New model PSAs: Oil companies will be required to develop excess gas

…must complete feasibility studies within 2 years of submitting plan

While priority will be given to using gas in oil production, such as for reinjection purposes, oil companies will be required under the new model Production Sharing Agreements (PSA) to develop and submit plans for developing excess gas.
The new model PSAs were released by the Government last week to the public for feedback. The agreements, which cover both deep and shallow blocks, also contain provisions for handling gas finds.
In the agreements, the operator is required to develop excess gas, and to submit plans to the Government on how they will go about this. The plan incorporates both utilisation and commercialisation of natural gas, as well as the markets.

According to the agreements, the plans must describe “utilization and commercialization of associated gas. Description of natural gas markets and infrastructure development in the case of non-associated gas discovery.”
The PSA states that if the contractor believes that the associated gas found in the field has commercial value, that investor will be required to make the investment to utilize it under cost recovery terms. The contractor will also be required to complete feasibility studies on using the gas within two years of submitting development plans.
“If there is any excess associated gas in the oil field after utilization pursuant to Article 19.1(a), the contractor shall carry out a feasibility study regarding the utilization of such excess gas. Such feasibility study, if completed before submittal of the development plan of an oil field, shall be included in the development plan.
“The contractor’s feasibility study shall be completed no later than two years following the submittal of the development plan. If the contractor believes that excess associated gas of an oil field has commercial value, the contractor shall be required to make further investment to utilize such excess associated gas, subject to terms (that include) cost recovery as recoverable contract costs for such further investment.”
This is a similar arrangement that obtains with Guyana and ExxonMobil, which is covering the initial costs of the Gas to-Energy pipeline. These costs, amounting to approximately US$1 billion, will be recovered by the oil company over a period of 20 years.
In budget 2023, the Gas-to-Energy Project received a $43.3 billion allocation. This allocation is in addition to the $24.6 billion injected into the start-up of the transformational project, which includes the construction of an Integrated Natural Gas Liquid (NGL) Plant and the 300-megawatt (MW) Combined Cycle Power Plant at Wales, WBD.
The NGL and 300 MW power plant components of the Gas-to-Shore project are meanwhile expected to cost US$759.8 million, and will be financed through sources that include budgets and loan financing.
The scope of Guyana’s Gas-to-Energy project consists of the construction of 225 kilometres of pipeline from the Liza field in the Stabroek Block offshore Guyana, where Exxon and its partners are currently producing oil.
It features approximately 200 kilometres of a subsea pipeline offshore that will run from Liza Destiny and Liza Unity Floating Production Storage and Offloading (FPSO) vessels in the Stabroek Block to the shore. Upon landing on the West Coast Demerara shore, the pipeline would continue for approximately 25 kilometres to the NGL plant at Wales, West Bank Demerara.
The pipeline would be 12 inches wide, and is expected to transport per day some 50 million standard cubic feet (mscfpd) of dry gas to the NGL plant, but it has the capacity to push as much as 120 mscfpd.
The pipeline’s route onshore would follow the same path as the fibre optic cables, and will terminate at Hermitage, part of the Wales Development Zone (WDZ) which will house the gas-to-shore project.
The new PSAs for both the deep and shallow blocks contain much of the terms the Government had previously hinted at. Under the new conditions, Guyana stands to benefit from as high as US$20 million signature bonuses for the deep-water blocks and US$10 million for the shallow-water blocks.
A perusal of the agreements show that the royalty rate has been increased from the meagre two per cent the former A Partnership for National Unity/Alliance For Change (APNU/AFC) Government agreed to in 2016 to a fixed rate of 10 per cent in both deep and shallow blocks.
Additionally, the model PSAs also include the retention of the 50-50 profit-sharing after cost recovery.
According to the draft agreements, the cost recovery ceiling (limit to which the oil company can recover cost oil) has been lowered to 65 per cent, from the previous 75 per cent. (G3)