Introduction
The Petroleum Industry Act (PIA) was passed in August 2021, initiating the restructuring of regulation for the oil and gas sector in Nigeria, with a significant impact on communities that host operations. One section of the Act is focused on community development and provides for the establishment of Host Community Development Trusts (HCDTs) to increase social spending by oil and gas companies (OGCs) in host communities. While SDN’s view is that this section of the act should have focused on a more holistic, government-led strategy for development in host communities and protecting them from the harmful impacts of hydrocarbon exploration and production, it does at least offer the hope for vastly increased social spending by OGCs, and greater autonomy of that spending for host communities.
The head of the Nigerian National Petroleum Company (NNPC) has stated that under the new legislation, huge sums of money – over US$500 million per year – are due communities. This is a significant opportunity for investments into widespread community development. However, it is also the latest in a long line of initiatives which are meant to direct funding to communities impacted by the oil and gas industry (for example, the creation of the Niger Delta Development Commission (NDDC) and the 13% derivation provided to states). These have seen large amounts of revenue from the oil and gas industry flow to the region, but with limited results, for example, due to misuse of funds and benefit capture by certain groups. It is therefore of paramount importance that these pitfalls are avoided, and it is in the interest of all parties that the funds are calculated, collected, and utilised in a transparent and accountable way, and that they are directed to initiatives which are in the widespread public interest.
To manage the investments locally, Host Community Development Trusts (HCDTs) are being established. To guide implementation, accompanying regulations were issued by gazette in June 2022. Our close reading highlights that the PIA and HCDT regulations lay the foundation for managing these funds, but there are many opportunities to build on this to ensure best practice is followed in finance and governance mechanisms.
This report outlines some of the key concerns under these two areas – finance and governance – and provides specific recommendations for the legislature and regulator to consider, in their efforts to improve implementation of the HCDTs, and wider PIA. We have structured our discussion around some key questions we believe need to be answered, providing answers where we can, and highlighted when more information and work is needed where we cannot. It is based on a close reading of the PIA, HCDT regulations, and from analysing the audited accounts of an OGC.
This is a major, complex new policy initiative, with many potential risks and benefits for communities. From our discussions with OGCs, the FGN, communities and wider civil society, it is clear that work is being done to try to navigate this complexity. However, the speed at which this is happening, and the focus on the business side of the reforms, may gloss over several critical issues related to host communities, which this report seeks to highlight.
Research and analysis findings Finances
When it comes to the Niger Delta and host communities, the first challenge is not lack of funds1, but the failure to use funds which have flowed to the region to the benefit of all citizens. For example, in 2020 alone, Federal and State Ministries, Departments and Agencies were allocated NGN1.4 trillion (US$3.7 billion) (see Annex 1). Our later section on governance focuses on some of these issues. However, firstly there is a need to understand the scale of funds involved with HCDTs, and to understand the risks if information on this is not transparent, in a context where mistrust between communities, companies and government is prevalent, and where the allocation of significant amount of funds is overlaid with locations where there are existing risks of intra- and inter-communal conflict.
How much funding are we expecting?
The PIA states that OGCs shall pay an annual contribution, “in an amount equal to 3% of its actual annual operating expenditure of the preceding financial year in the upstream petroleum operations affecting the host communities for which the fund was established”.2 The Federal Government of Nigeria (FGN) claims the total will be huge, with the Nigerian National Petroleum Company (NNPC) Group Managing Director, Mele Kyari, quoted as saying:
“The operating expense in the industry is up to $16 billion in a year. That means that 3% of that operating expenses is clearly somewhere around $500 to $600 million, it can even be as high as $800 million. So, when you look at this, that value is almost bigger than the size of the budget of the NDDC (Niger Delta Development Commission). So, it is a really huge investment.”3
The NDDC budget was on average US$806 million (NGN206 billion) per year between 2012-2020 (see Annex 2). However, the total amount contributed to HCDTs is expected to be far lower than the NDDC levy, which is equal to 3% of the operating budget of the preceding financial year, and supplemented with a contribution from the FGN.4 This is because the operating budget includes operating expenses (OPEX), as well as capital expenditure (CAPEX), plus other costs. On this point, the FGN ought to exercise caution in its communications, to avoid false expectations. The best way would be to publish total OPEX figures.
The definition of OPEX is itself open to interpretation. The HCDT regulations provide a fairly detailed definition of operating expenditure, which should take into account, “non-capital production costs, cost of sales, administrative expenses and any other expense incurred for the operations of the business on a day-to-day basis as included in the audited financial report, provided that such expenditures shall not include capital expenditures, impairment, depreciation or amortisation.”5 However, it is understood that the industry definition of OPEX is different to the FGN definition – as the latter typically does not include maintenance.6 This definition therefore leaves a lot of room for interpretation, and without a specific definition, companies may calculate their contributions differently. Therefore, we recommend that the regulator provides a specific definition, with the line costs to be included in financial accounting.
One thing is clear, the HCDT allocations will far surpass the existing non-mandatory social spending (CSR) of OGCs. The total of non- mandatory social spending reported for all OGCs between 2012-2020 was US$655 million, which is an average total of US$72 million per year.7 The expected contributions to HCDTs are therefore expected to be many times higher than what is currently spent (see Annex 3).
How will communities be able to tell if they are receiving the funds they are due?
At present, there appears to be a large transparency and accountability gap, what funds should be due to their HCDT and whether they have been received. Communities will not be able to validate what they are owed, because almost all companies do not publish their detailed annual audited accounts or budgets. These details are reported to the upstream industry regulator (Nigerian Upstream Petroleum Regulatory Commission, NUPRC), the manager of FGN interests in the industry (National Petroleum Investment Management Services, NAPIMS), and the Federal Inland Revenue Service (FIRS). But without publishing this information, the amount the companies should be remitting to the HCDT cannot be independently verified.
Moreover, compliance with provisions to fund NDDC has reportedly been poor. The FGN claims that several OGCs fail to submit their allocations, and that the deficit was US$4billion in 2021.8 This is exacerbated by the fact that NDDC has no statutory powers to compel the release of funds, or impose penalties for non-compliance. The NUPRC does have powers it can exercise if payments are not forthcoming – including issuing penalties up to US$250,000, and making recommendations to the Minister of Petroleum Resources to revoke a lease.9 This is positive, although it remains to be seen whether the NUPRC will follow through to compel the timely release of funds due.
How will the funds be calculated and split among Trusts?
Dividing the contributions among HCDTs will be complicated for a number of reasons. Firstly, there is no guidance in the regulations on how to form a HCDT cluster. It is therefore left to the OGCs to decide which communities are hosts to their facilities, group them into HCDTs, and calculate how much they are due.10 The regulator will have to approve the grouping of communities under HCDTs, but this may be done without ample risk assessments. This has the potential to cause conflict in areas where there are existing community-level disputes, for example, over territorial borders, and existing revenues and opportunities from the oil and gas industry. While HCDT structures have a range of positions that should ensure broad-based community representation, there could still be disputes when selecting representatives and projects.
Moreover, the OGC contributions will need to be split among different HCDTs, and there is no guidance in the regulations on how this will happen. The ad hoc approach to grouping communities will make it more difficult to calculate how much each HCDT is due, and for communities to verify this. If, for the sake of argument, HCDTs were based on existing oil mining licence (OML) boundaries, then production is already calculated and published at that level. However, in an ad hoc approach, the OGCs must calculate their production within the territory of each HCDT, assess how ‘impacted’ each area is, and then apportion contributions.11 The regulations specify that the settlor should design a funding matrix for the proposed allocation of funds to host communities “based on equitable and economic principles”.12 But it also outlines that “the commission may issue a template of fund distribution matrix to serve as a guide to settlors.” We recommend that the NUPRC exercises this right, and issues a uniform template, if it has not done so already, so all companies follow the same principles. Otherwise, there will inevitably be disputes with communities.
To further complicate this, all operations in Nigeria are under a Joint Venture (JV) or Production Sharing Contract (PSC). In this arrangement, various companies have a different equity share, contribute different levels of investment, and take different profits. Therefore, it is not clear how HCDTs will manage this issue, since it could become confusing to calculate the contributions due on a company-by-company basis, when the allocation of HCDTs to companies is different to the JVs. In addition, offshore oil blocks are set to make contributions to ‘littoral communities’ “located along the Gulf of Guinea of the Nigeria shoreline up to about 500 metres inland”, who will be “assigned to a settlor by the Commission (NUPRC)”.13 In terms of contributions from offshore operations, they will
be “pooled and distributed amongst beneficiary trusts equitably considering annual operating expenditure of the preceding financial year, asset value size, and any other criteria as may be determined by the Commission.”14 This is another grey area where the regulator should intervene, to create a uniform approach to allocating funds from offshore production, to communities along the coastal areas.
Case study: Calculating contributions
From an outside perspective, calculating the contributions due to HCDTs is currently not possible. We attempted to do this and ran into several challenges, which others will face when attempting to verify what HCDTs are due, and whether OGCs are making the payments required of them. More will need to be done to by the FGN and OGCs to align HCDTs with commitments to transparency and accountability. We sought to analyse the audited accounts of several OGCs, but could only find published reports for one domestic oil and gas company. In this process, we observed the following:
▪ The majority of OGCs do not publish their annual audited accounts so there is no transparency on OPEX.
International oil companies publish their annual audited accounts, but these cover the entire company, and they do not show the figures for their subsidiaries in Nigeria.
▪ Most companies are involved in upstream (production) and downstream (distribution) activities, and the OPEX for each is not separated in reports. Some companies are only involved in upstream activities, but they also have operations that are not directly impacting host communities, such as international offices, and sole cost projects, such as shares in power plants. Their reported OPEX totals cover all these activities, and it is not possible to separate for onshore oil and gas operations.
▪ All companies operate in Nigeria under joint ventures (JVs), where they have a share in the producing asset (e.g. NNPC 55%, SPDC 30%, Total 10%, Agip 5%), and OPEX is not reported on a JV basis. It is therefore not clear how contributions to HCDTs will be calculated under JVs.
▪ When we used the definition of OPEX provided in the HCDT regulations, we found that 3% of a company’s total OPEX was far higher than the amount they reportedly remit to NDDC. This should not be the case, as the NDDC levy is based on 3% of the operating budget, which includes OPEX, CAPEX, and other costs. Therefore, this implies that the OGC either uses a different definition to calculate their OPEX, have not fulfilled their mandatory NDDC payments, or NNPC has not contributed their share.
▪ In the industry, the definition of depreciation, depletion and amortisation (DDA) is subjective, meaning companies will calculate the costs to be deducted from their OPEX in different ways. Furthermore, DDA applies to CAPEX more than it does to OPEX, so it is not clear how much should be deducted from the contribution.
How much can be deducted for damage to infrastructure and what are the implications for host communities?
The Petroleum Industry Act (PIA) states that deductions can be made to HCDT funds to cover “the cost of repairs of the damage” that result from “third-party damage”, when “an act of vandalism, sabotage, or other civil unrest occurs that causes damage to petroleum and designated facilities or disrupts production activities”.15 However, the Host Community Development regulations appear to significantly broaden what is stated in the PIA, to allow deductions for not only for the cost of repairs and replacements, but also:
● the value of products lost as a result of the action (crude oil, gas, or products);
● the operating expenditure incurred during the period that production was shut down.16
On the face of it, it appears the regulations are a significant overreach on what the legislation permits. If implemented, this could lead to huge deductions to HCDTs, but it is challenging to establish exactly how much. During 2022, FGN sources publicly estimated as much as 200,000 to
400,000 barrels of oil a day were being stolen, so the deduction could be US$365-730 million per year (at US$50 per barrel, a price well below the current oil price).
The total deductions rise sharply when other permitted deductions are included, such as pipeline repairs, which according to NNPC statistics, costs on average US$370 million (NGN110 billion) per year.17 Assuming 80% of damage is due to third-party sabotage as OGCs claim (and this equated to 80% of the cost of damage), this equals US$296 million
(NGN88 billion).
Based on the cost of oil lost and pipeline repairs alone, under the new definition in the regulations, HCDTs could theoretically have US$661 million to US$1 billion (NGN303 – 458 billion) deducted every year. This exceeds the amount they are estimated to receive. The total could be even higher, as this does not include the value of other products, and operating expenditure during down time.
Furthermore, this provision will be controversial under the current system of recording and reporting oil spills, which is highly contested by communities and civil society organisations (CSOs), who claim that the regulator and OGCs often underreport the total volume of spills, and regularly misattribute the cause as third-party, instead of operational failure, to avoid paying fines and compensation. Under the PIA, if OGCs can charge communities the associated costs, this is a potential incentive to report more spills as third- party damage, and to increase their estimates of total spill volumes.
Furthermore, single extreme incidents could exhaust funds allocated to HCDTs. As an illustrative example, it has been claimed that third-party damage was the cause of a spill at OML 29 in Nembe in November 2021. No official joint investigation visit report has been made public, but an independent expert estimated that at least
500,000 barrels of oil were lost.18 At $50 per barrel, this would amount to US$25 million alone (NGN10 billion), on top of the other permitted deductions. Taking a more modest estimate of 50,000 barrels, this would still cost US$2.5 million (NGN1 billion) – which is still likely to be more than the total contributions to the local HCDT.
This highlights a broader question SDN has previously asked surrounding third-party damage – why should whole communities be held accountable? The situation is undoubtedly complex: the lack of jobs and access to energy in communities in the Niger Delta are among the drivers for the artisanal oil industry. These drivers have in part been created by the oil and gas industry, for example, through historic oil spill pollution which has destroyed local livelihoods. In turn, this situation has created a level of reluctant acceptance in communities for the existence of the artisanal oil industry, and the further environmental damage this creates on top of the damage already caused by OGCs
On the other hand, for this illicit industry to exist in the way and scale that it does, there is a failure of all actors. For example, a failure of oil companies to protect their infrastructure, of security agencies to perform their role effectively, and of the FGN to provide an effective and holistic policy response to tackle the underlying causes of the problem.
Finally, the reality of the artisanal oil industry is that it is controlled by organised, often heavily armed groups – and as is now publicly acknowledged, even in the National Assembly, with the collusion and active participation of a range of groups and influential individuals.
This has enabled the informal sector to grow in scale over the past two decades, with the FGN and OGCs unable to stop it, despite spending billions of dollars on military operations and hardware. This is a major problem across the Niger Delta and simply passing the costs that oil companies incur onto community members without adequate support is not an effective solution.
SDN campaigned for this provision to be removed entirely, as it abdicates OGCs from their responsibility to protect their own infrastructure, places an unfair onus on communities to ensure the security of oil and gas infrastructure, and punishes entire communities for the actions of a few, which may be completely outside of their control.19 At the very least, based on the fact that this provision in the regulations appears to be out of line with the PIA, we expect this can be challenged and hopefully the regulations can be reviewed to bring them back in line with the PIA.
Governance
With larger amounts of money allocated to communities, it is important that the correct governance structure is in place to coordinate planning, spending, and ensure accountability. New structures are being established for this purpose, but there is a lack of guidance, several grey areas open to interpretation, and several issues arising from the regulations.
Who will be involved in the Trusts and what will they do?
There were some welcome changes made in the final version of the PIA, for example clearly stating that community representation is required in certain parts of the structures, yet we fear they do not go far enough to ensure that communities have a significant and meaningful say on how HCDTs operate. On paper, the settlor (i.e. the OGC) retains a disproportionate level of control over management and direction of the HCDT – although in our discussions with OGCs, a number suggest that once the HCDT is set up, they will have very limited control and involvement beyond providing the funds. Regardless, the top-down structure provides layers of administration and upwards reporting and accountability (e.g. to the OGC and government), but very little provision is made for ensuring accountability to communities and ensuring regular communication, reporting, consultation and participation.
The structure of the HCDTs is outlined below, with their roles unpacked, as specified in the PIA and regulations. This is what the regulations require to be established in every group of communities that ‘host’ the operations of OGCs. The vast bureaucracy could become highly burdensome, and without guidance, risk causing disputes over control of the different structures. This could be improved, for example, by creating guidelines, and rolling these out across the industry. It could be produced in a multi-stakeholder process between OGCs, communities, and the FGN.
Another positive change in the final version of the PIA was to ensure the Board of Trustees (BOT) for every HCDT is composed of members of the host community, and that there must be consultation with communities on their selection20. However, the settlor retains the right to determine the criteria for appointments, without any requirements to consider gender or age, and it has powers to remove members21. This could lead to a situation where a handful of representatives – i.e. those who are already influential in the oil and gas sector, typically middle-aged and elderly men – will decide what projects are implemented, who is awarded contracts, and could scheme to create a cartel to capture these funds. Furthermore, the maximum number of BoT members is nine – so HCDTs that cover more than nine communities will force them to compete for representation.
The Management Committee is responsible for the general administration of the HCDTs, so it is positive that executive members must have experience in relevant professions, and that appointments must “give due consideration to diversity as it relates to age, gender, and physical disability”.22 However, it is not clear how the roles of these executive members – who will not necessarily be members of host communities – differs from the roles of the community representatives, who will serve as non-executive members. In corporate governance, non-executive directors typically provide oversight and insights to challenge executive directors. But that is at the director or board level, and the management committee is at the level below this, so they will not have usual powers to challenge executive members and remove them if performance is sub-standard. The structure therefore risks concentrating power with executive members, who are not from host communities, and appointed by the BoT, while non-executive members from the host communities could be accommodated for the sake of representation, without any formal role in day- to-day management.
The Advisory Committee has been given the responsibility for monitoring project implementation, and reporting to the Management Committee. Yet there is no guidance on what or how to monitor the impact and outcomes. This will likely be a significant undertaking, and it is not clear what proportion of the 5% of HCDT funds allocated to administrative purposes will be allocated to the advisory committee. There is a significant opportunity to develop an enhanced approach, which involves regular community consultation, monitoring and evaluation, and iterative updates of development plans, in line with best practice from the development sector.
Who decides what gets funded?
A needs assessment will be carried out in each HCDT at the outset. One positive change in the regulations is that the settlor has to show evidence it has engaged with each affected community to understand the issues and needs; consulted with and considered the concerns of women, youth and community leaders, and; engaged with each affected host community in developing a strategy to address the needs and effects identified in the applicable needs assessment.23 However, this will only happen at the outset, and be reviewed every five years, which could be improved by creating regular opportunities for community feedback, to make updates based on changes in issues and context.24 NUPRC reportedly has a template for needs assessments, but this does not appear to be enforced. In observed HCDTs, the approach used was not comprehensive – e.g. one settlor sent 50 forms for community members to fill their needs.
Moreover, the requirements for consultation do not extend to the subsequent community development plan, which is the key document guiding the strategy and project selection under the HCDT.25 The settlor is only required to consult with the proposed BoT members, and submit the development plan to the NUPRC for approval, after
30 days of completing the needs assessment.
This does not provide adequate time for thorough consultations to occur with the affected communities, even if this was required of the settlor, which it is not. As a result, OGCs may use existing needs assessments that were conducted for previous CSR projects, which will be outdated and geared towards OGC priorities. Anecdotally, in our informal discussions with OGCs, they have expressed concerns about the short timeframes given for needs assessments, and the complexities they will face in developing robust community development plans.
Because development of the plan rests with the settlor, it is ultimately within their power to define the issues to be addressed; set the objectives and strategy of the fund; determine and specify the community development projects to implement; and set the budget and timeframe for implementation.26 Therefore, community members may be consulted on their needs at the outset, but there is no guarantee that they will have a say in the design of the overall strategy of the development plan, or the projects that are implemented, nor will they be part of validating or approving the final plan, as this is left to the regulator. The process could even be open to elite capture of the benefits, potentially creating further fault lines along which conflict can emerge within and between communities, as we have seen with other initiatives in the Niger Delta.
While there of course needs to be a decision- making structure which prioritises initiatives from community consultations, we are concerned that the current process is not open enough and too much power rests with the settlor, which could be prone to capture by individuals or interest groups. Even if a settlor were to behave in completely responsible way, they will be open to accusations of bias, thus creating further risks of conflict. Without mechanisms to ensure consultation and feedback from community members, the only way they can have a say in the project selection will be by lobbying members of the Board of Trustees, Management Committee, and Advisory Committee. If these channels are not productive, disgruntled community members may turn to protest or sabotaging infrastructure, as has become common during lingering disputes with OGCs across the region.
