Management’s discussion and analysis
| | | | | |
| Production | | Reserves | | Cash flow |
| |
 | |  | |  |
The following Management’s Discussion and Analysis of the financial condition and results of our operations should be read in conjunction with the consolidated financial statements of the Corporation and notes relating thereto that are included elsewhere in this report. Our financial statements have been prepared in accordance with Canadian GAAP. Canadian GAAP differs in certain significant respects from U.S. GAAP. For a discussion of the most significant differences between Canadian GAAP and U.S. GAAP please refer to Note 24 in our consolidated financial statements. This discussion and analysis contains forward-looking statements, which involve risks and uncertainties. Our actual results could differ materially from those anticipated in the forward-looking statements.
In our Management’s Discussion and Analysis we use certain terms, which are specific to the oil and gas industry, including “netback” and “cash flow”. These are non-GAAP terms and are defined within our document. Cash flow is defined as cash generated from operating activities before changes in non-cash working capital.
Except as otherwise required by the context, reference in this Management’s Discussion and Analysis to “our”, “we” or “us” refer to the combined business of Hurricane Hydrocarbons Ltd. and all of its subsidiaries and joint ventures.
All numbers are in U.S. Dollars unless otherwise indicated.
OVERVIEW
We are an integrated oil company that owns and operates oil and gas production and a refinery in Kazakhstan. We use the term “Upstream” to refer to the exploration for and production of oil and gas from our licenses in the South Turgai basin, Kazakhstan. We use the term “Downstream” to refer to the operations of our refinery located in Shymkent, Kazakhstan and the marketing of refined products and the management of the marketing of crude oil for Upstream.
We acquired the Shymkent refinery, through our acquisition of HOP (then known as ShNOS), in March 2000, and assumed a greater role in the management of the Kazgermunai joint venture at the end of November 2000. Accordingly, our 2002 and 2001 results reflect the inclusion of the Shymkent refinery and Kazgermunai for a full year, as compared to nine months (in the case of the Shymkent refinery) and one month (in the case of Kazgermunai) in 2000.
We have achieved record average production levels of 135,842 barrels of oil per day (“bopd”) for the year and near record financial results. The year 2002 saw a significant increase in non-Free Carrier (“non-FCA”) sales as compared to 2001. At the end of 2002 approximately 1.6 million barrels of non-FCA sales were incomplete and hence, included in inventory. The effect of this was to cause an estimated $13.0 million of net income to be deferred into 2003.
26
We achieved record production of 135,842 bopd for the year and near record financial results.
Production
We derive our revenues principally from the sale of crude oil and refined products and to a lesser extent from refining crude oil on behalf of third parties, for which we receive processing fees, and production and ancillary support facilities provided to our joint venture Turgai Petroleum on a fee basis. Our results are dependent on the levels of our oil production and on prevailing prices for such production. Prices for oil are subject to large fluctuations in response to a variety of factors beyond our control.
During the year ended December 31, 2002, our production volumes totalled 49.6 million barrels or an average of 135,842 bopd, representing a 35% increase over production volumes of 100,877 bopd or 36.8 million barrels for the year ended December 31, 2001. Record export sales combined with enhanced performance from all fields led to these increases. Our production volumes increased by 20% in 2001 over 2000 production volumes of 30.69 million barrels or 84,090 bopd.
| | | | | | | | | | | | | |
| (bopd) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Field Kumkol South | | | 66,726 | | | | 59,585 | | | | 57,571 | |
| Kumkol North | | | 22,810 | | | | 15,876 | | | | 13,697 | |
| South Kumkol | | | 22,728 | | | | 12,968 | | | | 12,476 | |
| Kyzylkiya | | | 6,941 | | | | 2,973 | | | | 343 | |
| Aryskum | | | 4,330 | | | | 58 | | | | 3 | |
| Maibulak | | | 824 | | | | 750 | | | | — | |
| East Kumkol | | | 634 | | | | — | | | | — | |
| Kazgermunai Fields | | | 10,849 | | | | 8,667 | | | | — | |
| | | |
| | | |
| | | |
| |
| Total | | | 135,842 | | | | 100,877 | | | | 84,090 | |
| | | |
| | | |
| | | |
| |
In 2002, production increases were recorded in all fields. Major contributions came from the optimization of individual well rates in South Kumkol and Kumkol South by the installation of artificial lift and pump optimization, the continued development drilling in Kumkol North and the enhanced performance of the South Kumkol field. Two new Kumkol South free water knockout facilities, commissioned in early October, relieve water handling issues at the CPF, thereby increasing processing capacity. We currently have eight service rigs in operation throughout the producing fields that are contributing to the enhancement of daily production. These rigs are conducting artificial lift pump replacements and installations, as well as zonal isolation, recompletions and workovers.
27
The program of further development and production enhancement of the Akshabulak field, operated by Kazgermunai, required the installation of a new process facility in 2002. The purchase order for this new facility is being delayed by our joint venture partners, pending assurances from the government of Kazakhstan on marketing and transportation issues.
Overall, we participated in the drilling of 72 new wells during 2002, including wells drilled by our joint ventures.
Sales
During 2002, 49% of crude oil export sales were Free Carrier (“FCA”) sales to third parties within Kazakhstan, normally at the rail terminal at Tekesu, adjacent to the Shymkent refinery. The price achieved for these export sales is shown net of a differential to the prevailing Brent price at the time of the sale. The differential reflects a number of factors, the most significant of which relates to rail transportation costs. Title to the crude oil passes to the buyer at the point of loading the crude into rail cars. In the tables included in our Management’s Discussion and Analysis, these sales are shown as “Crude sales sold FCA”.
In addition, beginning in 2001 we made our first direct sale from a Black Sea port (Batumi) on FOB (“Free On Board”) terms. Under these types of sales, we arrange all transportation to the port and assume the obligations for this transportation. The sale price reflects the Brent price plus or minus a differential to the Black Sea port at the time of sale. With this type of sale, title to the crude does not pass to the buyer until the crude is loaded into an oil tanker in the respective Black Sea port. Sales contracts are also being concluded on Delivered At Frontier (“DAF”) terms, where title to the crude oil passes to the buyer at the border, Cost, Insurance and Freight (“CIF”) and Carriage Paid To (“CPT”) terms, where title to the crude oil passes at the final destination. In the tables following, these sales are shown as “Crude sales sold non-FCA”.
Revenue is recognized at the time title passes. In the case of FCA sales, we record revenue based on a provisional Brent price at the time of delivery at Tekesu, then mark to market at month end to reflect increases or decreases in prevailing Brent prices, and adjust the final price if necessary, upon delivery to the final destination by reference to the bill of lading date and the contract terms.
During the year ended December 31, 2002, 39% of crude oil export sales represented “Crude sales sold non-FCA”, including exports made CIF to Italian refineries, FOB Batumi, FOB Odessa via Atyrau-Samara, CPT Novorossiisk and DAF China and Ukraine, albeit the Chinese volumes were relatively small. The remaining 12% of sales were export sales made by our joint venture Kazgermunai.
The FCA differential or, in the case of non-FCA sales, the cost of transportation, represents our largest operating cost. As we continue to increase non-FCA sales in 2003, we anticipate that crude oil revenue and transportation costs will increase significantly, even in the event that prices and volumes remain consistent with prior periods. The move to non-FCA sales is also expected to have a detrimental effect on our working capital position both through the need to prepay transportation costs and the fact that oil is held in inventory for longer periods of time. We are increasing our use of non-FCA sales as we are able to contract directly for transportation related services, thereby increasing our understanding and control of our transportation expenses, ultimately leading to improved netbacks (revenues less transportation expenses).
Refinery operations and capacity
Feedstock is refined into a number of products, which are generally sold domestically. The refinery also refines crude oil on behalf of third parties for a processing fee. The refinery at Shymkent has a total operating capacity of 6.6 million tonnes per year or about 51.1 million barrels per year. Crude oil feedstock for our refinery is primarily acquired from our Upstream operations, but purchases are also made from third parties.
28
For the year ended December 31, 2002, the Shymkent refinery processed a total of 27.1 million barrels or 74,150 bopd compared to 26.3 million barrels or 72,107 bopd in 2001. Included in this production is 1.3 million barrels refined for third parties in 2002 and 5.4 million barrels in 2001. During the nine months ended December 31, 2000, the Shymkent refinery processed 17.2 million barrels of 62,407 bopd, of which 5.5 million barrels were refined for third parties.
The refinery continues to focus on the improvement of yields while minimizing the production of lower-end and lower-value products. The production of mazut, a lower-end and lower-value product, has been reduced year over year. Mazut yield in 2002 averaged 35.9% versus 40.4% in 2001. At the end of 2002 mazut yield was 35.7% versus 42.9% at the end of 2001. The improvement is attributed to capital improvement projects and process changes including the overhaul of the main tower K-102 internals that resulted in less fractionation overlap. The refinery also increased the mazut throughput of the visbreaker unit in 2002, reducing its pour point to produce additional amounts of light, higher value products.
Royalties
Royalties are levied at differing rates for each of our oil fields. The table below sets out the parameters for each field. Royalty rates remain the same throughout the term of the license.
Royalties are collected quarterly with the exception of Kumkol North, where royalties are collected monthly, and can either be paid in cash or in kind. The choice of collection method rests with the Government of Kazakhstan and can vary from quarter to quarter. Where royalties are paid in cash the crude oil to which the relevant royalty percentage is applied is valued at the wellhead. Where royalties are taken in kind, the Government pays all related costs of transporting the crude from our CPF.
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Annual Production | | Effective Average Royalty Rate |
| | | | | | | at which Maximum | |
|
| Field | | Range | | Royalty Rate is Charged | | 2002 | | 2001 | | 2000 |
| |
| |
| |
| |
| |
|
| Kumkol South | | | 3.0 — 15.0 | % | | 11.62 mmbbls | | | 10.9 | % | | | 10.4 | % | | | 10.2 | % |
| Kumkol North | | | 9.0 | % | | Flat | | | 9.0 | % | | | 9.0 | % | | | 9.0 | % |
| South Kumkol | | | 10.0 | % | | Flat | | | 10.0 | % | | | 10.0 | % | | | 10.0 | % |
| Kyzylkiya | | | 1.5 — 2.5 | % | | 24.8 mmbbls* | | | 1.5 | % | | | 1.5 | % | | | 1.5 | % |
| Aryskum | | | 1.5 — 2.5 | % | | 52.7 mmbbls* | | | 1.5 | % | | | 1.5 | % | | | — | |
| Maibulak | | | 3.0 — 6.0 | % | | 3.9 mmbbls | | | 3.0 | % | | | 3.0 | % | | | — | |
| Kazgermunai Fields | | | 3.0 — 15.0 | % | | 11.62 mmbbls | | | 4.5 | % | | | 4.2 | % | | | — | |
| * | | Royalty rate is based upon cumulative life of field production. |
Taxation
We are subject to a number of taxes in Kazakhstan including, but not limited to, income tax, excess profits tax, excise tax, land tax, property tax, transportation tax and mandatory contributions to social funds. Income is taxed at the Kazakhstani statutory rate of 30%. Excess profits tax has been negotiated with the Kazakhstani government in each hydrocarbon contract with the exception of the Kazgermunai licenses. With respect to the Kumkol South, South Kumkol and KAM fields, we are subject to excess profit tax at rates that vary from 0% to 30% based on the cumulative internal rate of return. With respect to Kumkol North, we are subject to excess profit tax at rates that vary from 0% to 50% based on the cumulative internal rate of return. We have not incurred any excess profit tax with respect to production from any of our fields. In 2003, the determination of excess profit taxes will be dependent upon crude oil prices and the level of capital expenditures.
Our Upstream operations are subject to excise tax on our domestic sales in Kazakhstan, for crude oil from the South Kumkol field, at a rate of 7.00 euros/tonne and the Maibulak field at a rate of 2.00 euros/tonne. Sales of gasoline are subject to excise tax at a rate of $29.00/tonne and diesel at a rate of $3.50 /tonne.
29
Within the hydrocarbon contracts for our production licenses are tax stability clauses that establish the tax regimes under which we operate. These are fixed as of the date of signing the agreement and remain in effect for the term of the agreement.
The foundation agreement for Kazgermunai provides for a tax on the profits of Kazgermunai with respect to its operations in the Akshabulak, Nurali and Aksai fields. The foundation agreement provides for taxes of: (i) 25% on annual profits up to $20.0 million, (ii) 30% on annual profits between $20.0 million and $30.0 million, (iii) 35% on annual profits between $30.0 million and $40.0 million and (iv) 40% on annual profits exceeding $40.0 million.
Kazakhstani income taxes are payable based upon financial statements prepared in accordance with Kazakhstani laws. The majority of the differences are temporary differences where an expense or revenue item is recorded for Canadian GAAP purposes in a different period than allowed under Kazakhstani law. The statutory income tax rate in Kazakhstan is 30%.
Adoption of certain accounting standards
Effective January 1, 2000, we adopted the new recommendations of the Canadian Institute of Chartered Accountants (“CICA”) with respect to future income taxes. Under this recommendation, future income tax assets and liabilities are computed based upon temporary differences between the accounting and taxation basis of assets and liabilities. On January 1, 2000, we recorded a future income tax asset of $19.1 million on the basis that realization of such asset is more likely than not. The restatement was applied retroactively without restatement of prior year figures. This increased retained earnings at January 1, 2000 by $19.1 million.
Effective January 1, 2001 we adopted the new recommendation of the CICA with respect to net income per share. The comparative diluted net income per share amounts for the year ended December 31, 2000 have been restated, to give effect to the new recommendation (Note 2 of the Consolidated Financial Statements).
We adopted the recommendations of the CICA regarding stock-based compensation. We elected to use the intrinsic value method in accounting for stock options and to disclose the pro forma results of using the fair value method (Note 16 of the Consolidated Financial Statements).
RESULTS OF OPERATIONS
For the year ended December 31, 2002 we generated $162.6 million of net income and $216.8 million of cash flow. This represents basic net income per share of $2.01 and basic cash flow per share of $2.68 for the year. The comparable figures for 2001 were net income of $169.3 million or $2.12 basic net income per share and $200.3 million of cash flow with basic cash flow per share of $2.51.
2002 saw a significant increase in non-FCA sales as compared to 2001. At the end of 2002 approximately 1.6 million barrels of non-FCA sales were incomplete and hence, included in inventory. The effect of this was to cause an estimated $13.0 million of net income to be deferred into 2003.
Revenue, production and sales
Total revenue was $814.7 million for the year ended December 31, 2002, which represented an increase of $211.6 million over total revenue of $603.1 million for the year ended December 31, 2001. Our increase in total revenue is due to a $228.1 million increase in crude oil revenue offset by a $7.0 million decrease in refined products revenue and a decrease in processing fees and interest and other income. Our crude oil revenue increased because of our increased production, higher crude oil export prices and due to our increasing use of non-FCA sales.
30
Upstream
Upstream production averaged 135,842 bopd for 2002, 100,877 bopd for 2001 and 84,090 bopd for 2000. The tables below set out total production and sales from our Upstream operations.
The following table sets out total production figures from Upstream operations for the years ended December 31.
| | | | | | | | | | | | | |
| (mmbbls) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Opening inventory of crude oil | | | 0.70 | | | | 0.39 | | | | 0.04 | |
| Production | | | 49.58 | | | | 36.82 | | | | 30.69 | |
| Crude oil purchased from third parties | | | 0.68 | | | | — | | | | 0.08 | |
| Crude oil purchased from joint ventures (50%) | | | 2.92 | | | | — | | | | — | |
| Sales or transfers | | | (51.08 | ) | | | (36.47 | ) | | | (30.38 | ) |
| Pipeline losses | | | (0.08 | ) | | | (0.04 | ) | | | (0.04 | ) |
| | | |
| | | |
| | | |
| |
| Closing inventory of crude oil | | | 2.72 | | | | 0.70 | | | | 0.39 | |
| | | |
| | | |
| | | |
| |
The following table sets out total crude oil sales volumes from Upstream operations for the years ended December 31.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2002 | | 2001 | | 2000 |
| | |
| |
| |
|
| | | mmbbls | | % | | mmbbls | | % | | mmbbls | | % |
| | |
| |
| |
| |
| |
| |
|
| Crude oil exports | | | 25.89 | | | | 50.7 | | | | 18.15 | | | | 49.8 | | | | 1.08 | | | | 3.6 | |
| Crude oil transferred to downstream | | | 16.82 | | | | 32.9 | | | | 10.83 | | | | 29.7 | | | | 6.83 | | | | 22.5 | |
| Crude oil transferred to downstream and exported | | | — | | | | — | | | | 0.15 | | | | 0.4 | | | | 9.58 | | | | 31.5 | |
| Crude oil transferred to downstream by joint ventures (50%) | | | 4.39 | | | | 8.6 | | | | 4.83 | | | | 13.2 | | | | 1.80 | | | | 5.9 | |
| Crude oil sold to HOP in Quarter 1, 2000 | | | — | | | | — | | | | — | | | | — | | | | 6.29 | | | | 20.7 | |
| Royalty payments | | | 3.48 | | | | 6.8 | | | | 1.69 | | | | 4.7 | | | | 1.32 | | | | 4.3 | |
| Crude oil domestic sales | | | 0.50 | | | | 1.0 | | | | 0.82 | | | | 2.2 | | | | 3.48 | | | | 11.5 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Total crude oil sales or transfers | | | 51.08 | | | | 100.0 | | | | 36.47 | | | | 100.0 | | | | 30.38 | | | | 100.0 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
Total consolidated revenue from crude oil sales amounted to $481.1 million in 2002, $253.0 million in 2001 and $301.2 million in 2000.
The increase in 2002 resulted from the increased volumes of crude oil sales from 20.8 million barrels at an average price of $12.16/bbl in 2001 compared to 29.9 million barrels at an average price of $16.11/bbl in 2002. The major reason for the increase in both volumes and average price is due to the shift to non-FCA sales (10.2 million barrels sold in 2002 at the average price of $22.70/bbl compared to 0.4 million barrels sold in 2001 at the average price of $17.72/bbl). Without non-FCA sales, crude oil sales in 2002 are consistent with 2001 (19.7 million barrels at the average price of $12.68/bbl in 2002 compared to 20.4 million barrels at the average price of $12.05/bbl in 2001).
The reduction of crude oil sales of $48.2 million in 2001 compared to 2000 was due to the decrease in volumes of 940,000 barrels from 21.8 million barrels in 2000 and a decrease in the average prices realized from $13.85/bbl in 2000 to $12.16/bbl in 2001.
31
| | | | | |
Crude oil sales | | Exports as a % of total
crude oil sales volumes | |
Refined product sales |
| |
 | |  | |  |
| * | | nine months revenue — from date of acquisition March 31, 2000 |
Total crude oil revenue can be analysed as follows:
| | | | | | | | | | | | | |
| | | Quantity | | Net Realized | | | | |
| | | Sold | | Price | | Revenue |
| | |
| |
| |
|
| | | (mmbbls) | | ($/bbl) | | ($000's) |
2002 | | | | | | | | | | | | |
| Crude sales sold FCA | | | 12.74 | | | | 13.48 | | | | 171,711 | |
| Crude sales sold non-FCA | | | 10.21 | | | | 22.70 | | | | 231,766 | |
| Kazgermunai export sales | | | 2.94 | | | | 14.22 | | | | 41,813 | |
| Royalty payments | | | 3.48 | | | | 9.27 | | | | 32,247 | |
| Crude oil domestic sales | | | 0.50 | | | | 7.15 | | | | 3,577 | |
| | | |
| | | |
| | | |
| |
| Total | | | 29.87 | | | | 16.11 | | | | 481,114 | |
| | | |
| | | |
| | | |
| |
| 2001 | | | | | | | | | | | | |
| Crude sales sold FCA | | | 15.58 | | | | 11.34 | | | | 176,720 | |
| Crude sales sold non-FCA | | | 0.39 | | | | 17.72 | | | | 6,910 | |
| Kazgermunai export sales | | | 2.33 | | | | 18.16 | | | | 42,307 | |
| Royalty payments | | | 1.69 | | | | 11.38 | | | | 19,232 | |
| Crude oil domestic sales | | | 0.82 | | | | 9.53 | | | | 7,812 | |
| | | |
| | | |
| | | |
| |
| Total | | | 20.81 | | | | 12.16 | | | | 252,981 | |
| | | |
| | | |
| | | |
| |
| 2000 | | | | | | | | | | | | |
| Crude sales sold FCA | | | 10.66 | | | | 19.52 | | | | 208,078 | |
| Royalty payments | | | 1.32 | | | | 8.60 | | | | 11,358 | |
| Crude oil domestic sales | | | 9.77 | | | | 8.37 | | | | 81,780 | |
| | | |
| | | |
| | | |
| |
| Total | | | 21.75 | | | | 13.85 | | | | 301,216 | |
| | | |
| | | |
| | | |
| |
Downstream
We acquired the Shymkent refinery on March 31, 2000. The comparative numbers in the tables for 2000 include only the nine months from the date of acquisition.
The refinery has a total design operating capacity of 6.6 million tonnes per year or the equivalent of approximately 51.1 million barrels per year. However, due to the size of the available market for refined products in Kazakhstan, the refinery operated at 53% capacity or 27.1 million barrels in 2002, 51.5% capacity or 26.3 million barrels in 2001 and 44.8% capacity or 17.2 million barrels during the nine months of our operation of the refinery in 2000.
32
The refinery continues to focus on the improvement of yields while minimizing the production of lower-end and lower-value products. The production of mazut a lower-end and lower-value product has been reduced year over year. Mazut yield in 2002 averaged 35.9% versus 40.4% in 2001.
The crude oil feedstock for the refinery is primarily acquired from Upstream operations but purchases are also made from third parties.
The following table sets out the source of feedstock supplies for our refinery:
| | | | | | | | | | | | | |
| (mmbbls) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Acquired from HKM | | | 16.82 | | | | 10.98 | | | | 16.41 | |
| Purchased from joint ventures (100%) | | | 8.78 | | | | 9.66 | | | | 3.61 | |
| Purchased from third parties | | | — | | | | 0.59 | | | | 1.05 | |
| | | |
| | | |
| | | |
| |
| Total feedstock acquired | | | 25.60 | | | | 21.23 | | | | 21.07 | |
| | | |
| | | |
| | | |
| |
The following table sets out the source of inventory levels of feedstock:
| | | | | | | | | | | | | |
| (mmbbls) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Opening inventory of crude oil feedstock | | | 0.34 | | | | 0.08 | | | | 0.19 | |
| Purchase and acquisition of feedstock | | | 25.60 | | | | 21.23 | | | | 21.07 | |
| Recoverable feedstock from traps | | | 0.03 | | | | 0.04 | | | | 0.05 | |
| Feedstock sold for export | | | — | | | | (0.15 | ) | | | (9.58 | ) |
| Feedstock sold domestically | | | — | | | | — | | | | (0.05 | ) |
| Feedstock refined into product | | | (25.77 | ) | | | (20.86 | ) | | | (11.60 | ) |
| | | |
| | | |
| | | |
| |
| Closing inventory of feedstock | | | 0.20 | | | | 0.34 | | | | 0.08 | |
| | | |
| | | |
| | | |
| |
The following table sets out the movement in inventory of refined product:
| | | | | | | | | | | | | |
| (mmtonnes)* | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Opening inventory of refined product | | | 0.20 | | | | 0.13 | | | | 0.11 | |
| Refined product from feedstock | | | 3.09 | | | | 2.55 | | | | 1.46 | |
| Refined product acquired | | | 0.09 | | | | 0.09 | | | | 0.15 | |
| Refined product sold | | | (3.16 | ) | | | (2.55 | ) | | | (1.54 | ) |
| Refined product internal use and yield losses | | | — | | | | (0.02 | ) | | | (0.05 | ) |
| | | |
| | | |
| | | |
| |
| Closing inventory of refined product | | | 0.22 | | | | 0.20 | | | | 0.13 | |
| | | |
| | | |
| | | |
| |
| * | | The inventory of products represents a mix of products for which no unique conversion from barrels to tonnes exists. The standard conversion used for crude oil by us is 7.746 barrels to the tonne. |
33
The crude oil feedstock is refined into a number of products, which are sold as refined products. Refined product sales revenue for 2002 was $322.0 million (2001 — $329.0 million and 9 months of 2000 — $203.7 million).
Sales of refined products in 2002 decreased by $7.0 million to $322.0 million as compared to 2001, as a result of price decreases, which were partially offset by increased volumes. Refined product sales of 3.2 million tonnes for 2002 were significantly higher than our 2.6 million tonnes in 2001. This increase in volumes was offset by a decline in the average price received (from $128.86/tonne in 2001 to $101.91/tonne in 2002). This decline occurred mainly during the first quarter of 2002 due to pressure on prices from increased Russian imports, and frommazut pricing, as therewas an over supply during the export ban in the heating season from early fall to late winter. Product prices have recovered at the end of 2002.
Sales of refined products increased by $125.3 million from $203.7 million in 2000 to $329.0 million in 2001 due to an increase in sales volumes of 1.0 million tonnes, as the refinery was included for a full year in 2001 versus nine months in 2000.
The table below sets out the products sold for 2002, 2001 and 2000, the volume sold, the average price achieved and the revenue for each product.
Refined product revenue
| | | | | | | | | | | | | |
| Product Produced | | Tonnes Sold | | Average Price | | Revenue |
| |
| |
| |
|
| | | | | ($/tonne) | | ($000's) |
2002 | | | | | | | | | | | | |
| Gasoline | | | 785,846 | | | | 145.90 | | | | 114,653 | |
| Diesel | | | 898,003 | | | | 121.15 | | | | 108,796 | |
| Mazut | | | 1,087,564 | | | | 42.37 | | | | 46,078 | |
| LPG | | | 108,931 | | | | 79.35 | | | | 8,644 | |
| Jet fuel | | | 178,695 | | | | 214.82 | | | | 38,388 | |
| | | |
| | | |
| | | |
| |
| Total self refined | | | 3,059,039 | | | | 103.48 | | | | 316,559 | |
| Resale of purchased refined products | | | 101,023 | | | | 54.23 | | | | 5,478 | |
| | | |
| | | |
| | | |
| |
| Total refined product sales | | | 3,160,062 | | | | 101.91 | | | | 322,037 | |
| | | |
| | | |
| | | |
| |
| 2001 | | | | | | | | | | | | |
| Gasoline | | | 548,503 | | | | 207.54 | | | | 113,838 | |
| Diesel | | | 710,029 | | | | 178.30 | | | | 126,600 | |
| Mazut | | | 1,045,682 | | | | 50.00 | | | | 52,284 | |
| LPG | | | 107,079 | | | | 92.71 | | | | 9,927 | |
| Jet fuel | | | 57,829 | | | | 231.84 | | | | 13,407 | |
| | | |
| | | |
| | | |
| |
| Total self refined | | | 2,469,122 | | | | 128.00 | | | | 316,056 | |
| Resale of purchased refined products | | | 83,695 | | | | 154.15 | | | | 12,902 | |
| | | |
| | | |
| | | |
| |
| Total refined product sales | | | 2,552,817 | | | | 128.86 | | | | 328,958 | |
| | | |
| | | |
| | | |
| |
| 2000 | | | | | | | | | | | | |
| Gasoline | | | 315,327 | | | | 215.31 | | | | 67,893 | |
| Diesel | | | 433,222 | | | | 185.30 | | | | 80,274 | |
| Mazut | | | 566,948 | | | | 49.79 | | | | 28,230 | |
| LPG | | | 63,478 | | | | 70.56 | | | | 4,479 | |
| Jet fuel | | | 16,637 | | | | 226.30 | | | | 3,765 | |
| | | |
| | | |
| | | |
| |
| Total self refined | | | 1,395,612 | | | | 132.30 | | | | 184,641 | |
| Resale of purchased refined products | | | 148,752 | | | | 128.31 | | | | 19,087 | |
| | | |
| | | |
| | | |
| |
| Total refined product sales | | | 1,544,364 | | | | 131.92 | | | | 203,728 | |
| | | |
| | | |
| | | |
| |
34
Processing fees
In addition to revenue generated from the refining and sale of product derived from acquired feed stock, the refinery also refined crude on behalf of third parties (“Tolling”) for which it receives a fee. During 2002 the refinery tolled 1.3 million barrels for third parties (5.4 million barrels in 2001 and 5.5 million barrels in 2000). Third party tolling volumes decreased in 2002 as crude producers elected to export their volumes due to the higher margin for exported oil.
The table below sets out the total quantity of oil processed for third parties into refined products, the average fee charged and revenue earned.
| | | | | | | | | | | | | |
| | | Volumes | | | | | | Processing |
| | | Processed | | Fee | | Revenue |
| | |
| |
| |
|
| | | (tonnes) | | ($/tonne) | | ($000's) |
2002 | | | 171,251 | | | | 15.54 | | | | 2,661 | |
| 2001 | | | 694,924 | | | | 16.32 | | | | 11,338 | |
| 2000 | | | 711,368 | | | | 16.71 | | | | 11,884 | |
INTEREST AND OTHER INCOME
Revenues from interest and other income decreased by $0.9 million from $9.8 million in 2001 to $8.9 million in 2002. This decrease was due to a decline in third party service fees.
Revenues from interest and other income increased by $3.4 million from $6.4 million in 2000 to $9.8 million in 2001. The increase was primarily due to an increase in third party service fees.
PRODUCTION EXPENSES
Production expenses relate to the cost of producing crude oil in the Upstream operations and production expenses were $60.6 million in 2002, $41.2 million in 2001 and $35.3 million in 2000. Based on the number of barrels of oil produced, these costs are $1.22/bbl for 2002, $1.12/bbl for 2001 and $1.15/bbl for 2000.
The absolute increase between 2002 and 2001 of $19.4 million and the per barrel increase of $0.10 is the result of the increase in production volumes of 12.7 mmbbls or 35% in 2002 and additional maintenance work required due to increasing production of formation water. Other reasons for the increase were higher insurance costs in 2002 and geophysical work, mainly bottom hole sampling.
The increase between 2001 and 2000 of $5.9 million was due to the increase in production volumes of 6 mmbbls and the inclusion of the Kazgermunai joint venture for the entire year.
ROYALTIES AND TAXES
Royalties and taxes were $58.1 million in 2002 as compared to $41.0 million for 2001 and $33.7 million for 2000.
| | | | | | | | | | | | | |
| ($000's) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Royalties and production bonus | | | 47,892 | | | | 35,504 | | | | 31,909 | |
| Tax assessments 1998 and 1999* | | | 5,121 | | | | 573 | | | | — | |
| Other taxes | | | 5,099 | | | | 4,946 | | | | 1,800 | |
| | | |
| | | |
| | | |
| |
| Royalties and taxes | | | 58,112 | | | | 41,023 | | | | 33,709 | |
| | | |
| | | |
| | | |
| |
| * | | See Note 22 of the Consolidated Financial Statements |
35
The royalty and production bonus expense for 2002 was $47.9 million, which represented an effective overall royalty rate of 9.03%. The royalty expense and production bonus expense for 2001 was $35.5 million, which is an overall royalty rate of 9.24%. For 2000 the expense was $31.9 million and the overall royalty rate was 9.95%. Our effective overall royalty rate has decreased as we have brought new fields with lower royalty rates on production. The absolute increase in royalties of 35% compared to 2001 is due to the increase in our production volumes and the increase from 2000 to 2001 is also due to an increase in our production volumes.
The table below indicates the royalty and production bonus paid in kind and in cash by quarter in 2002, 2001 and 2000.
| | | | | | | | | | | | | |
| ($000's) | | Royalty in Kind | | Cash Royalty | | Total Royalty |
| |
| |
| |
|
2002, Quarter Ending | | | | | | | | | | | | |
| March 31 | | | 2,972 | | | | 3,738 | | | | 6,710 | |
| June 30 | | | 7,456 | | | | 1,295 | | | | 8,751 | |
| September 30 | | | 12,723 | | | | 3,320 | | | | 16,043 | |
| December 31 | | | 2,967 | | | | 13,421 | | | | 16,388 | |
| | | |
| | | |
| | | |
| |
| Total | | | 26,118 | | | | 21,774 | | | | 47,892 | |
| | | |
| | | |
| | | |
| |
| 2001, Quarter Ending | | | | | | | | | | | | |
| March 31 | | | — | | | | 5,589 | | | | 5,589 | |
| June 30 | | | 6,680 | | | | 2,634 | | | | 9,314 | |
| September 30 | | | 11,103 | | | | 1,493 | | | | 12,596 | |
| December 31 | | | 7,526 | | | | 479 | | | | 8,005 | |
| | | |
| | | |
| | | |
| |
| Total | | | 25,309 | | | | 10,195 | | | | 35,504 | |
| | | |
| | | |
| | | |
| |
| 2000, Quarter Ending | | | | | | | | | | | | |
| March 31 | | | — | | | | 5,694 | | | | 5,694 | |
| June 30 | | | 785 | | | | 4,912 | | | | 5,697 | |
| September 30 | | | 5,563 | | | | 1,401 | | | | 6,964 | |
| December 31 | | | 9,548 | | | | 4,006 | | | | 13,554 | |
| | | |
| | | |
| | | |
| |
| Total | | | 15,896 | | | | 16,013 | | | | 31,909 | |
| | | |
| | | |
| | | |
| |
For the fourth quarter of 2002, HKM paid its royalties in cash as opposed to the first three quarters of 2002 when they were paid in kind. Turgai paid royalty in kind in the fourth quarter of 2002, as opposed to the first three quarters of 2002, where Turgai paid in cash.
TRANSPORTATION
Transportation costs are made up of the costs of shipping crude oil from the CPF to the Shymkent refinery, the costs of trucking crude oil from the KAM fields to the CPF and railway transportation from the Shymkent refinery under non-FCA sales contracts. Transportation costs also include transportation of crude produced by our Kazgermunai joint venture to its export customers.
The pipeline tariff from the CPF to Shymkent depends on the ultimate destination of the crude oil. In 2002, the tariff charged in respect of crude oil destined for export was $1.41/bbl (2001 — $1.41/bbl and 2000 — $1.00/bbl), whereas the cost for crude oil processed at the refinery is $0.81/bbl (2001 — $0.84/bbl, 2000 — $0.81/bbl).
36
The table below sets out the constituent components of transportation costs.
| | | | | | | | | | | | | |
| ($000's) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Pipeline | | | 56,230 | | | | 33,396 | | | | 25,152 | |
| Kazgermunai transportation | | | 8,462 | | | | 8,829 | | | | — | |
| Railway | | | 93,305 | | | | 6,255 | | | | — | |
| Other | | | 5,804 | | | | 1,757 | | | | — | |
| | | |
| | | |
| | | |
| |
| Total | | | 163,801 | | | | 50,237 | | | | 25,152 | |
| | | |
| | | |
| | | |
| |
The absolute increase in pipeline costs is due to the increased volumes of crude oil exported in 2002 versus 2001, which attracts a higher tariff. For 2002, export volumes were 25.9 million barrels or 41% higher than for 2001. Railway transportation increased as compared to 2001 due to the shift to non-FCA sales. Other related transportation costs are mainly trucking costs incurred to transport crude oil from the KAM fields to the central processing facility located at Kumkol. These costs have increased in proportion to the increase in production from the KAM fields.
The absolute increase in transportation costs in 2001 compared to 2000 was due to increased export sales volumes of 7.6 million barrels, as well as an increase in the pipeline tariff. There were no non-FCA sales in 2000 and therefore we had no railway costs. The KAM fields were not on production in 2000.
REFINING
Refining costs represent the direct costs related to processing all crude oil including tollers’ volumes. The total refining costs in 2002 were $21.7 million or $0.80/bbl of crude oil processed compared to $20.6 million or $0.78/bbl in 2001. The increase of $1.1 million year over year is mainly due to increased repair and maintenance at the refinery in 2002 as part of our ongoing maintenance program. In August of 2002, six refinery workshops, including the transportation, construction and repair workshops each of which has a direct impact on refining costs, became independent from the refinery. Costs incurred in separating these workshops are included in refining costs for 2002.
Refining costs in 2000 were $12.6 million or $0.75/bbl of crude oil processed compared to $20.6 million or $0.78/bbl in 2001. The absolute increase in refining costs in 2001 is from a full year’s activity being included in 2001 and increased processing. The increase on a per barrel basis was brought about by increased heat and energy costs during 2001 as the contract with the local power station was changed such that full market rates were paid for power, as opposed to the reduced rates in 2000. Correspondingly, HOP charged market prices for its fuel oil sales to the power plant.
CRUDE OIL AND REFINED PRODUCT PURCHASES
Crude oil and refined product purchases represent the cost of purchasing crude oil for the refinery from third parties, as well as refined product for resale. Purchases and sales between our Upstream and Downstream business units are eliminated on consolidation.
| | | | | | | | | | | | | |
| ($000's) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Crude oil | | | 69,410 | | | | 64,373 | | | | 30,495 | |
| Refined products | | | 3,917 | | | | 14,415 | | | | 17,605 | |
| | | |
| | | |
| | | |
| |
| Total | | | 73,327 | | | | 78,788 | | | | 48,100 | |
| | | |
| | | |
| | | |
| |
Crude oil and refined products purchases decreased in 2002 compared to 2001 due to a decrease in purchases of refined products. Crude oil and refined products purchases increased in 2001 compared to 2000 by $30.7 million due to an increase in purchased volumes of 2.56 million barrels from 2.86 million barrels in 2000.
37
SELLING
Selling expenses are comprised of the costs of operating the seven distribution centres of our Downstream operations that sell refined products, and certain costs associated with the sale and export of crude oil. Selling expenses in 2002 were $23.3 million compared to $19.3 million in 2001 and $7.7 million in 2000.
| | | | | | | | | | | | | |
| ($000's) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Crude oil | | | 3,471 | | | | 5,622 | | | | — | |
| Refined products | | | 19,782 | | | | 13,655 | | | | 7,728 | |
| | | |
| | | |
| | | |
| |
| Total | | | 23,253 | | | | 19,277 | | | | 7,728 | |
| | | |
| | | |
| | | |
| |
The absolute increase in 2002 compared to 2001 is the direct result of increased sales volumes. We sold 54.4 million barrels of crude oil and refined products during 2002 (2001 — 40.6 million barrels), a 34% increase in volumes compared to a 21% increase in costs.
The absolute increase in 2001 compared to 2000 is due to the inclusion of a full year of Downstream operations and increased sales volumes of 6.8 million barrels from 33.8 million barrels in 2000.
GENERAL AND ADMINISTRATIVE
The table below analyses total general and administrative costs between Upstream, Downstream and Corporate. In the case of Upstream and Downstream the general and administrative costs are also reflected on a per barrel basis.
| | | | | | | | | |
| | | General and | | Per Barrel of Oil |
| | | Administrative | | Produced or Processed* |
| | |
| |
|
| | | ($000's) | | ($/bbl) |
2002 | | | | | | | | |
| Upstream | | | 37,093 | | | | 0.75 | |
| Downstream | | | 17,216 | | | | 0.64 | |
| Corporate | | | 4,570 | | | | | |
| | | |
| | | | | |
| Total | | | 58,879 | | | | | |
| | | |
| | | | | |
| 2001 Upstream | | | 28,024 | | | | 0.76 | |
| Downstream | | | 17,906 | | | | 0.68 | |
| Corporate | | | 5,564 | | | | | |
| | | |
| | | | | |
| Total | | | 51,494 | | | | | |
| | | |
| | | | | |
| 2000 Upstream | | | 25,497 | | | | 0.83 | |
| Downstream | | | 14,200 | | | | 0.83 | |
| Corporate | | | 4,868 | | | | | |
| | | |
| | | | | |
| Total | | | 44,565 | | | | | |
| | | |
| | | | | |
| * | | Including tollers’ volumes |
38
The increase in 2002 of $7.4 million compared to 2001 is due to increased activity in Upstream operations, including increases in staff, insurance, legal and consulting costs. There has also been a change in 2002 in the method of allocating centrally incurred general and administrative costs whereby a higher percentage of costs are allocated to Upstream.
Our Upstream field office is located in Kyzylorda, the majority of our staff are there, and all related costs are classified as general and administrative in nature as opposed to production costs.
The increase in 2001 from 2000 relates to the inclusion of HOP for the entire year versus nine months in 2000 and the consolidation of our Kazgermunai joint venture for an entire year versus one month in 2000.
INTEREST AND FINANCING
The following table sets out the interest expense and any related amortization of debt issue costs or discounts upon issuance of the debt instrument.
| | | | | | | | | | | | | |
| ($000's) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Short-term debt | | | 1,470 | | | | 1,855 | | | | — | |
| Term facility | | | 4,106 | | | | — | | | | — | |
| Kazgermunai debt | | | 3,447 | | | | 5,960 | | | | 118 | |
| 12% Notes | | | 24,936 | | | | 8,881 | | | | — | |
| HOP bonds | | | 1,514 | | | | 1,029 | | | | — | |
| Canadian and U.S. notes | | | — | | | | 1,805 | | | | 18,590 | |
| | | |
| | | |
| | | |
| |
| Total | | | 35,473 | | | | 19,530 | | | | 18,708 | |
| | | |
| | | |
| | | |
| |
The increase in interest of $16 million is mainly due to the 12% Notes being outstanding for all of 2002 as compared to five months in 2001.
DEPRECIATION AND DEPLETION
Depreciation and depletion has increased by $10.8 million in 2002. This increase is due to the increase in production as compared to 2001 and capital additions in 2002. The effect of these increases was partly offset by an increase in proved producing reserves.
| | | | | | | | | |
| | | Depreciation | | Depreciation |
| | | and Depletion | | and Depletion |
| | |
| |
|
| | | ($000's) | | ($/bbl*) |
2002 | | | | | | | | |
| Upstream | | | 31,647 | | | | 0.64 | |
| Downstream | | | 13,347 | | | | 0.49 | |
| Corporate | | | 94 | | | | | |
| | | |
| | | | | |
| Total | | | 45,088 | | | | | |
| | | |
| | | | | |
| 2001 | | | | | | | | |
| Upstream | | | 24,116 | | | | 0.65 | |
| Downstream | | | 9,764 | | | | 0.37 | |
| Corporate | | | 374 | | | | | |
| | | |
| | | | | |
| Total | | | 34,254 | | | | | |
| | | |
| | | | | |
| 2000 | | | | | | | | |
| Upstream | | | 7,707 | | | | 0.25 | |
| Downstream | | | 6,973 | | | | 0.41 | |
| Corporate | | | — | | | | | |
| | | |
| | | | | |
| Total | | | 14,680 | | | | | |
| | | |
| | | | | |
| * | | Downstream includes tollers’ volumes |
39
In accordance with Canadian and United States accounting standards, and to provide comfort that anticipated future revenues are sufficient to cover the capitalised costs of properties, we perform a quarterly “ceiling test”. The ceiling test for the year ended December 31, 2002 demonstrated that future net revenues exceed the carrying value of the Upstream properties under the full cost method of accounting.
INCOME BEFORE INCOME TAXES
As a result of the foregoing factors, we had income before income taxes of $265.1 million for 2002, as compared to $239.7 million for 2001 and $264.6 million for 2000.
UNUSUAL ITEMS
We were named as defendants in a claim filed by a company alleging it was retained under a consulting contract, as disclosed in Note 22 to the Consolidated Financial Statements for the year ended December 31, 2002. The arbitration decision was received in 2002 and we accrued and paid $7.1 million for full settlement of the claim.
In 2001 we incurred $5.5 million in costs defending ourselves from a potential takeover bid. In 2000 we incurred $20.4 million in costs for restructuring and waiver fees (Please refer to Note 3 to the Consolidated Financial Statements).
INCOME TAXES
| | | | | | | | | | | | | |
| ($000's) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Upstream | | | 53,461 | | | | 18,859 | | | | (8,139 | ) |
| Downstream | | | 37,189 | | | | 43,744 | | | | 98,706 | |
| Corporate | | | 9,845 | | | | 5,791 | | | | 9,090 | |
| | | |
| | | |
| | | |
| |
| Total | | | 100,495 | | | | 68,394 | | | | 99,657 | |
| | | |
| | | |
| | | |
| |
The increase in income taxes by $32.1 million in 2002 is a result of the following items:
| • | | Upstream tax charges have increased due to the increase in sales volumes and in the price of crude oil; |
| |
| • | | $11.3 million due to the recognition of a deferred tax asset in 2001, which reduced 2001 taxes by a corresponding amount; |
| |
| • | | $7.5 million due to the non-deductibility for tax purposes of interest paid on the 12% Notes; |
| |
| • | | $4.5 million due to court decision with respect to the tax rate for South Kumkol (Note 22). |
The decrease in income taxes by $31.3 million in 2001 compared to 2000 is a result of the following items:
| • | | $11.3 million due to recognition of a deferred tax asset in 2001 (Note 17); |
| |
| • | | Decrease in non-deductible items in 2001 as we incurred $20.4 million of non-deductible restructuring costs in 2000. |
The corporate tax expense relates to taxes paid by Hurricane Overseas Services Inc., the company that provides services to the operating subsidiaries in Kazakhstan, and the tax impact of non-deductible interest. Please refer to Note 17 of the Consolidated Financial Statements for further information pertaining to income taxes.
49
NET INCOME
As a result of the foregoing factors, we had net income for 2002 of $162.6 million compared to net income of $169.3 million for 2001 and $154.9 million in 2000.
NET RETURN PER BARREL
Set out below are the details of the average net return achieved for export sales and sales derived from the refining of our own crude.
| | | | | | | | | |
| | | | | | | Own Crude Oil |
| ($/bbl) | | Crude Oil Exports | | Refined and Sold |
| |
| |
|
2002 | | | | | | | | |
| Net sales price achieved | | | 17.20 | | | | 13.16 | |
| Transportation costs | | | (5.04 | ) | | | (0.94 | ) |
| Production and refining costs | | | (1.22 | ) | | | (2.02 | ) |
| Purchase of crude oil | | | (0.55 | ) | | | — | |
| Royalty | | | (1.16 | ) | | | (1.18 | ) |
| Selling costs | | | (0.23 | ) | | | (0.67 | ) |
| General and administrative costs | | | (0.75 | ) | | | (1.39 | ) |
| | | |
| | | |
| |
| Net return per barrel | | | 8.25 | | | | 6.96 | |
| | | |
| | | |
| |
| 2001 | | | | | | | | |
| Net sales price achieved | | | 12.34 | | | | 16.53 | |
| Transportation costs | | | (1.87 | ) | | | (0.84 | ) |
| Production and refining costs | | | (1.12 | ) | | | (1.90 | ) |
| Royalty | | | (0.96 | ) | | | (0.96 | ) |
| Selling costs | | | (0.15 | ) | | | (0.86 | ) |
| General and administrative costs | | | (0.76 | ) | | | (1.44 | ) |
| | | |
| | | |
| |
| Net return per barrel | | | 7.48 | | | | 10.53 | |
| | | |
| | | |
| |
| 2000 | | | | | | | | |
| Net sales price achieved | | | 19.52 | | | | 17.08 | |
| Transportation costs | | | (1.00 | ) | | | (0.80 | ) |
| Production and refining costs | | | (1.15 | ) | | | (1.90 | ) |
| Royalty | | | (1.10 | ) | | | (1.10 | ) |
| Selling costs | | | — | | | | (0.45 | ) |
| General and administrative costs | | | (0.83 | ) | | | (1.66 | ) |
| | | |
| | | |
| |
| Net return per barrel | | | 15.44 | | | | 11.17 | |
| | | |
| | | |
| |
41
The net return per barrel for crude oil exports improved by $0.77 in 2002 compared to 2001 as a result of the increase in the price of crude oil, offset in part, by the increase in transportation costs. Net return per barrel on refined product sales is substantially lower than in 2001 due to lower prices received for refined products.
The net return per barrel for crude oil exports decreased by $7.96 in 2001 compared to 2000 due to higher oil prices in 2000 (average Brent for 2000 was $28.4/bbl versus $24.4/bbl during 2001), as well as increases in pipeline tariffs. Refined product net returns decreased by $0.64 in 2001 due to lower prices received for refined products.
COMPARISON OF COMPLETED FCA AND NON-FCA SALES
| | | | | | | | | | | | | | | | | |
| 2002, Quarter Ended ($/bbl) | | March 31 | | June 30 | | September 30 | | December 31 |
| |
| |
| |
| |
|
FCA | | | | | | | | | | | | | | | | |
| Average Brent | | | 21.99 | | | | 24.96 | | | | 27.01 | | | | 25.01 | |
| Differential | | | 13.26 | | | | 13.50 | | | | 13.74 | | | | 13.56 | |
| | | |
| | | |
| | | |
| | | |
| |
| Netback at Kumkol | | | 8.73 | | | | 11.46 | | | | 13.27 | | | | 11.45 | |
| | | |
| | | |
| | | |
| | | |
| |
Non-FCA | | | | | | | | | | | | | | | | |
| Average Brent | | | 23.15 | | | | 24.74 | | | | 27.07 | | | | 26.81 | |
| Differential | | | 12.82 | | | | 14.48 | | | | 15.20 | | | | 14.14 | |
| | | |
| | | |
| | | |
| | | |
| |
| Netback at Kumkol | | | 10.33 | | | | 10.26 | | | | 11.87 | | | | 12.67 | |
| | | |
| | | |
| | | |
| | | |
| |
The table above sets out our two types of sales transactions on a completed sale basis and is mainly a comparison of the Aktau route (FCA) with all of our other routes (non-FCA). The Aktau route is supported by the government and consequently, it receives preferential rail tariffs. It compares transactions that were completed in the quarter as opposed to shipments made in the quarter. We use this analysis, as it compares transactions finalized in the quarter. The average Brent is the average Brent price we received for all sale transactions for the quarter. Pricing is specific to the bill of lading date and the differential represents all costs to move our crude oil from Kumkol to various final destinations.
Our differential deteriorated for the first three quarters of 2002 and recovered in the fourth quarter as we increased the use of lower cost routes. While the average Brent price is comparable for the second and third quarters for the FCA versus non-FCA sales, it differs markedly for the two types of transactions in the first and fourth quarters because of the timing of when sales took place. For example, at the end of the fourth quarter when oil prices were at their highest level for the year, we had only non-FCA sales.
For the last three quarters of 2002, the FCA differential has been significantly better than the non-FCA differential. The combination of FCA and non-FCA sales leads to competition and, on an overall basis, a lower differential.
42
CAPITAL EXPENDITURES
The table below provides a breakdown of capital expenditures.
| | | | | | | | | | | | | | |
| ($000's) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Upstream Development wells | | | 40,489 | | | | 10,650 | | | | 3,045 | |
| | Facilities and equipment | | | 67,884 | | | | 79,330 | | | | 7,287 | |
| | Exploration | | | 23,502 | | | | 10,279 | | | | 4,529 | |
| Downstream Refinery HS&E | | | 773 | | | | 796 | | | | 233 | |
| | Refinery sustaining | | | 4,019 | | | | 5,046 | | | | 3,244 | |
| | Refinery return projects | | | 3,364 | | | | 3,013 | | | | 2,362 | |
| | Marketing and other | | | 71 | | | | 477 | | | | 927 | |
| Corporate | | | — | | | | 616 | | | | — | |
| | | |
| | | |
| | | |
| |
| Total capital expenditure | | | 140,102 | | | | 110,207 | | | | 21,627 | |
| | | |
| | | |
| | | |
| |
In 2003, capital expenditures will be incurred to:
| • | | Continue development of the Kumkol South and South Kumkol fields. |
| |
| • | | Complete and commission the KAM pipeline. |
| |
| • | | Further develop the KAM fields. |
| |
| • | | Continue exploration, including the drilling of deep wells in license 260 D1. |
| |
| • | | Further develop fields within our joint ventures. |
| |
| • | | Implement HS&E projects for the refinery. |
| |
| • | | Implement projects designed to increase the efficiency of the refinery. |
| |
| • | | Complete and commission our gas utilization project (“GUP”). |
Our 2003 capital budget is $167.0 million, of which $35.3 million is contractually committed. These are commitments for the KAM pipeline, GUP and construction and commissioning of a new boiler at HOP. The 2003 budget has been allocated as follows:
| | | | | |
| ($ millions) | | | | |
| | | | |
| Upstream, including joint ventures | | | 135.2 | |
| Downstream | | | 17.6 | |
| Marketing and trading | | | 8.1 | |
| Corporate | | | 6.1 | |
| | | |
| |
| Total | | | 167.0 | |
| | | |
| |
43
RISKS
Commodity price risk
Commodity price risk related to crude oil prices is our most significant market risk exposure. Crude oil prices are influenced by such worldwide factors as OPEC actions, political events, and supply and demand fundamentals.
FCA differential/transportation
Our most significant expenditure is the FCA differential or, in the case of non-FCA sales, the cost of transportation. The construction of the KAM pipeline and access to CPC and other pipelines, to the extent we are able to negotiate such access, will help address this issue. The completion of the KAM pipeline is expected to lower costs for exported crude oil by approximately $2.00 to $2.50/bbl shipped. We are also striving to open new routes with lower transportation costs. We have a full team in place, dedicated to minimizing our transportation costs.
Government taxes
We are currently engaged in litigation with respect to tax assessments received for prior years, for which the final outcome is uncertain. The impact of this pending litigation will be significant, but will not have a material adverse impact, if we do not prevail in our position with respect to these assessments.
Please refer to Note 22, Commitments and Contingencies of the Consolidated Financial Statements.
Kazakhstani environment and legislation
Please refer to Note 22, Commitments and Contingencies of the Consolidated Financial Statements.
FINANCIAL RISKS
Please refer to Note 19, Financial Instruments of the Consolidated Financial Statements for an analysis of our financial risks.
LIQUIDITY
The levels of cash, current assets and current liabilities at the balance sheet date for the last two financial years is set out below.
| | | | | | | | | |
| AS AT DECEMBER 31 | | 2002 | | 2001 |
| |
| |
|
| ($000's) | | | | |
| Cash and cash equivalents | | | 74,796 | | | | 64,812 | |
| Cash flow | | | 216,794 | | | | 200,349 | |
| Working capital* | | | 86,987 | | | | 49,138 | |
| Net debt | | | 217,754 | | | | 268,920 | |
| Ratio of cash flow to net debt | | | 1.0 | | | | 0.7 | |
| Ratio of cash flow to fixed charges** | | | 6.1 | | | | 10.2 | |
| Ratio of earnings to fixed charges*** | | | 8.5 | | | | 13.2 | |
| * | | Working capital is net of cash and short-term debt |
| |
| ** | | Fixed charges includes interest expense and preferred dividends before tax |
| |
| *** | | Earnings is net income plus fixed charges |
44
Working capital excluding cash and short-term debt as at December 31, 2002 was $87.0 million ($49.1 million as at December 31, 2001). The increase is due to our transition to non-FCA sales, whereby customers pay after the crude oil is delivered and we pay transportation charges in advance. Inventory has risen significantly because of our increased use of non-FCA sales and is partially offset by an increase in accounts payable.
Cash is managed centrally through the treasury department in Kazakhstan. Surplus funds are placed on deposit in Canada. Funds held within Kazakhstan are used to meet operational and immediate capital expenditure needs.
Our Kazgermunai non-recourse debt was repaid in part during 2002 (our 50% share repaid was $18.9 million of debt and accrued interest).
Our term facility for $60.0 million was repaid on December 28, 2002, and on February 3, 2003 we redeemed all $208.2 million of our outstanding 12% Notes.
Cash flow from our operations, together with proceeds of our new financings, provide us with sufficient means to implement our plans for 2003. Our new financings improve the structure of our balance sheet with a term of four years for our term facility with repayments of equal monthly amounts of principal commencing after six months and with a seven-year term on our new issue of $125.0 million principal amount 9.625% Notes (the “9.625% Notes”) due 2010. Of our 2003 capital budget of $167.0 million, $35.3 million is committed and we can curtail capital expenditures if necessary, to maintain liquidity.
Details of our new facilities are set out in Note 23 of the Consolidated Financial Statements.
SENSITIVITIES
| | | | | |
| ($ millions) | | Net income |
| |
|
| The estimated 2003 impact of: | | | | |
| Crude oil – $1.00/bbl change in dated Brent | | | 33.0 | |
| Export transportation differential – $1.00/bbl change | | | 25.0 | |
| Interest rates – 1.0% change | | | 1.6 | |
OUTLOOK
The KAM pipeline is on schedule for commissioning at the end of the second quarter of 2003, which will lead to a significant reduction in the costs relating to the export of crude oil. The GUP is scheduled for commissioning in the third quarter of 2003. This will significantly reduce our flaring of produced gas and provide a stable supply of electricity to our fields. The vacuum distillation unit is scheduled to be commissioned during the fourth quarter of 2003. This will further reduce our production of mazut, allowing us to improve our overall refining margin.
Our financial position is strong, our new financings completed early in 2003 provide a maturity of four years for the $225.0 million term facility with equal monthly principal repayments after six months and a maturity of seven years for our $125.0 million 9.625% Notes. This improves the structure of our balance sheet and our ability to withstand volatile oil prices.
45
We will continue to have a strong exploration and development program with our 2003 production target at 165,000 bopd, a 22% increase over 2002.
Our challenge for 2003 is to manage our transportation of crude oil destined for export, improving efficiencies and reducing costs.
QUARTERLY INFORMATION
The table below sets out selected quarterly information for 2002, 2001 and 2000.
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Net Income ($/share)* |
| | | | | | | | | | |
|
| ($000’s) | | Total Revenue | | Net Income | | Basic | | Diluted |
| |
| |
| |
| |
|
2002, Quarter Ended | | | | | | | | | | | | | | | | |
| March 31 | | | 143,331 | | | | 23,109 | | | | 0.29 | | | | 0.28 | |
| June 30 | | | 177,398 | | | | 33,808 | | | | 0.42 | | | | 0.40 | |
| September 30 | | | 247,962 | | | | 60,513 | | | | 0.74 | | | | 0.71 | |
| December 31 | | | 249,921 | | | | 45,138 | | | | 0.56 | | | | 0.54 | |
| | | |
| | | |
| | | |
| | | |
| |
| 2001, Quarter Ended | | | | | | | | | | | | | | | | |
| March 31 | | | 139,243 | | | | 55,372 | | | | 0.69 | | | | 0.67 | |
| June 30 | | | 174,849 | | | | 44,435 | | | | 0.56 | | | | 0.54 | |
| September 30 | | | 160,743 | | | | 46,490 | | | | 0.58 | | | | 0.55 | |
| December 31 | | | 128,221 | | | | 23,043 | | | | 0.29 | | | | 0.27 | |
| | | |
| | | |
| | | |
| | | |
| |
| 2000, Quarter Ended | | | | | | | | | | | | | | | | |
| March 31 | | | 61,191 | | | | (1,983 | ) | | | (0.04 | ) | | | (0.04 | ) |
| June 30 | | | 154,831 | | | | 48,364 | | | | 0.61 | | | | 0.54 | |
| September 30 | | | 172,776 | | | | 62,297 | | | | 0.79 | | | | 0.76 | |
| December 31 | | | 134,403 | | | | 46,252 | | | | 0.58 | | | | 0.55 | |
| | | |
| | | |
| | | |
| | | |
| |
| * | | Net income per share for 2000, has been restated to reflect the revised recommendations of the Canadian Institute of Chartered Accountants. |
46
Corporate governance
The Board of Directors and senior management of Hurricane consider good corporate governance to be central to the effective and efficient operation of Hurricane and its business.
Hurricane’s Board of Directors (the “Board”) and management are committed not only to satisfying legal and regulatory requirements, but also to developing and maintaining corporate governance practices that reflect evolving best practices standards as appropriate to Hurricane and its business.
The Board and management have been following developments in corporate governance requirements and best practices standards in both Canada and the United States closely. Hurricane will comply with legal requirements once they are finalized and will review the final form of corporate governance best practices standards of the stock exchanges on which it is listed with a view to adopting those practices which are appropriate to Hurricane and its business. Set out below are some of the highlights of Hurricane’s current corporate governance practices. A full report of Hurricane’s corporate governance practices is set out in the Management Proxy Circular issued in connection with the 2003 Special and Annual Meeting of Shareholders.
MANDATE OF THE BOARD
The mandate of the Board is to manage the business and affairs of Hurricane. Pursuant to this mandate, it has explicitly assumed responsibility for the stewardship of Hurricane and, as part of the overall stewardship responsibility, has assumed the responsibilities described below:
| • | | The Board provides input to management in the development of Hurricane’s strategic plan, approves that plan and monitors management’s execution of that plan. As part of the Board’s responsibility for the strategic planning process, the Board establishes the goals of the business of Hurricane with the input of management and strategies and policies within which Hurricane is managed. Management is required to seek approval of the Board for material deviations, financial or otherwise, from the approved business goals, strategies and policies. |
| |
| • | | It is management’s responsibility to identify the principal risks to Hurricane’s business and to develop strategies to manage those risks. The Board receives regular reports from management on those risks, the systems in place to manage those risks and the effectiveness of those systems. |
| |
| • | | The Board is responsible for the appointment, appraisal and monitoring of Hurricane’s senior management. Hurricane’s policy is to attract management personnel whose prior experience results in them having been well trained for their responsibilities with Hurricane. The Board discusses succession issues with the CEO on a regular basis and becomes acquainted with other members of senior management, their experience and skill sets. The Board encourages senior management to participate in appropriate professional and personal development activities, courses and programs, and supports management’s commitment to the training and development of all permanent employees. |
| |
| • | | The Board oversees the policy of communications by Hurricane with its shareholders and, in conjunction with management, continues to review Hurricane’s approach to communications with its shareholders, regulatory bodies, governments, media and the public. |
| |
| • | | The Board oversees the integrity of Hurricane’s internal control and management information systems, including reports from management, from the external auditors and from the Audit Committee. |
BOARD COMPOSITION
The Board consists of six members, five of whom are unrelated directors and one of whom is a related director within the meaning of the guidelines set out in The Toronto Stock Exchange Corporate Governance Policy.
COMMITTEES
The Board has established three committees: the Audit Committee, the Compensation Committee and the Corporate Governance Committee. All committees are comprised entirely of outside directors, all of whom are also unrelated directors.
RECENT DEVELOPMENTS
A Disclosure Committee, composed of non-director members including financial officers of Hurricane, has been established to assist and advise the Chief Executive Officer and Chief Financial Officer with respect to Hurricane’s internal controls and disclosure of financial information.
The Corporate Governance Committee has been charged with preparing a Code of Business Ethics and Communication Policy for Hurricane, to be submitted to the Board for approval.
In addition, the Board has adopted a number of prohibitions, as follows:
| • | | Hurricane is prohibited, directly or indirectly through any subsidiary, from extending or maintaining credit or arranging for the extension of credit or renewing an extension of credit, in the form of a personal loan, to or for any of Hurricane’s directors, officers or other senior members of management. |
| |
| • | | Hurricane is prohibited from materially modifying the terms of any existing loan, arrangement of credit or advance made, whether directly or indirectly, to any of its directors, officers or other senior members of management prior to July 30, 2002. |
| |
| • | | To ensure compliance with laws prohibiting insider trades during certain blackout periods, the Corporate Governance Committee has been charged with updating Hurricane’s Share Trading and “Tipping” Policy, to be submitted to the Board for approval. |
47
Corporate structure
The following diagram shows the principal subsidiaries of Hurricane Hydrocarbons Ltd, their respective jurisdictions of incorporation and the percentage ownership Hurricane has, directly or indirectly. The Company conducts virtually all of its operations through, and virtually all its assets are held, directly or indirectly, by Hurricane Kumkol Munai, Turgai Petroleum, Kazgermunai, Hurricane Oil Products and Hurricane Marketing Limited.
Hurricane Hydrocarbons Ltd.(Canada) is our corporate head office that directly or indirectly owns all of the other companies within the Hurricane group.
Hurricane Overseas Limited(Cyprus) is an intermediate holding company.
Hurricane Marketing Limited(Cyprus) is a crude oil marketing subsidiary of the Hurricane group.
OJSC Hurricane Kumkol Munai(Kazakhstan) is engaged in developing the Kumkol South, South Kumkol, KAM, East Kumkol, North Nurali fields and our exploration block 260 D1.
Kazgermunai LLP(Kazakhstan) is a 50% joint venture with RWE-DEA AG (25%), Erdol-Erdgas Gommern GmbH (17.5%), and International Finance Corporation (7.5%) engaged in developing the Akshabulak, Nurali and Aksai fields.
Hurricane Finance B.V.(Netherlands), a special purpose entity, is a wholly owned subsidiary of HKM.
Turgai Petroleum CJSC(Kazakhstan) is a 50% joint venture with LUKoil Ovrseas Ltd.,engaged in developing the North Kumkol field.
Valsera Holdings B.V.(Netherlands) is an intermediate holding company for our refining activities.
OJSC Hurricane Oil Products(Kazakhstan) is the company in which our refining activities take place.
Ascot Petroleum Consulting Ltd.(England) provides management services to companies in the Hurricane group.
Hurricane Overseas Services Inc.(Canada and Kazakhstan) supplies international goods and services for Hurricane’s Kazakhstani operations and provides personnel services to the group.
48
