Since the development of the Akosombo Dam in Ghana, generating power has progressed through several phases, beginning with diesel generators as well as stand-alone electricity supply systems operated by industrial mines and factories, then to a hydroelectric phase, and currently to a thermal transition stage powered by natural gas and/or light crude oil.
In addition, a growing severity of the country’s energy problem has become a recurring development concern in Ghana, threatening the country’s economic growth and transformation.
The worrisome rationing system, the slowdown in industrial activity, the loss of jobs and money, and the disturbance of social life are all stark reminders of what now seems to be a perennial burden on Ghana’s socioeconomic progress.
Ghana wants to industrialise, modernise its agriculture, and offer economic possibilities for its 28.2 million population, which is expected to continue to increase in the next decade. One of the most important obstacles to realising this goal is the inconsistent and expensive supply of electric power, as well as the sector’s substantial financial deficit. Despite the fact that Ghana has more over 5,000 megawatts (MW) of installed generating capacity, actual availability seldom surpasses 2,400 megawatts (MW) owing to fluctuating hydrological conditions, insufficient fuel supply, and outdated infrastructure. Ghana is well-positioned to solve these challenges because of its abundant natural gas reserves and use of renewable energy sources to produce power but there are issues that require immediate attention.
Due to the growth of the Ghana’s oil and gas industries, as well as the expansion of the services sector of the economy, which currently accounts for nearly 50% of total economic activity as measured by GDP, Ghana has seen fast growth since 2010. Increasing power consumption, which has grown at a rate of 7-10 percent per year since 2010, according to Ghana Energy Commission data, has been a catalyst for this growth. When comparing 2018 – 2021, the peak demand in Ghana increased by more than 10 percent year on year to 2,613 megawatts (MW), representing a 10.2 percent year on year increase. Access to sustainable power remains a primary challenge impacting commodities and businesses negatively in Ghana currently. It’s been reported that the country during the power crisis between 2006 – 2016 lost over 6 percent of its GDP on a yearly basis due to insufficient wholesale power supply. In 2020, the system peak recorded was 3,090 MW, up from 2,804 MW in 2019. This represents an increase of 10.2% over 2019 system peak demand, and a slightly higher than (by 0.9%) the system peak of 3,061 MW8 projected for 2020
The cost of producing electricity may account for more than 30 percent of total company production expenses in certain Sub-Saharan African nations, while typical losses due to electrical interruptions can account for as much as 16 percent of total yearly sales, according to estimates. This factor may be much higher in the case of micro, small, and medium-sized businesses, which account for more than two-thirds of all employment.
Due to the detrimental impact on company operations caused by insufficient power supply, businesses in many industries have been forced to decrease production and reduce employment as part of cutting down cost. Other negative effects of a shortage of power include high youth unemployment, rising rate of crime, as well as a general sense of despair among the population, which may culminate in anti-government demonstrations. Ghana’s competitiveness within the West African sub-region may be weakened therefore, decreasing the appeal of the country as an investment destination, particularly as a manufacturing centre.
Ghana has traditionally relied heavily on hydroelectric power from the Akosombo Dam to supply base production capacity, but unpredictable weather patterns beginning in the mid-1980s and continuing to the present day have forced a change in the country’s energy strategy. Since the 1990s, policy advancements have been oriented toward the growth of thermal energy to increase generating capacity while also increasing energy security. Several independent power producers (IPPs) have been hired by the government of Ghana under a public-private partnership (PPP) model to construct and operate thermal power plants to supplement the country’s current electricity production. Light crude oil, heavy fuel oil, and natural gas are all used in the operation of these thermal plants, which run on single or dual cycle combustion mechanisms.
Insufficient natural gas supplies led Ghana considering the possibility of creating new generating medium in order to meet the growing demand for power production and household consumption in the country’s growing economy. Since 2007, the finding of substantial natural gas resources has altered the dynamics of the gas supply, leading Ghana’s authorities to explore using these natural gas resources to accelerate inclusive economic growth and development. Some small-scale sustainable energy explorations were promoted and brought online at the same time, significantly diversifying the nation’s energy supply. Combined with the relatively high electricity tariff for non-residential and industrial users (which has prompted the installation of more cost-effective alternate solution), Ghana has reached a point where there is more than enough supply to meet the country’s current consumption needs. This poses a basic question: how has Ghana’s energy system been affected by the transition from hydroelectric to thermal power in terms of energy security, energy equality (accessibility), as well as environmental sustainability since the transition? Which variables, both global and local, will have the most effect on the growth of the Ghanaian electrical markets, as well as the difficulties and dangers that prospective investors and host governments will face?
Impact of COVID 19 on Energy Demand in 2020
Many sectors, notably Ghana’s energy industry, saw significant upheaval in the year 2020. Several factors contributed to this, including the breakout of COVID-19 in 2020 and the resulting shocks to the economy and work programmes of key industrial players. Although the energy industry had a good year, it could have been better.1 Over the previous year, peak load increased by 10.2 percent in 2020, compared to the previous year. Peak Load in 2019 rose by 11.0 percent as compared to the previous year. This indicates that COVID-19 had little impact on load, since there has been no substantial change in the load trend since the beginning of the year[1]. Figure 1 depicts the trends in domestic peak load for the years 2020, 2019 and 2018. Peak demand increased by 2 percent in 2020 compared to the same time in 2019 shown in Fig 1.
Fig. 1: Comparison between peak energy demand between 2016 – 2020.[2]
The shorter period of lockdown in 2020 (i.e., March 30 to April 20) was seen to be more effective (8 percent increase in the peak load over that of 2018). This shows a relatively stunted increase in load, which may be ascribed to decreased activity in the industrial and service sectors as a result of the COVID-19 epidemic. The decrease in energy production that occurred as a result of the lockout’s inception was quickly reversed after the removal of the lockdown. This may be partially attributable to the electricity relief announced by the government on April 11, 2020, with companies attempting to take advantage of the respite in order to save money. Installations of electric power generating capacity rose from 3,795 megawatts in 2016 to 5,288 megawatts in 2020, a 39.3 percent increase, with reliable capacity rising from 3,521 megawatts in 2016 to 4,842 megawatts in 2020.[3] In 2020, the energy mix was relatively steady, with hydroelectricity accounting for 29.9 percent of total installed capacity. In 2020, conventional thermal plants accounted for 69.0 percent of total installed capacity, with renewable energy sources accounting for 1.1 percent of total installed capacity shown in Figure 2. Since 2015, thermal energy has overtaken hydroelectricity as the most important source of power production in Ghana. In the year 2020, total energy production in the nation, including embedded generation and import, was 20,229 GWh, indicating an 11.2 percent increase over the total electrical generation in the previous year.[4] The total generation at the transmission level (excluding embedded generation and import) reached 19,659 GWh in 2019, representing a 10.6 percent increase over the previous year’s generation level. Combined domestic and export consumption of energy reached 18,829 GWh in December, an 8.9 percent rise over the same month in 2019 and 4.3 percent less than the anticipated demand of 19,685 GWh for the whole year. It was 16,974 GWh of energy that was supplied13 to the nation for domestic use in 2019, representing an increase of 8.7 percent over the previous year according to the Ghana Energy Commission
Regulatory bodies in charge of power generation in Ghana
The Ministry of Energy is responsible for the administration of Ghana’s power sector, which includes the development coupled with implementation of energy policies, monitoring and evaluation, as well as coordination of other government departments and institutions.[5] The Public Utilities Regulatory Commission of Ghana (PURC) and the Energy Commission are the two regulatory organisations in charge of the industry (EC) (Fig. 3). Public Utilities Regulatory Commission (PURC) is an independent agency established by the Public Utilities Regulatory Commission Act, 1997 (Act 538) to regulate and monitor electricity prices while also encouraging retail and wholesale competition. The EC shown below, on the other hand (which was established by Act 541), serves as the licencing body for service providers in the electricity and natural gas downstream sectors.
Fig. 3: Regulatory body in charge of harnessing energy in Ghana.
The Volta River Authority (VRA), a state-owned corporation with a market share of about 49 percent, is in charge of power production, which is supplemented by a number of independent power producers (IPPs).[6] As of December 2020, VRA had a combination of hydroelectric, thermal, and renewable power plants with a total installed capacity of 2,520 MW, which is a portion of the total installed capacity of 5,172 MW. VRA had extra responsibility for electricity transmission before to 2006, but under the current regulatory structure, this has been taken over by Ghana Grid Company Limited, which was established in 2006. (GRIDCo). GRIDCo is the only operator of Ghana’s electrical transmission network, and it charges a transmission fee to customers that want to transmit energy via its system. Southern Ghana is served by the Electricity Company of Ghana (ECG), whereas northern Ghana is served by the Northern Electricity Distribution Company (NEDCo).[7] In southern Ghana, electricity distribution is handled on a zone basis. ECG serviced the majority of Ghana’s demand centres, which were concentrated in the Accra-Tema, Kumasi, and Takoradi enclaves. In 2019, ECG was responsible for providing about 90 percent of the electricity bought in the country. It is important to note that both ECG and NEDCo are state-owned enterprises that fall under the jurisdiction of the Ministry of Energy. Its highly centralised organisational structure, combined with political involvement in operational choices, has led in a dismal track record in terms of revenue collection, mismanagement, and significant technical losses, which are believed to account for 25 percent of the total electricity bought.
Multiple stakeholders are involved in the generation of electricity in Ghana. The state-owned Volta River Authority (VRA) owns and operates the Akosombo Hydro Power Station, the Kpong Hydro Power Station, and the Takoradi Thermal Power Plant (TAPCO), all of which are located in the Western Region at Aboadze. As a minority joint partner in the Takoradi International Power Business (TICO) thermal plant, also situated at Aboadze,[8] VRA is also a minority shareholder in the Takoradi International Power Company (TAQA), a private sector company. Virtual reality applications now account for about 50% of the total energy delivered to the power grid (compared to 88 percent in 2010). Independent power producers (IPPs) such as Sunon Asogli, CENIT, Karpower, AKSA, and Cenpower, among others, account for the remaining 40% of total electricity production.[9]
Ghana’s Thermal Capacity till date
Ghana has had two power crises in the last two decades, notably in 2007 and 2014-2016, during which power supply failed to keep up with demand, resulting in load-shedding, which is known locally as ‘dumsor’ or on-off electricity. The building of the 400 MW Bui hydroelectric power station, which was financed by China, was one of the outcomes of the 2007 financial crisis. The crisis of 2014-2016 was also handled by increased IPP investments by the previous government, which promised to add 3,800 MW of mainly new thermal capacity within five years, mostly via new construction. Amid concerns about electricity availability, the NDC government acquired the following IPP emergency power contracts:
Karpowership: This was obtained as an emergency power badge from Turkey in order to momentarily alleviate the country’s then-current power shortage. The badge, which has a capacity of 450MW, was originally powered by Heavy Fuel Oil (HFO), but it is currently powered by natural gas after its towing from Tema to Takoradi.
Power from AKSA Enerji: The 370 MW plant in Tema, Ghana, was constructed by Turkey’s Aksa Enerji and is powered by Heavy Fuel Oil (HFO) under a five-year build, own, operate, and transfer (BOOT) agreement with the Ghanaian government.
The Africa Middle East Resources Investment Group (Ameri) is working on the following project: This is also a 250 MW combined-cycle gas turbine emergency plant operating on a short-term BOOT agreement for a period of up to five years at the time of writing. When the PPA conditions were later changed into normal IPP terms, it was possible to prolong the contract for an anticipated 15 years of operation. Located near Aboadze, in the Western Region, this natural gas-powered facility operates on a renewable energy source.
Early (Bridge) Power Project: This is a proposed 450 MW project with consortium partners comprising Sage Petroleum Limited Ghana and US-based Endeavor Energy and General Electric (GE). The plant is in Tema. LPG will be used as the primary feedstock fuel for the plant for the first five years before switching to natural gas as its primary fuel once it becomes available.
Aside from that, the ‘dumsor’ issue prompted a quest for more affordable sources of fuel for thermal energy production. Ghana has found substantial associated and non-associated gas resources from the Jubilee, TEN, and Sankofa fields throughout the course of the decade, which has had a major impact on the country’s fuel supply dynamics. Through the mid-2020s, domestic gas is expected to satisfy Ghana’s base-case demand; however, LNG imports will be required starting in the mid-2020s (Gas Master Plan, 2016). After being brought online in 2016, the TEN and Sankofa fields significantly increased gas supply and energy security via the Atuabo gas processing facility, which is now fully operational. If this were to happen, it would mean that imports of natural gas from Nigeria via the West Africa Gas Pipeline (WAGP), which have traditionally been unreliable and inefficient, would be a thing of the past. The fact that certain facilities in the Tema-enclave, such as Sunon Asogli, were dependent on WAGP supplies was despite the fact that the nation’s domestic gas could not be transported from the western half of the country to demand centres in the east.[10] With the discovery of large quantities of natural gas in the Western region and the majority of power plants in the Eastern region (Tema), the establishment of a connection between the west and east was necessitated in order to facilitate the transportation of fuel to the power plants in the eastern region. In this vein, Ghana completed the Takoradi–Tema Interconnection Project (TTIP) in August 2019, which reversed the flow of gas from Takoradi to Tema through the Western African Gas Pipeline (WAGP). It is now possible for the West African Gas Pipeline Company Limited (WAPCo), the company that operates the WAGP, to transfer natural gas from its western to its eastern terminus at the request of clients – both power and non-power demand consumers. The Ghana National Petroleum Corporation (GNPC), the country’s state-owned oil corporation, provided funding for the reverse flow project in Ghana. In addition, Ghana is exploring LNG import options to help meet the country’s medium-term gas demand increase. A floating storage and regasification unit with a capacity of 250 million standard cubic feet (mmscf) per day is scheduled to be built and available for use by the end of 2021 as part of the Tema LNG project. With the signing of a 12-year agreement between the Ghana National Petroleum Corporation (GNPC) and Rosneft for the supply of LNG, it is estimated that the Tema LNG project will be able to supply an expected 75 million standard cubic feet per day of LNG to meet the country’s growing demand for fuel for power generation.
Analysis of Tariff Pricing
Ghana’s Power Sector Reform Programme (PSRP), which began in 1995 and was completed in 2000, envisaged the establishment of the Public Utilities Regulatory Commission (PURC) as the body responsible for setting tariffs in order to ensure competition and international best practises in the power sector. PURC was established under Section 2 of the Public Utilities Regulatory Commission Act, 1997 (Act 538), which established the Commission. The governing board of the Commission is comprised of representatives from various stakeholders, including the Trades Union Congress, the Association of Ghana Industries (AGI), domestic consumers, and other persons with knowledge in the Commission’s areas of responsibility. However, political actions taken in response to public agitation over energy price increases, as well as restricted consultations in general on pricing issues, have often hampered the Commission’s ability to carry out its mandate effectively. It is important to note that the shift from hydro to thermal power production has significant consequences for the economics of electricity generation, namely how electricity is priced and, ultimately, how much electricity is charged to end-users. Supply is usually provided by two kinds of plants: Type 1 plants, which offer baseload to meet the underlying demand at the lowest possible level based on a daily demand schedule, and Type 2 plants, which provide peak or mid-merit load. Plant Type 1 has high fixed capital expenditure (capex) and low marginal operational costs because they often utilise comparatively cheaper fuel sources, while Plant Type 2 has lower fixed expenses but higher marginal operational costs since they regularly use more expensive fuel sources. The power purchased by the government via the IPPs is generated by Type 2 plants that use thermal generating as a fuel. Although Type 2 facilities, such as the Akosombo hydroelectric project, provide more flexibility and dependability, their generating costs are higher than those of Type 1 plants. The arrangement of various plant types, as well as their placement on the merit-order, has an effect on the tariffs charged to end users. Using natural gas as an example, the projected fuel costs in 2019 for using combined-cycle generation were US$7.4-8.84 per MMBtu and US$13.79 per MMBtu for light crude oil (LCO) (Table 2). Heavy fuel oil (HFO) and diesel were projected to cost US$9.68 per MMBtu and US$18.73 per MMBtu, respectively, according to the estimates.
The Automatic Adjustment Formula
As part of the computation of end-user rates, Ghana has been using the quarterly AAF, which was first adopted in July 2002 and subsequently updated in 2011.[11] When determining tariffs, the AAF takes into account the fuel mix (crude oil, natural gas, distillate fuel), the Ghana Cedi-US dollar exchange rate, the hydro-thermal generating mix, changes in the consumer price index, demand prediction, and chemical costs. The final power tariff build-up consists of four schedules, each of which is described below. Because to government intervention in the market price-setting process under the pretext of absorbing the price markup instead of passing it on to end-users under-recoveries in the energy sector, the AAF was not completely implemented until 2011. The tariff pricing system as a result failed to incentivize electricity producing firms (both state-owned such as VRA and other IPPs) to generate economic returns while simultaneously assuring investments in equipment to ensure energy security. Because of this inefficient market system, it has become difficult to collect the entire amount of operating expenses incurred, since there is no assurance that the price established by the PURC would accurately represent costs. It has been attempted to resolve this imbalance via the existing Public Utilities Regulatory Commission (PURC) pricing system; the cost of electricity production, excluding distribution and transmission service costs, is lower than typical end-user rates.
Bulk-Generation, Transmission and Distribution Tariffs Analysis
The Bulk Generation Charge (BGC) is defined as the weighted average rate at which electricity distribution companies (DISCos)30 purchase energy from generation sources in connection with their activities in the regulated market under the first schedule. 31 In this region, the generating sources include IPP thermal generation and VRA hydro, with the latter being much less expensive. It has been less than US$0.10 per kWh since 2014, and the composite BGC sources account for 54 percent of the overall cost composition. This rises to more over US$0.15 per kWh when transmission and distribution service costs are added on top of the BGC, representing an almost 100 percent increase in cost. The Transmission Service Charges (TSC) in the second schedule, which are due to GRIDCo, the operator of the National Interconnected Transmission System (NITS), are the next item to be included after the BGC. Prior to December 2015, Ghana charged a single Transmission Service Charge (TSC) for all energy transferred. This practise was decoupled when a new line item under the second schedule, known as Ancillary Service Charge, was introduced in December 2015. (ASC). Customers that purchased energy from IPPs directly, with the exception of ECG, were subject to the ASC requirement. “Voltage control, operational reserves, black-start capabilities, and frequency control” were all to be paid for with the funds. In 2013, ASC was imposed at a rate of about US$0.80 per kWh (GHp 3.15 per kWh) for three years, until it was abandoned and replaced in 2017. Transmission Service Charge 1 (TSC 1) and Transmission Service Charge 2 (TSC 2) were introduced in 2018 to further isolate the TSC into two distinct categories (TSC 2). TSC 1 is the rate charged to GRIDCo to recover the cost of its transmission network operations (which includes a regulatory fee), while TSC 2 is the rate payable to GRIDCo to recover transmission losses (which does not include a regulatory levy). As can be seen, an effort has been made to identify which transmission costs are attributable to network operations and which transmission costs are attributable to transmission losses. Both of these are presently taken into consideration when calculating tariffs. GRIDCo, the National Interconnected Transmission System (NITS) operator, collects the Transmission Service Charges (TSC), which are the next item after the BGC in the second schedule. The Transmission Service Charges (TSC) are paid to GRIDCo, which operates the National Interconnected Transmission System (NITS). Prior to December 2015, Ghana charged a single Transmission Service Charge (TSC) for all energy transferred. This practise was decoupled when a new line item under the second schedule, known as Ancillary Service Charge, was introduced in December 2015. (ASC). Customers that purchased energy from IPPs directly, with the exception of ECG, were subject to the ASC requirement. “Voltage control, operational reserves, black-start capabilities, and frequency control” were all to be paid for with the funds raised. In 2013, ASC was imposed at a rate of about US$0.80 per kWh (GHp 3.15 per kWh) for three years, until it was abandoned and replaced in 2017. Transmission Service Charge 1 (TSC 1) and Transmission Service Charge 2 (TSC 2) were introduced in 2018 to further isolate the TSC into two distinct categories (TSC 2). TSC 1 is the rate charged to GRIDCo to recover the cost of its transmission network operations (which includes a regulatory fee), while TSC 2 is the rate payable to GRIDCo to recover transmission losses (which does not include a regulatory levy). As can be seen, an effort has been made to identify which transmission costs are attributable to network operations and which transmission costs are attributable to transmission losses. Both of these are presently taken into consideration when calculating tariffs. Overall, transmission charges account for a very tiny portion of the overall cost of ownership (averaging 11 percent of the total costs). It is the third schedule in the tariff build-up architecture that contains Distribution Service Charges (DSC).
Once again, before the introduction of a Distribution Wheeling Charge (DWC) in 2016, Ghana used a single DSC for all energy delivered. DWC is the fee that third parties, such as bulk consumers, must pay to the DISCos (ECG and NEDCo) in exchange for the use of their networks. Third parties that have negotiated their supply with a wholesale provider are obliged to pay the DWC in accordance with the liberalised market rules of supply negotiation. 33 This guarantees that DISCOs get paid for the cost of service incurred as a result of the use of their infrastructure to transfer electricity from one grid to another. This is, in effect, the cost of providing energy to these types of consumers that is borne by a third party. In 2018, the DSC was further separated into two line items: Distribution Service Charge 1 (DSC) and Distribution Service Charge 2 (DSC2) (DSC 2). It is the DSC 1 rate that DISCos charge to recover the cost of distribution network operations, while DSC 2 is the rate that DISCos charge to recover the cost of distribution loss recovery operations. To be qualified to pay DSC 1 to the DISCo, bulk consumers must be embedded in the distribution network, but they must also acquire and pay in full for the entire cost of energy bought from the wholesale market (including TSC 1 and TSC 2), according to the Public Utility Regulatory Commission. The DSC 1 and DSC 2 (the DWC) are paid by bulk customers who purchase electricity directly from a DISCo rather than through a generating company. In essence, bulk customers who purchase electricity directly from a generating company pay DSC 1, which is used to recover the cost of distribution network operations, excluding distribution losses, and DSC 2 (the DWC). Power customers, on the other hand, pay both DSC 1 and DSC 2, which are referred to as DWC, with the latter covering distribution losses and the former covering transmission losses. Since 2014, DSCs have represented an average markup of 67 percent above the cost of bulk production. Despite the fact that these distribution costs are being collected, there is a continuing failure to reduce distribution losses in Ghana, which remain at or around 25% of total electricity bought in the country today.
Retail Electricity pricing
Since 2000, annual electricity end-user prices in Ghana have increased by an average of 9.6 percent per year, rising from US$0.024 per kWh in 2000 to US$0.14 per kWh in 2019, a trend that reflects the country’s increasing diversification of its generating mix from hydro to thermal over time. While there has been growth in cedi terms, the rate has been around 22 percent per year, which also reflects the ongoing devaluation of the local currency (the Cedi) in relation to the dollar.[12] Interestingly, average energy end-user prices have decreased by about 30% during 2016, to approximately US$0.15 per kilowatt hour. This is mostly due to the introduction of new domestic gas sources as well as the renegotiation of some of the costly emergency IPP contracts that were purchased to alleviate the power crisis, which has resulted in a reduction in the overall cost of power supply in the country. Ghana’s differential tariff pricing is shown in much more fascinating and nuanced detail when tariffs are broken down by various customer classes. Residential users (divided into four groups depending on usage from 0-50 kWh to 601+ kWh) pay the lowest end-user rates, with an average of US$0.14 per kWh from 2014 to 2020, according to the Energy Information Administration. This is in addition to an average monthly fixed service or access fee of US$1.19, which is charged on a recurring basis. Commercial clients (who are likewise divided into four groups depending on their consumption from 0-50 to 601+ kWh) pay an average end-user price of US$0.23 per kWh and a fixed monthly service fee of US$2.32 in addition to a fixed monthly service charge of US$2.32. High voltage (HV) customers, excluding mines, pay on average US$0.15 per kWh in the Special Load Tariff (SLT) category, followed by medium voltage (MV) customers at US$0.16 per kWh, low voltage (LV) customers at US$0.21 per kWh, and lastly high voltage -mines (HV-Mines) at US$0.31 per kWh. All SLT clients are also subject to a service fee, which averages US$9.27 for LV and US$12.98 for MV, HV, and HV-mines, respectively, and is collected by SLT. Current tariff structures in Ghana reflect the growth of the country’s electrical market, which is comparable to trends in other Sub-Saharan African nations, while also providing varied treatment for various types of consumers. There are a variety of tariff features available to do this, including schedules for big customers, hourly pricing, demand charges, sectorspecific tariffs, and block tariffs, among others. Although non-residential customers, SLT-LV and SLTHV mining users in Ghana pay much higher rates than the supplied cost of electricity, which is $0.15 per kWh in Ghana, this is not the case in other countries. A summary of the prospects and challenges of the Ghana power sector is summarized in Fig. 5 and Fig. 6.
Article by:
Tabbi Wilberforce Awotwe (Ph.D)
Lecturer in Mechanical Engineering, Aston University, Birmingham, UK
Email: t.awotwe@aston.ac.uk
Member – NDC UK/Ireland Chapter
