Appraise the risks associated with future oil investment and the operation of the petroleum industry.
Evaluate petroleum fiscal systems and their effects on project viability
Evaluate the global trends and movement in oil and gas markets, timing efficiency and bench marking in the industry.
Critically appraise the effects of current and future trends on the dynamics of the industry including the impact of the unconventional resources and renewable energy
Evaluate the strategic approaches in the future oil and gas industry.
This coursework is meant to test your understanding of the global petroleum industry, particularly the risk and fiscal terms, the global trends, strategies, industry benchmarks and challenges in decision making in the industry. You will appreciate the difficulty of selecting international upstream opportunities capable of generating real value, well in excess of the overall costs.
Your organisation Godiva Petroleum (GP) is considering options to develop a portfolio of assets both within the traditional petroleum industry, unconventional resources industry and the renewable energy sectors with which you wish to develop your future growth. GP has domestic production which is declining rapidly. Company Production is currently 120,000 boe/d. To maintain replacement and growth, the focus has now switched to rationalizing upstream and renewable energy assets in seven countries: Libya, Morocco, UK North Sea, Ghana, Canada, Caspian Sea and Mozambique.
Develop a portfolio out of all the assets by selecting those assets that in your view address the key challenges and opportunities. You may consider divestments and acquisitions to re-configure the final portfolio: –
Value
Continuing production
Product mix-oil /gas/ energy
Diversity of supply.
Operational & political risk
Future of the energy industry and climate change
Long term and short-term financial benefits
The DP Board has approved an annual budget expenditure of $950 million /year for the next six years for the purpose of this project.
You are expected to develop a ten-year strategic plan using all available resources and industry benchmarks to address the current declining production of GP worldwide and optimise the portfolio. You are expected to submit no more than 10 pages of report (1000 words per person) to show and justify your decisions and the rationale behind them. You must show all financial computations underpinning your choices and decisions.
Use the average oil price/UK energy price in 2019 to make your decisions. You may also want to consider prices sensitivity to the success of the project. You will also be making a 15 minutes’ presentation to the Management of GP on a date to be announced to defend your choices and decisions.
ASSETS
Libya
Your company has discovered 2 oilfields (Field A is a net reserve of 500 million barrel and Field B is 585 million barrels). The two fields are 43km apart in the Sahara Desert and the Government has ring fenced the fields. There is also one large gas field (net reserves of 10 trillion cubic feet). Crude quality is good at 340API, with sweet rich gas yielding ethane and propane. The gas has a ready market through pipeline sales contracts agreed with purchasers in Southern Europe. Development costs are estimated at $10.5/boe for the two oil fields. Net additional costs comprise a spur oil pipeline system estimated at $120million. Transport and tariff costs to coastal export facilities have been agreed at $3.70/boe. Operating costs are high at $11/boe. Fiscal terms administered under a production-sharing agreement. A price cap of $60/bbl is applied, with 2.95/mmbtu for gas. Initial Crude Oil Production set for June 2023 at a rate of 180,000 bopd net. Initial Gas Production set for September 2021 at a rate of 650mmcfg/d. with sales contracts in place.
UK North Sea
Equity holdings in mature assets: 5 oilfields (net reserves 130mmbbls) and 3 gas fields (net reserves 1000bcf). 3 fields are operated by your company. Production rates from both oilfields and gas fields are rapidly declining.
Oilfields
Aggregate production of 35,000 bopd from the 5 oilfields in 2016 but without incremental investments is forecast to decline to <20,000bopd by 2021.
Gas fields
Forecast to decline to 300mmcf/d but without incremental investments is forecast to decline to ~200mmcfg/d by 2021. Development costs are high at $12/boe for small, discovered satellite oilfields that can sustain the existing production rates at current prices. Operating costs: $13/boe and rising owing to increased cost pressures and declining production.
Alberta, Canada
Equity holdings in 20,000 acres of oil sands in area near Fort McMurray in northern Alberta. Potential reserves: 1200mmbbls. Current net production 35,000 bopd of bitumen. Large potential reserves that could be developed at a cost of $15/boe
Operating Cost: $11/barrel Environmental Costs: $3.50 barrel
Bitumen Sales price: WTI minus $20/bbl, SCO Sales price WTI minus $7/bbl
Synthetic Oil upgrade cost: $6/barrel
Plans to upgrade plant to increase production to net 80,000 bopd by 2021
Morocco
Equity interest in 600 hectares of land with Solar PV development expected to generate 250MW for domestic national consumption. The Levelized Cost of Energy (LCOE) is estimated at $0.31 per kWh.
Caspian Sea (Kazakhstan)
Equity interests in 3 licences with aggregate net reserves of 650 million barrels. The onshore projects will cost $5/boe to develop. Tariff costs via export pipeline are $3.50/boe to Asian export markets.
Crude oil quality: 280API, 3% sulphur
Sales Price: Brent minus $7.00
Development plan would yield net 200,000 barrels by 2025.
Potential additional reserves remain to be found.
Finding Costs currently running at $4/boe.
Projected operating costs: $5/boe
Mozambique
Equity interests in 3 licences with aggregate net gas reserves of 68TCF. The offshore projects will cost $16/boe to develop.
Finding Costs currently running at $2/boe.
Projected operating costs: $8/boe
No existing pipeline network to the market. LNG plant is planned for delivery in June 2022. Some uncertainty in fiscal regime.
Ghana
Equity interests in 3 licences with aggregate net reserves of 1.8 billion barrels. The offshore projects will cost $22/boe to develop. Tariff costs via ships are $3.50/boe to the Chinese and European export markets.
Crude oil quality: 350API, 0.5% sulphur
Sales Price: Brent plus $3.50
Development plan would yield net 165,000 barrels by 2024.
Potential additional reserves remain to be found.
Finding Costs currently running at $6/boe.
Projected operating costs: $11/boe