Kazakhstan - Resource Management
Boris Zilbermints and Ian Dunderdale, Gaffney, Cline & Associates
Over the last ten years Kazakhstan has made significant progress in the evolution of its oil and gas industry. Production of oil in 1999 was the highest achieved by the country based on published data and highlights continuing progress in the development of its gas resources. However, Kazakhstan also faces challenges, replacement of production, continued needs for foreign investment and the optimum management of large fields. In conjunction with the TACIS INOGATE1 program, senior staff from Kazakhoil, the Ministry of Natural Resources and various institutes have been evaluating these and other issues as they look to further enhance the capability of Kazakhstan’s hydrocarbon sector. Detailed below are three areas which have been a focus for attention.
I.Economic Evaluation of Reserves
The countries of the Former Soviet Union have had a classification system for petroleum reserves for over fifty years. The classification system served as a basis for the state assessment of quantity, quality, accumulation conditions and industrial production of reserves and for maintaining of the state reserves balance. This system was highly effective in that it established the same evaluation criteria for all deposits and all entities involved in their development. The system addressed potential resources of the hydrocarbon accumulation basins as well as the reserves in producing fields. However, the system was mainly directed on estimation and classification of technically recoverable reserves, with little or no regard to economics. Priority was given to producing large volumes at any cost, even when it was not commercially viable. Reserves were usually estimated at the beginning of a field’s life and then rarely revised. This situation might have been suitable for the command economy, where production targets, product prices and costs were set by the government. After the break-up of the Soviet Union and transition to the market economy the flaws of the old reserves classification system became apparent. Governments of the Newly Independent States (NIS) could no longer afford to subsidise loss-making enterprises and there was an obvious need for foreign investment and technology. But foreign companies and financial institutions could not, and in some instances did not want to understand the particularities of the old Soviet classification system. The apparent differences between the systems, and disagreements they caused between the interested parties, have complicated the negotiating process and slowed down the pace of investment into the industry. There were numerous efforts to bridge the differences between the two systems and find ways to compare them (Figure 1). The main purpose of the INOGATE “Hydrocarbon Reserves Assessment” project carried out on behalf of TACIS by Gaffney, Cline & Associates (GCA) in the NIS is to meet local authorities responsible for the reserves classification system in each country and explain to them the methodology and logic behind the international approaches to classification and management of hydrocarbon resources.
It is a well known and recognised fact that geological or in-place volumes of hydrocarbons are estimated more or less similarly in both systems and the results are often very close. The laws of Mother Nature still applied, regardless of the social system. The differences in methodology start to appear when recoverable reserves are being determined and categorised. Let us compare the definitions used under both systems:
Soviet: Reserves are mass of oil and condensate and volume of natural gas in explored and developed fields measured at standard conditions at the date of estimation.
International*: Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations, from a given date forward.
The Soviet system definition does not contain words like commercial or economic and is directed on extracting physical volumes of hydrocarbons. International systems demand that only commercially recoverable hydrocarbons should be categorised as reserves. The factors that determine commercial value of reserves are: development plan, production forecast, costs, prices and fiscal terms, market and license constraints.
The process of reserves determination usually takes three steps. Firstly geologists, geophysicists and petrophysicists determine in-place volumes of hydrocarbons; then petroleum and reservoir engineers prepare a development plan; and finally economists perform economic analysis of the project by creating cashflow models encompassing production profiles and costs based on the development plan along with product prices and applicable fiscal, contract and license terms. Therefore reserves are determined as the summation of the production profile up to the economic limit (Figure 2).
There are numerous economic criteria used to assess the commercial attractiveness of a project, the most commonly used are:
• Payout/Payback time - length of time after initial investment until accumulated net revenues are equal to the total investment.
• Profit to Investment Ratio (PI) - ratio of total (undiscounted) net revenues to investment.
• Net Present Value (NPV) – sum of discounted cash flows (annual amounts of cash expended or received) for a given discount rate over the life of the project.
• Internal Rate of Return (IRR) – the discount rate at which the project’s NPV has a zero value.
When a company evaluates a project it looks at all four factors but NPV is the most important one. A project would add value to the company only if its NPV is positive at a certain discount rate acceptable for the company. To calculate NPV it is necessary to determine annual cash flows during the life of a project. Calculation of annual cash flows involves estimation of revenue, capital costs, operating costs, and taxes.
UNDISCOUNTED CASH FLOW = REVENUE - COSTS – TAXES
Revenue is amount of production sold times price received per unit of production.
Costs include all payments during financial period for exploration expenses, development expenses, operating costs, overhead, etc.
Taxes include any royalties, special taxes on petroleum, local taxes and profit taxes.
While determination of revenue and costs is fairly straightforward, tax calculations are usually more complex. A contract may involve a variety of different taxes and payments, some of which are regulated by the country’s taxation code and some are contract/project specific and are usually subject to negotiations between a company and the host government. The most common fiscal terms would include royalty, bonus payments, special petroleum and local taxes, and corporate (income) taxes and are discussed below.
Royalty = Revenue x Royalty Rate
Royalty is a payment to the host country government for the use of the natural resources. Royalty can be set as a percentage of the revenue or as a fixed amount charged per barrel (tonne). The latter type of royalty is rare, it is known as an “export tariff” and still exists in some NIS countries. Payment of royalty has a regressive effect on a project’s profitability and can cause production to become uneconomic prematurely. Calculation of royalty depends on the point of valuation of produced hydrocarbons, i.e. whether at the wellhead or in the market. Some fiscal systems allow a netback of transportation costs. This occurs when there is a difference between the point of valuation and the point of sale. Transportation costs from the point of valuation to the point of sale are deducted (netted back). Royalty rate (%) is either set as a single fixed rate or as a sliding scale of rates applied to either incremental or total production. Payment of royalty can be taken either in kind or in cash.
Bonus payments are usually defined in the contract and often subject to negotiations. There are three main types of bonuses: signature bonus, commencement of production bonus and production bonuses. Signature bonus is paid upon finalisation of negotiations and contract signing. Commencement of production bonus is paid at production start-up. Production bonuses are paid upon achieving certain production levels or reaching milestones in cumulative production.
Corporate Tax = Chargeable Income x Tax Rate
Chargeable Income =Company Revenue – Tax Deductions – Tax Loss Brought Forward
Tax Deductions =Royalty +Exploration Costs +Operating Costs + Depreciation + Interest
Corporate tax is levied on the company’s profits, its rate is usually defined in the host country Tax Code. The rate is usually between 30 and 38 percent but in some countries it can be as high as 50 percent.
Governments can enact legislation or issue decrees that are designed to attract additional investment. To make projects more attractive a government may introduce tax or royalty holidays, which specify that for a given holiday period royalty or taxes are not payable.
Production Sharing Agreements (PSA) are becoming more and more popular in the NIS countries. Investors prefer this type of contract because it gives them protection from changes in a host country’s legislation and fiscal regime, which may significantly affect profitability of their projects. The main features of a PSA are Cost Recovery and Profit Sharing, sometimes royalty is also present.
Cost recovery is the means by which the company (contractor) recovers costs of exploration, development, and operations out of revenues before sharing production with the host government. Most PSAs place a limit on cost recovery and specify types of costs allowable for recovery and the hierarchy of cost recovery. Unrecovered costs can be carried forward and recovered in succeeding years.
Profit sharing is the means of splitting revenues remaining after royalty and cost recovery between the contractor and the government. Numerous variations of the profit sharing process have been developed over the years. The division may take a form of a predetermined fixed rate or a sliding scale depending on the contractor’s after-tax IRR or R-factor (ratio of cumulative revenues to cumulative costs). The split in most countries ranges from 15 to 55 percent for the contractor. The contractor’s share of profit is usually subject to corporate tax.
The results of an economic analysis would define a project’s commerciality. Cumulative volumes of hydrocarbons forecast to be extracted up to the last year of commercial production would define reserves.
The INOGATE program provided further background to Kazakhstan’s oil and gas institutions on how economic evaluations are undertaken, giving examples from different published schemes that have been promulgated by organisations such as the American Petroleum Institute (API), Society of Petroleum Engineers (SPE), U.S. Securities and Exchange Commission (SEC), World Petroleum Congress (WPC), major oil and gas companies, and government bodies such as the Norwegian Petroleum Directorate (NPD) and Department of Trade and Industry (DTI) in the UK.
As noted above reserves are sensitive to both prices and costs. Fig 3 shows how oil prices have varied over the last 10 years and it can be expected that they will continue to show volatility in the future. Therefore understanding of the marginal cost of production is an essential planning tool. This can only be achieved by an economic evaluation of petroleum reserves.
II. Stock Exchange Requirements for Oil and Gas Reserves
The major stock exchanges that deal with Oil and Gas Companies have all developed reporting requirements to be used in any transaction and in public reporting. The principal Stock exchanges involved in these types of activity are the US Stock Exchange, the London Stock Exchange and the Toronto Stock Exchange. Of these the SEC for use in US Stock Exchange activities has developed the most detailed requirements.
In 1979, the SEC adopted a definition of Proved reserves to be used by all companies, which are listed on a US stock exchange. These definitions have become a critical consideration for most international oil and gas companies, as the U.S. exchange is the primary place of listing and financing. Since most oil companies are listed on US stock exchanges, and are required to use the SEC definition of proved reserves for external reporting purposes, they will generally also follow the slightly more restrictive (but very similar) definitions of the SEC for their internal evaluations. However, the SPE/WPC definition for proved reserves is widely used and accepted outside the USA for project financing and gas contract negotiation purposes, and there are ongoing efforts to make the two the same. The SEC definition for proved reserves is as follows:
“Proved oil and gas reserves are the estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made.”
The primary differences between this and the SPE/WPC definition is that the SPE/WPC use the term current conditions rather than existing conditions in defining the economic limit. «Current conditions» means that proved reserves must be estimated without any assumptions with respect to possible future improvements in economic conditions (prices, costs), or technology, or regulations (licence term, fiscal system, environmental limitations, etc) based on averaging period. For example, no escalation of the current oil price can be assumed in establishing the economic limit of production. The SEC definitions requirement is to use prices and costs «as of the date the estimate is made». Thus, it is not allowable to take an average of the prices/costs over a preceding period, e.g. 12 months, as is the case for SPE/WPC definitions.
The London Stock Exchange (LSE) definitions for Proved (Proven) reserves are as stated below.
Proven reserves are those reserves which on the available evidence and taking into account technical and economic factors have a better than 90% chance of being produced.
These definitions must be used when publishing a prospectus in the UK to raise new capital through a share offering.
The key phrases, which distinguish, proved reserves from reserves in general are «reasonable certainty» and «current economic conditions, operating methods and government regulations». The term «reasonable certainty» has caused much discussion in the industry as to its precise meaning, and there is evidence that in some cases an interpretation of «most likely» has been incorrectly applied. Since the 1997 SPE/WPC definitions are the most widely used in the international industry, they are worth reviewing in some detail. They are also the most detailed definitions in extensive use.
Reserves are those quantities of petroleum, which are anticipated to be commercially recovered from known accumulations from a given date forward.
This is the fundamental definition of reserves. It requires that reserves (of any category) must be:
• «Commercially recoverable»;
• «From known accumulations» (i.e. discovered); and,
• «From a given date forward» (i.e. remaining to be recovered at that date).
The terms proved, probable and possible are very widely used in the international industry. However, in North America they are generally kept separate, with «increasing uncertainty» being more consistent with «increasing risk». In contrast, in many other parts of the world the terms are combined to capture the range of uncertainty in the overall estimate of reserves, with proved (1P) being the «low» estimate, proved plus probable (2P) as the middle or «best» estimate, and proved plus probable plus possible (3P) as the «high» estimate.
Since all estimates are subject to uncertainty due to inadequate information, any new information, whether technical or commercial, can impact the reserves estimate. In particular, and perhaps surprising to those accustomed to the FSU culture, reserves estimates can change with changing oil price.
Where probabilistic methods are used, a complete range of uncertainty in the reserves estimate for the accumulation is determined using probability distributions for each of the input parameters. Consequently, appropriate values can be selected for any probability level. Thus proved reserves can be selected at the 90% level - this means that there is a 90% probability that the actual reserves will lie between this value and the estimated maximum feasible value. Similarly, values for 2P (50%) and 3P (10%) can be derived.
Once volumes have been produced and sold, they may not be considered as reserves by a company. If some of the produced volumes of oil and/or gas are used as fuel, flared, or lost due to processing in the production facilities (i.e. are not available for sale) they are usually excluded from reserves volumes. In some cases, however, volumes used on site for fuel are included in reserves on the basis that they have economic value to the producer. Kazakhstan oil and gas production versus consumption are shown in figures 4 and 5. Figure 6 shows how oil production (reserves depletion) and oil reserves increases have impacted Kazakhstan’s reserves position over the last ten years.
Generally, for proved reserves, the reservoir has to have actually produced hydrocarbons to surface at commercial rates. However, where good log and/or core data have been obtained which support the presence of commercially-recoverable hydrocarbons and there is a good analogy with a nearby reservoir which has flowed at commercial rates, it may be acceptable to assign proved reserves. The analogy should include similarity in terms of geological setting and reservoir properties.
Beyond the area defined by wells and fluid contact data, geological and engineering data can be used to extrapolate away from well control, to the extent that it is «reasonably certain» that such areas do contain commercially recoverable hydrocarbons. Normally this limit would be based on geological information about reservoir extent or reservoir performance data and would not extend into undrilled fault blocks. Throughout these definitions, references to geological data includes any geophysical information such as seismic data.
Where a fluid contact has not been identified in wells, the proved limit is the lowest level where hydrocarbons have been seen in the wells. Where there is some doubt regarding the possible presence of a gas cap, the highest known level will also be the limit of proved oil.
Where the facilities necessary to produce, process and transport the proved reserves to market have not been installed, there must be some evidence that this will be done in the foreseeable future.
For proved undeveloped reserves:
(1) The locations are direct offsets to wells that have indicated commercial production in the objective formation;
(2) It is reasonably certain such locations are within the known proved productive limits of the objective formation;
(3) The locations conform to existing well spacing regulations where applicable; and,
(4) It is reasonably certain the locations will be developed.
Reserves for other locations are categorized as proved undeveloped only where interpretations of geological and engineering data from wells indicate, with reasonable certainty, that the objective formation is laterally continuous and contains commercially recoverable petroleum at locations beyond direct offsets.
Reserves which are to be produced through the application of established improved recovery methods are included in the proved classification when:
(1) Successful testing by a pilot project (or favourable response of an installed programme in the same or an analogous reservoir with similar rock and fluid properties) provides support for the analysis on which the project was based, and
(2) It is reasonably certain that the project will proceed.
III. Unitisation and Redetermination
Unitisation is an issue, which must be addressed by governments and companies in virtually every geological province around the world. It encompasses both technical and commercial issues associated with resource evaluation.
Where a field crosses some surface boundary or boundaries, which separate two or more different entities (groups of licences, governments) with rights to the petroleum beneath those areas, unitisation is the mechanism by which the field may be developed as a single “unit”. It is a common problem throughout the world, and approaches vary but recent practice (particularly in the offshore environment) has tended to follow the extensive experience of the situation in the North Sea over the last 20 years or so.
In virtually all countries, including Kazakhstan, the State owns the sub-surface resources. The principal exception to this is the U.S.A, where the landowner holds the rights to any mineral deposits beneath that land.
The State has a duty to ensure that its resources are used wisely, which means that it should ensure that oil and gas field developments lead to the maximum economic recovery of hydrocarbons, hence the general requirement for State approval of development plans. Usually, and especially offshore, a cross-boundary accumulation can be developed more efficiently if it is done as a single integrated project.
In the U.S.A., as supported by the Westmoreland case in 1889, the Rule of Capture was deemed to apply. This case contended that petroleum was like a wild animal and that if it crossed your land, you had ownership of it while it was on your land. This led to very inefficient drilling, with landowners drilling many wells close to the boundary with their neighbours in order to maximise their recovery from a field – this was frequently detrimental to the overall recovery from the field. Subsequently, recognising the damaging effect on the ultimate recovery of petroleum, most States enacted regulations with imposed constraints on well spacing and/or production rates during the primary recovery phase.
Formal unitisation is often unnecessary until the later implementation of a secondary recovery scheme to enhance the recovery (e.g. waterflood). In the North Sea, many fields have been formally unitised. Even though accumulations have tended to decrease in size over time, the continuing reduction in licence size (due to ongoing relinquishments) has led to an increasing number of fields requiring unitisation. Further, several fields which cross international boundaries (e.g. U.K./Norway/Netherlands) have been unitised and the process is now well established and can be used elsewhere in the world.
It is generally recognised during the appraisal phase that an accumulation crosses a boundary (though it will, in most cases, require at least one well on each side of the boundary to prove it extends across it). At this point, negotiations begin and there may be a pre-unit agreement to cover the activities leading up to unitisation (e.g. sharing of appraisal costs). The key point is the approval of the development plan. In order to prepare and support a single integrated plan, which has some chance of achieving government approval, a unitisation agreement must have been agreed by all parties at the same time. Subsequently there may be redeterminations (where the proportion of the field each side of the boundary (or boundaries) is re-assessed). Normally, the unitisation agreement will also cover the operating agreement for the unitised field, and will be termed the Unitisation and Unit Operating Agreement (UUOA). A UUOA is very similar to a Joint Operating Agreement (JOA), though it is extended to cover the specific issues pertaining to unitisation and redetermination.
An example of a field in Kazakhstan where unitisation may be applied is the giant Karachaganak field. Kazakhstan contains up to 83 trillion cubic feet (Tcf) of natural gas and more than 40% of these reserves are located in the giant Karachaganak field (Northwest Kazakhstan), an extension of Russia’s Orenburg field. In 1997, an international consortium consisting of Agip (32.5%, Italy), BG (32.5%, U.K.), Texaco (20%, United States), and Lukoil (15%, Russia) signed a $7 - $8 billion final production sharing agreement to develop the field for 40 years, with a planned investment of $4 billion by 2006. The fact that this field extends across an international boundary and has Russian participation on both sides would be a factor in considering unitisation, together with identifying the optimum field development plan.
With a declining population (Figure 7) Kazakhstan’s primary energy demand has decreased (Figure 8) and in particular for oil (Figure 9). However, demand for gas is starting to increase. In the coming years Kazakhstan needs to adopt international standards in the estimation of its reserves so that it can continue to attract foreign investment and also so that when privatising state owned companies it can realise appropriate returns on the international markets.
Economic Development of Kazakhstan and Policy of the National Bank at the Current Stage Grigory Marchenko
Forging Partnerships for the new Millenium - the First Privately-owned Intergrated Oil Company in Kazakhstan and the Leader in the Refined Products Market
Kazakhstan - Resource Management Boris Zilbermints, Ian Dunderdale
Changes in Kazakh Legislation and the Interests of Foreign Investors in the Oil Sector Alexander Lesser
Interview for our magazine has been given by the Counsellor of the Embassy of the Federal Republic of Germany Jorg G. Metger