash to fund our growth through capital expenditures and our ability to repay debt. The comparable GAAP measure is cash flow from operating activities. The following table reconciles our non-GAAP measure cash flow to the comparable GAAP measure "Cash flow from operating activities".

Three months ended June 30
	2004	2003
	($000’s)	($000’s)
Cash flow	141,552	91,020
Changes in non-cash operating working capital items	63,774	(58,272	)
Cash flow from operating activities	205,326	32,748

	Six months ended June 30
		2004	2003
		($000’s)	($000’s)
Cash flow		256,233	179,893
Changes in non-cash operating working capital items		44,214	(42,368	)
Cash flow from operating activities		300,447	137,525

5

NET RETURN PER BARREL

Set forth below are the details of the average net return achieved for crude oil export sales and sales derived from the refining of our own crude. These tables show averages across all types of sales contracts and illustrate the relationship between exports of crude oil versus refining our own crude oil and marketing refined crude oil products.

	Three months ended June 30, 2004
	Crude Oil			Own Crude Oil
	Exports			Refined and Sold*
	($/bbl)			($/bbl)
Net sales price achieved		27.81			22.04
Transportation costs		(5.53	)		(1.85	)
Selling costs		(0.59	)		(0.76	)
Crude utilized in refining		-			(1.40	)
Refining cost		-			(0.71	)
Royalties and taxes – downstream		-			(0.64	)
General and administrative costs – downstream		-			(0.45	)
Netback at Kumkol**		21.69			16.23
Production cost		(1.87	)		(1.87	)
Royalties and taxes – upstream		(1.50	)		(1.50	)
General and administrative costs – upstream		(0.58	)		(0.58	)
Net return per barrel		17.74			12.28

	Three months ended June 30, 2003
	Crude Oil			Own Crude Oil
	Exports			Refined and Sold*
	($/bbl)			($/bbl)
Net sales price achieved		18.56			14.66
Transportation costs		(7.89	)		(0.96	)
Selling costs		(0.34	)		(0.77	)
Crude utilized in refining		-			(0.86	)
Refining cost		-			(0.72	)
Royalties and taxes – downstream		-			(0.36	)
General and administrative costs – downstream		-			(0.36	)
Netback at Kumkol**		10.33			10.63
Production cost		(1.28	)		(1.28	)
Royalties and taxes – upstream		(1.13	)		(1.13	)
General and administrative costs – upstream		(0.56	)		(0.56	)
Net return per barrel		7.36			7.66

* Net sales price achieved shown in these tables does not include the price received for purchased refined products resold.

** Average Platts Brent or a similar index for each respective period does not reflect our average realized Brent price because of the timing of recognition of sales for financial statement purposes and the terms of the sales. Financial statement sales revenue is the basis used to determine the net sales price achieved in these tables. Therefore, a comparison of average Platts Brent or similar index to our netback at Kumkol cannot be used to determine our differential.

During the second quarter of 2004, the netback at Kumkol for crude oil exports increased by $11.36/bbl compared to the same quarter of 2003 due to a significant increase in market prices (average Platts Brent was $35.32/bbl compared to $26.03/bbl in 2003) and savings in transportation costs.

The netback at Kumkol for own crude oil refined and sold increased by $5.60/bbl compared to the second quarter of 2003 due to higher sales prices, offset in part by increases in our transportation costs, because we exported some refined products volumes on a non-FCA basis.

6

	Six months ended June 30, 2004
	Crude Oil			Own Crude Oil
	Exports			Refined and Sold*
	($/bbl)			($/bbl)
Net sales price achieved		25.92			20.56
Transportation costs		(6.64	)		(1.55	)
Selling costs		(0.55	)		(0.92	)
Crude utilized in refining		-			(1.33	)
Refining cost		-			(0.63	)
Royalties and taxes – downstream		-			(0.76	)
General and administrative costs – downstream		-			(0.46	)
Netback at Kumkol**		18.73			14.91
Production cost		(1.76	)		(1.76	)
Royalties and taxes – upstream		(1.30	)		(1.30	)
General and administrative costs – upstream		(0.57	)		(0.57	)
Net return per barrel		15.10			11.28

	Six months ended June 30, 2003
	��	Crude Oil			Own Crude Oil
		Exports			Refined and Sold*
		($/bbl)			($/bbl)
Net sales price achieved			20.70			14.38
Transportation costs			(7.98	)		(0.93	)
Selling costs			(0.34	)		(0.67	)
Crude utilized in refining			-			(0.86	)
Refining cost			-			(0.56	)
Royalties and taxes – downstream			-			(0.32	)
General and administrative costs – downstream			-			(0.44	)
Netback at Kumkol**			12.38			10.60
Production cost			(1.32	)		(1.32	)
Royalties and taxes – upstream			(0.94	)		(0.94	)
General and administrative costs – upstream			(0.58	)		(0.58	)
Net return per barrel			9.54			7.76

During the first six months of 2004, the netback at Kumkol for crude oil exports increased by $6.35/bbl compared to the same period of 2003 due to a significant increase in market prices (average Platts Brent was $33.66/bbl compared to $28.76/bbl in 2003) and savings in transportation costs.

The netback at Kumkol for own crude oil refined and sold increased by $4.31/bbl compared to the second quarter of 2003 due to higher sales prices, offset in part by increases in our transportation and selling costs. Transportation costs increased because we exported some refined products volumes on a non-FCA basis.

KEY PERFORMANCE INDICATORS

We measure the performance of our Upstream and Downstream operations using the following key performance indicators.

	Three months ended June 30
		2004		2003
BOPD		151,104		145,066
Differential* ($/bbl)		12.20		14.66
Average refined products price ($/bbl)		22.04		14.97
Production expenses ($/bbl)		1.87		1.28
Refining cost ($/bbl))		0.71		0.77
General and administrative ($/bbl)		1.03		0.92
Effective income tax rate, %		39.5	%	29.3	%

7

	Six months ended June 30
		2004		2003
BOPD		147,012		142,928
Differential* ($/bbl)		12.47		14.72
Average refined products price ($/bbl)		20.56		14.38
Production expenses ($/bbl)		1.76		1.32
Refining cost ($/bbl))		0.63		0.58
General and administrative ($/bbl)		1.03		1.02
Effective income tax rate, %		37.1	%	31.2	%

* Our differential is calculated as the difference between the average Brent price for crude oil export sales received by PKKR and Turgai, and our netback at Kumkol. It is the sum of the costs and discounts incurred in order to transport and sell our crude oil to international markets. The sales revenue used in this measure differs from sales revenue in the statement of net income and the net return table for the following reasons:
	•	The differential does not include Kazgermunai sales over which we have limited control. Kazgermunai is excluded because the differential is used to measure the performance of our internal marketing and transportation group.
	•	The differential is calculated using finalized sales transactions. Our financial statements include estimates that may or may not reflect the finalized transactions.

BOPD. See Production and Processing for a discussion of our production. Differentials. The graph to the right shows our differential over the last year and the first two quarters of 2004 ($/bbl). Our differential continued to improve during the quarter as a result of the increased shipments through CPC via the KAM pipeline, and better pricing received from some of our customers. Sales to Aktau and CPC are our most significant destinations, representing almost two thirds of the quarter’s total completed sales volumes. These constitute two of our five main destinations, where we have concentrated our efforts on routes that had the best differentials. Production expenses. Production expenses were higher in the second quarter of 2004 compared to 2003 because of a number of factors. We are using temporary power generators to operate single well batteries in the KAM fields pending construction of infrastructure. The increased number of production facilities commissioned in 2004 and the increasing water cut in a number of our fields has also increased production expenses.  

Refining cost.Refining costs in the second quarter of 2004 are consistent with the second quarter of 2003. Refining costs in the first six months of 2004 are higher due to higher purchased energy costs related to the start-up of the vacuum distillation unit.

General and administrative expenses.General and administrative expenses increased due to $1.3 million of compensation cost being recognized for stock options granted pursuant to the new CICA accounting standard, which we adopted at the beginning of 2004. The remaining increase is attributable to increased activity levels.

Effective income tax rate.The statutory tax rate in Kazakhstan, where all of our operations are located, is 30%. Our effective tax rate differs due to certain expenses, which cannot be deducted for statutory tax purposes. Our tax rate as a percentage of net income before tax in the second quarter of 2004 was 39.5% compared to 29.3% in the same quarter of 2003 (37.1% for the six months of 2004 compared to 31.2% for the same period of 2003). The effective income tax rates are higher in 2004 due to provisions for excess profit tax, whereas there was no provision in 2003.

8

PRODUCTION AND PROCESSING

PRODUCTION

The following table sets forth our barrels of oil produced per day by field and on a consolidated basis.

	Three months ended June 30
Field		2004	2003
		(BOPD)	(BOPD)
Kumkol South		50,014	62,550
Kumkol North		34,844	29,459
South Kumkol		23,311	27,488
Kyzylkiya		9,783	7,310
Aryskum		8,030	2,650
Maibulak		2,446	576
North Nurali		559	-
License #952		396	-
License #951		12	-
Kazgermunai Fields		21,709	15,033
Total		151,104	145,066

	Six months ended June 30
Field		2004	2003
		(BOPD)	(BOPD)
Kumkol South		46,127	59,630
Kumkol North		34,136	27,594
South Kumkol		24,564	29,120
Kyzylkiya		9,604	7,031
Aryskum		8,411	5,133
Maibulak		2,255	510
North Nurali		340	-
License #952		222	-
License #951		6	-
Kazgermunai Fields		21,347	13,909
Total		147,012	142,927

The decrease in Kumkol South production in the second quarter and for the first six months of 2004 was due to our field border well dispute with neighboring license holder, Turgai. We have resumed production with the exception of one well, which was not operational as of June 30, 2004. Also, production was impeded due to limited water handling capability. One of our Free Water Knock-out facilities remained out of production for three months due to an accident at the facility.

Increases in production from our Kumkol North field in the second quarter of 2004 were due to an increase in the number of production wells and a program to increase the size of the downhole pumps.

South Kumkol production was affected by bottom hole pump failures, requiring repair and replacement.

The increase in production from our KAM fields (Kyzylkiya, Aryskum, Maibulak) was due to the increased number of producing wells and implementation of our artificial lift program. At Maibulak, our wells became flowing wells as a result of our successful hydraulic fracturing campaign.

Kazgermunai completed surface facility debottlenecking measures in late 2003, leading to the increase in 2004 production.

9

INVENTORY

The following table sets forth the movements in crude oil inventory for our Upstream operations for the three and six months ended June 30, 2004 and 2003.

	Three months ended June 30
		2004		2003
		(MMbbls)		(MMbbls)
Opening inventory of crude oil		2.56		2.54
Production		13.75		13.20
Crude oil purchased from third parties		-		-
Crude oil purchased from joint ventures (50%)		(0.17	)	(0.21	)
Sales or transfers		(13.48	)	(13.33	)
Transportation losses		(0.05	)	(0.08	)
Closing inventory of crude oil		2.61		2.12

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

We do not eliminate crude oil purchased from our joint ventures 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 ventures are in excess of actual crude oil purchased from our joint ventures, 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
		2004		2003
		(MMbbls)		(MMbbls)
Opening inventory of crude oil		2.87		2.72
Production		26.76		25.87
Crude oil purchased from third parties		-		-
Crude oil purchased from joint ventures (50%)		0.15		0.41
Sales or transfers		(28.16	)	(26.14	)
Transportation losses		(0.10	)	(0.09	)
Return of purchased crude		-		(0.65	)
Closing inventory of crude oil		2.61		2.12

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.

SALES OF CRUDE OIL

The following table sets out our total crude oil sales and transfers from Upstream operations for the three and six months ended June 30, 2004 and 2003.

	Three months ended June 30
		2004	2004	2003	2003
		(MMbbls)	(%)	(MMbbls)	(%)
Crude oil exports		6.99	51.9	7.23	54.2
Crude oil transferred to Downstream		4.10	30.4	4.53	34.0
Crude oil transferred to Downstream by joint ventures (50%)		1.68	12.5	1.57	11.8
Royalty payments		0.71	5.2	-	-
Crude oil domestic sales		-	-	-	-
Total crude oil sales or transfers		13.48	100.0	13.33	100.0

10

	Six months ended June 30
		2004	2004	2003	2003
		(MMbbls)	(%)	(MMbbls)	(%)
Crude oil exports		14.84	52.7	13.36	51.1
Crude oil transferred to Downstream		8.25	29.2	9.93	38.0
Crude oil transferred to Downstream by joint ventures (50%)		3.19	11.4	2.85	10.9
Royalty payments		1.88	6.7	-	-
Crude oil domestic sales		-	-	-	-
Total crude oil sales or transfers		28.16	100.0	26.14	100.0

REFINING

Our total processed volumes were as follows:

	Three months ended June 30
		2004	2003
		(MMbbls)	(MMbbls)
Feedstock refined into product		7.62	7.52
Tolled volumes		0.10	-
Total processed volumes*		7.72	7.52

Six months ended June 30
	2004	2003
	(MMbbls)	(MMbbls)

Feedstock refined into product	14.70	15.55
Tolled volumes	0.13	0.23
Total processed volumes*	14.83	15.78

*The total processed volumes are used for our per barrel calculations.

Sources of feedstock supplies for our refinery were as follows:

Three months ended June 30
	2004	2003
	(MMbbls)	(MMbbls)

Acquired from PKKR	4.10	4.53
Purchased from joint ventures (100%)	3.37	3.14
Total feedstock acquired	7.47	7.67

Six months ended June 30
	2004	2003
	(MMbbls)	(MMbbls)

Acquired from PKKR	8.25	9.93
Purchased from joint ventures (100%)	6.40	5.70
Total feedstock acquired	14.65	15.63

11

The movements in our feedstock inventory at our refinery were as follows:

Three months ended June 30
	2004	2003
	(MMbbls)	(MMbbls)

Opening inventory of crude oil feedstock	0.15		0.08
Purchase and acquisition of feedstock	7.47		7.67
Recoverable feedstock from traps	0.05		-
Feedstock refined into product	(7.62	)	(7.52	)
Closing inventory of feedstock	0.05		0.23

Six months ended June 30
	2004	2003
	(MMbbls)	(MMbbls)

Opening inventory of crude oil feedstock	0.03		0.20
Purchase and acquisition of feedstock	14.65		15.63
Recoverable feedstock from traps	0.07		(0.05	)
Feedstock refined into product	(14.7	)	(15.55	)
Closing inventory of feedstock	0.05		0.23

The movement in inventory of refined products was as follows:

Three months ended June 30
	2004	2003
	(MM tonnes*)	(MM tonnes*)

Opening inventory of refined product	0.36		0.24
Refined product from feedstock	0.93		0.91
Refined product purchased	0.01		0.01
Refined product sold	(1.11	)	(1.04	)
Refined product internal use and yield losses	(0.01	)	-
Closing inventory of refined product	0.18		0.12

Six months ended June 30
	2004	2003
	(MM tonnes*)	(MM tonnes*)

Opening inventory of refined product	0.26		0.22
Refined product from feedstock	1.78		1.89
Refined product purchased	0.04		0.01
Refined product sold	(1.89	)	(2.00	)
Refined product internal use and yield losses	(0.01	)	-
Closing inventory of refined product	0.18		0.12

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

RESULTS OF OPERATIONS

REVENUE

As at March 31, 2004, approximately 1.2 mmbbls of non-FCA sales were incomplete and hence, included in inventory. The net profit realized on these sales in the second quarter of 2004 was $16.3 million, as compared to $15.6 million of net income estimated at March 31, 2004. As at June 30, 2004, approximately 1.3 mmbbls of non-FCA sales were incomplete and included in inventory. We expect to realize these volumes in the third quarter of 2004 for net profit of $18.1 million.

12

REVENUE
 

	Three months ended June 30
		2004	2003	Change	%
Crude oil		206,086	134,175	71,911	53.6
Revenue products		189,116	119,459	69,657	58.3
Service fees		3,904	460	3,444	749.7
Interest income		797	507	290	57.2
Total revenue		399,903	254,601	145,302	57.1

 

	Six months ended June 30
		2004	2003	Change		%
Crude oil		413,564	276,417	137,147		49.6
Revenue products		300,008	222,414	77,594		34.9
Service fees		6,572	3,327	3,245		97.5
Interest income		1,240	1,366	(126	)	(9.2	)
Total revenue		721,384	503,524	217,860		43.3

CRUDE OIL

The table below sets out volumes sold and net realized prices and crude oil revenue:

THREE MONTHS ENDED JUNE 30, 2004

	Volumes Sold		Net Realized Price		Revenue
	(MMbbls)		($ per bbl)		($000’s)
Crude sales sold FCA		-		-	-
Crude sales sold non-FCA		5.23		28.61	149,622
Kazgermunai export sales		1.76		25.46	44,815
Royalty payments*		0.71		16.41	11,649
Total		7.70		26.76	206,086

THREE MONTHS ENDED JUNE 30, 2003

	Volumes Sold		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*		-		-	-
Total		7.23		18.56	134,175

SIX MONTHS ENDED JUNE 30, 2004

	Volumes Sold		Net Realized Price		Revenue
	(MMbbls)		($ per bbl)		($000’s)
Crude sales sold FCA		-		-	-
Crude sales sold non-FCA		11.49		26.86	308,616
Kazgermunai export sales		3.35		22.73	76,155
Royalty payments*		1.88		15.32	28,793
Total		16.72		24.73	413,564

SIX MONTHS ENDED JUNE 30, 2003

	Volumes Sold		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*		-		-	-
Total		13.36		20.69	276,417

13

*Royalty price is the average sales price at wellhead.

Our increase in crude oil revenue for the second quarter and the first half of 2004 compared to the same period of 2003 was due to the absence of FCA sales and the increase in crude oil market prices.

Royalty payments represent deliveries for royalty in kind volumes. There were no royalty in kind volumes in the second quarter and first half of 2003, because we settled our royalty obligations in cash.

REFINED PRODUCT REVENUE

The table below sets forth the related tonnes of refined products sold, the average price obtained and revenue received for the three and six months ended June 30, 2004 and 2003.

	Three months ended June 30
		Tonnes	Average Price		Revenue
		Sold	($/tonne)		($000’s)
2004		1,107,668		170.73	189,116
2003		1,030,206		115.96	119,459

	Six months ended June 30
		Tonnes	Average Price	Revenue
		Sold	($/tonne)	($000’s)
2004		1,883,890	159.25	300,008
2003		1,996,121	111.42	222,414

The increase in refined products sales in the second quarter of 2004 compared to 2003 of $69.7 million was due to our higher average realized price of $170.73/tonne (compared to $115.96/tonne in 2003) and, to a lesser extent, increased sales volumes of 77,462 tonnes. We were able to obtain higher prices for the first six months of 2004 compared to 2003, as the world price of crude oil increased resulting in higher market prices for refined products in Kazakhstan.

PRODUCTION EXPENSES

Production expenses relate to the cost of producing crude oil in our Upstream operations. Based on the number of barrels of oil produced, these costs were $1.87/bbl in the second quarter of 2004 compared to $1.28/bbl for the second quarter of 2003. The absolute amount of production expenses increased by $8.8 million in the second quarter of 2004. There were a number of contributing factors.

We are experiencing higher chemical usage, an increase of $0.5 million for the second quarter, in our Kumkol South and South Kumkol fields due to the increasing water cut. Artificial lift spare parts usage increased by $0.8 million for the second quarter of 2004 and $1.3 million for the first six months of 2004. We expect these levels of expenditures to continue.

Our utilities increased by $0.9 million as the result of additional field pumps, production facilities, rented generators and wells on pump. The feasibility study for electricity supply to our KAM fields will be complete by the end of July 2004. The study has been undertaken to investigate two possible options, the first being to connect the KAM fields to our power generating facilities in Kumkol as well as the main power lines, and the second is to construct gas turbine power generating facilities in the KAM fields. We expect that completion of this project will reduce our production expenses in 2006.

Additionally, $1.2 million of the increase over the second quarter of 2003 was due to the fact that the second quarter of 2003 included a late audit adjustment in Turgai to reverse previously overaccrued costs.

Production expenses were $47.1 million during the six months ended June 30, 2004 ($1.76/bbl) compared to $34.1 million for the same period of 2003 ($1.32/bbl). In addition to the increases in the second quarter of 2004 described above, additional costs arose for our temporary truck offloading facility in the first quarter of 2004 due to adverse winter weather conditions. Additionally, approximately $1.8 million of the increase over the first six months of 2003 was due to the release of inventoried expenses, as sales volumes exceeded production volumes.

14

ROYALTIES AND TAXES

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

	Three months ended June 30
		2004	2003
		($000’s)	($000’s)
Royalties and production bonus		17,878	11,525
Provision for ARNM assessment		-	-
Tax assessments		251	492
Other taxes		7,414	5,600
Total		25,543	17,617

	Six months ended June 30
		2004	2003
		($000’s)	($000’s)
Royalties and production bonus		29,364	17,743
Provision for ARNM assessment		3,600	-
Tax assessments		251	492
Other taxes		12,709	11,185
Total		45,924	29,420

Royalties and Production Bonus

Royalties and production bonus for the second quarter of 2004 were $17.9 million, which represented an effective overall royalty rate of 6.9% excluding production bonuses of $0.1 million. Royalties and production bonus for the second quarter of 2003 were $11.5 million, an overall royalty rate of 7.8%, after excluding the production bonuses of $0.3 million. The reasons for the lower overall royalty rate were that a higher proportion of production came from fields with lower royalty rates and the temporary reduction in production at Kumkol South.

Royalties and production bonus for the six months ended June 30, 2004 were $29.4 million, which represented an effective overall royalty rate of 6.2% excluding production bonuses of $0.3 million. Royalties and production bonus for the same period of 2003 were $17.7 million, which represented an effective overall royalty rate of 6.8% excluding production bonuses of $0.4 million. The decrease in the royalty rate was mainly due to the decreased production from Kumkol South, a field with higher royalty rates.

Provision for ARNM Assessment

As described in Note 20 to our 2003 Annual Report, the Agency for Regulation of Natural Monopolies and Protection of Competition ("ARNM") alleged that PetroKazakhstan Oil Products, our subsidiary operating the refinery, charged prices for refined oil products that in total were $6.3 million in excess of ARNM authorized maximum prices. In April 2004 following the Supreme Court decision we paid $3.6 million to satisfy the assessment. See Note 13 to the interim consolidated financial statements.

Tax Assessments

The tax assessments of $0.3 million during the second quarter of 2004 represent assessments on property taxes and social taxes. The tax assessments of $0.5 million in the second quarter of 2003 represent tax assessments received on excise and other taxes for 2000 and 2001.

Other Taxes

Other taxes of $7.4 million in the second quarter of 2004 include:

• excise tax on refined products ($4.6 million in 2004 compared to $2.3 million in 2003);

• value added tax on crude oil ($1.4 million in 2004 compared to $2.1 million in 2003);

• various taxes, including property taxes, road fund and other ($1.4 million in 2004 compared to $1.2 million in 2003).

15

Other taxes of $12.7 million in the six month period ended June 30, 2004 include:
	•	excise tax on refined products ($7.0 million in 2004 compared to $4.5 million in 2003);
	•	excise tax on crude oil exports (nil in 2004 compared to $1.0 million in 2003);
	•	value added tax on crude oil ($3.0 million in 2004 compared to $3.3 million in 2003);
	•	various taxes, including property taxes, road fund and other ($2.7 million in 2004 compared to $2.4 million in 2003).

TRANSPORTATION

The table below sets out the components of transportation costs.

	Three months ended June 30
		2004	2003
		($000’s)	($000’s)
Pipeline		8,528	15,468
Kazgermunai transportation		7,704	4,760
Railway		33,156	38,411
Other		1,842	1,630
Total		51,230	60,269

	Six months ended June 30
		2004	2003
		($000’s)	($000’s)
Pipeline		17,339	38,037
Kazgermunai transportation		14,543	6,110
Railway		79,632	67,745
Other		3,795	3,380
Total		115,309	115,272

Pipeline

Pipeline costs decreased by $7.0 million in the second quarter of 2004 compared to 2003 primarily due to the following:

	•	Decrease of $1.5 million in non-FCA pipeline costs (nil for the second quarter of 2004 compared to $1.5 million in the same quarter of 2003) because we did not use the Atyrau-Samara pipeline;
	•	Decrease of $6.6 million, as a result of a decrease in volumes sold for export through the Kumkol - Shymkent pipeline (0.8 mmbbls in the second quarter of 2004 compared to 5.4 mmbbls in the second quarter of 2003), partially offset by higher tariffs for the Kumkol - Shymkent pipeline in 2004 ($1.64/bbl in 2004 compared to $1.49/bbl in 2003) due to the change in the exchange rate of Tenge to U.S. dollar;
	•	Increase of $1.1 million on volumes shipped through our KAM pipeline and through Atasu terminal to China (3.8 mmbbls through the KAM pipeline and 0.8 mmbbls through Atasu in the second quarter of 2004 compared to 0.3 mmbbls through Atasu and no shipments through the KAM pipeline in the second quarter of 2003).
Pipeline costs decreased by $20.7 million during the six months ended June 30, 2004 compared to the same period of 2003 primarily due to the following:
	•	Decrease of $10.1 million in non-FCA pipeline costs (nil for the first six months of 2004 compared to $10.1 million in the same period of 2003) because we did not use the Atyrau-Samara pipeline;
	•	Decrease of $11.9 million, as a result of a decrease in volumes sold for export through the Kumkol - Shymkent pipeline (2.3 mmbbls in 2004 compared to 10.8 mmbbls in 2003), partially offset by higher tariffs for the Kumkol - Shymkent pipeline in 2004 ($1.64/bbl in 2004 compared to $1.49/bbl in 2003) due to the change in the exchange rate of Tenge to U.S. dollar;
	•	Decrease of $1.5 million, as a result of a decrease of 1.6 mmbbls in crude oil volumes sent to the refinery through the Kumkol - Shymkent pipeline;
	•	Increase of $2.8 million on volumes shipped through our KAM pipeline and through Atasu terminal to China (7.7 mmbbls through the KAM pipeline and 1.6 mmbbls through Atasu in the first half of 2004 compared to 0.3 mmbbls through Atasu in the first half of 2003). There were no sales through the KAM pipeline in the first half of 2003.

16

Railway

Railway transportation decreased by $5.2 million in the second quarter of 2004 and increased by $11.9 million in the first six months of 2004 compared to the same periods of 2003 due to the use of sales routes, different from those used in 2003. Overall, railway costs are higher in the first six months of 2004 due to the increase in non-FCA sales and the absence of FCA sales in 2004, where revenue is reported net of transportation costs.

Other

Other transportation costs are mainly trucking costs incurred to transport crude oil from the KAM fields to the CPF located at Kumkol.

REFINING

Refining costs represent the direct costs related to processing all crude oil, including tollers’ volumes, at the refinery.

Refining costs for the second quarter of 2004 were $5.5 million ($0.71/bbl) consistent with $5.5 million ($0.72/bbl) in the same quarter of 2003. Refining costs for the six months ended June 30, 2004 were $9.4 million compared to $8.8 million in the same period of 2003. The main reason for the $0.6 million increase in refining costs was due to the higher steam and electric power costs related to the start-up of the vacuum distillation unit in the first quarter of 2004.

CRUDE OIL AND REFINED PRODUCT PURCHASES

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

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

	Three months ended June 30
		2004	2003
		($000’s)	($000’s)
Crude oil		29,135	16,046
Refined products		3,274	-
Total		32,409	16,046

	Six months ended June 30
		2004	2003
		($000’s)	($000’s)
Crude oil		59,779	25,416
Refined products		6,186	-
Total		65,965	25,416

During the first quarter of 2004 we repurchased the royalty-in-kind volumes for $17.1 million and subsequently resold them. The remaining purchases of crude oil were made from our joint ventures.

SELLING

Selling expenses for crude oil are comprised of customs, quality inspection and costs related to the export of crude oil. Selling expenses for refined products are comprised of the costs of operating the distribution centres for our Downstream operations.

	Three months ended June 30
		2004	2003
		($000’s)	($000’s)
Crude oil		4,109	2,659
Refined products		5,097	4,699
Total		9,206	7,358

17

	Six months ended June 30
		2004	2003
		($000’s)	($000’s)
Crude oil		8,234	4,507
Refined products		9,429	8,322
Total		17,663	12,829

The increase in crude oil selling expenses during the second quarter and first six months of 2004 compared to the same periods of 2003 was the direct result of increased export sales volumes related to non-FCA routes, for which all selling costs are absorbed by us, and the increase in Kazgermunai sales volumes.

GENERAL AND ADMINISTRATIVE

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

THREE MONTHS ENDED JUNE 30, 2004

	General and		Per barrel of oil
	Administrative		produced or processed*
	($000’s)		($/bbl)
Upstream		7,917		0.58
Downstream		3,467		0.45
Corporate		4,280
Total		15,664

* Including tollers’ volumes

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		2,723		0.36
Corporate		500
Total		10,556

* Including tollers’ volumes

The increase in general administrative expenses of $5.1 million was due to $1.3 million of compensation cost being recognized for stock options granted pursuant to the new CICA accounting standard, which we adopted at the beginning of 2004. The remaining increase is attributable to increased activity levels.

SIX MONTHS ENDED JUNE 30, 2004

	General and		Per barrel of oil
	Administrative		produced or processed*
	($000’s)		($/bbl)
Upstream		15,260		0.57
Downstream		6,831		0.46
Corporate		6,816
Total		28,907

* Including tollers’ volumes

18

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		6,889		0.44
Corporate		1,523
Total		23,533

* Including tollers’ volumes

The increase in corporate general administrative expenses of $5.3 million was mainly due to $2.1 million of compensation cost being recognized for stock options granted pursuant to the new CICA accounting standard, which we adopted at the beginning of 2004. The remaining increase is attributable to increased activity levels.

INTEREST AND FINANCING

The following table sets forth our interest and financing costs and any related amortization of debt issue costs or discounts upon issuance of the debt instrument.

	Three months ended June 30
		2004	2003
		($000’s)	($000’s)
9.625% Notes		3,504	3,150
Term facility		1,251	3,176
Kazgermunai debt		392	(327	)
PKOP bonds		-	695
Short-term debt		205	173
Accretion expense		608	513
Term loans		122	-
Less portion capitalized		-	-
Total		6,082	7,380

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.

	Six months ended June 30
		2004		2003
		($000’s)		($000’s)
9.625% Notes		7,531		4,852
Term facility		2,804		5,361
Kazgermunai debt		802		647
PKOP bonds		469		1,182
Short-term debt		426		366
12% Notes		-		8,718
Accretion expense		1,216		1,026
Term loans		250		-
Less portion capitalized		(13	)	-
Total		13,485		22,152

19

• Our 9.625% Notes interest expense increased in the first six months of 2004 by $2.7 million, as the Notes were issued in February 2003.

• Our term facility interest expense decreased by $1.9 million in the second quarter of 2004 and by $2.6 million in the first six months of 2004 due to the repayment of a portion of the principal.

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

• Accretion expense represents the increase in the present value of our asset retirement obligations due to the passage of time.

• Our 12% Notes interest expense in 2003 was $8.7 million including $6.6 million of issue costs that were expensed when we redeemed these notes on February 2, 2003.

DEPRECIATION AND DEPLETION

THREE MONTHS ENDED JUNE 30, 2004

	Depreciation and		Depreciation and
	Depletion ($000’s)		Depletion ($/bbl*)
Upstream		21,638		1.57
Downstream		5,046		0.65
Corporate		314
Total		26,998

* Downstream includes tollers’ volumes

THREE MONTHS ENDED JUNE 30, 2003

	Depreciation and		Depreciation and
	Depletion ($000’s)		Depletion ($/bbl*)
Upstream		14,174		1.07
Downstream		4,651		0.62
Corporate		32
Total		18,857

* Downstream includes tollers’ volumes

The increase in upstream depreciation and depletion expenses of $7.4 million is mainly due to the $165.9 million of capital additions since the second quarter of 2003.

SIX MONTHS ENDED JUNE 30, 2004

	Depreciation and		Depreciation and
	Depletion ($000’s)		Depletion ($/bbl*)
Upstream		37,791		1.41
Downstream		9,915		0.67
Corporate		625
Total		48,331

* Downstream includes tollers’ volumes

SIX MONTHS ENDED JUNE 30, 2003

	Depreciation and		Depreciation and
	Depletion ($000’s)		Depletion ($/bbl*)
Upstream		27,106		1.05
Downstream		9,321		0.59
Corporate		58
Total		36,485

* Downstream includes tollers’ volumes

20

The increase in Upstream depreciation and depletion expenses of $10.7 million is mainly due to the $165.9 million of capital additions since the second quarter of 2003.

INCOME TAXES

	Three months ended June 30
		2004	2003
		($000’s)	($000’s)
Upstream		44,988	15,357
Downstream		33,890	13,297
Corporate		1,114	(104	)
Total		79,992	28,550

	Six months ended June 30
		2004	2003
		($000’s)	($000’s)
Upstream		74,153	37,741
Downstream		47,382	24,868
Corporate		2,682	128
Total		124,217	62,737

Income taxes increased by $51.4 million in the second quarter of 2004 compared to the same quarter of 2003. $31.5 million of this increase is due to increases in sales volumes and in the price of crude oil and price of refined products, which led to an increase in income before income taxes of $105.1 million. We provided $6.8 million for excess profit tax in the second quarter of 2004. We also incurred additional $2.1 million of income tax in Kazgermunai, our joint venture, as the marginal tax rate exceeded the statutory rate of 30% per the sliding scale prescribed by the hydrocarbon contract and, therefore, the effective tax rate became 40% in the second quarter of 2004. The remaining increase of $11.0 million is due to various non-deductible expenses.

Income taxes increased by $61.5 million in the first six months of 2004 compared to the same period of 2003. $40.2 million of this increase is due to increase in income before income taxes of $134.1 million. We provided $9.8 million for excess profit tax in the first six months of 2004. We also incurred additional $1.5 million of income tax in Kazgermunai, because the marginal tax rate exceeded the statutory tax rate and, therefore, the effective tax rate became 36% for the first half of 2004. The remaining increase of $10.0 million is due to various non-deductible expenses.

Income taxes in our corporate segment are the withholding tax on the dividends paid from subsidiaries in Kazakhstan to Canada.

CAPITAL EXPENDITURES AND COMMITMENTS

The table below sets forth a breakdown of our capital expenditures.

	Three months ended June 30
		2004	2003
		($000’s)	($000’s)
Upstream
Development wells		9,940	9,497
Facilities and equipment		8,499	18,811
Exploration		6,049	4,545
Downstream
Refinery HS&E		1,350	113
Refinery sustaining		473	961
Refinery return projects		149	2,579
Marketing & other		469	5
Corporate		362	183
Total capital expenditures		27,291	36,694
Less accrued amounts		727	1,670
Total cash capital expenditures		28,018	38,364

21

	Six months ended June 30
		2004		2003
		($000’s)		($000’s)
Upstream
Development wells		16,330		13,418
Facilities and equipment		32,065		55,546
Exploration		11,691		8,461
Downstream
Refinery HS&E		1,892		340
Refinery sustaining		1,658		1,755
Refinery return projects		1,486		7,138
Marketing & other		650		16
Corporate		644		341
Total capital expenditures		66,416		87,015
Less accrued amounts		(3,362	)	(1,551	)
Total cash capital expenditures		63,054		85,464

LIQUIDITY

The levels of cash, current assets and current liabilities as at June 30, 2004 and December 31, 2003 are set out below.

	As at			As at
	June 30, 2004			December 31, 2003
	($000’s)			($000’s)
Cash		322,350			184,660
Cash flow (annualised)		512,466			399,931
Working capital*		103,726			151,737
Net debt**		(84,599	)		135,220
Ratio of cash flow to net debt***		(6.06	)		3.0
Ratio of cash flow to fixed charges****		19.0			10.6
Ratio of earnings to fixed charges*****		25.8			13.6

* Working capital is net of cash and short-term debt

** Net debt includes short-term and long-term debt less cash

*** Quarterly cash flow is annualized

**** Fixed charges include interest expense and preferred dividends before tax

***** Earnings is income before income taxes plus fixed charges

Our net working capital has decreased due to increases in our accounts payable. The main components are income and excess profit tax, accrued dividends payable and amounts owed for crude oil purchased from one of our joint ventures.

Our restricted cash is $47.0 million as at June 30, 2004 ($35.5 million at December 31, 2003). Restricted cash includes $10.5 million of cash dedicated to a debt service reserve account for the Corporation's Term Facility and $36.5 million of cash dedicated to a margin account for the Corporation’s hedging program. There was no change in the balance on our debt service reserve account since December 31, 2003. The balance related to the hedging program increased by $11.5 million since December 31, 2003 due to the change in the mark-to-market valuation of our hedging contracts.

Our long-term debt substantially decreased from $246.7 million at December 31, 2003 to $195.1 million at June 30, 2004. During the first half of 2004, we made $16.8 million of principal repayments and $16.2 million of mandatory repayments on our term facility. Kazgermunai repaid $24.3 million of its long-term debt.

We have entered into a $100.0 million committed credit facility, which is subject to certain conditions precedent and final syndication. This facility further strengthens our financial position.

22

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
		2004		2003			2004		2003
REVENUE
Crude oil		206,086		134,175			413,564		276,417
Refined products		189,116		119,459			300,008		222,414
Service fees		3,904		460			6,572		3,327
Interest income		797		507			1,240		1,366
		399,903		254,601			721,384		503,524
EXPENSES
Production		25,669		16,893			47,116		34,149
Royalties and taxes		25,543		17,617			45,924		29,420
Transportation		51,230		60,269			115,309		115,272
Refining		5,494		5,452			9,402		8,804
Crude oil and refined product purchases		32,409		16,046			65,965		25,416
Selling		9,206		7,358			17,663		12,829
General and administrative		15,664		10,556			28,907		23,533
Interest and financing costs		6,082		7,380			13,485		22,152
Depletion and depreciation		26,998		18,857			48,331		36,485
Foreign exchange gain		(1,111	)	(3,428	)		(5,795	)	(5,526	)
		197,184		157,000			386,307		302,534
INCOME BEFORE INCOME TAXES		202,719		97,601			335,077		200,990
INCOME TAXES (Note 9)
Current provision		89,643		27,080			135,002		63,252
Future income tax		(9,651	)	1,470			(10,785	)	(515	)
		79,992		28,550			124,217		62,737
NET INCOME BEFORE NON-CONTROLLING INTEREST		122,727		69,051			210,860		138,253
NON-CONTROLLING INTEREST		699		621			1,347		1,271
NET INCOME		122,028		68,430			209,513		136,982
RETAINED EARNINGS, BEGINNING OF PERIOD		466,295		140,903			378,819		73,151
Normal course issuer bid		-		(10,440	)		-		(11,232	)
Common share dividends		(17,706	)	-			(17,706	)	-
Preferred share dividends		(8	)	(8	)		(17	)	(16	)
RETAINED EARNINGS, END OF PERIOD		570,609		198,885			570,609		198,885
BASIC NET INCOME PER SHARE (Note 10)		1.54		0.88			2.64		1.74
DILUTED NET INCOME PER SHARE (Note 10)		1.51		0.84			2.60		1.68

See accompanying notes to the interim consolidated financial statements.

23

INTERIM CONSOLIDATED BALANCE SHEETS
(EXPRESSED IN THOUSANDS OF UNITED STATES DOLLARS)

Unaudited 

	As at		As at
	June 30,		December 31,
	2004		2003
ASSETS
CURRENT
Cash		322,350		184,660
Accounts receivable		169,330		150,293
Inventory		39,298		36,920
Prepaid expenses		37,282		44,901
Current portion of future income tax asset		23,252		14,697
		591,512		431,471
Deferred charges		6,619		6,729
Restricted cash (Note 5)		47,028		35,468
Future income tax asset		25,307		25,466
Property, plant and equipment		557,449		542,317
TOTAL ASSETS		1,227,915		1,041,451
LIABILITIES
CURRENT
Accounts payable and accrued liabilities		147,997		88,422
Short-term debt (Note 6)		42,654		73,225
Prepayments for crude oil and refined products		17,439		6,652
		208,090		168,299
Long-term debt (Note 7)		195,097		246,655
Asset retirement obligations (Note 2)		29,842		28,625
Future income tax liability		10,623		13,012
		443,652		456,591
Non-controlling interest		14,438		13,091
Preferred shares of subsidiary		80		80
COMMITMENTS AND CONTINGENCIES(Note 13)
SHAREHOLDERS’ EQUITY
Share capital (Note 8)		195,867		191,695
Contributed surplus		3,269		1,175
Retained earnings		570,609		378,819
		769,745		571,689
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		1,227,915		1,041,451

See accompanying notes to the interim consolidated financial statements.

APPROVED BY THE BOARD OF DIRECTORS.

(signed)	(signed)
BERNARD ISAUTIER	JACQUES LEFÈVRE
Director	Director

24

INTERIM CONSOLIDATED STATEMENTS OF CASH FLOW
(EXPRESSED IN THOUSANDS OF UNITED STATES DOLLARS)

Unaudited 

	Three months ended June 30					Six months ended June 30
		2004		2003			2004		2003
OPERATING ACTIVITIES
Net income		122,028		68,430			209,513		136,982
Items not affecting cash:
Depletion and depreciation		26,998		18,857			48,331		36,485
Amortization of deferred charges		396		359			783		3,052
Non-controlling interest		699		621			1,347		1,271
Other non-cash charges		1,082		1,283			7,044		2,618
Future income tax		(9,651	)	1,470			(10,785	)	(515	)
Cash flow		141,552		91,020			256,233		179,893
Changes in non-cash operating working capital items		63,774		(58,272	)		44,214		(42,368	)
Cash flow from operating activities		205,326		32,748			300,447		137,525
FINANCING ACTIVITIES
Short-term debt		-		(33,827	)		(24,494	)	16,675
Common share dividends		(8,829	)	-			(8,829	)	-
Purchase of common shares		-		(13,816	)		-		(14,847	)
Long-term debt		(42,392	)	34,698			(58,325	)	98,808
Deferred charges paid		(650	)	(1,150	)		(650	)	(3,601	)
Proceeds from issue of share capital, net of share issuance costs		596		20			4,172		470
Preferred share dividends		(8	)	(8	)		(17	)	(16	)
Cash flow (used in) from financing activities		(51,283	)	(14,083	)		(88,143	)	97,489
INVESTING ACTIVITIES
Restricted cash		(10,160	)	-			(11,560	)	-
Capital expenditures		(28,018	)	(38,364	)		(63,054	)	(85,464	)
Purchase of preferred shares of subsidiary		-		(2	)		-		(4	)
Cash flow used in investing activities		(38,178	)	(38,366	)		(74,614	)	(85,468	)
INCREASE / (DECREASE) IN CASH		115,865		(19,701	)		137,690		149,546
CASH, BEGINNING OF PERIOD		206,485		244,043			184,660		74,796
CASH, END OF PERIOD		322,350		224,342			322,350		224,342

See accompanying notes to the interim consolidated financial statements.

25

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS
(EXPRESSED IN THOUSANDS OF 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. Its main operating subsidiaries are PetroKazakhstan Kumkol Resources ("PKKR") and PetroKazakhstan Oil Products ("PKOP"). Certain information and disclosures normally required to be included in the notes to the annual financial statements have 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, 2003. The accounting principles applied are consistent with those as set out in the Corporation’s annual financial statements for the year ended De cember 31, 2003, except for the changes in accounting standards as described in Note 2.
	The presentation of certain amounts for previous periods has been changed to conform with the presentation adopted for the current period.
2	ACCOUNTING CHANGES
	Asset Retirement Obligations
	Effective January 1, 2004, the Corporation adopted the new recommendation of the Canadian Institute of Chartered Accountants (“CICA”) regarding asset retirement obligations. This new standard changes the method of estimating and accounting for future site restoration costs. Total estimated asset retirement obligations are discounted to estimate the fair value of the obligation and recorded as a liability when the related assets are constructed and commissioned. The fair value increases the value of property, plant and equipment and is depleted over the life of the asset. Accretion expense, resulting from the changes in the present value of the liability due to the passage of time is recorded as part of interest and financing costs.
	Estimated cash flows are discounted at 8.5%. The total undiscounted estimated cash flows required to settle the obligations is $73.0 million with the expenditures being incurred over ten years commencing in 2014.
	The new standard has been applied retroactively, and the financial statements of prior periods have been restated.
	Adoption of the new standard of accounting for asset retirement obligations resulted in the following changes in the consolidated balance sheet and statement of income and retained earnings.
	Changes in consolidated balance sheets:

Increase/(Decrease)	As at			As at
	June 30, 2004			December 31, 2003
Future income tax asset		510			651
Property, plant and equipment		14,819			15,181
Total assets		15,329			15,832
Asset retirement obligations		21,780			22,058
Retained earnings		(6,451	)		(6,226	)
Total liabilities and shareholders’ equity		15,329			15,832

26

Changes in consolidated statements of income and retained earnings for the three months ended June 30, 2004 and 2003:

Increase / (Decrease)	Three months			Three months
	ended June 30, 2004			ended June 30, 2003
Interest and financing costs		609			513
Depletion and depreciation		(571	)		(930	)
Income before income taxes		(38	)		417
Income taxes		72			198
Net income		(110	)		219
Basic net income per share		-			-
Diluted net income per share		-			-

Changes in consolidated statements of income and retained earnings for the six months ended June 30, 2004 and 2003:

Increase / (Decrease)	Six months			Six months
	ended June 30, 2004			ended June 30, 2003
Interest and financing costs		1,217			1,026
Depletion and depreciation		(1,133	)		(2,016	)
Income before income taxes		(84	)		990
Income taxes		141			443
Net income		(225	)		547
Basic net income per share		-			0.01
Diluted net income per share		-			0.01

The change in asset retirement obligations is as follows:

Asset retirement obligations liability as at January 1, 2003	22,831
Revisions	3,670
Accretion expense	2,124
Settlements	-
Asset retirement obligations liability as at January 1, 2004	28,625
Revisions	-
Accretion expense	1,217
Settlements	-
Asset retirement obligations as at March 31, 2004	29,842

Full Cost Accounting

In September 2003 the CICA issued Accounting Guideline 16 "Oil and Gas Accounting - Full Cost" ("AcG 16"), which replaced Accounting Guideline 5 "Full Cost Accounting in the Oil and Gas Industry" ("AcG 5"). The most significant change between AcG 16 and AcG 5 is that under AcG 16 the carrying value of oil and gas properties should not exceed their fair value. The fair value is equal to estimated future cash flows from proved and probable reserves using future price forecasts and costs discounted at a risk-free rate. This differs from the cost recovery ceiling test under AcG 5 that used undiscounted cash flows, and constant prices, less general and administrative, financing costs and taxes. The Corporation adopted AcG 16 effective January 1, 2004 and as at June 30, 2004 there were no indications of impairment.

Depletion of Property, Plant and Equipment

Effective January 1, 2004 PetroKazakhstan commenced using proved reserves to calculate depletion. Previously, the Corporation used proved developed reserves. The impact on the three and six month periods ended June 30, 2004 was a decrease in depletion expense of $0.5 million and $0.7 million, respectively.

Proved developed reserves were previously used to calculate depletion because this resulted in a more representative charge to earnings.

Impairment of Long-Lived Assets

Effective January 1, 2004, the Corporation adopted the new recommendation of the CICA issued in December 2002 on impairment of long-lived assets. This recommendation provides guidance on the recognition, measurement anddisclosure of impairment of long-lived assets. There is a requirement to recognize an impairment loss for a long-lived asset when its carrying amount exceeds the sum of the undiscounted cash flows expected from its use and eventual disposition. The impairment loss is measured as the amount by which carrying amount of the asset exceeds its fair value. As at June 30, 2004 there were no indications of impairment of long-lived assets.

27

	Hedge Accounting
	Effective January 1, 2004, the Corporation adopted Accounting Guideline 13 "Hedging Relationships" (AcG 13"). AcG 13 provides guidance regarding the identification, designation, documentation and effectiveness of hedging relationships for the purposes of applying hedge accounting. This guideline establishes certain conditions for when hedge accounting may be applied. The Corporation has applied hedge accounting for the financial instruments disclosed in Note 11.
3	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 and transportation of refined products and the management of the marketing and transportation 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, 2004
	Upstream			Downstream			Corporate		Eliminations			Consolidated
REVENUE
Crude oil		221,765			-			-		(15,679	)		206,086
Refined products		61,937			144,694			-		(17,515	)		189,116
Service fees		2,167			1,589			148		-			3,904
Interest income		211			190			396		-			797
		286,080			146,473			544		(33,194	)		399,903
EXPENSES
Production		25,669			-			-		-			25,669
Royalties and taxes		25,206			337			-		-			25,543
Transportation		51,230			-			-		-			51,230
Refining		-			5,494			-		-			5,494
Crude oil and refined product purchases		31,542			34,061			-		(33,194	)		32,409
Selling		4,109			5,097			-		-			9,206
General and administrative		7,917			3,467			4,280		-			15,664
Interest and financing costs		6,082			-			-		-			6,082
Depletion and depreciation		21,638			5,046			314		-			26,998
Foreign exchange loss (gain)		(55	)		(1,894	)		838		-			(1,111	)
		173,338			51,608			5,432		(33,194	)		197,184

INCOME (LOSS) BEFORE INCOME TAXES	112,742		94,865	(4,888	)	-	202,719
INCOME TAXES
Current Provision	58,562		29,967	1,114		-	89,643
Future income tax	(13,574	)	3,923	-		-	(9,651	)
	44,988		33,890	1,114		-	79,992
NON-CONTROLLING INTEREST	-		699	-		-	699
NET INCOME (LOSS)	67,754		60,276	(6,002	)	-	122,028

Eliminations are intersegment revenue.

	Three months ended June 30, 2004
		Export	Domestic	Consolidated
Crude oil		194,437	11,649	206,086
Refined products		62,403	126,713	189,116

	As at June 30, 2004
		Upstream	Downstream	Corporate	Consolidated
Total assets		831,552	181,124	215,239	1,227,915
Total liabilities		394,345	49,336	14,489	458,170
Capital expenditures in the quarter		24,488	2,441	362	27,291

28

	Three months ended June 30, 2003
		Upstream		Downstream		Corporate	Eliminations		Consolidated
REVENUE
Crude oil		169,134		-		-	(34,959	)	134,175
Refined products		13,866		113,002		-	(7,409	)	119,459
Service fees		198		245		17	-		460
Interest income		-		111		396	-		507
		183,198		113,358		413	(42,368	)	254,601
EXPENSES
Production		16,893		-		-	-		16,893
Royalties and taxes		16,918		699		-	-		17,617
Transportation		60,244		25		-	-		60,269
Refining		-		5,452		-	-		5,452
Crude oil and refined product purchases		8,808		49,606		-	(42,368	)	16,046
Selling		2,490		4,868		-	-		7,358
General and administrative		7,333		2,723		500	-		10,556
Interest and financing costs		6,640		695		45	-		7,380
Depletion and depreciation		14,174		4,651		32	-		18,857
Foreign exchange loss (gain)		(2,294	)	(1,484	)	350	-		(3,428	)
		131,206		67,235		927	(42,368	)	157,000

INCOME (LOSS) BEFORE INCOME TAXES	51,992	46,123	(514	)	-	97,601
INCOME TAXES
Current Provision	14,879	12,305	(104	)	-	27,080
Future income tax	478	992	-		-	1,470
	15,357	13,297	(104	)	-	28,550
NON-CONTROLLING INTEREST	-	621	-		-	621
NET INCOME (LOSS)	36,635	32,205	(410	)	-	68,430

Eliminations are intersegment revenue.

	Three months ended June 30, 2003
		Export	Domestic	Consolidated
Crude oil		134,175	-	134,175
Refined products		27,034	92,425	119,459

	As at June 30, 2003
		Upstream	Downstream	Corporate	Consolidated
Total assets		602,385	179,373	151,272	933,030
Total liabilities		469,454	55,018	6,993	531,465
Capital expenditures in the quarter		32,853	3,658	183	36,694

29

	Six months ended June 30, 2004
		Upstream		Downstream		Corporate	Eliminations		Consolidated
REVENUE
Crude oil		445,901		-		-	(32,337	)	413,564
Refined products		92,801		236,668		-	(29,461	)	300,008
Service fees		4,584		1,769		219	-		6,572
Interest income		343		224		673	-		1,240
		543,629		238,661		892	(61,798	)	721,384
EXPENSES
Production		47,116		-		-	-		47,116
Royalties and taxes		41,716		4,208		-	-		45,924
Transportation		115,309		-		-	-		115,309
Refining		-		9,402		-	-		9,402
Crude oil and refined product purchases		66,522		61,241		-	(61,798	)	65,965
Selling		8,234		9,429		-	-		17,663
General and administrative		15,260		6,831		6,816	-		28,907
Interest and financing costs		13,016		469		-	-		13,485
Depletion and depreciation		37,791		9,915		625	-		48,331
Foreign exchange loss (gain)		(1,364	)	(5,723	)	1,292	-		(5,795	)
		343,600		95,772		8,733	(61,798	)	386,307

INCOME (LOSS) BEFORE INCOME TAXES	200,029		142,889	(7,841	)	-	335,077
INCOME TAXES
Current Provision	85,722		46,598	2,682		-	135,002
Future income tax	(11,569	)	784	-		-	(10,785	)
	74,153		47,382	2,682		-	124,217
NON-CONTROLLING INTEREST	-		1,347	-		-	1,347
NET INCOME (LOSS)	125,876		94,160	(10,523	)	-	209,513

Eliminations are intersegment revenue.

	Six months ended June 30, 2004
		Export	Domestic	Consolidated
Crude oil		384,771	28,793	413,564
Refined products		94,795	205,213	300,008

	As at June 30, 2004
		Upstream	Downstream	Corporate	Consolidated
Total assets		831,552	181,124	215,239	1,227,915
Total liabilities		394,345	49,336	14,489	458,170
Capital expenditures in the half year		60,086	5,686	644	66,416

30

	Six months ended June 30, 2003
		Upstream		Downstream		Corporate	Eliminations		Consolidated
REVENUE
Crude oil		345,593		-		-	(69,176	)	276,417
Refined products		14,536		216,691		-	(8,813	)	222,414
Service fees		2,210		1,092		25	-		3,327
Interest income		509		153		704	-		1,366
		362,848		217,936		729	(77,989	)	503,524
EXPENSES
Production		34,149		-		-	-		34,149
Royalties and taxes		26,333		3,087		-	-		29,420
Transportation		115,272		-		-	-		115,272
Refining		-		8,804		-	-		8,804
Crude oil and refined product purchases		10,912		92,493		-	(77,989	)	25,416
Selling		4,507		8,322		-	-		12,829
General and administrative		15,121		6,889		1,523	-		23,533
Interest and financing costs		12,207		1,182		8,763	-		22,152
Depletion and depreciation		27,106		9,321		58	-		36,485
Foreign exchange loss (gain)		(3,668	)	(2,450	)	592	-		(5,526	)
		241,939		127,648		10,936	(77,989	)	302,534

INCOME (LOSS) BEFORE INCOME TAXES	120,909		90,288	(10,207	)	-	200,990
INCOME TAXES
Current Provision	39,048		24,076	128		-	63,252
Future income tax	(1,307	)	792	-		-	(515	)
	37,741		24,868	128		-	62,737
NON-CONTROLLING INTEREST	-		1,271	-		-	1,271
NET INCOME (LOSS)	83,168		64,149	(10,335	)	-	136,982

Revenue eliminations are intersegment revenue.

	Six months ended June 30, 2003
		Export	Domestic	Consolidated
Crude oil		276,417	-	276,417
Refined products		48,903	173,511	222,414

	As at June 30, 2003
		Upstream	Downstream	Corporate	Consolidated
Total assets		602,385	179,373	151,272	933,030
Total liabilities		469,454	55,018	6,993	531,465
Capital expenditures in the half year		77,425	9,249	341	87,015

31

4	JOINT VENTURES
	The Corporation has the following interests in two joint ventures:
	a)	a 50% equity shareholding with equivalent voting power in Turgai Petroleum CJSC (“Turgai”), which operates the northern part of the Kumkol field in Kazakhstan.
	b)	a 50% equity shareholding with equivalent voting power in LLP Kazgermunai (“Kazgermunai”), which operates three oil fields in Kazakhstan: Akshabulak, Nurali and Aksai.
	The 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, 2004
		Turgai		Kazgermunai		Total
Cash		28,140		24,204		52,344
Current assets, excluding cash		58,609		40,169		98,778
Property, plant and equipment, net		79,769		64,437		144,206
Current liabilities		76,536		19,899		96,435
Long-term debt		-		14,480		14,480
Revenue		64,873		49,019		113,892
Expenses		37,315		31,673		68,988
Net income		27,558		17,346		44,904
Cash flow from operating activities		11,046		22,824		33,870
Cash flow used in financing activities		-		(24,266	)	(24,266	)
Cash flow used in investing activities		(1,585	)	(2,363	)	(3,948	)
Revenue for the three months ended June 30, 2004 includes $12.0 million of crude oil sales made by Turgai and $2 million of crude oil sales made by Kazgermunai to Downstream. These amounts were eliminated on consolidation.

	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		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		16,469		16,052		32,521
Net income		13,025		4,601		17,626
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.

32

	Six months ended June 30, 2004
		Turgai		Kazgermunai		Total
Revenue		124,508		87,554		212,062
Expenses		78,594		54,602		133,196
Net income		45,914		32,952		78,866
Cash flow from operating activities		22,306		42,604		64,910
Cash flow used in financing activities		-		(24,266	)	(24,266	)
Cash flow used in investing activities		(2,534	)	(4,566	)	(7,100	)

Revenue for the six months ended June 30, 2004 includes $22.3 million of crude oil sales made by Turgai and $2.0 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
Revenue		59,710		42,787		102,497
Expenses		39,028		28,741		67,769
Net income		20,682		14,046		34,728
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.
5	RESTRICTED CASH
	Restricted cash includes $10.5 million of cash dedicated to a debt service reserve account for the Corporation's Term Facility ($10.5 as at December 31, 2003). This cash is not available for general corporate purposes until the Term Facility is repaid in full.
	Restricted cash as at June 30, 2004 includes $36.5 million of cash dedicated to a margin account for the Corporation’s hedging program ($25.0 million as at December 31, 2003).
6	SHORT-TERM DEBT

	June 30, 2004	December 31, 2003
Current portion of term facility	29,615	35,692
Current portion of term loans	2,039	2,039
Joint venture loan payable	11,000	11,000
PKOP bonds	-	24,494
	42,654	73,225

	The PKOP bonds were fully redeemed on February 26, 2004.
7	LONG-TERM DEBT

	June 30, 2004		December 31, 2003
Current portion of term facility		125,000		125,000
Current portion of term loans		44,422		71,384
Joint venture loan payable		11,195		12,528
PKOP bonds		14,480		37,743
	195,097		246,655

On June 24, 2004 Kazgermunai repaid $24.3 million of its outstanding subordinated debt.

33

	On May 25, 2004 the Corporation entered into a five and one half year $100.0 million committed credit facility. This facility is unsecured, bears interest at Libor plus 2.65% and is subject to annual review. Certain conditions precedent and final syndication remain to be completed as at June 30, 2004.
	Included in deferred charges as at June 30, 2004 is $0.7 million of issue costs relating to the facility, which will be amortized over the term of the facility.
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, 2004			June 30, 2003
		Number	Amount		Number		Amount
Balance, beginning of period		79,865,009	195,271		79,028,539		193,933
Shares repurchased and cancelled pursuant to normal course issuer bid		-	-		(1,379,300	)	(3,376	)
Stock options exercised for cash		732,157	596		3,900		20
Balance, end of period		80,597,166	195,867		77,653,139		190,577

	Six months ended			Six months ended
	June 30, 2004			June 30, 2003
		Number	Amount		Number		Amount
Balance, beginning of period		77,920,226	191,695		78,956,875		193,723
Shares repurchased and cancelled pursuant to normal course issuer bid		-	-		(1,477,400	)	(3,616	)
Stock options exercised for cash		2,648,382	4,163		170,400		467
Corresponding convertible securities, converted		28,558	9		3,264		3
Balance, end of period		80,597,166	195,867		77,653,139		190,577

A summary of the status of the Corporation's stock option plan as of June 30, 2004 and the changes during the six months ended June 30, 2004 and the year ended December 31, 2003 are presented below (weighted average exercise price expressed in Canadian dollars):

 

			Weighted Average
	Options		Exercise Price
Outstanding at December 31, 2002	4,850,136		5.01
Granted	791,000		25.82
Exercised	(440,751	)	3.76
Forfeited	(84,925	)	9.27
Outstanding at December 31, 2003	5,115,460		8.17
Granted	60,000		31.62
Exercised	(2,676,940	)	2.05
Forfeited	(111,525	)	14.85
Outstanding at June 30, 2004	2,386,995		15.31
Options excercisable at:
December 31, 2003	2,816,683		5.14
June 30, 2004	981,342		12.05

The pro forma net income per share for the three and six months ended June 30, 2003 and 2004, had we recognized compensation expense using the fair value of common stock options granted for all stock options outstanding prior to January 1, 2003 follows:

34

	Three months ended			Six months ended
	June 30			June 30
		2004	2003	2004	2003
Net Income
As reported		122,028	68,430	209,513	136,982
Pro forma		121,915	68,221	209,389	136,743
Basic Net Income
As reported		1.54	0.88	2.64	1.74
Pro forma		1.54	0.88	2.64	1.74
Diluted Net Income per share
As reported		1.51	0.84	2.60	1.68
Pro forma		1.51	0.84	2.60	1.68

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
		2004		2003			2004		2003
Statutory Kazakhstan income tax rate		30	%	30	%		30	%	30	%
Expected tax expense		60,816		29,280			100,523		60,297
Effect of higher tax rate in Kazgermunai		2,138		-			1,465		-
Excess profit tax provision		6,833		-			9,833		-
Other permanent differences, net		10,205		(730	)		12,396		2,440
Income tax expense		79,992		28,550			124,217		62,737

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
		2004	2003		2004	2003
Weighted average number of common shares outstanding		79,442,775	78,000,877		79,257,431	78,538,671
Dilution from exercisable options (including convertible securities)		1,278,756	3,173,080		1,227,461	3,138,160
Diluted number of shares outstanding		80,721,531	81,173,957		80,484,892	81,676,831

	No options were excluded from the calculation of diluted number of shares outstanding for the three months endedJune 30, 2004 and 2003, as the market price was in excess of exercise price.
11	FINANCIAL INSTRUMENTS
	The Corporation’s financial instruments include cash, accounts receivable, all current liabilities and long-term debt. The fair value of cash, accounts receivable and current liabilities approximates their carrying amounts due to the short-term maturity of these instruments. The fair value of the Term facility, Kazgermunai debt and the term loans approximates their carrying value as they bear interest at market rates. The fair value of the 9.625% Notes is $130.1 million versus the carrying value of $125.0 million as at June 30, 2004 as determined through reference to the market price.

35

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 major financial institutions.

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

	During the three months ended June 30, 2004, the Corporation has foregone revenue of $6.7 million through these contracts ($12.0 million during the six months ended June 30, 2004).
	The unrealized loss under these hedges as at June 30, 2004 is $31.1 million.
12	CASH FLOW INFORMATION
	Interest and income taxes paid:

	Three months ended			Six months ended
	June 30			June 30
		2004	2003		2004	2003
Interest paid		2,205	7,363		10,702	16,832
Income taxes paid		61,701	36,050		104,114	61,468

13	COMMITMENTS AND CONTINGENCIES
	Substantial Issuer Bid
	The Corporation announced a substantial issuer bid for its class A common shares conducted in the form of a modified “Dutch Auction”.
	The bid expired on July 19, 2004, and the Corporation purchased 3,999,975 of common shares at the final purchase price of C$40.00 per share.
	If we had excluded these shares from the common and diluted weighted average number of shares in the periods ended June 30, 2004, the pro forma net income per share would be as follows:

	Three months ended	Six months ended
	June 30, 2004	June 30, 2004
Net income
As reported	122,028	209,513
Basic net income per share
As reported	1.54	2.64
Pro forma	1.62	2.78
Diluted net income per share
As reported	1.51	2.60
Pro forma	1.59	2.74

36

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

PKOP

The ARNM alleged that PKOP charged prices for refined oil products that in total were $6.3 million in excess of ARNM authorized maximum prices. The Corporation has always taken the position that the ARNM does not have the right to establish prices for PKOP under the terms of the Privatization Agreement relating to the Shymkent refinery, which operates in a highly competitive environment. PKOP initiated legal proceedings to annul the ARNM claim and the court of first instance reduced the ARNM claim to approximately $1.1 million. PKOP and the ARNM appealed this decision to the Supreme Court. The Supreme Court recognized approximately $3.6 million of the ARNM’s original assessment. This amount has been paid and provided for in the financial statements.

PKOP received an additional assessment from ARNM in the amount of $8.8 million for allegedly charging prices for refined products in excess of ARNM authorized maximum prices. PKOP has appealed this assessment and a preliminary hearing has been held. The court hearing is expected to take place during the third quarter. No provision has been made in the accompanying financial statements for this assessment.

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

Group companies

The ARNM claimed $31.0 million from a group company for allegedly violating Kazakhstan’s competition law. The Corporation initiated legal proceedings and the court of first instance dismissed the ARNM claim. The ARNM appealed this decision, the appellate court upheld the decision of the lower court.

The ARNM claimed approximately $91.4 million from group companies for allegedly violating Kazakhstan’s competition law. The group companies initiated legal action, and at the Astana City Court they were unsuccessful in their challenge of allegations by the ARNM that these companies had violated Kazakhstan competition laws. The judgment upheld the ARNM determination that these distributors had received unjustified revenues totaling approximately $91.4 million. The Corporation appealed this judgment to the Supreme Court. The Supreme Court hearing for the ARNM claim of $91.4 million was held in April 2004 and the Court suspended the case and instructed the parties to seek an agreed settlement. During the period from April to May 13, the parties did engage in discussions aimed at a settlement, but were unable to resolve the matter through negotiations. On M ay 13, 2004 the Supreme Court overturned the lower court decision in favour of the ARNM and sent the case back to the Astana City Court for a new trial. The Prosecutor General (which participates in all civil cases in Kazakhstan and which supported the views of the ARNM at the Supreme Court hearing) has appealed this decision to Supervisory Panel of the Supreme Court. The date to hear this appeal has not been set.

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

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

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

Tax Matters

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

37

	In response to the Corporation’s submission, the Minister of Finance initiated the creation of a high-level Working Group between its Officials and the Corporation’s representatives to address and seek resolution of all outstanding tax issues through dialogue and negotiations. On January 22, 2004, the Working Group signed a memorandum that sets out the agreed resolution of all outstanding tax issues. Certain actions, such as amendments to hydrocarbon contracts and issuance of instruction letters must be taken to fully implement the terms of the memorandum. The terms of this memorandum are reflected in the ensuing discussion of the Corporation’s tax matters.
	PKKR received tax assessments for 1998 and 1999. The assessment 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 agreement of the Supervisory Panel of the Supreme Court to hear its appeal on the assessed taxes. The Corporation provided for $2.9 million of the $10.5 million total assessment in the December 31, 2002 consolidated financial statements. PKKR has been disputing the remaining $7.6 million of the $10.5 million, which relates to fines and penalties assessed, because PKKR believes there was an incorrect application of the provisions of the tax act. PKKR has paid this amount to stop the further accumulation of fines and penalties and has recorded this payment as an account receivable pending resolution of this issue. The Working Gr oup agreed with PKKR’s position and determined that there was an incorrect application of the provisions of the tax legislation. This matter was simultaneously appealed to the Supervisory Panel of the Supreme Court due to time limitations and the Supreme Court remanded the case back to the lower court for a retrial. The lower court rejected the Supreme Court’s instruction, a retrial was not held, and they let the original decision stand. The Corporation will appeal this decision to the Supreme Court. The account receivable of $7.6 million will either be recovered or expensed upon final resolution of this issue.
	PKKR also received assessments for 2000 and 2001. The 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 $6.8 million of the $13.0 million and was unsuccessful on the remainder. The major issue on which PKKR was unsuccessful was the assessment of royalties on flared associated gas (approximately $4.5 million). The Corporation believes the claim for royalties on flared associated gas, which has no commercial value, contravenes the provisions of its Hydrocarbon Contracts. PKKR appealed to the Supreme Court and was unsuccessful. The Corporation will appeal to the Supervisory Panel of the Supreme Court. The Corporation will also file an appeal regarding the method used to determine the value of gas for royalty purposes. The method used was not provided to the Corporation. The Working Group determined that PKKR would pay royalties on produ ced gas volumes less gas volumes reinjected and gas consumed in operations as fuel gas. A flat 5% royalty rate is to be applied and the valuation will be based upon sales value for those volumes sold and lifting costs for the remaining volumes. PKKR has provided $0.4 million for royalties on associated gas for the years 1998-2001 and $0.2 million for 2002 and 2003. PKKR has also provided $1.8 million for the years 2000 and 2001 and made a further provision of $1.7 million for 2002 and 2003 for the remaining issues.
	There has been no change in the status of the second case from December 31, 2003.
	Certain subsidiaries of the Corporation received assessments totaling $2.9 million including fines and penalties claiming incorrect application of the Canadian-Kazakhstan double tax treaty. The allegation is that the proper documentation was not in place to support withholding tax relief on the payment of dividends. The Ministry of Finance has asserted that the Certificates of Residency as legalized by the Government of Canada are not valid. The Corporation disputes this assertion. The Corporation has confirmation from the Kazakhstan Ministry of Foreign Affairs that the legalization process followed in Canada is in fact valid. The subsidiaries have filed court cases disputing these assessments. The court of first instance ruled in favour of the Ministry of Finance. The Corporation has appealed this assessment. No provision has been made in the financial statements for these assessments, as the Corporation believes it will ultimately prevail in its posi tion.
14	SUBSEQUENT EVENTS
	The Corporation received an approval from government authorities to amend certain of its hydrocarbon contracts. These amendments clarify a number of provisions related to taxes, which were previously subject to interpretation, particularly the issue of royalties on gas, value added tax and cost allocations between licenses. These amendments are effective from July 21, 2004.

38