The sale of oil and gas fields and their physical assets is a common necessity with the evolution of hydrocarbon basins. Deals in the U.K. sector alone surpassed $8 billion in 2017, according to the U.K. Oil & Gas Business Outlook 2018. It also is an increasing trend where the large, international operators divest their assets to small independents or mid-cap players that have a geographical focus or specialize in certain reservoir types.
However, purchasing an asset and taking on operatorship are part of a complex process, requiring robust due diligence and a well-considered transition plan to ensure achievement of production goals. Most deals are predicted to have a monetary upside, and so pursuing these incremental projects can be successful as long as there is a clear understanding of the condition and life expectancy of assets, realistic capex and opex estimates, identification and management of the risks involved, and the post-purchase strategy to maximize production and identify new revenue sources.
The actual transfer of operatorship is a specific time and date on which the outgoing operator relinquishes its responsibilities and the incoming operator takes over legal responsibility. Asset transfer represents a significant change process across a typical organization’s technical and functional groups and has a hard deadline and often complex issues to address (Figure 1).
Issues and challenges that could arise during an asset transfer process are numerous, and it is important to understand the risks.
FIGURE 1. The transition process and the asset transfer are governed by a number of objectives that cover three areas: production, transition, and HSE and integrity. (Source: Lloyd’s Registry)
Duty of care and regulatory compliance
The primary task is to ensure that the new operator can meet the legislative requirements of an operator from day one—executing its duty of care to the legislative standards of the country in which it operates and to its organizational standards. In instances where the regulator’s requirements are not met, third-party duty holders may need to be appointed.
Integrating the people factor
An asset transfer relies on the knowledge and skills of the personnel involved. People are integral to the transfer of knowledge. While there will be operating procedures, manuals and guidance, retaining the existing working knowledge of the asset is the cornerstone of achieving a safe and efficient transfer of operatorship.
Experience has shown that setting up a dedicated asset transfer management team to operate the asset and deliver the functional support required is essential. This team is also responsible for structuring a framework for the project governance which includes project tracking, reporting and assurance at appropriate review points.
Managing systems and process
Organizational operating systems need to be considered, and it could be as simple as transferring key management systems from the outgoing company into the new one. However, it is often the case that the operating systems are corporate and not standalone, and cannot be transferred directly but have to be substituted.
Enterprise risk planning (ERP) systems typically contain finance/human resources/inventory management and maintenance systems, and systems need to be migrated. On a large asset transfer, this will include a huge volume of data. Each operator will run its customized ERP system so any migration will need a process to map systems, data and extensive quality assurance/ quality control and testing along with safety case and environmental plans.
Asset integrity and architecture complexities
It is a basic requirement to understand what is being bought, such as the asset inventory, as well as its boundaries and interfaces with other assets. An asset integrity review is needed to determine the status of wells, platforms, production facilities and pipelines. Taking over existing projects that the outgoing operator has already started also requires a high level of coordination to agree how and when the projects will be taken over and where the financial responsibility lies between each company.
Additionally, larger assets are a complex network of wells, platforms and pipelines. There may be interrelated third-party arrangements for platforms processing hydrocarbons and product transported by pipelines. In extreme cases, there may be different license holders for different reservoirs in the same field. This adds to the complexity of any transfer and the ongoing responsibilities and liabilities between the new operator and other stakeholders.
Reservoir and data management
Often the subsurface team will not transfer from the previous operator, and this presents challenges given the accumulated knowledge is lost, even though subsurface data and models are transferred. The asset transfer goal for reservoir management is usually on the basis that reservoir performance is maintained, flow assurance strategies are in place and that well intervention plans are enhanced to maintain production.
The liability for decommissioning an asset rests with the licensees, and this is transferred to new operators under the Petroleum Act 1998. Current guidance suggests that this liability persists in “perpetuity” and the government reserves the right to hold licenses responsible both jointly and severally. The current regulatory framework also permits previous licensees to be pursued for decommissioning costs even if they have transferred ownership to other parties. All operators are required to have a mechanism for ensuring financial security to cover their potential decommissioning liabilities. This has been a factor in some large merger and acquisition opportunities in oil and gas where an accurate view of any company’s asset retirement obligations (AROs) are an important part of the valuation of an asset.
A recent financial review suggests that eight international oil companies (IOCs) have AROs on their balance sheets of more than $10 billion each, and, since 2010, the AROs of the seven largest IOCs have increased year over year. Estimating future costs is inherently risky, as the industry does not know how technology or standards will develop. So while decommissioning is a critical issue, it is difficult to tell whether sufficient or excess capital is being set aside.
Recent high-profile transfer cases have demonstrated that previous owners, although not responsible for how the asset is decommissioned, have retained some liability regarding costs. For example, the decommissioning cost associated with the assets sold by Shell to Chrysaor in 2017 is estimated at $3.9 billion, and Shell has retained a fixed liability of $1 billion for decommissioning these assets.
There may be up to 12 functional areas to consider across technical and nontechnical disciplines (Figure 2). The plan should focus only on key tasks required to deliver the objectives of the asset transfer, including a framing session such that everyone is at the same starting point in the project and that the company objectives of the asset transfer are clearly articulated and understood by everyone.
The asset transfer management team also can create a transition agreement between the outgoing and incoming operator. This agreement sets down the agreed methodology between the two parties on the implementation of specific noncontractual tasks of the asset transfer plan.
There are complexities in any asset transfer that increase the risk potential. An asset transfer risk register created alongside the main transfer plan can help to identify these risks and determine the mitigation measures needed depending on the criticality of each risk.
FIGURE 2. There are 12 key areas of focus during the transition of assets. (Source: Lloyd’s Registry)
The joint development project has a water depth of about 410 meters and features one 150,000-DWT FPSO with three underwater production systems, CNOOC said.
The Almirante Tamandaré FPSO unit is set to be Brazil’s largest, with capacity to produce 225,000 barrels of oil per day and 12 million cubic meters of gas, Petrobras said.
The Scoop and Stack plays are still in the money but only with improved well spacing and effective management of frac-driven interactions.