CASE STUDIES IN FINANCE (FIN3CSF), SEMESTER 1, 2024 CASE STUDY 2: CORIO GENERATION LIMITED DEVELOPMENT OF...

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CASE STUDIES IN FINANCE (FIN3CSF), SEMESTER 1, 2024 CASE STUDY 2: CORIO GENERATION LIMITED DEVELOPMENT OF AN OFFSHORE WIND FARM PROJECT FOR A TOMAGO ALUMINIUM SMELTER RENEWABLE ENERGY TENDER On March 13th 2024, Tomago Aluminium announced a forthcoming tender for expressions of interest for the supply of renewable energy (electricity) for the operation of its Tomago Aluminium Smelter located in Tomago which is just north of Newcastle, NSW. The Tomago Aluminium Smelter is currently the largest single consumer of electricity in Australia, so transitioning to cleaner, and potentially cheaper, sources of electricity is an important strategic business decision for company. The Tomago Aluminium Smelter commenced smelting operations in 1983 and now employs over 1,200 staff and contractors and produces approximately 37% of all primary aluminium products in Australia. The Tomago Aluminium Smelter business is majority owned by Rio Tinto Limited, the world's second-largest diversified resources company. Corio Generation Limited, a stand-alone portfolio company part of Macquarie Asset Management, is planning on submitting an expression of interest into the tender process associated with the development of a 1.2 Gigawatt (GW) off-shore wind farm located in the Australian Federal Government declared offshore wind area approximately 35 kilometres off the Hunter Central Coast area extending from Norah Head south of Newcastle up to Port Stephens which is north of Newcastle. The total area for the declared offshore wind area is 1,845km. This site is considered as suitable for wind farm location and energy generation as it has consistent strong winds, proximity to electricity transmission infrastructure associated with nearby existing coal-fired power stations, proximity to high demand electricity requirements including the Tomago Aluminium Smelter and growing population centres and availability of support and construction infrastructure using the Port of Newcastle. The proposed offshore wind farm project will have a maximum electricity generation of 1.2 Gigawatts (equivalent to 1,200 Megawatts (MW)) based on the installation and operation of 200 individual wind turbines each with a 6 Megawatt (MW) maximum generation capacity. Initial undersea geological analysis of the declared offshore wind area has indicated varying water depth, resulting in the proposed installation of 150 fixed bottom turbines installed on the sea-bed and 50 floating wind turbines in the area with the deeper water depth. The wind turbine technology associated with the proposed project is based on the rotor blades on each wind turbine being turned by wind moving over them which are attached to a shaft with a gearbox which spins a generator to create electricity. This turbine infrastructure will be connected to an offshore electricity substation using array cabling which will then be connected to an onshore substation using heavy-duty export cabling that will need to be buried under the sea-bed. The onshore substation will then transfer the generated electricity to the electricity grid using the existing above-ground transmission infrastructure (poles and wires). The selected wind turbines for the project are the Siemens SWT-6.0 model wind turbine which have an above- water tip height of 245 metres based on a tower height of 170 metres and a rotor length of 75 metres, with three rotor blades attached to each turbine tower. The wind turbines require a minimum 14.4 kilometres per hour (Km/h) wind speed to begin rotating and maximum electricity generation is achieved at a wind speed of approximately 47 Km/h. The wind turbines 1 will cut-out (stop turning) at very high wind speeds of 90 Km/h and above to prevent damage to the turbine shaft and generating equipment. The envisaged operating life of the offshore wind farm is 30 years following the commencement of full-capacity operation (based on installation of all 200 wind turbines). The planned construction, operational and decommissioning schedule for the offshore wind farm is outlined in the table below subject to acceptance of the project tender proposal by Tomago Aluminium: Date January 1st 2025 January 1st 2028 January 1st 2029 Project Activity Commencement of installation of the fixed bottom wind turbines (sea- bed mounting, tower and rotor blades). The installation schedule is for 50 fixed bottom wind turbines to be installed each year in 2025, 2026 and 2027 (expected completion of fixed bottom wind turbine installation by December 31st 2027). Commencement of installation of the 50 floating wind turbines (expected completion of floating wind turbine installation by December 31st 2028). Commencement of construction and installation of 1) the offshore and onshore electricity substations, 2) connection of the cable array from the wind turbine generators to the offshore substation and the installation of the under sea-bed export cabling to transmit electricity from the offshore substation to the onshore substation, and 3) construction of the transmission infrastructure transferring generated electricity from the onshore substation to the national electricity grid (expected completion of all wind turbine, substation, cabling and transmission infrastructure installation by December 31st 2028). Commencement of electricity generation and transmission by the offshore wind farm (expected to be continuous until December 31st 2058). December 31st 2058 Discontinuation of the offshore wind farm operation and electricity generation and transmission. January 1st 2059 Commencement of the decommissioning and removal of the offshore wind turbines, substation and under-sea cabling infrastructure. Decommission work is expected to continue for two years with 60% of the work completed in 2059 and the remaining 40% completed in 2060 (expected completion of the project decommissioning work by December 31st 2060). The following information outlines the base requirements, specifications and parameters that have been developed or forecast as part of the project planning and analysis: The offshore wind farm will involve the installation and operation of 150 fixed bottom wind turbines and 50 floating wind turbines (200 operational wind turbines in total) each with a maximum generation capacity of 6MW (full capacity operation would generate 6MW hours of electricity per hour). Maximum capacity operation of the overall offshore wind farm would generate 1.2GW hours of electricity per hour. . The cost of the wind turbines (delivered to the Port of Newcastle) is $12 million per wind turbine (in real terms). The under-sea foundation mounting for each fixed bottom wind turbine is an additional $1 million per turbine (in real terms). The estimated installation cost per fixed bottom wind turbine is $4 million (in real terms) and $2 million (in real terms) for each floating wind turbine. The cost of construction and installation of the offshore and onshore electricity substations is $200 million (in real terms) and the cost and installation of the array and export cabling and the transmission infrastructure to connect to the national electricity grid is $150 million (in real terms). The cost of annual maintenance on the offshore wind turbines in 2029 (first year of wind farm electricity generation) will total $180 million (in real terms) and increase 1%, on average, in each subsequent year of wind farm operation due to erosion and weathering effects associated with salt water and the strong winds. Other annual wind farm operating costs are estimated to be $50 million (which will remain constant in real terms). The wind farm and offshore wind turbines will be able to operate 24 hours each day, however, there is expected to be an average operating capacity factor (OCF) of 70% due to periods of light or very high winds. This means that the wind turbines are projected to generate electricity at the maximum generation capacity (based on wind speeds of at least 47 Km/h) only for 70% of the potential maximum operating time. Due to climate change effects winds off the east coast of Australia are predicted to increase in strength in the future, resulting in an annual 0.5% increase in the operating capacity factor for the project after the first year of electricity generation in 2029. The wind farm project will also have to pay an annual $20 million access fee (in real terms) for usage of the declared offshore wind area to the Australian Federal Government. This access fee will become payable from the year that wind farm construction / installation commences through to the year that the wind farm is fully decommissioned and the wind turbines and other offshore wind farm infrastructure are removed. The total estimated cost associated with the decommissioning of the offshore wind farm infrastructure at the end of its operational life is $350 million (in real terms). The project can claim annual straight-line depreciation deductions against the offshore wind farm turbine, mounting, substation, cabling and transmission infrastructure installed costs over the 30-year expected operational life of the wind farm (from 2029 to 2058). Corio Generation expects to be able to charge the Tomago Aluminium Smelter an average electricity tariff price (in real terms) of $90 per MW hour (MWh) for all of the electricity generated by the offshore wind farm. Any project profits will be subject to corporate taxation for Corio Generation at an expected average tax rate of 25% over the life of the project. The offshore wind farm is assumed to operate 24 hours a day, 365 days a year (ignore leap years). The Tomago Aluminium Smelter currently operates 24 hour a day also, so there is no requirement for any form of electricity storage to provide generated electricity to the smelter. The project has an expected long-term after-tax implied cost of capital of 9.50% (in nominal terms). The average rate of inflation over the life of the offshore wind farm project is expected to be 2.80% per annum, near the top of the Reserve Bank of Australia's targeted range. 2 3 All figures are expressed in December 31st 2023 real dollars. All monetary figures are expressed in Australian dollars. The project modelling and evaluation is being undertaken on April 1st 2024. Note that 1 Gigawatt hour represents 1,000 Megawatt hours and 1 Megawatt hour represents 1,000 Kilowatt hours. Corio Generation has engaged your consulting firm to conduct the spreadsheet modelling analysis and capital budgeting evaluation of the offshore wind farm project as well as undertaking project risk assessment and preparation of a business case proposal supporting the project to be submitted as part of the tender application to Tomago Aluminium. Required: This case study requires the completion of the following tasks as part of the project report preparation to support Corio Generation's tender submission: The development of a spreadsheet model representing the cash flows associated with the offshore wind farm project, and the assessment of the project's valuation and return attributes using a range of capital budgeting evaluating techniques. The completion and provision of qualitative and quantitative risk assessments of the project, with the quantitative risk assessment based on conducting appropriate sensitivity and scenario analyses of the project valuation focusing on key parameters impacting on the project's operation, feasibility and cash flows. The preparation of a business case proposal supporting the suitability and attractiveness of the offshore wind farm project for electricity provision to Tomago Aluminium. The due date for submission of this Case Study task is no later than Monday 22nd April 2024 at 11.59pm. This Case Study will represent 25% of the final assessment for this subject and is to be submitted using the upload facility provided in the Case Study 2 block on the subject LMS site. This Case Study is an individual assessment task, and should be a maximum of 1,500 words, excluding any calculations, tables, spreadsheets or other exhibits. The Case Study report should be prepared in a professional manner and include relevant, accurate and logical information to justify any project decision-making and feasibility conclusions drawn. The Case Study report submission should be accompanied by the provision of a spreadsheet model developed for the offshore wind farm project. Generative artificial intelligence (AI) tools such as OpenAI ChatGPT, Google Bard, and Microsoft Copilot are prohibited from being used to complete any requirements of this case study assessment task. 4 Model Components needing determination: 1) Discount rate (required return) Depends on if you create a project spreadsheet model based on real terms or nominal terms The discount rate for the project is directly provided by the project developer in nominal terms, which is 9.50% per annum. Nominal terms: Nominal discount rate = 9.50% per annum Annual discount rate factor = (1 + nominal discount rate)^time value year For year 0 (2023) the discount rate factor = (1.0950)^0 = 1.000. Note that 2023 is Year 0 for the project rather than when project construction / installation is scheduled to start in 2025 because this is the year (point in time) that the cash flows are valued at For year 1 (2024) the discount rate factor = (1.0950)^1 = 1.0950 For year 2 (2025) the discount rate factor = (1.0950)^2 = 1.1990 etc. Project cash flows should then be presented in nominal (inflation- adjusted) terms for consistency Real terms: Real discount rate = [(1 + nominal rate)/(1 + annual inflation rate)] - 1 Annual discount rate factor = (1 + real discount rate)^time value year For year 0 (2023) the discount rate factor = [(1.0950)/(1.0280)]^0 1.0000 = For year 1 (2024) the discount rate factor 1.0652 = [(1.0950)/(1.0280)]^1 = For year 2 (2025) the discount rate factor 1.1346 etc. = [(1.0950)/(1.0280)]^2 = Project cash flows should then be presented in real (inflation-unadjusted terms) for consistency 2) Present value of capital expenditure (equipment and installation costs): = PV of annual capital expenditure Annual capital expenditure cost / applicable discount rate factor or Annual capital expenditure cost 1/(applicable discount rate factor) Should again either be specified in real or nominal terms, depending on the nature of other model components PV of total capital expenditure = (PV of annual capital expenditure from 2025-2028). Bullet points outline the capital expenditure allocations associated with the project: 50 fixed bottom wind turbines are planned to be installed in 2025. Cost = turbine plus mounting costs plus installation costs = (50 ($12,000,000 + $1,000,000))+(50 $4,000,000) = $850,000,000 50 floating wind turbines are planned to be installed in 2028 and all of electrical substation, cabling and transmission. Cost = (50 $12,000,000) + (50 x $2,000,000) + $200,000,000 + $150,000,000 = $1,050,000,000 3) Wind power electricity generated per year The offshore wind farm infrastructure will operate all year round (24 hours per day and assume 365 days per year for simplicity) Although the amount of electricity generation is dependent on wind blowing (at a suitable speed) to turn the turbine rotor blades which spin a generator to generate electricity Information is provided about the expected operating (electricity generating) capacity (effectively the proportion of potential maximum Inputs Key parameters Real Discount Rate 6.52% Nominal Discount Rate 9.50% Inflation Rate 2.80% end operational decommission Time Factor Year Discount rate factor Inflation rate factor CAPEX PV CAPEX Operating Capacity Electricity Generated Electricity Revenue Turbine Maintenance Costs Other operating costs Wind Area Access Cost Annual Dep 0 2023 1 1 1 2024 1.065175097 2 2025 1.134597988 3 2026 1.208545522 4 2027 1.287312594 1.028 1.056784 1.086373952 1.116792423 5 2028 1.371213318 1.14806261 6 2029 1.460582279 1.180208364 7 2030 1.555775871 1.213254198 8 2031 1.657173715 1.247225315 9 2032 1.765180173 1.282147624 10 2033 1.880225962 1.318047758 11 2034 2.002769872 1.354953095 12 2035 2.133300594 1.392891781 13 2036 2.272338667 1.431892751 14 2037 2.420438561 1.471985748 15 2038 2.57819088 1.513201349 16 2039 2.746224721 1.555570987 17 2040 2.925210184 1.599126975 18 2041 3.115861043 1.64390253 19 2042 3.318937589 1.689931801 20 2043 3.535249669 1.737249891 21 2044 3.765659911 1.785892888 22 2045 4.011087162 1.835897889 23 2046 4.272510157 1.88730303 24 2047 4.550971423 1.940147515 25 2048 4.847581428 1.994471645 26 2049 5.163523019 2.050316851 27 2050 5.500056134 2.107725723 28 2051 5.858522828 2.166742043 29 2052 6.240352623 2.227410821 30 2053 6.647068212 2.289778324 31 2054 7.080291529 2.353892117 32 2055 7.541750218 2.419801096 33 2056 8.033284522 2.487555527 34 2057 8.556854623 2.557207081 31/12/2058 35 2058 9.114548455 2.62880888 60% 1/1/2059 36 40% 37 2059 2060 9.708590037 2.702415528 10.34134834 2.778083163 CAPEX PV CAPEX Operating Capacity Electricity Generated Electricity Revenue Turbine Maintenance Costs Other operating costs Wind Area Access Cost Annual Depreciation Operating profit Taxation Net Cash Flow PV Net Cash Flow generation capacity) that will be achieved on average by the offshore wind farm There is also a climate change expectation that wind speeds will increase over time which means that the wind turbine operating capacity factor and the amount of electricity generated will increase over the life of the operation of the offshore wind farm. This is assumed to be an increase in the operating capacity factor (OCF) of 0.50% per year after 2029. Maximum potential wind-powered electricity generated per day (assuming full capacity based on the 200 wind turbines) = Number of wind turbines Wind turbine maximum generating capacity per hour Number of operating hours per day Expected wind-powered electricity generated per day = Number of wind turbines Actual wind turbine operating capacity per hour (OCF) Number of operating hours per day Example calculations For 2029 (the first year of full capacity operation): Wind turbine generation capacity (OCF) in 2029 maximum electricity generation) = 0.7000 (70% of Maximum potential wind-powered electricity generated per day in 2029 = [200 6.00 MW 24 hours] = 28,800.00 megawatt hours (MWh) = Actual expected wind-powered electricity generated per day in 2029 - [200 6.00 MW 0.7000 24 hours] = 20,160.00 megawatt hours (MWh) These electricity generation outcomes will change each year with the indicated wind speed increases related to climate change effects and associated incremental OCF increases 4) Project revenue Project revenue will be based on the amount of electricity generated annually multiplied by the expected average electricity tariff rate that it can be sold to Tomago Aluminium for Electricity revenue = - Annual wind-powered electricity generated fixed rate electricity tariff For 2029 = 20,160.00 MWh per day 365 days $90.00 electricity tariff per MWh = $662,256,000 5 This is a real terms figure, and will be higher if you structure your spreadsheet model in nominal terms 5) Turbine maintenance costs This is the largest indicated ongoing project cost due to the importance of wind turbine operation to the revenue generation of the project and the harsh conditions associated with offshore wind farm locations. Estimated to be $180,000,000 in 2029, with turbine maintenance costs increasing 1% each year thereafter due to ongoing wear and tear associated with the offshore conditions. Turbine maintenance costs in 2030 (in real terms) = $180,000,000 (1+ (1 0.01)) = $181,800,000 6) Other operating costs Annual other operating costs are a set amount in real terms primarily reflecting costs associated with the staffing and operation of the offshore wind farm excluding the substantial turbine maintenance cost expectations Indicated to be $50,000,000 per year from the first year of wind farm operation onward (in real terms) These will either be real or nominal costs based on how the spreadsheet model is specified 7) Declared offshore wind area access costs Corio Generation will have to pay for annual access to the offshore wind farm area to the Australian Federal Government Access payments are indicated to be payable from the first year of construction / installation through to the final year of decommissioning / dismantling of the wind farm infrastructure Indicated to be $20,000,000 per year in real terms Will be higher incrementally in nominal terms 8) Depreciation charges Depreciation is based on a straight-line allocation across the 30 years of full operation of the wind farm project (from 2029-2058), based on the installed value of the project infrastructure (including wind turbines, substation, cabling and transmission equipment) Depreciation amount = Installed cost / 30 or Installed cost 0.0333 6 Correct treatment of depreciation allocations in real and nominal terms is important. Depreciation is a non-cash item and is not influenced by inflation. As such, depreciation allocations should decline in magnitude in real terms over time by the accumulated inflation rate (as they effectively provide less benefit over time), whereas they should be constant in nominal terms Nominal depreciation allocation in 2029 $120,000,000 = $3,600,000,000 / 30 = Real depreciation allocation in 2029 $101,676,961 == $120,000,000 / (1.0280)6 = 9) Operating profit before tax per year - Annual real operating profit before tax = Annual real electricity revenue annual real turbine maintenance costs annual real operating costs annual real wind area access costs annual real Depreciation charge Annual nominal operating profit before tax = Annual nominal electricity revenue annual nominal turbine maintenance costs annual nominal operating costs - annual nominal wind area access costs annual nominal Depreciation charge Note there is no need to separately adjust this calculation for inflation as inflation effects are already incorporated in each of the calculation components 10) Taxation expenditure per year = Annual real taxation expense applicable tax rate for the project Annual real operating profit before tax = Annual nominal operating profit before Annual nominal taxation expense tax applicable tax rate for the project 11) Net (after-tax) cash flow per year Need to add back depreciation charges to return the after-tax profit figure to a cash flow equivalent Annual real net cash flow = Annual real operating profit before tax annual real taxation expense + annual real Depreciation charge 7 Annual nominal net cash flow = Annual nominal operating profit before tax annual nominal taxation expense + annual nominal Depreciation charge 12) Present value of net cash flow per year PV of annual real net cash flow = Annual real net cash flow / applicable real discount factor or Annual real net cash flow 1/(applicable real discount factor) = PV of annual nominal net cash flow Annual nominal net cash flow / applicable nominal discount factor or Annual nominal net cash flow 1/(applicable nominal discount factor) Note that this is just one example of a number of ways that discounting could be incorporated into a spreadsheet cash flow model 13) Other cash flow inclusions and adjustments Project decommissioning / dismantling expenditure of $350,000,000 which will occur across 2059 and 2060 based on this specific project being discontinued at the end of the indicated useful life of the wind farm turbine and transmission infrastructure This is a real terms estimated cost and is indicated to be apportioned 60% in 2059 and 40% in 2060 14) Net present value (NPV) of project Project NPV (PV of annual net cash flows from 2029-2060) - PV of total capital expenditure from 2025-2028 Note that this equation specifically separates project operating cash flows from investment (construction and installation) cash flows, whereas just one overall project cash flow incorporate inflows and outflows could be calculated Also want to think about using other project evaluation techniques as well, such as IRR, profitability index, discounted and undiscounted payback period etc. 8 CASE STUDIES IN FINANCE (FIN3CSF), SEMESTER 1, 2024 CASE STUDY 2: CORIO GENERATION LIMITED DEVELOPMENT OF AN OFFSHORE WIND FARM PROJECT FOR A TOMAGO ALUMINIUM SMELTER RENEWABLE ENERGY TENDER On March 13th 2024, Tomago Aluminium announced a forthcoming tender for expressions of interest for the supply of renewable energy (electricity) for the operation of its Tomago Aluminium Smelter located in Tomago which is just north of Newcastle, NSW. The Tomago Aluminium Smelter is currently the largest single consumer of electricity in Australia, so transitioning to cleaner, and potentially cheaper, sources of electricity is an important strategic business decision for company. The Tomago Aluminium Smelter commenced smelting operations in 1983 and now employs over 1,200 staff and contractors and produces approximately 37% of all primary aluminium products in Australia. The Tomago Aluminium Smelter business is majority owned by Rio Tinto Limited, the world's second-largest diversified resources company. Corio Generation Limited, a stand-alone portfolio company part of Macquarie Asset Management, is planning on submitting an expression of interest into the tender process associated with the development of a 1.2 Gigawatt (GW) off-shore wind farm located in the Australian Federal Government declared offshore wind area approximately 35 kilometres off the Hunter Central Coast area extending from Norah Head south of Newcastle up to Port Stephens which is north of Newcastle. The total area for the declared offshore wind area is 1,845km. This site is considered as suitable for wind farm location and energy generation as it has consistent strong winds, proximity to electricity transmission infrastructure associated with nearby existing coal-fired power stations, proximity to high demand electricity requirements including the Tomago Aluminium Smelter and growing population centres and availability of support and construction infrastructure using the Port of Newcastle. The proposed offshore wind farm project will have a maximum electricity generation of 1.2 Gigawatts (equivalent to 1,200 Megawatts (MW)) based on the installation and operation of 200 individual wind turbines each with a 6 Megawatt (MW) maximum generation capacity. Initial undersea geological analysis of the declared offshore wind area has indicated varying water depth, resulting in the proposed installation of 150 fixed bottom turbines installed on the sea-bed and 50 floating wind turbines in the area with the deeper water depth. The wind turbine technology associated with the proposed project is based on the rotor blades on each wind turbine being turned by wind moving over them which are attached to a shaft with a gearbox which spins a generator to create electricity. This turbine infrastructure will be connected to an offshore electricity substation using array cabling which will then be connected to an onshore substation using heavy-duty export cabling that will need to be buried under the sea-bed. The onshore substation will then transfer the generated electricity to the electricity grid using the existing above-ground transmission infrastructure (poles and wires). The selected wind turbines for the project are the Siemens SWT-6.0 model wind turbine which have an above- water tip height of 245 metres based on a tower height of 170 metres and a rotor length of 75 metres, with three rotor blades attached to each turbine tower. The wind turbines require a minimum 14.4 kilometres per hour (Km/h) wind speed to begin rotating and maximum electricity generation is achieved at a wind speed of approximately 47 Km/h. The wind turbines 1 will cut-out (stop turning) at very high wind speeds of 90 Km/h and above to prevent damage to the turbine shaft and generating equipment. The envisaged operating life of the offshore wind farm is 30 years following the commencement of full-capacity operation (based on installation of all 200 wind turbines). The planned construction, operational and decommissioning schedule for the offshore wind farm is outlined in the table below subject to acceptance of the project tender proposal by Tomago Aluminium: Date January 1st 2025 January 1st 2028 January 1st 2029 Project Activity Commencement of installation of the fixed bottom wind turbines (sea- bed mounting, tower and rotor blades). The installation schedule is for 50 fixed bottom wind turbines to be installed each year in 2025, 2026 and 2027 (expected completion of fixed bottom wind turbine installation by December 31st 2027). Commencement of installation of the 50 floating wind turbines (expected completion of floating wind turbine installation by December 31st 2028). Commencement of construction and installation of 1) the offshore and onshore electricity substations, 2) connection of the cable array from the wind turbine generators to the offshore substation and the installation of the under sea-bed export cabling to transmit electricity from the offshore substation to the onshore substation, and 3) construction of the transmission infrastructure transferring generated electricity from the onshore substation to the national electricity grid (expected completion of all wind turbine, substation, cabling and transmission infrastructure installation by December 31st 2028). Commencement of electricity generation and transmission by the offshore wind farm (expected to be continuous until December 31st 2058). December 31st 2058 Discontinuation of the offshore wind farm operation and electricity generation and transmission. January 1st 2059 Commencement of the decommissioning and removal of the offshore wind turbines, substation and under-sea cabling infrastructure. Decommission work is expected to continue for two years with 60% of the work completed in 2059 and the remaining 40% completed in 2060 (expected completion of the project decommissioning work by December 31st 2060). The following information outlines the base requirements, specifications and parameters that have been developed or forecast as part of the project planning and analysis: The offshore wind farm will involve the installation and operation of 150 fixed bottom wind turbines and 50 floating wind turbines (200 operational wind turbines in total) each with a maximum generation capacity of 6MW (full capacity operation would generate 6MW hours of electricity per hour). Maximum capacity operation of the overall offshore wind farm would generate 1.2GW hours of electricity per hour. . The cost of the wind turbines (delivered to the Port of Newcastle) is $12 million per wind turbine (in real terms). The under-sea foundation mounting for each fixed bottom wind turbine is an additional $1 million per turbine (in real terms). The estimated installation cost per fixed bottom wind turbine is $4 million (in real terms) and $2 million (in real terms) for each floating wind turbine. The cost of construction and installation of the offshore and onshore electricity substations is $200 million (in real terms) and the cost and installation of the array and export cabling and the transmission infrastructure to connect to the national electricity grid is $150 million (in real terms). The cost of annual maintenance on the offshore wind turbines in 2029 (first year of wind farm electricity generation) will total $180 million (in real terms) and increase 1%, on average, in each subsequent year of wind farm operation due to erosion and weathering effects associated with salt water and the strong winds. Other annual wind farm operating costs are estimated to be $50 million (which will remain constant in real terms). The wind farm and offshore wind turbines will be able to operate 24 hours each day, however, there is expected to be an average operating capacity factor (OCF) of 70% due to periods of light or very high winds. This means that the wind turbines are projected to generate electricity at the maximum generation capacity (based on wind speeds of at least 47 Km/h) only for 70% of the potential maximum operating time. Due to climate change effects winds off the east coast of Australia are predicted to increase in strength in the future, resulting in an annual 0.5% increase in the operating capacity factor for the project after the first year of electricity generation in 2029. The wind farm project will also have to pay an annual $20 million access fee (in real terms) for usage of the declared offshore wind area to the Australian Federal Government. This access fee will become payable from the year that wind farm construction / installation commences through to the year that the wind farm is fully decommissioned and the wind turbines and other offshore wind farm infrastructure are removed. The total estimated cost associated with the decommissioning of the offshore wind farm infrastructure at the end of its operational life is $350 million (in real terms). The project can claim annual straight-line depreciation deductions against the offshore wind farm turbine, mounting, substation, cabling and transmission infrastructure installed costs over the 30-year expected operational life of the wind farm (from 2029 to 2058). Corio Generation expects to be able to charge the Tomago Aluminium Smelter an average electricity tariff price (in real terms) of $90 per MW hour (MWh) for all of the electricity generated by the offshore wind farm. Any project profits will be subject to corporate taxation for Corio Generation at an expected average tax rate of 25% over the life of the project. The offshore wind farm is assumed to operate 24 hours a day, 365 days a year (ignore leap years). The Tomago Aluminium Smelter currently operates 24 hour a day also, so there is no requirement for any form of electricity storage to provide generated electricity to the smelter. The project has an expected long-term after-tax implied cost of capital of 9.50% (in nominal terms). The average rate of inflation over the life of the offshore wind farm project is expected to be 2.80% per annum, near the top of the Reserve Bank of Australia's targeted range. 2 3 All figures are expressed in December 31st 2023 real dollars. All monetary figures are expressed in Australian dollars. The project modelling and evaluation is being undertaken on April 1st 2024. Note that 1 Gigawatt hour represents 1,000 Megawatt hours and 1 Megawatt hour represents 1,000 Kilowatt hours. Corio Generation has engaged your consulting firm to conduct the spreadsheet modelling analysis and capital budgeting evaluation of the offshore wind farm project as well as undertaking project risk assessment and preparation of a business case proposal supporting the project to be submitted as part of the tender application to Tomago Aluminium. Required: This case study requires the completion of the following tasks as part of the project report preparation to support Corio Generation's tender submission: The development of a spreadsheet model representing the cash flows associated with the offshore wind farm project, and the assessment of the project's valuation and return attributes using a range of capital budgeting evaluating techniques. The completion and provision of qualitative and quantitative risk assessments of the project, with the quantitative risk assessment based on conducting appropriate sensitivity and scenario analyses of the project valuation focusing on key parameters impacting on the project's operation, feasibility and cash flows. The preparation of a business case proposal supporting the suitability and attractiveness of the offshore wind farm project for electricity provision to Tomago Aluminium. The due date for submission of this Case Study task is no later than Monday 22nd April 2024 at 11.59pm. This Case Study will represent 25% of the final assessment for this subject and is to be submitted using the upload facility provided in the Case Study 2 block on the subject LMS site. This Case Study is an individual assessment task, and should be a maximum of 1,500 words, excluding any calculations, tables, spreadsheets or other exhibits. The Case Study report should be prepared in a professional manner and include relevant, accurate and logical information to justify any project decision-making and feasibility conclusions drawn. The Case Study report submission should be accompanied by the provision of a spreadsheet model developed for the offshore wind farm project. Generative artificial intelligence (AI) tools such as OpenAI ChatGPT, Google Bard, and Microsoft Copilot are prohibited from being used to complete any requirements of this case study assessment task. 4 Model Components needing determination: 1) Discount rate (required return) Depends on if you create a project spreadsheet model based on real terms or nominal terms The discount rate for the project is directly provided by the project developer in nominal terms, which is 9.50% per annum. Nominal terms: Nominal discount rate = 9.50% per annum Annual discount rate factor = (1 + nominal discount rate)^time value year For year 0 (2023) the discount rate factor = (1.0950)^0 = 1.000. Note that 2023 is Year 0 for the project rather than when project construction / installation is scheduled to start in 2025 because this is the year (point in time) that the cash flows are valued at For year 1 (2024) the discount rate factor = (1.0950)^1 = 1.0950 For year 2 (2025) the discount rate factor = (1.0950)^2 = 1.1990 etc. Project cash flows should then be presented in nominal (inflation- adjusted) terms for consistency Real terms: Real discount rate = [(1 + nominal rate)/(1 + annual inflation rate)] - 1 Annual discount rate factor = (1 + real discount rate)^time value year For year 0 (2023) the discount rate factor = [(1.0950)/(1.0280)]^0 1.0000 = For year 1 (2024) the discount rate factor 1.0652 = [(1.0950)/(1.0280)]^1 = For year 2 (2025) the discount rate factor 1.1346 etc. = [(1.0950)/(1.0280)]^2 = Project cash flows should then be presented in real (inflation-unadjusted terms) for consistency 2) Present value of capital expenditure (equipment and installation costs): = PV of annual capital expenditure Annual capital expenditure cost / applicable discount rate factor or Annual capital expenditure cost 1/(applicable discount rate factor) Should again either be specified in real or nominal terms, depending on the nature of other model components PV of total capital expenditure = (PV of annual capital expenditure from 2025-2028). Bullet points outline the capital expenditure allocations associated with the project: 50 fixed bottom wind turbines are planned to be installed in 2025. Cost = turbine plus mounting costs plus installation costs = (50 ($12,000,000 + $1,000,000))+(50 $4,000,000) = $850,000,000 50 floating wind turbines are planned to be installed in 2028 and all of electrical substation, cabling and transmission. Cost = (50 $12,000,000) + (50 x $2,000,000) + $200,000,000 + $150,000,000 = $1,050,000,000 3) Wind power electricity generated per year The offshore wind farm infrastructure will operate all year round (24 hours per day and assume 365 days per year for simplicity) Although the amount of electricity generation is dependent on wind blowing (at a suitable speed) to turn the turbine rotor blades which spin a generator to generate electricity Information is provided about the expected operating (electricity generating) capacity (effectively the proportion of potential maximum Inputs Key parameters Real Discount Rate 6.52% Nominal Discount Rate 9.50% Inflation Rate 2.80% end operational decommission Time Factor Year Discount rate factor Inflation rate factor CAPEX PV CAPEX Operating Capacity Electricity Generated Electricity Revenue Turbine Maintenance Costs Other operating costs Wind Area Access Cost Annual Dep 0 2023 1 1 1 2024 1.065175097 2 2025 1.134597988 3 2026 1.208545522 4 2027 1.287312594 1.028 1.056784 1.086373952 1.116792423 5 2028 1.371213318 1.14806261 6 2029 1.460582279 1.180208364 7 2030 1.555775871 1.213254198 8 2031 1.657173715 1.247225315 9 2032 1.765180173 1.282147624 10 2033 1.880225962 1.318047758 11 2034 2.002769872 1.354953095 12 2035 2.133300594 1.392891781 13 2036 2.272338667 1.431892751 14 2037 2.420438561 1.471985748 15 2038 2.57819088 1.513201349 16 2039 2.746224721 1.555570987 17 2040 2.925210184 1.599126975 18 2041 3.115861043 1.64390253 19 2042 3.318937589 1.689931801 20 2043 3.535249669 1.737249891 21 2044 3.765659911 1.785892888 22 2045 4.011087162 1.835897889 23 2046 4.272510157 1.88730303 24 2047 4.550971423 1.940147515 25 2048 4.847581428 1.994471645 26 2049 5.163523019 2.050316851 27 2050 5.500056134 2.107725723 28 2051 5.858522828 2.166742043 29 2052 6.240352623 2.227410821 30 2053 6.647068212 2.289778324 31 2054 7.080291529 2.353892117 32 2055 7.541750218 2.419801096 33 2056 8.033284522 2.487555527 34 2057 8.556854623 2.557207081 31/12/2058 35 2058 9.114548455 2.62880888 60% 1/1/2059 36 40% 37 2059 2060 9.708590037 2.702415528 10.34134834 2.778083163 CAPEX PV CAPEX Operating Capacity Electricity Generated Electricity Revenue Turbine Maintenance Costs Other operating costs Wind Area Access Cost Annual Depreciation Operating profit Taxation Net Cash Flow PV Net Cash Flow generation capacity) that will be achieved on average by the offshore wind farm There is also a climate change expectation that wind speeds will increase over time which means that the wind turbine operating capacity factor and the amount of electricity generated will increase over the life of the operation of the offshore wind farm. This is assumed to be an increase in the operating capacity factor (OCF) of 0.50% per year after 2029. Maximum potential wind-powered electricity generated per day (assuming full capacity based on the 200 wind turbines) = Number of wind turbines Wind turbine maximum generating capacity per hour Number of operating hours per day Expected wind-powered electricity generated per day = Number of wind turbines Actual wind turbine operating capacity per hour (OCF) Number of operating hours per day Example calculations For 2029 (the first year of full capacity operation): Wind turbine generation capacity (OCF) in 2029 maximum electricity generation) = 0.7000 (70% of Maximum potential wind-powered electricity generated per day in 2029 = [200 6.00 MW 24 hours] = 28,800.00 megawatt hours (MWh) = Actual expected wind-powered electricity generated per day in 2029 - [200 6.00 MW 0.7000 24 hours] = 20,160.00 megawatt hours (MWh) These electricity generation outcomes will change each year with the indicated wind speed increases related to climate change effects and associated incremental OCF increases 4) Project revenue Project revenue will be based on the amount of electricity generated annually multiplied by the expected average electricity tariff rate that it can be sold to Tomago Aluminium for Electricity revenue = - Annual wind-powered electricity generated fixed rate electricity tariff For 2029 = 20,160.00 MWh per day 365 days $90.00 electricity tariff per MWh = $662,256,000 5 This is a real terms figure, and will be higher if you structure your spreadsheet model in nominal terms 5) Turbine maintenance costs This is the largest indicated ongoing project cost due to the importance of wind turbine operation to the revenue generation of the project and the harsh conditions associated with offshore wind farm locations. Estimated to be $180,000,000 in 2029, with turbine maintenance costs increasing 1% each year thereafter due to ongoing wear and tear associated with the offshore conditions. Turbine maintenance costs in 2030 (in real terms) = $180,000,000 (1+ (1 0.01)) = $181,800,000 6) Other operating costs Annual other operating costs are a set amount in real terms primarily reflecting costs associated with the staffing and operation of the offshore wind farm excluding the substantial turbine maintenance cost expectations Indicated to be $50,000,000 per year from the first year of wind farm operation onward (in real terms) These will either be real or nominal costs based on how the spreadsheet model is specified 7) Declared offshore wind area access costs Corio Generation will have to pay for annual access to the offshore wind farm area to the Australian Federal Government Access payments are indicated to be payable from the first year of construction / installation through to the final year of decommissioning / dismantling of the wind farm infrastructure Indicated to be $20,000,000 per year in real terms Will be higher incrementally in nominal terms 8) Depreciation charges Depreciation is based on a straight-line allocation across the 30 years of full operation of the wind farm project (from 2029-2058), based on the installed value of the project infrastructure (including wind turbines, substation, cabling and transmission equipment) Depreciation amount = Installed cost / 30 or Installed cost 0.0333 6 Correct treatment of depreciation allocations in real and nominal terms is important. Depreciation is a non-cash item and is not influenced by inflation. As such, depreciation allocations should decline in magnitude in real terms over time by the accumulated inflation rate (as they effectively provide less benefit over time), whereas they should be constant in nominal terms Nominal depreciation allocation in 2029 $120,000,000 = $3,600,000,000 / 30 = Real depreciation allocation in 2029 $101,676,961 == $120,000,000 / (1.0280)6 = 9) Operating profit before tax per year - Annual real operating profit before tax = Annual real electricity revenue annual real turbine maintenance costs annual real operating costs annual real wind area access costs annual real Depreciation charge Annual nominal operating profit before tax = Annual nominal electricity revenue annual nominal turbine maintenance costs annual nominal operating costs - annual nominal wind area access costs annual nominal Depreciation charge Note there is no need to separately adjust this calculation for inflation as inflation effects are already incorporated in each of the calculation components 10) Taxation expenditure per year = Annual real taxation expense applicable tax rate for the project Annual real operating profit before tax = Annual nominal operating profit before Annual nominal taxation expense tax applicable tax rate for the project 11) Net (after-tax) cash flow per year Need to add back depreciation charges to return the after-tax profit figure to a cash flow equivalent Annual real net cash flow = Annual real operating profit before tax annual real taxation expense + annual real Depreciation charge 7 Annual nominal net cash flow = Annual nominal operating profit before tax annual nominal taxation expense + annual nominal Depreciation charge 12) Present value of net cash flow per year PV of annual real net cash flow = Annual real net cash flow / applicable real discount factor or Annual real net cash flow 1/(applicable real discount factor) = PV of annual nominal net cash flow Annual nominal net cash flow / applicable nominal discount factor or Annual nominal net cash flow 1/(applicable nominal discount factor) Note that this is just one example of a number of ways that discounting could be incorporated into a spreadsheet cash flow model 13) Other cash flow inclusions and adjustments Project decommissioning / dismantling expenditure of $350,000,000 which will occur across 2059 and 2060 based on this specific project being discontinued at the end of the indicated useful life of the wind farm turbine and transmission infrastructure This is a real terms estimated cost and is indicated to be apportioned 60% in 2059 and 40% in 2060 14) Net present value (NPV) of project Project NPV (PV of annual net cash flows from 2029-2060) - PV of total capital expenditure from 2025-2028 Note that this equation specifically separates project operating cash flows from investment (construction and installation) cash flows, whereas just one overall project cash flow incorporate inflows and outflows could be calculated Also want to think about using other project evaluation techniques as well, such as IRR, profitability index, discounted and undiscounted payback period etc. 8