Ghana has no Gas Policy yet preparations are seriously underway in developing the sector, in its bid to provide alternative policy views, Supported by Star-Ghana, ACEP organised a nationwide fora to educate stakeholders on the way forward. Below we pushed edited version.
With a Policy yet to be launched how will the industry be governed?
Media Consultant Seibik Bugri reports
Introduction
“Ensuring an adequate and secure supply of natural gas is fundamental to improving the availability and cost of power in Ghana. A delay in the set-up of gas supply costs Ghana US$ 1million per day of additional oil purchases. This is a fast incentive for the government to move new gas developments forward as fast as possibly” says the World Bank.
The bank adds, “Commercializing natural gas requires knitting together a complex set of contracts governing the purchase, sale, transportation and processing of gas. These must align with the interest of differing interest holders in the various links of the value chain”. It is to this end that Civil Society as major stakeholders make input to governments’ plans to advance the energy sector. But government say it is up to the task.
One of Ghana’s foremost civil society organisations and policy think tank - African Center for Energy Policy (ACEP) held a series of fora nationally focusing on policy options for Ghana’s fledging gas sector development being undertaken by government to present evidenced-base research findings it carried out to assist government chart a more-people centered and environmentally -friendly policy development. Below policy altenativess.
Findings
The three main policy objectives were to: Encourage new investments in the exploration and development of natural gas in a competitive manner, Promote domestic uses of gas as a means to adding value and transforming the economy as well as promoting clean energy development and prevent the environmental effects of energy resource development. ACEP notes that to achieve the above objectives, the following strategic options should be considered:
Fiscal Incentives.
A Gas policy requires designing an appropriate legal, regulatory contractual and fiscal framework with sufficient incentives relative to oil. Fiscal terms should encourage associated gas utilization investments: Special fiscal treatment of associated gas investments may be needed to overcome the high up-front capital cost and (relatively) poor economics of associated gas utilization projects. Tax laws must provide more specific fiscal clauses on gas with the aim of introducing more favourable terms for gas activities as the profitability of gas projects is frequently lower relative to oil projects for two main reasons: first, gas operations are often more costly especially for gas processing and transportation infrastructure; and second, gas is sold at a lower equivalent caloric value than oil.
The nature of fiscal incentives for gas depends greatly on the type of upstream petroleum contracts used by the country. Thus, the following tools may apply:
Under concession agreements, reduced royalty rates for gas.
Under production sharing agreements (PSCs), where most of the fiscal differences between oil and gas are of a contractual nature through more favorable cost recovery schemes and production split terms applicable to the investor in the event of gas production.
The fiscal adjustments for gas versus oil production may concern lower royalty rates and more favourable conditions for the investor regarding cost recovery ceiling and profit gas sharing. However, natural gas liquids including condensate are in most cases considered as oil for fiscal purposes under the tax law and contracts. In some countries, special provisions are provided in the legal and regulatory frameworks to encourage investments.
These include:
Extended exploration period – including a retention period of up to 7 years – and exploitation duration,
Royalty reduction along with the right to negotiate specific non-associated gas development and exploitation agreements.
Introduction of a “retention lease” for allowing the exploration permit-holder of an oil or gas discovery to benefit in specific cases of a longer exploration and appraisal phase for discoveries.
Introduction of “retention development period” to allow the permit holder to identify and secure market for discovered gas. And that the possibility of joint gas development projects combining the resources and infrastructure with third parties is encouraged “to jointly develop or complete an access agreement for use of facilities or technology which provides an acceptable rate of return.”
Any government response,
Develop Domestic Infrastructure
The regulatory and fiscal framework governing such downstream infrastructure should meet at least three objectives:
Grant sufficient incentives to the investor in order to reach a fair and reasonable return on the equity it intends to invest in the project;
Prevent the creation of monopoly situations in any segment of the gas supply chain, and protect the third parties’ users of such facilities and the end-consumers of gas from monopolistic situations. Thus, there should be open and non-discriminatory access to infrastructure, including gas processing and transmission facilities, and to electricity grids (to sell electricity produced on-site from associated gas)
Encourage reasonable tariffs and conditions of access for the use by third parties of the infrastructure facilities existing along the supply chain, and for the sale of gas to the end-consumers.
To encourage domestic use of natural gas, some policies are provided such as:
Domestic market supply obligation for gas, the joint development of separate gas fields. Often the need to aggregate the production of several gas fields, sometimes from various producers, in order, first, to reach the minimum gas reserves and production thresholds for justifying the construction of the required processing and transportation infrastructure and, second, to produce enough gas over a long-time period to interest the potential gas users. To that end, the petroleum law and the petroleum agreements should contain a special provision on joint development by several agreement-holders. This concept is different from the customary “unitization provision” which only concerns the joint exploitation of fields crossing the borders of a permit. The joint development clause goes beyond unitization as the fields covered by such clause may be separate and spread over a relative large area covered by more than one permit.
Gas flaring and venting should be prohibited through the following:
Developing a comprehensive package of actions regarding technical and operational rules prohibiting flaring and venting along with measures for promoting gas utilizations projects.
Encourage commercial projects for using associated gas to prevent flaring.
Examine the solutions to reduce CO2 emissions in each segment of the oil and gas supply chain.
Re-inject gas when such re-injection is justified for maximizing oil recovery and thus increasing oil production. This re-injected gas is not lost and can be produced at a later stage.
Flare and venting regulation should be clear, with effective monitoring and enforcement. The right market conditions and investment incentive schemes should be complemented by flare and vent regulation in order to challenge operators to consider every gas utilization option.
Reduction in legacy flaring requires a comprehensive and methodical approach. A generally accepted approach to address legacy flares and vents is to, create an environment enabling gas utilization investments, establish a realistic flare/vent-out deadline, coordinate operators’ investment programs, and closely monitor them to ensure that they are implemented on time. Developing these flare reduction programs should be a cooperative approach in consultation with key stakeholders, particularly the operators.
Appropriate Gas Pricing Policy.
The strategy of focusing on the development of the gas domestic markets when economically justified by the opportunity of obtaining higher net back gas prices from local markets than from exports is optimal in terms of revenues and benefits for the country. As a result of the relatively high costs incurred in the entire gas export supply chain, either in long-distance pipelines or under an LNG scheme, the economic value and the opportunity costs for the gas produced and consumed locally is often higher than exporting it when dealing with highly populated countries where large domestic gas markets can be developed.
Ghana is a gas-limited country, therefore priority should be given to the domestic uses of gas and the constitution of the so-called “gas national reserves” required for covering with sufficient security the long-term local gas requirements, authorizing exports of any additional available gas when such reserves are identified.
Gas prices depend on its uses and differ between different regional markets. Thus, a Gas Pricing Policy must deal with different pricing systems for the domestic sector, the industrial sector (such as fertilizers, methanol, GTL, etc.) and the commercial sector (such as cement plants, steel factories, etc.).
To encourage investment in gas development, there should be a more favourable gas pricing policy designed to offer to producers for new discoveries a higher minimum gas price than the current gas prices applied to the local sales remaining however lesser than import prices.
Natural Gas Liquids
A gas field development plan should maximize the economic extraction and sales of condensate and other natural gas liquids (NGLs) contained in produced gas because such NGL sales may significantly increase the economic value of gas and therefore facilitate the global profitability of gas projects.
When Ghana becomes a gas market limited country, gas exports may be justified. In this case, different options for gas development and transportation projects are opened. Infrastructure for exports includes pipelines and LNG facilities. There are different legal and regulatory rules governing pipelines and LNG facilities.
For an LNG infrastructure, the categories include:
Segmented scheme - under which the LNG plant is considered as a distinct project along the gas supply chain, outside the scope of the upstream activities and therefore not covered by the producer’s upstream gas agreement. The feed gas for the LNG plant is purchased to the upstream gas producers by the LNG plant owners at a negotiated price and the produced LNG is directly sold by such plant owners to third parties or affiliates. Examples are LNG plants in Equatorial Guinea, Yemen or Malaysia.
Tolling scheme - under which the gas producers signed a tolling contract with the separate LNG plant company and then sell to third parties or affiliates the LNG generated by the plant. The LNG plant company may have share-holders different from those participating in the upstream activities, or with different percentages of participation than in upstream activities. The LNG plant is operated as an industrial project subject to a fiscal regime different from the upstream one. Such a scheme is fully appropriate to common user LNG facility, such as the Browse plant in Australia, the LNG plants in Egypt or Trinidad and Tobago, which may be used by third parties paying a toll tariff for processing gas.
The integrated scheme - combining within a same unit the upstream activities and LNG plant operations. This scheme requires that the same entities hold identical participating offshore development and production.
ACEP Policy Options
In designing the market structure and regulatory framework for Ghana’s domestic gas markets, the following questions will serve to guide the policy options that must be considered,
Who are the Industry Players?
What is the fiscal Regime for Natural Gas Exploration and Exploitation?
How will the market link Local Gas Distribution Companies (LDC) to the end users?
Should Ghana opt for bundled or unbundled service structure among different stages of the supply chain (Transmission, distribution, marketing, storage, etc)?
Which Secondary Market(s) should be developed initially?
Should the Local Gas Distribution Companies be governmental entities or private firms or public/private entities?
Should the LDCs have exclusive rights to build and operate the network in designated zones or for designated consumers?
What should be the basis for LDCs to acquire rights of way or other land for creating a distribution network?
Who should have the authority to grant licenses and permits to Transmission and Distribution entities and what are the procedures to be used for licensing?
Who should be responsible for monitoring quality performance of Gas Distribution Companies?
Who should be responsible for setting tariffs for gas transportation through transmission and distribution?
What tariff design or tariff structure should be adopted?
Industry Players
The gas industry players define the supply chain for the industry. For Ghana’s purpose, our gas supply chain covers the following players: Exploration and Production Companies, Transportation/Transmission Companies, Distribution Companies, Marketing Companies/Traders, Operators of Storage Facilities and Consumers.
Fiscal Regime for Gas Exploration.
The fiscal regime for natural gas production is the same as oil except that the royalty rates for natural gas are lower than those of oil. There is already a form of competition in production because concessions rights are granted to different companies who have the right to produce once discovered and are satisfied with the requirement of regulations provided by PNDC Law 84. However, the procedure for granting concession rights is not competitive. It is based on an open door policy but bids are evaluated on financial and technical grounds. The Ghana National Petroleum Company (GNPC) has no monopoly in production but remains a shareholder on all petroleum production licenses. It is recommended that competition should be deepened in this segment by introducing open and competitive bidding process for concession rights.
Transmission Services
The Ghana National Gas Company (GNGC) has been mandated to build and own pipelines, buy, transport and sell gas. The GNGC therefore has exclusive right across the supply chain. Thus, under the current arrangement, the GNGC is operating as a vertically integrated company and also operating as a monopoly in the purchase of gas from producers; a natural monopoly in transmission; a monopoly in the sale of gas (Marketer) and a distributor to the power plants.
This follows the practice of countries that are building their gas industry for the first time. A close example is Mexico where at the inception of its gas industry, PEMEX was the only agency ‘’authorized to build, operate, and own pipelines, as well as the only one with the authorization to import, export, and commercialize natural gas in national territory’’. However, evidence shows that this vertically integrated structure resulted in limited domestic exploitation of natural gas for the domestic market as major investments in exploration and exploitation of gas reduced as a result of low investments. This also limited investments to expand the distribution network to serve industrial and residential consumers. The poor distribution system led to increased gas flaring from associated gas. The difference in Ghana is that there is enough market for Jubilee gas for power production, but with increasing potential from Sankofa and other recently discovered fields, the need for an investment friendly market structure cannot be overemphasized.
Transmission pipelines are currently being constructed by the GNGC from the Jubilee Fields to the Gas Processing Plant at Atuobo. The GNGC is also constructing a distribution line from the processing plant to Takoradi to supply gas to the thermal power plants in Takoradi.
It is recommended that the natural monopoly of the GNGC should be broken in the following ways:
There should be unbundling of Transmission from Distribution and marketing;
A state company should be a natural monopoly in transmission and shall own a transportation network for the supply of gas to the domestic market and for exports. It can also undertake limited distribution (vertical integration) where it already has distribution lines. However, in the long-term, it should embark on disincorporation from its distribution to end its vertical integration. The West African Gas Pipeline is operated under the West Africa Gas Pipeline Act which should continue for purposes of imports based on long-term contracts to industrial and power plants in Tema.
GNGC should not be responsible for buying and selling gas. Gas purchases should be opened to marketers and producers should be free to enter into Gas Sales arrangement with marketers and bulk consumers. Thus, some bulk consumers can be connected direct to the transportation network.
The GNGC should grant open access based on Third Party Access (TPA) to producers, marketers and bulk consumers, who shall pay a regulated tariff to transport their gas. Therefore, producers should not be granted the right to build transportation pipelines unless it is in partnership with the GNGC who shall operate the facilities. Tariffs on transportation lines are set by the Public Utilities Regulatory Commission as prescribed in Act 538.
Distribution Services
The distribution market is the most complex in the industry. The decision to introduce competition or regulated monopoly in the distribution system should depend on whether the projects are Greenfield or not. Greenfield projects require new investments, which are difficult to raise where there is competition because investors in the gas industry usually prefer exclusivity. However while zonal monopolies are preferable, there can be competition at different levels as follows:
LDCs should be private companies licensed to operate in the domestic gas market.
LDCs must be given permit and exclusive right to construct their pipelines in approved zones or to approve consumers to ensure quality and standardization across the country. Granting of exclusive rights must be done through a competitive tendering process. Duration of exclusivity should depend on implied tariffs for consumers, risks and amount of investments. Exclusivity should be time bound preferably 15 years and subject to renewal but renewal should require a Public Hearing as it pertains in Canada. The Energy Commission by Act 541, 1997 has authority to grant licenses to distribution companies. But tariffs on distribution lines are set by the Public Utilities and Regulatory Commission by Act 538.
There are two different ways of linking LDCs to end users – monopoly on distribution pipelines and operations; and competition for the market. In the first scenario, LDCs are given the right to build and operate distribution pipelines and also to market gas to end users. In the second scenario, ownership and operation of pipelines are unbundled from marketing of gas. In this case, marketers shall be given open access to distribution pipelines (commercial bypass) based on regulated tariffs set by the Public Utilities and Regulatory Commission. To ensure competition, there should not be physical bypass for companies that want to build and operate distribution pipelines for their own consumption. This can be allowed only when existing distribution lines have insufficient capacity. The holder of a distribution concession may benefit from the following rights: to acquire land; to acquire a right to use the maritime domain; and to expropriate.
The right to build and operate a distribution pipeline should also comply with Environmental Laws and regulations of the EPA, the Water Resources Commission, the Ghana Standards Authority, etc.
There should be a sanctions regime for concession and permit holders who flout the terms of their concessions or permits.
Regulatory Frameworks
The main objective of a regulatory framework is to promote efficiency through competition and maximize social welfare. Maximizing social welfare depends on two opposing elements: providing incentives to accelerate infrastructure development and mechanisms for reducing pricing pressure on consumers.
The primary objectives of the regulatory policy however are to:
Develop infrastructure based on policy measures regarding exclusivity and vertical integration
Regulate market power using pricing and tariff regulation
Promote competition through market liberalization and open access to services
The following are important regulatory considerations that underpin the development of natural gas markets for the domestic gas industry. Permit regime, vertical integration, open access, market control and regulatory institutions.
Permit Regime
Issuing permits should be the fundamental regulatory instrument for regulating and enforcing standards. This also provides certainty to investors. Regulators grant permits in order to ensure technical and economic uniformity in projects across the country. Market players including the Transmission Company, Local Distribution companies (LDCs), Marketers and Operators of Storage facilities must obtain permits issued by the Regulator to undertake their activities. Permit duration varies across the supply chain depending on the level of investments and the expected tariffs required for recovering cost of investments. Permits are issued for building and operational standards and follows concession rights. This must take into consideration legal aspects of a permit as well as technical aspects including project engineering, location, safety, and emergency measures; and economic aspects, such as information of the party providing the financing for the project and the commitment and responsibility for it, in order to decide if the permit is to be granted or not.
Vertical Integration
This permits companies to operate two or more segments of the supply chain. In this case, there is usually a dominant state company that has transmission and distribution pipelines especially where the markets are not developed and investments are low. However, other market participants may come in as marketers. Thus, there can still be competition in the secondary market for capacity by marketing firms and bulk consumers. Private firms can also be allowed vertical integration where they have the resources to invest and can compete effectively. For example in Germany, where most of the gas industry is privately owned, marketers also own and operate pipelines. There are also countries that have prohibited vertical integration including Argentina and Colombia. In their case, transmission companies are not allowed to market gas and cannot own and participate in distribution.
Open Access
Open access is a mechanism used to limit market power of transmission and distribution companies and ensure competition aimed at consumer satisfaction. Transmission companies must allow open access to their networks by producers, marketers and bulk consumers. Distribution companies must also allow consumers open access to buy gas from marketers. The competitive conditions that are introduced through open access ensure efficiency in the marketing of gas. This has been confirmed by the experiences in the United States, Canada and Argentina. However, open access is limited by capacity especially if the capacity is already booked over a longer time contract. Where there is capacity, transmission and distribution companies must provide non-discriminatory access or be sanctioned by regulators. Most of the reformed gas producing countries like Mexico, Algeria and Brazil, have open access clauses in their gas regulations.
Market Power
Gas marketing (also referred to as trading) is usually the most competitive segment of the supply chain. It is associated with low sunk cost because the main requirement in this segment is working capital which enables marketers to enter into contracts with producers and consumers. Marketing is made possible when there is open access to pipelines or where commercial bypass is allowed. Where a pipeline owner also does marketing, capacity constraints could undermine competitive marketing.
Gas Marketers’ main activities include gas purchases from producers, transporting gas through transmission lines and distribution lines where applicable, and selling gas to consumers. In some countries like Algeria, gas marketing is done by authorization. In Mexico on the other hand, gas marketers do not require authorization. Also, in Algeria due to authorization of gas marketing, basic information is provided as a mandatory requirement on gas sale contracts including for instance the name of the buyer and the quantity of gas sold as well as the price.
Regulatory Institutions
There are different types of regulatory authorities in the regulation of gas markets. There are those who are independent as against semi-autonomous regulators. There are also those who regulate legal and technical standards in the industry through licensing and issuing of permits as against those who regulate tariffs and quality of service.
In countries such as the United States, Argentina, Canada, Great Britain and Colombia, the regulators are not only independent but combine the regulations of both legal and technical matters as well as tariffs and quality of service. Great Britain and the United States have strong autonomous regulatory institutions empowered with regulatory instruments and financial independence. They are typically concerned with prices and tariffs, permits and contracts, and overseeing safety, service quality, and environmental matters.
Ghana has a regulatory regime in which two institutions have responsibility for different regulations. The Energy Commission regulates legal and technical standards and is semi-autonomous, whilst the Public Utilities and Regulatory Commission, an independent body, regulates tariffs and quality of service.
Contractual Framework
The following are some of the agreements that are signed in the gas market.
Gas sales and purchase agreements signed between the gas producers and the buyers of the gas. They provide for the long-term sale by the seller to a buyer of certain annual quantities of natural gas, delivered at a given point of the gas supply chain for an agreed price generally subject to an ad hoc indexation formula. Such contracts often last between 15 to 25 years and contains an obligation of “take or pay” for the buyer.
Gas balancing agreements for allocating under lifted gas between the producers of a gas field when joint selling is not possible.
Gas transportation agreements dealing with pipelines. They provide for the annual contractual quantities to be transported, the capacity reservation and the determination of the tariffs along with a “ship or pay” obligation for the shippers.
Current Regulations
Ghana has three-tier regulatory framework for gas industry. These include the Ministry of Energy responsible for policy making, the Energy Commission responsible for licensing and formulating technical standards; and the Public Utilities Regulatory Commission for tariff setting and quality performance.
The Energy Commission
The Commission was established under Act 541, 1997 to plan, regulate, manage and develop energy supply and utilization in Ghana, with the basic functions being:
To advise the Minister on national policies for the efficient economical and safe supply of electricity, natural gas and petroleum products having due regard to the national economy;
Prepare, review and update periodically indicative national plans to ensure that all reasonable demands for energy are met;
Secure comprehensive data base for national decision making the extent of development and utilization of energy resources available to the nation;
Receive and assess applications, and grant licenses under Act 541 to public utilities for the transmission, wholesale supply, distribution and sale of electricity and natural gas;
Establish and enforce in consultation with the PURC, standards of performance for public utilities engaged in the transmission, wholesale supply, distribution and sale of electricity and natural gas;
Promote and ensure uniform rules of practice for the transmission, wholesale supply, distribution and sale of natural gas; pursue and ensure strict compliance with this Act and regulations under this Act;
The Commission has responsibility for issuing licenses for gas transmission, distribution and Marketing (wholesale) activities. This includes licenses for building and operating pipelines and other gas infrastructure.
The Commission is also to issue regulations governing the domestic gas market. Some of the regulations already issued by the Commission are:
Rules of Practice for Natural Gas Public Utilities
Standards of Performance for Natural Gas Public Utilities
Safety Regulations
Other institutions that have roles to play in gas industry regulations in Ghana are: The Ghana Standards Authority, the Environmental Protection Agency, Water Resources Commission, Forestry Commission, Lands Commission and the Ghana Fire Service.
Public Utilities and Regulatory Commission (PURC)
The Commission is an independent Commission established by an Act of Parliament (Act 538) to regulate and oversee the provision of utility services (water, electricity and natural gas). The main responsibilities of the Commission are to:
Provide guidelines for rates to be charged by utilities.
Examine and approve rates to be charged by utilities for services provided
Monitor standards of performance for provision of utility services
Protect interest of both consumers and providers of utility services
Promote fair competition among public utilities
The key tariff considerations for gas by the Commission include:
Ensuring full cost recovery of reasonable and efficient costs
Encouraging efficiency through performance targets
Providing incentives for operational efficiency
Ensuring financial viability of LDC(s)
According to the Commission, the tariff structure for gas will be single and cost reflective of future consumption (i.e. long-run marginal cost based tariffs); whilst postage stamp tariff approach will apply to secondary gas transportation. To ensure financial viability of gas utilities, the Commission seeks to provide full coverage of cost–based on efficiency benchmarks; as well as a reasonable rate of return to cover debt service obligation and agreed reasonable investments.