Introduction
The
fiscal system is an essential part of the oil and gas industry as it governs
the manner in which revenue is earned or expended on the part of either Host
HGs or IOCs and in some cases even HG national oil companies (NOCs) (i.e.,
state-owned oil companies). The central objective in designing a petroleum
fiscal regime is to acquire for the state in whose legal territory the
resources in question lie, a fair share of the wealth accruing from the
extraction of that resource, whilst encouraging investors to ensure optimal
economic recovery of the hydrocarbon resources.’[13]
Despite these noble intents, what is “fair” can often be the subject of
controversy, and in some instances, legal dispute between investors and HGs.[14]
Regardless of the fiscal regime type—contractual or concessionary—, the key
components of any fiscal system tend to involve fiscal instruments such as
royalties, bonuses, profit oil, and taxes, among others. Royalties are
preferred by HGs as they are often the first line and most assured revenue
stream for many HGs without the complexities of tax calculations or cost
deductions.
The
term royalty traces its antecedents to the English language from the word
“royal” meaning “belonging to royalty” or “related to the King”, under the
applicable rules of British royalty.[15]
Thus, originally, royalty referred to the King’s right to receive an amount
from his subjects, in the form of taxes, for the use of resources available in
the kingdoms or for the exploitation of the natural resources available in its
lands. General definitions of royalties include: (i) payment for the financial
compensation of extracting a scarce resource, such as oil and gas. It guarantees
that the government gets a share of gross revenues regardless of the
profitability of a venture;[16]
(ii) rights to a portion of the production (or value of production) of one or
more wells without the normal costs of drilling and producing;[17]
or (iii) fundamental element in the international petroleum fiscal system
through either concessionary or contractual fiscal systems.[18]
In
current practice, royalties are simply payment of a fee due to a third party
for obtaining the right to use, explore and commercialize a specific asset.
Examples of these assets include intellectual property, brand identity and, of
course, natural resources. Royalties can either be paid to the HG or to the
private sector, based on which entity holds the title to the asset. In the case
of payment of royalties to governments, the fee is usually due for the
production of natural resources that are owned by the government—such as
minerals, coal, oil and gas—according to the specific legislation applicable in
a given country.
Within oil and gas fiscal systems,
royalties have undergone major changes as competition to attract oil and gas
activities has intensified. Since 2000, over one hundred (100) countries
including mature provinces with declining oil and gas production either replaced
their existing oil and gas royalty regime or made major amendments to it.[19]
Pertinently, royalty structures have advanced from “regressive rates” to more
“progressive type rates” considering the cost of production (daily/cumulative),
location (whether onshore, nearshore, shallow-water or deep-water), price, time
or category of product (whether crude oil or natural gas). These changes were
undertaken through either the laws applicable to the country or via concession
agreements or production sharing agreements or related HGI. In some cases, an
amendment to the law resulted in an adjustment to such HGI with a resultant
impact on the decisions of various IOC’s to invest in the exploration and
production.
Nevertheless, the role of royalties
and the current trends regarding such practices in mature provinces has not
been extensively studied in the literature, and this is the primary motive
behind writing the current paper.[20]
A mature province does not have a specific single definition. According to
PetroWiki, a research page created by the Petroleum Engineering Handbook
published by the Society of Petroleum Engineers (SPE), mature provinces could
be defined as follows: “Often, engineers consider fields mature when they have
declined in production by more than 50% of their plateau rate.” Different
companies might apply their own specific definitions though. For example, Total
considers the surface and the subsurface. For the subsurface, they consider a
field mature when the cumulative production has reached 50% of the initial 2P
(proved plus probable) reserves, and for the surface, they consider a field
mature after 10 years of production. They use other criteria, but these are the
main ones. Halliburton defines a mature field as “one where production has
reached its peak and has started to decline.” The criteria for basin maturity
significantly comes down to fields declining in production from their plateau
rate.[21]
There is also a time element where mature oil provinces, according other
definitions, are those established onshore or offshore provinces where such oil
fields are twenty-five (25) years or older from the date of first commercial
production.[22]
Examples include the United Kingdom Continental Shelf (UKCS) and Norwegian
Continental Shelf (NCS).[23]
There is a continuing debate on
whether royalties should be reduced or eliminated. For the purposes of this
paper, we seek to address the impact of the royalty regime on mature fields and
provide recommendations through case studies of countries that depict a
progressive fiscal system through royalty implementation, countries that have
reduced royalty rates to date, and received favourable fiscal outcomes and
countries that wholly abolished royalty rates altogether. The rest of this
paper is structured as follows: firstly, we delve into the origin and context
of royalties, the main challenges faced by mature provinces through the
implementation of royalties, followed by a comprehensive snapshot into
alternatives to adjust the royalty system. This snapshot would provide succinct
evidence of royalty regimes in mature provinces such as Nigeria, Mexico,
Colombia and Brazil, as well as the lack of royalty regimes in mature provinces
such as Norway and the United Kingdom. Recommendations to address challenges
faced in mature provinces through its implementation of royalties are provided
to identify potential contributions to economic growth and development in the
oil and gas sector, especially given energy transition imperatives.
1. Oil
and Gas Royalties
1.1 Origin and Context
Royalty
is a duty imposed on the amount (a quantum royalty) or value (an ad valorem
royalty) of production.[24]
In the oil and gas industry, usually royalties are defined as a compensation to
the State/HG or fiscal authority so that it receives a financial return for the
transfer of hydrocarbons’ exploration and production rights to the investor, as
well as to take part in the earnings related thereof. It should be noted that
this consideration is given by entities with the intent of obtaining profit
from the commercialization of resources that belong to the sovereign country
and its people, as compensation for the exploration of these assets (i.e., oil,
gas, coal, iron, among others). From the perspective of investors (including
IOCs), royalties represent a fixed cost as the amount of royalty payment is
independent of profitability. From government perspective, royalties are
relatively ‘simple’ to administer, difficult to avoid, predictable and provide
revenue as soon as production starts; that is, they are front-loaded.
Even
though each country also has its own rules as to how royalties are calculated,
the royalties’ amount is generally defined, charged, and paid according to the
revenue generated by those who are using, exploring, or commercializing such
asset.[25]
In Brazil for example, royalties are calculated considering the profitable
characteristic of each field and the rate varies from 5% to 15% of the field
production amount per month.[26]
The value of oil production is ascertained by the reference (norm) price established
by the applicable regulation.[27]
Several factors may influence the calculation of royalties, such as geological
risks, field production values or estimated reserves, and the international
value of the petroleum product for the reference time in question.
1.2 General challenges of royalties, and in mature provinces
1.2.1.
General challenges of royalties
Before
delving into challenges in mature provinces, we highlight some general
challenges with royalties presently:
i.
Blind
to costs and profit level
– Fixed royalty rates are payable whether the oil price is high or low. While
this stability appears attractive for the State with less fluctuation towards
the country’s economy, it is potentially detrimental to investment. Lower oil
prices reduce the State’s take from royalties and a decline in government
revenue can deter investment by financiers seeking to understand how IOC would
be able to pay off its debt in a low oil price scenario. An example of a fixed
royalty rate can be seen in the Republic of Croatia. Here, a fixed 10% royalty
rate[28]
was seen as too high of a royalty rate for future projects as a result of an
environment of unstable crude oil and natural gas prices over the past few
years.[29]
However, studies showed that Croatia would be able to benefit from applying
foreign solutions in its own legislative and fiscal framework including using a
sliding scale for royalty calculation.[30] Additionally,
due to Croatia’s use of Production Sharing Agreements (PSA) for all new
concessions, it was recommended that the royalty be rescinded altogether as it
was a remnant of previous fiscal regimes that introduced royalty in the first
place.
ii. Capable
of deterring production and encourages premature abandonment of fields – Royalties can deter
production at the end of the field life by accelerating the point at which the
field is no longer economic to operate. Where there is a rise in production
cost and decrease in the internal rate of return or other project profitability
metrics, it eventually leads to premature field abandonment. This can be
especially hard for smaller or marginal projects needed to keep production
platforms in clusters or hubs from shutting down all together because there is
not enough throughput.[31]
iii. Disincentivises
exploration activities
– Increased difficulty for investors to produce from small, marginal or
technically challenging fields or develop new fields as it does not account for
levels or cost of production.
1.2.2.
Mature fields
Among
the challenges faced today by producers from mature fields, is the legal burden
of paying royalties in the same percentages and systematics as those provided
to fields in their production commencement and peak stages. This structuring of
royalties can have a deleterious effect on mature fields due to its characteristic
of being levied on gross revenue, generating taxes even before the project
makes a profit.[32]
The point is that if the value of the financial return to the investor
differs—higher value to fields with great production and lower value to fields
with lower production—so should the regulatory and/or tax treatment. A
disproportionate tax treatment leads the applicable tax being considered too
high and burdensome, which, consequently, makes the investment expensive in the
eyes of the developers.[33]
IOCs
often at later field life need to make additional investment in projects
including procuring new machinery, technical and engineering professionals to
sustain continuing production. In this scenario, companies generally need to
prioritize investments in the face of several options and scarce resources.
Thus, there may be a need to incentivize these firms to make their investments
viable, contributing to job creation, energy security, maximizing the recovery,
and extending the useful life of the field.[34]
Understanding
that a field with high production must have a tax regime different from the one
applied to a field with lower production and in decline is the first step to
creating regulatory rules aiming at increasing the competitiveness of the
investments in mature provinces. The granting of fiscal incentives is one of
the proven mechanisms to reduce the risks of oil and gas recovery investment,
as a flexible regulatory framework can boost the oil and gas recovery projects
by decreasing the financial burden of investors, thereby generating a win-win
scenario, under the premise that for a State to win, companies must win as
well.[35]
The geological reality of a field
at the end of their useful life may require a regulatory treatment that would
incentivize IOCs to prioritize the investments in mature provinces, since while
the investments on enhancing production of the field are heavier, the
government takes may be lower but is compensated for by jobs created and
sustaining domestic energy security. In addition to the merits of the
discussion on the differentiation of royalties for fields with higher and lower
production, it is important to deepen the discussion on the criteria that the
regulator should use to define a field as a mature field other than the age or
production of the field.[36]
Therefore, the premise for this analysis remains the same, which is that the
greater the investment needed to continue production, the more flexible
regulatory regime should be.
The analysis of the profiling of a
mature field for the purpose of receiving a tax incentive of royalties’
reduction should include an analysis on a case-by-case basis, considering
different, individual and specific factors of the reality of each field. The
parameters to understand a mature field as susceptible to receiving the tax
benefit should consider its location (onshore or offshore), proven reserves,
rate projections, current reserves, reduced production, declining production,
production time, use of secondary or tertiary recovery, economy, peak
production, well-defined field, high water and sediment production, among
others.[37]
Establishing
a field’s production volume as the only parameter for granting a benefit that
could impact several projects with different economic and technical
difficulties may lead to the inefficacy of the implemented policy. Thus, the
characteristics to be considered in the granting of incentives for mature
fields must be thoroughly analysed in order to attest the effective impact of
envisioned regulatory incentives in the oil and gas industry.
The
rationale behind charging a tax or government participation is to assign its
value correspondingly to the economic value in place and to the financial
return of an investor against its commercial balance of cost vs. profit. It is
neither adequate nor economically attractive to fix a royalty amount for a
field with a production deterioration in the same manner as to a field that
does not require huge investments such as high-level technology on extraction
of oil. In the case of a field in declining production, with a greater need for
investment to continue production, the royalties should apply proportionally to
the profitability of such field in the face of the challenges to surpass the
difficulty to keep the asset producing, preserving the economic return in
detriment of the costs. The granting of regulatory incentives to keep mature
fields economically attractive should be a factor that, alone, could prolong
the continuity of production through the conservation of the financial
viability of the field.
Any decrease in royalties for
mature fields would incentivize the continuity of their production and,
consequently, cause the delay of the abandonment of the wells. This could help
the government to allay its concern regarding the management of fields
surrendered to the government at the end of a concession, an issue for
government agencies responsible for dealing with such abandoned fields. In
addition, a tax incentive that helps maintaining an investment with a positive
commercial balance also leverages the continuity of the exploration, and,
consequently, keeps the IOCs’ liable before the government for royalty
payments, even if decreased percentagewise. As such, it is important to review
the applicable royalties to the productivity reality in each field, which would
be harmonious with the foundation for the existence of a fiscal regime, that
should be equivalent to the profit of the product to which it refers.
2. Options
for Adjusting the Royalty System
In
this section, we address the impact of the royalty regime on mature fields and
provide recommendations through case studies of countries that depict a
progressive fiscal system through royalty implementation, countries that have
reduced royalty rates to date and received favourable fiscal outcomes and
countries that wholly abolished royalty rates altogether.
2.1 Progression
Progression
refers to a rising government share of net cash flows of a project as the value
of the resource increases.[38]
It accounts for the following:
i. Equity
– State benefiting where investor also benefits; and
ii. Flexibility
and Stability – An adjustable rate depending on changes in circumstances, e.g.
price.
In
terms of a ‘progressive’ royalty rate, such rate can be enhanced without
completely changing it for example, deferring royalty until payback, the point
at which the investor’s costs had been paid off from production revenue. In
addition to this there is an option for companies to stop making royalty
payments at the point when the IOC starts making payments into an abandonment fund.
Royalty payments can also be paused whilst the company invests in enhanced oil
recovery infrastructure as an incentive to maintain production. Such
progressive methods prove to be less complicated as other tax mechanisms such
as corporation tax or profit tax. Countries that demonstrate progressive
royalty rates include for example, Nigeria and Mexico.
2.1.1
Nigeria Case
Study
In
Nigeria, oil was reportedly first discovered in commercial quantity at
Oloibiri, Bayelsa State, in the Niger Delta, in 1956. Nigeria currently has the
world’s tenth largest crude oil reserves and is the world’s thirteenth-largest
crude oil producer.[39]
In 2020, its total proved oil reserves were 36.9 billion barrels.[40]
In 2020, oil production was at a rate of one 1.8 million barrels per day
whereas in 2021, oil production decreased to 1.6 million barrels per day.
A.
Snapshot summary of laws governing oil and gas royalties payable in Nigeria
Oil
and Gas companies in Nigeria operate under concessions or Production Sharing
Contracts (“PSCs”) with the umbrella guidance of legislation. Snapshots of
legislative provisions to guide the royalty rate in Nigeria can be seen below:
Table
1: Snapshot summary of Oil and Gas Royalties
payable in Nigeria
|
Legislative
Framework
|
Royalty Rate
|
|
Regulations 13 and 15 of the Petroleum Royalty Regulations
2022 made under section 304(2) of the Petroleum Industry Act 2021 (“PIA”)
[The Petroleum Royalty Regulations].
Section 94 of
the PIA.
|
Daily Production
& Location:
Sliding Scale for deep offshore
production:
●
Regulation 13(1)(a) states that for
production less than or equal to 50,000bopd the rate shall be 5%.
●
Regulation 13(1)(b) stipulates that for
production greater than 50,000bopd the rate shall be a weighted average rate
of 5% of 5000bopd plus 7.5% of incremental daily production above 50,000bopd
divided by total production per day.
●
Regulation 13(2) (c) states that for
onshore areas where production is greater than 10,000bopd, the rate shall be
the weighted average rate of 5% of 5,000bopd plus 7.5% of 5,000bopd plus 15%
of incremental daily production above 10,000bopd divided by total production
per day.
Price:
●
Pursuant to the Schedule to the
Petroleum Royalties Regulations, the benchmark price should be adjusted by
applying 2% annually and the results rounded to entire US$ cents.
●
Regulation 15(3)(a) states that for
fiscal oil price less than or equal to the benchmark price pursuant to
paragraph 11(1)(a) of the Seventh Schedule to the Act, the royalty price
shall be 0%.
●
Regulation 15(3)(b) adds that for fiscal
oil price between the benchmark prices pursuant to paragraph 11(1)(a) and (c)
of the Seventh Schedule to the Act shall be based on linear interpolation,
●
Regulation 15(3)(c) states that for
fiscal oil price greater than or equal to the benchmark price pursuant to
paragraph 11(c) of the Seventh Schedule to the Act, the royalty by price rate
shall be 10%.
Marginal field
operations
●
There are Producing Marginal Fields and
Non-Producing Marginal Fields catered for. The PIA allows Operators under the
former field to continue operating under the original royalty rates and farm
out agreements.
●
For Onshore fields and shallow waters
with production less than or equal to 10,000bopd in a month – 5% royalty for
the first 5,000bopd and 7.5% for the next 5,000bopd. Above 10,000bopd is
charged as follows:
(a)
Onshore areas – 15%
(b)
Shallow Water (up to 200m water depth) –
12.5%
(c)
Deep Offshore (greater than 200m water
depth) – 7.5%
(d)
Frontier basins – 7.5%
|
|
Paragraphs 6 to 11 of the Seventh
Schedule to the PIA.
|
Production
●
Paragraph 10(2) of the Seventh Schedule
states that royalty shall be at a rate per centum of the chargeable volume of
the crude oil and condensates produced from the field area in the relevant
month on terrain basins as follows:
(a)
Onshore areas – 15%;
(b)
Shallow waters – 12.5%;
(c)
Deep Offshore (greater than 200m water
depth) – 7.5%;
(d)
Frontier basins – 7.5%.
●
Paragraph 10(6) states that royalty
based on production for natural gas and natural gas liquids shall be at a
rate of 5% of the chargeable volume and royalty rate for natural gas produced
and utilised in-country shall be 2.5% of the chargeable volume.[41]
Price
Pursuant to Paragraph 11(1) of
the Seventh Schedule, there shall be payable, in addition to the royalty set
out in paragraph 10 for onshore, shallow water and deep offshore a royalty by
price with respect to crude oil and condensates at the rates set out below:
(a)
Below USD 50 per barrel, 0%
(b)
At USD 100 per barrel, 5%
(c)
Above USD 150 per barrel = 10%
(d)
Between USD50 and USD100 per barrel or
USD100 and USD150 per barrel, the royalty by price shall be determined based
on linear interpretation.
|
|
Section 5(1) & (4) of the
Deep Offshore and Inland Basin PSC (Amendment) Act, 2019. The key objective
of this Amendment Act was to maximise government take from PSCs in the face
of changed prices of oil and gas.[42]
It introduced a revision to the royalty rates straying from royalties
calculated based on water depth of the field ranging from 0-12% to
eliminating the 0% rate and calculating royalties on a field basis, dependent
on the chargeable volume of the crude and condensates produced per field.[43]
|
Production &
Location: Baseline Royalty of 10% for crude oil and
condensates produced in the deep offshore i.e.,> 200-meter water depth[44]
for the Frontier and Inland Basin.
Price:
Royalty based on the applicable
price of crude oil, condensate and natural gas applies as follows:
(a)
From $0 up to $20 per barrel – 0%
(b)
Above $20 and up to US $60 – 2.5%
(c)
Above $60 and up to US $100 – 4.0%
(d)
Above $100 and up to US $150 – 8.0%
(e)
Above $150 – 10.0%[45]
|
|
Paragraph 2 (1) of the Marginal
Field Operations (Fiscal Regime) Regulations S.I. No. 8, 2006.
|
The Marginal
field operations’ royalty rates are:
(a)
For production below 5,000bpd – 2.5%.
(b)
For production between 5,000 and
10,000bpd – 7.5%.
(c)
For production between 10,000 and
15,000bpd – 12.5%.
(d)
For production between 15,000 and
25,000bpd – 18.5%.[46]
|
|
Petroleum Act Chapter P10
(Chapter 350 LFN 1990) Part VI sections 61(a) and (b).
|
Royalty at a
rate per centum of the chargeable value of the crude oil inter alia:
(a)
In onshore areas – 20%.
(b)
In areas up to 100 metres water depth –
18.5%.
(c)
In areas up to 200 metres water depth –
16.5%.
(d)
In areas from 201 to 500 metres water
depth – 12.5%.
(e)
In areas from 501 to 800 metres water
depth – 8%.
(f)
In areas from 802 to 1000 metres water
depth – 4%.
(g)
In areas beyond 1000 metres water depth
– 0%.
Royalty at a
rate per centum of the price received by a licensee/lessee in the relevant
area and sold (without waste gas):
(a)
Onshore areas – 7%.
(b)
Offshore areas – 5%.
|
Prior to enactment of
the PIA, Nigeria was regulated by several statutes and subsidiary legislation
e.g., the Petroleum Act and the Deep Offshore and Inland Basin PSC Act. Most of
the laws and regulations were deemed outdated and inconsistent with present
economic and industry realities. The PIA serves to provide a more robust
framework to drive growth within the sector.[47] It also
provides a new fiscal regime for all marginal field operators in Nigeria.[48]
Through
such legislative provisions, considerations for equity, flexibility and
stability were implemented to encourage a balance for both the government and
the investor. Royalty rates based on a sliding scale of production demonstrated
that Nigeria accounted for the State to maximize where the investor also
maximizes. Additionally, in terms of royalty based on price, the royalty rate
was adjusted to account for circumstances such as increases or decreases in the
price of crude oil in this way, it showed a flexible regime with a form of
stability for both the State and the investor. In other words, due to the
regulated royalty provisions regarding price tiers, the higher oil prices
accounted for the higher royalty payments to the government. Notably based on
Nigeria’s statistics, royalties paid by one of Nigeria’s oil and gas companies
Seplat Energy, as at September 2022 was $132.2million whereas in 2021 it was
$92.1million.[49]
This was as a result of higher realised oil prices.
B. Interaction between royalties in
Nigeria and other tax mechanisms
Pursuant
to the Petroleum Profits Tax Act Cap 354 LFN 1990 and the Deep Offshore and
Inland Basin Production Sharing Contract (Amendment) Act, 2019, upstream
companies receive graduated royalty rates and lower PSC tax rates to encourage
offshore production.
Under
the PIA alongside the royalty rates include Hydrocarbon Tax (HT) which is a tax
on the profits of IOCs and Company Income Tax which is applicable on profits of
upstream petroleum companies for example, 15% for Petroleum Prospecting
Licensees operating in onshore and shallow waters.[50]
C.
Deductions
The
only deduction allowable against royalties which simply ensures that royalties
are paid on actual produced and saleable volumes is contained in paragraph
11(3) of the Petroleum Royalty Regulations made under section 304(2) of the
Petroleum Industry Act 2021 (the “PIA”). It specifies that:
“any
gas measured at the gas delivery meter and re-injected in reservoirs of the
Petroleum Mining Lease shall result in a royalty credit amount based on the
applicable royalty rates for domestic gas… This royalty credit amount shall be
deducted from the royalty applicable to crude oil or condensates or both. Where
the royalty is paid in cash the deduction shall be in cash and where the
royalty is paid in kind, it shall be a reduction of the royalty volume of a
value equal to the royalty credit.”[51]
2.1.2
Mexico Case
Study
Mexico
is the world’s 10th largest oil producer.[52]
At the end of 2020, its total proved oil reserves were 7.9 billion barrels.[53]
In 2020, oil production was 1.9 million bbls/d and about the same in 2021.[54]
A.
Snapshot of laws governing oil and gas royalties payable in Mexico
Oil
and gas companies in Mexico function utilizing License Contracts/PSCs but are
also guided under legislative provisions. The model contract for exploration
and extraction of hydrocarbons under production sharing modality (the Model
Contract) was a milestone in the implementation of the energy reform. The
royalty therein was established as a payment based on gross income and
highlighted as an increasing rate based on the price of hydrocarbons. Table 2
below provides a snapshot into the regulated royalty rates on oil and gas in
Mexico:
Table 2: Snapshot
of Oil and Gas Royalties payable in Mexico
|
Legislative
Framework
|
Royalty Rate
|
|
Hydrocarbons Revenue Law (HRL).
|
Revenue
based Royalty Rates on the Category of Product
|
|
Oil Royalty
●
The royalty rate is based on the value
of the barrel of oil. If the price is under US$ 49.36 per barrel, the rate is
fixed at 7.5%. If the price per barrel is above US$49.46, the rate will be
increased according to the following formula: [0.122 x contractual oil price)
+ 1.5] %[55]
Gas Royalty
The royalty rate for:
●
Associated Natural Gas Royalty is the
Contractual price divided by 102.85.
●
Non-associated Natural Gas utilizes the
following formulae:
i. If
the price is less than or equal to US$5.15 per million British Thermal Units
(BTUs) the royalty is 0%.
ii. If
the price is between US$5.15 and US$5.65 per million BTUs the following
formula should be used:
Rate=
([contractual natural gas price-
5.15] x
60.5)/contractual natural gas price.
iii. If
the price is more than US$5.65 per million BTUs, the formula for determining
the royalty is the same as associated gas.[56]
●
Condensates Royalty: With respect to
condensates (i.e., natural gas liquids formed primarily by pentanes and
heavier components of hydrocarbons), a progressive rate is established based
on the price of the condensates. Under US $61.71, the royalty rate will be
fixed at 5%. Over US$61.71 the following formula applies for determining the
royalty rate: [0.122 x contractual condensate price) - 2.5] %.[57]
|
The HRL was amended in
2019 based on the premise that upstream petroleum activities were taxed too
heavily and therefore constrained their ability to invest in exploration and
production. Increasing private investment and rising condensate production
helped reverse a downward trend in Mexico’s oil production that began in 2004.
In 2022, private investment growth was seen through private companies who
funded five percent (5%) of total production from almost none in 2017 and there
was also five percent (5%) of total natural gas production from private companies
that showed an increase from one percent (1%) in 2017.[58]
B. Interaction between royalties in
Mexico and other tax mechanisms
For
License Contracts, there is an adjustment mechanism available to capture
extraordinary profits for the State. In such a case, where daily production
reaches a determined cap, the over-royalty (payments made to the State based on
a percentage rate of the value of hydrocarbons) that is paid to the Mexican
State is increased by a formula contained in the License Contract.
For
PSCs, there is also an adjustment mechanism for the same reason as License
Contracts. Apart from royalties, a Corporate Income Tax (CIT) rate is payable
at 30% as Mexican resident companies are taxed on their worldwide earnings
pursuant to the Mexican Income Tax Law.[59]
C.
Deductions
In
Mexico, there is no specific concept of deductions in the context of royalties.
There is however a cap on cost deductions which are associated with
profit-sharing in an effort to try and contain costs. The HRL introduced caps
expressed as a percentage of revenue which range from twelve-point five percent
(12.5%) to eighty percent depending on the location of the activity and the
type of hydrocarbon being extracted.[60]
This cap on cost deductions, just like a royalty, secures up-front revenues to
the government as soon as production starts by ensuring a minimum quantity of
production revenue subject to the profit sharing fee.
2.2 Reduction
“Reduced” Royalty Rates refer to
countries that either lowered their initial royalty rates or regulated royalty
discounts.
Countries
that implement reduced royalty rates include for example, Colombia, Brazil, and
the United States.
2.2.1
Colombia Case
Study
Colombia
is among the top twenty (20) producers globally. Its geology is very similar to
Venezuelan fields since it is located in the Orinoco Belt Basin, which is the
biggest petroleum basin in the world in terms of reserves. Its total proved
reserves amount to 2 billion barrels.[61]
In 2020, its total production was 781 million bbls/d.[62]
A.
Snapshot of laws governing oil and gas royalties payable in Colombia
In
Colombia, oil and gas companies operate under concession agreements with the
umbrella guidance of legislative provisions. Colombia has a progressive and
flexible fiscal system including income tax and royalties. In July 2004, the
first model contract was released, i.e., the modern concession agreement/
exploration and production contract. This modern concession agreement was
essentially a royalty/tax agreement loaded with progressive fiscal mechanisms
that respond to different oil price conditions and quality of oil produced in a
relevant area. This contract was further amended, and its latest model contract
issued in May 2012 as used at the Colombia round 2012.
Table 3: Snapshot
into Oil and Gas Royalties payable in Colombia
|
Legislative
Framework
|
Royalty Rate
|
|
|
Production and
Location
|
|
Hydrocarbon royalties were
established in Law 141 of 1994 (as amended by Law 756 of 2002).
Law 1530 of 2012 highlights the
organization and functioning of the General Royalty System.
|
Monthly average in barrels of
crude oil per day:
●
Up to 5,000 = 8%.
●
5,001 to 125,000 = 8%+ ([production-
5,000] x 0.10).
●
125,001 to 400,000 = 20%.
●
400,001 to 600,000 = 20%+
([production-400,000] x 0.025).
●
More than 600,000 = 25%.[63]
Royalties for natural gas:
●
Onshore and offshore below 1,000 ft.
depth = 80%.
●
Offshore more than 1,000 ft. depth =
60%.[64]
Royalties for natural gas and
heavy oil:
●
Onshore and offshore up to a water depth
of 1000 ft. = Discount of 20% and 25%, respectively.
Royalties for natural gas:
●
Offshore water depths greater than 1000
ft.= Discount of 40%.
|
Colombia’s oil and gas
royalties were $6.4 trillion dollars[65]
as of December 31, 2021. Notwithstanding this, in July 2022, Colombia’s
government agreed to continue royalty deductions in exchange for an increase in
income and export taxes by 5% and 20% respectively for oil and coal sold above
certain threshold prices.[66]
B. Interaction between royalties in
Colombia and other tax mechanisms
In
addition to royalties, natural gas and heavy crude have general tax
considerations and special incentives which include but are not limited to a
CIT Rate from financial year 2022 at 30%, equity tax (in specific cases),
capital allowances and investment incentives for example, donations and
investments in research.[67]
C.
Deductions
It
is pertinent to pinpoint that in 2022, the Colombian Tax Reform was approved by
the Colombian Congress i.e., Law 2277-2023. It marked for the oil and
gas industry, the suppression of deductibility of royalties for income tax
purposes. Particularly, Paragraph 1 of Article 19 of Tax Reform Act
2277-2023, which prohibited the deduction of non-renewable natural
resources royalty payments by oil and gas companies to the Colombian
Government. It specifically stated:
“The
economic consideration as a royalty referred to in Articles 360 and 361 of the
Political Constitution shall not be deductible from income tax nor may it be
treated as a cost or expense of the respective company, regardless of the
denomination of the payment and the accounting or financial treatment that the
taxpayer performs, and regardless of the form of payment thereof, either in
cash or in kind. For income tax purposes, the non-deductible amount
corresponding to royalties paid in kind will be the total cost of production of
the non-renewable natural resources.”[68]
The
Constitutional Court pursuant to Judgment C-480 of 2023[69]
declared that it would be unconstitutional to prohibit such deduction for
income tax purposes, meaning, the deductibility of royalties from income tax
for the tax year in 2023 for example was not permitted to be challenged by the
Colombian Tax and Customs Directorate (DIAN). This ruling provided a step
towards long-term investment.
2.2.2
Brazil Case
Study
The
average yearly production of oil and gas in Brazil in 2024 was 4.322 million
barrels of oil equivalent per day (boe/d), which was nearly unchanged from
2023.
Compared to the previous year's total, which hit a record of 4.344 million
boe/d, there was a 0.5% decrease in 2024.
The production of oil in 2024 was 3.358 million barrels per day (bbl/d),
which was 1.29% less than the record set in 2023 (3.402 million bbl/d).The
average annual production of natural gas in 2024 was 153 million cubic meters
per day (m³/d), which was 2% more than the previous year's production of 150
million m³/d.Pre-salt reservoirs accounted
for the majority of output in 2024, accounting for an average of 78.29% of the
country's total oil and natural gas production in barrels of oil equivalent. Onshore and post-salt production made up, on
average, 5.38% and 16.33% of the nation's total production, respectively.
A.
Snapshot into laws governing oil and gas royalties payable in Brazil
In
Brazil, oil and gas companies operate under concession contracts, transfer of
rights surplus, and PSCs with the umbrella guidance of legislation.[76]
In terms of royalties, such amendments/ implementations were undertaken via
Resolutions. Table 4 provides a snapshot into the regulated royalty rates on
oil and gas in Brazil:
Table
4: Snapshot into Oil and Gas Royalties
payable in Brazil
|
Legislative
Framework
|
Royalty Rate
|
|
Production
|
|
Law No. 9,478 of August 6, 1997.
Law No. 12,351.
Resolution 749/2018 of the
National Agency for Petroleum, Natural Gas and biofuels (“ANP”).
ANP Resolution No. 853/2021
[Article 9].
CNPE Resolution No. 05/2022.
|
●
Royalties paid monthly from commencement
of commercial production of each field, in an amount corresponding to 10% of
production of petroleum or natural gas.[77]
●
15% royalty rate of production value,
from date of start-up of the commercial production of each field.
●
Royalty reduction on incremental production
for mature fields (25 years or more of production or that accumulated
production ≥70% of the expected production volume).
●
Royalty reduction for small and
medium-sized companies for the production of the month following the date of
signature of the amendment to the concession agreement:
-
Fields operated by small-sized companies
(average annual production <1000 boe/d in Brazil and abroad) permitted a
reduced royalty rate to 5%.
-
Fields operated by medium-sized
companies (average annual production <10,000 boe/d in Brazil and abroad)
permitted a reduced royalty rate to 7.5%.
-
Under the PSC, royalties are levied at a
rate of 15%.
●
Authorizes ANP to grant, based on
pre-established criteria, a reduction in royalties to the legal minimum (5%)
for fields and accumulations with marginal economic viability (i.e, marginal
fields and accumulations), and implement strategies to reduce the regulatory
burden with a view to modernizing, reducing bureaucracy, simplifying and
speeding up regulation. Although the parameters for qualifying marginal
fields are provided under ANP Resolution No. 877/2022, as of the date hereof,
ANP has not implemented the royalty reduction for marginal fields.
|
Between 2010 to 2016
royalty collection totalled US$17.99 billion and such expansion of the sector
was stimulated by the rise in international commodity prices and increased
collection of oil and natural gas royalties.[78]
B. Interaction between royalties in
Brazil and other tax mechanisms
CIT
is applicable on Brazilian resident legal residents’ entities’ worldwide
income at a rate of fifteen percent (15%) with a surtax of ten percent (10%)
for profits exceeding US$46,789.10 a year. A social contribution tax is also imposed
on corporate net profits at a rate of 9%. The combined CIT rate being
thirty-four percent (34%).[79]
C.
Deductions
It
is pertinent to highlight that, as of October 2024, royalties on oil and gas
production are fully tax-deductible. Expenditures incurred in the exploration
and production activities are immediately deductible for purposes of
calculating the taxes to be levied by the Brazilian government against
exploration and production companies. For the development phase, specific rules
on accelerated exhaustion apply.[80]
D.
Royalty Reductions
Reductions
were implemented on royalty rates in Brazil to encourage investment, especially
for small and medium sized operators, incremental production in mature fields
and for marginal fields.
For
instance, 15 of 113 fields belonging to small and medium-sized companies did
not produce oil in 2021 due to the uneconomic feasibility of their activities,
greatly impacted by the applicable royalty rates.[81]
Therefore, Resolution 853/2021 came into play and allowed small or medium-sized
operators to request reduced royalty rates for their concession contracts, such
request to be analysed by the ANP and, if approved, formalized by means of an
amendment to the applicable concession contract.
With
respect to marginal fields, the National Council for Energy Policy (CNPE)
published its Resolution No. 05/2022, which provides for measures to stimulate
the development and production of hydrocarbon fields or accumulations of
marginal profitability, specifically dealing with the reduction of royalties
for such fields. Through Resolution No. 05/2022, CNPE authorized ANP to grant,
based on pre-established criteria, a reduction in royalties to the legal
minimum (5%) and implement strategies to reduce the regulatory burden with a view
to modernizing, reducing bureaucracy, simplifying and speeding up regulation.
Royalty
reductions for incremental production in mature fields was provided for under
ANP Resolution No. 749/2018, which provided for reduction of rates up to the
legal minimum (5%). Such royalty reductions may be granted for fields with at
least twenty-five years of production, or whose accumulated production
corresponds to at least 70% of their proven reserves. The royalty reduction
benefit shall be requested by the mature field operators and must be
accompanied by the submission of a revised field development plan, which shall
provide for additional investments in infrastructure to maximize the field’s
production. If approved, the ANP and the concessionaires shall formalize the
reduced royalty rate by means of an amendment to the concession contract.
Taking
into consideration the benefits provided under the Brazilian regulation for
challenging production assets, Brazil is one of the royalty regimes that
wholeheartedly encourages investment and reinvestment in oil and gas no matter
how small a company is classified or how defying the producing conditions of a
field are considered.
E.
Other relevant payments
It
is worthy to note that other relevant payments are owed by exploration and
production companies in Brazil in connection with their activities.
For
instance, Law No. 9,478/1997 provides for special participation payments in
specific situations, characterized as an extraordinary financial compensation
owed by concessionaires for the exploration and production of oil or natural
gas for large production volume fields. Special participation is due when, in a
given trimester, a field’s production surpasses a certain threshold, which
varies in accordance with the type of field (onshore, shallow water or deep
water). The special participation may amount to 10% of the production in excess
of such threshold.
As
an incidental payment arising from the special participation payments, the ANP
includes an item known as the “1% clause” in concession contracts for the
exploration and production of oil and natural gas. The clause requires
concessionaires to invest in research, development and innovation (RD&I) at
an amount equivalent to 1% of the gross revenue generated by highly profitable
fields or fields with a large volume of production (those that pay the special
participation).
Another
relevant payment is applicable to onshore fields and constitutes a landlord
cost percentage due to the owner of the land in which the concession area is located.
This percentage usually varies between 0.5% to 1% of the oil and gas production
considering the reference price.[82]
2.2.3
United States
of America Case Study
The
United States has significant onshore and offshore oil and gas assets. As for
offshore assets, the Bureau of Ocean Energy Management and the Bureau of Safety
and Environmental Enforcement, have jurisdiction over 1.76 billion acres on the
Outer Continental Shelf, where they manage 8,300 active oil and gas leases.[83]
As for onshore, the Bureau of Land Management governs approximately 700 million
acres of onshore subsurface mineral rights.[84] Many of the
leases have been produced for over 50 years and are by all accounts mature.
Notably, for the first time in 100 years, the onshore minimum royalty was increased.[85]
The rate was previously 12.5% and will increase to 16.67% over the next decade.[86]
In the coming decades the royalty relief discussed below may ultimately be
implemented as these fields mature.
· Legislative
System
Recipients
of oil and gas royalties can vary between governmental and private entities
depending on where they are found. This includes sovereigns such as the
federal, indigenous, and state governments which may own onshore or offshore
minerals. However, private entities generally only own onshore minerals.
Accordingly, there can and will be various legal regimes potentially applicable
to royalties owed. For the purposes of this paper we examine federal onshore
and offshore as it is the most comparable to other government’s systems.
Federal
offshore royalty relief is increasingly important considering that shallow
water fields have been produced for over 75 years.[87]
With significant reserves already from many of the fields owned by the
government onshore and offshore, the economic potential of these fields is not
enough to keep major oil and gas companies interested in the leases.
Nonetheless the many of the leases remain economically valuable to the United
States government who seeks to ensure the remaining oil and gas is produced
from a revenue and energy security perspective. As such the Bureau of Land
Management and the Bureau of Safety and Environmental Enforcement, pursuant to
Federal law, have enacted royalty reduction programs to help ensure maximum value
is extracted from federal lands. The below table provides a summary of the
legislations and regulations that allow royalty reduction.
Table
5: Snapshot into Oil and Gas Royalties
Reductions in United States
|
Legislative
Framework
|
Royalty Rate
|
|
Federal Offshore
43 U.S.C. § 1331-1356.
43 U.S.C. 1337(a)(3)(A).
43 U.S.C. 1337(a)(3)(B).
43 U.S.C. 1337(a)(3)(C).
42 U.S.C. 15904-15905.
30 C.F.R. §203.50-56 (End-of-life
lease).
30 CFR § 203.80 (Special Case).
|
Outer
Continental Shelf Lands Act (OCSLA)
●
Governs Federal offshore leasing.
●
BOEM may reduce or eliminate any royalty
or a net profit share specified for an OCS lease to promote increased
production.[88]
●
BSEE may reduce, modify, or eliminate
any royalty to promote development, increase production, or encourage
production of marginal resources on certain leases or categories of leases.[89]
●
BSEE may suspend royalties for
designated volumes of new production from any lease if:
(1)
The lease is in deep water (water at
least 200 meters deep);
(2)
The lease is in designated areas of the
GOM (west of 87 degrees, 30 minutes West longitude);
(3)
The lease was acquired in a lease sale
held before the DWRRA (before November 28, 1995);
(4)
BSEE finds that new production would not
be economic without royalty relief; and
(5)
The lease is on a field that did not
produce before enactment of the DWRRA, or if a proposed project to
significantly expand production under a Development Operations Coordination
Document or a supplementary, that the Bureau of Ocean Energy Management
(BOEM) approved after November 28, 1995.
●
BSEE may suspend royalties for
designated volumes of gas production from deep and ultra-deep wells on a
lease if:
(1)
The lease is in shallow water (water
less than 400 meters deep) and produce from an ultra-deep well (top of the
perforated interval is at least 20,000 feet TVD SS) or the lease is for
waters entirely more than 200 meters and entirely less than 400 meters deep
and you produce from a deep well (top of the perforated interval is at least
15,000 feet TVD SS);
(2)
The lease is in the designated area of
the GOM (wholly west of 87 degrees, 30 minutes west longitude); and
(3)
The lease is not eligible for deep water
royalty relief.
●
To qualify for relief, lessee must
demonstrate that the sum of royalty payments over the 12 qualifying months
exceeds 75 percent of the sum of net revenues (before-royalty revenues minus
allowable costs).
●
Generally, the lease or project must not
qualify for formal programs and satisfy two or more criteria stated in the
rule.
|
|
Federal Onshore
30 U.S.C. § 209.
|
Mineral Leasing Act of 1920 (MLA)
● The
Secretary of the Interior, [through the Bureau of Land Management] for the
purpose of encouraging the greatest ultimate recovery of coal, oil, gas, oil
shale … and in the interest of conservation of natural resources, is
authorized to waive, suspend, or reduce the rental, or minimum royalty, or
reduce the royalty on an entire leasehold, or on any tract or portion thereof
segregated for royalty purposes, whenever in his judgment it is necessary to
do so in order to promote development, or whenever in his judgment the leases
cannot be successfully operated under the terms provided therein.
|
Like the United Kingdom,
United States policy, as it relates to mature fields focuses on the efficient
use of existing infrastructure (especially offshore) and avoiding cost wastage
of the final barrels of oil where existing infrastructure is available and
adequate to produce them. However, as evident above, the questions of whether
there will be a reduction in royalties is a case-by-case question for the lease
or project. However, there are critics of the royalty reduction programs, who
argue the royalty reduction programs are overused and subsidize the production
of oil at the cost of United States taxpayers.[90]
2.3 Abolition
Royalties
were essentially seen as a regressive tax as it applied to gross revenue and
acted as a disincentive to exploration and production.[91]
It should be understood that the United Kingdom (UK) and Norway abolished
royalty as part of their fiscal systems as their focus shifted from maximizing
fiscal revenues from highly profitable fields towards more emphasis on optimal
development of less profitable resources. These countries are close to each
other in the North Sea and also shared ownership of some cross-border fields.[92]
2.3.1
The United
Kingdom (UK) Case Study
UK’s
oil and gas sector is dominated by production from offshore areas. Production
of natural gas began in 1967 with the West Sole field in the Southern North
Sea. Offshore oil production began with the Argyll field in the Central North
Sea (CNS) in 1975. At the end of 2020, its total proved oil reserves were 2.5
billion barrels.[93]
In 2020, oil production was at a rate of 1.1 million bbls/d and 874,000 bbls/d
in 2021.[94]
The past royalty rate in the UK was twelve-point five percent (12.5%) of the
value of petroleum which was generally measured as “wellhead value.” The UK
utilized royalties when production was just starting, returns were high, fields
were large, and costs were relatively low. It was usually charged on the
licence rather than a field basis.
· Legislative
System
It
should be noted that in the UK, the law governing the development of
hydrocarbons is the UK Petroleum Act, 1998 which vests rights to oil and gas
resources in England and on the UK Continental Shelf in the Crown. Prior to the
UK Petroleum Act, in the early 1980’s, the government made changes to oil
taxation in an attempt to encourage exploration and development activities.
This was as a result of a significant decrease in the number of new oil and gas
projects generated by the industry. The year, 1983 marked the first of the
three (3) tier process towards the complete abolishment of royalties in the UK
in an attempt to encourage exploration and development activities.
Tier
1:
In 1983, royalties were abolished in the Petroleum Royalties (Relief) Act 1983
for qualifying fields receiving development approval from the Secretary of
State on or after 1st April 1982. According to this change, the new
fields, which were developed on or after the 1st April 1982, were
subject to a tax rate of eighty-nine point five percent (89.5%) (58% for
non-Petroleum Revenue Tax (PRT) paying fields) against eighty-eight percent
(88%) in old fields.[95]
This tax reform was the first stage of abolishing royalties.[96]
Tier
2:
The Chancellor of Exchequer announced in the 1988 Budget that all Southern
Basin and onshore fields for which a development permit was given after 31st
March 1982 would be exempted from royalties with effect from 1st
July 1988. In this regard, section 89 of the Petroleum Royalties (Relief) and
Continental Shelf Act 1989 stated:
“(1) Petroleum won and
saved from any relevant Southern Basin or onshore field or relevant onshore
area shall be disregarded in determining whether any and, if so, what—
(a) payments of royalty;
and
(b) deliveries of
petroleum, are to be made in relation to chargeable periods ending after 30th
June 1988 as consideration for the grant of a licence to which this section
applies.”
This
marked the second stage of abolishing royalties. Also, in June 1988 it was
announced that royalties would be taken in cash after 31st December
1988 rather than in kind. In the 1988 Budget, the Chancellor of the Exchequer
also reduced the PRT oil allowance.
During
the early 1990s the UK petroleum fiscal regime had some problems as fields that
were paying PRT faced a high marginal tax rate. This high tax rate led oil and
gas companies to attempt to avoid a heavy tax burden. For example, some
companies tried to shift income into fields that did not pay PRT and shift
expenditure into PRT paying fields, as immediate tax relief was available for
PRT paying fields. This practice, plus the low oil prices during that period of
time, resulted in a decline in the government tax taking from the oil industry.
These factors made the government consider a new relaxation package to reduce
taxes in the petroleum fiscal regime.
Tier
3:
A major
tax change to the North Sea regime came about in 2002 when the Chancellor of
the Exchequer announced on 17 April 2002 that companies producing oil and gas
in the UK or on the UK Continental Shelf (UKCS) would pay a supplementary
charge (SC) of ten percent (10%) on the profits from companies’ ring-fenced
trades in addition to the thirty percent (30%) corporation tax already payable
on these profits. Companies paid the supplementary charge on ring fence profits
at the same time as their general corporate tax liability, but special rules
for instalment payments covered the transitional period (i.e., the accounting
period that includes Budget Day).[97]
In the same Budget the Chancellor for the Exchequer announced the intention of
abolishing the royalty completely. In November that year the government
announced the abolition of North Sea royalty payments from 1 January 2003.[98]
UK’s
petroleum fiscal regime has always been described as one of the weakest and
more complex regimes in the World. Its changes in taxation were due to
political priorities altered between budget concerns and concerns for
sustaining the business. Changes between Conservative and Labour governments
occurred which impacted its fiscal regime. It was evident that the UK exhibited
a tendency to sharpen fiscal terms in response to budgetary requirements and at
other times relax them to promote more activity/maximise economic recovery.[99]
In terms of promotion of the latter, notably, the UK in 2016 published ‘the
Maximizing Economic Recovery Strategy for the UK” (MER UK). This recognized the
government’s strategy for intelligent investment in the North Sea as a mature
basin. A vital factor for advancing MER UK included the introduction of new
entrants as they were deemed crucially important for the basin because they
bring new capital, innovative technologies, cost-effective solutions and
increased risk appetite. MER UK also focussed on the efficient use of offshore
infrastructure and avoiding cost wastage by building new infrastructure where
existing infrastructure is available and adequate.
2.3.2
Norway’s Case
Study
Norway’s oil and gas/ petroleum
background dates back more than fifty (50) years ago. The first fields
developed were in the North Sea and now, it has gradually expanded northwards
into the Norwegian Sea and the Barents Sea.[100] At the end of
2020, its total proved oil reserves were 7.9 billion barrels.[101]
In 2020, oil production was at a rate of 2.0 million bbls/d per day.
· Legislative
System
In
Norway, its Petroleum Fiscal System was first introduced by the Petroleum Tax
Act in 1975 and thereafter supplemented by certain provisions via licences. In
this fiscal system, royalty was included to a maximum rate of sixteen percent
(16%) depending on field daily rates of production. It is important to
understand that its fiscal provisions were based in law and therefore
Parliament had the power to change tax rates applicable to existing and new
licensees.
The
Organization of Petroleum Exporting Countries (OPEC) emerged in or around the
period in which royalty provisions were included in Norway. Initially, Norway’s
fiscal system was structured so as to promote a beneficial gain for its
government. This introduction of royalty provisions impacted Norway’s global
economy and geopolitics. In consideration of its petroleum sector, Norway
sought to stimulate exploration and development in fields that were previously
unprofitable due to its stringent fiscal terms by abolishing royalties stepwise
from 1986. It is pertinent to note that no royalty has been payable since 2005.
The increase in the number of producing fields was possible as Norway’s economy
was capable of taking financial risks. Such capability arose as it’s
government’s share was secured through direct and indirect state participation,
corporation tax and petroleum special tax. In addition to this, Norway’s
stability was due to the broad and enduring consensus between its main
political parties behind its petroleum policy and taxation.[102]
Norway’s
tax system is based now on the taxation of the entity as opposed to specific
petroleum assets. Notably, the Norwegian Oil and Gas Taxation Code includes
direct and indirect taxation. Direct taxation plays the most important role for
companies investing in upstream activities on the Norwegian Continental Shelf
(“NCS”). Direct taxes consist of ordinary petroleum tax (27%) and special tax
at fifty-one percent (51%).[103]
The key difference with the aforementioned countries lies in the scope of
taxation. Entity-based taxation is more simplified. Taxing an entity’s overall
profits simplifies tax administration for both the government and the companies
and reduces the complexity associated with tracking and valuing specific
petroleum assets e.g., production/reserves/individual fields. It is also stable
due to its predictability. Entity-based taxation can anticipate tax liabilities
based on their overall financial performance rather than fluctuations in
individual asset values/production levels.
2.3.3
Deductions in
UK and Norway
In
the UK, royalties paid in oil and gas extraction were not typically deductible
against corporation tax. Royalty was allowable as a deduction against other
taxes such as field-based taxes e.g., the petroleum revenue tax (PRT) in the
UK. Whereas, in Norway, royalties paid for the extraction of oil and gas were
deductible against corporation tax.
3. Lessons
Learned & Recommendations
HGs all over the world have indeed
benefited over the years through revenue earned as a result of oil and gas
exploration. It is evident that in benefitting through such revenue, the fiscal
regime applicable to IOCs with respect to their oil and gas production
underwent considerable variations throughout the globe. Such variations were
implemented as a result of budgetary requirements, an attempt to encourage
investment, economic attractiveness, desires for equity, flexibility and
stability, and accounting for geological field viability inter alia. The
purpose of this analysis is to address the impact of the royalty regime on mature
provinces and fields and provide recommendations through case studies as to the
options available to promote:
i. Investments
that lead to an increase in production;
ii. The
extension of the useful life of the fields and postponement of the return of
the field;
iii. The maintenance of
government take;
iv. Awareness of costs and
profit level;
v. Incentives
towards exploration and development activities; and
vi. A reduction in the
premature abandonment of fields.
The means in which the aforementioned can be promoted
as seen earlier includes through:
i. Implementation
of proportionate and flexible tax regimes by the State considering the value
of financial return for fields with high and low production – a case by case
analysis is required considering different, individual and specific factors of
the reality of each field. The parameters to understand a mature field as
susceptible to receiving the tax benefit should consider its location (onshore
or offshore), proven reserves, rate projections, current reserves, reduced
production, declining production, production time, use of secondary or tertiary
recovery, economy, peak production, well-defined field, high water and sediment
production, among others[104];
and
ii. Encouraging
regulatory incentives,
for example, tax incentives and one-off incentives to make viable investments
that can increase oil and natural gas production, maximize the recovery factor
and extend the useful life of the field.
In
attempting to provide effective recommendations however, countries can consider
key methods applied by mature provinces like Nigeria, Mexico, Colombia, United
States, and Brazil, as well as the lack of royalty regimes in mature provinces
such as Norway and the United Kingdom. We make the following recommendations:
i. A
progressive type rate can ensure that the country has both a balance of equity
and flexibility when considering royalties on oil and gas. It essentially means
that where the HG benefits, the Investor/ IOC benefits as well. In terms of
progressivity, the royalty rate is adjustable depending on the changes in
circumstances. This rate could either be based on production levels, price
changes or in reference to a category of product. As an option to push towards
investments that lead to a reduction in the decline in production and
maintenance in government take, one can consider specifying different
thresholds of production for example, tier 1, tier 2 and tier 3. As the tier
goes up, production volumes and the royalty rate increases. It represents that
where production by an Investor/ IOC in a particular period is less than or
equal to a certain amount or more than or equal to a certain amount, royalty
rates would also coincide. An example of this is applied in Nigeria with their
first tranche being less than or equal to 50,000 and an applicable royalty rate
of 5%[105]
and it goes up accordingly as described in Table 1.
ii. Rate
price considerations could also be implemented to maintain government take; that is, a royalty
based on an applicable price on both applies where the price exceeds $20 per
barrel. Nigeria’s Deep Offshore and Inland Basin PSC (Amendment) Act, 2019 sets
out the various price categories with its royalty rate to coincide as seen in
Table 1. This provides stability on the part of IOC’s and the government, as
where the price is extremely low, so too would be the royalty rate. While still
earning income for the HG, it does not detract investors’ engagement in
exploration activities especially where production volumes are low based on the
Investor’s/ IOC’s decision to choose either a small, marginal or technically
challenging field. Regarding cost sensitivity, it can reduce the impact of any
early abandonment of fields with this approach as the Investor/IOC can save
more to contribute to later phases in production. Like Nigeria, other countries
with mature fields can benefit from higher oil prices realized.
iii. HGs can also consider
amending the royalty rate by accounting for revenue-based royalty rates on the
category of product produced. Another approach to correlating price and the royalty
rate is Mexico’s as seen in Table 2 which looks at the value of the barrel of
oil and applies a fixed rate of royalty. For non-associated natural gas, it
focuses on the value of the natural gas per million BTUs and applies a royalty
rate to coincide. Such a rate application also promotes investment into the
sector while attracting income for the HG.
iv. There is also a reduced
rate of royalty that could be considered, should the HG not intend to implement
a progressive based type of royalty. For example, in technically
challenging deep water and “end of life” leases or projects, the United States
will (and has) allowed operators to apply for and receive royalty reductions so
that a project or lease is fully produced. This has taken the form of no
royalties for a set number of barrels initially produced (essentially cost
recovery) to time-limited royalty reductions due to economic productions. In
other words, the royalty reduction schemes are flexible for mature fields.
Moreover, the Colombian government in 2022 showed an intention to back royalty
deductions in exchange for an increase in income taxes and export tax.[106]
This country like Nigeria also has a sliding scale type royalty focussed on
production and location meaning where production increases royalty also increases,
and in certain cases where the depth increases the discount permitted in terms
of royalties increases. This is an example that considers both the interests of
the Investor/ IOC and the HG. With respect to mature fields, it seems
reasonable that governments encourage investment in those production-declining
assets by means of royalty rates, tax burden and special participation
reductions. Brazil, for instance, is attempting to implement policies in this
regard to promote the continued investment in mature fields.
Another
approach for reduced royalty rates to encourage investment and exploration
activity is to account for different Investor/ IOC sizes and production levels.
With smaller-sized company investment, such endeavours could be encouraged by permitting
a reduced rate of royalty for example five percent (5%) where the production is
less than 1000boe/d as seen in Brazil. For medium-sized companies, where
production is less than 10,000boe/d a reduced rate of royalty can also be
applied such as seven point five percent (7.5%). Where there is a viable
marginal field development, production of such fields can be encouraged by
earning royalty deductions at a particular rate as highlighted in Brazil’s
legislation.[107]
This is one (1) of the royalty regimes that wholeheartedly encourages
investment in oil and gas no matter how small a company is. Such an approach
maintains government take and attracts further investment into the country
leading to a reduction in the decline in production.
3.1 Additional considerations
Apart
from the key royalty provisions for progressive and reduced approaches, the
State and investors should pay attention to the interaction between royalties
and other tax mechanisms as well as any deductions in terms of royalties. Other
taxes as combined from Nigeria, Mexico, Colombia and Brazil include the
Hydrocarbon tax (applicable on profits of upstream petroleum companies) and/or
Company/ Corporate Income Tax for example, the tax can be applicable on profits
of upstream oil and gas companies or it can be a percentage of resident
companies’ worldwide earnings at a rate of for example, thirty percent (30%) as
done in Mexico and Colombia. Corporate Income Taxes are most popular. In
Brazil, resident legal entities’ worldwide income is taxed at a rate of fifteen
percent (15%) with a surtax of 10% for profits exceeding BRL 240,000 a year.
In
terms of deductions, royalty deductions can incentivize investments especially
from small marginal fields. In Nigeria, alongside its progressive approach, it
permits a royalty credit where gas is re-injected in the reservoir and such
credit is deducted from the royalty applicable to crude oil or condensates or
both. The royalty credit amount is based on the applicable royalty rates for
domestic gas.[108]
In Mexico, its approach is not like its other fellow progressive country as it
considers a cap on cost deductions associated with profit sharing in an attempt
to contain costs. Mexico’s HRL expressed cost caps which range from twelve
point five percent (12.5%) to eighty percent (80%) depending on the location of
the activity and the type of hydrocarbon being extracted. Colombia, a country
with a reduced royalty rate, is an informative precedent for one to consider.
This country provides an example where the State implemented a provision under
its Tax Reform Act to prohibit deductions on royalty payments and it was struck
down by its Constitutional Court as being unconstitutional.[109]
The ruling provided a step towards long-term investment for investors.
Royalties on oil and gas production in Brazil are fully deductible. It is
noteworthy to commend Brazil again for its deductions as it encouraged
investment for small and medium-sized companies and for marginal fields hence
resulting in successful bid rounds.
Although
there are other taxes apart from royalties within the oil and gas fiscal regime
that can generate income for the HG, royalty is still of importance and a major
contributor to income in some countries around the world. UK’s economy is
dominated by the services industries such as retail, hospitality, business
administration and finance. UK’s recurrent changes in petroleum taxation
directly impacts the interest in investing in oil and gas assets in the
country, especially considering the country’s tendency to sharpen fiscal terms
in response to budgetary requirements. From what is perceived from the data
analysed, UK understood the royalty’s payment obligation as a measure that
would discourage the investment in oil and gas projects by private companies.
Many petroleum fields contribute to Norway’s economy and as such, the
exploration leads and prospects to be explored contributed to Norway taking the
financial risk. The HG’ share in Norway is secured also through corporate tax
and petroleum special tax. Norway’s stability was due to the broad and enduring
governmental consensus regarding its petroleum policy and taxation. HGs should
be keen on any decisions with abolishing royalty rates as it can reduce their
income where other taxes are not adjusted to account for the loss of income
from royalties.
It
should be highlighted that reasonable expectation with regards to the tax and
royalties impacts on production is considered in IOCs’ investment decisions on
any given country. The meaning itself of royalties brings the obligation of a
financial disbursement of the investor to the competent government, for the use
of the area for extraction of natural resources. A royalty rate must be set
according to the value of the asset, argument which reinforces the
understanding that the rate of royalties for mature fields must be fixed in a
lower percentage when compared to profitable fields or fields with the
production curve in its rising phase. As previously said, there are royalty
regimes that strongly stimulate investment and reinvestment in oil and gas,
regardless of the size of the firm, but only take into account the fields'
features, period of production, and proved reserves.
The
public policies in place by HGs should inspire other states to stimulate
exploration and development in fields that were previously unprofitable due to
its stringent fiscal terms. These incentives shall not only warrant the
continuance of tax collection but also safeguard energy safety through the
offer of oil and gas, especially considering the recent international political
issues between Russia and Ukraine that shed light on the world’s dependence of
Russian reserves.
In summary, in order to achieve the
purpose of incentivizing oil and gas production in mature fields, as
extensively analysed above, governments may opt to (i) raise government share
of net cash flows of a project as the value of the resource increases; (ii)
reduce royalty rates by the lowering of initial royalty rates or regulated
royalty discounts; or (iii) abolish royalties by emphasizing on optimal
development of less profitable resources.
Conclusion
The
process for making an investment decision for bidding and/or acquiring the
exploration and production rights for any given reservoir takes into
consideration many factors, such as the proven reserves, local taxes,
applicable governmental takes, term of concession, technical feasibility,
projected financial return, among others. The reality for mature fields is that
some of the abovementioned factors discourage the investments to maintain
production. In this sense, should there not be any governmental incentives for
the continuance of operations in this type of asset, some of these reservoirs
simply become unfeasible from an economic standpoint. The truth is that there
is not a correct answer on how to address the matter of mature fields
exploration and governmental incentives.
Each
country must analyse the factors that increase or decrease private sector
investments in its national energy industry, and regulatorily address solutions
that encourage investment, such as the establishment of fair and reasonable
government takes. The particularities of each country’s economic and social
needs must also be taken into consideration, meaning that governments should
all learn from other nations’ lessons to the extent they are applicable to
their economic characteristics. Thus, the tax system must be rigorously
examined as to its relevance at each stage of natural resource development,
taking into account the financial return of the investment in comparison to the
payments required to maintain the asset or the risks involved in deciding to
buy the asset.Decisions on the tax policies and governmental takes applicable
by any given country should consider the purpose of bringing profitability to
the asset in question while reassuring the government's rights over the private
exploration and commercialization of the natural resources, whilst
simultaneously promoting the competitiveness of investment return in the local
industry.
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