Net WAGP economic benefit requires Ghana development

Aug. 27, 2007
Ghana needs to complete its domestic pipeline infrastructure before start-up of the 470-MMcfd West African Gas Pipeline if the country is to take full advantage of the new high-volume access to natural gas WAGP will provide.

Ghana needs to complete its domestic pipeline infrastructure before start-up of the 470-MMcfd West African Gas Pipeline if the country is to take full advantage of the new high-volume access to natural gas WAGP will provide. Although the initial pipeline systems to be laid are small and therefore can be constructed fairly quickly, there will inevitably be delays associated with acquisition of rights of way, the import of equipment, or other contingencies.

Ghana also must finalize commercial arrangements between industrial users and the supply company and between the supply company and both the West Africa Pipeline Co. and natural gas producers in Nigeria. Beyond the foundation volume, no agreements for additional volumes for Ghana exist, even as demand for Nigerian natural gas grows both domestically and internationally.

Natural gas that will flow to Ghana through WAGP offers a competitive and clean alternative to current fuels, especially for power generation and industrial purposes. The ability to absorb foundation volumes when the pipeline starts operating is important in keeping down the cost of natural gas for all users. No incentives, however, are necessary to induce industrial users in Tema and Takoradi to switch to natural gas from oil products, so long as oil prices stay greater than $30/bbl.

In addition to the typical industrial uses of generating heat or steam, natural gas also opens up the possibility of economically competitive cogeneration of electricity, helping Ghana meet its electrification goals more quickly, reliably, and cheaply. Reduced demand for oil products will also help equalize Ghana’s trade balance, as payments for oil imports go down, and, in the long-run, may even help Ghana become an exporter of oil products if its refining capacity is expanded.

This article examines the factors affecting natural gas’ large-scale introduction to the Ghanian energy market both in preparation for and upon WAGP’s entering service.

Background

Natural gas is to start flowing from Nigeria through WAGP to Benin, Togo, and Ghana later this year. Ghana will buy 75% of the line’s 134 MMcfd start-up volume and initially use the gas primarily as feedstock for the Takoradi thermal power plant in the country’s western region (Fig. 1). The 550-Mw plant will provide a foundation market for Nigerian gas in the region. Initial demand from the plant will total 100-110 MMcfd, enough to generate 5 Tw-hr of electricity at 85% utilization. Plans call for the plant to be upgraded to 660 Mw.

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Other industries in Tema and Takoradi, Ghana, are early candidates for switching to natural gas from oil products. As elsewhere in the world, natural gas provides a fuel that is cleaner, more efficient, and more stable in pricing than oil products, allowing its use not only for typical industrial purposes but also for generating on site electricity either for self-sufficiency or backup.

Cogeneration of heat-steam and electricity maximizes natural gas’ energy content. The sale of excess power to the national grid from cogeneration or self-generation facilities can also improve system reliability and lower electricity costs.

Once industrial and electrical demand in Tema and Takoradi has been met, however, Ghana offers little else in the way of small commercial or residential demand. Laying pipelines to serve dispersed residential and small commercial customers will yield an expensive service per unit of natural gas, testing customers’ ability to afford it.

The most likely manner of providing natural gas to smaller users is the incremental expansion of pipelines in Tema to currently planned communities once the system to meet industrial demand has been put in place. This possibility lies at least 5-10 years in the future.

The transport sector is responsible for 21-22% of Ghana’s energy use, and accounts for 85% and 99% of diesel and gasoline consumption respectively, creating additional opportunities for natural gas use, particularly if oil prices remain high. Compressed natural gas is a low-cost alternative fuel for vehicles, especially in countries that have a gas infrastructure. CNG vehicles are roughly 10% more efficient than gasoline vehicles and are as efficient as diesel fuelled vehicles.

Evaluating the potential natural gas penetration of Ghana’s industrial and transportation sectors requires looking at the demand structure in each sector and estimating both cost of distribution infrastructure development and final cost of delivered gas to end users, relative to their current fuel supplies

Potential demand for natural gas by industrial and other large users is limited in Ghana. Tema and Takoradi, with their concentration of industrial activities, including the Tema oil refinery, Volta Aluminium Co., and Ghana cement works, provide the areas where pipeline systems can most easily be developed to allow industrial users to switch to natural gas early in the market development process. Past studies to determine natural gas demand in Tema and Takoradi have established a broad range of 4-20 MMcfd.

Takoradi and Tema also host Ghana’s only two international seaports.

Demand potential

Until Ghana builds a national natural gas pipeline network, introduction of natural gas into the economy will not necessarily displace all fuel-oil demand. Even absent such a network, however, natural gas will to displace about two-thirds of the country’s fuel-oil demand by 2020, especially in Tema and Takoradi, assuming industrial growth of more than 6%/year by 2020.

Ghana’s economic growth has exceeded 5%/year since 2003. Current government development plans call for the country to become a middle level developing country with real gross domestic product of $1,000 per capita by 2015, from the current level of about $600 per capita. This growth rate, however, would require expansion of more than 7%/year.

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Displacing this amount of residual fuel oil would require 8-14 MMcfd of natural gas in 2008 and as much as 23 MMcfd by 2020 (Table 1). If the necessary pipeline systems can be built in Tema and Takoradi, and industrial users in these areas switch to natural gas at expected rates, demand for natural gas in industrial heating could easily be closer to the 14-MMcfd end of the projected 2008 range.

Electricity

The industrial sector has accounted for 9% of the national diesel consumption demand on average since 2000. Industry uses diesel largely for backup power generation. Diesel consumption by industry rose to almost 97,000 tonnes in 2004 from about 61,000 tonnes in 2001. Based on diesel-demand forecasts provided by the Energy Commission of Ghana and Tema oil refinery, projected natural gas demand for backup generation, assuming it replaces diesel entirely, will exceed 20 MMcfd by 2020 (Table 2). Added to demand for heating, initial demand for natural gas in 2008 could reach 18-26 MMcfd.

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It may not be too meaningful, however, to talk about backup power in terms of daily demand for natural gas because backup generation does not have a constant demand. On days when the system is constrained or there are rolling blackouts, the need for electricity may be several times greater than the amount shown in Table 2. At other times, when the electricity from the grid is reliable, industry might use no natural gas at all for power generation.

This fluctuation in load may cause problems for the natural gas distribution company. Demand for storage could emerge, increasing the cost of gas. Industrial facilities could also retrofit their backup systems to be able to switch between diesel and natural gas, depending on the relative costs of each.

The best long-term option for industry, however, may be ongoing natural gas-fueled self-generation, or cogeneration, which would allow it to take advantage of cleaner, more efficient gas turbines for power while meeting heat and steam needs at the same time. Excess power could be sold back to the national grid, once Ghana fully implements electricity unbundling, easing the urgency of expanding generation capacity in the rest of the country.

Transportation

A city like Accra would need at least 5-10 CNG filling stations to make CNG-fuelled vehicles practical. Regulated vehicle conversion shops would also be needed.

The cost of 5-10 filling stations would total $5-10 million. Placing these stations efficiently along the roads would require expansion of the gas pipeline network as well, increasing initial investment and hence the cost of natural gas to everyone.

Private investors are unlikely to take such risks in the absence of a CNG fleet. Even assuming low-cost gas ($3-3.5/MMbtu) and high-cost oil ($50+/bbl), it would take 3-4 years for individuals to recover the cost of converting their vehicles to CNG.

Per capita income in Ghana ranges $450-600. The average Ghanian citizen is therefore unlikely to spend the $700 or more required to make the CNG conversion. Even those who can afford it would have to find the surrounding infrastructure convenient enough to make the change worthwhile. The likelihood of any large increase in demand for natural gas from the transportation sector is therefore low.

Secondary system

Addressing the demand potential described in this article requires timely development of pipeline systems in Tema and Takoradi and a low final cost of delivered gas to industrial users. Given the compactness of the distribution areas and proximity of most major potential customers, the local pipeline systems would be fairly short, consisting of a main trunk linking WAGP to a larger diameter backbone pipeline and smaller laterals feeding end users.

Major customers in the Tema and Takoradi areas would require two pipeline networks of roughly 20-25 km each in the early stages. These systems would be fairly quick and inexpensive to build. A discounted cash flow model using sensitivity analyses can calculate the per-unit cost impact of building distribution systems in Tema and Takoradi.

Economic assumptions

A system including all necessary pipelines to take natural gas from WAGP and deliver it to customers will most likely include a combination of steel and plastic pipes. Steel pipelines of 8-in. OD and greater are most appropriate for the section taking the gas from WAGP and bringing it to the service area, since the volumes will be relatively large and pressure will be high.

High-density polyethylene pipe of 4-6 in. OD will be most appropriate for laterals because it is far cheaper and easier and faster to lay. HDPE pipes have proven effective and durable for pressures less than 100 psi.

Steel pipes cost about $25,000/OD in./km. Value-added tax (12.5%), import duty (~10%) and port handling and haulage fees (~3.5%) will increase this cost by roughly 26%, to $31,500.

HDPE pipes cost about $3,100 and $4,200/OD in./km for 4 and 6-in. OD pipes, respectively. Including various taxes and fees, the total imported cost per inch becomes $4,000 and $5,300 for 4 and 6-in. pipelines, respectively.

The local distribution companies that this article assumes will be licensed to operate the Tema and Takoradi franchises will most likely generate revenues through charging tariffs to carry natural gas in their distribution networks to end users, rather than through sale of gas itself. The LDCs’ revenues will therefore depend heavily on the volume of gas they distribute.

A discounted cash flow model yields an optimum return on distribution tariff of 15% for each LDC. LDCs around the world are typically regulated and return 8-12%; but a higher rate in Ghana will make investment in these small systems attractive.

Several scenarios of various pipeline OD and lengths yielded a distribution tariff of similar magnitude. Only a summary of the results follows.

The base assumption for Tema includes a 22-km pipeline network consisting of 15 km of 6-in. HDPE pipe and 7 km of 12-in. steel pipe. The base assumption for Takoradi includes a 20-km pipeline network consisting of 5 km of 12-in. steel pipe and 15 km of 6-in. HDPE pipe.

These assumptions yield total costs of almost $2.4 million for Takoradi and $3.1 million for Tema. The estimate for Takoradi, however, does not include the cost of extending WAGP from the power plant to downtown Takoradi, about 15 km away. Building the additional 12-in. steel pipeline could double or even triple distribution tariffs unless demand for gas in Takoradi is much larger than initial estimates of 4-7 MMcfd.

Both networks can be constructed in less than 3 months. Using 6 and 12-in. pipelines, as opposed to 4-in. HDPE and 8-in. steel pipes, will lead to pipeline capacities that may not initially be supported by the market, increasing the capital cost of the infrastructure and leading to a higher distribution tariff for the same target rate of return of 15%.

Oversizing the pipelines makes sense on both engineering grounds and an optimistic view of future demand. Increasing size only adds incrementally to cost, as most other variables (rights of way, labor, equipment, etc.) are already covered, and adds the ability to accommodate future increases in load.

Calculating an upper limit for the distribution tariff is also desirable. If natural gas is competitive at this upper limit, it will also be competitive at lower cost. A 15% return requirement also helps establish this upper limit.

Tema network calculations assume initial natural gas delivery rates of 7 MMcfd, increasing 5%/year. The growth rate equals Ghana’s industrial growth rate since 2000.

Takoradi system calculations assume initial natural gas delivery rates of 4 MMcfd in 2007 and the same annual growth rate. These assumptions are fairly conservative, given initial demand estimates of 18-26 MMcfd. This analysis uses lower demand values to help establish the upper limits of the distribution tariff, so that improvements in switching and penetration rates will lead to declines in the tariff and make natural gas more attractive.

This analysis also calculates the cost incurred by new users of natural gas in installing or retrofitting the necessary equipment (burners, boilers, furnaces, etc.). Uniform average annualized cost for conversion-including investment, operation, and maintenance-total roughly $22,000. Conversion costs range between $0.005 and $0.06/MMbtu for consumption of 1-11 MMcfd of natural gas per customer.

Results

The distribution tariff for Tema equals $0.20/MMbtu. If industrial users in Tema are more enthusiastic about natural gas and switch quickly in 2007, for example at a rate of 12 MMcfd rather than 7 MMcfd, the tariff may fall to $0.12/MMbtu. Takoradi, a smaller system, will need a distribution tariff of $0.28/MMbtu. Increasing the initial load to 7 MMcfd from 4 MMcfd reduces the tariff to $0.16/MMbtu.

The starting load in 2007 is important, but even with low starting load and potentially oversized pipeline systems, the tariffs are not a significant component of the total cost of gas delivered through WAGP (Table 3). WAGP cost covers a wide range because the tariff is set to yield 12% on a foundation volume of 134 MMcfd and 15% for additional customers. To keep WAGP’s cost as low as possible, Ghana needs to be ready to take its share of the foundation volume, and preferably more, once WAGP is able to ship them.

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The gas cost range of $3.25-7.15/MMbtu leaves a lot of room for sensitivity to the price of oil. The higher the crude oil price, the more attractive a switch to gas becomes. The switch becomes less attractive to residual fuel oil users as crude falls below $45/bbl. Table 4 provides estimated costs compared to existing fuels at crude prices of $30, $45, and $60/bbl.

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The low end of the natural gas price range reflects a relatively high use of natural gas by Ghana in 2007, and the high end reflects a low-use scenario. As long as the oil price stays greater than $45/bbl, natural gas will remain competitive with oil products even in low-use scenarios. The more gas Ghana takes from the pipeline when gas starts flowing, the more competitive gas will be.

Even at oil prices of $30/bbl, gas can remain attractive to RFO users (Table 4), placing a premium on the readiness of distribution pipelines to serve industrial customers before WAGP starts delivering foundation volumes. New combined-cycle generation will produce electricity at roughly $0.045-0.075/kw-hr at a natural gas price of $3.25-7.15/MMbtu. A retrofitted Takoradi plant, however, should produce at rates $0.01-0.015/kw-hr cheaper because its prices would not reflect the capital cost of building a new facility.

Should industry decide to cogenerate, electricity generation costs would equal about $0.055-0.085/kw-hr, based on single-cycle gas turbine technology, making it less competitive to generate power than to buy it from the grid (Table 5). Most cogeneration units today, however, use more efficient combined-cycle technology.

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The value of heat-steam used by other industrial processes also figures into any accounting of relative costs, as does the increased reliability made available by self-generation. Finally, to the extent cogenerators can sell excess power into a market or to other users, they will reduce the cost of their own consumption even further.

These cost advantages make it easy to imagine cogeneration as competitive with electricity from the grid at $0.045/kw-hr. The accounting becomes even more straightforward for large commercial and service entities like hotels and cold stores; even at the high end, $0.085/kw-hr, the cogeneration prices are lower than the distribution tariff.

The authors

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Joseph Essandoh-Yeddu ([email protected]) heads the strategic planning and policy division of the Ghana Energy Commission, a regulatory body. He has more than 15 years’ experience in the energy sector of Ghana. He was the program manager for Ghana’s solar energy program until 1998 and led a national team that produced Ghana’s Strategic National Energy Plan 2006-20. He has been a member of Ghana’s negotiating team to the UN Climate Change Convention and the Kyoto Protocol meetings since 2005. Essandoh-Yeddu holds a BS in physics and an MS engineering degree in environment and energy from Chalmers University of Technology, Gothenburg, Sweden. He is currently pursuing a PhD at the University of Cape Coast, Ghana.

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Felix Ankomah Asante ([email protected]) is a senior research fellow and coordinator of the Resource Center for Energy Economics and Regulation at the Institute of Statistical, Social, and Economic Research, University of Ghana, Legon. He holds a PhD (2002) in development economics from the University of Bonn, Germany.

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Gürcan Gülen ([email protected]) is a senior energy economist at the Center for Energy Economics, Bureau of Economy Geology, Jackson School of Geosciences, University of Texas at Austin. Gülen comanages a 5-year cooperative agreement with the US AID, focusing on capacity building in energy sectors of emerging economies in Africa. He served as president, vice-president, and secretary of the Houston chapter of the US Association for Energy Economics 1998-2001. He is currently vice-president for conferences for the USAEE. Gülen received a PhD in economics from Boston College and a BA in economics from Bosphorus University, Istanbul.