PIA KEY PROVISIONS AND SUMMARY.pdf

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Key Provisions of the Petroleum Industry Act, 2021- Summary and Commentaries
September 2021
Key Provisions of
the Petroleum Industry
Act, 2021
Summary and Commentaries

2 | Key Provisions of the Petroleum Industry Act, 2021- Summary and Commentaries
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Highlights
Governance
Two Industry Regulators: The
Commission and the Authority
Establishment of Nigerian
National Petroleum Company
Limited
Establishment of Frontier
Exploration Fund
Establishment of Midstream and
Downstream Gas Infrastructure
Fund
Establishment of
Incorporated Joint Ventures
Administration
Producing
Marginal Field
to convert to
Petroleum
Mining Lease within
18 months from the
effective date
of the PIA
Introduction of
new license
types: Petroleum
Prospecting Licences
(PPL), Petroleum
Exploration Licences
(PEL) and Petroleum
Mining Licences
Introduction of
model licence/lease
during bid rounds
Anti-Competition
provisions for
licencees
Provision for
establishment of
decommissioning
and abandonment
funds for onshore
and offshore
petroleum
facilities
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Host Community
Provision for the
incorporation of Host
Communities’
Development Trusts
3% of settlors’ actual
annual operating
expenditure in
preceding financial
year to fund Trusts
Members of the
Board of Trustees to
come from the host
communities
Fiscal
Repeal of investment
allowance/credit and
introduction of
Production Allowance
Introduction of
Hydrocarbon Tax of 15%
and 30%
Introduction of
minimum Hydrocarbon
Tax Concept : Cost
Price Ratio
New Levy of 0.5% on
wholesale price of
petroleum products and
natural gas sold
in Nigeria
Upstream Companies to
pay Companies Income
Tax at 30%
Field/Production and
price-based Royalties
Exemption of deep
offshore operations
from Hydarbon Tax
Penalties for late
filing of tax returns to
be ₦10,000,000 on the
first day of default and
₦2,000,000 on existing
penalty for each
additional default day
Disposal of Qualifying
Assets (in full or in part)
to be backed by
certificate of disposals
issued by the
Commission or any
person authorized by it
Acquisition cost of
petroleum rights to
be broken into value
of rights and value of
assets
Operator may be
liable to additional
Chargeable Tax based on
the fiscal price
advised by the
Commission
Requirement to submit
revised HyrdoCarbon Tax
returns whenever prices,
costs and volumes change,
and strict penalty for
non-compliance
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D
espite the many years of rejections, suspensions
and approvals, President Muhammadu Buhari
presented the Petroleum Industry Bill (PIB) 2020
(the Bill) to the 9th National Assembly for consideration
and passage in September 2020. Although most
onlookers were not certain about the possibility of it
sailing, owing to the many years of disappointment,
the Bill was eventually passed by both the Senate and
the House of Representatives earlier in July 2021.
And more strikingly, the President signed the Bill into
Law (now Petroleum Industry Act, 2021 or PIA) on 16
August 2021.
The Act is a single omnibus law that provides legal,
governance, administrative, regulatory and fiscal
framework for the Nigerian Petroleum Industry
and development of Host Communities. It repeal
existing petroleum-related laws (but for some savings
provisions), with the bid to comprehensively reform
the Nigerian Petroleum Industry. The Act contains
five different chapters namely: Governance and
Institutions; Administration; Host Communities
Development; Petroleum Industry Fiscal Framework;
and Miscellaneous Provisions with seven schedules.
In this publication, we have highlighted key provisions
contained in these chapters, with commentaries to
guide industry participants.
Governance and Institutions
This chapter introduces changes to the governance
and institutional framework of the Nigerian oil and gas
industry, with the key objectives of creating effective
governing institutions, promoting transparency and
accountability in the administration of petroleum
resources; and to establish the framework for the
creation of a commercially oriented national petroleum
company.
Some of the key changes introduced under the
governance and institutions include the following:
1. Establishment of Nigerian Upstream
Regulatory Commission (NURC or the
Commission):
The PIA provides for the establishment of
the Commission to oversee the regulation of
upstream petroleum operations in the country. A
Chief Executive, who will be supported by six (6)
Executive Commissioners, will handle the day-to-
day administration of the Commission.
The Commission will take over the current
functions of the Department for Petroleum
Resources (DPR), with respect to the regulation
of technical, operational, commercial and
environmental activities associated with upstream
petroleum operations.
2. Establishment of Frontier Exploration Fund
(FEF):
In furtherance of the role of the Commission
in the exploration and development of frontier
basins in the country, the PIA provides for the
set-up of a FEF. The Fund will be managed by
the Commission and it is to be used for promoting
the exploration of frontier basins, while also
developing exploration strategies and portfolio
management for unassigned frontier basins in the
country.
Thirty percent (30%) of Nigerian National
Petroleum Company Limited’s profit from
production sharing, profit sharing and risk service
contracts will be set aside for funding the FEF.

3. Establishment of Nigerian Midstream and
Downstream Petroleum Regulatory Authority
(NMDPRA or the Authority):
The PIA provides for the establishment of
the Authority to oversee the regulation of the
midstream and downstream petroleum operations
in the country. A Chief Executive, who will be
supported by seven (7) Executive Directors,
will handle the day-to-day administration of
the Authority. The Authority will take over the
current functions of the DPR, with respect to the
regulation of technical and commercial activities
in the downstream and midstream petroleum
operations. Furthermore, the Authority will be
saddled with the responsibilities of providing
pricing and tariff frameworks for natural gas in
midstream and downstream gas operation, and
petroleum products based on fair market basis,
thus, absorbing the current responsibilities and
functions of the Petroleum Products Pricing
Regulatory Agency (PPPRA).
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4. Establishment of Midstream and Downstream
Gas Infrastructure Fund (MDGIF):
The PIA provides for the establishment of the
MDGIF that will be managed by a Governing
Council, with the objective of financing
government’s participating or shareholders’
interests in infrastructure related to midstream
operations to unlock private investments and to
enhance domestic consumption of natural gas
in Nigeria. The MDGIF will be mainly funded
by the imposition of a 0.5% levy on wholesale
price of petroleum products and natural gas sold
in Nigeria. The MDGIF levy shall become due
within 21 days of the sale of petroleum products
and natural gas in Nigeria, while necessary
administrative procedures and penalties for non-
compliance will be specified in a regulation to be
made by the Authority.
5. Establishment of Nigerian National Petroleum
Company Limited (NNPC Limited):
The PIA provides for the establishment and
incorporation of a new National Oil Company to
be known as NNPC Limited within six months
of the commencement of the Act. NNPC
Limited will be fully owned by the Government
of Nigeria and all shares in the company will
be held in equal proportions by the Ministry of
Finance Incorporated and Ministry of Petroleum
Incorporated.
Upon incorporation of NNPC Limited, the Ministers
of Petroleum Resources and Finance within an
18-month timeline, will determine the assets
and interests of the current Nigerian National
Petroleum Corporation (NNPC or Corporation) to
be transferred to NNPC Limited or its subsidiaries,
while also appointing NNPC Limited to act as the
agent of NNPC for the purpose of managing the
process of winding down the assets, interests and
liabilities of the Corporation.
The PIA further requires NNPC Limited and
its subsidiaries to conduct their affairs in
a commercial nature without recourse to
government funds; and the expectation is for the
Company to be operated as a full-fledge limited
liability company with the goal of delivering value,
profits and dividends on an ongoing basis to its
shareholders.
Key roles of NNPC Limited include:
• Carrying out petroleum operations on
commercial basis comparable to private
companies in Nigeria engaged in similar
activities
• Assuming the role of concessionaire of all
production sharing contracts (PSCs), profit
sharing and risk sharing contracts on behalf
of the Federation
• Lifting and selling royalty oil and tax oil
on behalf of the Commission and FIRS
at commercial rates and payment of the
corresponding revenue to the relevant
government accounts
• Carrying out test marketing to ascertain
the value of crude oil and report to the
Commission
• Holding the rights to natural gas under PSCs
entered prior and after the effective date of
the Act
• Acting as agent of the Commission for the
management of PSCs for a fee, in a contract
between the Commission and the NNPC
Limited
• Assuming the working interest of NNPC in
joint operating agreements (JOAs) executed
before the effective date of the PIA
• Engaging in the business of renewables and
other energy investments
• Promoting the domestic use of natural gas
through development and operation of large-
scale gas utilization industries.
• Acting as the supplier of last resort for
national security reasons.
6. Establishment of Incorporated Joint Ventures
(IJVs):
The PIA provides for NNPC Limited and other
parties in JOAs to voluntarily convert to IJVs, in
line with the principles specified in the second
The PIA provides for
the establishment
of the Authority to
oversee the regulation
of the midstream and
downstream petroleum
operations in the country.
A Chief Executive, who
will be supported by seven
(7) Executive Directors,
will handle the day-to-
day administration of the
Authority.

schedule to the PIA. The second schedule to
the PIA prescribes general provisions to be
adopted when converting JOAs to IJVs, while also
providing necessary guidance on matters such as
equity composition, board of director composition,
royalties and taxes payable, right of shareholders
to purchase crude oil and derivatives, dividend
policy and financing operations.
The PIA requires the IJV to be an independent
entity, with strong commercial orientation and clear
rules of transparency and accountability enshrined
in the operations of the entity.
Administration
This chapter is focused on the Administrative Model
for all oil and gas-related activities in Nigeria. It is
important to note that the two agencies responsible
for the administration of activities are the Commission
and the Authority. While the Commission is primarily
responsible for the regulation and administration of
upstream-related activities, the Authority is set-up
to exercise oversight on other oil and gas activities,
except for the exploration and exploitation of petroleum
resources.
Other key changes introduced by this chapter are as
follows:
1. Upstream Licence Types:
Unlike the previous nomenclature for upstream
licences under the Petroleum Act, the new
licences are tagged; petroleum exploration
licence (PEL), petroleum prospecting licence
(PPL) and petroleum mining lease (PML) and
will be issued by the commission upon fulfilment
of certain conditions. The Act provides that a
licence or lease may be granted only to a company
incorporated and validly existing in Nigeria under
the Companies and Allied Matters Act. In addition,
a holder of a PPL or PML is not permitted to
assign, novate or transfer his licence, lease, right,
power or interest without prior written consent of
the Minister which shall be granted in line with the
Commission’s recommendation. It is important to
note that a change of ownership or a change in
control of ownership in the holder of a Licence or
lease shall be deemed to be an assignment.
A holder of any of the licence types is expected
to pay to the Government royalties, fees, rents
and production or profit shares in the amount
and time as prescribed by the Act and in line with
the regulations made by the Commission. The
Commission is empowered to issue regulations
with regards to fines for gas flaring in line with
the PIA and such fines will not be eligible for cost
recovery or tax deductibility. A licensee or lessee
is also liable to penalty prescribed pursuant to the
Flare Gas (Prevention of Waste and Pollution)
Regulations.
2. National Grid System:
Based on the provisions of the PIA, the
Commission is empowered to adopt a national
grid system for acreage management after due
consultation with the Surveyor-General of the
Federation. The grid system will be based on the
Universal Transverse Mercator (UTM) system or
any other projection system in use by the office
of the Surveyor-General of the Federation, and
any current boundary of a licence, which does
not conform to the new national grid system shall
remain unaltered and be apportioned in parcels.
3. Other Licence Types:
The PIA provides for the issuance of various
licences by the Authority with respect to the
regulations for midstream and downstream
gas operations such as gas processing,
storage, transportation, supply, distribution, and
aggregation, crude oil refining, bulk petroleum
liquids storage, petroleum liquids transportation,
supply as well as construction, and operation
of facilities for retail supply and distribution of
petroleum products and petrochemicals.
The Authority may also require the holder of a
licence to maintain separation in management,
accounting or legal entities of its licenced or
permitted activities, which may prohibit the holder
of the licence from directly holding licences of
another type.
4. Anti-Competition Provisions:
The Authority is empowered with the responsibility
to prevent anti-competitive behaviour with
respect to midstream and downstream petroleum
operations and may monitor and determine
whether any conduct by a licensee or any other
person operating or intending to operate in
midstream and downstream petroleum operations
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is tantamount to lessening competition or market
domination.
5. Decommissioning and Abandonment:
The Act provides for the decommissioning and
abandonment of onshore and offshore petroleum
facilities in line with the guidelines to be issued
by the Commission or Authority. It also provides
that lessees should set up and maintain a
decommissioning and abandonment fund to be
held by a financial institution that is not an affiliate
of the lessee or licensee. Based on the Act, the
decommissioning and abandonment fund shall
only be used to pay for decommissioning and
abandonment costs.
Contributions to the Fund will be eligible for cost
recovery and shall be tax deductible to the extent
that costs disbursed therefrom will not be eligible
for cost recovery or deductible for tax purposes.
The excess of the fund after decommissioning
and abandonment will be considered income for
production sharing or tax purposes.
6. Issuance of Administrative Regulations:
It is instructive to note that the PIA provides
for a consultation with stakeholders by the
Commission and the Authority before
finalizing any regulations or amendments to
regulations. The stakeholders will include
lessees, licensees and permit holders that
may be impacted by the regulations, and
such other persons that may be interested
in the subject matter of the proposed
regulation.
Host Communities Development

1. Incorporation of Host Communities’
Development Trusts:
Exploration & Production (E&P) companies
(referred to as “settlors” in the Act) will be required
to set up Host Communities Development
Trusts (the Trust or HCDT) for the benefit of the
host communities where they operate. For this
purpose, the settlor shall appoint and authorize
a board of trustee after consultation with the host
communities to be registered as a corporate body
under the Companies and Allied Matters Act.
For joint ventures or production sharing contracts,
the operator of each arrangement will be
responsible for setting up the Trust on behalf of its
partners. The Trust will be governed by a “Board
of Trustees” which will be appointed by the E&P
companies.
The littoral communities and any other community
determined by the settlors shall be host
communities for settlors operating in shallow water
and deep offshore.
2. Sources of Funding for the Trust:
Settlors will be required to contribute to the
Trust, an amount equal to 3% of their actual
annual operating expenditure in the immediately
preceding financial year, with respect to
their petroleum operations affecting the host
communities. For this purpose, HCDT Funds
(HCDTF) which shall be managed by fund
managers, will be established.
Also, donations, gifts, grants can be made to the
trust for the attainment of its objectives. In addition,
the profits and interest accruing to the reserve fund
of the Trust shall be contributed to the HCDTF.
3. Objectives of the HCDT:
The primary objective of introducing the Trust
structure is to fund the implementation of the
host community development plan. The plan will
be developed by the settlor based on the “Host
Community Needs Assessment” conducted to
determine the specific needs of each affected
host community and to ascertain the effect that
the petroleum operations might have on the host
community.
Other associated objectives include:
• financing and execution of projects for the
benefit and sustainable development of the
host communities
• facilitation of economic empowerment
opportunities in the host communities
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A holder of any of
the licence types
is expected to pay
to the Government
royalties, fees, rents
and production or
profit shares in the
amount and time as
prescribed by the Act
and in line with the
regulations made by the
Commission.

• support of healthcare development and
security for the host communities.
Interestingly, there is an introduction of a provision
that will help discourage vandalism and sabotage
by the host communities. As such, the basis for
computation of the trust fund in any year shall
always exclude the cost of repairs of damaged
facilities attributable to any act of vandalism,
sabotage or other civil unrest.
4. Timeframe:
The timeframe for setting up the Host Communities
Development Trust varies, depending on the
operational status of the oil prospecting licence
or oil mining lease involved. For instance, the
Trust must be set up prior to the application for
field development plan for existing oil prospecting
licences.
5. Penalty for Non-compliance:
Failure to set up the Trust after having been
informed of such failure in writing, may be grounds
for revocation of the applicable licence or lease.
6. Composition of the Board of Trustees:
The settlor, in consultation with the host
communities is to determine the membership of
the board of trustees to include persons of high
integrity and professional standing. The members
of the board of Trustees shall come from the
host communities and shall elect a Chairman for
themselves. However, the Settlor shall appoint a
Secretary for the Board of Trustees to keep the
books of the Board.
The members of the Board of Trustees shall serve
a term of four years and may be re-appointed for
another four-year term.
The administrative procedures, financial
regulations, remuneration, qualification,
disqualification, and all other matters relating to the
operation and activities of the Board of Trustees,
shall be determined by the Settlor.
7. Duties of the Board of Trustees:
The Board of trustees is charged with the
responsibility of the general management of the
Trust including, determination of the criteria,
process and proportion of the HCDTF to be
allotted to specific development programs,
approval and provision of general oversight of the
projects for which the HCDTF shall be utilized,
approval of the appointment of fund managers for
purposes of managing the reserve fund, setting
up and appointing members of the management
committee of the Trust, determination of the
allocation of funds to the host communities based
on the matrix provided by the settlor.
8. Allocation of Funds:
• 75% of the funds will be allocated to a capital
fund to be disbursed for projects in each of
the host community. Any sums not utilised in
a given financial year shall be rolled over and
utilized in subsequent years.
• 20% will be allocated to the reserve fund,
which will be invested for the utilisation of the
HCDT whenever there is a cessation in the
contribution payable by the settlor.
• A maximum of 5% of the funds will be utilised
solely for administrative cost of running the
trust and special projects, which shall be
entrusted by the Board of Trustees to the
settlor. Any portion of the funds not utilised in a
given year will be returned to the capital fund.
9. Exemption of funds from Income Tax
The funds of the HCDT created pursuant to
the Act shall be exempted from taxation. Our
expectation is that the exemption will extend to the
interest and profits accruable from the investment
of the reserve fund. The Act also provides
that contributions made to the HCDTF by E&P
companies will be deductible, for the purposes of
hydrocarbon tax and companies income tax as
applicable.
The contribution of 3% of the annual operating
expenditure of E&P companies to the HCDTF will
obviously increase the cost of doing business for
the affected companies. More so, E&P companies
are already required to contribute 3% of their total
budgeted annual operating and capital expenditure
to the Niger-Delta Development Commission Fund
(NDDF). Given that the NDDF and HCDTF have
similar objectives which is the development of
the host communities, we expect that the proper
implementation of the PIA with respect to the Trust
and a renewed operation of the NDDC for the
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will result into massive socio-economic and
infrastructural growth for the relevant communities.
Meanwhile, it is important to monitor the taxes
and levies as they are applicable to private
sector players in the Nigerian Petroleum Industry
for their effectiveness and to ensure global
competitiveness. This is because multiplicity of
taxes and levies in any sector could result in a
major disincentive to local and foreign investments
in the sector.
Petroleum Industry Fiscal
Framework
This chapter provides the changes introduced by the
PIA to the fiscal regime of companies operating in the
Nigerian oil and gas industry. Key changes include:
1. Applicability of new taxation regime:
The new taxation regime will apply to companies
upon renewal of existing Oil Mining Leases (OMLs)
and Oil Prospecting Leases (OPLs) or execution
of new ones, after the commencement of the
Act. That is, the Petroleum Profits Tax (PPT) Act
will continue to apply to OMLs or OPLs obtained
prior to the coming into effect of this Act, until such
OMLs or OPLs are renewed.
However, a company may elect to be taxable
under the Act, by entering a conversion contract
prior to the termination or expiration of the
respective OPL and OML. Also, existing marginal
fields must convert to the PIA within 18 months of
the effective date of the Act.
2. Administration:
The Federal Inland Revenue Service (FIRS)
and the Commission will be responsible for the
collection of Government revenue in the Nigerian
petroleum industry. The FIRS remains the body
responsible for the assessment, enforcement
and collection of taxes {i.e. hydrocarbon tax (HT),
companies’ income tax (CIT) and tertiary education
tax (TET)} in the petroleum industry. However,
the determination, enforcement and collection of
rents, royalties, and related payments will be the
responsibility of the Commission.
The Act also gives the FIRS the powers to make
rules and specify the form of returns, claims,
statements and notices under the Act. This
provision appears ambiguous and to prevent a
dispute, it may be preferable to specify the extent
of the rules, which can be made by the FIRS, and
how much they can modify the form of a claim.
3. Activities taxable under the new tax regime:
A person intending to be involved in more than one
stream shall register and use a separate company
for each stream of petroleum operations under this
Act, subject to certain exemptions. Companies
with upstream petroleum operations are now
subjected to dual tax regimes, that is, the HT and
CIT.
a). Hydrocarbon Tax
The HT replaces the PPT as the tax to be
levied on the profits of any company engaged
in upstream petroleum operations in the
onshore and shallow water acreages, with the
exemption of frontier acreages. Deep offshore
fields will not be liable to HT.
The PIA provides that HT shall apply to crude
oil as well as field condensates and liquid
natural gas liquids derived from associated
gas and produced in the field upstream of the
measurement points.
Conversely, HT shall not apply to associated
natural gas, including gaseous natural
gas liquids (NGLs) produced in the field
and contained in the rich gas, and non-
associated natural gas. HT will also not apply
to condensates and NGLs produced from
associated and non-associated gas in fields or
gas processing plants, regardless of whether
the condensates or NGLs are subsequently
comingled with crude oil. However, the
applicability of HT will depend on whether the
volumes of the condensate or NGLs can be
determined at the measurement point or exit
of the gas processing plant.
In determining the total income liable to HT,
other income streams (e.g. interest income)
which to some extent are currently treated by
some operators as incidental to petroleum
operations will not be liable to HT. This is
because the PIA specifies the income streams
that HT will be applicable to, as noted above.
b). Companies Income Tax
The PIA provides that all companies,
concessionaires, licensees, lessees,
contractors or subcontractors involved
in upstream, midstream or downstream
petroleum operations under the PIA will be
subjected to income tax under the Companies
Income Tax Act (CITA).
Consequently, companies liable to HT will
also be subjected to CIT on their income from
petroleum operations at the applicable rate.
In determining the CIT payable in any given
accounting period, any HT payable under the
Act will not be deductible.
4. Ascertainment of tax payable:
a). Hydrocarbon Tax
The PIA amends several sections of the
PPT Act that affects the computation of the
tax payable by companies with upstream
petroleum operations, such as the sections on
deductible expenses, deductions not allowed,
D

and capital allowance schedule. The PIA
attempts to restrict expenses deductible for
HT purposes to only expenses directly related
to production activities.
i Deductibility of expenses
The Act seeks to amend the sections on
deductions allowed and deductions not
allowed as follows.
• Expenses incurred will now be
subjected to the reasonability test for
the purpose of HT deduction. This
may result in tax disputes, given that
the term “reasonable” was not defined
in the Act.
• The basis for the deductibility of
royalties incurred will change from
accrual to cash basis. That is,
amount of royalty deductible will be
restricted to that paid during that
accounting period.
• Any amount contributed into a fund
in respect of decommissioning costs
will be allowed for HT purposes.
However, any excess contribution,
which is returned to the lessee by
the fund, will be subjected to tax
accordingly.
• Interest expense will not be
deductible for HT purposes. This will
negatively impact upstream entities
that are highly geared.
• Education tax will not be an allowable
deduction for determining the
adjusted profits of a company.
• Any amount of contribution to any
fund, scheme, or arrangement
approved by the Commission
pursuant to the establishment of Host
Community Development Trusts, and
other similar contributions will be tax
deductible.
• Bad debts will not be deductible for
HT purposes.
• Expenditure incurred as a penalty,
natural gas flare fees or imposition
relating to natural gas flare will not be
tax deductible.
• Bank charges, arbitration and
litigation costs will be treated as non-
deductible expenses.
• Head office costs, shared costs or
costs incurred by affiliates and costs
incurred outside Nigeria will not be
allowable for deduction.
• Taxes paid on behalf of another
person, i.e., a vendor or a contractor.
• Custom duties will not be tax
deductible
ii Restriction of deductible cost – Cost
price ratio (CPR)
The Act introduces a restriction to the
allowable deductions claimable in a given
accounting period for the determination
of the HT payable, to 65% of the gross
revenues determined at the measurement
points.
• Certain statutory payments such
as royalties, rents and fees, stamp
duties, levies and contribution
to funds are excluded from the
restriction.
• Any excess cost not deductible in a
given accounting period because of
the above restriction will be carried
forward to subsequent years.
• Notwithstanding any costs carried
forward to subsequent years, the
total costs restriction will apply on the
aggregate of such costs.
• Any costs not fully deducted as
a result of the above restriction
upon termination of the upstream
petroleum operations related to
crude oil will not be deductible for the
purpose of ascertaining the HT.

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Notwithstanding the exclusion of the
above statutory payments, the CPR limit
will be a major disincentive for companies
with significant tax assets to convert to the
fiscal terms under the PIA, as they may
be unable to recover their tax assets and
valid operating expenses due to the limit
of 65%.
iii. Ascertainment of Tax Rate
The chargeable tax for onshore
and shallow water areas shall be a
percentage of the chargeable profit as
provided in the table below:
S/N Category
Applicable
Rate
1 Petroleum mining leases 30%
2 Petroleum prospecting
licences 15%
iv. Additional tax payable in certain
circumstances
Additional tax (relating to both HT
and CIT) shall be payable by an
upstream company, where the amount
of chargeable tax for that period is
less than the amount which would be
obtained by multiplying the number of
barrels of that crude oil determined at the
measurement point1
by the fiscal oil price.
The fiscal price is to be determined by the
Commission.
This provision appears punitive, due to
the possibility of paying taxes on revenue
not earned by companies. It is hoped
that fiscal prices to be determined by the
Commission will not be influenced by the
possibility of generating additional tax
revenue.
v. Production allowance
A production allowance of the lower of
$2.50 per barrel or 20% of the fiscal
oil price will be granted to companies
that convert their OMLs under the
conversion contract and those that
renew existing OMLs. However, the
production allowance for OMLs granted
after the commencement of the Act will
vary depending on the area of the field
(i.e. onshore and shallow waters). It
is however unclear how this allowance
will apply. That is, whether directly on
the value of the crude or after deduction
of other allowable reliefs. However,
the Act provides that the procedure for
determining the production allowance will
be established in a Regulation.
vi. Consolidation of Costs and Taxes
The Act provides that a company engaged
in upstream petroleum operations across
terrains shall be allowed to consolidate
costs for the purpose of CIT.
In addition, a company engaged in
upstream petroleum operations related to
crude oil across terrains shall be allowed
to consolidate costs and taxes for the
purposes of HT only across assets in
which it holds licences and leases in
accordance with the two categories of
chargeable tax i.e. petroleum prospecting
licence and petroleum mining lease.
b). Companies Income Tax
i. Deductible and non-deductible
expenses
The Act modifies the provisions of
Section 24 of the CITA (deductions
allowed), as applicable to the
relevant companies engaged in
•
Rent and royalty liabilities
which were incurred and
paid, in respect of crude oil
sold condensate sold, and
natural gas sold or delivered
or disposed of in any other
commercial manner are
allowable for CIT purposes.
• Any amount contributed
to a fund approved by the
Commission or Authority for the
purpose of abandonment and
decommissioning or petroleum
host communities’ development
trust are allowable deductions.
• Other deductions that may be
prescribed by the Minister of
Finance by Order published in
a Gazette.
The Act also extends the
provisions of Section 27 of the
CITA (deductions not allowed) to
include the following, as applicable
to companies engaged in
•
Expenditure for the purchase
of information relating to
the existence and extent of
petroleum deposits, other than
for the acquisition of geological,
1
”Measurement point” means -
(a) a point determined in the field development plan pursuant to section 79(2) of the Act, where petroleum is being measured and its value is determined for royalty purposes,
(b) where the point has not been determined, a point directly downstream of the flow station in the petroleum mining lease, and
(c) where measurements take place outside the petroleum mining lease, a deemed measurement point in the petroleum mining lease based on a calculation procedure approved by the Commission adjusting from the point(s) where
petroleum is being measured.

geophysical and geochemical
data or information.
• Penalties including natural
gas flare fees or any such
imposition relating to natural
gas flare.
• Production or signature
bonuses paid for the acquisition
of or rights in or over petroleum
deposits.
ii. Gas utilisation incentive
The Act expands the list of
companies eligible for the gas
utilisation incentive provided for
under Section 39 of the CITA to
include companies engaged in
midstream petroleum operations2
and large-scale gas utilisation
industries3
.
Investors in gas pipeline will
be granted an additional tax-
free period of five years at the
expiration of the tax-free period
granted in Section 39 of the
CITA. This incentive is expected
to encourage domestic gas
production and utilisation, in line
with the ongoing global energy
transition.
5. Ascertainment of royalty payable:
The Act provides that condensates shall be treated
as crude oil and natural gas liquids as natural gas
for the purpose of determining royalties.
a). Oil royalties
Production based royalty
The Act provides that royalties based on
production shall be calculated on a field basis
as follows:
Production terrain
Royalty
rate
Onshore 15%
Shallow water (up to 200m) 12.5%
Deep Offshore (greater than 200m) 7.5%
Frontier basins 7.5%
The PIA also specifies a royalty rate of 5% for
deep offshore fields where the production in a
month is not more than 50,000 bopd.
In addition, the Act provides that the royalty
rate for marginal fields, and other fields where
the oil and condensate production is less than
10,000 bopd during a month will be 5% for the
first 5,000 bopd, and 7.5% for the portion of
production over 5,000 bopd. For production
over 10,000 bopd during a month, the share
of the production over 10,000 bopd per month
shall be at the royalty rates in the above table.
Price based royalty
In addition to the production based royalty, the
Act provides that additional royalties shall be
payable depending on oil prices as follows:
Price Royalty rate
Below $50/bbl 0%
At $100/bbl 5%
Above $150/bbl 10%
Between $50 and $100/bbl, and between
$100 and $150/bbl, the royalty by price shall
be determined based on linear interpolation.
These price levels provided under the price
based royalty shall apply to the year 2020. At
the beginning of 2021 and of each succeeding
calendar year, these price levels shall be
increased by 2% relative to the values of the
previous year.
2
means midstream petroleum liquids operations and midstream gas operations.
3
large-scale industries that use natural gas as a feedstock such as gas-to-liquid plants, petrochemical industries and fertilizer plants; and mini-LNG plants, power plants and such other industries
as defined in regulations.

| 13
There shall be no royalty by price for frontier
acreages.
b). Gas royalties
Royalty based on production for natural
gas and NGLs is 5%, while the royalty
rate for natural gas produced and utilized
in-country shall be 2.5%.
6. Filing of HT and CIT returns:
The evidence of payment of the final instalment
based on the estimated returns that would have
been filed is now required for filing the actual
returns for that year. Companies are required to
submit their actual returns within five months after
the accounting period or five months after the
commencement of the Act whichever is later.
A newly incorporated company that is yet
to commence the bulk sales or disposal of
chargeable oil is now required to file its audited
accounts and returns within 18 months from the
date of its incorporation. A CIT return that may be
due by a company involved in upstream petroleum
operations should be filed on an actual year basis,
along with the actual HT returns.
7. Computation of capital allowances
a). Hydrocarbon Tax
i. Capital allowance rate
The capital allowance on other assets
utilised for upstream petroleum operations
shall be at an annual allowance rate of
20% with a retention value of 1% in the
last year until the asset is disposed.
In the case of acquisition costs for
petroleum rights, the value of the rights
and the value of the assets acquired will be
segregated and the value of the rights will
be eligible for annual allowance at the rate
of 20%, while the value of the assets shall
be depreciated based on the applicable
depreciation rates for the respective
assets, with a retention of 1%.
Given that the PIA does not define
“depreciation rates”, companies will
depreciate the assets for tax purposes
based on their internal accounting
policies and this may potentially result
in tax disputes, due to the potential
inconsistencies across various entities.
ii. Claim of capital allowance on capital
work in progress (CWIP)
Paragraph 15 of the Second Schedule of
the PPT Act (i.e. Extension of meaning of
“in use”), which extends the definition of
“in use” and serves as a basis for claiming
capital allowance on CWIP has been
deleted. Consequently, assets classified
as capital work in progress by a company
may not be available for the claim of
capital allowance until they are transferred
to the appropriate asset class.
iii. Other capital allowance provisions
• Any asset or part of it in respect of
which capital allowances has been
granted may only be disposed of on
the authority of a certificate of disposal
issued by the commission or any
person authorised by it.
• In the case of acquisition of a trade or
business, the acquisition cost eligible
for capital allowance will exclude any
capital allowance already claimed by
the seller.
b). Companies income tax
Companies engaged in midstream and
downstream petroleum operations are
required to claim capital allowance in
accordance with the second schedule of
the CITA. The capital allowances for the
acquisition costs of petroleum rights shall be
eligible for annual allowance at the rate of
10%, with a retention value of 1% in the last
year until the asset is disposed and claimable
under the CIT computations.
A company engaged
in upstream petroleum
operations related to crude
oil across terrains shall
be allowed to consolidate
costs and taxes for the
purposes of HT only across
assets in which it holds
licences and leases in
accordance with the two
categories of chargeable
tax i.e. petroleum
prospecting licence and
petroleum mining lease.

8 Trade or business sold or transferred:
In order to enjoy the tax benefits provided for
the transfer or sale of a company’s upstream
petroleum operations, the PPT Act requires one
company to have control over the other or that
both companies are controlled by some other
person or are members of a recognized group of
companies. However, this requirement has now
been extended to require the above relationship
to have existed for three years prior to the
reorganisation. Furthermore, any benefit granted
will be rescinded where the assets transferred
under this scheme is subsequently sold within
three years or the guarantee conditions of any
tax payable is breached. The Act also provides
that the provisions applicable to the transfer of
upstream petroleum operations to related parties
will be applicable for transfers to third parties.
Furthermore, the acquiring company will not
be allowed to claim the amount of any tax loss
incurred by the selling company prior to the
commencement of this Act, whether the companies
are connected or not.
The PIA also requires companies to seek the
approval and direction of the FIRS before
engaging in any merger, take-over, transfer or
restructuring of the trade or business
9 Penalties for defaults and offences:
The PIA significantly increased the penalties
applicable to companies in the event of defaults or
offences committed under Chapter IV of the Act. A
summary of the newly introduced penalties are as
follows:
S/N Default Condition Initial
Penalty
Additional
Penalty4
1
Non-filing of
estimated HT
return
Upon default
10,000,000 2,000,0005
2 Non-filing of
actual HT return Upon default
3
Non-filing of
CIT returns
by Upstream
companies
Upon default
4
Any default
with no specific
penalty
Upon default 10,000,000 2,000,0006
5
Any offence
with no specific
penalty
Upon
conviction 20,000,0005
2,000,0005
6
Making
incorrect
accounts
Upon
conviction
15,000,000
or 1% of
undercharged
tax7
N/A
7
False
statements and
returns
Upon
conviction
15,000,000
or 1% of
undercharged
tax68
N/A
a) Non-payment of tax liability
Non-payment of any HT due based on the
self-assessment made by the company
attracts a penalty of 10% of the tax due.
Furthermore, there is an introduction of
interest charge on the tax due at the rate
of the prevailing London Interbank Offered
Rate (LIBOR) or any successor rate, plus
10%, applicable from the date when the tax
becomes payable until it is paid.
Likewise, any CIT due by such company
will carry interest at the prevailing Nigerian
Interbank Offered Rate (NIBOR) plus 10% and
LIBOR plus 10% from the date when the tax
becomes payable until it is paid, for Naira and
foreign currency remittances respectively.
b) Non-filing of revised estimated
HT return
Where there is a change in price, cost and
volume of crude used in filing the estimated
HT returns during an accounting period, the
company is required to submit a revised
estimated return on a monthly basis. Where
this revised estimated return is not made, the
FIRS shall impose interest at the prevailing
LIBOR or any other successor rate plus 10%
points for the differential of the revised tax
over the estimated tax paid by the company.
Furthermore, the FIRS will have the right to
impose any additional tax on the company on
a best of judgment basis.
10 Fiscal Stabilization:
Fiscal stabilization clauses contained in any
Production Sharing Contract or other contract
entered into after the commencement of the Act
shall not be applicable to certain fiscal provisions,
regardless of whether these changes affect
the contractor favourably or unfavourably, if
changes are being made in a manner that is not
discriminatory to the petroleum industry or the
contractor, with respect to –
(a) generally applicable taxes, such as
withholding taxes, companies income tax,
tertiary education tax and VAT;
(b) levies, taxes or payments to comply with
modern principles in respect of environment,
labour laws, health and safety; and
(c) new taxes, levies or duties to implement
Nigeria’s commitments with respect to climate
change under the United Nations Framework
Convention on Climate Change and other
related international agreements.
4
Every day the default continues.
5
Or any sum as may by order be prescribed by the MOF to be published in a gazette .
6
Or any sum as may by order be prescribed by the MOF
7
The Act does not state whether the higher of both applicable penalty will apply.
8
Or 6 months imprisonment or to both the fine and imprisonment.

| 15
Miscellaneous Provisions
This chapter provides generally for legal proceedings,
pre-action notice, savings provisions, interpretation,
transfer of assets, projects amongst others. Some
highlights of this chapter are provided below:
1. Legal Proceedings & Pre-Action Notice:
The Act provides that the provisions of the Public
Officers Protection Act (POPA) will apply in relation
to any suit instituted against the Commission or
the Authority or any of its executives, directors,
officers or employees. In addition, all actions or
claims to be brought against the foregoing persons
under the PIA must be brought within three months
of the accrual of the cause of action. In this regard,
no suit may also be commenced without notifying
the commission or the authority at least one month
before the commencement of the said suit.
2. Repeals and Consequential Amendments:
The Act provides that the provisions of the PIA are
subject to the Constitution but will however prevail
where found to be inconsistent with the provisions
of other laws. Specifically, the Act clearly provides
for the repeal of the following laws-
• Associated Gas Re-Injection Act
• Hydrocarbon Oil Refineries Act
• Motor Spirits (Returns) Act
• Nigerian National Petroleum Corporation
(Projects) Act
• Nigerian National Petroleum (NNPC) Act
• Petroleum Products Pricing Regulatory
Agency (Establishment) Act
• Petroleum Profit Tax Act (upon the completion
of the conversion process under Section 92 of
the PIA)
• Deep Offshore Inland Basin Production
Sharing Contract Act (upon the completion of
the conversion process under Section 92 of
the PIA)
With respect to the Petroleum Equalization Fund,
the Act provides that the collection of net surplus
revenues and payment of reimbursements from
and to oil marketing companies will cease with the
coming into effect of the Act, except for payments
already earned prior to the effective date. Where
the Petroleum Equalization Fund is unable to make
the aforementioned payments, the authority may
prorate the amounts payable based on the ratio
between the remaining funds and the outstanding
payables. However, in the event that the Fund is in
deficit, oil marketing companies will have no claim
to further outstanding amounts.
Furthermore, any amount remaining in the Fund
sequel to the foregoing transactions will be
transferred to the “Midstream and Downstream
Infrastructure Fund”.
3. Savings Provisions:
The Act provides that any existing Act, subsidiary
legislation or regulation, guideline directive and
Order made pursuant to any law which has been
repealed or amended by the PIA will continue to
subsist to the extent that it does not contravene the
provisions of the PIA until it is revoked or replaced
by an amendment or another subsidiary legislation.
Furthermore, any OPL or OML granted under the
Petroleum Act, 1969 which is subsisting as at the
effective date of the PIA will continue to subsist
only subject to the fulfilment of certain terms and
conditions listed under the PIA. In this regard,
the Act specifically states that the following laws
will remain applicable with respect to the affected
OPLs and OMLs until the termination or expiration
of their tenures.
• Petroleum Act
• Petroleum Profit Tax Act
• Oil Pipelines Act
• Deep Offshore and Inland Basin Production
Sharing Contracts Act
• Any other laws or regulations that are
consistent with the principle in Section 92(6) of
the PIA.
In addition, any other licenses, lease, certificate,
authority or permit which was issued by the
Department of Petroleum Resources, Petroleum
Products Pricing and Regulatory Agency or
Petroleum Equalization Fund, which had effect
before the effective date of the PIA will continue
to have effect for the remainder of its period of
validity.
The Act also provides for certain tariffs, prices,
surcharges and other licenses, which are
applicable prior to the effective date of the Act
to remain applicable until the completion of their
tenure or until alternative provisions are made
pursuant to the provisions of the Act.
E

COVID-19 Notice:
At Andersen Nigeria, our staff and clients are our most valued assets, regardless of any prevailing circumstances. Thus, we are fully committed to
providing services to our clients at the same high standard as before, whilst taking all necessary precautions.
Given the regulatory issues around COVID-19, our teams are working remotely but we have implemented measures to ensure that we are able to communi-
cate with you effectively, whether this be through video/tele-conferencing or other alternative means.
Thus, as we keep hope alive and trust that business gradually stabilizes in no distant time, we encourage you to contact us and lean upon our
professionals for assistance in connection with the ongoing changes in laws and regulations, particularly those introduced in response to the Pandemic.
4. Transfer of Assets, Liabilities, Employees,
Projects etc.:
The Act provides that all rights, obligations, assets
and liabilities which are vested in the Petroleum
Inspectorate and the Department of Petroleum
Resources will be transferred to the Commission,
and employees in these institution will also
become employees of the Commission under no
less favourable terms. Similarly, rights, obligations,
assets and liabilities held by the DPR, Petroleum
Pricing and Product Regulatory Agency and the
Petroleum Equalization Fund (Management Board)
will be transferred to the Authority and employees
in these institution will also become employees of
the Authority under no less favourable terms.
Furthermore, any existing host community
development project or scheme being handled
by any Settlor will be transferred to a host
community development trust, which will be
established pursuant to the provisions of the Act.
The Act further provides that all references to the
provisions of the Petroleum Act, the Petroleum
Profit Tax Act and the Deep Offshore Inland
Basin Production Sharing Contract Act in any
enactment shall be construed as references to the
corresponding provisions of the PIA. The Act also
contains an interpretation provision in Section 318
amongst other provisions.
Conclusion
Now that the PIA has been passed into law, it is
important for stakeholders to take note of its provisions,
seek clarity, and propose changes where necessary,
to ensure that the Act passed achieves the overall
objective of reforming the petroleum sector positively.
It is equally expected that the legislative and executive
arms of government will carry all relevant stakeholders
along in modifying the relevant provisions of the Act
to meet with modern and ever-dynamic business
requirements and encourage competitive investment in
the Nigerian oil and gas industry.

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or “Andersen Tax & Legal.”
Connect with us
ng.andersen.com
Oladipo Maiye
Partner & Head
Oil, Gas and Power
E: oladipo.maiye@ng.andersen.com
Adebowale Adeniyi
Senior Manager
Oil, Gas and Power
E: adebowale.adeniyi@ng.andersen.com
Lanre Afuye
Manager
Oil, Gas and Power
E: lanre.afuye@ng.andersen.com
For further information, Please contact:
Contact Us
Chinwendu Enechi
Associate Director
Oil, Gas and Power
E: chinwendu.enechi@ng.andersen.com
Temitope Kolade
Senior Manager
Oil, Gas and power
E: temitope.kolade@ng.andersen.com
Andersen
Lagos, Nigeria
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Off Royal Palm Drive,
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t: (01) 277 7260
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