ENERGY COMMISSION, GHANA 2020 ENERGY (SUPPLY AND DEMAND) OUTLOOK FOR GHANA April 2020 i EXECUTIVE SUMMARY The Energy Commission in fulfilment of its mandate under the Energy Commission Act (Act 541, 1997) presents supply and demand forecasts for electricity, crude oil, petroleum products and natural gas for the year 2020. Electricity 1. As at the end of 2019, the installed electricity generation capacity available for grid power supply at the transmission level in the country was about 4,990 Megawatt (MW). The installed capacity increases to 5,171.6 MW if primary embedded generation, including the two major solar power plants at the sub-transmission (distribution grid) level are added1. This was about 4.2% expansion over the installed capacity in 2018. 2. Total grid electricity generation in the country including the embedded generation2 was 18,187.9 Gigawatt-hours (GWh), comprising 39.9% hydro, 59.8% thermal and about 0.3% solar power. It was about 12.2% more than in 2018. 3. Including imports, the grid electricity at the transmission3 level, was around 17,886.8 GWh comprising about 7,251.6 GWh (40.5%) from hydro generation, 10,507.8 GWh (58.7%) from thermal generation and about 127.4 GWh (0.7%) of import. It was about 12.1% increase over gross transmission in 2018. 4. Peak load on the transmission grid excluding export4, i.e. the maximum capacity utilised within the country was 2,612.6 MW; roughly 10.2% more than in 2018. The system (maximum including exports) peak i.e. the maximum capacity utilised on the transmission grid was 2,803.7 MW, which was about 11.0% more than in 2018. 5. The total dependable grid capacity 4,580.0 MW in 2019 was thus in excess of the Peak load by 1,776.3 MW. 6. In 2019, the average electricity end-user tariff was Ghp71.6 per unit of electricity (kilowatt- hour), an increase from Ghp70.5 per kilowatt-hour in 2018. 1 i.e. Trojan (44 MW), Genser (95 MW), BXC Solar (20 MW), Meinenergy (20 MW) and VRA Solar (2.5 MW). 2 i.e. Trojan, Genser thermal plants and the grid-tied solar plants 3 i.e. does not include embedded generation and solar since they are at the distribution grid level. 4 Referred to as Domestic Peak Load by some of the utilities ii 7. Average end-user tariff since the previous load shedding in 2007 to the beginning of the most recent load shedding in 2012 averaged up to Ghp17.0 per kilowatt-hour (kWh) whilst the average end-user tariff from 2013 to 2019 was Ghp57.3 per kWh. 8. The relatively high end-user tariff is likely to have contributed to the significant surge in the installation of alternative or captive or self-electricity back-up generation largely by the non-residential and industrial customers of the utilities. The said customers apparently found the self back-up generation more cost-competitive compared to the grid as their cumulative electricity consumption units exceeded 300 units per month during the year and thus making it more attractive for the switch at that consumption level. If this trend continues, it could worsen the income and profitability of the existing electricity utility companies. 9. With the Government’s projected real GDP growth of 6.8%5 and particularly 6.7% (non- oil growth), the total electricity required for the expansion of the country’s economy in 2020 is expected to be as follows:  19,594.4 GWh (with VALCO constrained to operate at most two potlines). Expected peak capacity demand required would lie within 3,115.2 MW. Average End-User tariff to make it realized should be within US cents 13-15 per kWh. This projection is achievable provided the following are accomplished: i. There is adequate financial resource to procure all the fuel needed to run the thermal power plants even at higher utilisation factors; and ii. Average end-user-tariff is reduced to within 13-15 US cents per kWh. 5 The World Bank and the IMF projects 5.6-6.8% for Ghana for 2020. iii Fuel for Power Generation 10. In 2019, total gas flow to the thermal power plants rose to about 65 million mmBTU (61,092 mmscf), almost 17.5% more than the supply of 2018; with about 36.6% coming from Nigeria (46% in 2018) via the WAGP and the remaining 63.4% (54% in 2018) coming from domestic gas, i.e. the Atuabo gas processing plant and Sankafo field. The average daily flows were about 61.3 mmscfd from WAGP and about 102.3 mmscfd from domestic gas. 11. For 2020, total gas available for power generation would be almost 107.6 million mmBTU largely coming from the local fields. VRA power plants are expected to receive about 44.4 million mmBTU (about an average of 140 mmscfd) whilst the IPPs receive the balance of 63.1 million mmBTU (about an average of 160 mmscfd). The expected WAGP gas flow would remain around 70 mmscfd throughout the year, whilst an average of 300 mmscfd could come from domestic gas during the year. 12. 1n 2019, the actual delivery price of the WAGP gas was $7.1/mmBTU and that of the indigenous gas was $6.8/mmBTU. 13. For 2020, delivery price of WAGP and domestic gas would be a weighted average price of $6.08/mmBTU . 14. In 2019, the total cost of gas for power generation was almost $455.8 million. 15. For 2020, the total cost of gas for power generation is estimated to cost almost $653.9 million. 16. In 2019, light crude oil (LCO) consumed by the thermal power plants for grid power production was about 913,648.1 barrels. 17. For 2020, no significant requirement for LCO should be anticipated, if high volumes of gas from Sankofa, Jubilee and TEN fields are realised and made available timely. Thus, only Cenpower is expected to operate on LCO. The estimated LCO for this power plant is 495,733 barrels. 18. In 2019, the average delivery price6 of LCO for power generation was $64.2 per barrel. 6 i.e. including transportation and treatment. iv 19. For 2020, it is expected that the average delivery price of the light crude would increase to about $85 per barrel. The total cost of LCO required would thus be about $42.14 million. 20. In 2019, total diesel consumed by the thermal power plants for grid power production as well as for starting and switching off the plants was about 79,606.5 barrels. 21. For 2020, it is estimated that the diesel required largely for the same exercise would remain the same and usage limited largely for starting and switching off the plants due to expected improvement in supply of gas and LCO which are cheaper alternative for power generation. 22. In 2019, HFO was largely used as fuel by the Karpower Barge and the AKSA power plant for electricity production. HFO consumed was about 2.5 million barrels and at an average delivery price of $65.4 per barrel. 23. For 2020, only AKSA power plant is expected to operate on HFO due to the relocation of the Karpower Barge to Takoradi to operate on gas. Thus, the estimated HFO required would be about 212,858 barrels (30,408.3 tonnes) at the average delivery price of $119 per barrel, bringing the total cost of supply to around $25.3 million. 24. In all, about $740.8 million would thus be needed to procure fuel for grid or public electricity generation. Crude oil and petroleum products 25. Ghana’s oil production in 2019 was about 72.1 million barrels coming from the three main commercial fields, Jubilee (45%), TEN (31%) and Sankofa-Gye Nyame (24%) compared to about 62.1 million barrels in 2018, representing an increase of about 15.0% over the previous year. Average daily production for the year was about 196,000 barrels as against 186,000 barrels in 2018, but still below the targeted average daily production of about 250,000 barrels. 26. In 2019, crude oil production from the Jubilee field again increased to about 32.6 million barrels from 28.5 million barrels in 2018. Corresponding average daily production, however, dropped from an average of 87,844 barrels in 2018 to 87,439 barrels in 2019. 27. For 2020, average crude production from Jubilee is likely to increase to within 90,000- 95,000 barrels per day. v 28. In 2019, total oil production from the TEN field dropped from 23.6 million barrels in 2018 to 22.3 million barrels. The corresponding average daily production equally dropped from about 64,000 barrels in 2018 to about 61,100 barrels. 29. For 2020, average daily crude production from the TEN field is expected to increase to the range of 65,000-90,000 barrels per day. 30. In 2019, crude oil production from the Sankofa-Gye Nyame field7 was about 17.2 million barrels, about 70% increase from 10 million barrels in 2018. Corresponding average daily production equally rose to 46,950 barrels from 27,500 barrels in 2018. 31. For 2020, the Sankofa field average daily crude production is expected to fall within the range of 48,000-50,000 barrels per day. 32. In 2019, the average price of Brent crude on the global market increased to $64.19 per barrel from about $71.5 per barrel in 2018, about 10.2% drop from the previous year. 33. For 2020, the average price at which Ghana would source Brent crude is expected to decrease from an average $58 per barrel to $30-32 per barrel due to the outbreak of coronavirus (Covid-19). The average price for other light crudes for refinery operations would also fall within $58-60 per barrel. Average delivery price for light crude oil for power generation would decrease from $85 per barrel to $43 per barrel. 34. In 2019, crude oil from the Jubilee field was sold at $63.8 per barrel ($70.6 per barrel in 2018). Those of the TEN and the Sankofa-Gye Nyame fields in 2018 were sold at an average price of $61.6 and $65.3 per barrel compared with $71.6 and $72 per barrel in 2018 respectively. 35. For 2020, average oil price from the Jubilee field is likely to drop to within $57-60 per barrel whilst those of TEN and Sankofa fields would also range from $52-57 and $60- $65 per barrel respectively. 36. In 2019, total petroleum products pumped into the economy increased to 4.1 million tonnes from 3.9 million tonnes in 2018 37. For 2020, total petroleum products required would continue to increase, ranging from 7 Also called OCTP (Offshore Cape Three Point) field vi 3.7-3.8 million tonnes, equivalent to 68,000-74,000 barrels per stream day refinery capacity. It would still largely comprise gasoline about 34-35% and diesel of about 46-47% (excluding products directly destined for the grid power generating plants). 38. In 2019, LPG supplied dropped to almost 340,000 tonnes from around 397,000 tonnes, about 14.4 percent lower than in 2018. About 80.9% was imported and the rest from local production. About 20% of the local supply came from the Atuabo Gas Processing Plant, which is producing LPG as by-product from processing the wet associated gas from the local fields into dry gas largely for electricity generation. 39. In 2019, about 770 tonnes (0.2% of supply) of LPG was exported, a drop from about 4,800 tonnes exported in 2018; 3% of total supply that year. 40. For 2020, the Government’s 6.8% GDP growth (6.7% non-oil) for the year would require 294,000-313,000 tonnes of LPG of which about 25% is likely to come from the Atuabo gas processing plant. Imports could still dominate since TOR is not likely to operate at full capacity largely due to financial challenges. There is still the growing demand for LPG as cooking fuel in homes and particularly as transport fuel. Natural Gas 41. Total indigenous wet gas produced in 2019 was about 140,853.67 mmscf coming from the three main commercial fields, Jubilee (36.4%), TEN (34.4%) and Sankofa Gye-Nyame (29.2%) compared to about 91,459 mmscf in 2018, representing an increase of about 54% over the previous year. 42. In 2019, wet gas exported from the Jubilee Field, TEN and Sankofa Gye-Nyame to Atuabo gas processing plant (Ghana Gas) was 20,689.05, 694 and 32,670 mmscf respectively. Thus, total raw gas receipt at Atuabo gas processing plant was 54,053.83 mmscf. 43. In 2019, about 56,118,413 mmBTU, representing 95% of the resulting processed (also called dry or lean) gas was shipped for power production whilst the remaining 5% was exported for non-power activities (fuel for industrial processing). 44. Total gas flow to consuming facilities in Ghana in 2019 was 75,798.75 mmscf. About 28.7% was from Nigeria via the WAGP and the remaining 71.3% coming from indigenous vii sources. About 42% of the gas was supplied to the thermal plants in the Tema power enclave, 54% went to the Takoradi power enclave and the remaining 4% went for non- power activities. 45. In 2019, average daily production of raw gas decreased from 137 mmscfd in 2018 to about 65 mmscfd. The Sankofa take-or-pay obligations have ensured that gas from the Sankofa Field is the first to be dispatched. This makes gas supply from the Jubilee Field interruptible. 46. In 2019, daily production of the raw gas from TEN fields decreased from about 93.7 mmscfd in 2018 to about 21 mmscfd in 2019. Just like Jubilee Field, the Sankofa take-or-pay obligations have ensured that gas from the Sankofa Field is the first to be dispatched, which makes gas supply from the TEN Field interruptible. 47. Daily production of raw gas from Sankofa field in 2019 increased from about 40 mmscfd in 2018 to over 88 mmscfd in 2019. Raw gas produced is processed at this field and exported through the Onshore Receiving Facility (ORF) to the Ghana National Gas Company (GNGC) pipeline to comingle with the other indigenous sources for power generation in Aboadze by VRA generation plants. 48. For 2020, the expected volumes of gas from OCTP and Jubilee fields are 180-200 mmscf/day and 100-120 mmscf/day respectively. 49. Given the availability of domestic gas, in 2020 priority will be given to usage of gas from the Ghana fields. Thus, we anticipate a daily average flow rate of about 73 mmscf/day, 24 mmscf/day and 180-200 mmscf/day from the Jubilee, TEN and Sankofa Fields respectively. 50. On the average, gas still remains the most sustainable and relatively cost-competitive fuel supply to produce affordable power in the country. The key challenges hampering reliability of gas supply are inadequate supply, particularly from Nigeria through the WAGP and finance (domestic and international payment deficits). Progress of Planned LNG projects 51. Two major liquefied Natural Gas (LNG) projects are currently underway: the Tema LNG Terminal Company and a small-scale virtual LNG pipeline project. 52. The Tema LNG Terminal Company project which is currently under construction is a viii Floating Storage and Floating Regasification Unit with expected capacity of 250 mmscfd, which is expected to be completed in 2020. The Tema LNG Project is expected to commence supply by the fourth quarter of 2020. Expected volumes from Tema LNG in 2020 is 75 mmscfd. 53. The small-scale virtual LNG pipeline is a virtual pipeline project to supply gas to Sunon- Asogli and Trojan power plants. Initial contract quantity is said to be 60 mmscfd. This project is currently on hold if not cancelled facing challenges with the supply of the LNG for the project. The source of LNG for the small-scale project is the LNG2Africa initiative; an Equatorial Guinea initiative to sell small-scale LNG for utilisation in Africa. Initial target countries are Togo, Burkina Faso and Ghana. Recommended Actions Ameliorating the overall power supply shortage 54. For 2020, Akosombo Generating Station would be required to operate four generating units during the off-peak period and up to five units during the peak period. This mode of operation is expected to result in operating capacity of up to 750 MW, which would ensure that the reservoir level is kept above the minimum operating level of 240ft (73.15m). This mode of operation would result in a projected minimum elevation of 255ft (77.7m) at the end of the dry season in 2020. It should be noted however that some thermal power plants will be rendered inoperable sometime in 2020, due to the WAGP Intelligent Pigging exercise that will curtail gas supply to Tema. As a result, all six units at Akosombo GS will be put in operation to ensure security of supply. 55. Kpong hydroelectric station, which is currently undergoing retrofit, would continue to run three out of the four total installed turbine units. Consequently, the total average plant output at the Kpong Station would remain at 105 MW. However, the retrofit is expected to be completed by April 2020 and all four units are expected to be available, increasing the dependable capacity of Kpong GS to 140 MW 56. 1n 2020, Bui hydropower plant is expected to operate an average of two turbine units throughout the year. This mode of operation would lead to a projected annual production of 764 GWh and is expected to ensure that its reservoir level would be about 5 metres ix above its target minimum level of 170 metres-high compared to its 168m-minimum operating level. It is estimated that for continuous and sustainable operation of the Bui Power Station for 2020 and for the subsequent years (in the likely event of low inflows), the reservoir level at the end of the dry season of 2020 should not drop below its 170 m elevation. 57. For 2020, as a result of the operations of the three hydropower plants, the expected total annual electricity generation from hydropower would not exceed 6,229 GWh. 58. Failure to adhere to the plan for hydropower production could significantly compromise reservoir integrity for subsequent years. 59. Crucial requirements for reliable power supply are the availability of the required plant capacities, quantities of fuel and funds to purchase the required fuel in a timely manner. 60. Inadequacy fuel when it is required and gas pricing remain the major risks to reliable electricity supply in Ghana. The present installed capacity is capable of generating over 25,000 GWh, which is enough to meet the country’s electricity requirement including suppressed demand, should there be adequate and cost-competitive fuel. The key challenge however is competitive grid electricity tariff. 61. The fuel supply challenge also has to do with financing besides technical constraints. It is therefore necessary to arrange to secure the needed funds to purchase the needed quantities of fuel on time. 62. Furthermore, there is also the need to pay off any indebtedness to fuel suppliers so that the required volumes would be obtained for thermal generation timely. Energy Sector Recovery Programme 63. Energy Sector arrears and debt situation was about $2.7 billion as at January 2018, and it was forecast that additional $1.3 billion will be added to this deficit in 2019. The sector arrears will grow to more than $12.5 billion by the end of 2023 if urgent actions are not taken. Most of the debt have been due to short term loan contracted by the power producers culminating in the ‘take or pay’ and the distribution utilities’ inability to collect adequate revenue to cover their operations. Also, persistent untimely and insufficient payments for x gas delivered also contributes to the huge debt burdens of the gas off-takers, most of them public entities. The Power subsector debt alone is increasing by about $300 million every quarter. 64. In order to address the chronic debt challenges and to facilitate equitable distribution of all cash collected in the power sector value chain using the end user tariff as a basis, the Cash Waterfall Mechanism (CWM) concept was instituted in 2016. It is expected to be operational in 2020 and implemented through the development of a formula, for adequate distribution of revenue to all stakeholders in the power sector value chain. 65. Further, the Energy Sector Recovery Program (ESRP) outlined more actions that Government must take to improve the financial health of the energy sector. The ESRP is a roadmap of immediate, near-term, and medium-term actions needed to achieve Government’s aim to bring the sector into balance by the end of 2023, and a commitment by Government to fund the Annual Sector Shortfall (with Sector Stabilization Payments) from 2020 onwards until the sector is in balance to prevent further accumulation of arrears. 66. The identified actions are classified into three phases: Phase I, II and III. Phase I actions are to be taken immediately while Phase II actions will be initiated within twelve months. Together Phase I and Phase II actions are expected to reduce the annual sector shortfall and prevent future imbalances, thereby minimizing needed increases in electricity tariffs and/or Sector Stabilization Payments by Government. Finally, Phase III actions will be required within two years to reduce further the shortfall until no Sector Stabilization Payments are required by 2023. Achieving 50% nationwide penetration of LPG 67. National LPG penetration rate increased from 6% in 2000 to 18% in 2010 and is currently around 25%. 68. The sector ministry is targeting 50% LPG penetration by 2030 but it is not likely to be achieved if limited distribution outlets nationwide remain the same and the its price continue to remain high. 69. The LPG consumption growth could surpass charcoal consumption again by implementing deliberate government policy not only to make the LPG produced available for local xi consumption as against export but producing LPG adequately to cover both local consumption and for export taking advantage of the market opportunities within the West Africa sub-region. 70. In addition, constructing LPG storage and supply infrastructure in all regional and district capitals in the long term. 71. In this light, the Ministry of Energy and the National Petroleum Authority need to consider investment incentives to encourage the Oil Marketing Companies and other interested investors to set up more LPG storage and distribution centres in-country to increase access and consumption. 72. There would also be the need to re-capitalised Ghana Cylinder Manufacturing Company (GCMC) to expand production capacity with the production of cylinders focused on small sized cylinders that would be portable and affordable to households in rural communities. Such can be achieved through private sector participation through Public-Private Partnership (PPP). Expanding Crude Oil Strategic Reserve 73. Fuel supply security and erratic fuel prices have compelled countries to set up strategic stocks both for crude oil and refined products. Crude oil storage however, has the comparative advantage of far longer lifespan and could even be indefinite depending upon the blend and state. Many developed countries have such storage mix and for OECD countries, minimum of six month storage is mandatory. 74. The Commission would continue to recommend for the inclusion of crude oil in the country’s strategic reserve. Expanding crude refining operations 75. Equivalent of 78,000-82,000 barrels per stream day refinery capacity would be required to enable the country meet its projected economic growth for 2020. 76. However, low capacity utilisation of TOR which has not made the facility profitable to operate in the past should not be lost in sight in future operations though still dependent on the production configuration. Profit could start emerging as the capacity utilisation increases, in most cases 90% and above. xii PREFACE ENERGY COMMISSION has the mandate to prepare, review and update periodically indicative national plans to ensure that reasonable demands for energy are met in a sustainable manner. In addition, the Energy Commission is mandated to secure and maintain a comprehensive data base for national decision making for the efficient development and utilisation of energy resources available to the nation. Energy Commission’s jurisdiction include promoting and ensuring uniform rules of practice for the production, transmission, wholesale supply, distribution and sale of electricity and natural gas. In fulfilment of its mandates, the Commission has been preparing annual energy demand and supply outlook to provide guidelines to the energy sector operators and potential investors as well as the wider business community wishing to operate in the country. The purpose of the 2020 Annual Energy Outlook therefore is to give government, industry and business, indications of the levels/quantities of electricity, liquid and gaseous fuels that would be required to be provided by the energy producers for this year. This document covers demand and supply of electricity, crude oil, petroleum products and natural gas. In the document, ‘Demand’ is used when referring to gross fuel or energy required by a demand sector, e.g. Residential, Commercial, or Industry. ‘Supply Requirement’ is Supply or Generation/Production plus transmission/transport losses. For further elaboration, please refer to Annex 1 of the document for a schematic overview of Ghana’s Energy Demand and Supply System. Your comments are most welcome. Ing. Oscar Amonoo Neizer Executive Secretary xiii TABLE OF CONTENT EXECUTIVE SUMMARY ....................................................................................................... I PREFACE ............................................................................................................................. XII LIST OF TABLES ................................................................................................................ XV LIST OF FIGURES ............................................................................................................ XVI ACRONYMS ...................................................................................................................... XVII 1.0 POWER SUBSECTOR .......................................................................................................1 1.1 OVERVIEW OF GRID POWER SUPPLY IN 2019 .......................................................................1 1.2 STATE OF THE GENERATION SOURCES IN 2019 .....................................................................4 1.2.1 The Hydro generation ..................................................................................................4 1.2.2 Thermal Generation .....................................................................................................7 1.2.3 Embedded Generation ................................................................................................8 1.2.4 Renewable Energy Generation.....................................................................................8 1.2.5 Electricity Exchanges (Export and Import) ..................................................................8 1.3 2019 FORECAST AND ACTUALS ...........................................................................................8 1.3.1 Fuel Supply Issues .......................................................................................................9 1.3.2 Fuel Cost ................................................................................................................... 12 1.4 FORECAST FOR 2020 ......................................................................................................... 15 1.4.1 Electricity Requirement of the Economy ................................................................... 15 1.4.2 The 2020 Grid Electricity Demand and Supply Outlook ............................................ 16 1.4.3 Available Electricity Supply for 2020-Generation Sources ........................................ 19 1.4.4 Grid Demand-Supply Balance ................................................................................... 23 1.4.5 Fuel Requirements and Cost Implications .................................................................. 25 1.5 TRANSMISSION SYSTEM PERFORMANCE ............................................................................ 29 1.5.1 State of the NITS ....................................................................................................... 29 1.5.2 Transmission Line, Feeder and Sub-station Availability ............................................ 30 1.5.3 Impacts of Transmission on Network Expansion Projects .......................................... 31 1.6 ELECTRICITY SUPPLY CHALLENGES .................................................................................. 31 1.6.1 Fuel Supply Challenges ............................................................................................. 31 1.6.2 Transmission Challenges ........................................................................................... 33 1.6.3 Impact of High Electricity Tariff on Demand............................................................. 34 1.6.4 Excess Grid Capacity ................................................................................................ 35 1.6.5 Impact of Novel Coronavirus on 2020 Electricity Demand ........................................ 37 2.0 PETROLEUM SUBSECTOR: OIL ................................................................................. 40 2.1 OVERVIEW OF PETROLEUM SUPPLY IN 2019 ...................................................................... 40 2.1.1 Indigenous Oil Production ......................................................................................... 40 2.1.2 Crude Oil Prices ........................................................................................................ 42 xiv 2.1.3 Domestic Consumption and Stocks in 2019 ............................................................... 43 2.1.4 2019 Forecast and Actuals ......................................................................................... 45 2.3 FORECAST FOR 2020 ......................................................................................................... 46 2.3.1 Forecast for Ghana .................................................................................................... 47 3.0 PETROLEUM SUBSECTOR: NATURAL GAS............................................................. 51 3.1 OVERVIEW OF NATURAL GAS SUPPLY IN 2019 ................................................................... 51 3.1.1 Domestic Gas Production .......................................................................................... 51 3.1.2 2019 Forecast and Actuals ......................................................................................... 55 3.2 FORECAST FOR 2020 AND BEYOND .................................................................................... 56 3.2.1 Gas Supply Challenges .............................................................................................. 57 3.2.2 Progress of Planned LNG projects ............................................................................. 61 4.0 THE REGULATORY REGIME ...................................................................................... 63 4.1 THE ELECTRICITY SUPPLY INDUSTRY ................................................................................ 63 4.1.2 Codes of Practices and Regulations ........................................................................... 64 4.1.3 Establishment of Wholesale Electricity Market .......................................................... 66 4.2 THE NATURAL GAS SUPPLY INDUSTRY .............................................................................. 67 4.2.1 Licensing and Permitting ........................................................................................... 67 4.2.2 Codes of Practices and Regulations ........................................................................... 68 4.3 RENEWABLE ENERGY UPDATE .......................................................................................... 69 ANNEXES ............................................................................................................................... 71 xv LIST OF TABLES Table 1: Installed Grid Electricity Generation Capacity operational as of December 2019 ........................ 3 Table 2: Grid Power Transmission losses since 2010 ............................................................................... 4 Table 3: Projected and Actual Generation of the Power Plants at Transmission level in 2019 ................... 9 Table 4: Projected and Actual fuel used by the thermal power plants in 2019 ......................................... 10 Table 5: Monthly and Daily Natural Gas Supply for Electricity Production in 2019 ............................... 12 Table 6: Costs due to Projected and Actual Price of the fuels in 2019 ..................................................... 13 Table 7: Grid Electricity and Associated fuels: Forecast and Actuals in 2019 ......................................... 14 Table 8: Summary of 2020 Peak Grid Power Demand forecast by Customer Classes ............................. 17 Table 9: Summary of Projected 2020 Grid Electricity Supply Purchases by Customer Classes ............... 18 Table 10: Thermal Grid Electricity Generation Plants for 2020 (MW) .................................................... 21 Table 11: 2020 Projected Grid Electricity and Supply Balance in GWh.................................................. 24 Table 12: 2020 monthly gas delivery profile (mmscfd) .......................................................................... 27 Table 13: Fuel allocation to thermal power plants .................................................................................. 28 Table 14: Expected Average Delivered Fuel Prices for the Thermal Plants for 2020 ............................... 29 Table 15: Comparison of Grid Electricity Tariffs Customer Class from 2018 to 2019............................. 34 Table 16: Sectoral Share of the Grid Electricity Consumption from 2010 to 2019 .................................. 35 Table 17: Comparison of Electricity Tariff ranges of Ghana and neighbouring countries in West Africa from 2018-2019 ..................................................................................................................................... 37 Table 18: Average Crude Oil prices in Ghana, United States (Gulf Coast), and Europe (the North Sea) from 2010-2019 ..................................................................................................................................... 43 Table 19: Petroleum products supplied to the Economy from 2016-2019 ............................................... 44 Table 20: Petroleum Products produced Locally, Imported and Exported from 2016-2019 ..................... 44 Table 21: 2019 Average Crude Oil Prices in Ghana, United States and Europe - Forecast and Actuals ... 45 Table 22: Forecast and Actual Petroleum Products Consumption in 2019 .............................................. 46 Table 23: Forecast for Average Crude Oil Prices for Ghana, United States and Europe for 2020 ............ 48 Table 24: Forecast for Ghana’s Crude Oil Prices and Production for 2020 ............................................. 49 Table 25: Average Delivery Gas Prices in Ghana (WAGP), United States (Henry Hub), and Europe (North Sea); 2016-2019 ......................................................................................................................... 55 Table 26: Projected delivered gas prices in Ghana (WAGP), United States (Henry Hub), and Europe (North Sea) for 2020 .............................................................................................................................. 56 Table 27: 2020 Projected Monthly Gas Delivery Profile in mmscfd by GNGC ....................................... 57 Table 28: Forecast for Ghana’s fields Gas export and WAGP Gas Supply for 2020 ................................ 57 xvi LIST OF FIGURES Figure 1 Akosombo Reservoir Trajectory for 2019 .................................................................................. 5 Figure 2: Bui Dam reservoir trajectory in 2019 ........................................................................................ 6 Figure 3: Total Grid Electricity Generation from Thermal Power Plants in 2019 ...................................... 7 Figure 4: Share of projected peak power demand based on Customer Classes for 2020 .......................... 16 Figure 5: Share of Projected Grid Electricity Supply based on Customer Classes for 2020 ..................... 18 Figure 6: 2020 projected Akosombo reservoir trajectory ........................................................................ 19 Figure 7: Bui Reservoir Trajectory projected for 2020 ........................................................................... 21 Figure 8: Share of Grid Electricity Supply by Generation Type for 2020 ................................................ 25 Figure 9: Trend in Installed Grid Capacity, Dependable Capacity and Peak Load; 2009-2019 ................ 36 Figure 10: Electricity Consumption distribution in Ghana (2019) ........................................................... 38 Figure 11: Residential Sector Load Profile in 24 hours ........................................................................... 38 Figure 12: Jubilee field daily oil production trend; 2011-2019................................................................ 40 Figure 13: TEN field daily oil production trend, 2016-2019 ................................................................... 41 Figure 14: Sankofa-Gye Nyame field daily oil production trend 2017-2019 ........................................... 42 Figure 15: Comparison of Jubilee field daily gas yield; 2017 and 2019 .................................................. 52 Figure 16: TEN field daily gas yield from 2016-2019 ............................................................................ 53 Figure 17: Sankofa-Gye Nyame field daily gas yield in 2019 ................................................................. 54 xvii ACRONYMS BOST Bulk Oil Storage and Transport company, a state company supposed to manage the country’s strategic reserve bscfd/bcfd Billion standard cubic feet per day / Billion standard cubic feet per day; a volumetric unit for gas flow ECG Electricity Company of Ghana, a public power distributor ESRP Energy Sector Recovery Programme ESTF Energy Sector Task Force GDP Gross Domestic Product; measure of wealth of an economy of a nation. GWh Gigawatt-hour, i.e. million units of electricity IPP Independent Power Producer kWh Kilowatt-hour, i.e. one unit of electricity LNG Liquefied Natural Gas; natural gas liquefied about 600 times LPG Liquefied Petroleum Gas mmBTU Million British Thermal Unit; an energy unit for gas flow mmscfd/mmcfd Million standard cubic feet per day/ Million standard cubic feet per day; a volumetric unit for gas flow mscfd/mcfd Thousand standard cubic feet per day/ Thousand standard cubic feet per day; a volumetric unit for gas flow MWh Megawatt-hour, i.e. thousand unit of electricity NG Natural Gas Solar PV Solar Photovoltaic; panel technology for electricity via solar or sunshine TAPCO Takoradi Thermal Power Company, a public power generator Tcf/tscfd Trillion standard cubic feet per day / trillion standard cubic feet per day; a volumetric unit for gas flow TICO Takoradi International Company, a public power generator TOR Tema Oil Refinery, the only crude oil and public refinery in the country. VALCO Volta Aluminium Company, a smelting company VRA Volta River Authority, a public power generator WAGP West African Gas Pipeline WAGPCo West African Gas Pipeline Company 1 1.0 Power Subsector 1.1 Overview of Grid Power Supply in 2019 Installed generation capacity available for grid power supply at the transmission level as at the end of 2019 was about 4,990 Megawatt (MW) with a dependable capacity of 4,580 MW. It totaled 5,171.6 MW if primary embedded generation including the listed solar plants8 at the sub- transmission level are included. This was about 4.2% expansion over last year’s compared to 13% increment from 2017 to 2018. The dependable capacity in this case is 4,738.6 MW which is about 4.4% more than in 2018 (see Table 1). The 20 MW BXC Solar, 20 MW Meinergy Solar9 and 2.5 MW VRA Solar are grid-tied plants connected at the distribution level, just as the Trojan and the Genser power plants. The gross grid generation in the country including the embedded generation10 in 2019 was 18,187.9 Gigawatt-hours (GWh), about 12.2% more than in 2018, comprising 39.9% hydro, 59.8% thermal and about 0.3% solar power. It increased to 18,315.1 GWh if imports was added. Without the primary embedded generation, the country’s gross generation in 2019 was 17,759.4 GWh, about 12.3% more than in 2018, comprising 40.8% hydro, 59.2% thermal power. Grid electricity made available for gross transmission11, during the year however was around 17,886.8 GWh consisting of about 7,251.6 GWh (40.5%) from hydro generation, 10,507.8 GWh (58.8%) from thermal generation and about 127.4 GWh (0.7%) of import. It was almost 12.1% improvement over 2018. Supply in 2018 was about 11.5% more than in 2017. Power exports to Togo/Benin (CEB) and Burkina Faso (SONABEL) reached a maximum of 120 MW and 60 MW respectively in 2019. 8 This does not include embedded or captive back-up generation. 9 The 20 MW Meinenergy was commissioned in 2018. 10 i.e. Trojan, Genser thermal plants and the grid-tied solar plants 11 Total generation, less own-use plus total imports. Does not include embedded generation and solar since they are at the distribution grid level. 2 A total of about 777.5 GWh of electricity was exported to Togo and Benin whilst about 576.5 GWh was also exported to Burkina Faso. A net of about 203.6 GWh was exchanged between Ghana and Cote d’Ivoire. This was made up of about 127.4 GWh imports and about 76.2 GWh exports. Total grid electricity supplied to the economy12, was about 17,042.8 GWh including about 0.7% net imports (127.4 GWh)13 and about 0.3% solar (51.3 GWh). It was about 8.9% increase over 2018 and 1.4% less than the minimum projected requirement of 17,277.5 GWh for the year. 12 Total generation + the net imports – transmission losses. 13 Total imports less wheeled from CIE to CEB. 3 Table 1: Installed Grid Electricity Generation Capacity operational as of December 2019 GENERATION PLANT FUEL TYPE CAPACITY (MW) TOTAL GENERATION In st al le d C ap ac it y (n am e p la te ) % S h ar e A ve ra ge D e p en d ab le A ve ra ge A va ila b le G W h % S h ar e (I n cl . e m b e d d ed ) % S h ar e (e xc l. e m b e d d ed ) Hydro Power Plants Akosombo Hydro 1020 900 849.2 5365.8 29.5 30.2 Bui Hydro 400 360 280.9 1043.9 5.7 5.9 Kpong Hydro 160 140 100.2 842.0 4.6 4.7 Sub-total 1,580 30.6# 31.7## 1,400 1,230 7,251.6 39.9 40.8 Thermal Power Plants Takoradi Power Company (TAPCO) Oil/NG 330 68.3 300 161.9 1,067.4 5.9 6.0 Takoradi International Company (TICO) Oil/NG 340 320 240.0 1,616.3 8.9 9.1 Sunon–Asogli Power (SAPP) NG 560 520 320.9 2,622.2 14.4 14.8 Tema Thermal Plant1 (TT1P) Oil/NG 110** 100 56.5 377.3 2.1 2.1 Tema Thermal Plant2 (TT2P) Oil/NG 87 70 37.9 138.4 0.8 0.8 CENIT Energy Ltd (CEL) Oil/NG 110** 100 209.6 183.4 1.0 1.0 KTPP Oil 220 200 127.6 393.0 2.2 2.2 AMERI NG 250 230 162.9 1,483.4 8.2 8.4 Karpower HFO/NG 470 450 312.9 1,510.2 8.3 8.5 AKSA HFO 370 350 252.4 608.4 3.3 3.4 Cenpower Oil/DFO 360 340 111.7 359.0 2.0 2.0 Amandi Oil/NG 203 200 22.8 148.8 0.8 0.8 Sub-total 3,410 3,180 2,017.2 10,507.8 59.2 Genser* Coal/LPG 95 85 82.5 377.1 2.1 Trojan* Diesel/NG 44 40 0.0 0.0 0.0 Sub – total (incl. embedded generation) 3,549 68.6 3,305 2,099.6 10,884.9 59.8 Renewables (excluding hydro) VRA Solar Solar 2.5 1.5 1.5 3.3 0.02 Meinergy Solar Solar 20 16 15.8 21.0 0.1 BXC Solar Solar 20 16 15.8 26.9 0.1 Safisana Biogas Biogas 0.1 0.1 0.1 0.3 0.001 Sub-total 42.6 0.8 33.6 33.2 51.3 0.3 Total (including embedded gen.) 5,171.6 4,738.6 3,363.0 18,187.9 Total (excluding embedded gen.) 4,990.0 4,580.0 3,247.4 17,759.4 NG is Natural gas. * Sub-transmission (primary embedded) connection. Including embedded generation and solar. ##Excluding embedded generation and solar. **Nameplate as licensed by Energy Commission is 126 MW. 4 The net grid electricity supplied14 to the country was about 15,612.6 GWh; about 706.6 GWh (about 4.7%) more than in 2018. Peak load on the transmission grid excluding export15 was 2,612.6 MW; 241.6 MW, roughly 10.2% more than in 2018 and was about 10.8% above the 2,358.3 MW projected for 2019. The total (maximum) system peak on the transmission grid16 was however 2,803.7 MW, which was about 6.8 MW (0.2%) more than the projected peak of 2,796.9 MW but 278.7 MW (about 11.0%) more than in 2018. The high growth in peak demand is attributed to the increased availability of natural gas for thermal generation especially in the western corridor coupled with an increase in exports facilitated by the construction of 330 kV transmission circuit. Total power transmission loss in 2019 was 844 GWh which is 4.7% of gross transmission, 0.3 percentage point higher than in 2018 (see Table 2). The increased in losses is as a result of increased system load and congestion in some sections of the transmission system. Table 2: Grid Power Transmission losses since 2010 Year 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Transmission losses as % of gross transmission 3.7 4.7 4.3 4.4 4.3 3.8 4.4 4.1 4.4 4.7 1.2 State of the Generation Sources in 2019 1.2.1 The Hydro generation 1.2.1.1 Akosombo and Kpong Akosombo was made to produce about 5,365.8GWh against projected supply of 4,258.4 GWh about 26.0% more than estimated17. On the other hand, Kpong was made to generate about 842.0 GWh as against a projected generation of 811.5 GWh which is about 3.8% more than projected. The Volta Lake started the year 2019 at an elevation of 261.85ft (79.81m), about 26.85ft (8.18m) above the Extreme Minimum Operating level of 235ft (71.6m). 14 Gross grid electricity plus imports, less wheeled, less exports, less transmission loss. 15 Referred to as Domestic Peak Load by some of the utilities 16 Ghana Peak load + Exports 17 Projected for Akosombo was 4,258.4 GWh and for Kpong was 811.5 GWh in 2019 Electricity Supply plan, p4. 5 Based on this low reservoir elevation, it was recommended to operate four (4) and five (5) units at off-peak and peak respectively. However, the plant did more than the projected due to the unavailability of some thermal plants. Consequently, the reservoir elevation dropped to a minimum of 252.25 ft (76.89 m) during the dry season in 2019. This elevation was 0.75 ft (0.23 m) lesser than the projected for the year. Figure 1 shows the Akosombo reservoir trajectory recorded for 2018 and 2019. Figure 1 Akosombo Reservoir Trajectory for 2019 The reservoir elevation at the end of 2019 was 264.76 ft, (80.70 m) representing an increase of 3.80 ft (1.16 m) above the projected of 260.96 ft (79.54 m) for the year. The recorded maximum lake elevation at the end of 2019 inflow season was 266.31 ft, (81.17 m) a rise of 26.31 ft (8.02 m) above the regular Minimum Operating Level of 240 ft (73.2 m). The total net inflow recorded in 2019 was 33.43 MAF (million acre feet), which implied that an above average inflow of 25.21 MAF was obtained in 201918. 18 Long term average inflow into Akosombo is about 30.6 MAF or 37,600 million cubic metres. 235 240 245 250 255 260 265 270 275 280 Jan/19 Feb/19 Mar/19 Apr/19 May/19 Jun/19 Jul/19 Aug/19 Sep/19 Oct/19 Nov/19 Dec/19 AKOSOMBO RESERVOIR ELEVATION Projected 2019 2019 2018 MAX MIN 2019 2018 Maximum Operating Level Minimum Operating Level Projected 2019 6 Kpong Hydroelectric Station which is currently undergoing retrofit, as expected ran three (3) out of the four (4) total installed turbine units resulted in an average plant output of 105 MW. As a result of the two hydro plants operations, the projected total annual electricity generation from Kpong and Akosombo hydropower Stations was 5,069.9 GWh but it was exceeded by about 22.4% more. 1.2.1.2 Bui Hydro In 2019, Bui hydropower plant was projected to operate an average of two turbine (2) units throughout the year. This mode of operation of the Bui Hydro was expected to lead to a projected annual production of 650.0 GWh and was expected to ensure that its reservoir level would be about 5 m above its target minimum level of 170 metres-high compared to its 168 m-minimum operating level to guarantee continuous and sustainable operation of the dam for 2019. Bui reservoir started the year at an elevation of about 176.97 MASL19 and dropped to 168.66 MASL at the end of the dry season thus about 2.19 MASL below the projected minimum of 170.85MASL for the year 2019. Figure 2 shows the Bui reservoir trajectory in 2018 and 2019. Figure 2: Bui Dam reservoir trajectory in 2019 19 masl is metres above sea level. 167 168 169 170 171 172 173 174 175 176 177 178 179 180 181 182 183 Jan/19 Feb/19 Mar/19 Apr/19 May/19 Jun/19 Jul/19 Aug/19 Sep/19 Oct/19 Nov/19 Dec/19 BUI RESERVOIR ELEVATION Projected 2019 2019 2018 Max MIN 2019 2018 Maximum Operating Level Minimum Operating Level Projected 2019 7 The total generation for Bui was 1,043.9 GWh compared to the projected of 650.0 GWh20. The higher than projected generation was due to higher than average inflows into the reservoir in the flood season of 2019, forcing a revised strategy to avoid the spillage of the Bui reservoir. This resulted in a much higher than anticipated generation. 1.2.2 Thermal Generation Total installed thermal generating capacity as at the end of 2019 was about 3,410 MW of which 3,180 MW was the Dependable Capacity; excluding the embedded generation (see Table 1). Total grid electricity generated from the thermal plants excluding the embedded generation was 10,507.8 GWh which was about 8.3% less than what was projected for 2019 and this was attributed to inadequate gas supply from the WAGP, GNGC21 (Ghana Gas) and Sankofa coupled with the inability of the thermal entities to purchase adequate liquid fuels to run the thermal plants just as it were in 2018 and 2017 (see Figure 3). Figure 3: Total Grid Electricity Generation from Thermal Power Plants in 2019 20 2020 Electricity Supply Plan, p23 21 Ghana National Gas Company 0 200 400 600 800 1000 1200 Thermal Generation in 2019 (GWh) Projected Gen Actual Gen 8 1.2.3 Embedded Generation Grid-tied embedded generation at the distribution level accounted for 3.5% (181.6 MW) of installed capacity and 2.4% of generation (428.3 GWh) in 2019. 1.2.4 Renewable Energy Generation Renewable Energy installations increased from about 71.3 MWp in 2018 to about 78.6 MW in 2019. Total grid tied Solar PV at the distribution level is 42.5 MW. 1.2.5 Electricity Exchanges (Export and Import) The total energy exported in 2019 was 1,430.4 MW which is about 93% increase from 739.50 in 2018, largely due to major transmission expansion that allowed for increase in exports to Burkina and Togo/Benin over the period. This was made up of 777.5 GWh, 576.5 GWh and 76.4 GWh of exports to Togo/Benin (CEB),Burkina Faso (SONABEL) and la Côte d’Ivoire (CIE) respectively. Electricity import in 2019 from Côte d’Ivoire was 127.4 GWh which means an aggregate of 203.8 GWh was exchanged between Ghana and Côte d’Ivoire. 1.3 2019 Forecast and Actuals For 2019, two scenarios were projected22: a) 17,238-18,014 GWh (with VALCO constrained to operate at most two potlines). Expected peak capacity demand required would lie within 2,666-2,797 MW. Average End-User tariff to make it realized should be within US cents 15-16 per kWh. b) 18,020-18,400 GWh (with VALCO constrained to operate at most two potlines). Expected peak capacity demand required would lie within 2,800-2,900 MW. Average End-User tariff to make it realized should be within US cents 14-15 per kWh. We indicated that all the two scenarios, (a) and (b) were achievable provided there is adequate financial resources to procure all the fuel needed to run the thermal power plants even at higher utilisation factors. 22 that all things being equal 9 The total grid electricity supplied inclusive of embedded generation in 2019 was about 18,187.7 GWh which fell within scenario (b) projection. The average end-user tariff was 13.7 US cents per kWh which is just about 0.3 US cents outside the scenario (b) projection. The economic growth rate for 2019, was 6.5% (for oil) and 5.8% (non-oil), were also somehow comparable to the Government’s projected GDP growth rate of 6.8% (oil growth) and maximum of 6.7% (for non-oil) for the year. 1.3.1 Fuel Supply Issues In 2019, there was about 3.4% (5% in 2018) increase in electricity supplied against what was projected (see Table 3). The increase in grid electricity demand also led to greater fuel demand. However, there was still inadequate stocks of liquid fuels (LCO and diesel) at the thermal plants which compelled some hydro plants to be operated beyond the projected (27.9%) (see Table 3). Table 3: Projected and Actual Generation of the Power Plants at Transmission level in 2019 Generation Source Fuel type Generation (GWh) Remarks Projected Actual Net Hydro Power Plants Akosombo Hydro 4,258.4 5,365.8 1,107.4 To make up for inadequate thermal supply Bui Hydro 650.0 1,043.9 443.9 Kpong Hydro 811.5 842.0 30.5 Sub-Total 5,719.9 7,251.6 1,531.7 Thermal Power Plants Takoradi Power Company (TAPCO) Oil/NG 1,491.8 1,067.4 -424.3 Maintenance & fuel issues Takoradi Inter. Company (TICO) Oil/NG 1,933.6 1,616.3 -317.3 Within range Sunon–Asogli Power (SAPP2) NG 2,655.9 2,622.2 -33.7 Within range Kpone Thermal Power Plant (KTPP) Oil/DFO 158.2 393.0 234.8 Back up Tema Thermal Plant1 (TT1PP) Oil/NG 211.4 377.3 165.9 Back up Tema Thermal Plant2 (TT2PP) Oil/NG 0.0 138.4 138.4 Fuel issue CENIT Energy Ltd (CEL) Oil/NG 0.0 183.4 183.4 Fuel issue AMERI NG 1,007.2 1,483.4 476.3 Within range Karpower HFO 2,775.2 1,510.2 -1,265.0 Relocation to Takoradi AKSA HFO 1,227.0 608.4 -618.6 Fuel issue CenPower Diesel/NG 0.0 359.0 359.0 Test-run mode Amandi Oil/NG 0.0 148.8 148.8 Test-run mode Sub – Total 11,460.1 10,507.8 -1,124.0 Total 17,180.0 17,759.4 579.4 10 The Akosombo and Kpong reservoirs were over-drafted to make up for power deficit arising from the fuel supply shortfall23; an offset which could have been addressed with thermal generation to maintain the integrity of the reservoirs. However, the variation of 74% for Bui plant was due to the high elevation of the reservoir, and therefore the plant was dispatched to utilize the excess inflows. The thermal generation, on the other hand, dropped by 8.3% just as in 2018. This was largely due to the inability of the generating entities to finance fuel purchases and perhaps the relocation of the Karpowership to Takoradi in the third quarter of 2019. Thus about 5.3 million barrels of liquid fuels (about 13.1 cargoes) projected dropped to about 3.8 million barrels (about 9.3 cargoes), a drop of about 28.3% (see Table 4). No LCO and DFO was projected for 2019, but about 2.3 cargos and less than half a cargo respectively was used24. Table 4: Projected and Actual fuel used by the thermal power plants in 2019 THERMAL POWER PLANTS FUELS GAS LCO DFO HFO 1000 mmscf Bbls Projected Actual Projected Actual Projected Actual Projected Actual TAPCO 14.73 9.39 - - - - - - TICO 16.67 11.93 - 76,449.40 - 211.70 - - AMERI 10.68 14.16 - - - - - - SAPP 20.93 18.65 - 165,008.18 - - - - TT1PP 2.28 4.14 - - - - - - CENIT - 1.87 - - - TT2PP - 1.68 - - - - - - KARPOWER 8.38 1.50 - - - - 2,447,363.00 1,737,705.43 TROJAN - - - - - - - - KTPP 1.75 3.87 - - - 63,403.27 - - AKSA - - - - - - 2,861,364.00 790,439.85 CENPOWER - 0.22 - 495,864.11 - 4,440.41 - - AMANDI - - - 176,326.42 - 11,551.13 - - GENSER - 2.52 - - - - - - Total 75.42 69.93 - 913,648.11 - 79,606.51 5,308,727.00 2,528,145.28 Esti. Cargos25 - - -  2.3 -  0.5  13.1  6.2 Delivery Price US$/bbl - - 70 64.19 84 - 84 65.40 23 A similar instance in 2018 24 Based on a usual cargo size of 405,000 barrels. 25 Estimated cargo ships; about 405,000 bbls per cargo. 11 Heavy fuel oil (HFO), destined for Karpower and AKSA plants, was below the projected thirteen cargos by seven less. Importing more HFO was favoured than LCO due to its lower price. Although, diesel (DFO) is largely used for starting and stopping the thermal plant operations, about 79.3% and 6.0% went to operate KTPP and Cenpower as back-up plants and around 14.4% went to Amandi for the latter’s test-runs during the year. Total lean gas supplied in 2019 for electricity production was 65,002,087 mmBTU comprising 63.4% indigenous sources, i.e., supply from Ghana Gas and Sankofa Gas and the remaining 36.6% import from Nigeria, i.e. WAGP supply (see Table 5). This was about 17.5% increase over supply in 2018. Total gas supply from domestic gas (Atuobo Gas and Sankofa Gas) was about 41.2 million mmBTU in 2019, about 37% increase from 2018. Average daily gas flow from domestic gas also increased from about 80.0 mmscfd to 102.3 mmscfd, about 28% more. Daily flow during the first quarter averaged 106.7 mmscfd, a sharp increase from about 69.5 mmscfd in the last quarter of 2018. The average gas flow in the first quarter then dropped to about 87.2 mmscfd during the second quarter then ramped up again to about 112.1 mmscfd in the third quarter and then dropped again to about 102.1 mmscfd in the last quarter of 2019. Majority of the domestic gas supply (accounting for about 63.4% of total supply) was to the power plants located at the Takoradi power plants enclave, while the WAGP supply (accounting for the remaining 36.6%) was destined to the Tema enclave. However, there was occasional flow of gas from WAGP to Takoradi, and domestic gas now flows through a reverse flow system to Tema enclave. 12 Table 5: Monthly and Daily Natural Gas Supply for Electricity Production in 2019 Month Domestic Gas Supply WAGPCo Supply Monthly flow in mmBTU Daily flow in mmscf Monthly flow in mmBTU Daily flow in mmscf January 4,234,928.32 120.13 1,862,224.36 55.49 February 3,663,565.98 117.86 1,362,289.02 45.47 March 2,705,220.24 81.96 1,519,494.89 45.9 April 2,202,171.36 82.27 1,863,654.39 57.81 May 3,098,802.36 88.21 2,167,784.65 71.18 June 3,041,673.62 91.21 2,025,474.04 66.43 July 3,454,651.97 98.69 2,406,898.73 71.28 August 4,201,699.11 119.53 3,062,869.05 88.53 September 4,010,601.00 118.07 1,776,610.34 59.25 October 3,775,140.43 107.54 2,000,399.83 59.96 November 3,276,082.05 96.3 1,568,357.01 49.11 December 3,573,017.62 102.37 2,148,476.61 63.36 Total 41,237,554.06 23,764,532.93 Average 3,436,462.84 102.32 1,980,377.74 61.25 Total gas flow from WAGP was about 23.8 million mmBTU in 2019, a drop from 2018. Average daily flow for the entire year declined from about 67.5 mmscfd, in 2018 to about 61.3 mmscfd in 2019. The average daily flow during the first quarter of 2019 was 49.0 mmscfd, about 34.2% decrease from the last quarter of 2018. It increased significantly to 65.1 mmscfd in the second quarter, then jumped to 73.0% by the end of the third quarter, but dropped to an average of about 57.5 mmscfd during the last quarter of the year. 1.3.2 Fuel Cost In 2019 and unlike 2018, all the prices of the liquid fuels purchased purposely for power generation were below the projected; a decrease of about 8.3% for the LCO and about 22.2% decrease for HFO. Actual N-Gas delivery price to VRA, the foundation customer, was $7.1 per mmBTU in 2019; about 18% decrease from 2018. It averaged $7.3 per mmBTU during the first quarter, decreased to $7.2 per mmBTU in the second quarter, then $7.0 during the third, before increasing to $7.1 per mmBTU in the fourth quarter of the year. 13 However, the actual delivered price of gas from domestic sources (Atuabo GPP and Sankofa) was $6.8 per mmBTU, about 5% lower than the N-Gas. The first quarter average was $7.5 per mmBTU same as the N-Gas, decreased to $7.3 in the second quarter, then $6.5 during the third, then reaching $6.08 per mmBTU in the fourth quarter of the year (same as the current PURC’s WACOG). The actual delivery price of gas for both WAGP and domestic gas was $6.9/mmBTU. In all about, $1,039.7 million was estimated for fuel procurement; US$ 593.8 million (i.e. 57.1%) for oil fuels and about $445.9 million (42.9%) for gas. However, only about 65.4%, amounting to $679.9 million, could be secured. Thus the gas purchased was 2.2% more, and total liquid fuels were 62.3% less than the estimated requirement. Based on the original projected fuel prices, only $693.4 million would have been needed, but the relatively low actual prices brought down the actual expenditure on fuel to about $679.9 million, i.e. about $13.5 million less (see Table 6). Table 6: Costs due to Projected and Actual Price of the fuels in 2019 GAS LCO HFO Projected Actual Projected Actual Projected Actual Price US$/unit 7.4 6.91 70 64.19 84 65.40 Fuel consumed 65,002.087 mmBTU 913,648.11bbl 2,528,145.28 bbl Cost US$1000 481,015.4 455,813.3 - 58,647 212,364.2 165,429.2 Net gain US$1000 25,202.1 -58,647 46,935.0 Total Savings 13,490.1 US$/unit: mmBTU for gas and bbl for the liquid fuels Table 7 shows the summary of some of projected and actual indicators in 2019. 14 Table 7: Grid Electricity and Associated fuels: Forecast and Actuals in 2019 2018 2019 Forecast Actual Ghana’s Electricity requirement (GWh) VALCO @ 2potlines (EUT @ 14-15US cents/kWh) 17,238-18,014 VALCO @ 2potlines (EUT @ 13-14US cents/kWh) 18,020-18,400 Total Grid Electricity available (i.e. including imports) GWh 16,353 17,887 Grid Electricity generation available (i.e. excluding imports) GWh 16,213 17,759 Percentage hydropower of generation (%) 37-38* (6,017 GWh) 33 (5,669.9 GWh) 40-41* (7,251.6 GWh) Ghana System Peak (Domestic peak ) MW 2,271 2,469.5 2,612.6 GRIDCO Transmission System Peak/Maximum Demand MW 2,525 2,796.9 2,803.7 Average WAGP gas flow (mmscf per day) 67 57 61.3 Average domestic gas flow (mmscf per day) 80 187 102.3 Average Delivered WAGP gas price (VRA receipt +other charges included#) US$ per mmBTU 8.71 7.4 7.14 Average Delivered GhanaGas gas price * (other charges included) US$ per mmBTU 7.53 7.4 6.79 Oil required (Million barrels) LCO - Diesel - HFO 5.31 Oil consumed (Million barrels) LCO 0.35 0.91 Diesel 0.08 HFO 4.41 2.53 Average delivered light crude oil price dedicated for power $ per bbl ($ per mmBTU) LCO 80 (13.79) 70 64.19 Diesel 109 (18.73) - - HFO 60 (9.68) 84 65.4 EUT implies End-User Tariff * Low-side included embedded generation; High-side excluded imbedded generation 15 1.4 Forecast for 2020 1.4.1 Electricity Requirement of the Economy The real GDP growth rate for 2019 was 6.5% (5.8% non-oil), a slight increase from the 6.3% (6.5% for non-oil) in 2018. The increase in the Petroleum subsector growth, from about 3.6% in 2018 to about 15.1% in 2019 may have contributed to the slight increase in the GDP growth in 2019. There was however 0.7 percentage points drop in the non-oil GDP which was attributed to a decline in the growth of the Mining and Quarrying (excluding oil) sector, from 48.6% in 2018 to about 10.4% in 2019. Before the novel coronavirus (Covid-19) pandemic, Ghana’s overall real GDP growth is projected to expand from the 6.5% in 2019 to 6.8% this year and the non-oil component is expected to also expand to about 6.7% from the 5.8% last year26. At this Government’s projected GDP growth rate of 6.8% (5.6-6.8% by donor agencies) and particularly 6.7% (non-oil growth) for the country in 2020, we expect the total electricity required for the GDP growth to be as follows:  19,594.4 GWh (with VALCO constrained to operate at most two potlines). Expected peak capacity demand required would be 3,115.2 MW. Average End-User tariff to make it realized should be within US cents 13-15 per kWh. This projected electricity requirement is achievable provided there is adequate financial resource to procure all the fuel needed to run the thermal power plants even at higher utilisation factors. 26 2020 Ghana Government’s Budget Statement and Economic Policy. The World Bank and the IMF forecasts 6.8% and 5.6% respectively. https://www.imf.org/en/Countries/GHA https://www.worldbank.org/en/country/ghana/overview https://www.worldbank.org/en/country/ghana/overview 16 1.4.2 The 2020 Grid Electricity Demand and Supply Outlook27 1.4.2.1 Peak Power Demand The following spot loads are expected to contribute to peak demand growth in 2020: a) Full operation of the second potline of VALCO, increasing its peak demand from the current 55 MW to 150 MW. b) Increase in export to Togo/Benin and SONABEL (Burkina Faso) - from 120 MW in 2019 to 180 MW in 2020 for Togo/Benin and from 120 MW in 2019 to 150 MW by close of 2020 for SONABEL. c) On-going distribution network expansion works intended to extend coverage and improve service quality to consumers nationwide. d) Expected completion and commissioning of various ongoing rural electrification projects under the National Electrification Programme in 2020. Figure 4 describes the percentage share of Peak Demand on the grid of each of the customer class. Figure 4: Share of projected peak power demand based on Customer Classes for 2020 27 This work mostly adapted from the 2019 Electricity Supply report jointly produced by Energy Commission, GRIDCo, VRA, Bui, ECG and NEDCo, January, 2019. Available at www.energycom.gov.gh/planning ECG 60% NEDCo 8% Enclave Power 2% Mines 8% Other Bulk Customers 2% Losses 5% Export 10% VALCO 5% 2020 Projected Peak Demand (MW) http://www.energycom.gov.gh/planning 17 From Figure 4, ECG’s demand would constitute 60% of the total system peak, followed by NEDCo at 8%, then Mines (8%) and VALCO (5%). Enclave Power (operating at the Free Zone) and Other Bulk Customers are expected to account for 2% each. Exports to Togo & Benin (CEB) and Burkina Faso (SONABEL) together would account for 10%28. The remaining 5% will be losses. Table 8 shows a summary of 2020 peak grid power demand forecast based on the utilities’ customer classes. Table 8: Summary of 2020 Peak Grid Power Demand forecast by Customer Classes DEMAND SECTOR CUSTOMER CLASS COINCIDENT PEAK DEMAND (MW) Ghana Domestic Peak Demand29 ECG 1,874.73 NEDCo 243.30 Enclave Power 57.04 Mines (largely gold mining) 246.01 Other Bulk 50.14 Losses+Network Usage 163.94 Total Domestic Peak Demand 2,635.15 Exports CEB (Togo & Benin) 180.00 CIE (la Cote d’Voire) 0.00 SONABEL (Burkina Faso) 150.00 Total Exports 330.00 VALCO 150.00 Coincident Peak Demand MW 3,115.15 1.4.2.2 Outlook of Grid Electricity Supply For 2020, the total grid electricity supply including transmission network losses is projected to be between 19,594.4 GWh. This includes estimated transmission losses and network usage of 876.2 GWh, representing 4.5% (5.2% in 2019) of the total projected electricity supply. The projected 2020 grid electricity supply represents a growth of approximately 9.1% over the 2019 actual consumption (electricity made available for gross transmission) of 17,886.8 GWh. Table 9 presents the summary of 2020 grid electricity supply purchases by customer classes. 28 ECG is Electricity Company of Ghana, a distribution utility for largely southern Ghana. NEDCo is Northern Electrification Company of Ghana, a distribution utility for largely northern Ghana. 29Excluding VALCO 18 Table 9: Summary of Projected 2020 Grid Electricity Supply Purchases by Customer Classes ENERGY CUSTOMER PROJECTED REQUIREMENT (GWh) Ghana35/Domestic Consumption ECG 12,234.84 NEDCo 1,462.70 Enclave Power Company 283.78 Mines (largely gold mining) 1,618.69 Other Bulk Customers 236.39 Losses + Network Usage 876.22 Total 16,712.62 Export CEB (Togo & Benin) 902.06 CIE (la Cote d’Voire) 0.00 SONABEL (Burkina Faso) 750.00 VALCO 1,229.76 Total Electricity (GWh) 19,594.44 Source: 2020 Electricity Supply Plan Figure 5 shows a representation of the projected electricity consumption of the various customer groupings and their percentage share in 2020. As shown in Figure 5, ECG’s uptake of 12,234.8 GWh for its customers represents about 62.4% of the total projected grid electricity requirement in 2020. It is followed by NEDCo, Mines and Exports with 8% a piece, while VALCO with a projected consumption of 1,229.8 GWh represent 6% of the total consumption. Figure 5: Share of Projected Grid Electricity Supply based on Customer Classes for 2020 ECG 62.44% NEDCo 7.46% Enclave Power 1.45% Mines 8.26% Other Bulk Customers 1.21% Losses 4.47% Export 8.43% VALCO 6.28% 2020 Projected Energy Consumption (GWh) 19 1.4.3 Available Electricity Supply for 2020-Generation Sources30 The sources of generation considered are mainly from the existing generation and the committed projects expected to come online in 2020. 1.4.3.1 Existing Generation Sources – Hydropower Akosombo and Kpong Hydro Akosombo Generating Station (GS) is planned to operate to four generating units during the off- peak period and up to five (5) units during the peak period in the year 2020. This mode of operation is expected to result in operating capacity of up to 750 MW at Akosombo GS in 2020, which would ensure that the reservoir level is kept above the minimum operating level of 240 ft. This mode of operation would result in a projected minimum elevation of 255ft at the end of the dry season in 2020. Figure 6: 2020 projected Akosombo reservoir trajectory It is worth noting however that some thermal power plants will be rendered inoperable in the first quarter of 2020, due to the WAGP Intelligent Pigging exercise that will curtail gas supply to Tema. 30 This work mostly adapted from a 2020 Electricity Supply Plan jointly produced with GRIDCo, VRA, Bui, ECG and NED, January, 2020. 20 Consequently, all 6 units at Akosombo GS will be put in operation to ensure security of supply. Kpong Generation Station (Kpong GS), which is currently undergoing retrofit, would have three (3) out of the four (4) units available in the first quarter of 2020. The total average capacity that would be available at Kpong GS is 105 MW. However, the retrofit is expected to be completed by April 2020 and all four units are expected to be available, increasing the dependable capacity of Kpong GS to 140 MW. As a result of the above mode of operation, the projected total annual hydro generation from Kpong and Akosombo generating stations is 5,465 GWh. Bui Hydro In 2020, Bui hydropower plant is projected to operate an average of two turbine (2) units throughout the year. This mode of operation would lead to a projected annual production of 764 GWh. Bui Hydro is assumed to provide an average generation capacity of 220 MW to support demand. It is estimated that, for continuous and sustainable operation of the Bui Power Station for 2020 and for the subsequent years (in the likely event of low inflows), the reservoir level at the end of the dry season of 2020 should not drop below elevation 170 masl31. With a year-start elevation of 180.37 masl in 2020 and the total estimated total electricity production of 764 GWh for 2020, the year-end elevation is projected at 177.65 masl. Figure 7 shows the 2020 projected trajectory for Bui hydropower plant. 31 metres above sea level, a description used by the Bui Power Authority to describe the reservoir level at Bui. 21 Figure 7: Bui Reservoir Trajectory projected for 2020 1.4.3.2 Existing Generation Sources - Thermal Thermal The total installed grid thermal generating capacity for 2020 is 3,542 MW of which dependable capacity would be 3,238 MW (see Table 10). Table 10: Thermal Grid Electricity Generation Plants for 2020 (MW) Power Plants Installed Capacity Dependable Capacity Fuel Type TAPCO (T1) 330 300 LCO/Gas TICO (T2) 340 320 LCO/Gas TT1PP 110 (126*) 100 LCO/Gas TT2PP 87 70 Gas KTPP 220 200 Gas/ Diesel CENIT 110 (126*) 100 LCO/Gas AMERI 250 230 Gas SAPP 200 180 Gas SAPP 2 360 340 Gas Karpower 470 450 HFO/Gas AKSA 370 350 HFO/Gas 22 Power Plants Installed Capacity Dependable Capacity Fuel Type CENPOWER 360 340 Gas/LCO AMANDI 203 200 Gas/LCO Sub-transmission level Trojan 44 39.6 Diesel/Gas Genser 95 85 LPG Total 3,542 (3,574) 3,238 * Nameplate installed capacities of the TT1PP and CENIT as licensed by Energy Commission is 126 MW. In 2020, 203 MW Amandi Thermal Power Plant located in Takoradi which was completed and underwent test-runs in 2019 is expected to come online. Another new major plant coming online is the 144 MW Bridgepower Plant which is expected to be commissioned by April 2020. The projected total thermal generation for 2020 is 14,128 GWh. 1.4.3.3 Existing Generation Sources – Distributed Generation As indicated earlier, electricity from distributed back-up generation in 2017 was estimated at 3,600 GWh. This was equivalent to generation from about 500 MW combined cycle thermal power plant32. With the prevailing relatively high grid electricity tariff, distributed generation would continue to serve as a supplementary source of electricity to help reduce energy cost. For instance, supply from embedded generation (Genser and Trojan) increased from about 359 GWh in 2018 to 377.1 GWh in 2019 (see Table 1). 1.4.3.4 Existing Generation Sources - Renewable Energy Even though grid-tied Solar PV was almost 43 MW, significant embedded grid-connected solar power units totalling about 6.5 MW peak and largely owned by commercial customers of ECG are expected to come on line in 2020. There is also a 500 MWp solar irrigation system expected to be completed this year. However, these are likely to have an impact on grid electricity consumption. 1.4.3.5 New Generation Sources 32 A nationwide survey by Energy Commission and METSS of USAID, Ghana, December, 2017 23 In 2020, a number of new generation projects are expected to be commissioned into service as follows:  144 MW Bridgepower Plant located in Tema. The Plant would run on LGP or Gas and would be evacuated through the 161kV Collector Substation.  VRA Kaleo and Lawra Solar Power Plants – VRA commenced construction of a 17 MW solar power plant at Kaleo in the Upper West region in September 2019. Commissioning for the first phase is expected to begin in June 2020 and the entire project completed in the First Quarter of 2021. 1.4.4 Grid Demand-Supply Balance The criteria used to determine which power plants would be dispatched on a monthly basis during the year are as follows: i. Merit order dispatch. ii. Availability of fuel per plant. iii. Must-run plants; take-or-pay plants. iv. Variable or intermittent systems like the grid-tied solar plants. v. System stability requirements. Instances where there is supply surplus, some plants would not be dispatched under normal operating conditions. The grid electricity demand-supply balance for 2020 is presented in Table 11. The total generation from VRA plants would be about 9,189 GWh, representing 47.4% of the projected total grid electricity generation for 2019. Generation from Bui Hydro would be 764.0 GWh (4.6%), while Independent Power Producers (IPPs) would generate about 10,404 GWh (47.4%). 24 Table 11: 2020 Projected Grid Electricity and Supply Balance in GWh PROJECTED GRID DEMAND/SUPPLY DEMAND/SUPPLY (GWh) DEMAND: Customer Category Total Ghana (so-called Domestic) 16,712.62 VALCO 1,229.76 Exports (CEB+SONABEL+CIE) 1,652.06 Total Projected Electricity Requirement 19,594.44 PROJECTED SUPPLY Total VRA Hydro (Akosombo & Kpong GS) 5,465.00 Bui GS 764.00 Sub-Total: hydro 6,229.00 VRA Existing Thermal & Solar Generation TAPCO 1,414.00 TICO 1,968.00 TT1PP 97.00 KTPP 237.00 TT2PP 5.00 VRA Solar 3.00 Sub Total 3,724.00 Existing IPP Thermal & Solar Generation AMERI Power Plant 1,292.00 Karpower Barge 3,175.00 SAPP1+SAPP2 2,720.00 CENIT 364.00 AKSA 157.00 CENPOWER 997.00 Amandi 880.00 BXC Solar 27.00 MEINERGY Solar 27.00 Safisana 1.00 Sub Total 10,404 Total VRA Supply 9,189.00 Total Non-VRA Supply 10,404.00 Total Supply 19,594.00 Figure 8 shows a graphical representation of Table 11, giving the percentage share of each generation type. Thermal generation thus would constitute about 67.9% of projected total generation whilst hydro generation and generation from solar PV would constitute 31.8% and 0.3% respectively. 25 Figure 8: Share of Grid Electricity Supply by Generation Type for 2020 This implies that in 2020, as in 2019, generation from thermal sources would be more than twice that from hydro sources. This high percentage of thermal generation could have serious implications for the power sector for the following reasons: i. It will adversely impact the finances of the local power utilities, since local tariffs are cedi denominated and if the cedi becomes relatively unstable during the year. ii. Any prolong disruptions in gas supply would have dire consequences on the power supply situation in the country in terms of reliability of supply and on generation costs since gas price is on the average cheaper than liquid fuels. However, if VRA Hydro could generate 6000 GWh, without causing damage to the dam, then the share of Hydro would increase from 31.8% (6,229 GWh) to 34.5% (6,764 GWh). 1.4.5 Fuel Requirements and Cost Implications In 2020, the main fuel for thermal power generation would be natural gas. However, some generating units such as AKSA will run on heavy fuel oil (HFO) whiles Bridgepower runs on LPG. Light Crude Oil (LCO) and Diesel (DFO) would remain as backup fuel for some plants. Thermal 67.91% Hydro 31.79% Renewable 0.30% 2020 Projected Generation Mix 26 1.4.5.1 Fuel Allocation and Cost Fuel type LCO The total LCO used in 2019 was about 913,606.1 barrels. In 2020, only Cenpower is scheduled to operate on LCO. The estimated LCO for this power plant is 495,733 bbl. HFO HFO would be used mainly by the AKSA power plant due to the relocation of the Karpowership to Takoradi to use gas. HFO used in 2019 was about 4.4 million barrels. In 2020. the AKSA Plant is scheduled to operate on HFO throughout the year. Total requirement for the plant is estimated at 212,858 barrels. Natural Gas Natural gas would as usual come from three sources; WAGP carrying gas from Nigeria; and Ghana Gas pipeline carrying indigenous gas from the Jubilee and TEN, then ENI gas from the Sankofa fields. Average WAGP gas delivered in 2019 was about 61.3 mmscfd, whilst supply from domestic gas was about 102.3 mmscfd. For 2020, total gas consumption is projected to be about 107.6 million mmBTU which translates to an average daily delivery of about 200-300 mmscfd. VRA power plants would require about 44.4 million mmBTU (about an average of 140 mmscfd) whilst the balance of 63.1 million mmBTU (about an average of 160 mmscfd) would go to the IPPs. In 2020, priority is given to maximise the use of natural gas for generation. Expansion works are ongoing to increase the capacity of the gas infrastructure at Tema from 140 mmscfd to 235 mmscfd. This is expected to be completed by April 2020, which will allow up to approximately 120 mmscfd to be transported from the West to the East. The expected monthly volumes of gas from the various gas sources are shown in Table 12. 27 Table 12: 2020 monthly gas delivery profile (mmscfd) Month Source OCTP Jubilee / TEN N-GAS LNG Total Jan 128 87 80 - 295 Feb 128 87 80 - 295 Mar 128 87 80 - 295 Apr 130 125 30 - 285 May 130 125 30 - 285 Jun 130 125 30 - 285 Jul 130 125 30 - 360 Aug 130 125 30 - 360 Sep 130 125 30 - 360 Oct 130 125 30 75 360 Nov 130 25 30 75 360 Dec 130 125 30 75 360 In 2020 it is expected that a total of about 300 mmscfd of gas will be supplied by Ghana Gas fields. This could go up to 320 mmscfd, while a total of about 70 mmscfd will be supplied by Nigeria. Thus, total gas supply from Ghana fields and Nigeria is estimated to be 370 mmscfd. It is assumed that Reverse Flow from Takoradi to Tema through the WAGP will be 60 mmscfd up to April 2020 and increase to 120 mmscfd from May 2020. Natural Gas availability and thermal plant availability in the West could limit the flows to 30 mmscfd. Also, the Tema LNG Project is expected to commence supply by the fourth quarter of 2020. Expected volumes from Tema LNG in 2020 is 75 mmscfd. This would add to the diversity of gas sources and significantly improve gas supply reliability. Diesel As usual, diesel would be used mainly for starting and shutting down the thermal plants. In 2019, just about 79,606.5 barrels (about quarter of a cargo size of 405,000 barrels) was used. For 2020, we maintain the same quantity needed 28 Thermal Plants Fuel Allocation Table 13 summarizes the estimated quantity of fuel required for each thermal power plant in 2020. Table 13: Fuel allocation to thermal power plants Plant LCO (Barrels) Natural Gas (MMBtu) HFO (Barrels) TAPCO - 11,569,743 - TICO - 16,010,601 - TT1PP - 1,066,827 - KTPP - 2,679,931 - TT2PP - 68,655 - AMERI - 13,036,789 - Karpower - 25,480,157 - SAPP - 21,808,320 - CENIT - 3,968,932 - AMANDI - 6,571,200 - CENPOWER 495,733 5,292,938 - AKSA - - 212,858 TOTAL 495,733 107,554,093 212,858 West-to-East Reverse Flow The Takoradi-Tema Interconnection Project (TTIP) to allow transportation of domestic gas from gas producing fields in the West for use at Thermal Power plants in the East (Tema) using the West African Gas Pipeline is completed. So far this has made it possible for Ghana Gas and WAPCo to transmit up to about 60 mmscfd of natural gas to power plants in the Tema Generation Enclave. Fuel Prices Total LCO of about 495,733 barrels estimated for 2020 would cost $42.14 million at delivery cost of $85 per barrel. It is expected that no power plant will use diesel as fuel for electricity generation in 2020. As stated earlier, diesel maybe used only for starting and shutting down the thermal plants. Total HFO requirement of 212,858 barrels translates to about half a cargo, assuming a cargo size of 29 405,000 barrels at an estimated delivery cost of about $25.33 million at $119 per barrel will be required in 2020. For 2020, the delivery gas price for both WAGP and domestic gas would be a weighted average price of $6.08/mmBTU as published by the Public Utility Regulatory Authority (PURC). Consequently, about $653.9 million would be needed for the gas procurement. In all, about $721.4million would be needed for fuel for the year 2020. Summary of estimated amount of fuel needed and the cost involved are as presented in Table 14. Table 14: Expected Average Delivered Fuel Prices for the Thermal Plants for 2020 FUEL TYPE Average Delivered Cost and equivalent Total Coast US$/mmBTU US$/bbl US$/tonne (US$) million Gas 6.08* - - 653.92 LCO - 85 595 42.14 HFO - 119 833 25.33 Total 721.39 The US$/mmBTU in italics are approximate equivalent prices of the liquid fuels. *weighted gas price released by PURC, 1st July 2019. 1.5 Transmission System Performance 1.5.1 State of the NITS33 In Ghana, the transmission of electricity is done at three main voltage levels, namely; 69 kV, 161 kV and 330 kV. There is also a 225 kV voltage level transmission that facilitates interconnection with Ghana’s western neighbour Cote d’Ivoire and now with northern neighbour Burkina Faso as well. A similar interconnection with Togo is through two 161 kV lines and a 330 kV line. The National Interconnected Transmission System (NITS) increased from approximately 5,284 circuit kilometres (km) of high voltage transmission lines in 2017 to about 5,965.83 circuit km at the end of 2018 and currently stands at 6,472.23 circuit kilometres. It connects all the major generation plants to sixty-five (65) Bulk Supply Points across the nation. 33 See Annex 2 30 There is a 225 kV tie-line which interconnects the Ghana grid with that of Cote d’Ivoire and two 161 kV tie-lines that interconnect Ghana grid with that of Togo. In addition, there is a single circuit 225 kV tie-line of about 74 km linking the country’s network with that of Cote d’Ivoire. The network total transformer capacity increased from about 8,106.9 MVA34 in 2018 to about 8,959.6 MVA in 2019, an increase of 852.7 MVA. The National Interconnected Transmission System (NITS) has over 600 MVArs of fixed shunts installed at various Substations including Achimota, Mallam, Smelter, Winneba, Takoradi, Kumasi etc. and a 40 MVArs of Static Synchronous Compensator (STATCOM) installed at the Tamale substation. The fixed shunts and the STATCOM complement the generating units in providing the reactive power requirements of the NITS, to maintain good voltages and minimize overall transmission losses. Ghana Grid Company (GRIDCo) is the operator of the NITS and is responsible for the real-time dispatch (monitoring, coordination and control) of power system operations on the Ghana Power System as well as cross-border power exchanges with neighbouring countries. The System Control Centre (SCC) in Tema is responsible for the real-time dispatch (monitoring, coordination and control) of the Ghana Power System as well as cross-border power exchanges with neighbouring countries. 1.5.2 Transmission Line, Feeder and Sub-station Availability The criteria for transmission Line, Feeder and Substation availability are as presented below; i. All existing transmission lines are expected to be in service to ensure transmission of electricity from the generation stations to the Bulk Supply Points across the nation and to enable the execution of power exchanges with neighbouring countries. ii. Maintenance work on transmission lines and substations is not to significantly affect power supply to customers except for single transformer substations and consumers served on radial lines. In 2020, just as in the previous years, all existing transmission lines are expected to be in service for the transmission of electricity generated at the power plants to bulk supply points across the 34 MVA is Megavolt-Ampere 31 nation and as well to enable the execution of power exchange programmes with neighbouring countries. Maintenance work on transmission lines and substations are not expected to significantly affect power supply to customers except for single transformer substations and consumers served on single radial lines. Most transformers in operation on the NITS are designed with a capability of 100% continuous loading and Transformer Utilization Factor (TUF). Indications from GRIDCo therefore suggests that there is adequate transformer capacity on the NITS for the supply of power under normal operating conditions35. 1.5.3 Impacts of Transmission on Network Expansion Projects There are some transmission expansion projects that have been completed and commissioned into service in 2019. They are:  161 kV Sunyani-Berekum line  161 kV Mim-Juabeso line  330kV Aboadze-Anwomaso  330kV Kintampo- Nayagnia  161 kV Buipe – Adubiliyi  161 kV Adubiliyi – Tamale  330 kV Kintampo-Adubiyili  330 kV Adubiyili-Nayagnia  330kV Karpowership -Takoradi Thermal Power Plant  161 kV Bolga – Nayagnia  161 kV Bridge Power Plant – New Tema Line 1  161 kV Bridge Power Plant – New Tema Line 2 1.6 Electricity Supply Challenges 1.6.1 Fuel Supply Challenges Hydro Risk Even though there are high prospects for rainfall this year, it would still be prudent to continue the conservative dispatch of the hydro plants to ensure that the reservoirs are not drawn down below their minimum operating levels to guarantee sustainable operations in the coming years. The 35 2020 Electricity Supply Plan; joint work with GRIDCo, VRA, Bui Authority, ECG and NEDCo 32 availability and reliability of the thermal units are also very key to maintain the planned hydro draft rate. Thermal Fuel Risk Reliability of Gas supply from WAGP and Ghana Gas Company remains a major risk to electricity supply reliability in Ghana. Although there is high installed generating capacity, gas supply sustainability remains one of the major risks to reliable electricity supply in Ghana. Any disruptions in fuel supply, mostly gas, would render some thermal plants inoperable and consequently adversely impact on supply reliability. The Aboadze Power Enclave presently has a dependable total generation capacity of 1,490 MW as a result of the relocation of the 450 MW Karpoweship to Sekondi and the commissioning of the 190 MW Amandi Power Plant in 2020. Thus making the Western Enclave the largest generation enclave with over 53% of the overall system peak demand, outstripping both Tema and Akosombo generation enclaves. This means any incident that affects either the ability of any power plant or the evacuation of power generated in the Western Enclave would have significant consequences on the nation’s power system. For instance, there have been incidences of sudden losses of or drop in gas supplies to the power enclaves. The power system suffered a system disturbance as a result of sudden loss of gas supply from Ghana Gas to the generating plants in the Western enclave leading to sudden drop in generation. Should such and similar situations persist, there could result in prolonged load shedding. Such could be averted by securing alternative fuels and supply for the power plants to make up for any shortfall in the supply of gas within the period of disruptions. Thus, there is the need to make advanced arrangements for adequate LCO storage at both Tema and Takoradi power enclaves. It is also still imperative that the companies in the Gas Supply chain, namely, Tullow, ENI, GNPC, Ghana Gas, BOST and others collaborate strongly with the power supply entities to ensure effective planning and coordination. 33 1.6.2 Transmission Challenges Power Evacuation There are also transmission capacity constraints in some portions of the network which could lead to transmission line overloads. For instance, insufficient reactive power compensation could lead to poor customer supply voltage in areas such as Kumasi, Accra and some parts of the Western region. Due to project financing issues, work on the following projects have delayed;  330kV Anwomaso – Kintampo transmission line  161kV Volta – Achimota – Mallam corridor upgrade The 330kV Anwoamso – Kintampo line is the remaining section of the 330kV Central Transmission Backbone infrastructure. This project is to enable the NITS improve system stability whilst exporting at least 100MW power to Burkina. Due to the delays in delivering the project, the 161kV Anwwomaso –Kumasi line is experiencing high loading contributing to system losses. Any contingency on the line will create severe system disturbances which may collapse the power system. GRIDCo must get the necessary support from Government and AfD to complete this section of the line. The 161kV Volta-Achimota-Mallam Corridor is the most heavily loaded corridor on the Ghana grid, supplying power to the Capital and surrounding towns. It is made up of light capacity conductors which are at least 50 years old. In 2018 GRIDCo secured funds to replace all the towers and transmission lines with high capacity conductors. The project has stopped due to project management issues and non-disbursement from AfD. As the demand for power increases in 2020, any line contingency on the corridor will mean severe load curtailment to the Capital. It is of utmost importance all efforts be harnessed to complete the project to avoid any load shedding to the Capital in 2020. Radial Lines and Single Transformer Stations Currently, supply reliability to customers served via single circuit radial lines is quite low. This is because an outage on such single circuit radial lines interrupts supply to such customers. Some of the single circuit radial lines on the NITS are the: Tamale–Yendi, Takoradi–Esiama; Dunkwa– 34 Asawinso; Bogoso–Akyempim; Bolga- Zebilla; Zebila–Bawku lines, etc. Supply reliability to customers served on these lines would improve in future when such lines are upgraded through the construction of additional line(s) or by looping them into other adjoining substations. Similar to single circuit radial lines, consumers supplied by single transformer substations also suffer low level of supply reliability. Maintenance and/or upgrade works at these stations are often a challenge due to difficulties in securing outages to carry out planned maintenance works. Such townships supplied via single transformer stations are Yendi, Sogakope, Esiama, Akosombo Township, VRA Township at Akuse, etc. There are also transmission capacity constraints in some portions of the network which could lead to transmission line overloads. For instance, insufficient reactive power compensation could lead to poor customer supply voltage in areas such as Kumasi, Accra, and some parts of the Western Region. 1.6.3 Impact of High Electricity Tariff on Demand In July 2019, new tariff were released by the Government announcing an increment of 11.17% across all sectors. This came after a year in March 2018, when the Government announced the following reductions; about 17% reduction in Residential; 30% in Commercial and 25% in industrial tariffs. Table 14 compares the 2019 tariffs against the 2018 tariff regime. Table 15: Comparison of Grid Electricity Tariffs Customer Class from 2018 to 2019 US cents/kWh US cents/kWh US cents/kWh Oct-18 Oct-18 Oct-18 51-300 55.54 65.42 13 67.75 79.79 15 301-600 72.09 84.90 16 72.10 84.91 16 601+ 80.10 94.33 18 113.76 133.98 26 SLT – L V 75.66 104.73 20 SLT – MV 58.57 79.52 15 SLT – HV 53.82 83.46 16 SLT – HV Mines 102.57 263.97 51 Oct-19 Oct-19 Oct-19 CONSUMPTION CLASS RESIDENTIAL NON-RESIDENTIAL INDUSTRIES (Domestic usage) (Commercial usage less than 100 kVA) (SLT usage)* Ghp/ kWh Ghp/kWh Ghp/kWh 35 US cent 1 = 5.22 Ghana pesewas average as at the end of 2019. US cents/kWh rounded up to the nearest whole number. *SLT is Special Load Tariff for energy usage for industrial purposes; supply voltages LV–Low Voltage (400V); MV- Medium Voltage (11,000 V) and HV-High Voltage (33,000 V). The increase in tariff in 2019 may have led to a reduction in the rate of increase in electricity consumption from 8% in 2018 to 5% in 2019, about half of the annual average growth of 10% before the power crisis in 2012. This was after the drop in tariff in 2018 saw an improvement in electricity consumption from about 6% in 2017 to about 8% in 2018. The tariffs are now on the high side from the 2018 reduced tariffs affecting the share of the wealth creation sectors, i.e. SLT consumption reduced by about 1.7 percentage points from 2018 to 2019. Also, the residential sector saw a decrease by almost 2.9% points during the same period as seen from Table 15. Table 16: Sectoral Share of the Grid Electricity Consumption from 2010 to 2019 Year SECTORS Total Residential Non-residential Industrial36 GWh % share GWh % share GWh % share 2010 2,483 37.5 966 14.6 3,174 47.9 6,623 7.7 2011 2,527 33.1 1,199 15.7 3,901 51.1 7,627 15.2 2012 2,819 33.1 1,549 18.2 4,153 48.7 8,521 11.7 2013 3,060 33.9 1,532 17.0 4,435 49.1 9,027 5.9 2014 2,772 30.9 1,529 17.0 4,680 52.1 8,981 -0.5 2015 2,436 29.6 1,531 18.6 4,274 51.9 8,241 -8.2 2016 3,932 40.8 1,068 11.1 4,626 48.1 9,626 16.8 2017 3,931 38.7 1,356 13.3 4,880 48.0 10,167 5.6 2018 4,824 44.0 1,103 10.1 5,046 46.0 10,973 7.9 2019 4,755 41.1 1,523 13.2 5,282 45.7 11,560 5.3 1.6.4 Excess Grid Capacity Figure 9 shows the trend in installed grid capacity, dependable capacity and peak demand from 2009 to 2019. The excess grid capacity started to widen from 2014. 36 NB: Industrial are Special load tariff customers of ECG/PDS and NE